Dyne Therapeutics 10-K 2017 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 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 ________

DYNEGY INC.

(Exact name of registrant as specified in its charter)

Commission File Number	State of Incorporation	I.R.S. Employer Identification No.
001-33443	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)

Securities registered pursuant to Section12(b) of the Act:

Title of each class	Name of each exchange on which registered
Dynegy’s common stock, $0.01 par value	New York Stock Exchange
Dynegy’s warrants, exercisable for common stock at an exercise price of $35 per share	New York Stock Exchange

Securities registered pursuant to Section12(g) of the Act:

None

(Title of Class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ý No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o No ý

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

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

As of June 30, 2017, the aggregate market value of the Dynegy Inc. common stock held by non-affiliates of the registrant was $918,348,807 based on the closing sale price as reported on the New York Stock Exchange.

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 ¨

Number of shares outstanding of Dynegy Inc.’s class of common stock, as of the latest practicable date: Common stock, $0.01 par value per share, 144,390,952 shares outstanding as of February 8, 2018.

DOCUMENTS INCORPORATED BY REFERENCE

Part III (Items 10, 11, 12, 13 and 14) incorporates by reference portions of the Notice and Proxy Statement for the registrant’s 2018 Annual Meeting of Stockholders, which the registrant intends to file no later than 120 days after December 31, 2017. However, if such proxy statement is not filed within such 120-day period, Items 10, 11, 12, 13 and 14 will be filed as part of an amendment to this Form 10-K no later than the end of the 120-day period.

DYNEGY INC.

FORM 10-K

TABLE OF CONTENTS

		Page
PART I
Definitions		1
Item 1.	Business	2
Item 1A.	Risk Factors	22
Item 1B.	Unresolved Staff Comments	32
Item 2.	Properties	32
Item 3.	Legal Proceedings	32
Item 4.	Mine Safety Disclosures	32
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	33
Item 6.	Selected Financial Data	36
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	37
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	84
Item 8.	Financial Statements and Supplementary Data	86
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	86
Item 9A.	Controls and Procedures	86
Item 9B.	Other Information	86
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	87
Item 11.	Executive Compensation	87
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	87
Item 13.	Certain Relationships and Related Transactions, and Director Independence	87
Item 14.	Principal Accountant Fees and Services	88
PART IV
Item 15.	Exhibits and Financial Statement Schedules	89
Signatures		99

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PART I

DEFINITIONS

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. Further, as used in this Form 10-K, the abbreviations contained herein have the meanings set forth below.

ATSI	American Transmission Service, Inc.
CAA	Clean Air Act
CAISO	California Independent System Operator
CDD	Cooling Degree Days
CPUC	California Public Utility Commission
COMED	Commonwealth Edison
CT	Combustion Turbine
DEOK	Duke Energy Ohio Kentucky
EBITDA	Earnings Before Interest, Taxes, Depreciation and Amortization
EGU	Electric Generating Units
ELG	Effluent Limitation Guidelines
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
GW	Gigawatts
HAPs	Hazardous Air Pollutants, as defined by the Clean Air Act
HDD	Heating Degree Days
ICR	Installed Capacity Requirement
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
LMP	Locational Marginal Pricing
MAAC	Mid-Atlantic Area Council
MISO	Midcontinent Independent System Operator, Inc.
MMBtu	One Million British Thermal Units
Moody’s	Moody’s Investors Service, Inc.
MSCI	Morgan Stanley Capital International
MTM	Mark-to-market
MW	Megawatts
MWh	Megawatt Hour
NERC	North American Electric Reliability Corporation
NYISO	New York Independent System Operator
NYSE	New York Stock Exchange
PJM	PJM Interconnection, LLC
PPL	PPL Electric Utilities, Corp.
PRIDE	Producing Results through Innovation by Dynegy Employees
RCRA	Resource Conservation and Recovery Act of 1976
RGGI	Regional Greenhouse Gas Initiative
RTO	Regional Transmission Organization
S&P	Standard & Poor’s Ratings Services
SEC	U.S. Securities and Exchange Commission
ST	Steam Turbine
TWh	Terawatt Hour

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Item 1.    Business

THE COMPANY

Dynegy began operations in 1984 and became incorporated in the State of Delaware in 2007. We are a holding company and conduct substantially all of our business operations through our subsidiaries. Our primary business is the production and sale of electric energy, capacity and ancillary services from our fleet of 43 power plants in 12 states totaling approximately 28,000 MW of generating capacity.

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 through our Homefield Energy and Dynegy Energy Services retail businesses, through which we provide retail electricity to approximately 1,141,000 residential customers and approximately 88,000 commercial, industrial and municipal customers in Illinois, Massachusetts, Ohio and Pennsylvania. Wholesale electricity customers will primarily contract for rights to capacity from generating units for reliability reasons and to meet regulatory requirements. Ancillary services support the transmission grid operation, follow real-time changes in load and provide emergency reserves for major changes to the balance of generation and load. Retail electricity customers purchase energy and these related services in the deregulated retail energy market. We sell these products individually or in combination to our customers for various lengths of time from hourly to multi-year transactions.

We do business with a wide range of customers, including RTOs and ISOs, integrated utilities, municipalities, electric cooperatives, transmission and distribution utilities, power marketers, financial participants such as banks and hedge funds, and residential, commercial, and industrial end-users. Some of our customers, such as municipalities or integrated utilities, purchase our products for resale in order to serve their retail, commercial and industrial customers. Other customers, such as some power marketers, may buy from us to serve their own wholesale or retail customers or as a hedge against power sales they have made.

We report the results of our operations in the following five segments based upon the market areas in which our plants operate: (i) PJM, (ii) ISO-NE/NYISO (“NY/NE”), (iii) ERCOT, (iv) MISO, and (v) CAISO. Our consolidated financial results also reflect corporate-level expenses such as general and administrative expense, interest expense and income tax benefit (expense). Please read Note 21—Segment Information for further discussion. In the fourth quarter of 2017, we combined our previous MISO

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and IPH segments into a single MISO segment to better align our IPH assets, which reside within the MISO market area. Accordingly, the Company has recast data from prior periods to conform to the current year segment presentation.

The charts below include our net generation capacity, wholesale generation, retail delivered volumes, and Adjusted EBITDA contribution as of December 31, 2017. Adjusted EBITDA Contribution by Segment excludes our corporate-level expenses.

Our principal executive office is located at 601 Travis Street, Suite 1400, Houston, Texas 77002, and our telephone number is (713) 507-6400. We file annual, quarterly and current reports, and other information with the SEC. You may read and copy any document we file at the SEC’s Public Reference Room at 100 F Street N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the SEC’s Public Reference Room. Our SEC filings are also available to the public at the SEC’s website at www.sec.gov. No information from such website is incorporated by reference herein. Our SEC filings are also available free of charge on our website at www.dynegy.com, as soon as reasonably practicable after those reports are filed with or furnished to the SEC. The contents of our website are not intended to be, and should not be considered to be, incorporated by reference into this Form 10-K.

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Our Power Generation Portfolio

Our generating facilities are as follows:

Facility	Total Net Generating Capacity (MW)(1)	Primary Fuel Type	Technology Type	Location	Region
Calumet	380	Gas	CT	Chicago, IL	PJM
Dicks Creek	155	Gas	CT	Monroe, OH	PJM
Fayette	726	Gas	CCGT	Masontown, PA	PJM
Hanging Rock	1,430	Gas	CCGT	Ironton, OH	PJM
Hopewell	370	Gas	CCGT	Hopewell, VA	PJM
Kendall	1,288	Gas	CCGT	Minooka, IL	PJM
Killen (2)(3)	204	Coal	ST	Manchester, OH	PJM
Kincaid	1,108	Coal	ST	Kincaid, IL	PJM
Liberty	607	Gas	CCGT	Eddystone, PA	PJM
Miami Fort	1,020	Coal	ST	North Bend, OH	PJM
Miami Fort	77	Oil	CT	North Bend, OH	PJM
Northeastern	52	Waste Coal	ST	McAdoo, PA	PJM
Ontelaunee	600	Gas	CCGT	Reading, PA	PJM
Pleasants	388	Gas	CT	Saint Marys, WV	PJM
Richland	423	Gas	CT	Defiance, OH	PJM
Sayreville (2)(3)	170	Gas	CCGT	Sayreville, NJ	PJM
Stryker	16	Oil	CT	Stryker, OH	PJM
Stuart (2)(3)	679	Coal	ST	Aberdeen, OH	PJM
Washington	711	Gas	CCGT	Beverly, OH	PJM
Zimmer	1,300	Coal	ST	Moscow, OH	PJM
Total PJM Segment	11,704
Bellingham	566	Gas	CCGT	Bellingham, MA	ISO-NE
Bellingham NEA (2)(3)	157	Gas	CCGT	Bellingham, MA	ISO-NE
Blackstone	544	Gas	CCGT	Blackstone, MA	ISO-NE
Casco Bay	543	Gas	CCGT	Veazie, ME	ISO-NE
Independence	1,212	Gas	CCGT	Oswego, NY	NYISO
Lake Road	827	Gas	CCGT	Dayville, CT	ISO-NE
MASSPOWER	281	Gas	CCGT	Indian Orchard, MA	ISO-NE
Milford - Connecticut	600	Gas	CCGT	Milford, CT	ISO-NE
Total NY/NE Segment	4,730
Coleto Creek	650	Coal	ST	Goliad, TX	ERCOT
Ennis	366	Gas	CCGT	Ennis, TX	ERCOT
Hays	1,047	Gas	CCGT	San Marcos, TX	ERCOT
Midlothian	1,596	Gas	CCGT	Midlothian, TX	ERCOT
Wharton	83	Gas	CT	Boling, TX	ERCOT
Wise	787	Gas	CCGT	Poolville, TX	ERCOT
Total ERCOT Segment	4,529
Baldwin	1,185	Coal	ST	Baldwin, IL	MISO
Coffeen	915	Coal	ST	Coffeen, IL	MISO
Duck Creek	425	Coal	ST	Canton, IL	MISO
Edwards	585	Coal	ST	Bartonville, IL	MISO
Havana	434	Coal	ST	Havana, IL	MISO
Hennepin	294	Coal	ST	Hennepin, IL	MISO
Joppa/EEI (2)	802	Coal	ST	Joppa, IL	MISO
Joppa units 1-3	165	Gas	CT	Joppa, IL	MISO
Joppa units 4-5 (2)	56	Gas	CT	Joppa, IL	MISO
Newton	615	Coal	ST	Newton, IL	MISO
Total MISO Segment (4)	5,476

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Facility	Total Net Generating Capacity (MW)(1)	Primary Fuel Type	Technology Type	Location	Region
Moss Landing	1,020	Gas	CCGT	Moss Landing, CA	CAISO
Oakland	165	Oil	CT	Oakland, CA	CAISO
Total CAISO Segment	1,185
Total Capacity	27,624

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(1) Unit capabilities are based on winter capacity and are reflected at our net ownership interest. We have not included units that have been retired or are out of operation.

(2) Co-owned with other generation companies.

(3) Facilities not operated by Dynegy.

(4) We have transmission rights into PJM for certain of our MISO plants and currently offer power and capacity into PJM.

Business Strategies

Our business strategy is to create value through the optimization of our generation facilities, cost structure and financial resources.

Customer Focus. Our commercial outreach focuses on the needs of the customers and constituents we serve, including the end-use and wholesale customer, our market channel partners and the government agencies and regulatory bodies that represent the public interest. The insight provided through these relationships will influence our decisions aimed at meeting customer needs while optimizing the value of our business.

Currently, our commercial strategy seeks to optimize the value of our assets by locking in near-term cash flow while preserving the ability to capture higher values long-term as power markets improve. We may hedge portions of the expected output from our facilities with the goal of stabilizing near-term earnings and cash flow while preserving upside potential should commodity prices or market factors improve. Our wholesale organization and retail marketing teams are responsible for implementation of this strategy. These teams provide access to a broad portfolio of customers with varying energy and capacity requirements. There is a significant risk reduction from the relationship between our generation and our customer load which reduces the need to transact additional financial hedging products in the market.

Our wholesale origination efforts focus on marketing energy and capacity and providing certain associated services through structured transactions that are designed to meet our customers’ operating, financial and risk requirements while simultaneously compensating Dynegy appropriately. In order to optimize the value of our generation portfolio, we use a wide range of products and contracts such as tolling agreements, fuel supply contracts, capacity auctions, bilateral capacity contracts, power and natural gas swap agreements and other financial instruments.

Our retail marketing efforts focus on offering end-use customers energy products that range from fixed price and full requirements to flexible price and volume structures. Our goal is to deliver value beyond price by leveraging our experience in the energy markets to provide products that help customers make sound energy decisions. Establishing and maintaining strong relationships with retail energy channel partners is another key focus where personal service and transparent communication further build our retail brands as trusted suppliers. Our objective is to maximize the benefit to both Dynegy and our customers.

Dynegy operates in a complex and highly-regulated environment with multiple federal, state and local stakeholders, such as legislators, government agencies, industry groups, consumers and environmental advocates. Dynegy works with these stakeholders to encourage reasonable regulations, constructive market designs and balanced environmental policies. Our regulatory strategy includes a continuous process of advocacy, visibility, education and engagement. The ultimate goal is to find solutions that provide adequate cost recovery, incentives for investment, and safe, reliable, cost-effective and environmentally-compliant generation for the communities we serve.

Continuous Improvement.We are committed to operating all of our facilities in a safe, reliable, cost-efficient and environmentally compliant manner. We will continue to invest in our facilities to maintain and improve the safety, reliability and efficiency of our fleet.

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We continue to employ our cost and performance improvement initiative launched in 2011, known as PRIDE, which is designed to drive recurring cash flow benefits by optimizing our cost structure, implementing company-wide process and operating improvements, and improving balance sheet efficiency. Our current 3-year PRIDE targets and results are shown below.

As shown in the table above, in 2016, we exceeded our EBITDA target of $135 million by $15 million, and exceeded our balance sheet target of $200 million by $222 million. In 2017, we exceeded our EBITDA target of $65 million by $24 million, and exceeded our balance sheet target of $100 million by $41 million.

In furtherance of our PRIDE program, in October 2017, we launched the Earnings & Cost Improvement initiative, or ECI. Similar to PRIDE, ECI is driven by our employees, but also involves assistance from a third party consultant. ECI was created to drive leading practices across key areas of our power generation fleet to ensure that the operations of our fleet as well as supporting processes are “best in class”. Key areas of ECI include:

• Operating our power plants more efficiently and driving higher operating margins;

• Optimizing working capital and plant inventory levels; and

• Leveraging the scale of our generation portfolio to drive cost savings.

ECI has separate targets from our current PRIDE targets and is expected to contribute more than $100 million in sustainable earnings improvements. Over the next 18-24 months we expect to identify and implement practices that drive improved operational performance across our generation fleet in a manner that provides meaningful EBITDA improvements. The primary areas of focus for enhancements include ramp rate increases, scope refinements for planned maintenance outages, heat rate improvements, auxiliary load reduction and lowering fixed O&M costs.

Capital Allocation.  The power industry is a capital intensive, cyclical commodity business with significant commodity price volatility. As such, it is imperative to build and maintain a balance sheet with manageable debt levels supported by a flexible and diverse liquidity program. Our ongoing capital allocation priorities, first and foremost, are to maintain an appropriate leverage and liquidity profile and to make the necessary capital investments to maintain the safety and reliability of our fleet and to comply with environmental rules and regulations. We also evaluate other capital allocation options including investing in our existing portfolio, making potential acquisitions, and returning capital to shareholders. Capital allocation decisions are generally based on alternatives that provide the highest risk adjusted rates of return.

We continue to focus on maintaining a diverse liquidity program to support our ongoing operations and commercial activities. This includes maintaining adequate cash balances, expanding our first lien collateral program to include additional hedging counterparties and having in place sufficient committed lines of credit and revolving credit facilities to support our ongoing liquidity needs.

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. Accordingly, we are focused on strengthening our balance sheet, managing debt maturities and improving our leverage profile through debt reduction primarily from operating cash flows, as well as our PRIDE and ECI initiatives.

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Recent Developments

Vistra Merger    

On October 29, 2017, Dynegy and Vistra Energy Corp., a Delaware corporation (“Vistra Energy”), entered into an Agreement and Plan of Merger (the ��Merger Agreement”). Under the Merger Agreement, which has been approved by the boards of directors of both companies, Dynegy will merge with and into Vistra Energy in a tax-free, all-stock transaction, with Vistra Energy continuing as the surviving corporation (the “Merger”). Under the terms of the agreement, Dynegy stockholders will receive 0.652 shares of Vistra Energy common stock for each share of Dynegy common stock they own, resulting in Vistra Energy stockholders and Dynegy stockholders owning approximately 79 percent and 21 percent, respectively, of the combined company.

We expect the transaction to close in the second quarter of 2018 after meeting the remaining customary conditions, including (a) stockholder approval and (b) regulatory approvals including FERC, the Public Utility Commission of Texas and the New York Public Service Commission. Please read Note 1—Organization and Operations for further discussion.

ENGIE Acquisition

On February 7, 2017, (“the ENGIE Acquisition Closing Date”), Dynegy acquired approximately 9,017 MW of generation, 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”). Please read Note 3—Acquisitions and Divestitures for further discussion.

Asset Divestitures

In 2017, we sold the following five generating facilities, providing approximately $773 million in proceeds which were used for debt reduction:

•On July 11, 2017, we sold our Troy and Armstrong facilities (1,269 MW);

• On September 22, 2017, we sold our Dighton and Milford-MA facilities (356 MW) to comply with FERC mitigation requirements; and

•On October 12, 2017, we sold our Lee facility (787 MW).

Please read Management’s Discussion and Analysis - Liquidity and Capital Resources - Liquidity Highlights and Note 3—Acquisitions and Divestitures for further discussion.

Jointly Owned Generating Facilities

During 2017, in an effort to simplify our structure and drive operating efficiencies, we acquired or exchanged ownership interests in certain of our jointly owned generating facilities. As a result, we now own 100 percent of Miami Fort and Zimmer and disposed of our full interest in Conesville. No ownership changes occurred related to the Stuart and Killen facilities, as they are scheduled to be retired mid-2018. Please read Note 9—Joint Ownership of Generating Facilities for further discussion.

Debt Restructuring, Repayments, and Repricing

During 2017 we extended our 2019 debt maturities by repaying a significant portion of existing senior notes and issuing new senior notes. In addition, we repaid $200 million and repriced our term loan. See Management’s Discussion and Analysis - Liquidity and Capital Resources - Liquidity Highlights for further discussion.

Genco Bankruptcy

On February 2, 2017, Illinois Power Generating Company (“Genco”) emerged from bankruptcy. As a result, we eliminated $825 million of Genco senior notes in exchange for approximately $122 million of cash, $188 million of new seven-year unsecured notes, and 9 million Dynegy common stock warrants. Please read Note 20—Genco Chapter 11 Bankruptcy for further discussion.

Tax Reform Act

On December 22, 2017, the President of the United States signed into law the Tax Cuts and Jobs Act (“TCJA”). Substantially all of the provisions of the TCJA are effective for taxable years beginning after December 31, 2017. The TCJA includes significant changes to the Internal Revenue Code of 1986, as amended (“the Code”), including amendments which significantly change the taxation of business entities. The more significant changes in the TCJA that impact Dynegy are:

•reductions in the corporate federal income tax rate from 35 percent to 21 percent,

•repeal of the corporate Alternative Minimum Tax (“AMT”) providing for refunds of excess AMT credits,

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• limiting the utilization of Net Operating Losses (“NOLs”) arising after December 31, 2017 to 80 percent of taxable income with an indefinite carryforward (existing NOLs can continue to be utilized at 100 percent of taxable income with a 20 year carryforward), and

• limiting the deduction of net business interest expense to 30 percent of adjusted taxable income as defined in the TCJA.

We are currently in the process of finalizing and quantifying the tax effects of the TCJA, but have recorded provisional amounts based on reasonable estimates for the measurement and accounting of certain effects of the TCJA in our Consolidated Financial Statements for the year ended December 31, 2017.

As a result of the reduction in the U.S. federal corporate tax rate, Dynegy has recorded a $394 million reduction to our net deferred tax assets, including the federal benefit of state deferred taxes, which was fully offset by a decrease in our valuation allowance for the year ended December 31, 2017. Additionally, we have recorded a $223 million current tax benefit and long term tax receivable in 2017 related to the expected refund of our existing AMT credits. As prescribed by the TCJA, and unless used to offset a cash tax liability, we expect to receive the cash refunds as follows: 2019 - $112 million; 2020 - $56 million; 2021 - $28 million; 2022 - $27 million. Please read Note 14—Income Taxes for further discussion.

We expect in the near term that the unfavorable limit on deducting net business interest expense will be offset by greater utilization of our NOL’s. Any disallowed deduction of net business interest expense may be carried forward indefinitely.

MARKET DISCUSSION

Our business operations are focused primarily on the wholesale power generation sector of the energy industry. We manage and report the results of our power generation business within the following five segments: (i) PJM, (ii) NY/NE, (iii) ERCOT, (iv) MISO, and (v) CAISO. Please read Note 21—Segment Information for further information regarding revenues from external customers, operating income (loss) and total assets by segment. The discussion herein reflects generating capacity at our net ownership interest.

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NERC Regions, RTOs and ISOs

  In discussing our business, we often refer to NERC regions. The NERC and its regional reliability entities were formed to ensure the reliability and security of the electricity system. The regional reliability entities set standards for reliable operation and maintenance of power generation facilities and transmission systems. For example, each NERC region establishes a minimum operating reserve requirement to ensure there is sufficient generating capacity to meet expected demand within its region. Each NERC region reports seasonally and annually on the status of generation and transmission in such region.

Separately, RTOs and ISOs administer the transmission infrastructure and markets across a regional footprint in most of the markets in which we operate. They are responsible for dispatching all generation facilities in their respective footprints and are responsible for both maximum utilization and reliable and efficient operation of the transmission system. RTOs and ISOs administer energy and ancillary service markets in the short term, usually day-ahead and real-time markets. Several RTOs and ISOs also ensure long-term planning reserves through monthly, semi-annual, annual and multi-year capacity markets. The RTOs and ISOs that oversee most of the wholesale power markets in which we operate currently impose, and will likely continue to impose, bid and price limits or other similar mechanisms. NERC regions and RTOs/ISOs often have different geographic footprints, and while there may be geographic overlap between NERC regions and RTOs/ISOs, their respective roles and responsibilities do not generally overlap.

In RTO and ISO regions with centrally dispatched market structures, all generators selling into the centralized market receive the same price for energy sold based on the bid price associated with the production of the last MWh that is needed to balance supply with demand within a designated zone or at a given location. Different zones or locations within the same RTO/ISO may produce different prices respective to other zones within the same RTO/ISO due to transmission losses and congestion. For example, a less efficient and/or less economical natural gas-fired unit may be needed in some hours to meet demand. If this unit’s production is required to meet demand on the margin, its offer price will set the market clearing price that will be paid for all dispatched generation in the same zone or location (although the price paid at other zones or locations may vary because of transmission losses and congestion), regardless of the price that any other unit may have offered into the market. In RTO and ISO regions with centrally dispatched market structures and location-based marginal price clearing structures (e.g. PJM, ISO-NE, NYISO, ERCOT, MISO, and CAISO), generators will receive the location-based marginal price for their output. The location-based marginal price, absent congestion, would be the marginal price of the most expensive unit needed to meet demand. In regions that are outside the footprint of RTOs/ISOs, prices are determined on a bilateral basis between buyers and sellers.

Reserve Margins

RTOs and ISOs are required to meet NERC planning and resource adequacy standards.  The reserve margin, which is the amount of generation resources in excess of peak load, is a measure of resource adequacy and is also used to assess the supply-demand balance of a region.  RTOs and ISOs use various mechanisms to help market participants meet their planning reserve margin requirements.  Mechanisms range from centralized capacity markets administered by the ISO to markets where entities fulfill their requirements through a combination of long- and short-term bilateral contracts between individual counterparties and self-generation.

Contracted Capacity and Energy

We commercialize our assets through a combination of bilateral wholesale and retail physical and financial power sales, fuel purchases and tolling arrangements. Uncontracted energy is sold in the various ISOs’ day ahead and real-time markets.  Capacity is commercialized through a combination of centrally cleared auctions and/or bilateral contracts. We use our retail activity to hedge a portion of the output from our MISO, PJM, and ISO-NE facilities.

PJM Segment

Our PJM segment is comprised of 19 power generation facilities located in Ohio (9), Pennsylvania (4), Illinois (3), Virginia (1), West Virginia (1) and New Jersey (1), totaling 11,704 MW of electric generating capacity.

RTO/ISO Discussion

The PJM market includes all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia.

PJM administers markets for wholesale electricity and provides transmission planning for the region, utilizing an LMP methodology which calculates a price for every generator and load point within PJM.  This market is transparent, allowing generators and load serving entities to see real-time price effects of transmission constraints and the impacts of congestion at each pricing point. PJM operates day-ahead and real-time markets into which generators can bid to provide energy and ancillary services. PJM also administers a forward capacity auction, the Reliability Pricing Model (“RPM”), which establishes long-term markets for capacity. We have participated in RPM base residual auctions for years up to and including PJM’s Planning Year 2020-2021,

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which ends May 31, 2021. We also enter into bilateral capacity transactions. Beginning with Planning Year 2016-2017, PJM has started to transition to Capacity Performance (“CP”) rules. These rules are designed to improve system reliability and include penalties for underperforming units and rewards for overperforming units during shortage events. Beginning in Planning Year 2018-2019, PJM introduced Base Capacity (“Base”), which, alongside its new CP product, 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. Full transition of the capacity market to CP rules will occur by Planning Year 2020-2021. An independent market monitor continually monitors PJM markets to ensure a robust, competitive market and to identify any improper behavior by any entity.

Reserve Margins

Planning Reserve Margins based on deliverable capacity by Planning Year are as follows:

	2017-2018	2018-2019	2019-2020	2020-2021	2021-2022
Planning Reserve Margin (%)	15.7	16.1	15.9	15.9	15.8

NY/NE Segment

Our NY/NE segment is comprised of eight power generation facilities located in Massachusetts (4), Connecticut (2), Maine (1) and New York (1), totaling 4,730 MW of electric generating capacity.

RTO/ISO Discussion

The NYISO market includes the entire state of New York. The NYISO market dispatches power plants to meet system energy and reliability needs and settles physical power deliveries at LMPs. Energy prices vary among the regional zones in the NYISO and are largely influenced by transmission constraints and fuel supply. NYISO offers a forward capacity market where capacity prices are determined through auctions. Strip auctions occur one to two months prior to the commencement of a six month seasonal planning period. Subsequent auctions provide an opportunity to sell excess capacity for the balance of the seasonal planning period or the prompt month. Due to the short term nature of the NYISO-operated capacity auctions and a relatively liquid market for NYISO capacity products, our Independence facility sells a significant portion of its capacity through bilateral transactions. The balance is cleared through the seasonal and monthly capacity auctions.

The ISO-NE market includes the six New England states of Vermont, New Hampshire, Massachusetts, Connecticut, Rhode Island, and Maine. ISO-NE also dispatches power plants to meet system energy and reliability needs and settles physical power deliveries at LMPs. Energy prices vary among the participating states in ISO-NE and are largely influenced by transmission constraints and fuel supply. ISO-NE offers a forward capacity market where capacity prices are determined through auctions. ISO-NE implemented changes to its capacity market starting in FCA-8 for Planning Year 2017-2018, which include removal of the price floor and implementation of a minimum offer price rule for new resources to prevent buy-side market power. Additionally, performance incentive rules will go into effect for Planning Year 2018-2019 (FCA-9), which will have 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.

Reserve Margins

NYISO. Planning Reserve Margins by Planning Year are as follows:

	2017-2018	2018-2019
Planning Reserve Margin (%)	18.1	18.2

ISO-NE. Similar to PJM, ISO-NE will publish on an annual basis the installed capacity requirement, commonly referred to as the ICR.  The ICR is the amount of capacity that must be procured over and above the load forecast for the applicable Planning Year.  ISO-NE updates this information annually for each planning year during the Annual Reconfiguration Auctions. ICRs by Planning Year are as follows:

	2018-2019	2019-2020	2020-2021	2021-2022
ICR (%)	15.3	15.6	15.3	14.6

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ERCOT Segment

Our ERCOT segment, new in 2017 as a result of the ENGIE Acquisition, is comprised of six power generation facilities located in Texas, totaling 4,529 MW of electric generating capacity. Our ERCOT fleet is comprised of 3,796 MW of natural gas powered combined-cycle generation, 650 MW of Powder River Basin coal powered generation, and 83 MW of natural gas powered peaking generation.

RTO/ISO Discussion

ERCOT serves about 90 percent of load in the state of Texas over a high-voltage transmission system of more than 46,500 circuit miles. The ERCOT system is entirely contained within the state of Texas, and thus is regulated by the Texas Public Utility Commission rather than the FERC. The ERCOT nodal market provides a transparent means to reflect the cost of congestion in nodal prices across the system. The day-ahead market and real-time markets provide generators the ability to competitively offer energy and ancillary services into the market. ERCOT is an “energy-only” market, meaning there is no capacity market. Alternatively, ERCOT has implemented the Operating Reserve Demand Curve (“ORDC”), which causes prices to rise to as much as $9,000/MWh during reserve shortage events. ERCOT has a high level of wind generation, which tends to be a source of real-time price volatility.

Reserve Margins

As contained in ERCOT’s December 2017 Capacity, Demand and Reserves (“CDR”) report, the Target Reserve Margin is 13.75 percent through 2022.

MISO Segment

Our MISO segment is comprised of eight power generation facilities located in Illinois, totaling 5,476 MW of electric generating capacity.  Joppa, which is within the Electric Energy, Inc. (“EEI”) 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 MISO 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 17 percent of MISO’s current capacity and energy, electrically tied into PJM through pseudo-tie arrangements. As of June 1, 2017, Hennepin began offering 260 MW of the facility’s energy and capacity into PJM as a block schedule and will begin dispatching as a pseudo-tie unit for Planning Year 2018-2019. 

RTO/ISO Discussion

The MISO market includes all or parts of Iowa, Minnesota, North Dakota, Wisconsin, Michigan, Kentucky, Indiana, Illinois, Missouri, Arkansas, Mississippi, Texas, Louisiana, Montana, South Dakota, and Manitoba, Canada.

The MISO energy market is designed to ensure that all market participants have open-access to the transmission system on a non-discriminatory basis. MISO, as an independent RTO, maintains functional control over the use of the transmission system to ensure transmission circuits do not exceed their secure operating limits and become overloaded. MISO operates day-ahead and real-time energy markets using a similar LMP methodology as described above. An independent market monitor is responsible for evaluating the performance of the markets and identifying conduct by market participants or MISO that may compromise the efficiency or distort the outcome of the markets.

MISO administers a one-year FCA for the next planning year from June 1st of the current year to May 31st of the following year. We participate in these auctions with open capacity that has not been committed through bilateral or retail transactions.

We participate in the MISO annual and monthly FTR auctions to manage the cost of our transmission congestion, as measured by the congestion component of the LMP price differential between two points on the transmission grid across the market area.

Reserve Margins

Planning Reserve Margins by Planning Year are as follows:

	2018-2019	2019-2020	2020-2021	2021-2022	2022-2023
Planning Reserve Margin (%)	17.1	17.1	17.2	17.2	17.2

CAISO Segment

Our CAISO segment is comprised of two power generation facilities located in California, totaling 1,185 MW of electric generating capacity.

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RTO/ISO Discussion

The CAISO market covers approximately 80 percent of the State of California and operates a centrally cleared market for energy and ancillary services. Energy is priced utilizing an LMP methodology as described above. The capacity market is comprised of Generic and Flexible Resource Adequacy (“RA”) Capacity. Unlike other centrally cleared capacity markets, the CAISO resource adequacy market is a bilaterally traded market which typically transacts in monthly products as opposed to annual capacity products in other regions. Beginning on November 1, 2016, CAISO implemented a voluntary capacity auction for annual, monthly, and intra-month procurement to cover for deficiencies in the market.  The voluntary Competitive Solicitation Process, which FERC approved on October 1, 2015, is a modification to the Capacity Priced Mechanism (“CPM”) and provides another avenue to sell RA capacity. There have been recent CPM designations through the Competitive Solicitation Process including Moss Landing Unit 1 on December 18, 2016 for 140 MW over a 30-day period and again on December 22, 2017 for 510 MW for the calendar year 2018.

Reserve Margins

The California Public Utility Commission requires a Planning Reserve Margin of at least 15 percent.

Other

Market-Based Rates.  Our ability to charge market-based rates for wholesale sales of electricity, as opposed to cost-based rates, is governed by FERC. We have been granted market-based rate authority for wholesale power sales from our exempt wholesale generator facilities, as well as wholesale power sales by our power marketing entities, Dynegy Power Marketing, LLC, Dynegy Marketing and Trade, LLC (“DMT”), Illinois Power Marketing Company, Dynegy Energy Services, LLC, and Dynegy Commercial Asset Management, LLC. Every three years, FERC conducts a review of our market-based rates and potential market power on a regional basis (known as the triennial market power review). In June 2017, we filed a market power update with FERC for our PJM, ISO-NE and NYISO assets. In December 2017, we filed a market power update with FERC for our Central Region (MISO and EEI) assets.

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. Unless enjoined or eliminated, the ZECs will result in an estimated $7.6 billion of payments over 12 years to Exelon. 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. On July 25, 2017, the court granted the motions of the defendants and Exelon to dismiss the complaint. On August 25, 2017, we filed a notice of appeal of the July 25 Order to the United States Court of Appeals for the Second Circuit. Oral argument will be heard by the Second Circuit on March 12, 2018. We cannot predict the outcome of this litigation, but if left unchecked, we believe these subsidies 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 became effective on June 1, 2017 and, unless enjoined or eliminated, the ZECs will result in an estimated $2.35 billion of payments over 10 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. On July 14, 2017, the court granted the motions of defendants and Exelon to dismiss the complaint and denied the motion for preliminary injunction.  On July 17, 2017, we filed a notice of appeal of the July 14thOrder to the United States Court of Appeals for the Seventh Circuit.  Oral argument was held before the Seventh Circuit on January 3, 2018. We cannot predict the outcome of this litigation but, if left unchecked, we believe these subsidies will continue to adversely affect the energy and capacity markets in PJM and MISO.

ENVIRONMENTAL MATTERS

Our business is subject to extensive federal, state and local laws and regulations concerning environmental matters, including the discharge of materials into the environment. We are committed to operating within these laws and regulations and to conducting our business in an environmentally responsible manner. The environmental, legal and regulatory landscape continues to change and has become more stringent over time. This may create unprofitable or unfavorable operating conditions or require significant capital and operating expenditures. Further, changing interpretations of existing regulations may subject historical maintenance, repair and replacement activities at our facilities to claims of noncompliance.

The following is a summary of (i) the material federal, state and local environmental laws and regulations applicable to us and (ii) certain pending judicial and administrative proceedings related thereto.  Compliance with these environmental laws and regulations and resolution of these various proceedings may result in increased capital expenditures and other environmental

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compliance costs, impairments, increased operations and maintenance expenses, increased Asset Retirement Obligations (“AROs”), and the imposition of fines and penalties, any of which could have a material adverse effect on our financial condition, results of operations and cash flows.  In addition, if we are required to incur significant additional costs or expenses to comply with applicable environmental laws or to resolve a related proceeding, the incurrence of such costs or expenses may render continued operation of a plant uneconomical such that we may determine, subject to applicable laws and any applicable financing or other agreements, to reduce the plant’s operations to minimize such costs or expenses or cease to operate the plant completely to avoid such costs or expenses.  Unless otherwise expressly noted in the following summary, we are not currently able to reasonably estimate the costs and expenses, or range of the costs and expenses, associated with complying with these environmental laws and regulations or with resolution of these judicial and administrative proceedings.  For additional information regarding our pending environmental, judicial, and administrative proceedings, please read Note 16—Commitments and Contingencies for further discussion.

Our aggregate expenditures by segment for compliance with environmental laws and regulations were as follows for the years ended December 31, 2017 and 2016:

	Year Ended December 31,
	2017						2016
(amounts in millions)	Total Expenditures		Capital Expenditures		Operating Expenses		Total Expenditures		Capital Expenditures		Operating Expenses
PJM	$	65	$	1	$	64	$	62	$	6	$	56
NY/NE	10		—		10		17		—		17
ERCOT	2		—		2		—		—		—
MISO	53		6		47		61		17		44
CAISO	4		—		4		5		—		5
Other	3		—		3		11		—		11
Total	$	137	$	7	$	130	$	156	$	23	$	133

Our estimated total environmental compliance expenditures by segment in 2018 are as follows:

(amounts in millions)	Total Environmental Expenditures		Capital Expenditures		Operating Expenses
PJM	$	86	$	6	$	80
NY/NE	4		—		4
ERCOT	4		1		3
MISO	73		17		56
CAISO	3		—		3
Other	4		—		4
Total	$	174	$	24	$	150

The Clean Air Act

The CAA and comparable state laws and regulations relating to air emissions impose various responsibilities on owners and operators of sources of air emissions, which include requirements to obtain construction and operating permits, pay permit fees, monitor emissions, submit reports and compliance certifications, and keep records. The CAA requires that fossil-fueled electric generating plants meet certain pollutant emission standards and have sufficient emission allowances to cover sulfur dioxide (“SO₂”) emissions and in some regions nitrogen oxide (“NO_x”) emissions.

In order to ensure continued compliance with the CAA and related rules and regulations, we utilize various emission reduction technologies. These technologies include flue gas desulfurization (“FGD”) systems, baghouses and activated carbon injection or mercury oxidation systems on select units and electrostatic precipitators, selective catalytic reduction (“SCR”) systems, low-NO_x burners and/or overfire air systems on all units. Additionally, our MISO coal-fired facilities mainly use low sulfur coal, which, prior to combustion, goes through a refined coal process to further reduce NO_x and mercury emissions.

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Multi-Pollutant Air Emission Initiatives

Cross-State Air Pollution Rule. The “Cross-State Air Pollution Rule” (“CSAPR”) to reduce emissions of SO₂ and NO_x from EGUs across the eastern U.S. took effect in 2015. The CSAPR imposes cap-and-trade programs within each affected state that limit emissions of SO₂ and NO_x at levels to help downwind states attain and maintain compliance with the 1997 ozone National Ambient Air Quality Standards (“NAAQS”) and the 1997 and 2006 fine particulate matter (“PM_2.5”) NAAQS. In October 2016, the EPA updated the CSAPR rule to further reduce ozone season NO_x emissions beginning in 2017 to attain and maintain compliance with the 2008 ozone NAAQS. Numerous parties filed petitions for judicial review challenging the CSAPR update rule.

Under the CSAPR, our generating facilities in Illinois, Ohio, New Jersey, New York, Pennsylvania, Virginia and West Virginia are subject to cap-and-trade programs for ozone-season emissions of NO_x from May 1 through September 30 and for annual emissions of SO₂ and NO_x. Our generating facilities in Texas are subject to the CSAPR NO_x ozone season cap-and trade program beginning in 2017. The CSAPR requirements applicable to SO₂ emissions from our affected EGUs were implemented in two stages with fewer SO₂ emission allowances allocated in the second phase, which began in 2017. We do not believe that CSAPR compliance will cause a material adverse impact on our future financial results.

Mercury/HAPs.  The EPA’s Mercury and Air Toxic Standards (“MATS”) rule for EGUs, which was issued in 2011, established numeric emission limits for mercury, non-mercury metals, and acid gases as well as work practice standards for organic HAPs. Compliance with the MATS rule was required by April 16, 2015. In March 2016, the EPA finalized corrections to its November 2014 MATS rule revisions addressing startup and shutdown monitoring instrumentation.

In June 2015, the U.S. Supreme Court found that the EPA failed to properly consider costs when it promulgated the MATS rule. In response to a court ordered remand, in April 2016, the EPA issued a final finding that consideration of cost does not change the Agency’s determination that regulation of HAP emissions from coal- and oil-fired EGUs is appropriate and necessary under CAA section 112. Numerous parties filed petitions for judicial review challenging the EPA’s finding. The United States Court of Appeals for the District of Columbia Circuit is currently holding the cases in abeyance.

We continue to monitor the MATS compliance performance of our units and evaluate approaches to optimize compliance strategies.

Illinois MPS. In 2007, our MISO coal-fired facilities elected to demonstrate compliance with the Illinois Multi-Pollutant Standards (“MPS”), which require compliance with NO_x, SO₂ and mercury emissions limits. We are in compliance with the MPS. In October 2017, the Illinois EPA (“IEPA”) filed a proposed rule with the IPCB that would amend the MPS rule by replacing the two separate group-wide annual emission rate limits that currently apply to our eight downstate Illinois coal-fired stations with tonnage limits for both SO₂ (annual) and NO_x (annual and seasonal) that apply to the eight stations as a single group. Under the MPS proposal as proposed to be amended by the IEPA in February 2018, allowable annual emissions of SO₂ would be 26 percent lower than under the current rule, while NO_x emissions would be 24 percent lower. All other federal and state air quality regulations, including health-based standards, would remain unchanged and in place. The proposed rule also would impose new requirements to ensure the continuous operation of existing SCR control systems during the ozone season, require SCR-controlled units to meet an ozone season NO_x emission rate limit, and set an additional, site-specific annual SO₂ limit for our Joppa Power Station. Dynegy is supportive of the proposed rule as it would provide a number of regulatory and environmental benefits, as well as operating flexibility.

Other Air Emission Initiatives

NAAQS. The CAA requires the EPA to regulate emissions of pollutants considered harmful to public health and the environment. The EPA has established NAAQS for six such pollutants, including SO_2, ozone, and PM_2.5. Each state is responsible for developing a plan (a state implementation plan “SIP”) that will attain and maintain the NAAQS.  These plans may result in the imposition of emission limits on our facilities.

SO₂ NAAQS. The EPA’s initial area designations for the 2010 one-hour SO₂ NAAQS included designating the area where our MISO segment’s Edwards facility is located as nonattainment. In January 2015, Illinois Power Resources Generating, LLC (“IPRG”) entered a Memorandum of Agreement (“MOA”) with the IEPA that voluntarily committed to early limits on Edwards’ allowable one-hour SO₂ emission rate that, in conjunction with reductions to be imposed by the state on other sources, will enable the IEPA to demonstrate attainment with the one-hour SO₂ NAAQS in the Edwards area. The IPCB subsequently approved an IEPA rule that included the emission limits on Edwards as agreed to in the MOA. In February 2018, the EPA approved Illinois’ attainment demonstration for the area.

The EPA will complete area designations for the 2010 one-hour SO₂ NAAQS in three additional rounds before December 31, 2020. The EPA’s second and third rounds of area designations for the one-hour SO₂ NAAQS in July 2016 and December 2017 did not include any nonattainment areas for our facilities.

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Ozone NAAQS. The EPA issued a final rule in October 2015 lowering the ozone NAAQS from 75 to 70 parts per billion. Various parties have filed lawsuits challenging the 2015 ozone NAAQS. In November 2017, the EPA issued an initial round of area designations for the 2015 ozone NAAQS, designating most areas of the United States as attainment/unclassifiable. Several states and other groups have filed lawsuits seeking to compel the EPA to complete designations for all areas of the country. In December 2017, the EPA notified states of expected nonattainment area designations for the 2015 ozone NAAQS. Those areas include areas concerning our Dicks Creek, Miami Fort and Zimmer facilities in Ohio, our Calumet facility in Illinois, and our Wise, Ennis and Midlothian facilities in Texas. The EPA anticipates completing area designations for the 2015 ozone NAAQS in spring 2018.

In November 2017, the EPA denied a petition from nine northeastern states to add several states, including Illinois and Ohio, to the Ozone Transport Region. Eight of the northeastern states have filed a petition for judicial review challenging the EPA’s action. In January 2018, New York and Connecticut filed a lawsuit against the EPA seeking to compel the agency to issue a FIP for the 2008 ozone NAAQS that addresses sources in five upwind states, including Illinois.

In November 2016, the State of Maryland petitioned the EPA to impose additional NO_x emission control requirements on 36 EGUs in five upwind states, including our Zimmer facility, that the State alleges are contributing to nonattainment with the 2008 ozone NAAQS in Maryland. In fall 2017, Maryland and several environmental groups filed lawsuits against the EPA seeking to compel the Agency to act on the State’s petition. While we cannot predict the outcome of the judicial or petition proceedings, given that the Zimmer facility utilizes SCR technology to control NO_x emissions, we do not believe that the result of these proceedings will cause a material adverse impact on our future financial results.

Other. In May 2015, the EPA issued a final rule that eliminates existing exemptions in the SIPs of many states, including Illinois and Ohio, for emissions during periods of startup, shutdown or malfunction (“SSM”). Under the rule, affected states were required to submit corrective SIP revisions by November 2016. Various parties have filed lawsuits challenging the EPA’s SSM SIP rule. The D.C. Circuit Court is currently holding the cases in abeyance.

The nature and scope of potential future requirements concerning the 2010 one-hour SO₂ NAAQS, ozone NAAQS and SSM SIP rule cannot be predicted with confidence at this time. A future requirement for additional emission reductions at any of our coal-fired generating facilities may result in significantly increased compliance costs and could have a material adverse effect on our financial condition, results of operations and cash flows.

New Source Review and Clean Air Act Matters

New Source Review. Since 1999, the EPA has been engaged in a nationwide enforcement initiative to determine whether coal-fired power plants failed to comply with the requirements of the New Source Review and New Source Performance Standard provisions under the 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 (“PSD”), 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.

Zimmer NOVs. In December 2014, the EPA issued an NOV alleging violation of opacity standards at our Zimmer facility. 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. We are unable to predict the outcome of these matters.

Killen and Stuart NOVs. The EPA issued NOVs in December 2014 for Killen and Stuart, and in February 2017 for Stuart, alleging violations of opacity standards. In May and June 2017, we received two letters from the Sierra Club providing notice of its intent to sue various Dynegy entities and the owner and operator of the Killen and Stuart facilities, respectively, alleging violations of opacity standards under the CAA. The Dayton Power and Light Company, the operator of Killen and Stuart, is expected to act on behalf of itself and the co-owners with respect to these matters. We are unable to predict the outcome of these matters.

Texas Regional Haze/FIP/BART. The EPA issued a federal implementation plan (“FIP”) in December 2015 for the State of Texas that imposed regional haze program requirements on numerous coal-fired EGUs. The FIP would require our Coleto Creek facility 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.

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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.

In October 2017, the EPA issued a final rule BART FIP for EGUs in Texas. In contrast to the EPA’s January 2017 proposed rule, the final rule BART FIP establishes an SO₂ emissions intrastate trading program for affected Texas EGUs. The FIP’s intrastate SO₂ trading program will begin in 2019. The EPA final rule also approves Texas’ participation in the CSAPR ozone season NO_x trading program as BART for NO_x and Texas’ determination that EGUs in the State are not subject to BART for particulate matter (“PM”), and determines that the BART FIP is sufficient to address CAA interstate visibility transport requirements for six relevant NAAQS. The EPA’s final rule does not fully resolve the Agency’s obligations as a result of the Fifth Circuit’s remand of the EPA’s December 2016 regional haze FIP, which the EPA intends to address in future action. Various groups have challenged the EPA’s final rule BART FIP, including filing a petition for judicial review and filing an administrative petition with the EPA to reconsider the rule. We intervened in the judicial appeal in support of the EPA.

In a separate final rule issued in September 2017, the EPA withdrew FIP revisions requiring EGUs in Texas to participate in the CSAPR Phase 2 for annual SO₂ and NO_x, determined that Texas sources do not contribute significantly to nonattainment in, or interfere with maintenance by, other states regarding the 1997 NAAQS for PM_2.5, and affirmed that participation in CSAPR meets BART. Various groups have filed a petition for judicial review challenging the rule. We intervened in the appeal in support of the EPA.

While we cannot predict the outcome of litigation related to these matters, a future requirement to install a scrubber at Coleto Creek as a result of either the regional haze FIP or BART FIP could have a material adverse effect on Coleto Creek. Based on the BART FIP’s annual SO₂ allowance allocation for Coleto Creek and anticipated liquidity in the Texas intrastate SO₂ trading program, we do not believe the BART FIP will cause any material financial, operational or cash flow issues for our Coleto Creek facility.

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 MISO 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 March 2019. 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.

The Clean Water Act

The Clean Water Act (“CWA”) and analogous state laws regulate water withdrawals and wastewater discharges at our power generation facilities. Our facilities are authorized to discharge pollutants to waters of the United States by National Pollutant Discharge Elimination System (“NPDES”) permits, which contain discharge limits and monitoring, recordkeeping and reporting requirements. NPDES permits are issued for 5-year periods and are subject to renewal after expiration.

Cooling Water Intake Structures. Cooling water intake structures at our facilities are regulated under CWA Section 316(b). This provision generally requires that the location, design, construction and capacity of cooling water intake structures reflect best technology available (“BTA”) for minimizing adverse environmental impacts. Historically, permitting authorities have developed and implemented BTA standards through NPDES permits on a case-by-case basis using best professional judgment.

In 2014, the EPA issued a final rule for cooling water intake structures at existing facilities. The rule establishes seven BTA alternatives for reducing impingement mortality, including modified traveling screens, closed-cycle cooling, a numeric impingement standard, or a site-specific determination. For entrainment, the permitting authority is required to establish a case-by-case standard considering several factors, including social costs and benefits. Compliance with the rule’s entrainment and impingement mortality standards is required as soon as practicable, but will vary by site depending on several different factors, including determinations made by the state permitting authority and the timing of renewal of a facility’s NPDES permit. Various environmental groups and industry groups filed petitions for judicial review of the EPA’s final rule. The United States Court of Appeals for the Second Circuit held oral argument in September 2017.

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At this time, we estimate the cost of our compliance with the cooling water intake structure rule will be approximately $17 million, with the majority of spend in the 2020-2023 timeframe. This estimate excludes Moss Landing, which is discussed in “California Water Intake Policy” below. Our estimate could change materially depending upon a variety of factors, including site-specific determinations made by states in implementing the rule, the results of impingement and entrainment studies required by the rule, the results of site-specific engineering studies, and the outcome of litigation concerning the rule.

California Water Intake Policy.  The California State Water Board (the “State Water Board”) adopted its Statewide Water Quality Control Policy on the Use of Coastal and Estuarine Waters for Power Plant Cooling (the “Policy”) in 2010. The Policy requires existing power plants to reduce water intake flow rate to a level commensurate with that which can be achieved by a closed cycle cooling system or if that is not feasible, to reduce impingement mortality and entrainment to a level comparable to that achieved by such a reduced water intake flow rate using operational or structural controls, or both.

In 2014, we entered into a settlement agreement with the State Water Board that would resolve a lawsuit we filed with other California power plant owners challenging the Policy. In accordance with the settlement agreement, following a public rulemaking process, in April 2015, the State Water Board approved an amendment to the Policy extending the compliance deadline for Moss Landing from December 31, 2017 to December 31, 2020. Under the settlement agreement, we have implemented operational control measures at Moss Landing for purposes of reducing impingement mortality and entrainment, including the installation of variable speed drive motors on the circulating water pumps in late 2016. In addition, we must evaluate and install supplemental control technology by December 31, 2020. At this time, we preliminarily estimate the cost of our compliance at Moss Landing under the provisions of the settlement agreement will be approximately $5 million in aggregate through 2020.

Effluent Limitation Guidelines. In November 2015, the EPA revised the ELGs for Steam Electric Generating Facilities, which will impose more stringent standards (as individual permits are renewed) for wastewater streams, flue desulfurization, fly ash, bottom ash, and flue gas mercury control. In April 2017, the EPA granted petitions requesting reconsideration of the ELG final rule issued in 2015 and administratively stayed the ELG rule’s compliance date deadlines pending ongoing judicial review of the rule.

The EPA issued a final rule in September 2017 postponing the earliest compliance dates in the ELG rule for bottom ash transport water and FGD wastewater by two years, from November 1, 2018 to November 1, 2020, and the legal challenges have been suspended while EPA reconsiders and likely modifies the rules.

Given the EPA’s decision to reconsider and potentially revise the bottom ash transport water and FGD wastewater provisions of the ELG rule, the rule postponing the ELG rule’s earliest compliance dates for those provisions, and the intertwined relationship of the ELG rule with the Coal Combustion Residuals (“CCR”) rule, which is also being reconsidered by the EPA, as well as pending legal challenges concerning both rules, substantial uncertainty exists regarding our projected capital expenditures for ELG compliance, including the timing of such expenditures. As rulemaking continues to develop and planning and work progress, we continue to review the estimates and related timing of our capital expenditures. The following table presents the projected capital expenditures by period for ELG compliance as of December 31, 2017 assuming the majority of ELG compliance expenditures will be required to occur in the 2019-2023 timeframe:

(amounts in millions)	Less than 1 Year		1 - 3 Years (1)		3 - 5 Years		More than 5 Years		Total
ELG expenditures	$	—	$	199	$	38	$	37	$	274

_________________________________________

(1) Includes $52 million for 2019 and $147 million for 2020.

Coal Combustion Residuals/ Groundwater

The combustion of coal to generate electric power creates large quantities of ash and byproducts that are managed at power generation facilities in dry form in landfills and in wet form in surface impoundments. Each of our coal-fired plants has at least one CCR surface impoundment. At present, CCR is regulated by the states as solid waste.

EPA CCR Rule. The EPA’s CCR rule, which took effect in October 2015, establishes minimum federal requirements for existing and new CCR landfills and surface impoundments, as well as inactive CCR surface impoundments. The requirements include location restrictions, structural integrity criteria, groundwater monitoring, operating criteria, liner design criteria, closure and post-closure care, recordkeeping and notification. The rule allows existing CCR surface impoundments to continue to operate for the remainder of their operating life, but generally would require closure if groundwater monitoring demonstrates that the CCR surface impoundment is responsible for exceedances of groundwater quality protection standards or the CCR surface impoundment does not meet location restrictions or structural integrity criteria. The deadlines for beginning and completing closure vary depending on several factors. Several petitions for judicial review of the CCR rule were filed. The Water Infrastructure Improvements for the Nation Act (the “WIIN Act”), which was enacted in December 2016, provides for EPA review and approval

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of state CCR permit programs in lieu of the self-implementing CCR rule requirements and authorizes the EPA to institute administrative or judicial enforcement actions for violations of state or federal CCR rule requirements.

In September 2017, the EPA granted petitions requesting reconsideration of the CCR rule and agreed to seek to hold in abeyance pending legal challenges to the rule. The EPA anticipates completing its reconsideration of the CCR rule in two phases, with notice and comment rulemaking processes completed by December 2019. In November 2017, the EPA filed a motion for voluntary remand of the CCR rule to address the issues raised in the petitions for review challenging the rule. The United States Court of Appeals for the District of Columbia Circuit subsequently held oral argument in the pending legal challenges, including hearing arguments on whether abeyance, in whole or in part, is appropriate for the cases.

Pursuant to the CCR rule, we have filed notices of intent with the IEPA to close 13 surface impoundments located at our Baldwin, Hennepin, Wood River, Coffeen and Duck Creek facilities. This includes the Hennepin west and Baldwin west fly ash CCR surface impoundments, the closure of which would resolve concerns that were raised in the EPA’s dam safety assessment reports.

Given the EPA’s decision to reconsider and potentially revise the CCR rule and the intertwined relationship of the CCR rule with ELG rule, which is also being reconsidered by the EPA, substantial uncertainty exists regarding our projected compliance costs with the CCR rule, including the timing of such expenditures. At this time, assuming no significant changes to the CCR rule, we estimate the cost of our compliance will be approximately $318 million with the majority of the expenditures in the 2018-2023 timeframe. This estimate is reflected in our AROs. See Asset Retirement Obligations below for further discussion.

Illinois CCR Rule.In 2013, the IEPA filed a proposed rulemaking with the IPCB that would establish processes governing monitoring, corrective action and closure of CCR surface impoundments at power generating facilities. In July 2016, the IEPA issued a revised proposed rule. The IPCB has stayed the rulemaking proceeding since 2015 to allow consideration of the EPA CCR rule, including the impact of legal and legislative actions concerning that rule.

MISO Segment.In 2012, the IEPA issued violation notices alleging violations of groundwater standards onsite at our Baldwin and Vermilion facilities’ CCR surface impoundments. 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 those closure plans.

At our retired Vermilion facility, which is not subject to the CCR rule, we submitted proposed corrective action plans involving closure of two CCR surface impoundments (i.e., the old east and the north impoundments) to the IEPA in 2012, with revised plans submitted in 2014. In May 2017, in response to a request from the IEPA for additional information regarding the closure of these Vermilion surface impoundments, we agreed to perform additional groundwater sampling and further analysis of closure options and riverbank stabilization options. By letter dated January 31, 2018, Prairie Rivers Network provided 60-day notice of its intent to sue our subsidiary Dynegy Midwest Generation, LLC under the federal Clean Water Act for alleged unauthorized discharges from the surface impoundments at our Vermilion facility and alleged related violations of the facility’s NPDES permit. We dispute the allegations and will vigorously defend our position.

In 2012, the IEPA issued violation notices alleging violations of groundwater standards at the Newton and Coffeen facilities’ CCR surface impoundments. We are addressing these CCR surface impoundments in accordance with the CCR rule.

If remediation measures concerning groundwater are necessary at any of our coal-fired MISO Segment facilities, we may incur significant costs that could have a material adverse effect on our financial condition, results of operations and cash flows. At this time we cannot reasonably estimate the costs, or range of costs, of remediation, if any, that ultimately may be required. CCR surface impoundment and landfill closure costs are reflected in our AROs.

Asset Retirement Obligations

AROs are recorded as liabilities in our consolidated balance sheets at their Net Present Value (“NPV”). The following table presents the NPV and projected obligation as of December 31, 2017:

			Projected Obligation by Period
(amounts in millions)	NPV		Less than 1 Year		1 - 3 Years		3 - 5 Years		More than 5 Years		Total
CCR	$	242	$	28	$	59	$	97	$	134	$	318
Non-CCR	87		8		10		26		224		268
Total AROs	$	329	$	36	$	69	$	123	$	358	$	586

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________________________________________

CCR expenditures relate primarily to surface impoundments and ground water monitoring. Non-CCR expenditures relate primarily to surface impoundments and ground water monitoring at non-CCR sites, landfill closures, decommissioning, and asbestos removal.

Climate Change

For the last several years, there has been a robust public debate about climate change and the potential for regulations requiring lower emissions of greenhouse gas (“GHG”), primarily carbon dioxide (“CO₂” and equivalent carbon dioxide “CO_2e”) and methane. Power generating facilities are a major source of GHG emissions. In 2017, our facilities emitted approximately 79 million tons of CO₂. The amounts of CO₂ emitted from our facilities during any time period will depend upon their dispatch rates during the period. We believe that the focus of any federal program attempting to address climate change should include three critical, interrelated elements: (i) the environment, (ii) the economy and (iii) energy security.

Federal Regulation of GHGs.  The EPA has issued several rules concerning GHGs as directly relevant to our facilities since the U.S. Supreme Court’s 2007 decision in Massachusetts v. EPA, which held that GHGs meet the definition of a pollutant under the CAA and that regulation of GHG emissions is authorized by the CAA. We have implemented processes and procedures to report our GHG emissions. The EPA’s Tailoring Rule and Timing Rule phased in GHG emissions annual applicability thresholds for the PSD permit program and the Title V operating permit program beginning in 2011. Application of the PSD program to GHG emissions will require implementation of best available control technology (“BACT”) for new and modified major sources of GHG.

In 2014, the U.S. Supreme Court decided Utility Air Regulatory Group v. EPA, holding that the EPA may not impose PSD or Title V permitting requirements on facilities based solely on emissions of GHGs. While invalidating the EPA’s Tailoring Rule, the Court concluded that the EPA may impose BACT requirements on GHG emissions if a facility is subject to BACT for other pollutants and determined that the EPA may establish a de minimis threshold below which BACT would not be required for GHG emissions, but left it open to the EPA to justify the appropriate threshold. In October 2016, the EPA proposed to establish a GHG significant emission rate of 75,000 tons per year CO_2e for sources that trigger PSD based on their emissions of air pollutants other than GHGs.

Clean Power Plan. In August 2015, the EPA issued the Clean Power Plan to reduce carbon emissions from existing EGUs.  The EPA also separately issued final rules establishing carbon standards for new, modified and reconstructed EGUs (“GHG NSPS”), which include emission standards for new fossil fuel-fired utility boilers based on the performance of a new efficient coal unit implementing partial carbon capture and storage. The EPA expected that by 2030 when the Clean Power Plan was fully implemented, CO₂ emissions from EGUs would be 32 percent below 2005 levels.  Under the Clean Power Plan, states are required to develop plans to achieve interim CO₂ emission rates reductions phased in over the period 2022 to 2029 and the final CO₂ rate for their state by 2030.  The state-specific CO₂ emission performance rates reflect the EPA’s determination that the best system of emission reduction is comprised of three building blocks: increasing the operational efficiency of existing coal-fired EGUs, shifting electricity generation to natural gas-fired EGUs, and increasing electricity generation from renewable sources. Emission trading programs are permitted.

Numerous states, industry associations and labor groups filed lawsuits challenging the Clean Power Plan. In February 2016, the U.S. Supreme Court stayed the rule pending completion of judicial review. Oral argument in the challenges to the Clean Power Plan occurred before the U.S. Court of Appeals for the District of Columbia Circuit in September 2016. Judicial challenges also have been filed against the EPA’s GHG NSPS. The D.C. Circuit Court is currently holding both the Clean Power Plan and GHG NSPS cases in abeyance. We cannot predict the outcome of the litigation involving these matters.

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 NSPS, and, if appropriate, initiate proceedings to suspend, revise or rescind those rules. In October 2017, the EPA issued a proposed rule to repeal the Clean Power Plan. Based on its review of the Clean Power Plan in accordance with Executive Order 13783, the EPA has concluded the Clean Power Plan exceeds the Agency’s authority under the CAA. In December 2017, the EPA issued an advance notice of proposed rulemaking to solicit public comment as the Agency considers proposing emissions guidelines to limit GHG from existing EGUs. We continue to monitor the EPA’s GHG rulemaking efforts regarding EGUs.

The nature and scope of CO₂ emission reduction requirements that ultimately may be imposed on our facilities as a result of the EPA’s EGU CO₂ reduction rules are uncertain at this time, but may result in significantly increased compliance costs and could have a material adverse effect on our financial condition, results of operations and cash flows.

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State Regulation of GHGs.  Many states where we operate generation facilities have, are considering, or are in some stage of implementing, state-only regulatory programs intended to reduce emissions of GHGs from stationary sources as a means of addressing climate change.

California. Our assets in California are subject to the California Global Warming Solutions Act (“AB 32”), which required the California Air Resources Board (“CARB”) to develop a GHG emission control program to reduce emissions of GHGs in the state to 1990 levels by 2020. In April 2015, the Governor of California issued an executive order establishing a new statewide GHG reduction target of 40 percent below 1990 levels by 2030 to ensure California meets its 2050 GHG reduction target of 80 percent below 1990 levels. The CARB and the Province of Québec held their thirteenth joint allowance auction in November 2017 with current vintage auction allowances selling at a clearing price of $15.06 per metric ton and 2020 auction allowances selling at a clearing price of $14.76 per metric ton. The CARB expects allowance prices to be in the $15 to $30 range by 2020. We have participated in quarterly auctions or in secondary markets, as appropriate, to secure allowances for our affected assets.

In July 2017, California enacted legislation extending its GHG cap-and-trade program through 2030 and the CARB adopted amendments to its cap-and-trade regulations that, among other things, established a framework for extending the program beyond 2020 and linking the program to the new cap-and-trade program in Ontario, Canada beginning in January 2018.

Our generating facilities in California emitted approximately 1 million tons of GHGs during 2017. The cost of GHG allowances required to operate our units in California during 2017 was approximately $13 million.  We estimate the cost of GHG allowances required to operate Moss Landing in California during 2018 will be approximately $13 million; however, we expect that the cost of compliance would be reflected in the power market, and the actual impact to gross margin would be largely offset by an increase in revenue.

RGGI. RGGI, a state-driven GHG emission control program that took effect in 2009 was initially implemented by ten New England and Mid-Atlantic states to reduce CO₂ emissions from power plants. The participating RGGI states implemented a cap-and-trade program. Compliance with RGGI can be achieved by reducing emissions, purchasing or trading allowances, or securing offset allowances from an approved offset project. We are required to hold allowances equal to at least 50 percent of emissions in each of the first two years of the three-year control period.

In December 2017, RGGI held its thirty-eighth auction, in which approximately 14.7 million allowances were sold at a clearing price of $3.80 per allowance. We have participated in quarterly RGGI auctions or in secondary markets, as appropriate, to secure allowances for our affected assets. We expect any future changes in the price of RGGI allowances to be reflected in both the forward and locational marginal prices for power and be neutral to our gross margin.

In December 2017, the RGGI states released an updated model rule with changes to the CO₂ budget trading program, including an additional 30 percent reduction in the CO₂ annual cap by the year 2030, relative to 2020 levels. The RGGI cap on CO₂ emissions would decline by 2.275 million tons per year beginning in 2021. Each RGGI state will work to ensure that its program changes are in effect by 2021.

Our generating facilities in Connecticut, Maine, Massachusetts, and New York emitted approximately 9 million tons of CO₂ during 2017. The cost of RGGI allowances required to operate these facilities during 2017 was approximately $41 million. We estimate the cost of RGGI allowances required to operate our affected facilities during 2018 will be approximately $32 million. While the cost of allowances required to operate our RGGI-affected facilities is expected to increase in future years, we expect that the cost of compliance would be reflected in the power market, and the actual impact to gross margin would be largely offset by an increase in revenue. We expect any future changes in the price of RGGI allowances to be reflected in both the forward and locational marginal prices for power and be neutral to our gross margin.

Massachusetts. In August 2017, the Massachusetts Department of Environmental Protection (“MassDEP”) adopted final rules establishing an annual declining limit on aggregate CO₂ emissions from 21 in-state fossil-fuel fired electric generating facilities. The rules establish an allowance trading system under which the annual aggregate EGU sector cap on CO₂ emissions declines from 8.96 million metric tons in 2018 to 1.8 million metric tons in 2050. MassDEP will allocate emission allowances to affected facilities for 2018. Beginning in 2019, allowances will be distributed through a competitive auction process. Limited banking of unused allowances is allowed. The New England Power Generators Association, in which Dynegy is a member, and other generators have filed complaints in Massachusetts superior court challenging the rules. On January 30, 2018, the Massachusetts Supreme Judicial Court decided to review the challenges to MassDEP’s EGU CO₂ rules and transferred the case from the superior court.

Based on current projections of operations for our Massachusetts generating facilities in 2018, we anticipate that allocated allowances will cover CO₂ emissions. We expect the rules will have little or no near-term impact on the financial results of our generating facilities in Massachusetts. However, if upheld, the rules would have an adverse impact on the long-term future of these facilities.

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Virginia. In January 2018, the Virginia Department of Environmental Quality issued a proposed rule to adopt a carbon cap-and trade program for fossil-fuel fired EGUs, including our Hopewell facility, beginning in 2020. The proposed program is based on the RGGI proposed 2017 model rule and is intended to link Virginia to RGGI.

New Jersey. In January 2018, the Governor of New Jersey signed an executive order directing the state's environmental agency and public utilities board to begin the process of rejoining RGGI.

Remedial Laws

We are subject to environmental requirements relating to handling and disposal of toxic and hazardous materials, including provisions of the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) and RCRA and similar state laws. CERCLA imposes strict liability for contributions to contaminated sites resulting from the release of “hazardous substances” into the environment. CERCLA or RCRA could impose remedial obligations with respect to a variety of our facilities and operations.

A number of our older facilities contain quantities of asbestos-containing materials, lead-based paint and/or other regulated materials. Existing state and federal rules require the proper management and disposal of these materials. We have developed a plan that includes proper maintenance of existing non-friable asbestos installations and removal and abatement of asbestos-containing materials where necessary because of maintenance, repairs, replacement or damage to the asbestos itself.

COMPETITION

The power generation business is regional in nature and diverse in terms of industry structure. Demand for power may be met by generation based on several competing technologies, such as natural gas-fired, coal-fired or nuclear generation, as well as alternative energy, including hydro power, synthetic fuels, solar, wind, wood, geothermal, waste heat and solid waste sources. Our power generation business competes with other non-utility generators, regulated utilities, unregulated subsidiaries of regulated utilities, and other energy service companies, including retail power companies and financial institutions. Our ability to compete in the power generation business will be driven in large part by our ability to achieve and maintain a low cost of production, primarily by managing fuel costs and maintaining the reliability of our generating facilities. Our ability to compete will also be impacted by various governmental and regulatory activities, such as those designed to reduce emissions and to promote specific generation types. For example, regulatory requirements for load-serving entities to acquire a percentage of their energy from renewable sources will potentially reduce the demand for energy from coal- and gas-fired facilities, such as those we own and operate. In addition, the extension of federal renewable energy tax credit programs is expected to further continue renewable energy development. Finally, certain of our competitors are receiving subsidies from the states of New York, Connecticut and Illinois for their otherwise uneconomic nuclear plants. At this time, the direct impact on the organized power markets of these subsidy programs is a shift in the generation supply stack that otherwise would not occur absent the subsidies, specifically in NYISO, PJM and MISO.

SIGNIFICANT CUSTOMERS

For the years ended December 31, 2017, 2016 and 2015, customers who individually accounted for more than 10 percent of our consolidated revenues are presented below. No other customer accounted for more than 10 percent of our consolidated revenues during the years ended December 31, 2017, 2016 and 2015.

Customer	2017	2016	2015
PJM	27%	32%	28%
MISO	10%	16%	22%
ISO-NE	14%	10%	N/A

EMPLOYEES

At December 31, 2017, we had approximately 372 employees at our corporate headquarters and approximately 2,117 employees at our facilities, including 229 field-based administrative employees who are part of our support and retail functions. Approximately 997 employees at our operating facilities are subject to collective bargaining agreements with various unions. In 2017, we reached an agreement to extend the expiration of the collective bargaining agreements with IBEW Local 15, which represents employees at our Kincaid facility, IBEW Local 702, which represents employees at our Newton facility, and UWUA Local 600, which represents employees at our Miami Fort and Zimmer facilities. During 2017, the Company did not experience a labor stoppage or a labor dispute at any of its facilities.

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Item 1A.    Risk Factors

FORWARD-LOOKING STATEMENTS

This Form 10-K 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 annual 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:

• expectations regarding the Merger, including beliefs concerning stockholder and regulatory approvals;

• the occurrence of any event that could give rise to the termination of the Merger Agreement, including a termination of the Merger Agreement under circumstances that could require us to pay a termination fee;

• expectations regarding anticipated benefits of the Merger;

• 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;

• beliefs and assumptions about the benefits of state-based subsidies to our market competition, and the corresponding negative impacts on us;

• sufficiency of, access to, and costs associated with coal, fuel oil, and natural gas inventories and transportation thereof;

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

• our ability to mitigate forced outage risk, including managing risk associated with CP in PJM 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 reliability must run (“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 PRIDE and ECI initiatives;

• expectations regarding strengthening the balance sheet, managing debt and improving Dynegy’s leverage profile;

• anticipated timing, outcome, and impact of our expected retirements; and

• beliefs about the costs and scope of ongoing demolition and site remediation efforts.

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Any or all of our forward-looking statements may turn out to be wrong. They can be affected by inaccurate assumptions or by known or unknown risks, uncertainties and other factors, many of which are beyond our control, including those set forth below.

FACTORS THAT MAY AFFECT FUTURE RESULTS

Risks related to the proposed Merger with Vistra Energy

We may be unable to obtain necessary stockholder or regulatory approvals required to complete the Merger Agreement.

On October 30, 2017, we announced the execution of the Merger Agreement with Vistra Energy.

Before the Merger may be completed, both Dynegy and Vistra Energy will need to obtain stockholder approval in connection with the proposed transaction. In addition, various filings must be made with FERC and various regulatory, antitrust and other authorities in the United States. These governmental authorities may impose conditions on the completion, or require changes to the terms, of the Merger, including restrictions or conditions on the business, operations or financial performance of the combined company following completion of the Merger. These conditions or changes, including potential litigation brought in connection with the proposed Merger, could have the effect of delaying completion of the Merger or imposing additional costs on or limiting the revenues of the combined company following the Merger, which could have a material adverse effect on the financial condition, results of operations and cash flows of the combined company and/or cause either Dynegy or Vistra Energy to abandon the Merger.

If we are unable to complete the Merger, we still will incur and will remain liable for significant transaction costs, including legal, accounting, filing, printing and other costs relating to the Merger. Also, depending upon the reasons for not completing the Merger, we may be required to pay Vistra Energy a termination fee of $87 million.

The Merger may not achieve its intended results.

We entered into the Merger Agreement with the expectation that the Merger would result in various benefits, including, among other things, cost savings and operating efficiencies. Achieving the anticipated benefits of the Merger is subject to a number of uncertainties, including whether the businesses of Dynegy and Vistra Energy are integrated in an efficient and effective manner. Failure to achieve these anticipated benefits could result in increased costs, decreases in the amount of expected revenues generated by the combined company and diversion of management’s time and energy and could have an adverse effect on the combined company’s business, financial results and prospects.

We will be subject to business uncertainties and contractual restrictions while the Merger is pending that could adversely affect our financial results.

Uncertainty about the effect of the Merger with Vistra Energy on employees, customers and suppliers may have an adverse effect on our business. Although we intend to take steps designed to reduce any adverse effects, these uncertainties may impair our ability to attract, retain and motivate key personnel until the Merger is completed and for a period of time thereafter, and could cause customers, suppliers and others that deal with us to seek to change existing business relationships.

Employee retention and recruitment may be particularly challenging prior to the completion of the Merger, as employees and prospective employees may experience uncertainty about their future roles with the combined company. If, despite our retention and recruiting efforts, key employees depart or prospective employees fail to accept employment with us because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with the combined company, our financial results could be affected.

The pursuit of the Merger and the preparation for the integration of Dynegy and Vistra Energy may place a significant burden on management and internal resources. The diversion of management attention away from ongoing business concerns and any difficulties encountered in the transition and integration process could affect our business, and our financial condition, results of operations and cash flows.

In addition, we are restricted under the Merger Agreement, without Vistra Energy’s consent, from making certain acquisitions and taking other specified actions until the Merger occurs or the Merger Agreement terminates. These restrictions may prevent us from pursuing otherwise attractive business opportunities and making other changes to our business prior to completion of the Merger or termination of the Merger Agreement.

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Because the market price of shares of Vistra Energy and Dynegy common stock will fluctuate and the exchange ratio is fixed, the market value of the Merger consideration at the date of the closing may vary significantly from the date the Merger Agreement was executed.

Upon completion of the Merger, each outstanding share of Dynegy common stock will be converted into the right to receive 0.652 of a share of Vistra Energy common stock. The number of shares of Vistra Energy common stock to be issued pursuant to the Merger Agreement for each share of Dynegy common stock is fixed and will not change to reflect changes in the market price of Vistra Energy common stock or Dynegy common stock. The market prices of Vistra Energy common stock or Dynegy common stock at the time of completion of the Merger may vary significantly from the market prices of Vistra Energy common stock on the date the Merger agreement was executed.

In addition, the Merger might not be completed until a significant period of time has passed after the respective stockholder meetings. Because the exchange ratio is fixed, the market value of the Vistra Energy common stock issued in connection with the Merger and the Dynegy common stock surrendered in connection with the Merger may be higher or lower than the values of those shares on earlier dates. Stock price changes may result from market assessment of the likelihood that the Merger will be completed, changes in the business, operations or prospects of Vistra Energy or Dynegy prior to or following the Merger, litigation or regulatory considerations, general business, market, industry or economic conditions and other factors both within and beyond the control of Vistra Energy and Dynegy. Neither Vistra Energy nor Dynegy is permitted to terminate the Merger Agreement solely because of changes in the market price of either company’s common stock.

The Merger Agreement contains provisions that limit Dynegy’s ability to pursue alternatives to the Merger, could discourage a potential competing acquirer of Dynegy from making a favorable alternative transaction proposal and, in certain circumstances, could require Dynegy to pay a termination fee to Vistra Energy.

Under the Merger Agreement, Dynegy is restricted from entering into alternative transactions. Unless and until the Merger Agreement is terminated, subject to specified exceptions, Dynegy is restricted from soliciting, initiating or knowingly encouraging, inducing or facilitating, or participating in any discussions or negotiations with any person regarding, or cooperating in any way with any person with respect to, any alternative proposal or any inquiry or proposal that would reasonably be expected to lead to an alternative proposal. While Dynegy’s Board of Directors is permitted to change its recommendation to stockholders prior to the special meeting under certain circumstances, namely if Dynegy is in receipt of a superior proposal or an intervening event has occurred, before Dynegy’s Board of Directors changes its recommendation to stockholders in such circumstances, Dynegy must, if requested by Vistra Energy, negotiate with Vistra Energy regarding potential amendments to the Merger Agreement. Dynegy may terminate the Merger Agreement and enter into an agreement with respect to a superior proposal only if specified conditions have been satisfied, including compliance with the provisions of the Merger Agreement restricting solicitation of alternative proposals and requiring payment of a termination fee in certain circumstances. These provisions could discourage a third party that may have an interest in acquiring all or a significant part of Dynegy from considering or proposing such an acquisition, even if such third party were prepared to pay consideration with a higher per share cash or market value than the market value proposed to be received or realized in the merger, or could result in a potential competing acquirer proposing to pay a lower price than it would otherwise have proposed to pay because of the added expense of the termination fee that may become payable in certain circumstances. As a result of these restrictions, Dynegy may not be able to enter into an agreement with respect to a more favorable alternative transaction without incurring potentially significant liability to the other.

If the Merger Agreement is terminated because Dynegy’s Board of Directors changes its recommendation to stockholders or Dynegy enters into a definitive agreement for a superior proposal, Dynegy will be required to pay Vistra Energy a termination fee of $87 million. If such a termination fee is payable, the payment of this fee could have an adverse effect on the financial condition, results of operations and cash flows of Dynegy.

Current Dynegy stockholders will have a reduced ownership and voting interest after the Merger and will exercise less influence over management of the combined company.

Upon completion of the Merger, Dynegy stockholders will own approximately 21 percent of the combined company. Dynegy stockholders currently have the right to vote for Dynegy’s Board of Directors and on other matters affecting Dynegy. When the Merger occurs, each Dynegy stockholder will receive 0.652 shares of Vistra Energy common stock per share of Dynegy common stock, with a percentage ownership of the combined company that is significantly smaller than the stockholders’ percentage ownership of Dynegy prior to the Merger. As a result of these reduced ownership percentages, current Dynegy stockholders will have less influence on the management and policies of the combined company than they now have with respect to Dynegy.

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Risks Related to the Operation of Our Business

Wholesale and retail power prices are subject to significant volatility and because many of our power generation facilities operate without long-term power sales agreements, our revenues and profitability are subject to wide fluctuations.

The majority of our facilities operate as “merchant” facilities without long-term power sales agreements. As a result, we largely sell electric energy, capacity and ancillary services into the wholesale energy spot market or into other wholesale and retail power markets on a short-term basis and are not guaranteed any rate of return on our capital investments. Consequently, there can be no assurance that we will be able to sell any or all of the electric energy, capacity or ancillary services from those facilities at commercially attractive rates or that our facilities will be able to operate profitably. We depend, in large part, upon prevailing market prices for power, capacity and fuel. Given the volatility of commodity power prices, to the extent we do not secure long-term power sales agreements for the output of our power generation facilities, our revenues and profitability will be subject to volatility, and our financial condition, results of operations and cash flows could be materially adversely affected. Factors that may materially impact the power markets and our financial results include:

• addition of new supplies of power from existing competitors or new market entrants as a result of the development of new generation plants, expansion of existing plants or additional transmission capacity;

• uneconomic generation kept on line by utilities, aided by state-based subsidies;

• environmental regulations and legislation;

• weather conditions, including extreme weather conditions and seasonal fluctuations;

• electric supply disruptions including plant outages;

• basis risk from transmission losses and congestion and changes in power transmission infrastructure;

• development of new technologies for the production of natural gas;

• natural gas and coal supply disruptions;

• fuel price volatility;

• economic conditions;

• capacity performance, or similar construct, requirements and penalties;

• increased competition or price pressure driven by generation from renewable sources and other subsidized generation;

• regulatory constraints on pricing (current or future), including RTO and ISO rules, policies and actions, or the functioning of the energy trading markets and energy trading generally;

• the existence and effectiveness of demand-side management; and

• conservation efforts and energy efficiency rules and the extent to which they impact electricity demand.

Our commercial strategies for our wholesale and retail businesses may not be executed as planned, may result in lost opportunities or adversely affect financial performance.

We seek to commercialize our assets through sales arrangements of various types. In doing so, we attempt to balance a desire for greater predictability of earnings and cash flows in the short- and medium-terms with our expectation that commodity prices will rise over the longer term, creating upside opportunities for those with unhedged generation volumes. Our ability to successfully execute this strategy is dependent on a number of factors, many of which are outside our control, including market liquidity and design, correlation risk, commodity price cycles, the availability of counterparties willing to transact with us or to transact with us at prices we think are commercially acceptable, the availability of liquidity to post collateral in support of our derivative instruments and the reliability of the systems and models comprising our commercial operations function. The availability of market liquidity and willing counterparties could be negatively impacted by poor economic and financial market conditions, including impacts on financial institutions and other current and potential counterparties as well as counterparties’ views of our creditworthiness. If we are unable to transact in the short- and medium-terms, our financial condition, results of operations and cash flows will be subject to significant uncertainty and volatility. Alternatively, significant power sales for any such period may precede a run-up in commodity prices, resulting in lost up-side opportunities.

Further, financial performance may be adversely affected if we are unable to effectively manage our power portfolio. A portion of the generation power portfolio is used to provide power to wholesale and retail customers. To the extent portions of the power portfolio are not needed for that purpose, generation output is sold in the wholesale market. To the extent our power portfolio is not sufficient to meet the requirements of our customers, we must purchase power in the wholesale power markets. Our financial results may be negatively affected if we are unable to manage the power portfolio and cost-effectively meet the requirements of our customers.

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A decline in market liquidity and our ability to manage our counterparty credit risk could adversely affect us.

Our counterparties may experience deteriorating credit. These conditions could cause counterparties in the natural gas, coal and power markets, particularly in the energy commodity derivative markets that we rely on for our hedging activities, to withdraw from participation in those markets. If multiple parties withdraw from those markets, market liquidity may be threatened, which in turn could adversely impact our business. Additionally, these conditions may cause our counterparties to seek bankruptcy protection under Chapter 11 or liquidation under Chapter 7 of the Bankruptcy Code. Our credit risk may be exacerbated to the extent collateral held by us cannot be realized or is liquidated at prices not sufficient to recover the full amount due to us. There can be no assurance that any such losses or impairments to the carrying value of our financial assets would not materially and adversely affect our financial condition, results of operations and cash flows. In addition, retail sales subject us to credit risk through competitive electricity supply activities to serve commercial and industrial companies and governmental entities. This risk represents the loss that may be incurred due to the nonpayment of a customer’s account balance, as well as the loss from the resale of energy previously committed to serve that customer, which could have a material adverse effect on our financial condition, results of operations and cash flows.

We are exposed to the risk of fuel and fuel transportation cost increases and interruptions in fuel supplies.

We purchase the fuel requirements for many of our power generation facilities, primarily those that are natural gas-fired, under short-term contracts or on the spot market. As a result, we face the risks of supply interruptions and fuel price volatility, as fuel deliveries may not exactly match those required for energy sales.

Further, any changes in the costs of coal, fuel oil, natural gas or transportation rates and changes in the relationship between such costs and the market prices of power will affect our financial results. If we are unable to procure fuel for physical delivery at prices we consider favorable, our financial condition, results of operations and cash flows could be materially adversely affected.

Operation of power generation facilities involves significant risks customary to the power industry that could have a material adverse effect on our financial condition, results of operations and cash flows.

The ongoing operation of our facilities involves risks customary to the power industry that include the breakdown or failure of equipment or processes, operational and safety performance below expected levels and the inability to transport our product to customers in an efficient manner due to a lack of transmission capacity. Unplanned outages of generating units, including extensions of scheduled outages due to mechanical failures or other problems, occur from time to time and are an inherent risk of our business. Any unexpected failure, including failure associated with breakdowns, forced outages or any unanticipated capital expenditures, could result in reduced profitability, or with respect to capacity performance, performance incentive or similar construct, significant penalties or exceptionally high real-time LMPs. Unplanned outages typically increase our operation and maintenance expenses and may reduce our revenues as a result of selling fewer MW or require us to incur significant costs as a result of running one of our higher cost units or obtaining replacement power from third parties in the open market to satisfy our forward power sales obligations. If we are unsuccessful in operating our facilities efficiently, such inefficiency could have a material adverse effect on our financial condition, results of operations and cash flows.

Certain of our competitors may receive state-based subsidies that could materially adversely affect our financial condition, results of operations and cash flows.

A number of states in which we operate have either enacted or are considering regulations or legislation to subsidize otherwise uneconomic nuclear plants, and attempt to incent the development of new renewable resources as well as increase energy efficiency investments. In addition, in December 2015, federal renewable energy tax credits, including the wind power production tax credit and solar investment tax credits, were extended as part of the Consolidated Appropriations Act of 2016. Dynegy has actively challenged these types of programs and will continue to do so, including initiating legal challenges where appropriate. At this time, the direct impact on the organized power markets is a change in the generation supply stack created by the continued operation of subsidized resources that would retire absent the subsidies. The net combined impact of existing subsidy programs on Dynegy is uncertain at this time. Continued growth of energy subsidies could have a material adverse effect on our financial condition, results of operations and cash flows.

Our costs of compliance with existing environmental requirements are significant, and costs of compliance with new environmental requirements or factors could materially adversely affect our financial condition, results of operations and cash flows.

Our business is subject to extensive and frequently changing environmental regulation by federal, state and local authorities. Such environmental regulation imposes, among other things, capital and operating expenditures, restrictions, liabilities and obligations in connection with the generation, handling, use, transportation, treatment, storage and disposal of certain substances and wastes, including CCR, and in connection with spills, releases and emissions of various substances (including carbon emissions)

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into the environment, as well as environmental impacts associated with cooling water intake structures. Existing environmental laws and regulations may be revised or reinterpreted, new laws and regulations may be adopted or may become applicable to us or our facilities, and litigation or enforcement proceedings could be commenced against us. Proposals being considered by federal and state authorities (including proposals regarding cooling water intake structures and carbon) could, if and when adopted or enacted, require us to make substantial capital and operating expenditures, impair assets, or limit or terminate operation of certain of our facilities. If any of these events occur, our financial condition, results of operations and cash flows could be materially adversely affected.

Many environmental laws require approvals or permits from governmental authorities before construction, modification or operation of a power generation facility may commence. Certain environmental permits must be renewed periodically in order for us to continue operating our facilities. The process of obtaining and renewing necessary permits can be lengthy and complex and can sometimes result in the establishment of permit conditions that make the project or activity for which the permit was sought unprofitable or otherwise unattractive. Even where permits are not required, compliance with environmental laws and regulations can require significant capital and operating expenditures. We are required to comply with numerous environmental laws and regulations, and to obtain numerous governmental permits when we modify and operate our facilities. If there is a delay in obtaining any required environmental regulatory approvals or permits, if we fail to obtain any required approval or permit, or if we are unable to comply with the terms of such approvals or permits, the operation of our facilities may be interrupted or become subject to additional costs and/or legal challenges. Further, changed interpretations of existing regulations may subject historical maintenance, repair and replacement activities at our facilities to claims of noncompliance. With the trend toward stricter environmental standards and more extensive regulatory and permitting requirements, our capital and operating environmental expenditures are likely to be substantial and may significantly increase in the future. As a result, our financial condition, results of operations and cash flows could be materially adversely affected.

Our business is subject to complex government regulation. Changes in these regulations or in their implementation may affect costs of operating our facilities or our ability to operate our facilities, or increase competition, any of which would negatively impact our results of operations.

We are subject to extensive federal, state and local laws and regulations governing the generation and sale of energy commodities in each of the jurisdictions in which we have operations. Compliance with these ever-changing laws and regulations requires expenses (including legal representation) and monitoring, capital and operating expenditures. Potential changes in laws and regulations that could have a material impact on our business include: the introduction, or reintroduction, of rate caps or pricing constraints; inability to pass on costs to customers; state regulatory initiatives, including subsidized generation; increased credit standards, collateral costs or margin requirements, as well as reduced market liquidity, as a result of potential OTC market regulation; or a variation of these. Furthermore, these and other market-based rules and regulations are subject to change at any time, and we cannot predict what changes may occur in the future or how such changes might affect any facet of our business.

The costs and burdens associated with complying with the increased number of regulations may have a material adverse effect on us if we fail to comply with the laws and regulations governing our business or if we fail to maintain or obtain advantageous regulatory authorizations and exemptions. Failure to comply with such requirements could result in the shutdown of any noncompliant facility, the imposition of liens or fines, or civil or criminal liability. Moreover, increased competition within the sector resulting from potential legislative changes, regulatory changes or other factors may create greater risks to the stability of our power generation earnings and cash flows.

Regulators, politicians, non-governmental organizations and other private parties have expressed concern about GHG emissions and the potential risks associated with climate change and are taking actions which could materially adversely affect our financial condition, results of operations and cash flows.

For the last several years, there has been a robust public debate about climate change and the potential for regulations requiring lower emissions of GHG, primarily CO₂ and methane. As discussed in Item 1. Business-Environmental Matters, at the federal and state levels, rules are in effect and policies are under development to regulate GHG emissions, thereby effectively putting a cost on such emissions in order to create financial incentives to reduce them. Power generating facilities are a major source of GHG emissions. We cannot confidently predict the final outcome of the current debate on climate change nor can we predict with confidence the ultimate requirements of proposed, anticipated or existing federal and state legislation and regulations intended to address climate change. These activities, and the highly politicized nature of climate change, suggest a trend toward increased regulation of GHG that could result in a material adverse effect on our financial condition, results of operations and cash flows. Existing and anticipated federal and state regulations intended to address climate change may significantly increase the cost of providing electric power, resulting in far-reaching and significant impacts on us and others in the power generation industry over time. It is possible that federal and state actions intended to address climate change could result in costs assigned to GHG emissions that we would not be able to fully recover through market pricing or otherwise. If capital and/or operating costs related to compliance with regulations intended to address climate change become great enough to render the operations of certain plants uneconomical, we could, at our option and subject to any applicable financing agreements or other obligations,

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reduce operations or cease to operate such plants and forego such capital and/or operating costs. Though we consider our largest risk related to climate change to be legislative and regulatory changes, we are subject to physical risks inherent in industrial operations including severe weather events such as hurricanes and tornadoes. To the extent that changes in climate affect changes in weather patterns (such as more severe weather events), we could be adversely affected.

Availability and cost of emission allowances could materially impact our costs of operations.

We are required to maintain, either through allocation or purchase, sufficient emission allowances to support our operations in the ordinary course of operating our power generation facilities. These allowances are used to meet our obligations imposed by various applicable environmental laws, and the trend toward more stringent regulations (including regulations regarding GHG emissions) will likely require us to obtain new or additional emission allowances. If our operational needs require more than our allocated quantity of emission allowances, we may be forced to purchase such allowances on the open market, which could be costly. If we are unable to maintain sufficient emission allowances to match our operational needs, we may have to curtail our operations so as not to exceed our available emission allowances, or install costly new emissions controls. As we use the emissions allowances that we have purchased on the open market, costs associated with such purchases will be recognized as an operating expense. If such allowances are available for purchase, but only at significantly higher prices, their purchase could materially increase our costs of operations in the affected markets and materially adversely affect our financial condition, results of operations and cash flows.

Competition in wholesale and retail power markets, together with subsidized generation, may have a material adverse effect on our financial condition, results of operations and cash flows.

Our power generation business competes with other non-utility generators, regulated utilities, unregulated subsidiaries of regulated utilities, other energy service companies and financial institutions in the sale of electric energy, capacity and ancillary services, as well as in the procurement of fuel, transmission and transportation services. Moreover, aggregate demand for power may be met by generation capacity based on several competing technologies, as well as power generating facilities fueled by alternative or renewable energy sources, including hydroelectric power, synthetic fuels, solar, wind, wood, geothermal, waste heat and solid waste sources. Regulatory initiatives designed to enhance and/or subsidize renewable generation increases competition from these types of facilities.

We also compete against other energy merchants on the basis of our relative operating skills, financial position and access to credit sources. Electric energy customers, wholesale energy suppliers and transporters often seek financial guarantees, credit support such as letters of credit and other assurances that their energy contracts will be satisfied. Companies with which we compete may have greater resources in these areas. Over time, some of our plants may become unable to compete because of subsidized generation, including public utility commission supported power purchase agreements, and the construction of new plants. Such new plants could have a number of advantages including: more efficient equipment, newer technology that could result in fewer emissions or more advantageous locations on the electric transmission system. Additionally, these competitors may be able to respond more quickly to new laws and regulations because of the newer technology utilized in their facilities or the additional resources derived from owning more efficient facilities.

Other factors may contribute to increased competition in wholesale power markets. New forms of capital and competitors have entered the industry, including financial investors who perceive that asset values are at levels below their true replacement value. As a result, a number of generation facilities in the U.S. are now owned by lenders and investment companies. Furthermore, mergers and asset reallocations in the industry could create powerful new competitors. Under any scenario, we anticipate that we will face competition from numerous companies in the industry.

In addition, our retail marketing efforts compete for customers in a competitive environment, which impacts the margins that we can earn on the volumes we are able to serve. Further, with retail competition, residential customers where we serve load can switch to and from competitive electric generation suppliers for their energy needs. If fewer customers switch to another supplier than anticipated, the load we must serve will be greater and, if market prices have increased, our costs will increase due to the need to go to the market to cover the incremental supply obligation. If more customers switch to another supplier than anticipated, the load we must serve will be lower and, if market prices have decreased, we could lose opportunities in the market. To the extent that competition increases, our financial condition, results of operations and cash flows may be materially adversely affected.

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Generally, we do not own or control transmission facilities required to sell wholesale power from our generation facilities. If transmission services are inadequate, our ability to sell and deliver wholesale power may be materially adversely affected. Furthermore, RTOs and ISOs administer the transmission infrastructure and market, which are subject to changes in structure and operation and impose various pricing limitations. These changes and pricing limitations may affect our ability to deliver power to the market that would, in turn, adversely affect the profitability of our generation facilities.

With the exception of EEI, which owns and controls transmission lines interconnecting the Joppa facility in EEI’s control area to MISO, Tennessee Valley Authority and Louisville Gas and Electric Company, we do not own or control the transmission facilities required to deliver the power from our generation facilities to the market. If transmission services from these facilities are unavailable or disrupted, or if the transmission capacity infrastructure is inadequate, our ability to sell and deliver wholesale power may be materially adversely affected, which could result in reduced profitability, or with respect to capacity performance in PJM and performance incentives in ISO-NE, significant penalties. RTOs and ISOs provide transmission services, administer transparent and competitive power markets and maintain system reliability. Many of these RTOs and ISOs operate in the real-time and day-ahead markets in which we sell energy. The RTOs and ISOs that oversee most of the wholesale power markets impose price limitations, offer caps, capacity performance requirements, penalties, and other mechanisms to guard against the potential exercise of market power in these markets. Price limitations and other regulatory mechanisms may adversely affect the profitability of our generation facilities that sell energy and capacity into the wholesale power markets. Problems or delays that may arise in the formation and operation of maturing RTOs and similar market structures, or changes in geographic scope, rules or market operations of existing RTOs, may also affect our ability to sell, the prices we receive or the cost to transmit power produced by our generating facilities. Market design as well as rules governing the various regional power markets may also change from time to time, which could materially adversely affect our financial condition, results of operations and cash flows.

Our Retail business is subject to the risk that sensitive customer data may be compromised, which could result in an adverse impact to our reputation and/or the results of operations of the Retail business.

The Retail business requires access to sensitive customer data in the ordinary course of business. Examples of sensitive customer data are names, addresses, account information, historical electricity usage, expected patterns of use, payment history, credit bureau data and bank account information. The Retail business may need to provide sensitive customer data to vendors and service providers who require access to this information in order to provide services, such as call center operations, to the Retail business. If a significant breach occurred, our reputation may be adversely affected, customer confidence may be diminished or we may be subject to legal claims, any of which may contribute to the loss of customers and have a negative impact on our business and/or financial condition, results of operations and cash flows.

Unauthorized hedging and related activities by our employees could result in significant losses.

We intend to continue our commercial strategy, which emphasizes forward power sales opportunities intended to reduce the market price exposure of the Company to power price declines. We have various internal policies and procedures designed to monitor hedging activities and positions. These policies and procedures are designed, in part, to prevent unauthorized purchases or sales of products by our employees. We cannot assure, however, that these steps will detect and prevent inaccurate reporting and all other violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved. A significant policy violation that is not detected could result in a substantial financial loss.

Our risk management policies cannot fully eliminate the risk associated with our commodity hedging activities.

Our asset-based power position as well as our power marketing, fuel procurement and other commodity hedging activities expose us to risks of commodity price movements. We attempt to manage this exposure through enforcement of established risk limits and risk management procedures. These risk limits and risk management procedures may not work as planned and cannot eliminate all risks associated with these activities. Even when our policies and procedures are followed, and decisions are made based on projections and estimates of future performance, results of operations may be diminished if the judgments and assumptions underlying those decisions prove to be incorrect. Factors, such as future prices and demand for power and other energy-related commodities, become more difficult to predict and the calculations become less reliable the further into the future estimates are made. As a result, we cannot fully predict the impact that our commodity hedging activities and risk management decisions may have on our business and/or financial condition, results of operations and cash flows.

Strikes, work stoppages or an inability to negotiate future collective bargaining agreements on commercially reasonable terms could have a material adverse effect on our financial condition, results of operations and cash flows.

A majority of the employees at our facilities are subject to collective bargaining agreements with various unions. Additionally, unionization activities, including votes for union certification, could occur at the non-union generating facilities in our fleet. If union employees strike, participate in a work stoppage or slowdown or engage in other forms of labor strike or disruption, we could experience reduced power generation or outages if replacement labor is not procured. The ability to procure such replacement labor is uncertain. Strikes, work stoppages or an inability to negotiate future collective bargaining agreements

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on commercially reasonable terms could have a material adverse effect on our financial condition, results of operations and cash flows.

Terrorist attacks and/or cyber-attacks may result in our inability to operate and fulfill our obligations, and could result in material repair costs.

As a power generator, we face heightened risk of terrorism, including cyber terrorism, either by a direct act against one or more of our generating facilities or an act against the transmission and distribution infrastructure that is used to transport our power.  We rely on information technology networks and systems, including third party cloud systems, to operate our generating facilities, engage in asset management activities, and process, transmit and store electronic information. Security breaches of this information technology infrastructure, including cyber-attacks and cyber terrorism, could lead to system disruptions, generating facility shutdowns or unauthorized disclosure of confidential information related to our employees, vendors and counterparties, including retail counterparties.

Systemic damage to one or more of our generating facilities and/or to the transmission and distribution infrastructure could result in our inability to operate in one or all of the markets we serve for an extended period of time. If our generating facilities are shut down, we would be unable to respond to the ISOs and RTOs or fulfill our obligations under various energy and/or capacity arrangements, resulting in lost revenues and potential fines, penalties and other liabilities. Pervasive cyber-attacks across our industry could affect the ability of ISOs and RTOs to function in some regions. The cost to restore our generating facilities after such an occurrence could be material.

Risks Related to Our Financial Structure

Our indebtedness could adversely affect our ability in the future to raise additional capital to fund our operations. It could also expose us to the risk of increased interest rates and limit our ability to react to changes in the economy, or our industry as well as impact our cash available for distribution.

As of December 31, 2017, we had approximately $8.6 billion of total indebtedness and approximately $8.3 billion of indebtedness net of cash. Our debt could have negative consequences for our financial condition including:

• increasing our vulnerability to general economic and industry conditions;

• requiring a substantial portion of our cash flow from operations to be dedicated to the payment of principal and interest on our indebtedness, therefore reducing our ability to use our cash flow to fund our operations, capital expenditures and future business opportunities;

• limiting our ability to enter into long-term power sales or fuel purchases which require credit support;

• limiting our ability to fund operations or future acquisitions;

• restricting our ability to make certain distributions with respect to our capital stock and the ability of our subsidiaries to make certain distributions to us, in light of restricted payment and other financial covenants in our credit facilities and other financing agreements;

• inhibiting the growth of our stock price;

• exposing us to the risk of increased interest rates because certain of our borrowings, including borrowings under our revolving credit facility, are at variable rates of interest;

• limiting our ability to obtain additional financing for working capital including collateral postings, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes; and

• limiting our ability to adjust to changing market conditions and placing us at a competitive disadvantage compared to our competitors who may have less debt.

We may not be successful in obtaining additional capital for these or other reasons. Furthermore, we may be unable to refinance or replace our existing indebtedness on favorable terms or at all upon the expiration or termination thereof. Our failure to obtain additional capital or enter into new or replacement financing arrangements when due may constitute a default under such existing indebtedness and may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our existing credit facilities contain, and agreements we enter into in the future may contain, covenants that could restrict our financial flexibility.

Our existing credit facilities contain covenants imposing certain requirements on our business. These requirements may limit our ability to take advantage of potential business opportunities as they arise and may adversely affect the conduct of our current business, including restricting our ability to finance future operations and capital needs and limiting our ability to engage in other business activities. These covenants could place restrictions on our ability and the ability of our operating subsidiaries

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to, among other things:

• declare or pay dividends, repurchase or redeem stock or make other distributions to stockholders;

• incur additional debt or issue some types of preferred shares;

• create liens;

• make certain restricted investments;

• enter into transactions with affiliates;

• enter into any agreements which limit the ability of certain subsidiaries to make dividends or otherwise transfer cash or assets to us or certain other subsidiaries;

• sell or transfer assets; and

• consolidate or merge.

Agreements we enter into in the future may also have similar or more restrictive covenants. A breach of any covenant in the existing credit facilities or the agreements governing our other indebtedness would result in a default. A default, if not waived, could result in acceleration of the debt outstanding under any such agreement and in a default with respect to, and acceleration of, the debt outstanding under any other debt agreements. The accelerated debt would become due and payable immediately. If that should occur, we may not be able to make all of the required payments or borrow sufficient funds to refinance our debt obligations. Even if new financing were then available, it may not be on terms that are acceptable to us.

Our sub-investment grade status may adversely impact our commercial operations, increase our liquidity requirements and increase the cost of refinancing opportunities. We may not have adequate liquidity to post required amounts of additional collateral.

Our corporate family credit rating is currently below investment grade and we cannot assure you that our credit ratings will improve, or that they will not decline, in the future. Our credit ratings may affect the evaluation of our creditworthiness by trading counterparties and lenders, which could put us at a disadvantage to competitors with higher or investment grade ratings. We use a portion of our capital resources, in the form of cash, short-term investments, lien capacity and letters of credit, to satisfy these counterparty collateral demands. Our commodity agreements are tied to market pricing and may require us to post additional collateral under certain circumstances. If we are unable to reliably forecast or anticipate collateral calls or if market conditions change such that counterparties are entitled to additional collateral, our liquidity could be strained and may have a material adverse effect on our financial condition, results of operations and cash flows. Factors that could trigger increased demands for collateral include changes in our credit rating or liquidity and changes in commodity prices for power and fuel, among others. Should our ratings continue at their current levels, or should our ratings be further downgraded, we would expect these negative effects to continue and, in the case of a downgrade, become more pronounced.

If our goodwill, amortizable intangible assets, or long-lived assets become impaired, we may be required to record a significant charge to earnings.

We have significant goodwill, amortizable intangible assets and long-lived assets recorded on our balance sheet. In accordance with the Generally Accepted Accounting Principles of the United States of America (“GAAP”), goodwill is required to be tested for impairment at least annually. Additionally, we review goodwill, our amortizable intangible assets and long-lived assets for impairment when events or changes in circumstances indicate the carrying value of the asset may not be recoverable. Factors that may be considered include a decline in future cash flows, slower growth rates in the energy industry, and a sustained decrease in the price of our common stock.

We have performed our annual goodwill assessment and determined that no impairment was required. Please read Critical Accounting Policies—Goodwill Impairment for further discussion. However, further goodwill impairment testing will be performed in future periods and may result in an impairment loss, which could be material. In 2017, in connection with our asset sales, we wrote off approximately $27 million of goodwill. We performed certain asset impairment analyses in 2017 and, as a result, recorded impairment charges of $148 million. Please read Note 8—Property, Plant and Equipment-Impairments for further discussion.

Issuances or acquisitions of our common stock, or sales or dispositions of our common stock by stockholders, that result in an ownership change as defined in Internal Revenue Code (“IRC”) §382 could further limit our ability to use our federal net operating losses or alternative minimum tax credits to offset our future taxable income.

If an “ownership change,” as defined in Section 382 of the IRC (“IRC §382”) occurs, the amount of NOLs and AMT credits that could be used in any one year following such ownership change could be substantially limited. In general, an “ownership change” would occur when there is a greater than 50 percentage point increase in ownership of a company's stock by stockholders, each of which owns (or is deemed to own under IRC §382) 5 percent or more of such company's stock. Given IRC §382’s broad definition, an ownership change could be the unintended consequence of otherwise normal market trading in our stock that is

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outside our control. Dynegy has already experienced two “ownership changes” under IRC §382 that limit the use of our NOLs and AMT credits that existed at the time and prior to our emergence from bankruptcy. NOLs that have been generated subsequent to our emergence from bankruptcy are not currently subject to the limitations imposed by IRC §382. If, however, there is another “ownership change,” the utilization of all NOLs and AMT credits existing at that time would be subject to additional annual limitations based upon a formula provided under IRC §382 that is based on the fair market value of the Company and prevailing interest rates at the time of the ownership change. 

The effects of the Tax Cuts and Jobs Act on our business have not yet been fully analyzed and could have an adverse effect on our financial statements.

The TCJA, enacted on December 22, 2017, reduces the U.S. federal corporate tax rate from 35 percent to 21 percent. This resulted in a reduction to our net deferred tax assets with a corresponding reduction to our valuation allowance. The TCJA also repealed the corporate AMT, which resulted in a $223 million tax benefit for Dynegy related to the expected refund of our excess AMT credits. 

The amounts discussed above are considered to be provisional as we continue to assess available tax methods and elections and refine our computations.  Additionally, further regulatory guidance related to the TCJA may be issued in 2018 which could result in changes to our assessment and current estimates. We continue to analyze the TCJA and its possible effects on the Company. Any changes or clarifications to the TCJA may change our expectation on the amount of our net deferred tax assets and our expectation on the amount or timing of the AMT credit refunds.

Item 1B.    Unresolved Staff Comments

Not applicable.

Item 2.    Properties

We have included descriptions of the location and general character of our principal physical operating properties by segment in “Item 1. Business,” which is incorporated herein by reference. Substantially all of the Company’s assets are pledged as collateral to secure the repayment of, and our other obligations under, the Credit Agreement. Please read Note 13—Debt for further discussion.

Our principal executive office located in Houston, Texas, is held under a lease that expires in 2022. We also lease additional offices in Illinois and Ohio.

Item 3. Legal Proceedings

Please read Note 16—Commitments and Contingencies—Legal Proceedings for a description of our material legal proceedings, which is incorporated herein by reference.

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 to this Annual Report on Form 10-K.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our authorized capital stock consists of 420 million shares of common stock, with a par value of $0.01 per share. Our common stock is listed on the NYSE under the symbol “DYN” and has been trading since October 3, 2012, following our emergence from bankruptcy on October 1, 2012 (the “Plan Effective Date”). Based on information provided by our transfer agent, there were 2,349 stockholders of record of our common stock as of February 8, 2018.

On April 1, 2015, pursuant to the ERC Purchase Agreement, 3,460,053 shares of common stock of Dynegy were issued as part of the consideration for the EquiPower Acquisition, valued at approximately $105 million based on the that day’s closing price of Dynegy’s common stock. Please read Note 3—Acquisitions and Divestitures for further discussion.

On February 7, 2017, pursuant to the terms of the Stock Purchase Agreement with Terawatt Holdings, LLC (“Terawatt”), 13,711,152 shares of common stock of Dynegy (the “PIPE Shares”) were issued to Terawatt for $150 million (the “PIPE Transaction”) as part of the consideration for the ENGIE Acquisition. Please read Note 3—Acquisitions and Divestitures for further discussion.

On February 2, 2017 upon Genco’s emergence from bankruptcy, Dynegy issued 8,653,038 seven-year warrants (the “2017 Warrants”). Each 2017 Warrant entitles the holder thereof to purchase one share of Dynegy Common Stock at an exercise price of $35.00 per share. The 2017 Warrants will have a seven-year term expiring on February 2, 2024.

Our 4 million shares of Series A Mandatory Convertible Preferred Stock converted on November 1, 2017, into 12.9 million shares of our common stock.

The following table sets forth the per share high and low closing prices for our common stock as reported on the NYSE for the periods presented:

	High		Low
2018:
First Quarter (through February 8, 2018)	$	12.80	$	11.19
2017:
Fourth Quarter	$	12.49	$	9.09
Third Quarter	$	9.93	$	7.38
Second Quarter	$	9.12	$	5.93
First Quarter	$	10.42	$	6.96
2016:
Fourth Quarter	$	13.38	$	7.34
Third Quarter	$	18.09	$	12.04
Second Quarter	$	21.51	$	14.16
First Quarter	$	14.37	$	7.43

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.

Investor Rights Agreement. In connection with the closing of the PIPE Transaction, Dynegy and Terawatt entered into the Terawatt Investor Rights Agreement. Under the Terawatt Investor Rights Agreement, Terawatt will be subject to a customary standstill obligation with respect to Dynegy for a period ending on (i) the six-month anniversary of the first date Terawatt and certain affiliates cease to hold, collectively, at least 10 percent of the then-outstanding shares of Common Stock or (ii) upon the occurrence of certain transactions involving Dynegy, including change-of-control transactions.

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Terawatt is entitled to certain customary registration rights and piggyback registration rights under the Securities Act of 1933, as amended. Dynegy filed a resale shelf registration statement on Form S-3 on December 19, 2017 covering the PIPE Shares. Dynegy shall use its reasonable best efforts to keep such registration statement continuously effective until the earlier of (i) the date as of which all the Registrable Securities (as defined in the agreement) have been sold and (ii) the date there are no longer any Registrable Securities outstanding. If at any time there is no currently effective shelf registration statement, holders of Registrable Securities shall have the right to demand that Dynegy file a registration statement. Any holder of Registrable Securities may request to sell all or any portion of their Registrable Securities in a public offering, which offering may be underwritten, in each case, subject to certain exceptions provided for in the Terawatt Investor Rights Agreement. Further, when we propose to offer shares in a public offering, whether for our own account or the account of others, holders of Registrable Securities will be entitled to request that their Registrable Securities be included in such offering, subject to specific exceptions.

The Terawatt Investor Rights Agreement grants Terawatt a right of first refusal with respect to the issuance of its pro rata share of any Dynegy equity securities that would rank senior to the Common Stock until the earlier to occur of (i) the first date that Terawatt and its affiliates cease to hold, collectively, at least 7.5 percent of the then-outstanding shares of Common Stock and (ii) 3 years after the ENGIE Acquisition Closing Date.

Stockholder Return Performance Presentation. The following graph compares the cumulative total stockholder return from December 31, 2012 through December 31, 2017, for our common stock, the S&P Midcap 400 index and a customized peer group. The peer group for the fiscal year ended December 31, 2016 and prior periods, which we refer to as the “2016 Peer Group,” is comprised of Calpine Corp. and NRG Energy Inc. The peer group for the fiscal years ended December 31, 2017, which we refer to as the “2017 Peer Group,” is comprised of Vistra Energy Corp., Calpine Corp. and NRG Energy Inc.

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The graph tracks the performance of a $100 investment in our current existing common stock, in the peer group and the index (with the reinvestment of all dividends) from December 31, 2012 through December 31, 2017.

	December 31, 2012		December 31, 2013		December 31, 2014		December 31, 2015		December 31, 2016		December 31, 2017
Dynegy Inc.	$	100.00	$	112.49	$	158.65	$	70.05	$	44.22	$	61.94
S&P Midcap 400	$	100.00	$	133.50	$	146.54	$	143.35	$	173.08	$	201.20
2016 Peer Group	$	100.00	$	116.77	$	121.26	$	66.56	$	60.19	$	109.27
2017 Peer Group	$	100.00	$	116.77	$	121.26	$	66.56	$	60.19	$	91.97

The stock price performance included in this graph is not necessarily indicative of future stock price performance. The above stock price performance comparison and related discussion is not deemed to be incorporated by reference by any general statement incorporating by reference this Form 10-K into any filing under the Securities Act or under the Exchange Act or otherwise, except to the extent that we specifically incorporate this stock price performance comparison and related discussion by reference, and is not otherwise deemed “filed” under the Securities Act or Exchange Act.

Purchases of Equity Securities. We did not have any purchases of equity securities during the year ended December 31, 2017.

Securities Authorized for Issuance Under Equity Compensation Plans. Please read Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters for information regarding securities authorized for issuance under our equity compensation plans.

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Item 6.    Selected Financial Data

The selected financial information presented below was derived from, and is qualified by, reference to our Consolidated Financial Statements, including the notes thereto, contained elsewhere herein. The selected financial information should be read in conjunction with the Consolidated Financial Statements and related notes and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

	Year Ended December 31,
(in millions, except per share data)	2017			2016			2015			2014			2013
Statements of Operations Data:
Revenues	$	4,842		$	4,318		$	3,870		$	2,497		$	1,466
Impairments	$	(148	)	$	(858	)	$	(99	)	$	—		$	—
General and administrative expense	$	(189	)	$	(161	)	$	(128	)	$	(114	)	$	(97	)
Operating income (loss)	$	(412	)	$	(640	)	$	64		$	(19	)	$	(318	)
Bankruptcy reorganization items, net	$	494		$	(96	)	$	—		$	3		$	(1	)
Interest expense and debt extinguishment costs	$	(695	)	$	(625	)	$	(546	)	$	(223	)	$	(108	)
Income tax benefit	$	610		$	45		$	474		$	1		$	58
Income (loss) from continuing operations	$	72		$	(1,244	)	$	47		$	(267	)	$	(359	)
Net income (loss) attributable to Dynegy Inc.	$	76		$	(1,240	)	$	50		$	(273	)	$	(356	)
Basic earnings (loss) per share attributable to Dynegy Inc. common stockholders	$	0.37		$	(9.78	)	$	0.22		$	(2.65	)	$	(3.56	)
Cash Flow Data:
Net cash provided by operating activities	$	585		$	645		$	94		$	221		$	173
Net cash provided by (used in) investing activities	$	(2,759	)	$	(93	)	$	(6,368	)	$	(107	)	$	141
Net cash provided by (used in) financing activities	$	(1,299	)	$	2,742		$	(265	)	$	6,126		$	(154	)
Capital expenditures and acquisitions	$	(3,543	)	$	(293	)	$	(6,379	)	$	(125	)	$	138
Interest paid	$	557		$	558		$	503		$	129		$	94

	December 31,
(amounts in millions)	2017		2016		2015		2014		2013
Balance Sheet Data:
Current assets	$	1,524	$	2,987	$	1,932	$	2,664	$	1,682
Current liabilities	$	1,049	$	916	$	809	$	678	$	718
Property, plant and equipment, net	$	8,884	$	7,121	$	8,347	$	3,255	$	3,315
Total assets	$	11,771	$	13,053	$	11,459	$	11,154	$	5,264
Long-term debt (including current portion) (1)	$	8,433	$	8,979	$	7,209	$	7,028	$	1,965
Total equity	$	1,893	$	2,039	$	2,919	$	3,023	$	2,207

__________________________________________

(1) The year ended December 31, 2016 includes a $2 billion seven-year Term Loan related to the ENGIE Acquisition. The year ended December 31, 2014 includes $5.1 billion related to our notes issued on October 27, 2014 related to the Duke Midwest and EquiPower acquisitions. Please read Note 13—Debt for further discussion.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion should be read together with the consolidated financial statements and the notes thereto included in this report.

OVERVIEW

We are a holding company and conduct substantially all of our business operations through our subsidiaries.  Our current business operations are focused primarily on the power generation sector of the energy industry. We currently own approximately 28,000 MW of generating capacity in twelve states and also provide retail electricity to approximately 1,141,000 residential customers and 88,000 commercial, industrial, and municipal customers in Illinois, Massachusetts, Ohio, and Pennsylvania.  We report the results of our operations in the following five segments based upon the market areas in which our plants operate: (i) PJM, (ii) NY/NE, (iii) ERCOT, (iv) MISO and (v) CAISO. In the fourth quarter of 2017, we combined our previous MISO and IPH segments into a single MISO segment to better align our IPH assets, which reside within the MISO market area. The Company has recast data from prior periods to conform to the current year segment presentation.

Business Discussion

We generate earnings and cash flows in the five segments of our power generation business through sales of electric energy, capacity, and ancillary services. Primary factors affecting our earnings and cash flows include:

• prices for power, natural gas, coal and fuel oil, and related transportation, which in turn are largely driven by supply and demand. Demand for power can vary due to weather and general economic conditions, among other things. Power supplies similarly vary by region and are impacted significantly by available generating capacity, transmission capacity, and federal and state regulation;

• the relationship between electricity prices and prices for natural gas and coal, commonly referred to as the “spark spread” and “dark spread,” respectively, which impacts the margin we earn on the electricity we generate; and

• our ability to enter into commercial transactions to mitigate short- and medium-term earnings volatility and our ability to manage our liquidity requirements resulting from potential changes in collateral requirements as prices move.

Other factors that have affected, and are expected to continue to affect, earnings and cash flows for the power generation business include:

• transmission constraints, congestion, and other factors that can affect the price differential between the locations where we deliver generated power and the liquid market hub;

• our ability to control capital expenditures, which primarily include maintenance, safety, environmental and reliability projects, and to control operating expenses through disciplined management;

• our ability to optimize our assets by maintaining a high in-market availability, reliable run-time and safe, low-cost operations;

• our ability to optimize our assets through targeted investment in cost effective technology enhancements, such as turbine uprates, or efficiency improvements;

• our ability to operate and market production from our facilities during periods of planned/unplanned electric transmission outages;

• our ability to post the collateral necessary to execute our commercial strategy;

• the cost of compliance with existing and future environmental requirements that are likely to be more stringent and more comprehensive. Please read Item 1. Business—Environmental Matters for further discussion;

• market supply conditions resulting from federal and regional renewable power mandates and initiatives or other state-led initiatives;

• our ability to maintain coal inventory levels during critical winter and summer peak periods, which is dependent upon the reliable performance of the mines, railroads, and river transporters;

• costs of transportation related to coal deliveries;

• regional renewable energy mandates and initiatives that may alter supply conditions within an ISO and our generating units’ positions in the aggregate supply stack;

• changes in market design or associated rules in the markets in which we operate, including the resulting effect on future capacity revenues from changes in the existing bilateral MISO capacity markets and the existing bilateral CAISO resource adequacy markets;

• our ability to maintain and operate our plants in a manner that ensures we receive full capacity payments under our various tolling agreements;

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• our ability to mitigate forced outage risk, including managing risk associated with capacity performance in PJM and performance incentives in ISO-NE;

• our ability to mitigate impacts associated with expiring RMR and/or capacity contracts;

• access to capital markets on reasonable terms, interest rates and other costs of liquidity;

• benefits from our PRIDE and ECI initiatives;

• interest expense; and

• income taxes, which will be impacted by our ability to realize value from our NOLs and AMT credits.

Please read “Item 1A. Risk Factors” for additional factors that could affect our future operating results, financial condition and cash flows.

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, as well as our PRIDE and ECI initiatives.

Liquidity.  The following table summarizes our liquidity position at December 31, 2017 (amounts in millions):

Revolving facilities and LC capacity (1)	$	1,650
Less:
Outstanding revolver draws	—
Outstanding LCs	(438		)
Revolving facilities and LC availability	1,212
Cash and cash equivalents	365
Total available liquidity	$	1,577

__________________________________________

(1) Includes $1.545 billion in senior secured revolving credit facilities and $105 million related to letter of credit facilities (“LCs”). Please read Note 13—Debt for further discussion.

Liquidity Highlights:

• Effective on the ENGIE Acquisition Closing Date, amended the Credit Agreement to (i) increase the revolver capacity by $120 million, (ii) extend the maturity date on $450 million in revolver capacity to 2021, (iii) reduce the interest rate applicable to the Term Loan by 75 basis points and exchanged the previous Term Loan for a new Term Loan.

• Closed the ENGIE Acquisition for a base purchase price of $3.3 billion, paid the Energy Capital Partners (“ECP”) Buyout Price of $375 million and issued 13,711,152 common shares to Terawatt for $150 million.

• Genco emerged from bankruptcy and, as a result, we eliminated $825 million of Genco senior notes in exchange for approximately $122 million cash, $188 million in Dynegy senior notes and 9 million 2017 Warrants with a fair value of $17 million.

• Extended payment obligations of previously monetized capacity transactions (Forward Capacity Sales Agreement) by 24 months.

• Received approximately $773 million in proceeds from assets sales. Troy and Armstrong facilities ($472 million); Lee facility ($176 million); and Dighton and Milford-MA facilities ($125 million).

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• Issued $850 million of 2026 Senior Notes. We used these proceeds, together with proceeds from asset sales and cash-on-hand to repurchase $1.25 billion of our 6.75 percent senior notes due 2019 and repay $200 million of our Term Loan.

• Amended the Credit Agreement to reduce the interest rate applicable to the Term Loan by 50 basis points through an exchange. This amendment is expected to save Dynegy approximately $63 million in interest costs over the next six years. Further interest rate reductions are available to us to the extent our credit ratings increase.

Cash Flows

The following table presents net cash from operating, investing and financing activities for the years ended December 31, 2017, 2016 and 2015:

	Year Ended December 31,
(amounts in millions)	2017			2016			2015
Net cash provided by operating activities	$	585		$	645		$	94
Net cash used in investing activities	$	(2,759	)	$	(93	)	$	(6,368	)
Net cash provided by (used in) financing activities	$	(1,299	)	$	2,742		$	(265	)

Operating Activities

Changes in net cash provided by operating activities for the year ended December 31, 2017 compared to December 31, 2016 were primarily due to:

	(in millions)
Increase in cash provided by our power generation facilities and retail operations	$	237
Increase in interest payments on our various debt agreements	(2		)
Increase in payments for acquisition-related costs	(36		)
Decrease in cash provided by changes in working capital and other	(259		)
	$	(60	)

Changes in net cash provided by operating activities for the year ended December 31, 2016 compared to December 31, 2015 were primarily due to:

	(in millions)
Increase in cash provided by our power generation facilities and retail operations	$	129
Increase in interest payments on our various debt agreements	(48		)
Decrease in payments for acquisition-related costs	96
Increase in cash provided by changes in working capital and other	391
Decrease in legal settlement received in 2015	(17		)
	$	551

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 and ECI initiatives. Additionally, our future operating cash flows will benefit from the collection of the AMT refund associated with the TCJA.

Collateral Postings. We use a portion of our capital resources in the form of cash and letters of credit to satisfy counterparty collateral demands. The following table summarizes our collateral postings to third parties at December 31, 2017 and 2016:

(amounts in millions)	December 31, 2017		December 31, 2016
Cash (1)	$	92	$	124
LCs	438		382
Total	$	530	$	506

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__________________________________________

(1) Includes broker margin as well as other collateral postings included in Prepayments and other current assets in our consolidated balance sheets. As of December 31, 2017 and 2016, $47 million and $54 million, respectively, of cash posted as collateral were netted against Liabilities from risk management activities in our consolidated balance sheets.

Collateral postings increased from December 31, 2016 to December 31, 2017 primarily due to an increase in LCs as a result of the ENGIE Acquisition and a fourth quarter 2017 movement in commodity prices. The fair value of our derivatives collateralized by first priority liens included liabilities of $243 million and $136 million at December 31, 2017 and 2016, respectively.

Investing Activities

Historical Investing Cash Flows. Changes in net cash used in investing activities for the year ended December 31, 2017 compared to December 31, 2016 were primarily due to:

	(in millions)
Cash paid, net of cash acquired for the ENGIE Acquisition	$	(3,249	)
Increase in proceeds from asset sales, net	596
Purchase of Miami Fort and Zimmer from AES	(70		)
Decrease in capital expenditures	69
Decrease in distributions received from our unconsolidated investments and other investing activity	(12		)
	$	(2,666	)

Changes in net cash used in investing activities for the year ended December 31, 2016 compared to December 31, 2015 were primarily due to:

	(in millions)
Decrease in cash paid for the Duke Midwest and EquiPower acquisitions in 2015	$	6,078
Increase in proceeds from asset sales, primarily related to the sale of our unconsolidated investment in Elwood	176
Decrease in capital expenditures	8
Increase in distributions received from our unconsolidated investment in Elwood and other investing activity	13
	$	6,275

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Capital Expenditures.  Our capital spending by reportable segment is as follows:

	Year Ended December 31,									Estimated
(amounts in millions)	2017			2016			2015			2018
PJM	$	87		$	158		$	142		$	69
NY/NE	86			105			44			37
ERCOT	33			—			—			69
MISO	29			47			122			55
CAISO	36			5			9			7
Other	7			9			13			9
Total capital expenditures incurred (1)	$	278		$	324		$	330		$	246
Non-cash investing activities (2)	(31		)	2			(55		)	N/A
Capital work performed under prepaid long-term service agreement	(60		)	(121		)	(18		)	N/A
Prepaid cash for long-term service agreements (3)	37			88			44			N/A
Capital Expenditures - Statement of Cash Flows	$	224		$	293		$	301		N/A

__________________________________________

(1) Includes capitalized interest of $2 million, $10 million, and $12 million for the years ended December 31, 2017, 2016 and 2015, respectively.

(2) Please read Note 6—Cash Flow Information for further details.

(3) Prepaid cash reclassified into Investing Activities on the consolidated statements of cash flows.

Capital spending in our PJM and MISO 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. Capital expenditures for 2018 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 year ended December 31, 2017 compared to cash used in financing activities for the year ended December 31, 2016 were primarily due to:

	(in millions)
Decrease in proceeds from long-term borrowings, net of issuance costs	$	(1,271	)
Increase in repayment of borrowings	(2,000		)
Decrease in proceeds from issuance of equity, net of issuance costs	(209		)
Cash paid for debt extinguishment costs in 2017	(50		)
Cash paid related to the ECP Buyout in 2017	(375		)
Cash paid related to the Genco Bankruptcy in 2017	(133		)
Other financing activity	(3		)
	$	(4,041	)

Changes in net cash provided by financing activities for the year ended December 31, 2016 compared to cash provided by financing activities for the year ended December 31, 2015 were primarily due to:

	(in millions)
Increase in proceeds from long-term borrowings, net of issuance costs	$	2,948
Increase in repayment of borrowings, primarily due to the early paydown of the Term Loan in 2016	(558		)
Increase in proceeds from issuance of equity, net of issuance costs primarily related to TEUs	365
Repurchases of common stock related to our share repurchase program in 2015	250
Other financing activity	2
	$	3,007

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Summarized Debt and Other Obligations.  The following table depicts our third party debt obligations, and the extent to which they are secured as of December 31, 2017 and 2016:

(amounts in millions)	December 31, 2017			December 31, 2016
Secured obligations:
Term loan	$	2,018		$	2,224
Revolving Facility	—			—
Forward Capacity Agreement	241			219
Inventory Financing Agreements	48			129
Unsecured obligations (Amortizing Notes, Senior Notes, and Equipment Financing)	6,323			6,527
Unamortized discounts and issuance costs	(197		)	(120		)
Total long-term debt	$	8,433		$	8,979

Future Financing Cash Flows. Our future cash flows from financing activities include principal payments on our debt instruments and periodic payments to settle certain of our interest rate swap agreements.

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 13—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). Balances under our Forward Capacity Agreement, Inventory Financing Agreements, and Equipment Financing Agreements are excluded from Net Debt. Consolidated Senior Secured Net Debt to Consolidated Adjusted EBITDA ratio is 4.00:1.00. We were in compliance with these covenants as of and for the three year period ended December 31, 2017.

Please read Note 13—Debt for further discussion.

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 paid 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. Our dividends paid for 2017 and 2016 are as follows:

Dividend Payment Dates and Amounts Paid
(amounts in millions)	2017		2016
February 1	$	5.4	$	5.4
May 1	$	5.4	$	5.4
August 1	$	5.4	$	5.4
November 1	$	5.4	$	5.4

Our 4 million shares of Series A Mandatory Convertible Preferred Stock converted on November 1, 2017 into approximately 12.9 million shares of our common stock. Please see Note 15—Stockholders’ Equity for further discussion.

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Credit Ratings

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

	Moody’s	S&P
Corporate Family Rating	B2	B+
Senior Secured	Ba3	BB
Senior Unsecured	B3	B+

Disclosure of Contractual Obligations and Other Environmental Obligations

We have incurred various contractual obligations, financial commitments, and other environmental obligations in the normal course of business.  Contractual obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements.  These obligations may result from both general financing activities and from commercial arrangements that are directly supported by related revenue-producing activities.  Our other environmental obligations consist of ELG expenditures and AROs.

The following table summarizes the contractual obligations and other environmental obligations of the Company and its consolidated subsidiaries as of December 31, 2017. Cash obligations reflected are not discounted and do not include accretion or dividends.

	Expiration by Period
(amounts in millions)	Total		Less than 1 Year		1 - 3 Years		3 - 5 Years		More than 5 Years
Long-term debt (including current portion) (1)	$	8,498	$	83	$	1,063	$	1,795	$	5,557
Interest payments on debt	3,316		566		1,050		979		721
Coal purchase commitments	802		402		400		—		—
Coal transportation	837		148		181		188		320
Contractual service agreements	788		118		283		347		40
Gas purchase commitments	212		212		—		—		—
Gas transportation	183		48		73		28		34
Pension funding obligations	220		13		5		50		152
Operating leases	33		6		10		9		8
Other obligations	88		35		16		12		25
Total contractual obligations	14,977		1,631		3,081		3,408		6,857
Total ELG expenditures (2)	274		—		199		38		37
Total AROs (2)	586		36		69		123		358
Total contractual and other environmental obligations	$	15,837	$	1,667	$	3,349	$	3,569	$	7,252

_______________________________________

(1) Excludes $132 million of Equipment Financing Agreements which are included in Contractual service agreements.

(2) See Item 1. Business-Environmental Matters for further discussion.

Long-Term Debt (including Current Portion).  Long-term debt includes amounts related to the Dynegy senior notes, the Credit Agreement, the Revolving Facility, the Inventory Financing Agreements, the Forward Capacity Agreement, and the Amortizing Notes. Amounts do not include debt to finance parts, equipment and services or unamortized discounts. Please read Note 13—Debt for further discussion.

Interest Payments on Debt.  Interest payments on debt represent estimated periodic interest payment obligations associated with the Dynegy senior notes, the Revolving Facility, the Credit Agreement, the Inventory Financing Agreements, and the Amortizing Notes. Amounts include the impact of interest rate swap agreements. Please read Note 13—Debt for further discussion.

Coal Purchase Commitments.  At December 31, 2017, our subsidiaries had contracts in place to purchase coal for various generation facilities. The amounts in the table reflect our minimum purchase obligations. To the extent forecasted volumes have not been priced but are subject to a price collar structure, the obligations have been calculated using the minimum purchase price of the collar.

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Coal Transportation.  At December 31, 2017, we had long-term coal transportation contracts in place. We also had long-term rail car leases in place. The amounts included in Coal transportation reflect our minimum purchase obligations based on the terms of the contracts.

Contractual Service Agreements.  Contractual service agreements represent obligations with respect to long-term plant maintenance agreements. In prior periods, we have undertaken several measures to restructure some of our existing maintenance service agreements with our turbine service providers. The table above includes our current estimate of payments under the contracts through 2048 based on anticipated timing of outages and are subject to change as outage dates move. As of December 31, 2017, our obligation with respect to these restructured agreements is limited to the termination payments, which are approximately $707 million in the event all contracts are terminated by us. In addition, we have committed to securing capital spares and turbine uprates for our gas-fueled generation fleet to help minimize production disturbances, improve efficiency, and increase generation. As of December 31, 2017, we have obligations to purchase spare parts and turbine uprates of $112 million with payments made through 2026, of which $103 million reflects spare parts received and upgrades completed. Please read Note 16—Commitments and Contingencies—Other Commitments for further discussion.

Gas Purchase Commitments.  At December 31, 2017, our subsidiaries had contracts in place to purchase gas for various generation facilities. The amounts in the table reflect our minimum purchase obligations.

Gas Transportation.  Gas transportation includes fixed transport capacity obligations associated with fuel procurement for our gas plants.

Pension Funding Obligations. Amounts include our minimum required contributions to our defined benefit pension plans through 2027 as determined by our actuary and are subject to change based on actual results of the plan. We may elect to make voluntary contributions in 2018 which would decrease future funding obligations. Please read Note 17—Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans for further discussion.

Operating Leases.  Operating leases include minimum lease payment obligations associated with office space, office equipment, and land leases.

Other Obligations.  Other obligations primarily include the following:

• $25 million related to limestone and ash purchase commitments;

• $17 million related to interconnection services;

• $23 million related to water services; and

• $23 million related to other miscellaneous items which are individually insignificant.

Commitments and Contingencies

Please read Note 16—Commitments and Contingencies, which is incorporated herein by reference, for further discussion of our material commitments and contingencies.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements at December 31, 2017.

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 years ended December 31, 2017, 2016 and 2015. 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 five separate segments in our consolidated financial statements: (i) PJM, (ii) NY/NE, (iii) ERCOT, (iv) MISO and (v) CAISO. Our consolidated financial results 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-K relate to economic hedging activities as we do not elect hedge accounting.    

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, and Adjusted Free Cash Flow (“FCF”) as a liquidity measure. 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.

44

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 amounts such as those associated with acquisitions, dispositions or restructurings, (v) non-cash compensation expense, (vi) gains or losses related to modification or extinguishment of debt, and (vii) 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 (i) mark-to-market accounting, (ii) impairment charges and (iii) 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). 

Adjusted Free Cash Flow. We define Adjusted FCF as cash flow from operating activities adjusted for (i) non-discretionary maintenance and environmental capital expenditures, (ii) the cash impact of acquisition and integration-related costs, (iii) receipts or payments related to interest rate swaps reported as financing activities in our consolidated statements of cash flows, and (iv) excludes the impact of changes in collateral, working capital and other receipts and payments. The most directly comparable GAAP financial measure is cash flows from operating activities.

Adjusted FCF may not be representative of the amount of residual cash flow that is available to Dynegy for discretionary expenditures, since it may not include deductions for mandatory debt service requirements and other non-discretionary expenditures. Management believes, however, that Adjusted FCF is useful to investors and the company because it measures the cash generating ability of Dynegy’s assets. Dynegy measures Adjusted FCF on a consolidated basis.

The following table presents Adjusted FCF from operations for the years ended December 31, 2017, 2016 and 2015:

	Year Ended December 31,
(amounts in millions)	2017			2016			2015
Net cash provided by operating activities	$	585		$	645		$	94
Capital expenditures	(249		)	(228		)	(251		)
Acquisition & integration related payments	55			73			272
Adjustment related to acquired derivatives	42			47			60
Interest rate swap settlement payments	(20		)	(17		)	(17		)
Collateral, working capital and other	(39		)	(257		)	28
Adjusted Free Cash Flow	$	374		$	263		$	186

45

Consolidated Summary Financial Information—Year Ended December 31, 2017 Compared to Year Ended December 31, 2016

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. The following table provides summary financial data regarding our consolidated results of operations for the years ended December 31, 2017 and 2016, respectively: 

	Year Ended December 31,						Favorable (Unfavorable) $ Change
(amounts in millions)	2017			2016
Revenues
Energy	$	4,000		$	3,366		$	634
Capacity	978			769			209
Mark-to-market income (loss), net	(243		)	136			(379		)
Contract amortization	(33		)	(80		)	47
Other	140			127			13
Total revenues	4,842			4,318			524
Cost of sales, excluding depreciation expense	(2,932		)	(2,281		)	(651		)
Gross margin	1,910			2,037			(127		)
Operating and maintenance expense	(995		)	(940		)	(55		)
Depreciation expense	(811		)	(689		)	(122		)
Impairments	(148		)	(858		)	710
Loss on sale of assets, net	(122		)	(1		)	(121		)
General and administrative expense	(189		)	(161		)	(28		)
Acquisition and integration costs	(57		)	(11		)	(46		)
Other	—			(17		)	17
Operating loss	(412		)	(640		)	228
Bankruptcy reorganization items	494			(96		)	590
Earnings from unconsolidated investments	8			7			1
Interest expense	(616		)	(625		)	9
Loss on early extinguishment of debt	(79		)	—			(79		)
Other income and expense, net	67			65			2
Loss before income taxes	(538		)	(1,289		)	751
Income tax benefit	610			45			565
Net income (loss)	72			(1,244		)	1,316
Less: Net loss attributable to noncontrolling interest	(4		)	(4		)	—
Net income (loss) attributable to Dynegy Inc.	$	76		$	(1,240	)	$	1,316

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The following tables provide summary financial data regarding our operating income (loss) by segment for the years ended December 31, 2017 and 2016, respectively:

	Year Ended December 31, 2017
(amounts in millions)	PJM			NY/NE			ERCOT			MISO			CAISO			Other			Total
Revenues	$	2,262		$	1,029		$	277		$	1,152		$	122		$	—		$	4,842
Cost of sales, excluding depreciation expense	(1,217		)	(658		)	(256		)	(723		)	(78		)	—			(2,932		)
Gross margin	1,045			371			21			429			44			—			1,910
Operating and maintenance expense	(389		)	(170		)	(95		)	(300		)	(39		)	(2		)	(995		)
Depreciation expense	(379		)	(224		)	(73		)	(75		)	(53		)	(7		)	(811		)
Impairments	(49		)	—			—			(99		)	—			—			(148		)
Gain (loss) on sale of assets, net	(36		)	(90		)	—			1			3			—			(122		)
General and administrative expense	—			—			—			—			—			(189		)	(189		)
Acquisition and integration costs	—			—			—			—			—			(57		)	(57		)
Operating income (loss)	$	192		$	(113	)	$	(147	)	$	(44	)	$	(45	)	$	(255	)	$	(412	)

	Year Ended December 31, 2016
(amounts in millions)	PJM			NY/NE			MISO			CAISO			Other			Total
Revenues	$	2,202		$	837		$	1,137		$	142		$	—		$	4,318
Cost of sales, excluding depreciation expense	(985		)	(486		)	(741		)	(69		)	—			(2,281		)
Gross margin	1,217			351			396			73			—			2,037
Operating and maintenance expense	(391		)	(165		)	(347		)	(36		)	(1		)	(940		)
Depreciation expense	(346		)	(215		)	(81		)	(42		)	(5		)	(689		)
Impairments	(65		)	—			(793		)	—			—			(858		)
Gain (loss) on sale of assets, net	—			—			1			—			(2		)	(1		)
General and administrative expense	—			—			—			—			(161		)	(161		)
Acquisition and integration costs	—			—			8			—			(19		)	(11		)
Other	(1		)	—			(16		)	—			—			(17		)
Operating income (loss)	$	414		$	(29	)	$	(832	)	$	(5	)	$	(188	)	$	(640	)

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			CAISO			Total
Revenues, attributable to newly acquired ENGIE plants	$	203		$	227		$	277	$	—		$	—		$	707
Higher (lower) realized power prices, net of hedges	29			108			—		(47		)	27			117
Lower generation volumes (1)	(23		)	(51		)	—		(57		)	(8		)	(139		)
Higher (lower) capacity revenues	26			25			—		47			(22		)	76
Change in MTM value of derivative transactions	(200		)	(128		)	—		68			(7		)	(267		)
Lower contract amortization	24			4			—		7			10			45
Other (2)	1			7			—		(3		)	(20		)	(15		)
Total change in revenues	$	60		$	192		$	277	$	15		$	(20	)	$	524

 _______________________________________

(1) Decrease due to mild winter weather which decreased demand across our key markets as well as planned outages and shutdowns.

(2) Other primarily consists of ancillary, tolling, transmission and gas revenues.

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Cost of Sales. The following table summarizes the change in cost of sales by segment:

(amounts in millions)	PJM			NY/NE			ERCOT		MISO			CAISO			Total
Cost of sales attributable to newly acquired ENGIE plants	$	91		$	119		$	256	$	—		$	—		$	466
Higher (lower) delivered fuel cost, primarily due to higher gas costs	117			142			—		(1		)	15			273
Lower burn volumes (1)	(39		)	(76		)	—		(12		)	(6		)	(133		)
Lower (higher) contract amortization	42			(18		)	—		13			—			37
Other (2)	21			5			—		(18		)	—			8
Total change in cost of sales	$	232		$	172		$	256	$	(18	)	$	9		$	651

 _______________________________________

(1) Lower burn volumes primarily due to milder weather at our PJM, NY/NE, and MISO segments, unit shutdowns primarily at our MISO segment, and a plant retirement at our NY/NE segment.

(2) Other primarily consists of transmission expenses and various non-recurring expenses.

Operating and Maintenance Expense. Operating and maintenance expense increased by $55 million primarily due to the newly acquired ENGIE plants, partially offset by lower costs from long-term service agreements at our PJM, NY/NE and CAISO segments, plant shutdowns at our MISO segment, and the Brayton Point plant retirement at our NY/NE segment.

Depreciation Expense. Depreciation expense increased by $122 million primarily due to increases from the newly acquired ENGIE plants partially offset by the Brayton Point plant retirement at our NY/NE segment.

Impairments.  Impairments decreased by $710 million due to the following (amounts in millions):

	Year Ended December 31,
Description	2017		2016
Inventory	$	14	$	—
Property, plant and equipment	119		849
Equity investment	—		9
Assets held-for-sale, including $9 of allocated goodwill	15		—
Total	$	148	$	858

Please read Note 7—Inventory, Note 8—Property, Plant and Equipment, Note 10—Unconsolidated Investments, and Note 3—Acquisitions and Divestitures for further discussion.

Loss on Sale of Assets, net.  Loss on sale of assets, net increased by $121 million primarily due to the Conesville and Zimmer ownership interest exchange, and the sale of our Lee, Dighton and Milford-MA facilities. Please read Note 9—Joint Ownership of Generating Facilities and Note 3—Acquisitions and Divestitures for further discussion.

General and Administrative Expense.  General and administrative expense increased by $28 million primarily due to higher overhead associated with the ENGIE Acquisition and higher professional fees of $17 million related to the Merger.

Acquisition and Integration Costs. Acquisition and integration costs increased by $46 million primarily due to $36 million higher advisory and consulting fees and $10 million higher severance, retention, and payroll costs primarily related to the ENGIE Acquisition in 2017.

Other. Other decreased by $17 million primarily due to a charge in 2016 associated with the termination of an above market coal supply contract at our MISO segment.

Bankruptcy Reorganization Items. Bankruptcy reorganization items increased by $590 million primarily due to the gain on extinguishment of debt and legal costs associated with the Genco bankruptcy reorganization. Please read Note 20—Genco Chapter 11 Bankruptcy for further discussion.

Interest Expense. Interest expense decreased by $9 million primarily due to the elimination of the Genco senior notes partially offset by the interest on our Term Loan and our Senior Notes. Please read Note 13—Debt for further discussion.

Loss on Early Extinguishment of Debt.  Loss on early extinguishment of debt was $79 million due to the repurchase of a portion of our senior notes, and the partial repayment and repricing of our Term Loan. Please read Note 13—Debt for further discussion.

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Income Tax Benefit.  The net favorable change of $565 million was primarily due to a partial release of our valuation allowance as a result of the ENGIE Acquisition of $354 million and recognition of the benefit of AMT credits of $223 million that had previously been subject to a valuation allowance as a result of the TCJA.

Net Income (Loss) Attributable to Dynegy Inc. The $1.316 billion increase was primarily due to (i) a $228 million lower operating loss primarily attributable to lower impairments, (ii) a $590 million gain primarily due to extinguishment of debt associated with the Genco bankruptcy, and (iii) a $565 million increase in tax benefit as discussed above, partially offset by a $79 million loss on early extinguishment of debt.

Adjusted EBITDA — Year Ended December 31, 2017 Compared to Year Ended December 31, 2016

The following table provides summary financial data regarding our Adjusted EBITDA by segment for the year ended December 31, 2017:

	Year Ended December 31, 2017
(amounts in millions)	PJM		NY/NE			ERCOT			MISO			CAISO			Other			Total
Net income																		$	72
Income tax benefit																		(610		)
Other income and expense, net																		(67		)
Loss on early extinguishment of debt																		79
Interest expense																		616
Earnings from unconsolidated investments																		(8		)
Bankruptcy reorganization items																		(494		)
Operating income (loss)	$	192	$	(113	)	$	(147	)	$	(44	)	$	(45	)	$	(255	)	$	(412	)
Depreciation and amortization expense	390		232			74			91			57			7			851
Bankruptcy reorganization items	—		—			—			494			—			—			494
Earnings from unconsolidated investments	3		5			—			—			—			—			8
Loss on early extinguishment of debt	—		—			—			—			—			(79		)	(79		)
Other income and expense, net	16		—			—			26			—			25			67
EBITDA	601		124			(73		)	567			12			(302		)	929
Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude noncontrolling interest	5		2			—			2			—			—			9
Acquisition, integration and restructuring costs	—		—			—			—			—			74			74
Bankruptcy reorganization items	—		—			—			(494		)	—			—			(494		)
Mark-to-market adjustments, including warrants	125		75			99			(21		)	7			(16		)	269
Impairments	49		—			—			99			—			—			148
Loss (gain) on sale of assets, net	36		90			—			(1		)	—			—			125
Loss on early extinguishment of debt	—		—			—			—			—			79			79
Non-cash compensation expense	—		—			—			1			—			20			21
Other	2		2			—			(1		)	—			(3		)	—
Adjusted EBITDA	$	818	$	293		$	26		$	152		$	19		$	(148	)	$	1,160

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The following table provides summary financial data regarding our Adjusted EBITDA by segment for the year ended December 31, 2016:

	Year Ended December 31, 2016
(amounts in millions)	PJM			NY/NE			MISO			CAISO			Other			Total
Net loss																$	(1,244	)
Income tax benefit																(45		)
Other income and expense, net																(65		)
Interest expense																625
Earnings from unconsolidated investments																(7		)
Bankruptcy reorganization items																96
Operating income (loss)	$	414		$	(29	)	$	(832	)	$	(5	)	$	(188	)	$	(640	)
Depreciation and amortization expense	349			243			87			53			5			737
Bankruptcy reorganization items	—			—			(96		)	—			—			(96		)
Earnings from unconsolidated investments	7			—			—			—			—			7
Other income and expense, net	9			1			15			12			28			65
EBITDA	779			215			(826		)	60			(155		)	73
Adjustments to reflect Adjusted EBITDA from unconsolidated investment and exclude noncontrolling interest	—			—			2			—			—			2
Acquisition, integration and restructuring costs	—			—			(8		)	—			29			21
Bankruptcy reorganization items	—			—			96			—			—			96
Mark-to-market adjustments, including warrants	(92		)	(44		)	47			—			(6		)	(95		)
Impairments	65			—			793			—			—			858
Loss (gain) on sale of assets, net	—			—			(1		)	—			2			1
Non-cash compensation expense	—			—			6			—			22			28
Other (1)	5			—			20			(1		)	(1		)	23
Adjusted EBITDA	$	757		$	171		$	129		$	59		$	(109	)	$	1,007

__________________________________________

(1) Other includes an adjustment to exclude Wood River’s energy margin and O&M costs of $23 million.

Adjusted EBITDA increased by $153 million. The newly acquired ENGIE plants contributed $216 million in 2017. The offsetting $63 million decrease was primarily driven by lower energy margin, net of hedges, as a result of lower generation volumes driven by milder weather and decreased spark spreads driven by higher gas costs and milder weather at the PJM and NY/NE segments, and decreased dark spreads at the MISO segment and lower retail contribution at the PJM and MISO segments, all driven by milder weather. Please read Discussion of Segment Adjusted EBITDA for further information.

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Discussion of Segment Adjusted EBITDA — Year Ended December 31, 2017 Compared to Year Ended December 31, 2016

PJM Segment

The following table provides summary financial data regarding our PJM segment results of operations for the years ended December 31, 2017 and 2016, respectively:

	Year Ended December 31,						Favorable (Unfavorable) $ Change
(dollars in millions, except for price information)	2017 (1)			2016
Operating Revenues
Energy	$	1,793		$	1,681		$	112
Capacity	493			398			95
Mark-to-market income (loss), net	(83		)	118			(201		)
Contract amortization	(18		)	(47		)	29
Other	77			52			25
Total operating revenues	2,262			2,202			60
Operating Costs
Cost of sales	(1,228		)	(1,033		)	(195		)
Contract amortization	11			48			(37		)
Total operating costs	(1,217		)	(985		)	(232		)
Gross margin	1,045			1,217			(172		)
Operating and maintenance expense	(389		)	(391		)	2
Depreciation expense	(379		)	(346		)	(33		)
Impairments	(49		)	(65		)	16
Loss on sale of assets, net	(36		)	—			(36		)
Other	—			(1		)	1
Operating income	192			414			(222		)
Depreciation and amortization expense	390			349			41
Earnings from unconsolidated investments	3			7			(4		)
Other income and expense, net	16			9			7
EBITDA	601			779			(178		)
Adjustment to reflect Adjusted EBITDA from unconsolidated investment	5			—			5
Mark-to-market adjustments	125			(92		)	217
Impairments	49			65			(16		)
Loss on sale of assets, net	36			—			36
Other	2			5			(3		)
Adjusted EBITDA	$	818		$	757		$	61
Million Megawatt Hours Generated (1)	52.8			52.8			—
IMA (1)(2):
Combined-Cycle Facilities	95		%	97		%
Coal-Fired Facilities	75		%	80		%
Average Capacity Factor (1)(3):
Combined-Cycle Facilities	64		%	74		%
Coal-Fired Facilities	56		%	53		%
CDDs (4)	1,143			1,417			(274		)
HDDs (4)	4,403			4,719			(316		)
Average Market On-Peak Spark Spreads ($/MWh) (5):
PJM West	$	16.90		$	22.62		$	(5.72	)
AD Hub	$	19.22		$	22.52		$	(3.30	)
Average Market On-Peak Power Prices ($/MWh) (6):
PJM West	$	34.38		$	34.65		$	(0.27	)
AD Hub	$	34.00		$	32.93		$	1.07
Average natural gas price—TetcoM3 ($/MMBtu) (7)	$	2.50		$	1.72		$	0.78

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_______________________________________

(1) 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 excludes such activity for our period of ownership in February.

(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 quoted 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 $222 million primarily due to the following:

	(in millions)
Income attributable to newly acquired plants in 2017	$	59
Lower energy margin, net of hedges, due to the following:
Lower spark spreads as a result of higher gas costs and milder weather	$	(49	)
Lower generation volumes due to milder weather	$	(23	)
Lower retail contribution as a result of higher supply costs and milder weather	$	(30	)
Higher capacity revenues as a result of higher 2017 pricing and performance penalties in 2016	$	26
Lower O&M costs associated with outages in 2016 and lower costs from long-term service agreements	$	26
Change in MTM value of derivative transactions	$	(200	)
Lower impairment charges	$	16
Loss on sale of assets due to the sale of Lee and the Conesville and Zimmer ownership interest exchange	$	(36	)

Adjusted EBITDA increased by $61 million primarily due to the following:

	(in millions)
Contribution from newly acquired plants in 2017	$	85
Lower energy margin, net of hedges, due to the following:
Lower spark spreads as a result of higher gas costs and milder weather	$	(23	)
Lower generation volumes due to milder weather	$	(37	)
Lower retail contribution as a result of higher supply costs and milder weather	$	(30	)
Higher capacity revenues as a result of higher 2017 pricing and performance penalties in 2016	$	26
Lower O&M costs associated with outages in 2016 and lower costs from long-term service agreements	$	24
Net casualty loss insurance reimbursement	$	7

52

NY/NE Segment

The following table provides summary financial data regarding our NY/NE segment results of operations for the years ended December 31, 2017 and 2016, respectively:

	Year Ended December 31,						Favorable (Unfavorable) $ Change
(dollars in millions, except for price information)	2017 (1)			2016
Operating Revenues
Energy	$	813		$	570		$	243
Capacity	257			168			89
Mark-to-market income (loss), net	(75		)	65			(140		)
Contract amortization	(9		)	(10		)	1
Other	43			44			(1		)
Total operating revenues	1,029			837			192
Operating Costs
Cost of sales	(660		)	(469		)	(191		)
Contract amortization	2			(17		)	19
Total operating costs	(658		)	(486		)	(172		)
Gross margin	371			351			20
Operating and maintenance expense	(170		)	(165		)	(5		)
Depreciation expense	(224		)	(215		)	(9		)
Loss on sale of assets, net	(90		)	—			(90		)
Operating loss	(113		)	(29		)	(84		)
Depreciation and amortization expense	232			243			(11		)
Earnings from unconsolidated investments	5			—			5
Other income and expense, net	—			1			(1		)
EBITDA	124			215			(91		)
Adjustments to reflect Adjusted EBITDA from unconsolidated investment	2			—			2
Mark-to-market adjustments	75			(44		)	119
Loss on sale of assets, net	90			—			90
Other	2			—			2
Adjusted EBITDA	$	293		$	171		$	122
Million Megawatt Hours Generated (1)	19.2			16.9			2.3
IMA for Combined-Cycle Facilities (1)(2)	96		%	96		%
Average Capacity Factor for Combined-Cycle Facilities (1)(3)	43		%	48		%
CDDs (4)	721			884			(163		)
HDDs (4)	5,495			5,593			(98		)
Average Market On-Peak Spark Spreads ($/MWh) (5):
New York—Zone C	$	14.78		$	16.46		$	(1.68	)
Mass Hub	$	12.09		$	13.80		$	(1.71	)
Average Market On-Peak Power Prices ($/MWh) (6):
New York—Zone C	$	29.56		$	26.88		$	2.68
Mass Hub	$	37.83		$	35.52		$	2.31
Average natural gas price—Algonquin Citygates ($/MMBtu) (7)	$	3.68		$	3.10		$	0.58

53

_______________________________________

(1) 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 excludes such activity for our period of ownership in February.

(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.

(6) Reflects the average of day-ahead quoted 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 $84 million primarily due to the following:

	(in millions)
Income attributable to newly acquired plants in 2017	$	26
Lower energy margin, net of hedges, due to lower generation volumes as a result of milder weather and the retirement of our Brayton Point facility	$	(8	)
Higher capacity revenues as a result of higher 2017 pricing, offset by capacity lost due to the retirement of our Brayton Point facility	$	25
Change in MTM value of derivative transactions	$	(128	)
Lower contract amortization	$	22
Lower O&M costs associated with planned major maintenance outages and as a result of the retirement of our Brayton Point facility	$	20
Lower depreciation primarily due to the retirement of our Brayton Point facility	$	48
Loss on sale of our Dighton and Milford-MA facilities	$	(90	)

Adjusted EBITDA increased by $122 million primarily due to the following:

	(in millions)
Contribution from newly acquired plants in 2017	$	105
Lower energy margin, net of hedges, due to the following:
Lower spark spreads, net of hedges as a result of higher gas costs and milder weather	$	(22	)
Lower generation volumes as a result of milder weather and the retirement of our Brayton Point facility	$	(10	)
Higher capacity revenues as a result of higher 2017 pricing, offset by capacity lost due to the retirement of our Brayton Point facility	$	25
Lower O&M costs associated with planned major maintenance outages and as a result of the retirement of our Brayton Point facility	$	20

54

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 year ended December 31, 2017:

	Year Ended December 31,						Favorable (Unfavorable) $ Change
(dollars in millions, except for price information)	2017			2016
Operating revenues
Energy	$	366		$	—		N/A
Mark-to-market loss, net	(99		)	—			N/A
Other	10			—			N/A
Total operating revenues	277			—			N/A
Operating costs
Cost of sales	(256		)	—			N/A
Total operating costs	(256		)	—			N/A
Gross margin	21			—			N/A
Operating and maintenance expense	(95		)	—			N/A
Depreciation expense	(73		)	—			N/A
Operating loss	(147		)	—			N/A
Depreciation and amortization expense	74			—			N/A
EBITDA	(73		)	—			N/A
Mark-to-market adjustments	99			—			N/A
Adjusted EBITDA	$	26		$	—		N/A
Million Megawatt Hours Generated (1)	11.0			—			N/A
IMA (1)(2):
Combined-Cycle Facilities	94		%	—		%
Coal-Fired Facility	96		%	—		%
Average Capacity Factor (1)(3):
Combined-Cycle Facilities	25		%	—		%
Coal-Fired Facility	67		%	—		%
CDDs (4)	3,390			3,355			35
HDDs (4)	1,090			1,222			(132		)
Average Market On-Peak Spark Spreads ($/MWh) (5):
ERCOT North	$	7.79		$	9.79		$	(2.00	)
Average Market On-Peak Power Prices ($/MWh) (6):
ERCOT North	$	26.45		$	26.02		$	0.43
Average natural gas price—Waha Hub ($/MMBtu) (7)	$	2.67		$	2.32		$	0.35

__________________________________________

(1) Million Megawatt Hours Generated and Average Capacity Factor include such activity for the full month of February. IMA excludes such activity for our period of ownership in February.

(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.

(7) Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us.

55

Operating loss of $147 million primarily consisted of the following:

	(in millions)
Energy margin, net of hedges	$	110
MTM loss	$	(99	)
Ancillary sales	$	8
O&M costs	$	(95	)
Depreciation expense	$	(73	)

Adjusted EBITDA was $26 million primarily related to the following:

	(in millions)
Energy margin, net of hedges	$	110
Ancillary sales	$	8
O&M costs	$	(94	)

56

MISO Segment

The following table provides summary financial data regarding our MISO segment results of operations for the years ended December 31, 2017 and 2016, respectively:

	Year Ended December 31,						Favorable (Unfavorable) $ Change
(dollars in millions, except for price information)	2017			2016
Operating Revenues
Energy	$	920		$	1,027		$	(107	)
Capacity	210			163			47
Mark-to-market income (loss), net	21			(47		)	68
Contract amortization	(6		)	(13		)	7
Other	7			7			—
Total operating revenues	1,152			1,137			15
Operating Costs
Cost of sales	(731		)	(762		)	31
Contract amortization	8			21			(13		)
Total operating costs	(723		)	(741		)	18
Gross margin	429			396			33
Operating and maintenance expense	(300		)	(347		)	47
Depreciation expense	(75		)	(81		)	6
Impairments	(99		)	(793		)	694
Gain on sale of assets, net	1			1			—
Acquisition and integration costs	—			8			(8		)
Other	—			(16		)	16
Operating loss	(44		)	(832		)	788
Depreciation and amortization expense	91			87			4
Bankruptcy reorganization items	494			(96		)	590
Other income and expense, net	26			15			11
EBITDA	567			(826		)	1,393
Adjustments to reflect Adjusted EBITDA from noncontrolling interest	2			2			—
Acquisition, integration, restructuring and bankruptcy reorganization costs	—			(8		)	8
Bankruptcy reorganization items	(494		)	96			(590		)
Mark-to-market adjustments	(21		)	47			(68		)
Impairments	99			793			(694		)
Gain on sale of assets, net	(1		)	(1		)	—
Non-cash compensation expense	1			6			(5		)
Other (1)	(1		)	20			(21		)
Adjusted EBITDA	$	152		$	129		$	23
Million Megawatt Hours Generated	29.1			29.8			(0.7		)
IMA for Coal-Fired Facilities (2)	89		%	89		%
Average Capacity Factor for Coal-Fired Facilities (3)	63		%	53		%
CDDs (4)	1,272			1,652			(380		)
HDDs (4)	4,534			4,662			(128		)
Average Market On-Peak Power Prices ($/MWh) (5):
Indiana (Indy Hub)	$	34.36		$	33.71		$	0.65
Commonwealth Edison (NI Hub)	$	32.28		$	31.98		$	0.30

57

______________________________________

(1) Other includes an adjustment to exclude Wood River’s energy margin and O&M costs of $23 million for the year ended December 31, 2016. Adjusted EBITDA did not include this adjustment for the year ended December 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 quoted prices for the periods presented and does not necessarily reflect prices we realized.

Operating loss decreased by $788 million primarily due to the following:

	(in millions)
Lower energy margin due to the following:
Lower dark spreads, net of hedges, as a result of milder weather, and higher fuel and transportation costs	$	(47	)
Lower generation volumes as a result of shutdowns in 2016	$	(4	)
Lower retail contribution as a result of milder weather	$	(43	)
Change in fuel and transportation costs related to Wood River	$	14
Change in fuel costs as a result of a coal inventory adjustment in 2016	$	7
Higher capacity revenues due to higher pricing and volumes, including revenues related to PJM pseudo-ties	$	47
Change in MTM value of derivative transactions	$	68
Termination of an above market coal supply contract in 2016	$	15
Lower O&M costs primarily due to shutdowns in 2016, ARO accretion, property taxes, and fewer outages	$	47
Absence of impairment charges primarily due to our Baldwin and Newton facilities in 2016	$	694

Adjusted EBITDA increased by $23 million primarily due to the following:

	(in millions)
Lower energy margin, net of hedges, due to the following:
Lower dark spreads, net of hedges, as a result of milder weather, and higher fuel and transportation costs	$	(48	)
Lower retail contribution as a result of milder weather	$	(43	)
Change in fuel costs as a result of a coal inventory adjustment in 2016	$	6
Higher capacity revenues due to higher pricing and volumes, including revenues related to PJM pseudo-ties	$	47
AER proceeds	$	25
Lower O&M costs primarily due to shutdowns in 2016, property taxes, and fewer outages	$	31

58

CAISO Segment

The following table provides summary financial data regarding our CAISO segment results of operations for the years ended December 31, 2017 and 2016, respectively:

	Year Ended December 31,						Favorable (Unfavorable) $ Change
(dollars in millions, except for price information)	2017			2016
Operating Revenues
Energy	$	108		$	88		$	20
Capacity	18			40			(22		)
Mark-to-market loss, net	(7		)	—			(7		)
Contract amortization	—			(10		)	10
Other	3			24			(21		)
Total operating revenues	122			142			(20		)
Operating Costs
Cost of sales	(78		)	(69		)	(9		)
Total operating costs	(78		)	(69		)	(9		)
Gross margin	44			73			(29		)
Operating and maintenance expense	(39		)	(36		)	(3		)
Depreciation expense	(53		)	(42		)	(11		)
Gain on sale of assets, net	3			—			3
Operating loss	(45		)	(5		)	(40		)
Depreciation and amortization expense	57			53			4
Other income and expense, net	—			12			(12		)
EBITDA	12			60			(48		)
Mark-to-market adjustments	7			—			7
Other	—			(1		)	1
Adjusted EBITDA	$	19		$	59		$	(40	)
Million Megawatt Hours Generated	2.3			2.6			(0.3		)
IMA for Combined-Cycle Facilities (1)	92		%	96		%
Average Capacity Factor for Combined-Cycle Facilities (2)	26		%	27		%
CDDs (3)	1,337			1,211			126
HDDs (3)	1,233			1,218			15
Average Market On-Peak Spark Spreads ($/MWh) (4):
North of Path 15 (NP 15)	$	15.38		$	12.67		$	2.71
Average Market On-Peak Power Prices ($/MWh) (5):
North of Path 15 (NP 15)	$	38.02		$	31.60		$	6.42
Average natural gas price—PG&E Citygate ($/MMBtu) (6)	$	3.23		$	2.70		$	0.53

__________________________________________

(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. This 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 ISO-NE 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 day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.

59

(6) Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us.

Operating loss increased by $40 million primarily due to the following:

	(in millions)
Higher energy margin, net of hedges, due to higher spark spreads as a result of warmer weather	$	12
Lower capacity revenues due to lower volumes and prices	$	(22	)
Lower tolling revenue due to expiration of tolling agreement	$	(19	)
Change in MTM value of derivative transactions	$	(7	)
Higher O&M costs due to higher ARO accretion	$	(3	)
Higher depreciation and amortization	$	(2	)

Adjusted EBITDA decreased by $40 million primarily due to the following:

	(in millions)
Higher energy margin, net of hedges, due to higher spark spreads as a result of warmer weather	$	12
Lower capacity revenues due to lower volumes and prices	$	(22	)
Lower tolling revenue due to expiration of tolling agreement in 2016	$	(19	)
Supplier settlement in 2016	$	(12	)

60

Consolidated Summary Financial Information—Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

We completed the EquiPower Acquisition and Duke Midwest Acquisition on April 1, 2015 and April 2, 2015, respectively; therefore, the results of these plants within our PJM and NY/NE segments are only included in our consolidated results from their respective acquisition dates. Please read Note 3—Acquisitions and Divestitures—EquiPower Acquisition and Duke Midwest Acquisition for further discussion. The following table provides summary financial data regarding our consolidated results of operations for the years ended December 31, 2016 and 2015, respectively: 

	Year Ended December 31,						Favorable (Unfavorable) $ Change
(amounts in millions)	2016			2015
Revenues
Energy	$	3,366		$	3,083		$	283
Capacity	769			626			143
Mark-to-market income, net	136			127			9
Contract amortization	(80		)	(83		)	3
Other	127			117			10
Total revenues	4,318			3,870			448
Cost of sales, excluding depreciation expense	(2,281		)	(2,028		)	(253		)
Gross margin	2,037			1,842			195
Operating and maintenance expense	(940		)	(839		)	(101		)
Depreciation expense	(689		)	(587		)	(102		)
Impairments	(858		)	(99		)	(759		)
Loss on sale of assets, net	(1		)	(1		)	—
General and administrative expense	(161		)	(128		)	(33		)
Acquisition and integration costs	(11		)	(124		)	113
Other	(17		)	—			(17		)
Operating income (loss)	(640		)	64			(704		)
Bankruptcy reorganization items	(96		)	—			(96		)
Earnings from unconsolidated investments	7			1			6
Interest expense	(625		)	(546		)	(79		)
Other income and expense, net	65			54			11
Loss before income taxes	(1,289		)	(427		)	(862		)
Income tax benefit	45			474			(429		)
Net income (loss)	(1,244		)	47			(1,291		)
Less: Net loss attributable to noncontrolling interest	(4		)	(3		)	(1		)
Net income (loss) attributable to Dynegy Inc.	$	(1,240	)	$	50		$	(1,290	)

61

The following tables provide summary financial data regarding our operating income (loss) by segment for the years ended December 31, 2016 and 2015, respectively:

	Year Ended December 31, 2016
(amounts in millions)	PJM			NY/NE			MISO			CAISO			Other			Total
Revenues	$	2,202		$	837		$	1,137		$	142		$	—		$	4,318
Cost of sales, excluding depreciation expense	(985		)	(486		)	(741		)	(69		)	—			(2,281		)
Gross margin	1,217			351			396			73			—			2,037
Operating and maintenance expense	(391		)	(165		)	(347		)	(36		)	(1		)	(940		)
Depreciation expense	(346		)	(215		)	(81		)	(42		)	(5		)	(689		)
Impairments	(65		)	—			(793		)	—			—			(858		)
Gain (loss) on sale of assets, net	—			—			1			—			(2		)	(1		)
General and administrative expense	—			—			—			—			(161		)	(161		)
Acquisition and integration costs	—			—			8			—			(19		)	(11		)
Other	(1		)	—			(16		)	—			—			(17		)
Operating income (loss)	$	414		$	(29	)	$	(832	)	$	(5	)	$	(188	)	$	(640	)

	Year Ended December 31, 2015
(amounts in millions)	PJM			NY/NE			MISO			CAISO			Other			Total
Revenues	$	1,716		$	695		$	1,281		$	178		$	—		$	3,870
Cost of sales, excluding depreciation expense	(716		)	(414		)	(793		)	(105		)	—			(2,028		)
Gross margin	1,000			281			488			73			—			1,842
Operating and maintenance expense	(296		)	(126		)	(389		)	(32		)	4			(839		)
Depreciation expense	(281		)	(186		)	(68		)	(48		)	(4		)	(587		)
Impairments	—			(25		)	(74		)	—			—			(99		)
Loss on sale of assets, net	—			—			—			(1		)	—			(1		)
General and administrative expense	—			—			—			—			(128		)	(128		)
Acquisition and integration costs	—			—			—			—			(124		)	(124		)
Operating income (loss)	$	423		$	(56	)	$	(43	)	$	(8	)	$	(252	)	$	64

Discussion of Consolidated Results of Operations

Revenues. The following table summarizes the change in revenues by segment:

(amounts in millions)	PJM			NY/NE			MISO			CAISO			Total
Revenues, net of hedges, attributable to Duke Midwest and EquiPower plants for the first quarter of 2016	$	467		$	194		$	—		$	—		$	661
Lower power prices and spark spreads	(66		)	(26		)	(13		)	—			(105		)
Higher (lower) generation volumes (1)	122			(64		)	(139		)	(39		)	(120		)
Higher (lower) capacity revenues	(36		)	(17		)	67			9			23
Change in MTM value of derivative transactions	(61		)	41			(63		)	(4		)	(87		)
Lower (higher) contract amortization	9			(4		)	12			(3		)	14
Other (2)	51			18			(8		)	1			62
Total change in revenues	$	486		$	142		$	(144	)	$	(36	)	$	448

_______________________________________

(1) Decrease due to mild winter weather which decreased demand across our key markets as well as planned outages and shutdowns; PJM segment increased due to higher demand for gas-fired generation as a result of lower gas prices.

(2) Other primarily consists of ancillary, tolling, transmission and gas revenues.

62

Cost of Sales. The following table summarizes the change in cost of sales by segment:

(amounts in millions)	PJM			NY/NE			MISO			CAISO			Total
Cost of sales attributable to Duke Midwest and EquiPower plants for the first quarter of 2016	$	157		$	128		$	—		$	—		$	285
Higher (lower) prices	(95		)	(13		)	23			(7		)	(92		)
Higher (lower) burn volumes (1)	133			(23		)	(101		)	(19		)	(10		)
Higher (lower) transportation costs (2)	3			(16		)	—			(1		)	(14		)
Lower (higher) contract amortization	20			(3		)	16			—			33
Other (3)	51			(1		)	10			(9		)	51
Total change in cost of sales	$	269		$	72		$	(52	)	$	(36	)	$	253

_______________________________________

(1) Lower burn volumes primarily due to mild winter weather which decreased demand across our key markets as well as planned outages and shutdowns; PJM segment increased as a result of higher plant availability and demand.

(2) Lower transportation costs primarily at our NY/NE segment due to reduced demand charge payment at Independence.

(3) Other primarily consists of transmission expenses, gas purchases, and various non-recurring expenses.

Operating and Maintenance Expense. Operating and maintenance expense increased by $101 million primarily due to the Duke Midwest and EquiPower plants for the first quarter of 2016 and planned major maintenance outages at our PJM and NY/NE segments, partially offset by a decrease primarily due to plant shutdowns at our MISO segment.

Depreciation Expense. Depreciation expense increased by $102 million primarily due to Duke Midwest and EquiPower plants for the first quarter of 2016, offset by a decrease due to a lower depreciable base of certain generation facilities as a result of impairments at our MISO and NY/NE segments.

Impairments. Impairments increased by $759 million due to the following (amounts in millions):

	Year Ended December 31,
Description	2016		2015
Property, plant and equipment	$	849	$	99
Equity investment	9		—
Total	$	858	$	99

Please read Note 8—Property, Plant and Equipment and Note 10—Unconsolidated Investments for further discussion.

General and Administrative Expense.  General and administrative expense increased by $33 million primarily due to higher overhead associated with the Duke Midwest and EquiPower acquisitions and higher legal fees primarily related to costs associated with the Genco reorganization that were incurred prior to Genco’s filing of the Bankruptcy Petition. Please read Note 20—Genco Chapter 11 Bankruptcy for further discussion.

Acquisition and Integration Costs. Acquisition and integration costs decreased by $113 million due to $53 million in lower advisory and consulting fees, $12 million in severance, retention, and payroll costs, and $48 million in Bridge Loan financing fees related to the Duke Midwest and EquiPower acquisitions in 2015.

Other. Other of $17 million for the year ended December 31, 2016 is primarily due to a charge associated with the termination of an above market coal supply contract.

Bankruptcy Reorganization Items. Bankruptcy reorganization items increased by $96 million primarily due to the write-off of the remaining unamortized discount related to the Genco senior notes and legal costs associated with the Genco reorganization that were incurred after Genco’s filing of the Bankruptcy Petition. Please read Note 20—Genco Chapter 11 Bankruptcy for further discussion.

Interest Expense. Interest expense increased by $79 million primarily due to interest on our Term Loan, newly issued Senior Notes, and Amortizing Notes. Please read Note 13—Debt for further discussion.

63

Other Income and Expense, Net. Other income and expense, net increased by $11 million primarily due to:

	(in millions)
Gain related to the Ponderosa Pine Energy, LLC settlement	$	20
Previously contingent proceeds received related to the AER Acquisition	$	14
Supplier settlement	$	12
Casualty loss insurance reimbursement, net	$	11
Change in fair value of our common stock warrants	$	(48	)

Income Tax Benefit.  Income tax benefit decreased by $429 million as a result of a $459 million benefit due to a release of the valuation allowance that occurred during the year ended December 31, 2015. The remaining $30 million favorable change was for discrete items including a 2016 change in our corporate tax structure, a 2015 state law change in Connecticut, the benefit from accelerating the minimum tax credit and the application of our effective state tax rates for jurisdictions for which we do not record a valuation allowance.

As of December 31, 2016, 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 that our net deferred tax assets can be realized in the future. Please read Note 14—Income Taxes for further discussion.

Net Income (Loss) Attributable to Dynegy Inc. The $1.290 billion decrease was primarily due to (i) $759 million in higher impairment charges recorded in 2016 compared to 2015, and (ii) income from a $459 million deferred tax valuation allowance release in 2015, which did not reoccur in 2016, partially offset by a $156 million contribution from Duke Midwest and EquiPower plants in the first quarter of 2016.

Adjusted EBITDA — Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

The following table provides summary financial data regarding our Adjusted EBITDA by segment for the year ended December 31, 2016:

	Year Ended December 31, 2016
(amounts in millions)	PJM			NY/NE			MISO			CAISO			Other			Total
Net loss																$	(1,244	)
Income tax benefit																(45		)
Other income and expense, net																(65		)
Interest expense																625
Earnings from unconsolidated investments																(7		)
Bankruptcy reorganization items																96
Operating income (loss)	$	414		$	(29	)	$	(832	)	$	(5	)	$	(188	)	$	(640	)
Depreciation and amortization expense	349			243			87			53			5			737
Bankruptcy reorganization items	—			—			(96		)	—			—			(96		)
Earnings from unconsolidated investments	7			—			—			—			—			7
Other income and expense, net	9			1			15			12			28			65
EBITDA	779			215			(826		)	60			(155		)	73
Adjustments to reflect Adjusted EBITDA from unconsolidated investment and exclude noncontrolling interest	—			—			2			—			—			2
Acquisition and integration costs	—			—			(8		)	—			29			21
Bankruptcy reorganization items	—			—			96			—			—			96
Mark-to-market adjustments, including warrants	(92		)	(44		)	47			—			(6		)	(95		)
Impairments	65			—			793			—			—			858
Loss (gain) on sale of assets, net	—			—			(1		)	—			2			1
Non-cash compensation expense	—			—			6			—			22			28
Other (1)	5			—			20			(1		)	(1		)	23
Adjusted EBITDA	$	757		$	171		$	129		$	59		$	(109	)	$	1,007

_______________________________________

(1) Other includes an adjustment to exclude Wood River’s energy margin and O&M costs of $23 million.    

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The following table provides summary financial data regarding our Adjusted EBITDA by segment for the year ended December 31, 2015:

	Year Ended December 31, 2015
(amounts in millions)	PJM			NY/NE			MISO			CAISO			Other			Total
Net income																$	47
Income tax benefit																(474		)
Other income and expense, net																(54		)
Interest expense																546
Earnings from unconsolidated investments																(1		)
Operating income (loss)	$	423		$	(56	)	$	(43	)	$	(8	)	$	(252	)	$	64
Depreciation and amortization expense	275			195			73			55			4			602
Earnings from unconsolidated investments	1			—			—			—			—			1
Other income and expense, net	(2		)	—			1			—			55			54
EBITDA	697			139			31			47			(193		)	721
Adjustments to reflect Adjusted EBITDA from unconsolidated investment and exclude noncontrolling interest	12			—			3			—			—			15
Acquisition and integration costs	—			—			—			—			124			124
Mark-to-market adjustments, including warrants	(58		)	11			(16		)	(4		)	(54		)	(121		)
Impairments	—			25			74			—			—			99
Loss on sale of assets, net	—			—			—			1			—			1
Other (1)	(2		)	—			12			—			1			11
Adjusted EBITDA (2)	$	649		$	175		$	104		$	44		$	(122	)	$	850

__________________________________________

(1) Other includes an adjustment to exclude costs related to the Baldwin transformer project of $7 million.

(2) Not adjusted for the following items which are excluded in 2016: (i) non-cash compensation expense of $27 million, and (ii) Wood River’s energy margin and O&M costs of $13 million.

Adjusted EBITDA increased by $157 million primarily due to a $209 million contribution from Duke Midwest and EquiPower plants in the first quarter of 2016. The offsetting $52 million decrease was driven by (i) lower energy margin, net of hedges, at the NY/NE and CAISO segments as a result of mild winter weather which decreased demand across our key markets and lowered power prices and spark spreads, (ii) lower energy margin, net of hedges, at the MISO segment due to higher fuel costs as a result of the 2015 coal inventory management efforts and an inventory flyover adjustment, and (iii) lower capacity revenues as a result of performance penalties and lower pricing at the PJM segment and lower pricing at the NY/NE segment. Please read Discussion of Segment Adjusted EBITDA for further information.

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Discussion of Segment Adjusted EBITDA — Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

PJM Segment

The following table provides summary financial data regarding our PJM segment results of operations for the years ended December 31, 2016 and 2015, respectively:

	Year Ended December 31,						Favorable (Unfavorable) $ Change
(dollars in millions, except for price information)	2016			2015
Operating Revenues
Energy	$	1,681		$	1,257		$	424
Capacity	398			345			53
Mark-to-market income, net	118			105			13
Contract amortization	(47		)	(47		)	—
Other	52			56			(4		)
Total operating revenues	2,202			1,716			486
Operating Costs
Cost of sales	(1,033		)	(771		)	(262		)
Contract amortization	48			55			(7		)
Total operating costs	(985		)	(716		)	(269		)
Gross margin	1,217			1,000			217
Operating and maintenance expense	(391		)	(296		)	(95		)
Depreciation expense	(346		)	(281		)	(65		)
Impairments	(65		)	—			(65		)
Other	(1		)	—			(1		)
Operating income	414			423			(9		)
Depreciation and amortization expense	349			275			74
Earnings from unconsolidated investments	7			1			6
Other income and expense, net	9			(2		)	11
EBITDA	779			697			82
Adjustment to reflect Adjusted EBITDA from unconsolidated investment	—			12			(12		)
Mark-to-market adjustments	(92		)	(58		)	(34		)
Impairments	65			—			65
Other	5			(2		)	7
Adjusted EBITDA	$	757		$	649		$	108
Million Megawatt Hours Generated (1)	52.8			40.4			12.4
IMA (1)(2):
Combined-Cycle Facilities	97		%	99		%
Coal-Fired Facilities	80		%	74		%
Average Capacity Factor (1)(3):
Combined-Cycle Facilities	74		%	75		%
Coal-Fired Facilities	53		%	51		%
CDDs (4)	1,417			1,218			199
HDDs (4)	4,719			4,992			(273		)
Average Market On-Peak Spark Spreads ($/MWh) (5):
PJM West	$	22.62		$	25.24		$	(2.62	)
AD Hub	$	22.52		$	28.22		$	(5.70	)
Average Market On-Peak Power Prices ($/MWh) (6):
PJM West	$	34.65		$	43.21		$	(8.56	)
AD Hub	$	32.93		$	37.52		$	(4.59	)
Average natural gas price—TetcoM3 ($/MMBtu) (7)	$	1.72		$	2.57		$	(0.85	)

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_______________________________________

(1) Reflects the activity for the period in which the EquiPower and Duke Midwest acquisitions were included in our consolidated results.

(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 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 quoted 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 $9 million primarily due to the following:

	(in millions)
Contribution from Duke Midwest and EquiPower plants in the first quarter of 2016	$	174
Lower capacity revenues as a result of lower pricing and performance penalties	$	(36	)
Change in MTM value of derivative transactions	$	(61	)
Higher O&M costs associated with planned major maintenance outages	$	(25	)
Impairment charges incurred in 2016	$	(65	)

Adjusted EBITDA increased by $108 million primarily due to the following:

	(in millions)
Contribution from Duke Midwest and EquiPower plants in the first quarter of 2016	$	170
Higher energy margin, net of hedges, due to the following:
Higher generation volumes as a result of higher plant availability	$	21
Lower power prices and spark spreads as a result of mild weather	$	(10	)
Lower capacity revenues as a result of lower pricing and performance penalties	$	(36	)
Higher O&M costs associated with planned major maintenance outages	$	(23	)

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NY/NE Segment

The following table provides summary financial data regarding our NY/NE segment results of operations for the years ended December 31, 2016 and 2015, respectively:

	Year Ended December 31,						Favorable (Unfavorable) $ Change
(dollars in millions, except for price information)	2016			2015
Operating Revenues
Energy	$	570		$	524		$	46
Capacity	168			154			14
Mark-to-market income, net	65			2			63
Contract amortization	(10		)	(4		)	(6		)
Other	44			19			25
Total operating revenues	837			695			142
Operating Costs
Cost of sales	(469		)	(410		)	(59		)
Contract amortization	(17		)	(4		)	(13		)
Total operating costs	(486		)	(414		)	(72		)
Gross margin	351			281			70
Operating and maintenance expense	(165		)	(126		)	(39		)
Depreciation expense	(215		)	(186		)	(29		)
Impairments	—			(25		)	25
Operating loss	(29		)	(56		)	27
Depreciation and amortization expense	243			195			48
Other income and expense, net	1			—			1
EBITDA	215			139			76
Mark-to-market adjustments	(44		)	11			(55		)
Impairments	—			25			(25		)
Adjusted EBITDA	$	171		$	175		$	(4	)
Million Megawatt Hours Generated (1)	16.9			15.7			1.2
IMA for Combined-Cycle Facilities (1)(2)	96		%	98		%
Average Capacity Factor for Combined-Cycle Facilities (1)(3)	48		%	56		%
CDDs (4)	884			820			64
HDDs (4)	5,593			6,056			(463		)
Average Market On-Peak Spark Spreads ($/MWh) (5):
New York—Zone C	$	16.46		$	24.76		$	(8.30	)
Mass Hub	$	13.80		$	15.23		$	(1.43	)
Average Market On-Peak Power Prices ($/MWh) (6):
New York—Zone C	$	26.88		$	35.05		$	(8.17	)
Mass Hub	$	35.52		$	48.96		$	(13.44	)
Average natural gas price—Algonquin Citygates ($/MMBtu) (7)	$	3.10		$	4.82		$	(1.72	)

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_______________________________________

(1) Reflects the activity for the period in which the EquiPower and Duke Midwest acquisitions were included in our consolidated results.

(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.

(6) Reflects the average of day-ahead quoted 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 decreased $27 million primarily due to the following:

	(in millions)
Loss attributable to Duke Midwest and EquiPower plants in the first quarter of 2016	$	(16	)
Lower energy margin, net of hedges, due to lower spark spreads and lower generation volumes	$	(39	)
Higher O&M costs associated with planned major maintenance outages	$	(8	)
Change in MTM value of derivative transactions	$	41
Impairment charges incurred in 2015	$	25
Lower depreciation due to a fourth quarter 2015 impairment of our Brayton Point facility	$	22

Adjusted EBITDA decreased by $4 million primarily due to the following:

	(in millions)
Contribution from Duke Midwest and EquiPower plants in the first quarter of 2016	$	39
Lower energy margin, net of hedges, due to the following:
Lower spark spreads as a result of mild winter weather	$	(14	)
Lower generation volumes as a result of more planned outages	$	(25	)
Lower capacity revenues as a result of lower pricing	$	(17	)
Higher tolling revenues as a result of a 2016 tolling contract	$	12
Higher O&M costs associated with planned major maintenance outages	$	(5	)

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MISO Segment

The following table provides summary financial data regarding our MISO segment results of operations for the years ended December 31, 2016 and 2015, respectively:

	Year Ended December 31,						Favorable (Unfavorable) $ Change
(dollars in millions, except for price information)	2016			2015
Operating Revenues
Energy	$	1,027		$	1,177		$	(150	)
Capacity	163			96			67
Mark-to-market income (loss), net	(47		)	16			(63		)
Contract amortization	(13		)	(25		)	12
Other	7			17			(10		)
Total operating revenues	1,137			1,281			(144		)
Operating Costs
Cost of sales	(762		)	(830		)	68
Contract amortization	21			37			(16		)
Total operating costs	(741		)	(793		)	52
Gross margin	396			488			(92		)
Operating and maintenance expense	(347		)	(389		)	42
Depreciation expense	(81		)	(68		)	(13		)
Impairments	(793		)	(74		)	(719		)
Gain on sale of assets, net	1			—			1
Acquisition and integration costs	8			—			8
Other	(16		)	—			(16		)
Operating loss	(832		)	(43		)	(789		)
Depreciation and amortization expense	87			73			14
Bankruptcy reorganization items	(96		)	—			(96		)
Other income and expense, net	15			1			14
EBITDA	(826		)	31			(857		)
Adjustments to reflect Adjusted EBITDA from noncontrolling interest	2			3			(1		)
Acquisition, integration and restructuring costs	(8		)	—			(8		)
Bankruptcy reorganization items	96			—			96
Mark-to-market adjustments	47			(16		)	63
Impairments	793			74			719
Gain on sale of assets, net	(1		)	—			(1		)
Non-cash compensation expense	6			—			6
Other (1)	20			12			8
Adjusted EBITDA	$	129		$	104		$	25
Million Megawatt Hours Generated	29.8			34.4			(4.6		)
IMA for Coal-Fired Facilities (2)	89		%	88		%
Average Capacity Factor for Coal-Fired Facilities (3)	53		%	56		%
CDDs (4)	1,652			1,425			227
HDDs (4)	4,662			5,061			(399		)
Average Market On-Peak Power Prices ($/MWh) (5):
Indiana (Indy Hub)	$	33.71		$	33.50		$	0.21
Commonwealth Edison (NI Hub)	$	31.98		$	33.98		$	(2.00	)

_______________________________________

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(1) Other includes an adjustment to exclude Wood River’s energy margin and O&M costs of $23 million for the year ended December 31, 2016. Adjusted EBITDA did not include this adjustment for the year ended December 31, 2015.

(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 quoted prices for the periods presented and does not necessarily reflect prices we realized.

Operating loss increased by $789 million primarily due to the following:

	(in millions)
Lower energy margin due to the following:
Lower dark spreads, net of hedges as a result of mild winter weather	$	(33	)
Lower generation volumes as a result of mild winter weather and shutdowns in 2016	$	(28	)
Lower retail contribution as a result of milder weather	$	(4	)
Coal inventory adjustments at Baldwin & Wood River	$	(7	)
Fuel and transportation costs related to Wood River shutdown	$	(14	)
Higher capacity revenues as a result of higher pricing and volumes	$	67
Change in MTM value of derivative transactions	$	(63	)
Termination of an above market coal supply contract in 2016	$	(15	)
Lower O&M costs due to shutdowns in 2016 and fewer outages	$	42
Higher depreciation and amortization	$	(17	)
Higher impairment charges primarily due to our Baldwin and Newton facilities in 2016	$	(719	)

Adjusted EBITDA increased by $25 million primarily due to the following:

	(in millions)
Lower energy margin due to the following:
Lower dark spreads, net of hedges as a result of mild winter weather	$	(25	)
Lower generation volumes as a result of mild winter weather and shutdowns in 2016	$	(28	)
Lower retail contribution as a result of milder weather	$	(4	)
Higher fuel costs incurred in 2016 as a result of 2015 coal inventory management efforts and a coal inventory adjustment	$	(13	)
Higher capacity revenues as a result of higher pricing and volumes	$	67
Lower O&M costs due to fewer outages	$	27

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CAISO Segment

The following table provides summary financial data regarding our CAISO segment results of operations for the years ended December 31, 2016 and 2015, respectively:

	Year Ended December 31,						Favorable (Unfavorable) $ Change
(dollars in millions, except for price information)	2016			2015
Operating Revenues
Energy	$	88		$	125		$	(37	)
Capacity	40			31			9
Mark-to-market income, net	—			4			(4		)
Contract amortization	(10		)	(7		)	(3		)
Other	24			25			(1		)
Total operating revenues	142			178			(36		)
Operating Costs
Cost of sales	(69		)	(105		)	36
Total operating costs	(69		)	(105		)	36
Gross margin	73			73			—
Operating and maintenance expense	(36		)	(32		)	(4		)
Depreciation expense	(42		)	(48		)	6
Loss on sale of assets, net	—			(1		)	1
Operating loss	(5		)	(8		)	3
Depreciation and amortization expense	53			55			(2		)
Other income and expense, net	12			—			12
EBITDA	60			47			13
Mark-to-market adjustments	—			(4		)	4
Loss on sale of assets, net	—			1			(1		)
Other	(1		)	—			(1		)
Adjusted EBITDA	$	59		$	44		$	15
Million Megawatt Hours Generated	2.6			4.0			(1.4		)
IMA for Combined-Cycle Facilities (1)	96		%	96		%
Average Capacity Factor for Combined-Cycle Facilities (2)	27		%	38		%
CDDs (3)	$	1,211		$	1,480		$	(269	)
HDDs (3)	$	1,218		$	1,237		$	(19	)
Average Market On-Peak Spark Spreads ($/MWh) (4):
North of Path 15 (NP 15)	$	12.67		$	14.32		$	(1.65	)
Average Market On-Peak Power Prices ($/MWh) (5):
North of Path 15 (NP 15)	$	31.60		$	35.23		$	(3.63	)
Average natural gas price—PG&E Citygate ($/MMBtu) (6)	$	2.70		$	2.99		$	(0.29	)

__________________________________________

(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. This 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 ISO-NE 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.

72

(5) Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.

(6) Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us.

Operating loss 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 fuel costs	$	(7	)
Higher capacity revenues due to higher contracted volumes	$	9

Adjusted EBITDA increased by $15 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 fuel costs	$	(7	)
Higher capacity revenues due to higher contracted volumes	$	9
Supplier settlement	$	12

Outlook

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, as well as our PRIDE and ECI initiatives.

On October 29, 2017, Dynegy and Vistra Energy entered into the Merger Agreement. We expect the transaction to close in the second quarter of 2018 after meeting the remaining customary conditions, including (a) stockholder approval and (b) regulatory approvals including FERC, the Public Utility Commission of Texas and the New York Public Service Commission.    

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 has been a historical trend toward greater environmental regulation of all aspects of our business. To the extent this trend continues, it is possible that we will experience additional costs related to water, air, and coal ash regulations.

Certain states (Illinois, New York and Connecticut) in our markets have passed legislation or orders whereby those states will subsidize or could subsidize certain nuclear energy producers. We believe these subsidies have and will continue to 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 New Jersey, Pennsylvania, and Ohio are also considering similar nuclear subsidy programs. Please read Item 1. Business-Market Discussion 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, NY/NE, and MISO segments, and in accordance with our risk management policy.

Our Operating Segments

PJM Segment. The PJM segment is comprised of 19 power generation facilities located within the PJM region, with a total generating capacity of 11,704 MW. We have recently announced the planned retirements of our jointly owned Stuart (679 MW related to our ownership) and Killen (204 MW related to our ownership) facilities by mid-2018.

In PJM, we have installed 325 MW of uprates since 2014, primarily through upgrades to the hot gas path components of our combined-cycle gas turbines. We are installing an additional 18 MW of uprates in the spring of 2018 at our Pleasants peaking facility.

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PJM introduced its new 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 2019 is primarily open to benefit from possible future power market pricing improvements.

The following table reflects our hedging activities as of February 8, 2018:

	2018	2019	2020 to 2022
Generation volumes hedged	78%	40%	5%
Coal requirements contracted (1)	99%	100%	33%
Coal requirements priced (1)	99%	58%	6%
Coal transportation requirements contracted (1)	100%	100%	100%

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(1) Excludes non-operated jointly-owned generating units.

PJM Capacity Market. The most recent RPM auction results, for the zones in which our assets are located, are as follows for each Planning Year:

	2017-2018				2018-2019				2019-2020				2020-2021
(price per MW-day)	Legacy Capacity		CP		Base		CP		Base		CP		CP
RTO zone (1)	$	120.00	$	151.50	$	149.98	$	164.77	$	80.00	$	100.00	$	88.32
MAAC zone	$	120.00	$	151.50	$	149.98	$	164.77	$	80.00	$	100.00	$	86.04
EMAAC zone	$	120.00	$	151.50	$	210.63	$	225.42	$	99.77	$	119.77	$	187.87
COMED zone	$	120.00	$	151.50	$	200.21	$	215.00	$	182.77	$	202.77	$	188.12
ATSI zone	$	120.00	$	151.50	$	149.98	$	164.77	$	80.00	$	100.00	$	76.53
PPL zone	$	120.00	$	151.50	$	75.00	$	164.77	$	80.00	$	100.00	$	86.04

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(1) Planning Year 2020-2021 includes DEOK zone which broke out from RTO zone at $130.00 per MW-day.

Our capacity sales, net of purchases, aggregated by Planning Year and capacity type through Planning Year 2020-2021, are as follows:

	2017-2018	2018-2019	2019-2020	2020-2021
Legacy/Base auction capacity sold, net (MW)	2,920	1,910	1,413	—
CP auction capacity sold, net (MW)	7,276	7,804	8,159	8,558
Bilateral capacity sold, net (MW)	2	270	200	200
Total segment capacity sold, net (MW)	10,198	9,984	9,772	8,758
Average price per MW-day	$143.99	$180.72	$128.72	$130.13

NY/NE Segment. The NY/NE segment is comprised of seven power generation facilities located within the ISO-NE region (3,518 MW) and one power generation facility located within the NYISO region (1,212 MW), totaling 4,730 MW of electric generating capacity. We began retail activities in Massachusetts in 2017, providing additional channels to market for our ISO-NE plants.

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. Dynegy has been awarded six municipal load contracts encompassing 76,100 accounts in the state of MA.

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The following table reflects our hedging activities as of February 8, 2018:

	2018	2019	2020 to 2022
Generation volumes hedged (1)	64%	19%	3%

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(1) Excludes volumes subject to tolling agreements.

NYISO Capacity Market. 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:

	Summer 2017	Winter 2017-2018
Price per kW-month	$3.00	$0.37

Due to the short-term, seasonal nature of the NYISO capacity auctions, we monetize the majority of our capacity through bilateral trades. Our capacity sales, aggregated by season through Summer 2020, are as follows:

	Winter 2017-2018	Summer 2018	Winter 2018-2019	Summer 2019	Winter 2019-2020	Summer 2020
Auction capacity sold (MW)	122	—	—	—	—	—
Bilateral capacity sold (MW)	1,088	855	605	305	210	75
Total capacity sold (MW)	1,210	855	605	305	210	75
Average price per kW-month	$1.79	$3.12	$2.19	$3.06	$2.57	$3.15

ISO-NE Capacity Market. 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:

	2017-2018	2018-2019	2019-2020	2020-2021	2021-2022
Price per kW-month	$7.03	$9.55	$7.03	$5.30	$4.63

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 Planning Year 2021-2022.

Our capacity sales, aggregated by Planning Year through Planning Year 2021-2022, are as follows:

	2017-2018	2018-2019	2019-2020	2020-2021	2021-2022
Auction capacity sold (MW)	3,155	3,168	3,203	3,229	2,762
Bilateral capacity sold (MW)	148	86	30	—	—
Total capacity sold (MW)	3,303	3,254	3,233	3,229	2,762
Average price per kW-month	$6.92	$9.98	$7.02	$5.39	$4.79

ERCOT Segment. The ERCOT segment is comprised of six power generation facilities located within the ERCOT region, with a total generating capacity of 4,529 MW.

The following table reflects our hedging activities as of February 8, 2018:

	2018	2019	2020 to 2022
Generation volumes hedged	74%	26%	—%
Coal requirements contracted	100%	—%	—%
Coal requirements priced	100%	—%	—%
Coal transportation requirements contracted	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.

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MISO Segment. Our MISO segment is comprised of eight power generation facilities located in Illinois, totaling 5,476 MW of electric generating capacity.  Joppa, which is within the EEI 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 MISO 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 17 percent of MISO’s current capacity and energy, electrically tied into PJM through pseudo-tie arrangements. As of June 1, 2017, Hennepin began offering 260 MW of the facility’s energy and capacity into PJM as a block schedule and will begin dispatching as a pseudo-tie unit for Planning Year 2018-2019.

Dynegy’s portfolio beyond 2018 is primarily open to benefit from possible future power market pricing improvements. MISO will continue to use our retail business to hedge a portion of the output from our MISO facilities. The retail hedges are well correlated to our facilities due to the close proximity of the hedge and through participation in FTR markets. The following table reflects our hedging activities as of February 8, 2018:

	2018	2019	2020 to 2022
Generation volumes hedged	75%	39%	17%
Coal requirements contracted	91%	74%	43%
Coal requirements priced	90%	6%	5%
Coal transportation requirements contracted	100%	100%	99%

MISO Capacity Market. The capacity auction results for MISO Local Resource Zone 4, in which our assets are located, are as follows for each Planning Year:

	2017-2018
Price per MW-day	$1.50

Our MISO segment cleared no incremental volumes, in excess of our retail load obligations, in the MISO Planning Year 2017-2018 capacity auction. MISO capacity sales through Planning Year 2020-2021 are as follows:

	2017-2018	2018-2019	2019-2020	2020-2021
Bilateral capacity sold in MISO (MW)	3,506	2,269	1,978	1,520
Legacy/Base auction capacity sold in PJM (MW)	572	—	260	—
CP auction capacity sold in PJM (MW)	472	835	356	444
Total MISO segment capacity sold (MW)	4,550	3,104	2,594	1,964
Average price per kW-month	$4.01	$4.37	$3.72	$3.80

The results of the most recent MISO capacity auction continue to validate our strategy of right-sizing our MISO wholesale generation business to more closely match our retail business or to export capacity to PJM. Despite continuing low auction clearing prices, Dynegy has been able to effectively monetize much of its available MISO 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.

The following table reflects our hedging activities as of February 8, 2018:

	2018	2019	2020 to 2022
Generation volumes hedged	56%	24%	—%

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 Generic and Flexible RA capacity. On December 22, 2017, the CAISO issued a Capacity Procurement Mechanism designation on Moss Landing Unit 1 for 510 MW for 2018, which is reflected in our capacity sales table below.

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Our capacity sales, aggregated by calendar year for 2018 through 2020 for Moss Landing, are as follows:

	2018	2019	2020
Bilateral capacity sold (Avg MW)	966	850	—

We have also sold seasonal capacity for Moss Landing opportunistically. Our Oakland facility operated under an RMR contract with the CAISO for 2017 and was given notice of extension for 2018.

SEASONALITY

Our revenues and operating income are subject to fluctuations during the year, primarily due to the impact seasonal factors have on sales volumes and the prices of power and natural gas. Power marketing operations and generating facilities typically have higher volatility and demand in the summer cooling months and winter heating season.

CRITICAL ACCOUNTING POLICIES

Our Accounting Department is responsible for the development and application of accounting policy and control procedures. This department conducts these activities independent of any active management of our risk exposures, is independent of our business segments, and reports to the Chief Financial Officer (“CFO”).

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The process of preparing financial statements in accordance with GAAP requires our management to make estimates and judgments. It is possible that materially different amounts could be recorded if these estimates and judgments change or if actual results differ from these estimates and judgments. We have identified the following critical accounting policies that require a significant amount of estimation and judgment and are considered important to the portrayal of our financial position and results of operations:

Description	Judgments and Uncertainties	Effect if Actual Results Differ From Assumptions
Derivative Instruments
Commodity contracts that meet the definition of a derivative are often entered into to mitigate or eliminate market and financial risks associated with our generation business. These contracts include forward contracts, which commit us to sell commodities in the future; futures contracts, which are generally broker-cleared standard commitments to purchase or sell a commodity; option contracts, which convey the right to buy or sell a commodity; and swap agreements, which require payments to or from counterparties based upon the differential between two prices for a predetermined quantity. There are two different ways to account for these types of commodity contracts, as Dynegy does not elect hedge accounting for any of its derivative instruments: (i) as an accrual contract, if the criteria for the “normal purchase, normal sale” exception are met, documented, and elected; or (ii) as a mark-to-market contract with changes in fair value recognized in current period earnings. Comparability of our financial statements to our peers for similar contracts may not be possible due to differences in electing the “normal purchase, normal sale” exception or electing hedge accounting. We are exposed to changes in interest rate risk through our variable rate debt and enter into interest rate swaps to manage our interest rate risk with the changes in fair value recorded currently to interest expense. Our interest-based derivative instruments are not designated as hedges of our variable debt. We elect to offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting agreement and we elect to offset the fair value of amounts recognized for the cash collateral paid or received against the fair value of amounts recognized for derivative instruments executed with the same counterparty under a master netting agreement.	We utilize market data or assumptions, including assumptions about risk and the risks inherent in the inputs to the valuation technique, primarily forward price curves, pricing risk, and credit risk. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. These inputs are classified into three levels of fair value hierarchy under GAAP and described as actively quoted market prices (Level 1), directly or indirectly observable (Level 2), or generally unobservable (Level 3). Those inputs include not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), but also the impact of our nonperformance risk on our liabilities. Valuation adjustments are generally based on capital market implied ratings when assessing the credit standing of our counterparties, and when applicable, adjusted based on management’s estimates of assumptions market participants would use in determining fair value.	Changes to our assumptions for the fair value of our derivative instruments could result in a material change to the fair value of our risk management assets and liabilities recorded to our consolidated balance sheets and corresponding changes in fair value recorded to our consolidated statements of operations. Please read Note 5-Fair Value Measurements for further discussion of our assumptions.

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Description	Judgments and Uncertainties	Effect if Actual Results Differ From Assumptions
Accounting for Income Taxes
We file a consolidated U.S. federal income tax return. We use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant differences. We also account for changes in the tax code when enacted. Because we operate and sell power in many different states, our effective annual state income tax rate may vary from period to period due to changes in our sales profile by state, as well as jurisdictional and legislative changes by state. As a result, changes in our estimated effective annual state income tax rate can have a significant impact on our measurement of temporary differences. We conduct a valuation assessment on our deferred tax assets, which involves an extensive analysis of positive and negative evidence, to determine if it is more likely than not that they will not be realized.	As part of the process of preparing our consolidated financial statements, we are required to estimate our income taxes in each of the jurisdictions in which we operate. This process involves estimating our actual current tax payable and related tax expense together with assessing temporary differences resulting from differing tax and accounting treatment of certain items, such as depreciation, for tax and accounting purposes. We project the rates at which state tax temporary differences will reverse based upon estimates of revenues and operations in the respective jurisdictions in which we conduct business. The guidance related to accounting for income taxes also require that a valuation allowance be established when it is more likely than not that all or a portion of a deferred tax asset will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income of the appropriate character during the periods in which those temporary differences are deductible. In making this determination, management considers all available positive and negative evidence affecting specific deferred tax assets, including our past and anticipated future performance, the reversal of deferred tax liabilities and the implementation of tax planning strategies.	Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A change in the future taxable income assumptions used to determine our need for a valuation allowance can result in more or less deferred tax assets being recognized in our financial statements. The ultimate tax outcome is uncertain and the assumptions used on the utilization of tax benefits in the future can change primarily as a consequence of newly enacted tax laws and management’s view of future taxable income. These changes can materially affect our overall financial results.
Accounting for uncertainty in income taxes requires that we determine whether it is more likely than not that a tax position we have taken will be sustained upon examination. If we determine that it is more likely than not that the position will be sustained, we recognize the largest amount of the benefit that is greater than 50 percent likely of being realized upon settlement.	There is a significant amount of judgment involved in assessing the likelihood that a tax position will be sustained upon examination and in determining the amount of the benefit that will ultimately be realized.	A change in our assumptions assessing the likelihood that a tax position will be sustained upon examination may change the amount of tax benefit that is recognized in our financial statements. Please read Note 14-Income Taxes for further discussion of our accounting for income taxes, uncertain tax positions, and changes in our valuation allowance.

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Description	Judgments and Uncertainties	Effect if Actual Results Differ From Assumptions
Business Combinations
Accounting Standards Codification (“ASC”) 815, Business Combinations requires that the purchase price for a business combination be assigned and allocated to the identifiable assets acquired and liabilities assumed based upon their fair value. Generally, the amount recorded in the financial statements for an acquisition’s assets and liabilities is equal to the purchase price (the fair value of the consideration paid); however, a purchase price that exceeds the fair value of the net assets acquired will result in the recognition of goodwill. Conversely, a purchase price that is below the fair value of the net assets acquired will result in the recognition of a bargain purchase in the income statement. In addition to the potential for the recognition of goodwill or a bargain purchase, differing fair values will impact the allocation of the purchase price to the individual assets and liabilities and can impact the gross amount and classification of assets and liabilities recorded in our consolidated balance sheets, which can impact the timing and amount of depreciation and amortization expense recorded in any given period.	In estimating fair value, we use discounted cash flow (“DCF”) projections, recent comparable market transactions, if available, or quoted prices. We consider assumptions that third parties would make in estimating fair value, including, but not limited to, the highest and best use of the asset. There is a significant amount of judgment involved in cash-flow estimates, including assumptions regarding market convergence, discount rates, commodity prices, useful lives and growth factors. The assumptions used by another party could differ significantly from our assumptions. We utilize our best effort to make our determinations and review all information available, including estimated future cash flows and prices of similar assets when making our best estimate. We also may hire independent appraisers or valuation specialists to help us make this determination as we deem appropriate under the circumstances. Refer to Note 3—Acquisitions and Divestitures for further discussion of assumptions used in acquisitions.	There is a significant amount of judgment in determining the fair value of acquisitions and in allocating the purchase price to individual assets and liabilities. Had different assumptions been used, the fair value of the assets acquired and liabilities assumed could have been significantly higher or lower with a corresponding increase or reduction in recognized goodwill, or could have required recognition of a bargain purchase.

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Description	Judgments and Uncertainties	Effect if Actual Results Differ From Assumptions
Impairment of Long-Lived Assets
ASC 360, Property, Plant and Equipment (“PP&E”) requires for an entity to assess whether the recorded values of PP&E and finite-lived intangible assets have become impaired when certain indicators of impairment exist.  Examples of these indicators include, but are not limited to: ● a significant decrease in the market price of a long-lived asset (asset group); ● a significant adverse change in the extent or manner in which a long-lived asset (asset group) is being used, or in its physical condition; ● a significant adverse change in legal factors or in the business climate that could affect the value of a long-lived asset (asset group), including an adverse action or assessment by a regulator; ● an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset (asset group); ● a current-period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset (asset group); and ● a current expectation that it is more likely than not a long-lived asset (asset group) will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.	Determining whether an impairment trigger exists involves significant judgment by management which may result in a different answer if our peers were to consider the same facts and circumstances. If it is determined that the asset’s value is not recoverable, then we will perform step two of the impairment analysis and fair value the asset using a DCF model and record an impairment charge to reduce the value of the asset to its fair value.  The assumptions and estimates used by management to assess whether the asset may have become impaired, whether the asset’s value is recoverable, and to determine the fair value of the estimate are significant and may vary materially from the assumptions used by our peers. Examples of the assumptions and estimates used by management include: ● determination of increases/decreases in the market price of an asset being a short-term or long-term, fundamental change; ● the highest and best use of the asset; ● forecasted environmental changes; ● forecasted regulatory changes; ● management’s fundamental view of the long-term pricing environment for energy and capacity; ● management’s forecast of gross margin, capital expenditures, and operations and maintenance costs; ● remaining useful life of our assets; ● salvage value; ● discount rates; and ● inflation rates. The assumptions used in impairment analyses often include unobservable inputs that are based on management’s long-term view of our assets remaining useful lives, operating margin and capital requirements.	Changes in market economics and environmental requirements can alter previous assumptions and trigger impairment charges that can materially differ from the results we have reported herein.

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Description	Judgments and Uncertainties	Effect if Actual Results Differ From Assumptions
Goodwill Impairment
We record goodwill when the purchase price for an acquisition classified as a business combination exceeds the estimated net fair value of the identifiable tangible and intangible assets acquired. The amount of goodwill which can be recognized as part of an acquisition can change materially based upon the assumptions used when determining the net fair value of those assets. We allocate goodwill to reporting units based on the relative fair value of the purchased operating assets assigned to those reporting units. ASC 350, Intangibles-Goodwill and Other requires an entity to assess whether goodwill has become impaired at least annually, or when certain indicators of impairment exist on an interim basis. We have elected October 1 for our annual assessment. Examples of the indicators of impairment include, but are not limited to: ● a deterioration of general economic conditions, limitation on accessing capital, or other developments in equity and credit markets; ● increases in costs which have a negative effect on earnings and cash flows; ● overall financial performance such as negative or declining cash flows or a decline in actual or planned revenue or earnings; ● other relevant entity-specific events such as changes in management, key personnel, strategy, or customers, contemplation of bankruptcy, or litigation; ● a more likely than not expectation of selling or disposing all, or a portion, of a reporting unit; and, ● recognition of a goodwill impairment loss in the financial statements of a subsidiary that is a component of a reporting unit.	Determining whether a goodwill impairment trigger exists involves significant judgment by management, which may result in a different answer if our peers were to consider the same facts and circumstances.  The assumptions and estimates used by management to determine the fair value of our reporting units and goodwill for step one, and the fair value of our equity to reconcile to our market capitalization, are significant and require management judgment.  Some examples of the assumptions and estimates used include: ● the highest and best use of the reporting units assets; ● recent comparable market transactions, if available, or quoted prices; ● management’s forecast of gross margin, capital expenditures, and operations and maintenance costs; ● forecasted environmental and regulatory changes; ● management’s fundamental view of the long-term pricing environment for energy and capacity; ● remaining useful life of our assets; ● salvage value; ● discount rates; and ● inflation rates.	Changes in management’s assumptions and estimates regarding the fair value of these reporting units could result in a materially different result. The assumptions used in goodwill impairment analyses often include unobservable inputs that are based on management’s long-term view of the reporting unit asset’s remaining useful lives, operating margin and capital requirements. Changes in the reporting unit’s economics can alter previous assumptions and trigger impairment charges that can materially affect our financial results.

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Description	Judgments and Uncertainties	Effect if Actual Results Differ From Assumptions
Goodwill Impairment (Continued)
In the event management determines an impairment indicator exists or is performing the annual assessment, ASC 350 allows an entity to elect to qualitatively assess whether it is more likely than not (a likelihood of more than 50 percent) that an impairment has occurred.  If we determine that it is more likely than not that goodwill has become impaired, we will impair goodwill by the amount by which the carrying value of the reporting unit, including goodwill, exceeds its fair value that will be retained. When we dispose of a reporting unit or a portion of a reporting unit that constitutes a business, we include goodwill associated with that business in the carrying amount of the business in order to determine the gain or loss on sale. The amount of goodwill to be included in that carrying amount is based on the relative fair value of the business to be disposed of as compared to the portion of the reporting unit that will be retained.

RECENT ACCOUNTING PRONOUNCEMENTS

Please read Note 2—Summary of Significant Accounting Policies for further discussion of accounting principles adopted and accounting principles not yet adopted.

RISK MANAGEMENT DISCLOSURES

The following table provides a reconciliation of the risk management data contained within our consolidated balance sheets on a net basis:

(amounts in millions)	As of and for the Year Ended December 31, 2017
Fair value of portfolio at December 31, 2016	$	6
Risk management losses recognized through the statement of operations in the period, net	(223		)
Contracts realized or otherwise settled during the period	16
Cash received related to option premiums	(3		)
Acquired derivatives	9
Change in collateral/margin netting	(7		)
Fair value of portfolio at December 31, 2017	$	(202	)

The net risk management liability of $202 million is the aggregate of the following line items in our 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.

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Risk Management Asset and Liability Disclosures.  The following table provides an assessment of net contract values by year as of December 31, 2017, based on our valuation methodology: 

Net Fair Value of Risk Management Portfolio

(amounts in millions)	Total			2018			2019			2020		2021		2022		Thereafter
Market quotations (1)(2)	$	(224	)	$	(219	)	$	(21	)	$	3	$	4	$	4	$	5
Prices based on models (2)	(25		)	(25		)	—			—		—		—		—
Total (3)	$	(249	)	$	(244	)	$	(21	)	$	3	$	4	$	4	$	5

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(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—Fair Value Measurements for further discussion.

(3) Excludes $47 million of broker margin that has been netted against Risk management liabilities in our consolidated balance sheets. Please read Note 4—Risk Management Activities, Derivatives and Financial Instruments for further discussion.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to commodity price variability related to our power generation business. In order to manage these commodity price risks, we routinely utilize various fixed-price forward purchase and sales contracts, futures and option contracts traded on the New York Mercantile Exchange (“NYMEX”) or the Intercontinental Exchange, and swaps and options traded in the OTC financial markets to:

• manage and hedge our fixed-price purchase and sales commitments;

• reduce our exposure to the volatility of cash market prices; and

• hedge our fuel requirements for our generating facilities.

The potential for changes in the market value of our commodity and interest rate portfolios is referred to as “market risk.” A description of each market risk category is set forth below:

• commodity price risks result from exposures to changes in spot prices, forward prices and volatilities in commodities, such as electricity, natural gas, coal, fuel oil, emissions and other similar products; and

• interest rate risks primarily result from exposures to changes in the level, slope and curvature of the yield curve and the volatility of interest rates.

In the past, we have managed these market risks through diversification, controlling position sizes, and executing hedging strategies. The ability to manage an exposure may, however, be limited by adverse changes in market liquidity, our credit capacity, or other factors.

Value at Risk (“VaR”).  The modeling of the risk characteristics of our mark-to-market portfolio involves a number of assumptions and approximations. We estimate VaR using a Monte Carlo simulation-based methodology. Inputs for the VaR calculation are prices, positions, instrument valuations, and the variance-covariance matrix. VaR does not account for liquidity risk or the potential that adverse market conditions may prevent liquidation of existing market positions in a timely fashion. While management believes that these assumptions and approximations are reasonable, there is no uniform industry methodology for estimating VaR, and different assumptions and/or approximations could produce materially different VaR estimates.

We use historical data to estimate our VaR and, to better reflect current asset and liability volatilities, this historical data is weighted to give greater importance to more recent observations. Given our reliance on historical data, VaR is effective in estimating risk exposures in markets in which there are no sudden fundamental changes or abnormal shifts in market conditions. An inherent limitation of VaR is that past changes in market risk factors, even when weighted toward more recent observations, may not produce accurate predictions of future market risk. VaR should be evaluated in light of this and the methodology’s other limitations.

VaR represents the potential loss in value of our mark-to-market portfolio due to adverse market movements over a defined time horizon within a specified confidence level. For the VaR numbers reported below, a one-day time horizon and a 95 percent confidence level were used. This means that there is a one in 20 chance that the daily portfolio value will drop in value by an amount larger than the reported VaR. Thus, an adverse change in portfolio value greater than the expected change in portfolio value on a single trading day would be anticipated to occur, on average, about once a month. Gains or losses on a single day can

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exceed reported VaR by significant amounts. Gains or losses can also accumulate over a longer time horizon such as a number of consecutive trading days.

In addition, we have provided our VaR using a one-day time horizon with a 99 percent confidence level. The purpose of this disclosure is to provide an indication of earnings volatility using a higher confidence level. Under this presentation, there is a one in 100 statistical chance that the daily portfolio value will fall below the expected maximum potential reduction in portfolio value at least as large as the reported VaR. We have also disclosed a two-year comparison of daily VaR in order to provide context for the one-day amounts.

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.    

Daily and Average VaR for Risk-Management Portfolios

(amounts in millions)	December 31, 2017		December 31, 2016
One day VaR—95 percent confidence level	$	36	$	38
One day VaR—99 percent confidence level	$	53	$	53
Average VaR—95 percent confidence level for the rolling twelve months ended	$	13	$	14

Credit Risk.  Credit risk represents the loss that we would incur if a counterparty fails to perform pursuant to the terms of its contractual obligations. To reduce our credit exposure, we execute agreements that permit us to offset receivables, payables, and mark-to-market exposure. We attempt to reduce credit risk further with certain counterparties by obtaining third-party guarantees or collateral as well as the right of termination in the event of default.

Our Credit Department, based on guidelines approved by the Board of Directors, establishes our counterparty credit limits. Our industry typically operates under negotiated credit lines for physical delivery and financial contracts. Our credit risk system provides current credit exposure of wholesale counterparties on a daily basis and outstanding receivable size and aging information of retail customers on a weekly basis.

The following table represents our credit exposure at December 31, 2017 associated with the wholesale mark-to-market portion of our risk-management portfolio, on a net basis. We had exposure of less than $1 million related to non-investment grade quality counterparties.

Credit Exposure Summary

(amounts in millions)	Investment Grade Quality
Type of Business:
Financial institutions	$	1
Utility and power generators	6
Total	$	7

Interest Rate Risk

We are exposed to fluctuating interest rates related to our variable rate debt obligations outstanding under our Credit Agreement. We have entered into interest rate swaps to mitigate interest rate exposure through changes in LIBOR, which results in a partially fixed interest rate for our debt obligations.  Our interest rate hedging instruments are recorded at their fair value, with changes in mark-to-market reflected in earnings.  An increase in LIBOR by 25 basis points would result in a $0.1 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 December 31, 2017 and December 31, 2016, respectively:

	December 31, 2017			December 31, 2016
Interest rate swaps (in millions of U.S. dollars)	$	1,961		$	769
Fixed interest rate paid (percent)	2.38		%	3.19		%

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Item 8.    Financial Statements and Supplementary Data

The report of our independent registered public accounting firm and our Consolidated Financial Statements and Financial Statement Schedules are filed pursuant to this Item 8 and are included later in this report. See Index to Consolidated Financial Statements and Financial Statement Schedules on page F-1.

Item 9.    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Not applicable.

Item 9A.    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 management, including our Chief Executive Officer (“CEO”) and our CFO, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). 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 December 31, 2017.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act). Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. Our internal control over financial reporting includes those policies and procedures that:

(i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

(ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of our company are being made only in accordance with authorizations of our management and directors; and

(iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Under the supervision and with the participation of our management, including the CEO and CFO, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2017. In making this assessment, we used the criteria set forth in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013. Based on the results of this assessment and on those criteria, we concluded that our internal control over financial reporting was effective as of December 31, 2017.

The effectiveness of our internal control over financial reporting as of December 31, 2017 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report, which is included herein.

Changes in Internal Controls Over Financial Reporting

There were no changes in our internal controls over financial reporting that materially affected or are reasonably likely to materially affect our internal controls over financial reporting during the quarter ended December 31, 2017.

Item 9B.    Other Information

Not applicable.

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PART III

Item 10.    Directors, Executive Officers and Corporate Governance

Executive Officers.  We intend to include the information with respect to our executive officers required by this Item 10 in our definitive proxy statement for our 2018 annual meeting of stockholders under the heading “Executive Officers,” which information will be incorporated herein by reference; such proxy statement will be filed with the SEC not later than 120 days after December 31, 2017. However, if such proxy statement is not filed within such 120-day period, information with respect to Executive Officers will be filed as part of an amendment to this Form 10-K not later than the end of the 120-day period.

Code of Ethics.  We have adopted a Code of Ethics within the meaning of Item 406(b) of Regulation S-K. This Code of Ethics applies to our CEO, CFO, Chief Accounting Officer, and other persons performing similar functions designated by the CFO, and is filed as an exhibit to this Form 10-K.

Other Information.  We intend to include the other information required by this Item 10 in our definitive proxy statement for our 2018 annual meeting of stockholders under the headings “Proposal 1—Election of Directors” and “Compliance with Section 16(a) of the Exchange Act,” which information will be incorporated herein by reference; such proxy statement will be filed with the SEC not later than 120 days after December 31, 2017. However, if such proxy statement is not filed within such 120-day period, information with respect to Other Information will be filed as part of an amendment to this Form 10-K not later than the end of the 120-day period.

Item 11.    Executive Compensation

We intend to include information with respect to executive compensation in our definitive proxy statement for our 2018 annual meeting of stockholders under the heading “Executive Compensation,” which information will be incorporated herein by reference; such proxy statement will be filed with the SEC not later than 120 days after December 31, 2017. However, if such proxy statement is not filed within such 120-day period, information with respect to executive compensation will be filed as part of an amendment to this Form 10-K not later than the end of the 120-day period.

Item 12.    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

We intend to include information regarding ownership of our outstanding securities in our definitive proxy statement for our 2018 annual meeting of stockholders under the heading “Security Ownership of Certain Beneficial Owners and Management” which information will be incorporated herein by reference; such proxy statement will be filed with the SEC not later than 120 days after December 31, 2017. However, if such proxy statement is not filed within such 120-day period, information with respect to beneficial ownership will be filed as part of an amendment to this Form 10-K not later than the end of the 120-day period.

SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS

The following table sets forth certain information as of December 31, 2017, as it relates to our equity compensation plans for our common stock:

Plan Category	Number of securities to be issued upon exercise of outstanding options and rights (a)	Weighted-average exercise price of outstanding options and rights (b)		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)
Equity compensation plans approved by security holders (1)	6,929,289	$	14.02	115,176
Equity compensation plans not approved by security holders	—	—		—
Total	6,929,289	$	14.02	115,176

__________________________________________

(1) The plan that is approved by our security holders is the 2012 Long Term Incentive Plan, as amended. Please read Note 15—Stockholders’ Equity—Stock Award Plans for further discussion.

Item 13.    Certain Relationships and Related Transactions, and Director Independence

We intend to include the information regarding related party transactions and director independence in our definitive proxy statement for our 2018 annual meeting of stockholders under the headings “Transactions with Related Persons, Promoters

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and Certain Control Persons,” and “Corporate Governance,” respectively, which information will be incorporated herein by reference; such proxy statement will be filed with the SEC not later than 120 days after December 31, 2017. However, if such proxy statement is not filed within such 120-day period, information with respect to certain relationships will be filed as part of an amendment to this Form 10-K not later than the end of the 120-day period.

Item 14.    Principal Accountant Fees and Services

We intend to include information regarding principal accountant fees and services in our definitive proxy statement for our 2018 annual meeting of stockholders under the heading “Independent Registered Public Auditors—Principal Accountant Fees and Services,” which information will be incorporated herein by reference; such proxy statement will be filed with the SEC not later than 120 days after December 31, 2017. However, if such proxy statement is not filed within such 120-day period, information with respect to the principal accountant fees and services will be filed as part of an amendment to this Form 10-K not later than the end of the 120-day period.

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PART IV

Item 15.    Exhibits and Financial Statement Schedules

(a)   The following documents, which we have filed with the SEC pursuant to the Securities Exchange Act of 1934, as amended, are by this reference incorporated in and made a part of this report:

1. Financial Statements—Our consolidated financial statements are incorporated under Item 8. of this report.

2. Financial Statement Schedules—Financial Statement Schedules are incorporated under Item 8. of this report.

3. Exhibits—The following instruments and documents are included as exhibits to this report.

Exhibit Number	Description
1.1	Underwriting Agreement relating to the 4,000,000 7.00% Tangible Equity Units, dated as of June 15, 2016, among Dynegy Inc., Morgan Stanley & Co. LLC, and RBC Capital Markets, LLC (incorporated by reference to Exhibit 1.1 to the Current Report on Form 8-K of Dynegy Inc. filed on June 21, 2016 File No. 001-33443).
2.1	Confirmation Order for Dynegy Inc. and Dynegy Holdings, LLC, as entered by the United States Bankruptcy Court for the Southern District of New York on September 10, 2012 (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. and Dynegy Holdings, LLC filed on September 13, 2012 File No. 001-33443).
2.2	Purchase and Sale Agreement by and among Duke Energy SAM, LLC and Duke Energy Commercial Enterprises, Inc., as sellers, and Dynegy Resources I, LLC, as buyer, dated as of August 21, 2014 (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. filed on August 26, 2014 File No. 001-33443).*
2.3	Letter Agreement to Purchase and Sale Agreement by and among Duke Energy SAM, LLC and Duke Energy Commercial Enterprises, Inc., as sellers, and Dynegy Resources I, LLC, as buyer, dated as of October 24, 2014 (incorporated by reference to Exhibit 2.2 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2014 of Dynegy Inc. File No. 001-33443).*
2.4	Stock Purchase Agreement by and among Energy Capital Partners II, LP, Energy Capital Partners II-A, LP, Energy Capital Partners II-B, LP, Energy Capital Partners II-C (Direct IP), LP, Energy Capital Partners II-D, LP and Energy Capital Partners II (EquiPower Co-Invest), LP, Energy Capital Partners II-C, LP, for the limited purposes set forth therein, EquiPower Resources Corp., Dynegy Resource II, LLC, and Dynegy Inc., for the limited purposes set forth therein, dated as of August 21, 2014 (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K of Dynegy Inc. filed on August 26, 2014 File No. 001-33443).*
2.5	Letter Agreement to Purchase and Sale Agreement by and among Energy Capital Partners II, LP, Energy Capital Partners II-A, LP, Energy Capital Partners II-B, LP, Energy Capital Partners II-C (Direct IP), LP, Energy Capital Partners II-D, LP and Energy Capital Partners II (EquiPower Co-Invest), LP, Energy Capital Partners II-C, LP, for the limited purposes set forth therein, EquiPower Resources Corp., Dynegy Resource II, LLC, and Dynegy Inc., for the limited purposes set forth therein, dated November 12, 2014 (incorporated by reference to Exhibit 2.5 to the Annual Report on Form 10-K for the Year Ended December 31, 2014 of Dynegy Inc. File No. 001-33443).
2.6	Letter Agreement to Purchase and Sale Agreement by and among Energy Capital Partners II, LP, Energy Capital Partners II-A, LP, Energy Capital Partners II-B, LP, Energy Capital Partners II-C (Direct IP), LP, Energy Capital Partners II-D, LP and Energy Capital Partners II (EquiPower Co-Invest), LP, Energy Capital Partners II-C, LP, for the limited purposes set forth therein, EquiPower Resources Corp., Dynegy Resource II, LLC, and Dynegy Inc., for the limited purposes set forth therein, dated March 30, 2015 (incorporated by reference to Exhibit 2.1 to the Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2015 of Dynegy Inc. File No. 001-33443).*
2.7	Amendment to Stock Purchase Agreement, dated as of March 30, 2015, by and among Energy Capital Partners II, LP, Energy Capital Partners II-A, LP, Energy Capital Partners II-B, LP, Energy Capital Partners II-C (Direct IP), LP, Energy Capital Partners II-D, LP and Energy Capital Partners II (EquiPower Co-Invest), LP, Energy Capital Partners II-C, LP, for the limited purposes set forth therein, EquiPower Resources Corp., Dynegy Resource II, LLC, and Dynegy Inc., for the limited purposes set forth therein (incorporated by reference to Exhibit 2.1 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on April 1, 2015).
2.8	Stock Purchase Agreement and Agreement and Plan of Merger by and among Energy Capital Partners GP II, LP, Energy Capital Partners II, LP, Energy Capital Partners II-A, LP, Energy Capital Partners II-B, LP, Energy Capital Partners II-D, LP, Energy Capital Partners II-C (Cayman), LP, Energy Capital Partners II-C, LP, for the limited purposes set forth therein, Brayton Point Holdings, LLC, Dynegy Resource III, LLC, Dynegy Resource III-A, LLC, and Dynegy Inc., for the limited purposes set forth therein, dated as of August 21, 2014 (incorporated by reference to Exhibit 2.3 to the Current Report on Form 8-K of Dynegy Inc. filed on August 26, 2014 File No. 001-33443).*

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2.9	Letter Agreement to Purchase and Sale Agreement by and among Energy Capital Partners II, LP, Energy Capital Partners II-A, LP, Energy Capital Partners II-B, LP, Energy Capital Partners II-C (Direct IP), LP, Energy Capital Partners II-D, LP and Energy Capital Partners II (EquiPower Co-Invest), LP, Energy Capital Partners II-C, LP, for the limited purposes set forth therein, EquiPower Resources Corp., Dynegy Resource II, LLC, and Dynegy Inc., for the limited purposes set forth therein, and Stock Purchase Agreement and Agreement and Plan of Merger by and among Energy Capital Partners GP II, LP, Energy Capital Partners II, LP, Energy Capital Partners II-A, LP, Energy Capital Partners II-B, LP, Energy Capital Partners II-D, LP, Energy Capital Partners II-C (Cayman), LP, Energy Capital Partners II-C, LP, for the limited purposes set forth therein, Brayton Point Holdings, LLC, Dynegy Resource III, LLC, Dynegy Resource III-A, LLC, and Dynegy Inc., for the limited purposes set forth therein dated November 25, 2014 (incorporated by reference to Exhibit 2.7 to the Annual Report on Form 10-K for the Year Ended December 31, 2014 of Dynegy Inc. File No. 001-33443).
2.10	Revised Attachment A to the Letter Agreement to Purchase and Sale Agreement by and among Energy Capital Partners II, LP, Energy Capital Partners II-A, LP, Energy Capital Partners II-B, LP, Energy Capital Partners II-C (Direct IP), LP, Energy Capital Partners II-D, LP and Energy Capital Partners II (EquiPower Co-Invest), LP, Energy Capital Partners II-C, LP, for the limited purposes set forth therein, EquiPower Resources Corp., Dynegy Resource II, LLC, and Dynegy Inc., for the limited purposes set forth therein, and Stock Purchase Agreement and Agreement and Plan of Merger by and among Energy Capital Partners GP II, LP, Energy Capital Partners II, LP, Energy Capital Partners II-A, LP, Energy Capital Partners II-B, LP, Energy Capital Partners II-D, LP, Energy Capital Partners II-C (Cayman), LP, Energy Capital Partners II-C, LP, for the limited purposes set forth therein, Brayton Point Holdings, LLC, Dynegy Resource III, LLC, Dynegy Resource III-A, LLC, and Dynegy Inc., for the limited purposes set forth therein dated February 4, 2015 (incorporated by reference to Exhibit 2.8 to the Annual Report on Form 10-K for the Year Ended December 31, 2014 of Dynegy Inc. File No. 001-33443).
2.11	Stock Purchase Agreement, dated February 24, 2016, by and between Atlas Power Finance, LLC, GDF SUEZ Energy North America, Inc. and International Power, S.A. (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. filed on March 1, 2016 File No. 001-33443).*
2.12	First Amendment Stock Purchase Agreement, dated May 2, 2016, by and between Atlas Power Finance, LLC, GDF SUEZ Energy North America, Inc. and International Power, S.A. (incorporated by reference to Exhibit 2.2 to the Quarterly Report on Form 10-Q of Dynegy Inc. for the Quarter Ended March 31, 2016 File No. 001-33443).*
2.13	Amended and Restated Stock Purchase Agreement, dated as of June 27, 2016, by and among Atlas Power Finance, LLC, GDF SUEZ Energy North America, Inc. and International Power, S.A.(incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. filed on June 28, 2016 File No. 001-33443).*
2.14	First Amendment to Amended and Restated Stock Purchase Agreement, dated January 24, 2017, by and among Atlas Power Finance, LLC, GDF SUEZ Energy North America, Inc. and International Power, S.A.(incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K of Dynegy Inc. filed on February 8, 2017 File No. 001-33443).*
2.15	Membership Interest Purchase Agreement, dated as of August 3, 2016, by and among Elwood Expansion Holdings, LLC, Elwood Energy Holdings, LLC, Tomcat Power, LLC, Elwood Energy Holdings II, LLC and J-POWER USA Development Co., Ltd. (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. filed on August 4, 2016 File No. 001-33443).*
2.16	Confirmation Order for Dynegy Northeast Generation, Inc., Hudson Power, L.L.C., Dynegy Danskammer, L.L.C., and Dynegy Roseton, L.L.C., as entered by the United States Bankruptcy Court for the Southern District of New York on March 15, 2013 (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. filed on March 19, 2013 File No. 001-33443).
2.17	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).*
2.18	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).*
2.19	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).*
2.20	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).*

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2.21	Membership Interest Purchase Agreement, dated as of July 10, 2017, by and between Dynegy Inc. and Bruce Power, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. filed on July 12, 2017 File No. 001-33443).*
2.22	Purchase and Sale Agreement, dated July 10, 2017, by and among Dynegy Resources Generating Holdco, LLC, ANP Funding I, LLC and Marco DM Holdings, L.L.C.(incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. filed on July 13, 2017 File No. 001-33443).*
2.23	Agreement and Plan of Merger, dated as of October 29, 2017, by and between Dynegy Inc. and Vistra Energy Corp. (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. filed on October 30, 2017 File No. 001-33443).*
2.24	Confirmation Order for Illinois Power Generating Company, as entered by the United States Bankruptcy Court for the Southern District of Texas on January 25, 2017 (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K of Dynegy Inc. filed on January 30, 2017 File No. 001-33443).
3.1	Dynegy Inc. Third Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K of Dynegy Inc. filed on October 4, 2012 File No. 001-33443).
3.2	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).
4.1	Indenture, dated May 20, 2013, among Dynegy Inc., the Guarantors and Wilmington Trust, National Association as Trustee (5.875% Senior Notes due 2023) (2023 Notes Indenture) (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K of Dynegy Inc. filed on May 21, 2013 File No. 001-33443).
4.2	First Supplemental Indenture to the 2023 Notes Indenture, dated as of December 5, 2014, among Dynegy Inc., the Guarantors and Wilmington Trust, National Association as Trustee (incorporated by reference to Exhibit 4.3 to the Annual Report on Form 10-K for the Year Ended December 31, 2013 of Dynegy Inc. File No. 001-33443).
4.3	Second Supplemental Indenture to the 2023 Notes Indenture, dated April 1, 2015, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association as Trustee (incorporated by reference to Exhibit 4.20 to the Current Report on Form 8-K of Dynegy Inc. filed April 7, 2015 File No. 001-33443).
4.4	Third Supplemental Indenture to the 2023 Notes Indenture, dated April 2, 2015, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association as Trustee, pursuant to which the Subsidiary Guarantors are added to the 2023 Notes Indenture (incorporated by reference to Exhibit 4.28 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on April 8, 2015).
4.5	Fourth Supplemental Indenture to the 2023 Notes Indenture, dated May 11, 2015, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association as Trustee, adding Dynegy Resource Holdings, LLC as a guarantor (incorporated by reference to Exhibit 4.4 to the Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2015 of Dynegy Inc. File No. 001-33443).
4.6	Fifth Supplemental Indenture to the 2023 Notes Indenture, dated September 21, 2015, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association as Trustee, adding Dynegy Resource Holdings, LLC as a guarantor (incorporated by reference to Exhibit 4.4 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2015 of Dynegy Inc. File No. 001-33443).
4.7	Sixth Supplemental Indenture to the 2023 Notes Indenture, dated February 2, 2017, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association as Trustee, adding certain IPH entities as guarantors (incorporated by reference to Exhibit 4.7 to the Annual Report on Form 10-K for the Year Ended December 31, 2016 of Dynegy Inc. File No. 001-33443).
4.8	Seventh Supplemental Indenture to the 2023 Notes Indenture, dated February 7, 2017, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association as Trustee, adding Delta Transaction entities as guarantors (incorporated by reference to Exhibit 4.8 to the Annual Report on Form 10-K for the Year Ended December 31, 2016 of Dynegy Inc. File No. 001-33443).
4.9	2019 Notes Indenture, dated October 27, 2014, among Dynegy Finance II, Inc. and Wilmington Trust, National Association, as trustee (2019 Notes Indenture) (incorporated by reference to Exhibit 4.7 to the Current Report on Form 8-K of Dynegy Inc. filed on October 30, 2014 File No. 001-33443).
4.10	First Supplemental Indenture to the 2019 Notes Indenture, dated April 1, 2015, between Dynegy Inc. and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.8 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on April 7, 2015).

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4.11	Second Supplemental Indenture to the 2019 Notes Indenture, dated April 1, 2015, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.9 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on April 7, 2015).
4.12	Third Supplemental Indenture to the 2019 Notes Indenture, dated April 2, 2015, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee, adding the Duke Acquired Entities as guarantors (incorporated by reference to Exhibit 4.13 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on April 8, 2015).
4.13	Fourth Supplemental Indenture to the 2019 Notes Indenture, dated May 11, 2015, among Dynegy Inc., the Subsidiary Guarantors, (as defined therein) and Wilmington Trust, National Association, as trustee, adding Dynegy Resource Holdings, LLC as a guarantor (incorporated by reference to Exhibit 4.1 to the Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2015 of Dynegy Inc. File No. 001-33443).
4.14	Fifth Supplemental Indenture to the 2019 Notes Indenture, dated September 21, 2015, among Dynegy Inc., the Subsidiary Guarantors, (as defined therein) and Wilmington Trust, National Association, as trustee, adding Dynegy Resource Holdings, LLC as a guarantor (incorporated by reference to Exhibit 4.1 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2015 of Dynegy Inc. File No. 001-33443).
4.15	Sixth Supplemental Indenture to the 2019 Notes Indenture, dated February 2, 2017, among Dynegy Inc., the Subsidiary Guarantors, (as defined therein) and Wilmington Trust, National Association, as trustee, adding certain IPH entities as guarantors (incorporated by reference to Exhibit 4.16 to the Annual Report on Form 10-K for the Year Ended December 31, 2016 of Dynegy Inc. File No. 001-33443).
4.16	Seventh Supplemental Indenture to the 2019 Notes Indenture, dated February 7, 2017, among Dynegy Inc., the Subsidiary Guarantors, (as defined therein) and Wilmington Trust, National Association, as trustee, adding Delta Transaction entities as guarantors (incorporated by reference to Exhibit 4.17 to the Annual Report on Form 10-K for the Year Ended December 31, 2016 of Dynegy Inc. File No. 001-33443).
4.17	2022 Notes Indenture, dated October 27, 2014, among Dynegy Finance II, Inc. and Wilmington Trust, National Association, as trustee (2022 Notes Indenture) (incorporated by reference to Exhibit 4.8 to the Current Report on Form 8-K of Dynegy Inc. filed on October 30, 2014 File No. 001-33443).
4.18	First Supplemental Indenture to the 2022 Notes Indenture, dated April 1, 2015, between Dynegy Inc. and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.11 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on April 7, 2015).
4.19	Second Supplemental Indenture to the 2022 Notes Indenture, dated April 1, 2015, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.12 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on April 7, 2015).
4.20	Third Supplemental Indenture to the 2022 Notes Indenture, dated April 2, 2015, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee, adding the Duke Acquired Entities as guarantors (incorporated by reference to Exhibit 4.17 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on April 8, 2015).
4.21	Fourth Supplemental Indenture to the 2022 Notes Indenture, dated May 11, 2015, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee, adding Dynegy Resource Holdings, LLC as a guarantor (incorporated by reference to Exhibit 4.2 to the Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2015 of Dynegy Inc. File No. 001-33443).
4.22	Fifth Supplemental Indenture to the 2022 Notes Indenture, dated September 21, 2015, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee, adding Dynegy Resource Holdings, LLC as a guarantor (incorporated by reference to Exhibit 4.2 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2015 of Dynegy Inc. File No. 001-33443).
4.23	Sixth Supplemental Indenture to the 2022 Notes Indenture, dated February 2, 2017, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee, adding certain IPH entities as guarantors (incorporated by reference to Exhibit 4.24 to the Annual Report on Form 10-K for the Year Ended December 31, 2016 of Dynegy Inc. File No. 001-33443).
4.24	Seventh Supplemental Indenture to the 2022 Notes Indenture, dated February 7, 2017, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee, adding Delta Transaction entities as guarantors (incorporated by reference to Exhibit 4.25 to the Annual Report on Form 10-K for the Year Ended December 31, 2016 of Dynegy Inc. File No. 001-33443).

92

4.25	7.625% 2024 Notes Indenture, dated October 27, 2014, among Dynegy Finance II, Inc. and Wilmington Trust, National Association, as trustee (2024 Notes Indenture) (incorporated by reference to Exhibit 4.9 to the Current Report on Form 8-K of Dynegy Inc. filed on October 30, 2014 File No. 001-33443).
4.26	First Supplemental Indenture to the 7.625% 2024 Notes Indenture, dated April 1, 2015, between Dynegy Inc. and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.14 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on April 7, 2015).
4.27	Second Supplemental Indenture to the 7.625% 2024 Notes Indenture, dated April 1, 2015, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.15 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on April 7, 2015).
4.28	Third Supplemental Indenture to the 7.625% 2024 Notes Indenture, dated April 2, 2015, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee, adding the Duke Acquired Entities as guarantors (incorporated by reference to Exhibit 4.21 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on April 8, 2015).
4.29	Fourth Supplemental Indenture to the 7.625% 2024 Notes Indenture, dated May 11, 2015, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee, adding Dynegy Resource Holdings, LLC as a guarantor (incorporated by reference to Exhibit 4.2 to the Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2015 of Dynegy Inc. File No. 001-33443).
4.30	Fifth Supplemental Indenture to the 7.625% 2024 Notes Indenture, dated September 21, 2015, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee, adding Dynegy Resource Holdings, LLC as a guarantor (incorporated by reference to Exhibit 4.3 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2015 of Dynegy Inc. File No. 001-33443).
4.31	Sixth Supplemental Indenture to the 7.625% 2024 Notes Indenture, dated February 2, 2017, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee, adding certain IPH entities as guarantors (incorporated by reference to Exhibit 4.32 to the Annual Report on Form 10-K for the Year Ended December 31, 2016 of Dynegy Inc. File No. 001-33443).
4.32	Seventh Supplemental Indenture to the 7.625% 2024 Notes Indenture, dated February 7, 2017, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee, adding Delta Transaction entities as guarantors (incorporated by reference to Exhibit 4.33 to the Annual Report on Form 10-K for the Year Ended December 31, 2016 of Dynegy Inc. File No. 001-33443).
4.33	2025 Notes Indenture, dated October 11, 2016, between Dynegy Inc. and Wilmington Trust, National Association (2025 Notes Indenture) (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K of Dynegy Inc. filed on October 11, 2016 File No. 001-33443).
4.34	First Supplemental Indenture to the 2025 Notes Indenture, dated February 2, 2017, between Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee, adding certain IPH entities as guarantors (incorporated by reference to Exhibit 4.35 to the Annual Report on Form 10-K for the Year Ended December 31, 2016 of Dynegy Inc. File No. 001-33443).
4.35	Second Supplemental Indenture to the 2025 Notes Indenture, dated February 7, 2017, between Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee, adding Delta Transaction entities as guarantors (incorporated by reference to Exhibit 4.36 to the Annual Report on Form 10-K for the Year Ended December 31, 2016 of Dynegy Inc. File No. 001-33443).
4.36	Indenture (TEU), dated June 21, 2016, between Dynegy Inc. and Wilmington Trust, National Association (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K of Dynegy Inc. filed on June 21, 2016 File No. 001-33443).
4.37	First Supplemental Indenture to the Indenture (TEU), dated June 21, 2016, between Dynegy Inc. and Wilmington Trust, National Association (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K of Dynegy Inc. filed on June 21, 2016 File No. 001-33443).
4.38	Purchase Contract Agreement (TEU), dated June 21, 2016, between Dynegy Inc. and Wilmington Trust, National Association (incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K of Dynegy Inc. filed on June 21, 2016 File No. 001-33443).
4.39	Indenture to the 8.034% Notes due 2024, dated February 2, 2017, by and among Dynegy Inc., the guarantors party thereto and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K of Dynegy Inc. filed on February 7, 2017 File No. 001-33443).

93

4.40	First Supplemental Indenture to the 8.034% 2024 Notes Indenture, dated February 7, 2017, between Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee, adding certain IPH entities as guarantors (incorporated by reference to Exhibit 4.41 to the Annual Report on Form 10-K for the Year Ended December 31, 2016 of Dynegy Inc. File No. 001-33443).
4.41	Indenture, dated August 21, 2017, by and among Dynegy Inc., the Guarantors and Wilmington Trust, National Association, as trustee (8.125% Senior Notes due 2026) (2026 Notes Indenture) (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K of Dynegy Inc. filed on August 21, 2017 File No. 001-33443).
4.42	Registration Rights Agreement, dated August 21, 2017, by and among Dynegy Inc., the Guarantors and Goldman Sachs & Co. LLC related to the 2026 Senior Notes (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K of Dynegy Inc. filed on August 21, 2017 File No. 001-33443).
10.1	Dynegy Inc. Severance Plan (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on October 30, 2015 File No. 001-33443).††
10.2	Dynegy Inc. Restoration 401(k) Savings Plan, effective June 1, 2008 (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q of Dynegy Inc. filed on August 7, 2008 File No. 001-33443).††
10.3	First Amendment to the Dynegy Inc. Restoration 401(k) Savings Plan, effective June 1, 2008 (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q of Dynegy Inc. filed on August 7, 2008 File No. 001-33443).††
10.4	Second Amendment to Dynegy Inc. Restoration 401(k) Savings Plan, effective January 1, 2012 (incorporated by reference to Exhibit 10.23 to the Annual Report on Form 10-K of Dynegy Inc. for the year ended December 31, 2011 File No. 1-33443).††
10.5	Dynegy Inc. Restoration Pension Plan, effective June 1, 2008 (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q of Dynegy Inc. filed on August 7, 2008 File No. 001-33443).††
10.6	First Amendment to the Dynegy Inc. Restoration Pension Plan, effective June 1, 2008 (incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q of Dynegy Inc. filed on August 7, 2008 File No. 001-33443).††
10.7	Second Amendment to the Dynegy Inc. Restoration Pension Plan, executed on July 2, 2010 (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q of Dynegy Inc. and Dynegy Holdings Inc. filed on August 6, 2010 File No. 000-29311).††
10.8	Third Amendment to Dynegy Inc. Restoration Pension Plan, effective January 1, 2012 (incorporated by reference to Exhibit 10.27 to the Annual Report on Form 10-K of Dynegy Inc. for the year ended December 31, 2011 File No. 1-33443).††
10.9	Dynegy Inc. 2009 Phantom Stock Plan (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc. filed on March 10, 2009, File No. 001-33443).††
10.10	First Amendment to the Dynegy Inc. 2009 Phantom Stock Plan, dated as of July 8, 2011 (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2011 of Dynegy Inc., File No. 1- 33443).††
10.11	Dynegy Inc. Deferred Compensation Plan for Certain Directors, as amended and restated, effective January 1, 2008 (incorporated by reference to Exhibit 10.55 to the Annual Report on Form 10-K for the Fiscal Year ended December 31, 2009, filed on February 26, 2009 File No. 001-33443).††
10.12	Trust under Dynegy Inc. Deferred Compensation Plan for Certain Directors, effective January 1, 2009 (incorporated by reference to Exhibit 10.56 to the Annual Report on Form 10-K for the Fiscal Year ended December 31, 2009 filed on February 26, 2009, File No. 001-33443).††
10.13	Dynegy Inc. Incentive Compensation Plan, as amended and restated effective May 21, 2010 (incorporated by reference to Exhibit 10.34 to the Annual Report on Form 10-K for the Fiscal Year ended December 31, 2010 File No. 001-33443)††
10.14	Amended and Restated 2012 Long Term Incentive Plan (incorporated by reference to Annex B to the Proxy Statement on Schedule 14A of Dynegy Inc. filed on March 31, 2016 File No. 001-33443).††
10.15	Amended and Restated Employment Agreement by and between Dynegy Operating Company and Robert C. Flexon (incorporated by reference to Exhibit 10.1 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on May 6, 2015).††
10.16	First Amendment to Amended and Restated Employment Agreement, dated as of October 29, 2017, by and between Dynegy Operating Company and Robert Flexon (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on October 30, 2017 File No. 001-33443).††
10.17	Form of Dynegy Inc. Executive Participation Agreement (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on October 30, 2015 File No. 001-33443).††

94

10.18	Amendment to Executive Participation Agreement by and between Dynegy Inc. and Mario E. Alonso effective October 24, 2016 (incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2016 of Dynegy Inc., File No. 001-33443).††
10.19	Form of Non-Qualified Stock Option Award Agreement (2012 Awards) (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. on November 2, 2012 File No. 001-33443).††
10.20	Form of Non-Qualified Stock Option Award Agreement (2013 Awards) (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on March 22, 2013 File No. 001-33443).††
10.21	Form of Non-Qualified Stock Option Award Agreement (2014 Awards) (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2014 of Dynegy Inc. File No. 001-33443).††
10.22	Form of Non-Qualified Stock Option Award Agreement (2015 Awards) (incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2015 of Dynegy Inc. File No. 001-33443).††
10.23	Amendment to Non-Qualified Stock Option Award Agreement - Flexon (2015 Employment Agreement Award) (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2015 of Dynegy Inc. File No. 001-33443).††
10.24	Form of Non-Qualified Stock Option Award Agreement (CEO) (2016 Awards) (incorporated by reference to Exhibit 10.6 to the Current Report on Form 8-K of Dynegy Inc. filed on March 14, 2016 File No. 001-33443).††
10.25	Form of Non-Qualified Stock Option Award Agreement (2016 Awards) (incorporated by reference to Exhibit 10.5 to the Current Report on Form 8-K of Dynegy Inc. filed on March 14, 2016 File No. 001-33443).††
10.26	Form of Non-Qualified Stock Option Award Agreement (CEO) (2017 Awards) (incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2017 of Dynegy Inc. File No. 001-33443).††
10.27	Form of Non-Qualified Stock Option Award Agreement (2017 Awards) (incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2017 of Dynegy Inc. File No. 001-33443).††
10.28	Form of Stock Unit Award Agreement - Officers (2015 Awards) (incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2015 of Dynegy Inc. File No. 001-33443).††
10.29	Form of Stock Unit Award Agreement - Flexon (2015 Employment Agreement Award) (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2015 of Dynegy Inc. File No. 001-33443).††
10.30	Form of Stock Unit Award Agreement (CEO) (2016 Awards) (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K of Dynegy Inc. filed on March 14, 2016 File No. 001-33443).††
10.31	Form of Stock Unit Award Agreement (Executive Management) (2016 Awards) (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc. filed on March 14, 2016 File No. 001-33443).††
10.32	Form of Stock Unit Award Agreement (CEO) (2017 Awards) (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2017 of Dynegy Inc. File No. 001-33443).††
10.33	Form of Stock Unit Award Agreement (Executive Management) (2017 Awards) (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2017 of Dynegy Inc. File No. 001-33443).††
10.34	Form of Stock Unit Award Agreement - Directors (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc. on November 2, 2012 File No. 001-33443).††
10.35	Form of Performance Award Agreement (2015 Awards) (for Managing Directors and Above) (incorporated by reference to Exhibit 10.8 to the Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2015 of Dynegy Inc. File No. 001-33443).††
10.36	Form of Performance Award Agreement (CEO) (2016 Awards) (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on March 14, 2016 File No. 001-33443).††
10.37	Form of Performance Award Agreement (2016 Awards) (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on March 14, 2016 File No. 001-33443).††
10.38	Form of Performance Award Agreement (CEO) (2017 Awards) (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2017 of Dynegy Inc. File No. 001-33443).††

95

10.39	Form of Performance Award Agreement (EVP) (2017 Awards) (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2017 of Dynegy Inc. File No. 001-33443).††
10.40	Form of Acknowledgment between Dynegy Inc. and certain executive officers (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on December 21, 2017 File No. 001-33443).
10.41	Credit Agreement, dated as of April 23, 2013, among Dynegy Inc., as borrower and the guarantors, lenders and other parties thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on April 24, 2013 File No. 001-33443).
10.42	Guarantee and Collateral Agreement, dated as of April 23, 2013 among Dynegy Inc., the subsidiaries of the borrower from time to time party thereto and Credit Suisse AG, Cayman Islands Branch, as Collateral Trustee (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on April 24, 2013 File No. 001-33443).
10.43	Collateral Trust and Intercreditor Agreement, dated as of April 23, 2013 among Dynegy, the Subsidiary Guarantors (as defined therein), Credit Suisse AG, Cayman Islands Branch and each person party thereto from time to time (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc. filed on April 24, 2013 File No. 001-33443).
10.44	First Amendment to Credit Agreement, dated as of April 1, 2015, among Dynegy Inc., as borrower, and the guarantors, lenders and other parties thereto (incorporated by reference to Exhibit 10.4 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on April 7, 2015).
10.45	Second Amendment to Credit Agreement, dated as of April 2, 2015, among Dynegy Inc., as borrower, and the guarantors, lenders and other parties thereto (incorporated by reference to Exhibit 10.5 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on April 8, 2015).
10.46	Third Amendment to Credit Agreement, dated as of June 27, 2016, among Dynegy Inc., as borrower, and the guarantors, lenders and other parties thereto (incorporated by reference to Exhibit 10.4 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on June 28, 2016).
10.47	Waiver to Credit Agreement, dated as of June 27, 2016, among Dynegy Inc., as borrower, and the lenders party thereto (incorporated by reference to Exhibit 10.5 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on June 28, 2016).
10.48	Waiver and Consent to Credit Agreement, dated as of December 13, 2016, among Dynegy Inc., as borrower, and the guarantors, lenders and other parties thereto (incorporated by reference to Exhibit 10.1 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on December 14, 2016).
10.49	Fourth Amendment to the Credit Agreement, dated January 10, 2017, among Dynegy Inc., as borrower and the guarantors, lenders and other parties thereto (incorporated by reference to Exhibit 10.3 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on January 17, 2017).
10.50	Fifth Amendment to the Credit Agreement, dated February 7, 2017, among Dynegy Inc., as borrower and the guarantors, lenders and other parties thereto (incorporated by reference to Exhibit 10.2 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on February 9, 2017).
10.51	Sixth Amendment to the Credit Agreement, dated December 20, 2017, among Dynegy Inc., as borrower and the guarantors, lenders and other parties thereto (incorporated by reference to Exhibit 10.2 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on December 20, 2017).
10.52	Letter of Credit Reimbursement Agreement, dated as of February 7, 2017, between Dynegy Inc. and Goldman Sachs Bank USA (incorporated by reference to Exhibit 10.3 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on February 9, 2017).
10.53	Letter of Credit Reimbursement Agreement, dated as of September 18, 2014 among Dynegy Inc., Macquarie Bank Limited, and Macquarie Energy LLC (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on September 22, 2014 File No. 001-33443).
10.54	First Amendment to the Letter of Credit Reimbursement Agreement, dated August 10, 2016 among Dynegy Inc., Macquarie Bank Limited and Macquarie Energy LLC (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q of Dynegy Inc. for the Quarter Ended September 30, 2016 File No. 001-33443).
10.55	Second Amendment to Letter of Credit Reimbursement Agreement, dated July 13, 2017, between Dynegy Inc. and Macquarie Bank Limited (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the Quarter ended June 30, 2017 of Dynegy Inc. File No. 001-33443).
10.56	Purchase Agreement, dated May 15, 2013, among Dynegy Inc., the Guarantors, Morgan Stanley and Credit Suisse (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on May 21, 2013 File No. 001-33443).

96

10.57	Purchase Agreement, dated October 10, 2014, among Dynegy Inc., Dynegy Finance I, Inc., Dynegy Finance II, Inc., the guarantors identified therein and Morgan Stanley & Co. LLC, Barclays Capital Inc., Credit Suisse Securities (USA) LLC, RBC Capital Markets, LLC and UBS Securities LLC, as representatives of the initial purchasers (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on October 14, 2014 File No. 001-33443).
10.58	Warrant Agreement, dated February 2, 2017, by and among Dynegy Inc., Computershare Inc. and Computershare Trust Company, N.A., as warrant agent (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K of Dynegy Inc. filed on February 7, 2017 File No. 001-33443).
10.59	Letter of Credit and Reimbursement Agreement, dated as of January 29, 2014 between Illinois Power Marketing Company and Union Bank, N.A. (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. and Illinois Power Generating Company filed on February 4, 2014 File No. 001-33443).
10.60	Waiver and Amendment No. 1 to Letter of Credit and Reimbursement Agreement by and between Illinois Power Marketing Company and Union Bank, N.A. (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2014 of Dynegy Inc. File No. 001-33443).
10.61	Amendment No. 2 to Letter of Credit and Reimbursement Agreement by and between Illinois Power Marketing Company and Union Bank, N.A. (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2015 of Dynegy Inc. File No. 001-33443).
10.62	Amendment No. 3 to Letter of Credit and Reimbursement Agreement by and between Illinois Power Marketing Company and Union Bank, N.A. (incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2016 of Dynegy Inc. File No. 001-33443).
10.63	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. (incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2017 of Dynegy Inc. File No. 001-33443).
10.64	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. (incorporated by reference to Exhibit 10.8 to the Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2017 of Dynegy Inc. File No. 001-33443).
10.65	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 (incorporated by reference to Exhibit 10.9 to the Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2017 of Dynegy Inc. File No. 001-33443).
10.66	Investor Rights Agreement, dated as of February 7, 2017, by and between Dynegy Inc. and Terawatt Holdings, LP (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on February 8, 2017 File No. 001-33443).
10.67	Amendment No. 1 to the Investor Rights Agreement by and between Dynegy Inc. and Terawatt Holdings, LP (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on September 6, 2017 File No. 001-33443).
10.68	Guaranty, dated as of August 3, 2016, by Dynegy Inc., for the benefit of J-POWER USA Development Co., Ltd. (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on August 4, 2016 File No. 001-33443).
10.69	Restructuring Support Agreement dated October 14, 2016 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on October 14, 2016 File No. 001-33443).
10.70	Amendment to Restructuring Support Agreement dated October 21, 2016 (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2016 of Dynegy Inc. File No. 001-33443).
10.71	Merger Support Agreement, dated as of October 29, 2017, by and between Dynegy Inc. and Stockholders of Vistra Energy Corp. Party Thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on October 30, 2017 File No. 001-33443).
14.1	Dynegy Inc. Code of Ethics for Senior Financial Professionals, as amended on July 23, 2013 (incorporated by reference to Exhibit 14.1 to the Annual Report on Form 10-K for the Year Ended December 31, 2013 of Dynegy Inc. File No. 001-33443).
***21.1	Significant subsidiaries of the Registrant
***23.1	Consent of Ernst & Young LLP
***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.

97

†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	Mine Safety Violations and Other Legal Matter Disclosures pursuant to section 1503(a) of the Dodd-Frank Act and Item 104 of Regulation S-K (17 CFR 229.104).
**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

__________________________________________

* Pursuant to Item 6.01(b)(2) of Regulation S-K exhibits and schedules are omitted. Dynegy agrees to furnish to the Commission supplementally a copy of any omitted schedule or exhibit upon request of the Commission.

** XBRL information is furnished and not filed for purposes of Section 11 and 12 of the Securities Act of 1933 and Section 18 of the Securities Exchange Act of 1934, and is not subject to liability under those sections, is not part of any registration statement or prospectus to which it relates and is not incorporated or deemed to be incorporated by reference into any registration statement, prospectus or other document.

*** Filed herewith.

**** Pursuant to a request for confidential treatment, portions of this Exhibit have been redacted and filed separately with the SEC as required by Rule 24b-2 under the Securities Exchange Act of 1934, as amended.

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

†† Management contract or compensation plan.

98

SIGNATURES

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, the thereunto duly authorized.

		DYNEGY INC.
Date:	February 22, 2018	By:	/s/ ROBERT C. FLEXON Robert C. Flexon President and Chief Executive Officer

________________________________________________________________________________________________________________________

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the dates indicated.

/s/ ROBERT C. FLEXON Robert C. Flexon	President and Chief Executive Officer & Director (Principal Executive Officer)	February 22, 2018
/s/ CLINT C. FREELAND Clint C. Freeland	Executive Vice President and Chief Financial Officer (Principal Financial Officer)	February 22, 2018
/s/ J. CLINTON WALDEN J. Clinton Walden	Vice President and Chief Accounting Officer (Principal Accounting Officer)	February 22, 2018
/s/ PAT WOOD III Pat Wood III	Chairman of the Board	February 22, 2018
/s/ HILARY E. ACKERMANN Hilary E. Ackermann	Director	February 22, 2018
/s/ PAUL M. BARBAS Paul M. Barbas	Director	February 22, 2018
/s/ RICHARD LEE KUERSTEINER Richard Lee Kuersteiner	Director	February 22, 2018
/s/ JEFFREY S. STEIN Jeffrey S. Stein	Director	February 22, 2018
/s/ JOHN R. SULT John R. Sult	Director	February 22, 2018

99

DYNEGY INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Consolidated Financial Statements
Reports of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets:
December 31, 2017 and 2016	F-4
Consolidated Statements of Operations:
For the years ended December 31, 2017, 2016 and 2015	F-6
Consolidated Statements of Comprehensive Income (Loss):
For the years ended December 31, 2017, 2016 and 2015	F-7
Consolidated Statements of Cash Flows:
For the years ended December 31, 2017, 2016 and 2015	F-8
Consolidated Statements of Changes in Equity:
For the years ended December 31, 2017, 2016 and 2015	F-9
Notes to Consolidated Financial Statements	F-10

F-1

Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of Dynegy Inc.:

Opinion on Internal Control over Financial Reporting

We have audited Dynegy Inc.’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Dynegy Inc. (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of Dynegy Inc. as of December 31, 2017 and 2016, and the related consolidated statements of operations, comprehensive income (loss), changes in equity and cash flows for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the “consolidated financial statements”), and our report dated February 22, 2018 expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP

Houston, Texas

February 22, 2018

F-2

Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of Dynegy Inc.:

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Dynegy Inc. (the Company) as of December 31, 2017 and 2016, and the related consolidated statements of operations, comprehensive income (loss), changes in equity and cash flows for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 22, 2018 expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Ernst & Young LLP

We have served as the Company’s auditor since 2007

Houston, Texas

February 22, 2018

F-3

Item 1—FINANCIAL STATEMENTS

DYNEGY INC.

CONSOLIDATED BALANCE SHEETS

(in millions, except share data)

	December 31, 2017		December 31, 2016
ASSETS
Current Assets
Cash and cash equivalents	$	365	$	1,776
Restricted cash	—		62
Accounts receivable, net of allowance for doubtful accounts of $1 and $1, respectively	513		386
Inventory	445		445
Assets from risk management activities	32		130
Intangible assets	25		38
Prepayments and other current assets	144		150
Total Current Assets	1,524		2,987
Property, plant and equipment, net	8,884		7,121
Investment in unconsolidated affiliate	123		—
Restricted cash	—		2,000
Assets from risk management activities	26		16
Goodwill	772		799
Intangible assets	39		23
Other long-term assets	403		107
Total Assets	$	11,771	$	13,053

See the notes to consolidated financial statements.

F-4

DYNEGY INC.

CONSOLIDATED BALANCE SHEETS

(in millions, except share data)

	December 31, 2017			December 31, 2016
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	367		$	332
Accrued interest	115			81
Intangible liabilities	14			21
Accrued taxes	64			45
Accrued liabilities and other current liabilities	109			88
Liabilities from risk management activities	229			97
Asset retirement obligations	46			51
Debt, current portion, net	105			201
Total Current Liabilities	1,049			916
Liabilities subject to compromise (Note 20)	—			832
Debt, long-term portion, net	8,328			8,778
Other Liabilities
Liabilities from risk management activities	31			43
Asset retirement obligations	283			236
Deferred income taxes	7			5
Intangible liabilities	34			34
Other long-term liabilities	146			170
Total Liabilities	9,878			11,014
Commitments and Contingencies (Note 16)
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 at December 31, 2016	—			400
Common stock, $0.01 par value, 420,000,000 shares authorized; 155,710,613 shares issued and 144,384,491 shares outstanding at December 31, 2017; 128,626,740 shares issued and 117,300,618 outstanding at December 31, 2016	1			1
Additional paid-in capital	3,719			3,547
Accumulated other comprehensive income, net of tax	32			21
Accumulated deficit	(1,851		)	(1,927		)
Total Dynegy Stockholders’ Equity	1,901			2,042
Noncontrolling interest	(8		)	(3		)
Total Equity	1,893			2,039
Total Liabilities and Equity	$	11,771		$	13,053

See the notes to consolidated financial statements.

F-5

DYNEGY INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per share data)

	Year Ended December 31,
	2017			2016			2015
Revenues	$	4,842		$	4,318		$	3,870
Cost of sales, excluding depreciation expense	(2,932		)	(2,281		)	(2,028		)
Gross margin	1,910			2,037			1,842
Operating and maintenance expense	(995		)	(940		)	(839		)
Depreciation expense	(811		)	(689		)	(587		)
Impairments	(148		)	(858		)	(99		)
Loss on sale of assets, net	(122		)	(1		)	(1		)
General and administrative expense	(189		)	(161		)	(128		)
Acquisition and integration costs	(57		)	(11		)	(124		)
Other	—			(17		)	—
Operating income (loss)	(412		)	(640		)	64
Bankruptcy reorganization items (Note 20)	494			(96		)	—
Earnings from unconsolidated investments	8			7			1
Interest expense	(616		)	(625		)	(546		)
Loss on early extinguishment of debt (Note 13)	(79		)	—			—
Other income and expense, net	67			65			54
Loss before income taxes	(538		)	(1,289		)	(427		)
Income tax benefit (Note 14)	610			45			474
Net income (loss)	72			(1,244		)	47
Less: Net loss attributable to noncontrolling interest	(4		)	(4		)	(3		)
Net income (loss) attributable to Dynegy Inc.	76			(1,240		)	50
Less: Dividends on preferred stock	18			22			22
Net income (loss) attributable to Dynegy Inc. common stockholders	$	58		$	(1,262	)	$	28
Earnings (Loss) Per Share (Note 15):
Basic earnings (loss) per share attributable to Dynegy Inc. common stockholders	$	0.37		$	(9.78	)	$	0.22
Diluted earnings (loss) per share attributable to Dynegy Inc. common stockholders	$	0.36		$	(9.78	)	$	0.22
Basic shares outstanding	155			129			125
Diluted shares outstanding	162			129			126

See the notes to consolidated financial statements.

F-6

DYNEGY INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in millions)

	Year Ended December 31,
	2017			2016			2015
Net income (loss)	$	72		$	(1,244	)	$	47
Other comprehensive income before reclassifications:
Actuarial gain and plan amendments (net of tax of $5, $3, and zero, respectively)	19			3			4
Amounts reclassified from accumulated other comprehensive income:
Settlement cost (net of tax of zero)	—			6			—
Amortization of unrecognized prior service credit and actuarial gain (net of tax of zero, zero, and zero, respectively)	(8		)	(5		)	(4		)
Other comprehensive income, net of tax	11			4			—
Comprehensive income (loss)	83			(1,240		)	47
Less: Comprehensive loss attributable to noncontrolling interest	(4		)	(2		)	(2		)
Total comprehensive income (loss) attributable to Dynegy Inc.	$	87		$	(1,238	)	$	49

See the notes to consolidated financial statements.

F-7

DYNEGY INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Year Ended December 31,
	2017			2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	72		$	(1,244	)	$	47
Adjustments to reconcile net income (loss) to net cash flows from operating activities:
Depreciation expense	811			689			587
Loss on early extinguishment of debt	79			—			—
Non-cash interest expense	44			56			38
Amortization of intangibles	12			21			(11		)
Bankruptcy reorganization items	(494		)	96			—
Impairments	148			858			99
Risk management activities	207			(148		)	(130		)
Loss on sale of assets, net	122			1			1
Earnings from unconsolidated investments	(8		)	(7		)	(1		)
Deferred income taxes	(610		)	(45		)	(477		)
Change in value of common stock warrants	(16		)	(6		)	(54		)
Other	81			14			51
Changes in working capital:
Accounts receivable, net	(47		)	42			(64		)
Inventory	110			154			(119		)
Prepayments and other current assets	26			94			94
Accounts payable and accrued liabilities	46			84			25
Distributions from unconsolidated investments	5			1			3
Changes in non-current assets	(12		)	(43		)	—
Changes in non-current liabilities	9			28			5
Net cash provided by operating activities	585			645			94
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(224		)	(293		)	(301		)
Acquisitions, net of cash acquired	(3,319		)	—			(6,078		)
Distributions from unconsolidated investments	12			14			8
Proceeds from asset sales, net	772			176			—
Other investing	—			10			3
Net cash used in investing activities	(2,759		)	(93		)	(6,368		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of debt issuance costs	1,743			3,014			66
Repayments of borrowings	(2,589		)	(589		)	(31		)
Proceeds from issuance of equity, net of issuance costs	150			359			(6		)
Payments of debt extinguishment costs	(50		)	—			—
Preferred stock dividends paid	(22		)	(22		)	(23		)
Interest rate swap settlement payments	(20		)	(17		)	(17		)
Acquisition of noncontrolling interest	(375		)	—			—
Payments related to bankruptcy settlement	(133		)	—			—
Repurchase of common stock	—			—			(250		)
Other financing	(3		)	(3		)	(4		)
Net cash provided by (used in) financing activities	(1,299		)	2,742			(265		)
Net increase (decrease) in cash, cash equivalents and restricted cash	(3,473		)	3,294			(6,539		)
Cash, cash equivalents and restricted cash, beginning of period	3,838			544			7,083
Cash, cash equivalents and restricted cash, end of period	$	365		$	3,838		$	544

See the notes to consolidated financial statements. 

F-8

DYNEGY INC.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(in millions)

	Preferred Stock			Common Stock		Additional Paid-In Capital			AOCI			Accumulated Deficit			Total Controlling Interests			Noncontrolling Interest			Total
December 31, 2014	$	400		$	1	$	3,338		$	20		$	(736	)	$	3,023		$	—		$	3,023
Net income (loss)	—			—		—			—			50			50			(3		)	47
Equity issuance for acquisition, net (Note 15)	—			—		99			—			—			99			—			99
Other comprehensive income (loss), net of tax	—			—		—			(1		)	—			(1		)	1			—
Share-based compensation expense, net of tax	—			—		22			—			—			22			—			22
Options exercised	—			—		1			—			—			1			—			1
Dividends Paid	—			—		(23		)	—			—			(23		)	—			(23		)
Repurchases of common stock (Note 15)	—			—		(250		)	—			—			(250		)	—			(250		)
December 31, 2015	400			1		3,187			19			(686		)	2,921			(2		)	2,919
Net loss	—			—		—			—			(1,240		)	(1,240		)	(4		)	(1,244		)
TEUs (Note 12)	—			—		359			—			—			359			—			359
Other comprehensive income, net of tax	—			—		—			2			—			2			2			4
Share-based compensation expense, net of tax	—			—		22			—			—			22			—			22
Dividends paid	—			—		(22		)	—			—			(22		)	—			(22		)
Other	—			—		1			—			(1		)	—			1			1
December 31, 2016	400			1		3,547			21			(1,927		)	2,042			(3		)	2,039
Net income (loss)	—			—		—			—			76			76			(4		)	72
Equity issuance for acquisition, net (Note 15)	—			—		150			—			—			150			—			150
Preferred stock conversion	(400		)	—		400			—			—			—			—			—
Other comprehensive income, net of tax	—			—		—			11			—			11			—			11
Share-based compensation expense, net of tax	—			—		19			—			—			19			—			19
Acquisition of non-controlling interest	—			—		(375		)	—			—			(375		)	—			(375		)
Dividends paid	—			—		(22		)	—			—			(22		)	—			(22		)
Other	—			—		—			—			—			—			(1		)	(1		)
December 31, 2017	$	—		$	1	$	3,719		$	32		$	(1,851	)	$	1,901		$	(8	)	$	1,893

See the notes to consolidated financial statements.

F-9

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Organization and Operations

We are a holding company and conduct substantially all of our business operations through our subsidiaries. Our current business operations are focused primarily on the power generation sector of the energy industry. 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 report the results of our power generation business as five segments in our consolidated financial statements: (i) PJM, (ii) NY/NE, (iii) ERCOT, (iv) MISO and (v) CAISO. Our consolidated financial results also reflect corporate-level expenses such as general and administrative expense, interest expense, and income tax benefit (expense). In the fourth quarter of 2017, we combined our previous MISO and IPH segments into a single MISO segment to better align our IPH assets, which reside within the MISO market area, and changed our organizational structure to manage our assets, make financial decisions, and allocate resources based upon the market areas in which our plants operate. Accordingly, the Company has recast data from prior periods to conform to the current year segment presentation. All significant intercompany transactions have been eliminated. Please read Note 21—Segment Information for further discussion.

On February 2, 2017, Illinois Power Generating Company (“Genco”) emerged from bankruptcy. Please read Note 20—Genco Chapter 11 Bankruptcy for further discussion.

On February 7, 2017, (“the ENGIE Acquisition Closing Date”), Dynegy acquired approximately 9,017 MW of generation, 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”). Please read Note 3—Acquisitions and Divestitures for further discussion.

On October 29, 2017, Dynegy and Vistra Energy Corp., a Delaware corporation (“Vistra Energy”), entered into an Agreement and Plan of Merger (the “Merger Agreement”). Under the Merger Agreement, which has been approved by the boards of directors of both companies, Dynegy will merge with and into Vistra Energy in a tax-free, all-stock transaction, with Vistra Energy continuing as the surviving corporation (the “Merger”). Under the terms of the agreement, Dynegy stockholders will receive 0.652 shares of Vistra Energy common stock for each share of Dynegy common stock they own, resulting in Vistra Energy stockholders and Dynegy stockholders owning approximately 79 percent and 21 percent, respectively, of the combined company. During 2017, we incurred approximately $17 million in costs related to the Merger, which are included in General and administrative expense in our consolidated statement of operations.

We expect the transaction to close in the second quarter of 2018 after meeting the remaining customary conditions, including, among others, (a) approval by Vistra Energy’s stockholders of the issuance of the Vistra Energy common stock in the Merger, scheduled for March 2, 2018, and (b) receipt of all requisite regulatory approvals including FERC, the Public Utility Commission of Texas and the New York Public Service Commission. Each party’s obligation to consummate the Merger is also subject to certain additional customary conditions. The Merger Agreement contains customary representations, warranties and covenants of Dynegy and Vistra Energy, and contains certain termination rights for both Dynegy and Vistra Energy. If the Merger Agreement is terminated because Dynegy’s Board of Directors changes its recommendation to stockholders or Dynegy enters into a definitive agreement for a superior proposal, Dynegy will be required to pay Vistra Energy a termination fee of $87 million. If the Merger Agreement is terminated for a failure to obtain certain requisite regulatory approvals or Vistra Energy’s Board of Directors changes its recommendation in favor of the Merger, Vistra Energy may be required to pay Dynegy a termination fee of $100 million.

Note 2—Summary of Significant Accounting Policies

Principles of Consolidation. The accompanying consolidated financial statements include our accounts and the accounts of our majority-owned or controlled subsidiaries for which we are the primary beneficiary. Intercompany accounts and transactions have been eliminated. Certain prior period amounts in our consolidated financial statements have been reclassified to conform to current year presentation. Accounting policies for all of our operations are in accordance with accounting principles generally accepted in the United States of America (“U.S.”).

Unconsolidated Investments.  We use the equity method of accounting for investments in affiliates over which we exercise significant influence. We use the cost method of accounting where we do not exercise significant influence.

Our share of net income (loss) from these affiliates is reflected in the consolidated statements of operations as Earnings from unconsolidated investments. All investments in unconsolidated affiliates are periodically assessed for other-than-temporary declines in value, with write-downs recognized in Earnings from unconsolidated investments in the consolidated statements of operations.

F-10

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Undivided Interest Accounting. We account for our undivided interests in certain of our coal-fired power generation facilities whereby our proportionate share of each facility’s assets, liabilities, revenues, and expenses are included in the appropriate classifications in the accompanying consolidated financial statements.

Noncontrolling Interest. Noncontrolling interest is comprised of the 20 percent of Electric Energy, Inc. (“EEI”) which we do not own. This noncontrolling interest is classified as a component of equity separate from our equity in the consolidated balance sheets.

Use of Estimates. The preparation of consolidated financial statements in conformity with Generally Accepted Accounting Principles (“GAAP”) requires management to make informed estimates and judgments that affect our reported financial position and results of operations based on currently available information. We review significant estimates and judgments affecting our consolidated financial statements on a recurring basis and record the effect of any necessary adjustments. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things: (i) developing fair value assumptions, including estimates of future cash flows and discount rates related to impairment analyses and business combinations, (ii) valuation of derivative instruments, (iii) analyzing tangible and intangible assets for possible impairment, (iv) estimating the useful lives of our long-lived assets, (v) estimating the scope, costs and timing of remediation work related to Asset Retirement Obligations (“AROs”), (vi) assessing future tax exposure and the realization of deferred tax assets, (vii) determining amounts to accrue for contingencies, guarantees, and indemnifications, and (viii) estimating various factors used to value our pension assets and liabilities. Actual results could differ materially from our estimates. In the opinion of management, all adjustments considered necessary for a fair presentation have been included in our consolidated financial statements.

Cash and Cash Equivalents.  Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid short-term investments with original maturities of three months or less.

Restricted Cash.  Restricted cash represents cash that is not readily available for general purpose cash needs. Restricted cash is classified as a current or long-term asset based on the timing and nature of when or how the cash is expected to be used or when the restrictions are expected to lapse. As of December 31, 2017, the Company had no restricted cash balances, and as of December 31, 2016, the Company had the following restricted cash balances:

(amounts in millions)
Restricted cash, current:
Cash deposits associated with certain letters of credit (1)	$	41
Pre-funded original issue discount on the Term Loan (2)	20
Interest earned on funds in escrow	1
	$	62
Restricted cash, long-term:
Restricted cash related to the issuance of the Term Loan (2)	$	2,000

_________________________________________

(1) Upon the emergence of Genco from bankruptcy, approximately $35 million of these deposits were returned to Dynegy.

(2) Upon the close of the ENGIE Acquisition, as defined herein, the proceeds from the issuance of the Term Loan were released from escrow. Please read Note 13—Debt for further information. 

Accounts Receivable and Allowance for Doubtful Accounts.  We record accounts receivable at net realizable value (“NRV”) when the product or service is delivered to the customer. We establish provisions for losses on accounts receivable if it becomes probable that we will not collect all or part of outstanding balances. We review collectability and establish or adjust our allowance as necessary using the specific identification method.

Inventory.  Our commodity and materials and supplies inventories are carried at the lower of weighted average cost or NRV.

Property, Plant and Equipment.  Property, plant and equipment (“PP&E”), which consists principally of power generating facilities, including capitalized interest, is generally recorded at historical cost. Expenditures for major installations, replacements, and improvements or betterments are capitalized and depreciated over the expected life cycle. Expenditures for maintenance, repairs, and minor renewals to maintain the operating condition of our assets are expensed. Depreciation is recognized using the straight-line method over the estimated economic service lives of the assets, ranging from one to 40 years.

F-11

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The estimated economic service lives of our asset groups are as follows:

Asset Group	Range of Years
Power generation	1 to 36
Buildings and improvements	1 to 40
Office and other equipment	1 to 28

Gains and losses on sales of assets are reflected in Gain (loss) on sale of assets, net in the consolidated statements of operations. We evaluate our PP&E for impairment when events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. If an impairment is indicated, the carrying value is first compared to the undiscounted cash flows for the asset’s remaining useful life to determine if the carrying value is recoverable.  In the event the carrying value is not recoverable, an impairment is recognized for the amount of carrying value in excess of the asset’s fair value.  We recorded impairments on certain of our assets in 2017. Please read Note 8—Property, Plant and Equipment for further information.

Goodwill. Goodwill represents, at the time of an acquisition, the excess of purchase price over fair value of the identifiable tangible and intangible net assets acquired. The carrying amount of our goodwill is periodically reviewed, at least annually, for impairment and when certain indicators of impairment exist on an interim basis.  We have elected October 1 for our annual assessment. In accordance with Accounting Standards Codification (“ASC”) 350, Intangibles-Goodwill and Other, we can opt to perform a qualitative assessment to test goodwill for impairment to determine whether it is more likely than not (a likelihood of more than 50 percent) that an impairment has occurred or we can directly perform a quantitative assessment of our reporting units. In the absence of sufficient qualitative factors, we will compare the fair value of a reporting unit to the book value, including goodwill. If the fair value exceeds book value, the goodwill of the reporting unit is not considered impaired. If the book value exceeds fair value, an impairment charge is recognized for the excess.

There were no impairments of goodwill for the year ended December 31, 2017. We wrote off approximately $27 million of goodwill during the year ended December 31, 2017 related to divestitures of facilities located within our reporting units. Please see Note 3—Acquisitions and Divestitures for further information.

Intangible Assets and Liabilities.  We initially record and measure intangible assets and liabilities (“Intangibles”) based on the fair value of those rights transferred in the transaction in which the asset was acquired. Our recognized Intangibles consist of contractual rights and obligations with finite lives, and their initial values are based on quoted market prices, if available, or measurement techniques based on the best information available such as a present value of future cash flows. We amortize our definite-lived Intangibles over the useful life of the respective contracts.

Asset Retirement Obligations.  We record the present value of our legal obligations to retire tangible, long-lived assets when the liability is incurred. Please see Use of Estimates above for a description of the significant estimates used by management in determining our liability. Our AROs relate to activities such as Coal Combustion Residuals (“CCR”) surface impoundments and landfill closure, dismantlement of power generation facilities, future removal of asbestos-containing material from certain power generation facilities, closure and post-closure costs, environmental testing, remediation, monitoring, and land obligations. Accretion expense is included in Operating and maintenance expense in our consolidated statements of operations. A summary of the changes related to our AROs is as follows:

	Year Ended December 31,
(amounts in millions)	2017			2016
Balance at beginning of year	$	287		$	280
Accretion expense	20			20
Liabilities settled	(8		)	(1		)
Revision of previous estimate (1)	22			(12		)
Acquisitions	24			—
Divestitures	(16		)	—
Balance at end of year	$	329		$	287

__________________________________________

(1) Based on management’s review and assessment of CCR compliance timing and site-specific analysis.

Contingencies, Commitments, Guarantees and Indemnifications.  We are involved in numerous lawsuits, claims, and proceedings in the normal course of our operations. We record a loss contingency for these matters when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. We review our loss contingencies on an ongoing

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

basis to ensure that we have appropriate reserves recorded in our consolidated balance sheets. These reserves are based on estimates and judgments made by management with respect to the likely outcome of these matters, including any applicable insurance coverage, and are adjusted as circumstances warrant. Liabilities for environmental contingencies are recorded when an environmental assessment indicates that remedial efforts are probable and the costs can be reasonably estimated. Measurement of liabilities is based, in part, on relevant past experience, currently enacted laws and regulations, existing technology, site-specific costs, and cost-sharing arrangements. Recognition of any joint and several liability is based upon our best estimate of our final pro-rata share of such liability.

We enter into various guarantees and indemnifications during the ordinary course of business. When a guarantee or indemnification is entered into, an estimated fair value of the underlying guarantee or indemnification is recorded. Some guarantees and indemnifications could have significant financial impact under certain circumstances; however, management also considers the probability of such circumstances occurring when estimating the fair value.

Preferred Stock.  The outstanding shares of our Preferred Stock converted to approximately 12.9 million shares of Common Stock on November 1, 2017 (the “Mandatory Conversion Date”). Our preferred shares were mandatorily convertible, were not redeemable and are classified within stockholders’ equity.  We presented the gross proceeds from their issuance as a single line item within stockholders’ equity on the consolidated balance sheets.  Dividends on the preferred shares were cumulative and are presented as a reduction of net income (or increase of net loss) to derive net income (loss) attributable to common shareholders on the consolidated statements of operations.  Dividends are recognized in stockholders’ equity in the period in which they are declared, and are presented as a financing activity on the consolidated statements of cash flows when paid.

On October 2, 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.

Treasury Stock. Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as treasury stock, which is presented in our consolidated balance sheets as a reduction of Additional paid-in capital.

Revenue Recognition.  We earn revenue from our facilities in three primary ways: (i) the sale of energy through both physical and financial transactions to optimize the financial performance of our generating facilities; (ii) the sale of capacity; and (iii) the sale of ancillary services, which are the products of a generation facility that support the transmission grid operation, allow generation to follow real-time changes in load, and provide emergency reserves for major changes to the balance of generation and load. We recognize revenue from these transactions when the product or service is delivered to a customer, unless they meet the definition of a derivative. Please read “Derivative Instruments—Generation” for further discussion of the accounting for these types of transactions.

Derivative Instruments—Generation.  We enter into commodity contracts that meet the definition of a derivative. These contracts are often entered into to mitigate or eliminate market and financial risks associated with our generation business. These contracts include forward contracts, which commit us to buy or sell commodities in the future; futures contracts, which are generally broker-cleared standard commitments to purchase or sell a commodity; option contracts, which convey the right to buy or sell a commodity; and swap agreements, which require payments to or from counterparties based upon the differential between two prices for a predetermined quantity. All derivative commodity contracts that do not qualify for the “normal purchase, normal sale” exception are recorded at fair value in Risk management assets and liabilities in the consolidated balance sheets. We elect not to apply hedge accounting to our derivative commodity contracts; therefore, changes in fair value are recorded currently in Revenues in our consolidated statements of operations. As a result, these mark-to-market gains and losses are not reflected in the consolidated statements of operations in the same period as the underlying activity for which the derivative instruments serve as economic hedges. Derivative instruments and related cash collateral or margin that are executed with the same counterparty under a master netting agreement are reflected on a net basis in the consolidated balance sheets.

Cash inflows and cash outflows associated with the settlement of risk management activities are recognized in net cash provided by (used in) operating activities on the consolidated statements of cash flows.

Derivative Instruments—Financing Activities.  We are exposed to changes in interest rates through our variable rate debt. In order to manage our interest rate risk, we enter into interest rate swap agreements. We elect not to apply hedge accounting to our interest rate derivative contracts; therefore, changes in fair value are recorded currently in earnings through interest expense. Cash settlements related to interest rate contracts are generally classified as either inflows or outflows from operating activities on the consolidated statements of cash flows. However, due to an other-than-insignificant financing element at inception on a portion of our interest rate swaps, certain of our cash flows related to these contracts are classified as financing activities. Please read Note 13—Debt for more information.

Fair Value Measurements.  Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Our estimate of fair value reflects the

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DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

impact of credit risk. We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs are classified as readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We classify fair value balances based on the classification of the inputs used to calculate the fair value of a transaction. The inputs used to measure fair value have been placed in a hierarchy based on priority.

The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

• Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed equities, and U.S. government treasury securities.

• Level 2—Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using industry-standard models or other valuation methodologies in which substantially all assumptions are observable in the marketplace throughout the full term of the instrument, and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as over the counter forwards, options, and swaps.

• Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to our needs. At each balance sheet date, we perform an analysis of all instruments and include in Level 3 all of those whose fair value is based on significant unobservable inputs.

The determination of fair value incorporates various factors. These factors include not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), but also the impact of our nonperformance risk on our liabilities. Valuation adjustments are generally based on capital market implied ratings evidence when assessing the credit standing of our counterparties and, when applicable, adjusted based on management’s estimates of assumptions market participants would use in determining fair value.

Income Taxes.  We file a consolidated U.S. federal income tax return. We use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant timing differences as of each reporting date. We also account for changes in the tax code when enacted.

As part of the process of preparing our consolidated financial statements, we are required to estimate our income taxes in each of the jurisdictions in which we operate. This process involves estimating our actual current tax payable and related tax expense together with assessing temporary differences resulting from differing tax and accounting treatment of certain items, such as depreciation. These differences can result in deferred tax assets and liabilities which are included within our consolidated balance sheets and are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

Because we operate and sell power in many different states, our effective annual state income tax rate may vary from period to period because of changes in our sales profile by state, as well as jurisdictional and legislative changes by state. As a result, changes in our estimated effective annual state income tax rate can have a significant impact on our measurement of temporary differences. We project the rates at which state tax temporary differences will reverse based upon estimates of revenues and operations in the respective jurisdictions in which we conduct business.

The Company routinely assesses the realizability of its deferred tax assets. If the Company concludes that it is more likely than not that some or all of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. In making this determination, we consider all available positive and negative evidence affecting specific deferred tax assets, including our past and anticipated future performance, the reversal of deferred tax liabilities, and the implementation of tax planning strategies.

Accounting for uncertainty in income taxes requires that we determine whether it is more likely than not that a tax position we have taken will be sustained upon examination. If we determine that it is more likely than not that the position will be sustained, we recognize the largest amount of the benefit that is greater than 50 percent likely of being realized upon settlement.

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DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Please read Note 14—Income Taxes for further discussion of our accounting for income taxes, uncertain tax positions, and changes in our valuation allowance.

Earnings (Loss) Per Share. Basic earnings (loss) per share represents the amount of earnings for the period available to each share of common stock outstanding during the period. Diluted earnings (loss) per share includes the effect of issuing shares of common stock, assuming (i) stock options and warrants are exercised, (ii) restricted stock units and performance stock units are fully vested under the treasury stock method, and (iii) our mandatory convertible preferred stock and the prepaid stock purchase contracts (“SPCs”) are converted into common stock under the if-converted method.

Business Combinations Accounting. The Company accounts for its business combinations in accordance with ASC 805, Business Combinations (“ASC 805”), which requires an acquirer to recognize and measure in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at fair value at the acquisition date. It also requires an acquirer to measure any goodwill acquired and determine what information to disclose to enable users of an entity’s financial statements to evaluate the nature and financial effects of the business combination. In addition, ASC 805 requires transaction costs to be expensed as incurred.

Variable Interest Entities. We evaluate our interests in variable interest entities (“VIEs”) to determine if we are considered the primary beneficiary and should therefore consolidate the VIE. The primary beneficiary of a VIE is the party that both: (i) has the power to direct the activities of a VIE that most significantly impact its economic performance and (ii) has an obligation to absorb losses or a right to receive benefits that could potentially be significant to the VIE.

Accounting Standards Adopted

Goodwill. In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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 consolidated financial statements.

Statement of Cash Flows. In August 2016, the FASB issued ASU 2016-15-Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. To reduce current and future diversity in practice, the amendments in this ASU provide guidance for several cash flow classification issues identified where current GAAP is either unclear or does not include specific guidance. We early adopted this ASU as of December 31, 2016 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 $(33) million, and $26 million of cash prepayments from operating activities to investing activities in our consolidated statement of cash flows for the years ended December 31, 2016 and 2015, respectively.

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 explains 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 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 early adopted this ASU as of December 31, 2016 and applied the amendments on a retrospective basis. As a result of the retrospective application of this ASU, we reclassified a change of approximately $2 million and $26 million of restricted cash from operating activities and $2.021 billion and $5.148 billion of restricted cash from investing activities to Net increase (decrease) in cash, cash equivalents, and restricted cash in our consolidated statement of cash flows for the years ended December 31, 2016 and 2015, respectively. Additionally, restricted cash of $39 million and $2.062 billion are now reflected in the beginning of period and end of period cash, cash equivalents and restricted cash line items, respectively, in our consolidated statement of cash flows for the year ended December 31, 2016 and $5.213 billion and $39 million are now reflected in the beginning of period and end of period cash, cash equivalents and restricted cash line items, respectively, in our consolidated statement of cash flows for the year ended December 31, 2015.

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DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within our consolidated balance sheets that sum to the total of the same such amounts shown in our consolidated statements of cash flows:

(amounts in millions)	December 31, 2017		December 31, 2016		December 31, 2015
Cash and cash equivalents	$	365	$	1,776	$	505
Restricted cash included in current assets (1)	—		62		39
Restricted cash included in long-term assets (2)	—		2,000		—
Total cash, cash equivalents and restricted cash	$	365	$	3,838	$	544

__________________________________________

(1) Year ended December 31, 2016, includes $41 million related to collateral and $21 million placed in escrow for the issuance of the Term Loan ($20 million of pre-funded original issue discount and $1 million interest income earned). Year ended December 31, 2015, includes $39 million related to collateral.

(2) Relates to amounts placed into escrow for the issuance of the Term Loan.

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 consolidated financial statements.

Accounting Standards Not Yet Adopted    

Business Combinations. In January 2017, the FASB issued ASU 2017-01-Business Combinations (Topic 805): Clarifying the Definition of a Business. The amendments in this ASU clarify the definition of a business. The amendments affect all companies and other reporting organizations that must determine whether they have acquired or sold a business. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. We are currently evaluating this ASU and any potential impacts the adoption will have on our consolidated financial statements.

Pensions. In March 2017, the FASB issued ASU 2017-07-Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. The amendments of this ASU require an entity to report the service cost component of net benefit costs in the same line item as other compensation costs arising from services rendered by the related employees during the applicable service period. The other components of net benefit cost are required to be presented separately from the service cost component and below the subtotal of operating income. Additionally, only the service cost component of net benefit costs is eligible for capitalization. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. The adoption of this standard must be applied on a retrospective basis for the amendments concerning income statement presentation and on a prospective basis for the amendments regarding the capitalization of the service cost component. We are currently evaluating this ASU and any potential impacts the adoption will have on our consolidated financial statements.

Leases. In February 2016, the FASB issued ASU 2016-02-Leases (Topic 842). The provisions in this ASU will require lessees to recognize lease assets and lease liabilities, for all leases, including operating leases, on the 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 based on the present value of the minimum rental payments. Entities may make an accounting policy election to not recognize lease assets or lease liabilities for leases with a term of 12 months or less. 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 have established an implementation team to assess the impact the new accounting standard will have on our financial statements, as well as accounting policies, business processes and controls.

Revenue from Contracts with Customers. In May 2014, the FASB issued ASU 2014-09-Revenue from Contracts with Customers (Topic 606). This ASU supersedes current revenue recognition requirements and industry specific guidance and develops a common revenue recognition standard whereby an entity will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing, and uncertainty of revenues and cash flows from contracts with customers. The guidance in this ASU and its amendments are effective for interim and annual periods beginning after December 15, 2017, unless early adopted. We intend on adopting the ASU using the modified retrospective approach.

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DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

We have finalized our evaluation of the impact that the new accounting standard will have on our financial statements. As a result of our evaluation, the Company did not identify any material changes to the timing of our revenue recognition. Changes to our disclosures will primarily include a regional presentation of our revenues disaggregated by revenue type - energy, capacity, and ancillary services, as well as disclosure of future performance obligations. We have assessed our accounting policies and internal processes and controls, and identified changes which will become effective upon adoption.

Note 3—Acquisitions and Divestitures

Acquisitions

ENGIE Acquisition. On 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”).

Business Combination Accounting

The ENGIE Acquisition has been accounted for in accordance with ASC 805 with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the ENGIE Acquisition Closing Date. 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 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 3).

• Acquired derivatives were valued using the methods described in Note 5—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.

• AROs were recorded in accordance with ASC 410, Asset Retirement and Environmental Obligations (Level 3).

The accounting for the ENGIE Acquisition is not complete because certain information and analysis that may impact our initial valuation is still being obtained or reviewed. Dynegy expects to finalize these amounts during the first quarter of 2018. The significant assets and liabilities for which provisional amounts are recognized are PP&E, deferred income taxes, and taxes other than deferred income taxes. Additionally, some taxes have not yet been finalized with the associated taxing jurisdictions, resulting in a potential change to their fair value at acquisition. These changes may also impact the fair value of the acquired PP&E or deferred tax liability. As such, the provisional amounts recognized are subject to revision until our valuation is completed, not to exceed one year from the ENGIE Acquisition Closing Date, and any material adjustments identified that existed as of the acquisition date will be recognized in the period in which they are identified.

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DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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	(31		)
Fair value of total consideration transferred	$	3,269
Cash	$	20
Accounts receivable	22
Inventory	95
Prepayments and other current assets	3
Assets from risk management activities (including current portion of $21 million)	25
Property, plant and equipment	2,775
Investment in unconsolidated affiliate	132
Intangible assets (including current portion of $7 million)	50
Assets held-for-sale	472
Other long-term assets	131
Total assets acquired	3,725
Accounts payable	18
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	372
Other long-term liabilities	1
Total liabilities assumed	456
Net assets acquired	$	3,269

EquiPower Acquisition. On April 1, 2015, we purchased 100 percent of the equity interests in EquiPower Resources Corp. (“ERC”) from certain affiliates of ECP thereby acquiring (i) five combined-cycle natural gas-fired facilities in Connecticut, Massachusetts, and Pennsylvania, (ii) a partial interest in one natural gas-fired peaking facility in Illinois, (iii) two gas- and oil-fired peaking facilities in Ohio, and (iv) one coal-fired facility in Illinois (the “ERC Acquisition”). In a related transaction on the same date, we purchased, through a wholly owned subsidiary, 100 percent of the equity interests in Brayton Point Holdings, LLC (“Brayton”) from certain affiliates of Energy Capital Partners (“ECP”), thereby acquiring a coal-fired facility in Massachusetts (the “Brayton Acquisition”).

The ERC Acquisition and the Brayton Acquisition (collectively, the “EquiPower Acquisition”) added approximately 6,300 MW of generation in Connecticut, Illinois, Massachusetts, Ohio, and Pennsylvania for an aggregate base purchase price of approximately $3.35 billion in cash plus approximately $105 million in common stock of Dynegy, subject to certain adjustments.

Duke Midwest Acquisition. On April 2, 2015, we purchased 100 percent of the membership interests in Duke Energy Commercial Asset Management, LLC and Duke Energy Retail Sales, LLC, from two affiliates of Duke Energy Corporation (collectively, “Duke Energy”), thereby acquiring approximately 6,200 MW of generation in (i) three combined-cycle natural gas-fired facilities located in Ohio and Pennsylvania, (ii) two natural gas-fired peaking facilities located in Ohio and Illinois, (iii) one oil-fired peaking facility located in Ohio, (iv) partial interests in five coal-fired facilities located in Ohio, and (v) one retail energy business for a base purchase price of $2.8 billion in cash (the “Duke Midwest Acquisition”), subject to certain adjustments.

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DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table summarizes acquisition costs incurred related to the ENGIE Acquisition, the EquiPower Acquisition and the Duke Midwest Acquisition, which are included in Acquisition and integration costs in our consolidated statements of operations, and revenues and operating income (loss) attributable to the acquisitions, which are included in our consolidated statements of operations:

	Year Ended December 31,
(amounts in millions)	2017		2016		2015
Acquisition costs	$	38	$	5	$	86
Revenues	$	3,079	$	2,280	$	1,703
Operating income	$	86	$	235	$	230

Pro Forma Results. The unaudited pro forma financial results for the years ended December 31, 2017, 2016 and 2015 assume the February 2017 ENGIE Acquisition occurred on January 1, 2016 and the April 2015 EquiPower and Duke Midwest Acquisitions occurred on January 1, 2014. The unaudited pro forma financial results may not be indicative of the results that would have occurred had the acquisitions been completed on the above dates, nor are they indicative of future results of operations. The unaudited pro forma financial results for the three years ended December 31, 2017 include adjustments of $38 million, $5 million, and $86 million, respectively, for non-recurring acquisition costs.

	Year Ended December 31,
(amounts in millions)	2017			2016			2015
Revenues	$	4,899		$	5,046		$	4,860
Net income (loss)	$	77		$	(1,361	)	$	308
Net loss attributable to noncontrolling interest	$	(4	)	$	(4	)	$	(3	)
Net income (loss) attributable to Dynegy Inc.	$	81		$	(1,357	)	$	311

Other. On April 12, 2017, we received approximately $25 million of cash related to the 2013 New Ameren Energy Resources, LLC (“AER”) Acquisition. As a result, we have recorded $25 million in Other income and expense, net in our consolidated statement of operations for the year ended December 31, 2017.

During the year ended December 31, 2016, we received proceeds of $14 million of cash related to the AER Acquisition. As a result, we recorded $14 million in Other income and expense, net in our consolidated statement of operations for the year ended December 31, 2016.

Divestitures

Troy and Armstrong. On July 11, 2017, Dynegy completed the sale of its equity ownership interests in two peaking facilities in PJM to LS Power (the “Troy and Armstrong Sale”) for approximately $472 million in cash, including working capital adjustments. The facilities sold were recently acquired in the ENGIE Acquisition and total 1,269 MW.

Dighton and Milford-MA. On September 22, 2017, Dynegy completed the sale of its equity ownership interests in two intermediate natural gas-fueled facilities to Starwood Energy Group for approximately $125 million in cash, including working capital adjustments. This sale has fulfilled the mitigation plan approved by FERC regarding the Company’s purchase of ENGIE’s US-based asset portfolio. For the year ended December 31, 2017, we recognized a loss on sale of assets on our Dighton and Milford-MA facilities of $90 million, which includes $18 million of allocated goodwill. Goodwill was allocated based on the relative fair values of Dighton and Milford-MA compared to the fair values of the remaining reporting unit.

Lee.On October 12, 2017, Dynegy completed the sale of its equity ownership in the Lee facility, a natural gas-fueled peaking facility in PJM, to an affiliate of Rockland Capital for $176 million in cash, including working capital adjustments.

Our Lee facility met Held-for-Sale criteria during the third quarter of 2017.  As a result, we wrote down the carrying value of the assets held-for-sale to the sales price and recognized an impairment of $15 million, which includes $9 million of allocated goodwill and was recorded in Impairments in our consolidated statements of operations. Additionally, upon the closing of the sale, we recorded a $5 million loss to Loss on sale of assets, net in our consolidated statements of operations.

Note 4—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

F-19

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 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 consolidated statements of operations until the delivery occurs.

Quantitative Disclosures Related to Financial Instruments and Derivatives

As of December 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)	(62	)	MWh	$	(150	)
Electricity basis derivatives (3)	(25	)	MWh	$	(4	)
Natural gas derivatives (2)	404		MMBtu	$	(4	)
Natural gas basis derivatives	120		MMBtu	$	(1	)
Physical heat rate derivatives (4)	177/(17)		MMBtu/MWh	$	(95	)
Heat rate option	6/(1)		MMBtu/MWh	$	(4	)
Emissions derivatives	8		Metric Ton	$	2
Interest rate swaps	1,961		U.S. Dollar	$	7
Common stock warrants (5)	9		Warrant	$	(2	)

_________________________________________

(1) Includes both asset and liability risk management positions but excludes margin and collateral netting of $47 million.

(2) Mainly comprised of swaps and physical forwards.

(3) Comprised of FTRs and swaps.

(4) Comprised of swaps which settle on the relationship of power pricing to natural gas pricing.

(5) Each warrant is convertible into one share of Dynegy common stock.

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DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Derivatives on the Balance Sheet.      The following tables present the fair value and balance sheet classification of derivatives in our consolidated balance sheets as of December 31, 2017 and 2016. As of December 31, 2017 and 2016, there were no gross amounts available to be offset that were not offset in our consolidated balance sheets.

			December 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	$	155		$	(112	)	$	—	$	43
	Interest rate contracts	Assets from risk management activities	20			(5		)	—		15
	Total derivative assets		$	175		$	(117	)	$	—	$	58
Derivative liabilities:
	Commodity contracts	Liabilities from risk management activities	$	(411	)	$	112		$	47	$	(252	)
	Interest rate contracts	Liabilities from risk management activities	(13		)	5			—		(8		)
	Common stock warrants	Accrued liabilities and other current liabilities and other long-term liabilities	(2		)	—			—		(2		)
	Total derivative liabilities		$	(426	)	$	117		$	47	$	(262	)
Total derivatives			$	(251	)	$	—		$	47	$	(204	)

			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 December 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 $32 million for which we have posted no collateral. Transactions with our clearing brokers are excluded as they are fully collateralized. Our remaining derivative instruments do not have credit-related collateral contingencies as they are included within our first-lien collateral program.

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DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table summarizes our cash collateral posted as of December 31, 2017 and 2016, within Prepayments and other current assets in our consolidated balance sheets, and the amount applied against short-term risk management activities:

Location on Balance Sheet	December 31, 2017		December 31, 2016
(amounts in millions)
Gross collateral posted with counterparties	$	92	$	116
Less: Collateral netted against risk management liabilities	47		54
Net collateral within Prepayments and other current assets	$	45	$	62

Impact of Derivatives on the 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 consolidated statements of operations.

Our consolidated statements of operations for the years ended December 31, 2017, 2016 and 2015 include the impact of derivative financial instruments as presented below. 

Derivatives Not Designated as Hedges	Location of Gain (Loss) Recognized in Income on Derivatives	Year Ended December 31,
		2017			2016			2015
(amounts in millions)
Commodity contracts	Revenues	$	(58	)	$	270		$	194
Interest rate contracts	Interest expense	$	16		$	(5	)	$	(15	)
Common stock warrants	Other income and (expense), net	$	16		$	6		$	54

Note 5—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 2—Summary of Significant Accounting Policies—Fair Value Measurements for further discussion.

The finance organization monitors commodity risk through the Commodity Risk Control Group (“CRCG”).  The Executive Management Team (“EMT”) monitors interest rate risk.  The EMT has delegated the responsibility for managing interest rate risk to the Chief Financial Officer (“CFO”).  The CRCG is independent of our commercial operations and has direct access to the Audit Committee. The Finance and Risk Management Committee, comprised of members of management and chaired by the CFO, meets periodically and is responsible for reviewing our overall day-to-day energy commodity risk exposure, as measured against the limits established in our Commodity Risk Policy. Each quarter, as part of its internal control processes, representatives from the CRCG review the methodology and assumptions behind the pricing of the forward curves.  As part of this review, liquidity periods are established based on third party market information, the basis relationship between direct and derived curves is evaluated, and changes are made to the forward power model assumptions.

The CRCG reviews changes in value on a daily basis through the use of various reports.  The pricing for power, natural gas, and fuel oil curves is automatically entered into our commercial system nightly based on data received from our market data provider.  The CRCG reviews the data provided by the market data provider by utilizing third party broker quotes for comparison purposes.  In addition, our traders are required to review various reports to ensure accuracy on a daily basis.

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DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 December 31, 2017 and 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 December 31, 2017
(amounts in millions)	Level 1			Level 2			Level 3			Total
Assets:
Assets from commodity risk management activities:
Electricity derivatives	$	—		$	71		$	6		$	77
Natural gas derivatives	—			62			10			72
Physical heat rate derivatives	—			4			—			4
Emissions derivatives	—			2			—			2
Total assets from commodity risk management activities	—			139			16			155
Assets from interest rate contracts	—			20			—			20
Total assets	$	—		$	159		$	16		$	175
Liabilities:
Liabilities from commodity risk management activities:
Electricity derivatives	$	—		$	(200	)	$	(31	)	$	(231	)
Natural gas derivatives	—			(71		)	(6		)	(77		)
Physical heat rate derivatives	—			(99		)	—			(99		)
Heat rate option	—			—			(4		)	(4		)
Total liabilities from commodity risk management activities	—			(370		)	(41		)	(411		)
Liabilities from interest rate contracts	—			(13		)	—			(13		)
Liabilities from outstanding common stock warrants	(2		)	—			—			(2		)
Total liabilities	$	(2	)	$	(383	)	$	(41	)	$	(426	)

	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, heat rate derivatives, 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, heat rate derivative valuations are derived using a DCF model, which uses modeled forward natural gas and power prices, and the heat rate option is derived using a Black-Scholes spread model, which uses forward natural gas and power prices, market implied volatilities, and modeled correlation

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DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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, and natural gas pricing, and the difference between our plant locational prices to liquid hub prices. Power price spreads, and natural gas 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 December 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)	(14	)	Million MWh	$	(23	)	Basis spread + liquid location	Basis spread	$4.25 - $6.25
FTRs	(22	)	Million MWh	$	(2	)	Historical congestion	Forward price	$0 - $6.00
Physical heat rate derivatives	4/0		Million MMBtu /Million MWh	$	—		Discounted Cash Flow	Forward price	$2.00 - $2.80 / $22 - $27
Heat rate option	6/1		Million MMBtu /Million MWh	$	(4	)	Option models	Power price volatility Gas/Power price correlation	30% - 50% / 70% - 100%
Natural gas derivatives (1)	95		Million MMBtu	$	4		Illiquid location fixed price	Forward price	$2.00 - $2.45

__________________________________________

(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:

	Year Ended December 31, 2017
(amounts in millions)	Electricity Derivatives			Natural Gas Derivatives			Heat Rate Option			Total
Balance at December 31, 2016	$	8		$	(6	)	$	—		$	2
Total gains (losses) included in earnings	(30		)	5			—			(25		)
Settlements (1)	(4		)	5			—			1
Option premiums received	—			—			(4		)	(4		)
Acquired derivatives	1			—			—			1
Balance at December 31, 2017	$	(25	)	$	4		$	(4	)	$	(25	)
Unrealized gains (losses) relating to instruments held as of December 31, 2017	$	(30	)	$	5		$	—		$	(25	)

	Year Ended December 31, 2016
(amounts in millions)	Electricity Derivatives			Natural Gas Derivatives			Coal Derivatives			Total
Balance at December 31, 2015	$	(18	)	$	(32	)	$	2		$	(48	)
Total gains (losses) included in earnings	59			49			(4		)	104
Settlements (1)	(33		)	(23		)	2			(54		)
Balance at December 31, 2016	$	8		$	(6	)	$	—		$	2
Unrealized gains (losses) relating to instruments held as of December 31, 2016	$	59		$	49		$	(4	)	$	104

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DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	Year Ended December 31, 2015
(amounts in millions)	Electricity Derivatives			Natural Gas Derivatives			Heat Rate Derivatives			Coal Derivatives			Total
Balance at December 31, 2014	$	(4	)	$	—		$	—		$	—		$	(4	)
Total gains included in earnings	39			3			—			—			42
Settlements (1)	1			28			9			(2		)	36
Acquired derivatives	(54		)	(63		)	(9		)	4			(122		)
Balance at December 31, 2015	$	(18	)	$	(32	)	$	—		$	2		$	(48	)
Unrealized gains relating to instruments held as of December 31, 2015	$	39		$	3		$	—		$	—		$	42

__________________________________________

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

Gains and losses recognized for Level 3 recurring items are included in Revenues in our 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 material transfers between Level 1, Level 2 and Level 3 for the years ended December 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.

Impairments. During the years ended December 31, 2017, 2016 and 2015, we recorded impairment charges related to certain of our facilities, materials and supplies inventory and assets held-for-sale using fair value measurements. See Note 3—Acquisitions and Divestitures, Note 7—Inventory and Note 8—Property, Plant and Equipment for further discussion. Certain impairments were determined through a DCF model using similar fair value methodologies used to value our business acquisitions.

Fair Value of Financial Instruments.  The following table discloses the fair value of financial instruments which are not recognized at fair value in our 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 December 31, 2017 and 2016, respectively.

		December 31, 2017						December 31, 2016
(amounts in millions)	Fair Value Hierarchy	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Dynegy Inc.:
Term Loan, due 2024 (1)	Level 2	$	(1,944	)	$	(2,021	)	$	(2,213	)	$	(2,250	)
Revolving Facility (1)	Level 2	$	—		$	—		$	—		$	—
6.75% Senior Notes, due 2019 (1)	Level 2	$	(845	)	$	(873	)	$	(2,083	)	$	(2,137	)
7.375% Senior Notes, due 2022 (1)	Level 2	$	(1,734	)	$	(1,844	)	$	(1,731	)	$	(1,665	)
5.875% Senior Notes, due 2023 (1)	Level 2	$	(493	)	$	(508	)	$	(492	)	$	(431	)
7.625% Senior Notes, due 2024 (1)	Level 2	$	(1,237	)	$	(1,344	)	$	(1,237	)	$	(1,156	)
8.034% Senior Notes, due 2024 (1)	Level 2	$	(188	)	$	(198	)	$	—		$	—
8.00% Senior Notes, due 2025 (1)	Level 2	$	(739	)	$	(812	)	$	(738	)	$	(703	)
8.125% Senior Notes, due 2026 (1)	Level 2	$	(842	)	$	(933	)	$	—		$	—
7.00% Amortizing Notes, due 2019 (TEUs) (1)	Level 2	$	(51	)	$	(54	)	$	(78	)	$	(90	)
Forward capacity agreement (1)	Level 3	$	(215	)	$	(215	)	$	(205	)	$	(205	)
Inventory financing agreements	Level 3	$	(48	)	$	(48	)	$	(129	)	$	(127	)
Equipment financing agreements (1)	Level 3	$	(97	)	$	(97	)	$	(73	)	$	(73	)
Genco:
Liabilities subject to compromise (2)	Level 3	$	—		$	—		$	(825	)	$	(366	)

F-25

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

__________________________________________

(1) Carrying amounts include unamortized discounts and debt issuance costs. Please read Note 13—Debt for further discussion.

(2) Carrying amounts represent the Genco senior notes that were 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 20—Genco Chapter 11 Bankruptcy for further details.

Concentration of Credit Risk.  We sell our energy products and services to customers in the electric and natural gas distribution industries, financial institutions, residential customers and to entities engaged in commercial and industrial businesses. These industry concentrations have the potential to impact our overall exposure to credit risk, either positively or negatively, because the customer base may be similarly affected by changes in economic, industry, weather or other conditions.

At December 31, 2017 and 2016, our credit exposure as it relates to the mark-to-market portion of our risk management portfolio totaled $7 million and $79 million, respectively.

Our Credit Department, based on guidelines approved by the Board of Directors, establishes our counterparty credit limits. Our credit risk system provides current credit exposure to counterparties on a daily basis. Our industry typically operates under negotiated credit lines for physical delivery and financial contracts. We enter into master netting agreements in an attempt to both mitigate credit exposure and reduce collateral requirements. In general, the agreements include our risk management subsidiaries and allow the aggregation of credit exposure, margin and set-off. We attempt to further reduce credit risk with certain counterparties by obtaining third party guarantees or collateral as well as the right of termination in the event of default. As a result, we decrease a potential credit loss arising from a counterparty default.

We include cash collateral deposited with brokers and cash paid to non-broker counterparties which has not been offset against risk management liabilities in Prepayments and other current assets in our consolidated balance sheets. As of December 31, 2017 and 2016, we had $45 million and $62 million recorded to Prepayments and other current assets, respectively. We include cash collateral received from non-broker counterparties in Accrued liabilities and other current liabilities in our consolidated balance sheets. As of December 31, 2017 and 2016, we were not holding any collateral received from counterparties.

Note 6—Cash Flow Information

The supplemental disclosures of cash flow and non-cash investing and financing information are as follows:

	Year Ended December 31,
(amounts in millions)	2017			2016			2015
Interest paid (net of amount capitalized of $2, $10, and $12, respectively)	$	555		$	548		$	491
Taxes paid (net of refunds)	$	(5	)	$	(1	)	$	2
Other non-cash investing and financing activity:
Change in capital expenditures included in accounts payable	$	7		$	(13	)	$	(8	)
Change in capital expenditures pursuant to equipment financing agreements	$	24		$	11		$	63
Issuance of 2017 Warrants	$	17		$	—		$	—
Issuance of senior notes related to the Genco restructuring	$	188		$	—		$	—
Sale of interest in Conesville facility	$	(58	)	$	—		$	—
Acquisition of interest in Zimmer facility	$	27		$	—		$	—
Non-cash consideration transferred for acquisitions	$	—		$	—		$	105

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DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 7—Inventory

A summary of our inventories is as follows: 

(amounts in millions)	December 31, 2017		December 31, 2016
Materials and supplies	$	242	$	182
Coal	166		238
Fuel oil	15		17
Natural gas	9		—
Emissions allowances (1)	13		8
Total	$	445	$	445

__________________________________________

(1) At December 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 13—Debt—Emissions Repurchase Agreements for further discussion.

As discussed in Note 9—Joint Ownership of Generating Facilities, Stuart Unit 1 was retired early on September 30, 2017, with remaining Stuart and Killen units scheduled to be retired by mid-2018. We determined that we would not be able to recover the carrying value of our inventory at these facilities and, as a result, recognized a charge of $14 million in Impairments in our consolidated statements of operations for the year ended December 31, 2017.

Note 8—Property, Plant and Equipment

A summary of our property, plant and equipment is as follows:

(amounts in millions)	December 31, 2017			December 31, 2016
Power generation	$	9,998		$	7,537
Buildings and improvements	955			944
Office and other equipment	115			98
Property, plant and equipment	11,068			8,579
Accumulated depreciation	(2,184		)	(1,458		)
Property, plant and equipment, net	$	8,884		$	7,121

The following table summarizes total interest costs incurred and interest capitalized related to costs of construction projects in process:

	Year Ended December 31,
(amounts in millions)	2017		2016		2015
Total interest costs incurred	$	576	$	556	$	487
Capitalized interest	$	2	$	10	$	12

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DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Impairments

During the years ended December 31, 2017, 2016 and 2015, we recognized the following impairments in our consolidated statements of operations (amounts in millions).

Facility	Fair Value		2017		2016		2015
Baldwin (1)	$	97	$	—	$	645	$	—
Stuart (2)	$	—	—		56		—
Newton FGD (3)	$	—	—		148		—
Killen (4)	$	—	20		—		—
Hennepin (1)	$	16	10		—		—
Havana (1)	$	37	89		—		—
Wood River (5)	$	—	—		—		74
Brayton Point (6)	$	86	—		—		25
Total PP&E Impairments			$	119	$	849	$	99
Inventory	$	—	14		—		—
Equity investment	$	173	—		9		—
Assets held-for-sale, including $9 of allocated goodwill	$	176	15		—		—
Total Impairments			$	148	$	858	$	99

_________________________________________

(1) Units failed to recover their basic operating costs in the MISO capacity auctions. The impairment was measured using a DCF model. As part of our impairment analysis, we changed the remaining useful lives of certain of our facilities.

(2) We determined that the facility would experience recurring negative cash flows due to on-going required maintenance and environmental capital expenditures, combined with consistently poor reliability. The impairment was measured using a DCF model.

(3) We terminated the flue gas desulfurization (“FGD”) systems construction project at our Newton generation facility. The impairment charge was equal to the capitalized cost of the project.

(4) In first quarter 2017, Dayton Power and Light Co., the partner and operator of Killen, announced the shutdown of the Killen generation facility by June 2018. As a result, the DCF model for the facility indicated negative cash flows, resulting in an impairment charge equal to its book value.

(5) Primarily attributable to its uneconomic operation stemming from a poorly designed wholesale capacity market and increased environmental costs. The impairment was measured using a DCF model.

(6) Temperate weather had a significant impact on the facility’s remaining cash flows, as the facility retired in May 2017. The impairment was measured using a DCF model.

Brayton Point Retirement

The Brayton Point facility officially retired on June 1, 2017. During the year ended December 31, 2017, we recognized approximately $12 million of severance costs, which were classified within Operating and maintenance expense in our consolidated statement of operations.

Note 9—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 the 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 consolidated statements of operations.

F-28

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

During 2017, in an effort to simplify structure and drive operating efficiencies, we acquired or exchanged ownership interests in certain of our jointly owned generating facilities. As a result, we now own 100 percent of Miami Fort and Zimmer and disposed of our full interest in Conesville. No ownership changes occurred related to the Stuart and Killen facilities, as they are scheduled to be retired mid-2018. The following tables present the ownership interests of the jointly owned facilities as of December 31, 2017 and 2016 included in our consolidated balance sheets. Each facility is co-owned with one or more other generation companies.

	December 31, 2017
(dollars in millions)	Ownership Interest		Property, Plant and Equipment		Accumulated Depreciation		Construction Work in Progress		Total
Stuart (1)(2)	39.0	%	$	1	$	—	$	—	$	1
Killen (1)(2)	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 (1)	39.0	%	$	—	$	—		$	4	$	4
Conesville (1)	40.0	%	$	61	$	(3	)	$	6	$	64
Zimmer	46.5	%	$	115	$	(25	)	$	6	$	96
Killen (1)	33.0	%	$	19	$	(2	)	$	3	$	20

__________________________________________

(1) Facilities not operated by Dynegy.

(2) Stuart Unit 1 was retired early on September 30, 2017, with remaining Stuart and Killen units scheduled to be retired by mid-2018.

On May 9, 2017, Dynegy finalized the sale of its 40 percent ownership interest in Conesville to American Electric Power (“AEP”) in exchange for AEP’s 25.4 percent ownership interest in Zimmer. As a result, Dynegy then owned 71.9 percent of the Zimmer facility and no longer had an ownership interest in the Conesville facility. No cash was exchanged in the transaction and no additional debt was incurred by either party. AEP returned a previously issued letter of credit totaling $58 million to Dynegy. The fair value of the additional Zimmer interest is $27 million and was allocated $14 million to Property, plant and equipment, $14 million to Inventory, and $1 million to ARO liability in our consolidated balance sheets. As a result of the Conesville sale, we recognized a loss of $31 million for the twelve months ended December 31, 2017, representing the difference between the $58 million book value of our transferred interest in Conesville and the $27 million fair value of the acquired interest in Zimmer.

On December 8, 2017, Dynegy finalized the purchase of AES Ohio Generation, LLC’s and The Dayton Power and Light Company’s (collectively, “AES”) 28.1 percent interest in Zimmer and 36 percent interest in Miami Fort for $70 million in cash for PP&E, Inventory, and the assumption of certain liabilities, subject to customary adjustments. Dynegy now owns 100 percent of Zimmer and Miami Fort, which are fully consolidated as of December 31, 2017.

The transactions above were accounted for as business combinations using similar fair value methodologies as described in Note 3—Acquisitions and Divestitures.

Note 10—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 December 31, 2017, our equity method investment in NELP included in our consolidated balance sheets was $123 million. Upon the acquisition, we recognized basis differences in the net assets of approximately $39 million primarily 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 year ended December 31, 2017, we recorded $8 million in equity earnings related to our investment in NELP which is reflected in Earnings from unconsolidated investments in our consolidated statements of operations. For the year ended December 31, 2017, we received distributions of $17 million, of which $12 million was considered to be a return of investment using the cumulative earnings approach and reflected as Distributions from unconsolidated investments in our consolidated

F-29

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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”). As a result, we recorded an impairment charge of $9 million to Impairments in our consolidated statements of operations for the year ended December 31, 2016, to write down our investment in Elwood to the sales price. For the years ended December 31, 2016 and 2015, we recorded $7 million and $1 million in equity earnings related to our investment in Elwood, which is reflected in Earnings from unconsolidated investments in our consolidated statements of operations. For the year ended December 31, 2016, we received distributions of $15 million, of which $14 million was considered to be a return of investment. For the year ended December 31, 2015, we received distributions of $11 million, of which $8 million was considered a return on investment. Both used the accumulated earnings approach and were reflected as Distributions from unconsolidated investments in our consolidated statements of cash flows.

Note 11—Intangible Assets and Liabilities

The following table summarizes the components of our intangible assets and liabilities as of December 31, 2017 and 2016:

	December 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	$	178		$	(131	)	$	47		$	260		$	(206	)	$	54
Gas transport contracts	30			(13		)	17			13			(6		)	7
Total intangible assets	$	208		$	(144	)	$	64		$	273		$	(212	)	$	61
Intangible Liabilities:
Electricity contracts	$	(11	)	$	7		$	(4	)	$	(28	)	$	26		$	(2	)
Coal contracts	—			—			—			(49		)	42			(7		)
Coal transport contracts	(48		)	44			(4		)	(86		)	73			(13		)
Gas transport contracts	(58		)	19			(39		)	(41		)	8			(33		)
Gas storage contracts	(2		)	1			(1		)	—			—			—
Total intangible liabilities	$	(119	)	$	71		$	(48	)	$	(204	)	$	149		$	(55	)
Intangible assets and liabilities, net	$	89		$	(73	)	$	16		$	69		$	(63	)	$	6

The following table presents our amortization expense (revenue) of intangible assets and liabilities for the years ended December 31, 2017, 2016 and 2015:

	Year Ended December 31,
(amounts in millions)	2017			2016			2015
Electricity contracts, net (1)	$	32		$	70		$	75
Coal contracts, net (2)	(5		)	(41		)	(60		)
Coal transport contracts, net (2)	(9		)	(27		)	(32		)
Gas transport contracts, net (2)	(5		)	19			6
Gas storage contracts, net (2)	(1		)	—			—
Total	$	12		$	21		$	(11	)

__________________________________________

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

(2) The amortization of these contracts is recognized in Cost of sales in our consolidated statements of operations.

Amortization expense (revenue), net for the next five years as of December 31, 2017 is as follows: 2018—$11 million, 2019—$17 million, 2020—$2 million, 2021—($3) million, and 2022—($4) million.

F-30

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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)	Gross Carrying Amount			Weighted-Average Amortization Period (months)
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

Note 12—Tangible Equity Units

In 2016, we issued 4.6 million, 7 percent tangible equity units (“TEUs”) at $100 per unit and received proceeds of $443 million, net of issuance costs of $17 million.

Each TEU is comprised of: (i) a prepaid SPC issued by Dynegy, and (ii) an amortizing note (“Amortizing Note”), with an initial principal amount of $18.95 that pays an equal quarterly cash installment of $1.75 per Amortizing Note on January 1, April 1, July 1, and October 1 of each year, with the exception of the first installment payment of $1.94 which was due on October 1, 2016. In the aggregate, the annual quarterly cash installments are equivalent to a 7 percent cash payment per year. Each installment cash payment constitutes a payment of interest and a partial repayment of principal. Each TEU may be separated by a holder into its constituent SPC and Amortizing Note after the initial issuance date of the TEUs, and the separate components may be combined to create a TEU after the initial issuance date, in accordance with the terms of the SPC. The TEUs are listed on the New York Stock Exchange under the symbol “DYNC”.

In 2016, we allocated the proceeds from the issuance of the TEUs, including other fees and expenses, to equity and debt based on the relative fair value of the respective components of each TEU as follows:

(in millions, except price per TEU)	SPC			Amortizing Note			Total
Price per TEU	$	81		$	19		$	100
Gross proceeds	$	373		$	87		$	460
Less: Issuance costs	(14		)	(3		)	(17		)
Net proceeds	$	359		$	84		$	443

The fair value of the SPCs was recorded as additional paid in capital, net of issuance costs. The fair value of the Amortizing Notes was recorded as debt, with deferred financing costs recorded as a reduction of the carrying amount of the debt in our consolidated balance sheet. Deferred financing costs related to the Amortizing Notes will be amortized through the maturity date using the effective interest rate method.

Unless settled early at the holder’s or Dynegy’s election or redeemed by Dynegy in connection with an acquisition termination redemption, on July 1, 2019, Dynegy will deliver to the SPC holders a number of shares of common stock based on the 20 day volume-weighted average price (“VWAP”) of our common stock, at a conversion price ranging from 5.0201 shares to 6.1996 shares.

In addition, on any business day during the period beginning on, and including, the business day immediately following the date of initial issuance of the TEUs to, but excluding, the third business day immediately preceding the mandatory settlement date, any holder of an SPC may settle any or all of its SPCs early, and Dynegy will deliver a number of shares of Common Stock equal to the minimum settlement rate.  Additionally, the SPCs may be redeemed in the event of a fundamental change or under an acquisition termination event, both as defined in the SPC.

F-31

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 13—Debt

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

(amounts in millions)	December 31, 2017			December 31, 2016
Secured Obligations:
Term Loan, due 2024	$	2,018		$	2,224
Revolving Facility	—			—
Forward Capacity Agreement	241			219
Inventory Financing Agreements	48			129
Subtotal secured obligations	2,307			2,572
Unsecured Obligations:
7.00% Amortizing Notes, due 2019 (TEUs)	53			80
6.75% Senior Notes, due 2019	850			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	188			—
8.00% Senior Notes, due 2025	750			750
8.125% Senior Notes, due 2026	850			—
Equipment Financing Agreements	132			97
Subtotal unsecured obligations	6,323			6,527
Total debt obligations	8,630			9,099
Unamortized debt discounts and issuance costs	(197		)	(120		)
	8,433			8,979
Less: Current maturities, including unamortized debt discounts and issuance costs, net	105			201
Total long-term debt	$	8,328		$	8,778

Certain of our debt instruments contain change of control provisions, which will not be triggered with the Merger with Vistra Energy. For further discussion of the Merger, see Note 1—Organization and Operations.

Aggregate maturities of the principal amounts of all indebtedness, excluding unamortized discounts, as of December 31, 2017 are as follows:

	(in millions)
2018	$	115
2019	971
2020	136
2021	59
2022	1,760
Thereafter	5,589
Total	$	8,630

F-32

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Credit Agreement

As of December 31, 2017, we had a $3.563 billion credit agreement, as amended, that consisted of (i) a $2.018 billion seven-year senior secured term loan facility (the “Term Loan”) and (ii) $1.545 billion in senior secured revolving credit facilities (the “Revolving Facility,” and collectively with the Term Loan, the “Credit Agreement”). During the year ended December 31, 2017, we made the following changes to the Credit Agreement:

• During 2017, we amended the Credit Agreement to increase the revolver capacity by $120 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 to (i) reduce the interest rate applicable to the Term Loan by 75 basis points and (ii) exchange our previous Term Loan for the current Term Loan. As a result of this exchange, we recorded a loss on early extinguishment of debt of approximately $7 million in our consolidated statements of operations in the first quarter of 2017, of which approximately $5 million was related to the write-off of unamortized deferred financing costs and approximately $2 million was related to the write-off of unamortized debt discount.

• On August 22, 2017, we repaid $200 million of our Term Loan. As a result of this transaction, we recorded a loss on early extinguishment of debt of approximately $8 million in our consolidated statements of operations for the year ended December 31, 2017, of which $6 million was related to the write-off of unamortized deferred financing costs and $2 million was related to the write-off of unamortized debt discount.

• On December 20, 2017, we amended the Credit Agreement to reduce interest rate margins applicable to the Term Loan from 2.25 percent to 1.75 percent with respect to base rate borrowings and from 3.25 percent to 2.75 percent with respect to LIBOR borrowings through an exchange. Additional reductions from 2.25 percent to 1.50 percent with respect to base rate borrowings and from 2.75 percent to 2.50 percent with respect to LIBOR borrowings are available to the Company based on certain corporate ratings or corporate family ratings from Moody’s and S&P. As a result of this exchange, we recorded a loss on early extinguishment of debt of approximately $6 million in our consolidated statements of operations in the fourth quarter of 2017, of which approximately $4 million was related to the write-off of unamortized deferred financing costs, approximately $1 million was related to the write-off of unamortized debt discount, and approximately $1 million related to fees.

At December 31, 2017, there were no amounts drawn on the Revolving Facility; however, we had outstanding letters of credit (“LCs”) of approximately $353 million, which reduce the amount available under the Revolving Facility. In the first quarter of 2017 there was $300 million drawn on the Revolving Facility, and subsequently fully repaid in the fourth quarter of 2017. The Credit Agreement contains customary events of default and affirmative and negative covenants, subject to certain specified exceptions, including a 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. Based on the calculation outlined in the Credit Agreement, we were in compliance with these covenants as of December 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 Consolidated Senior Secured Net Debt, as defined in the Credit Agreement.

Interest Rate Swaps. In March 2017, we amended our existing interest rate swaps to more closely match the terms of our Term Loan. The swaps have an aggregate notional value of approximately $761 million at an average fixed rate of 3.03 percent and expire between the second quarter of 2018 and the second quarter of 2020. In a previous extension to the existing interest rate swaps, 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 consolidated statements of cash flows.

Additionally, in May 2017, we entered into new interest rate swap agreements. The swaps have an aggregate notional value of approximately $1.2 billion at an average fixed rate of 1.97 percent and expire in the first quarter of 2024. Any cash flows related to the settlement of these swaps are reflected as an operating activity in our consolidated statements of cash flows.

Senior Notes

The senior notes are unsecured and unsubordinated obligations of the Company and are guaranteed by each of the Company’s current and future wholly-owned domestic subsidiaries that from time to time are a borrower or guarantor under the Credit Agreement. The senior notes indentures limit, among other things, the ability of the Company or any of the guarantors to

F-33

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

create liens upon any principal property to secure debt for borrowed money in excess of, among other limitations, 30 percent of total assets.

As a result of Genco’s emergence from bankruptcy, we issued $188 million of new seven-year unsecured notes as partial consideration in exchange for Genco’s existing senior notes. Please read Note 20—Genco Chapter 11 Bankruptcy for further discussion.

On August 21, 2017, we issued $850 million of 8.125 percent senior notes due 2026 (the “2026 Senior Notes”) in a private placement transaction. Interest is payable semiannually in arrears on January 30 and July 30 of each year, beginning January 30, 2018. Dynegy used the proceeds of the offering, together with proceeds from the sale of certain facilities, and cash-on-hand to repurchase $1.25 billion of its 6.75 percent senior notes due 2019 and repay $200 million of its Term Loan, as noted above.

In connection with the extinguishment of a portion of our 2019 senior notes, we recorded a loss on early extinguishment of debt of approximately $58 million in our consolidated statements of operations for the year ended December 31, 2017, of which approximately $44 million related to a premium paid in excess of debt principal, approximately $8 million related to the write-off of unamortized deferred financing costs, and approximately $6 million related to fees. The Company, pursuant to a Registration Rights Agreement, has agreed to use commercially reasonable efforts to register the 2026 Senior Notes by August 16, 2018. Otherwise, the 2026 Senior Notes are generally identical in all material respects to Dynegy’s other outstanding senior notes.

Amortizing Notes

On June 21, 2016, in connection with the issuance of the 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. Please read Note 12—Tangible Equity Units for further discussion.

Letter of Credit Facilities

Dynegy has a Letter of Credit Reimbursement Agreement with an issuing bank, for an LC in an amount not to exceed $55 million. In July 2017, the expiry date of the facility was extended one year, to September 19, 2018. At December 31, 2017, there was $55 million of 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. At December 31, 2017, there was $30 million of LCs outstanding under this facility. The facility matured February 7, 2018 and the LCs under this facility have since been transferred to under the Dynegy revolver.

Forward Capacity Agreement

As of December 31, 2017, we have sold a portion of our PJM capacity that cleared for Planning Years 2018-2019, 2019-2020 and 2020-2021 to a financial institution. Dynegy will continue to be subject to the performance obligations as well as any associated performance penalties and bonus payments for those planning years. As a result, this transaction is accounted for as a debt issuance of $241 million with an implied interest rate of 4.9 percent. On March 29, 2017, we replaced an existing Planning Year 2017-2018 contract in the amount of $110 million, with a Planning Year 2019-2020 contract in the amount of $121 million. On July 7, 2017, we replaced $99 million of $109 million of an existing Planning Year 2018-2019 contract with a Planning Year 2020-2021 contract in the amount of $110 million.

Inventory Financing Agreements

Brayton Point Inventory Financing. In connection with the EquiPower Acquisition, we assumed an inventory financing agreement (the “Inventory Financing Agreement”) for coal and fuel oil inventories at our Brayton Point facility, 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. On May 31, 2017, the Brayton Point inventory financing agreement terminated and the remaining obligation was paid. The Brayton Point facility officially retired on June 1, 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 December 31, 2017, there was $48 million, in aggregate, outstanding under these agreements. In February 2018, we repaid all amounts outstanding under these agreements.

F-34

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 2019 to 2026. 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 consolidated statements of cash flows. The related assets were recorded at the net present value of the payments of $97 million. The $35 million discount is currently being amortized as interest expense over the life of the payments.

Note 14—Income Taxes

We are subject to U.S. federal and state income taxes on our operations.

Tax Reform Act.

On December 22, 2017, the President of the United States signed into law the Tax Cuts and Jobs Act (“TCJA”). Substantially all of the provisions of the TCJA are effective for taxable years beginning after December 31, 2017. The TCJA includes significant changes to the Internal Revenue Code of 1986, as amended (“the Code”), including amendments which significantly change the taxation of business entities. The more significant changes in the TCJA that impact Dynegy are:

• reductions in the corporate federal income tax rate from 35 percent to 21 percent,

• repeal of the corporate Alternative Minimum Tax (“AMT”) providing for refunds of excess AMT credits,

• limiting the utilization of Net Operating Losses (“NOLs”) arising after December 31, 2017 to 80 percent of taxable income with an indefinite carryforward (existing NOLs can continue to be utilized at 100 percent of taxable income with a 20-year carryforward), and

• limiting the deduction of net business interest expense to 30 percent of adjusted taxable income as defined in the TCJA.

As a result of the reduction in the U.S. federal corporate tax rate, Dynegy has recorded a $394 million reduction to our net deferred tax assets, including the federal benefit of state deferred taxes, which was fully offset by a decrease in our valuation allowance for the year ended December 31, 2017. Additionally, we have recorded a $223 million current tax benefit and long term tax receivable in 2017 related to the expected refund of our existing AMT credits.

In accordance with Staff Accounting Bulletin 118, the amounts recorded in the fourth quarter of 2017 related to the TCJA represent reasonable estimates based on our analysis to date and are considered to be provisional and subject to revision during 2018.  Provisional amounts were recorded for the re-measurement of our 2017 U.S. deferred taxes and ancillary state tax effects.  These amounts are considered to be provisional as we continue to assess available tax methods and elections and refine our computations.  Additionally, further regulatory guidance related to the TCJA is expected to be issued in 2018 which may result in changes to our current estimates.

Our losses from continuing operations before income taxes were $538 million, $1.289 billion and $427 million for the years ended December 31, 2017, 2016 and 2015, respectively, which were solely from domestic sources.

Our components of income tax benefit related to losses from continuing operations were as follows:

	Year Ended December 31,
(amounts in millions)	2017		2016		2015
Current tax benefit (expense)	$	233	$	15	$	(3	)
Deferred tax benefit	377		30		477
Income tax benefit	$	610	$	45	$	474

F-35

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Our income tax benefit related to losses from continuing operations before income taxes for each of the years ended December 31, 2017, 2016 and 2015 were equivalent to effective rates of 113 percent, 3 percent, and 111 percent, respectively. Differences between taxes computed at the U.S. federal statutory rate and our reported income tax benefit were as follows:

	Year Ended December 31,
(amounts in millions)	2017			2016			2015
Expected tax benefit at U.S. statutory rate (35%)	$	189		$	451		$	149
State taxes	35			16			68
Permanent differences (1)	(21		)	(4		)	16
Non-deductible goodwill	(10		)	—			—
Valuation allowance (2)(3)	879			(404		)	271
NOL adjustments from use limitations	(13		)	(17		)	—
Adjustment to AMT credits	(17		)	—			(26		)
Change in federal tax rate as included in TCJA	(429		)	—			—
Other	(3		)	3			(4		)
Income tax benefit	$	610		$	45		$	474

__________________________________________

(1) Permanent items for years ended December 31, 2017, 2016 and 2015 included a benefit of less than $1 million, a benefit of $2 million, and a benefit of $18 million, respectively, for the change in the fair value of warrants during the year that were not deductible for income taxes. Income tax benefit for the years ended December 31, 2017 and 2016 includes $8 million and $5 million, respectively, of income tax expense for non-deductible fees related to the Genco Plan. Please read Note 20—Genco Chapter 11 Bankruptcy for further discussion. Income tax benefit for the year ended December 31, 2017, includes $22 million for non-deductible legal fees related to the ENGIE Acquisition.

(2) The EquiPower Acquisition on April 1, 2015 caused a change in the attributes and impacted our estimate of the realizability of our deferred tax assets. As a result, we recorded a $453 million reduction to our valuation allowance in 2015 and $3 million in 2016.

(3) The ENGIE Acquisition on February 7, 2017 caused a change in the attributes and impacted our estimate of the realizability of our deferred tax assets. As a result, we recorded a $354 million reduction to our valuation allowance in 2017. We also recorded a benefit for the repeal of the corporate AMT in the amount of $223 million as included in the TCJA.

F-36

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Deferred Tax Liabilities and Assets.  Our significant components of deferred tax assets and liabilities were as follows:

	Year Ended December 31,
(amounts in millions)	2017			2016
Non-current deferred tax assets:
NOL carryforwards	$	1,195		$	1,629
AMT, state, and other tax credit carryforwards	25			241
Reserves (legal, environmental and other)	4			7
Pension and other post-employment benefits	11			18
Asset retirement obligations	68			85
Deferred financing costs and intangible/other contracts	22			48
Derivative contracts	69			57
Other	29			46
Subtotal	1,423			2,131
Less: valuation allowance	(852		)	(1,704		)
Total non-current deferred tax assets	$	571		$	427
Non-current deferred tax liabilities:
Depreciation and other property differences	$	(560	)	$	(371	)
Derivative contracts	(7		)	(44		)
Other	(11		)	(17		)
Total non-current deferred tax liabilities	$	(578	)	$	(432	)
Net non-current deferred tax liabilities	$	(7	)	$	(5	)

NOL Carryforwards.  As of December 31, 2017, we had approximately $4.6 billion of NOLs and $3.6 billion of state NOLs that can be used to offset future taxable income. The federal NOLs expire beginning in 2024 through 2037. Similarly, the state NOLs will expire at various dates (based on the company’s review of the application of apportionment factors and other state tax limitations). Under federal income tax law, our NOLs can be utilized to reduce future taxable income subject to certain limitations, including if we were to undergo an ownership change as defined by Internal Revenue Code (“IRC”) Section 382. If an ownership change were to occur as a result of future transactions in our stock, our ability to utilize the NOLs may be significantly limited.

Alternative Minimum Tax Credit Carryforwards. For the years ended December 31, 2017 and 2016, the Company elected to accelerate the minimum tax credit in lieu of claiming the bonus depreciation allowance, resulting in a current Income tax benefit of $18 million and $16 million, respectively. Dynegy has recorded a $223 million tax benefit in 2017 related to the expected refund of its existing AMT Credits as provided for in the TCJA.

Change in Valuation Allowance.  Realization of our deferred tax assets is dependent upon, among other things, our ability to generate taxable income of the appropriate character in the future. At December 31, 2017 and 2016, we have a valuation allowance against our net deferred assets including federal and state NOLs and AMT credit carryforwards. Additionally, at December 31, 2017 and 2016, our temporary differences were in a net deferred tax asset position. We do not believe we will produce sufficient future taxable income, nor are there tax planning strategies available, to realize the tax benefits of our net deferred tax asset associated with temporary differences. Accordingly, we have recorded a full valuation allowance against the net asset temporary differences related to federal income tax and the net asset temporary differences related to most state income tax as appropriate.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The changes in the valuation allowance were as follows:

	Year Ended December 31,
	2017			2016		2015
Beginning of period	$	1,704		$	1,276	$	1,535
Changes in valuation allowance—continuing operations:
Charged to costs and expenses	(854		)	428		(259		)
Charged to other accounts	2			—		—
End of period	$	852		$	1,704	$	1,276

Unrecognized Tax Benefits. We are complete with federal income tax audits by the Internal Revenue Service (“IRS”) through 2015 as a result of our participation in the IRS’ Compliance Assurance Process. However, any NOLs we claim in future years to reduce taxable income could be subject to additional IRS examination regardless of when the NOLs occurred. We are generally not subject to examinations for state and local taxes for tax years 2013 or earlier with few exceptions.

A reconciliation of our beginning and ending amounts of unrecognized tax benefits were as follows:

	Year Ended December 31,
amounts in millions	2017			2016		2015
Unrecognized tax benefits, beginning of period	$	3		$	3	$	4
Increase due to ENGIE acquisition	63			—		—
Decrease due to rate changes	(26		)	—		—
Decrease due to settlements and payments	—			—		(1		)
Unrecognized tax benefits, end of period	$	40		$	3	$	3

As of December 31, 2017, approximately $3 million of unrecognized tax benefits would impact our effective tax rate if recognized.

Note 15—Stockholders’ Equity

Preferred Stock

We have authorized preferred stock consisting of 20 million shares, $0.01 par value. Our preferred stock may be issued from time to time in one or more series, the shares of each series to have such designations and powers, preferences, rights, qualifications, limitations and restrictions thereof as specified by our Board of Directors. Our 4 million shares of Series A Mandatory Convertible Preferred Stock converted on November 1, 2017, into approximately 12.9 million shares of our common stock, whereupon we reclassified the balance of Preferred Stock to Additional paid-in-capital.

Stock Purchase Agreement-Terawatt

On February 24, 2016, Dynegy entered into a Stock Purchase Agreement with Terawatt Holdings, LP (“Terawatt”), an affiliate of the investment funds of ECP, pursuant to which, at the ENGIE Acquisition Closing Date, Dynegy issued to Terawatt 13,711,152 shares of Dynegy common stock for $150 million (the “PIPE Transaction”).

ECP Buyout

Dynegy settled its payment obligation to ECP of $375 million on the ENGIE Acquisition Closing Date. This payment is recorded as a reduction in additional paid-in capital in our consolidated balance sheet and is reflected as a purchase of a noncontrolling interest in financing activities in our consolidated statement of cash flows as of December 31, 2017.

TEUs

On June 21, 2016, pursuant to a registered public offering, we issued 4.6 million, 7 percent TEUs at $100 per unit. Each TEU was comprised of a prepaid stock purchase contract and an amortizing note which were accounted for as separate instruments. Please read Note 12—Tangible Equity Units for further discussion.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Common Stock

Upon our emergence from bankruptcy on October 1, 2012 (the “Plan Effective Date”), we authorized 420 million shares of common stock, $0.01 par value per share, of which 11,326,122 shares are currently held in treasury. The following table reflects balances and activity in our outstanding shares of common stock, for the years ended December 31, 2017, 2016 and 2015:

	Shares outstanding balance as of December 31,
(in millions)	2017	2016	2015
Shares outstanding at the beginning of the period	117	117	124
Shares issued under the PIPE Transaction	14	—	—
Shares issued as consideration for the EquiPower Acquisition	—	—	3
Shares repurchases (in treasury)	—	—	(11	)
Shares issued from conversion of preferred stock	13	—	—
Shares issued under long-term compensation plans	—	—	1
Shares outstanding at the end of period	144	117	117

Warrants. As of the Plan Effective Date, we issued to then-existing stockholders warrants to purchase up to 15.6 million shares of common stock for an exercise price of $40 per share (the “2012 Warrants”). The 2012 Warrants expired on October 2, 2017.

During 2017, we issued 9.0 million warrants (the “2017 Warrants”), each of which entitles the holder to purchase one share of Dynegy common stock, to eligible holders of Genco senior notes as a result of the Genco Chapter 11 Bankruptcy. The 2017 Warrants have an exercise price of $35 per share of common stock and a seven-year term expiring on February 2, 2024. The warrants are recorded as Other long-term liabilities in our consolidated balance sheet and are adjusted to their estimated fair value at the end of each reporting period with the change in fair value recognized in Other income (expense) in our consolidated statement of operations. Please read Note 20—Genco Chapter 11 Bankruptcy and Note 4—Risk Management Activities, Derivatives and Financial Instruments for further discussion.

Stock Award Plans

We have one stock award plan, the Dynegy Amended and Restated 2012 Long Term Incentive Plan (the “ LTIP”), which provides for the issuance of authorized shares of our common stock. Restricted Stock Units (“RSUs”), Performance Stock Units (“PSUs”) and option grants have been issued under the LTIP. The LTIP is a broad-based plan and provides for the issuance of approximately 3.2 million authorized shares through May 2026.

All options granted under the LTIP cease vesting for employees who are terminated with cause. For severance-eligible terminations, as defined under the severance pay plan, disability, retirement or death, immediate or continued vesting and/or an extended period in which to exercise vested options may apply, dependent upon the terms of the grant agreement applying to a specific grant that was awarded. Shares of common stock are issued upon exercise of stock options from previously unissued shares. Any options granted under the LTIP will expire no later than 10 years from the date of the grant.

All RSUs granted under the LTIP contain a service condition and cease vesting for employees or directors who are terminated with cause. For severance-eligible employee terminations, as defined under the severance pay plan, director terminations without cause, employee or director disability, retirement or death, immediate vesting of some or all of the RSUs may apply, dependent upon the terms of the grant agreement applying to a specific grant that was awarded. Shares of common stock are issued upon vesting of RSUs from previously unissued shares, with the exception of 2.5 million and 1.5 million shares of RSU’s granted in 2017 and 2016, respectively, to be settled in cash. As these awards must be settled in cash, we account for them as liabilities, with changes in the fair value of the liability recognized as expense in our consolidated statements of operations. We paid $3 million in cash for 0.4 million of the RSU’s accounted for as liabilities that vested during the year ended December 31, 2017.

All PSUs granted under the LTIP contain a performance condition and cease vesting for employees who do not remain continuously employed during the performance period under the grant agreements. For severance-eligible terminations, as defined under the severance pay plan, disability, retirement or death, immediate vesting of some or all of the PSUs may apply, dependent upon the terms of the grant agreement applying to a specific grant that was awarded. Upon a corporate change, employees receive an immediate vesting of PSUs regardless of whether the employee is terminated.

We use the fair value based method of accounting for stock-based employee compensation. We estimate forfeiture rates based on our actual forfeitures. Compensation expense related to options, RSUs and PSUs granted totaled $44 million, $31 million

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

and $28 million for the years ended December 31, 2017, 2016 and 2015, respectively. We recognize compensation expense ratably over the vesting period of the respective awards. Tax benefits for compensation expense related to options, RSUs and PSUs granted totaled $15 million, $11 million and $10 million for the years ended December 31, 2017, 2016 and 2015, respectively. As of December 31, 2017, $31 million of total unrecognized compensation expense related to options, RSUs and PSUs granted is expected to be recognized over a weighted-average period of 1.43 years. The total fair value of options, RSUs and PSUs vested was $26 million, $27 million and $18 million for the years ended December 31, 2017, 2016 and 2015, respectively. We did not capitalize any share-based compensation in the years ended December 31, 2017, 2016 and 2015. We settled 0.1 million RSUs related to severances and retirements for $1 million in cash for the year ended December 31, 2017. We did not settle any share-based compensation for cash in the years ended December 31, 2016 and 2015.

No options were exercised for the years ended December 31, 2017 and 2016. Cash received from option exercises was $0.5 million and the tax benefit realized for the additional tax deduction from share-based payment awards totaled less than $1 million for the year ended December 31, 2015.

The following summarizes our stock option activity:

	Year Ended December 31, 2017
	Options (in thousands)		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (in years)	Aggregate Intrinsic Value (amounts in millions)
Outstanding at beginning of period	2,805		$	18.69
Granted	1,454		$	8.02
Forfeited	(10	)	$	27.24
Expired	(42	)	$	21.79
Outstanding at end of period	4,207		$	14.95	7.65	$	6.4
Vested and unvested expected to vest	4,207		$	14.95	7.65	$	6.4
Exercisable at end of period	2,023		$	20.02	6.40	$	0.5

During the years ended December 31, 2017, 2016 and 2015, we did not grant any options at an exercise price less than the market price on the date of grant. The weighted average exercise price of options granted during the years ended December 31, 2016 and 2015 was $11.05 and $27.43, respectively. The intrinsic value of options exercised during the years ended December 31, 2016 and 2015 was less than $1 million.

For stock options, we determine the fair value of each stock option at the grant date using a Black-Scholes model, with the following weighted-average assumptions used for grants:

	Year Ended December 31,
	2017			2016			2015
Dividend Yield	$	—		$	—		$	—
Expected volatility (1)	48.50		%	41.19		%	27.70		%
Risk-free interest rate (2)	2.07		%	1.42		%	1.64		%
Expected option life (3)	5.5 years			5.5 years			5.5 years
Weighted average grant-date fair value	$	3.71		$	4.37		$	7.93

__________________________________________

(1) For the years ended December 31, 2017, 2016 and 2015, the expected volatility was calculated based on the historical volatilities of our stock since October 3, 2012.

(2) The risk-free interest rate was calculated based upon observed interest rates appropriate for the term of our employee stock options.

(3) Currently, we calculate the expected option life using the simplified methodology suggested by authoritative guidance issued by the SEC.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following summarizes our RSU activity:

	Year Ended December 31, 2017
	RSUs (in thousands)		Weighted Average Grant Date Fair Value
Outstanding at beginning of period	2,717		$	16.11
Granted	3,177		$	7.99
Vested and released	(1,241	)	$	19.04
Forfeited	(107	)	$	11.08
Outstanding at end of period	4,546		$	9.75

For RSUs, we consider the fair value to be the closing price of the stock on the grant date. The weighted average grant date fair value of RSUs granted during the years ended December 31, 2016 and 2015 was $11.20 and $28.93, respectively. We recognize the fair value of our share-based payments over the vesting periods of the awards, which is typically a three-year service period.

The following summarizes our PSU activity:

	Year Ended December 31, 2017
	PSUs (in thousands)		Weighted Average Grant Date Fair Value
Outstanding at beginning of period	1,221		$	16.48
Granted	583		$	8.02
Vested and released	(3	)	$	26.66
Forfeited	(186	)	$	23.10
Outstanding at end of period	1,615		$	12.65

The weighted average grant date fair value of PSUs granted during the years ended December 31, 2016 and 2015 was $16.48 and $27.54.

For PSUs granted prior to 2016, the fair value is determined using total shareholder return (“TSR”), measured over a three-year period relative to a selected group of energy industry peer companies, using a Monte Carlo model. The key characteristics of the PSUs are as follows:

• Three-year performance period;

• Payout opportunity of 0-200 percent of target (100 percent), intended to be settled in shares;

• Cumulative TSR percentile ranking calculated at end of performance period and applied to the payout scale to determine the number of earned/vested PSUs; and

• If absolute TSR is negative, PSU award payouts will be capped at 100 percent of the target number of PSUs granted, regardless of relative TSR positioning.

For PSUs granted in and subsequent to 2016, the fair value is determined using TSR for one-half of the award and the other half using pre-determined adjusted free cash flow (“FCF”) thresholds based upon the three year performance period. The FCF payout opportunity is also 0-200 percent of target (100 percent) intended to be settled in shares. These PSUs have the same key characteristics as described above.

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 12—Tangible Equity Units for further discussion.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table reflects the significant components of our weighted average shares outstanding used in the basic and diluted loss per share calculations for the years ended December 31, 2017, 2016 and 2015:

	Year Ended December 31,
(in millions, except per share amounts)	2017	2016	2015
Shares outstanding at the beginning of the period	140	117	124
Weighted-average shares during the period of:
Shares issuances	13	—	4
Shares converted from preferred stock	2	—	—
Shares repurchases	—	—	(3	)
Prepaid stock purchase contract (TEUs) (1)	—	12	—
Basic weighted-average shares	155	129	125
Dilution from potentially dilutive shares (2)	7	—	1
Diluted weighted-average shares (3)	162	129	126

_________________________________________

(1) The minimum settlement amount, or 23.1 million shares, are considered to be outstanding since June 21, 2016, and are included in the computation of basic earnings (loss) per share. Please read Note 12—Tangible Equity Units for further discussion.

(2) Shares included in the computation of diluted earnings per share for the year ended December 31, 2017 consist of:

• 5.4 million 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 (28.5 million shares); and

• 1.9 million additional shares attributable to restricted stock units and performance stock units.

(3) 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 year ended December 31, 2016.

For the years ended December 31, 2017, 2016 and 2015, the following potentially dilutive securities were not included in the computation of diluted per share amounts because the effect would be anti-dilutive:

	Year Ended December 31,
(in millions of shares)	2017	2016	2015
Stock options	2.8	2.8	0.5
Restricted stock units	—	1.3	—
Performance stock units	—	1.2	—
Warrants (1)	9.0	15.6	15.6
Series A 5.375% mandatory convertible preferred stock (2)	—	12.9	12.9
TEUs	—	5.4	—
Total	11.8	39.2	29.0

_________________________________________

(1) During 2017, we issued 9.0 million warrants to eligible holders of Genco senior notes as a result of the Genco Chapter 11 Bankruptcy. Warrants to purchase 15.6 million shares of our Common Stock expired on October 2, 2017.

(2) On November 1, 2017, our outstanding Preferred Stock was converted to approximately 12.9 million shares of Common Stock.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Accumulated Other Comprehensive Income

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

	Year Ended December 31,
(amounts in millions)	2017			2016			2015
Beginning of period	$	21		$	19		$	20
Other comprehensive income before reclassifications:
Actuarial gain and plan amendments (net of tax of $5, $3, and zero, respectively)	19			2			3
Amounts reclassified from accumulated other comprehensive income:
Settlement cost (net of tax of zero) (1)	—			5			—
Amortization of unrecognized prior service credit and actuarial gain (net of tax of zero, zero, and zero, respectively) (2)	(8		)	(5		)	(4		)
Net current period other comprehensive income (loss), net of tax	11			2			(1		)
End of period	$	32		$	21		$	19

__________________________________________

(1) Amount is related to the EEI other post-employment benefit plan settlement cost and was recorded in Operating and maintenance expense in our consolidated statements of operations. Please read Note 17—Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans for further discussion.

(2) Amounts are associated with our defined benefit pension and other post-employment benefit plans and are included in the computation of net periodic pension cost. Please read Note 17—Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans for further discussion.

Note 16—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 will be subject to an interlocutory appeal granted by the Ninth Circuit on June 13, 2017.  At this time we cannot reasonably estimate a potential loss.

Advatech Dispute. On September 2, 2016, our Genco subsidiary terminated its Second Amended and Restated Newton FGD 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 16, 2017. Settlement discussions required under the dispute resolution process have been unsuccessful. We believe the risk of a material loss related to this dispute to be remote. We dispute the allegations and will defend our position vigorously.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Vistra Merger Stockholder Litigation. On January 4, 2018, a putative class action complaint was filed in the United States District Court for the Southern District of Texas against Dynegy, Dynegy’s individual Board members, and Vistra Energy alleging that the December 13, 2017 S-4 Registration Statement related to the Merger “omits material information with respect to the Merger, which renders the Registration Statement false and misleading.”  Two additional lawsuits have been filed in Texas and Delaware making nearly identical allegations but excluding Vistra as a defendant. We dispute the allegations and will defend our position vigorously.

Wood River Rail Dispute. On November 30, 2017, Dynegy Midwest Generation, LLC (“DMG”) received notification that BNSF Railway Company and Norfolk Southern Railway Company were initiating dispute resolution related to DMG’s suspension of its Wood River Rail Transportation Agreement with the railroads. The parties are attempting to negotiate a resolution per the mandatory terms of the dispute resolution provision of the agreement. If the parties are unable negotiate a resolution, the railroads can initiate an arbitration to resolve the dispute. At this time, we view the likelihood of material loss as remote and dispute the railroads’ allegations and, if arbitration ensues, will defend our position vigorously.

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. Dynegy is participating in the investigation. We believe the risk of a material loss related to the investigation to be remote.

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.

Zimmer NOVs. In December 2014, the EPA issued an NOV alleging violation of opacity standards at the Zimmer facility. The EPA previously had issued NOVs to Zimmer in 2008 and 2010 alleging violations of the CAA, the Ohio State Implementation Plan, and the station’s air permits involving standards applicable to opacity, sulfur dioxide, sulfuric acid mist, and heat input. The NOVs remain unresolved. We are unable to predict the outcome of these matters.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Killen and Stuart NOVs. The EPA issued NOVs in December 2014 for Killen and Stuart, and in February 2017 for Stuart, alleging violations of opacity standards. In May and June 2017, we received two letters from the Sierra Club providing notice of its intent to sue various Dynegy entities and the owner and operator of the Killen and Stuart facilities, respectively, alleging violations of opacity standards under the CAA. The Dayton Power and Light Company, the operator of Killen and Stuart, is expected to act on behalf of itself and the co-owners with respect to these matters. We are unable to predict the outcome of these matters.

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 MISO 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 March 2019. 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.

Coal Combustion Residuals/ Groundwater.

MISO Segment. In 2012, the Illinois EPA (“IEPA”) issued violation notices alleging violations of groundwater standards onsite at our Baldwin and Vermilion facilities’ Coal Combustion Residuals (“CCR”) surface impoundments. 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 those closure plans.

At our retired Vermilion facility, which is not subject to the CCR rule, we submitted proposed corrective action plans involving closure of two CCR surface impoundments (i.e., the old east and the north impoundments) to the IEPA in 2012, with revised plans submitted in 2014. In May 2017, in response to a request from the IEPA for additional information regarding the closure of these Vermilion surface impoundments, we agreed to perform additional groundwater sampling and closure options and riverbank stabilizing options. By letter dated January 31, 2018, Prairie Rivers Network provided 60-day notice of its intent to sue our subsidiary Dynegy Midwest Generation, LLC under the federal Clean Water Act for alleged unauthorized discharges from the surface impoundments at our Vermilion facility and alleged related violations of the facility’s NPDES permit. We dispute the allegations and will vigorously defend our position.

In 2012, the IEPA issued violation notices alleging violations of groundwater standards at the Newton and Coffeen facilities’ CCR surface impoundments. We are addressing these CCR surface impoundments in accordance with the CCR rule.

If remediation measures concerning groundwater are necessary at any of our coal-fired MISO Segment facilities, we may incur significant costs that could have a material adverse effect on our financial condition, results of operations, and cash flows. At this time we cannot reasonably estimate the costs, or range of costs, of remediation, if any, that ultimately may be required. CCR surface impoundment and landfill closure costs are 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. The following describes the significant commitments outstanding at December 31, 2017.

Coal Purchase Commitments. At December 31, 2017, we had contracts in place to purchase coal for our generation facilities with aggregate minimum commitments of $802 million. To the extent purchased or committed volumes have not been priced but are subject to a price collar structure, the obligations have been calculated using the minimum purchase price of the collar.

Coal Transportation. At December 31, 2017, we had coal transportation contracts and rail car leases in place for our generation facilities with aggregate minimum commitments of $837 million.

Contractual Service Agreements.  Contractual service agreements represent obligations with respect to long-term plant maintenance agreements. In prior periods, we have undertaken several measures to restructure some of our existing maintenance service agreements with our turbine service providers. As of December 31, 2017, our obligation with respect to these restructured agreements is limited to the termination payments, which are approximately $707 million in the event all contracts are terminated by us.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

In addition, we have committed to securing capital spares and turbine uprates for our gas-fueled generation fleet to help minimize production disturbances, improve efficiency, and increase generation. As of December 31, 2017, we have obligations to purchase spare parts and turbine uprates of $112 million with payments made through 2026, of which $103 million reflects spare parts received and upgrades completed. Upon the receipt of the parts and transfer of title to Dynegy, we recognize the asset and the associated payment obligation at the NPV of those payments, which we record to PP&E and Debt in our consolidated balance sheets.

Gas Purchase Commitments. At December 31, 2017, we had contracts in place to purchase gas for our generation facilities with aggregate minimum commitments of $212 million.

Gas Transportation. At December 31, 2017, we had firm capacity payment obligations related to transportation of natural gas. Such arrangements are routinely used in the physical movement and storage of energy. The total of such obligations was $183 million.

Operating Leases.

Office Space, Equipment and Other Property. Minimum lease payment obligations, by year, associated with office space, equipment, land and other leases per year for the years 2018-2022 are as follows:

	(in millions)
2018	$	6
2019	$	5
2020	$	5
2021	$	5
2022	$	4

During the years ended December 31, 2017, 2016 and 2015, we recognized rental expense of approximately $5 million, $5 million and $5 million, respectively.

Other Obligations. We have other obligations of $25 million for contracts in place to purchase limestone and ash, $17 million for interconnection services, $23 million for water services and $23 million for other miscellaneous items which are individually insignificant.

Indemnifications and Guarantees

In the ordinary course of business, we routinely enter into contractual agreements that contain various representations, warranties, indemnifications and guarantees.  Examples of such agreements include, but are not limited to, service agreements, equipment purchase agreements, engineering and technical service agreements, asset sales agreements, and procurement and construction contracts.  Some agreements contain indemnities that cover the other party’s negligence or limit the other party’s liability with respect to third party claims, in which event we will effectively be indemnifying the other party.  Virtually all such agreements contain representations or warranties that are covered by indemnifications against the losses incurred by the other parties in the event such representations and warranties are false.  While there is always the possibility of a loss related to such representations, warranties, indemnifications, and guarantees in our contractual agreements, and such loss could be significant, in most cases management considers the probability of loss to be remote.  We have accrued no amounts with respect to the indemnifications as of December 31, 2017 because none were probable of occurring, nor could they be reasonably estimated.

Note 17—Employee Compensation, Savings, 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. During the years ended December 31, 2017, 2016 and 2015, our contributions related to these plans were approximately $63 million, $43 million and $50 million, respectively. The following summarizes these plans:

Short-Term Incentive Plan.  Dynegy maintains a discretionary incentive compensation plan to provide our employees with rewards for the achievement of corporate goals and individual, professional accomplishments. Specific awards are determined by Dynegy’s Compensation and Human Resources Committee of the Board of Directors and are based on predetermined goals and objectives established at the start of each performance year.

Dynegy Inc. 401(k) Savings Plans.  For the years ended December 31, 2017, 2016 and 2015, our employees participated in several 401(k) savings plans, all of which meet the requirements of IRC Section 401(k) and are defined contribution plans subject to the provisions of the Employee Retirement Income Security Act. Effective January 1, 2016, all of these plans, except

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

for the Brayton Point Energy LLC 401k Plan for Bargaining Employees, were merged into the Dynegy 401(k) Plan and employees who participate in these plans became eligible to participate in the Dynegy 401(k) Plan. The following summarizes the plan:

• Dynegy 401(k) Plan.  This plan and the related trust fund are established and maintained for the exclusive benefit of participating employees in the U.S. Generally, all employees of designated Dynegy subsidiaries are eligible to participate in this plan. Except for certain represented employees, employee pre-tax and Roth contributions to the plan are matched by the Company at 100 percent, up to a maximum of five percent of base pay (subject to IRS limitations) and vesting in company contributions is based on years of service with 50 percent vesting per full year of service. This plan also allows for a discretionary contribution to eligible employee accounts for each plan year, subject to the sole discretion of the Compensation and Human Resources Committee of the Board of Directors. No discretionary contributions were made for any of the years in the three-year period ended December 31, 2017.

During the years ended December 31, 2017, 2016 and 2015, we recognized aggregate costs related to our 401(k) Plans of $13 million, $15 million and $10 million, respectively.

Pension and Other Post-Employment Benefits

We have various defined benefit pension plans and post-employment benefit plans. Generally, all employees participate in the pension plans (subject to plan eligibility requirements), but only some of our employees participate in the other post-employment medical and life insurance benefit plans. The pension plans are in the form of cash balance plans and more traditional career average or final average pay formula plans. Separately, our EEI employees and retirees participate in EEI’s single-employer pension and other post-employment plans. We consolidate EEI, and therefore, EEI’s plans are reflected in our pension and post-employment balances and disclosures. Dynegy and EEI both use a measurement date of December 31 for their pension and post-employment benefit plans.

In December 2017, we merged our Dynegy Inc. Retirement Plan into the Sithe Stable Pension Account Plan, which is sponsored by our wholly-owned subsidiary, Sithe Energies, Inc. The combined plan was re-named as the Dynegy Pension Plan, and the sponsorship of the combined plan was transferred from Sithe Energies, Inc. to Dynegy Inc.

In 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 were frozen as of December 31, 2017 and began 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 affected plans and recorded a net-of-tax gain of approximately $15 million through accumulated other comprehensive income during 2017.

In the fourth quarter of 2016, EEI other post-employment plans were amended to change health benefits to a Health Reimbursement Account (“HRA”) for salaried employees and union employees. As a result of these amendments, we remeasured our affected plans and recorded a net-of-tax gain of approximately $17 million through accumulated other comprehensive income.

Additionally, in the fourth quarter of 2016, annuities and individual life insurance policies were purchased from the EEI other post-employment plans, relieving Dynegy of its obligation for the medical and life insurance coverage for inactive participants. As a result, we recorded a net-of-tax settlement cost of $6 million through operating and maintenance expense.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Obligations and Funded Status.  The following tables contain information about the obligations, plan assets, and funded status of all plans in which we, or one of our subsidiaries, formerly sponsored or participated in on a combined basis.

	Pension Benefits						Other Benefits
	Year Ended December 31,
(amounts in millions)	2017			2016			2017			2016
Benefit obligation, beginning of the year	$	508		$	483		$	42		$	74
Service cost	17			16			—			1
Interest cost	20			20			2			3
Actuarial loss	28			23			1			4
Benefits paid	(36		)	(32		)	(4		)	(6		)
Plan change	(10		)	(2		)	(1		)	(17		)
Settlements	—			—			—			(17		)
Acquisitions	—			—			—			—
Divestitures	—			—			—			—
Benefit obligation, end of the year	$	527		$	508		$	40		$	42
Fair value of plan assets, beginning of the year	$	415		$	410		$	49		$	67
Actual return on plan assets	65			37			4			2
Employer contributions	4			—			—			—
Benefits paid	(36		)	(32		)	(2		)	(3		)
Settlements	—			—			—			(17		)
Acquisitions	—			—			—			—
Divestitures	—			—			—			—
Transfers Out (1)	—			—			(19		)	—
Fair value of plan assets, end of the year	$	448		$	415		$	32		$	49
Funded status	$	(79	)	$	(93	)	$	(8	)	$	7

__________________________________________

(1) As permitted by EEI’s other post-employment plan for EEI union employees, part of the overfunded portion of the plan assets was segregated in 2017 to offset the employer cost of the active EEI employees’ health and welfare benefits.

Our accumulated benefit obligation related to pension plans was $527 million and $501 million as of December 31, 2017 and 2016, respectively. Our accumulated benefit obligation related to other post-employment plans was $40 million and $42 million as of December 31, 2017 and 2016, respectively.

Amounts recognized in the consolidated balance sheets consist of:

	Pension Benefits						Other Benefits
	Year Ended December 31,
(amounts in millions)	2017			2016			2017			2016
Non-current assets	$	—		$	7		$	33		$	32
Current liabilities	—			—			(2		)	(2		)
Non-current liabilities	(79		)	(100		)	(20		)	(23		)
Net amount recognized	$	(79	)	$	(93	)	$	11		$	7

Pre-tax amounts recognized in AOCI consist of:

	Pension Benefits						Other Benefits
	Year Ended December 31,
(amounts in millions)	2017			2016			2017			2016
Prior service credit	$	(19	)	$	(12	)	$	(43	)	$	(47	)
Actuarial loss (gain)	(8		)	2			1			1
Net gain recognized	$	(27	)	$	(10	)	$	(42	)	$	(46	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The net actuarial loss (gain) and prior service credit that were amortized from AOCI into net periodic benefit cost during the years ended December 31, 2017, 2016 and 2015 for the defined benefit pension plans were $2 million, $1 million and $1 million, respectively. The net prior service credit that was amortized from AOCI into net periodic benefit cost during the years ended December 31, 2017, 2016 and 2015 for other post-employment benefit plans was $5 million, $4 million and $3 million, respectively.

The expected amounts that will be amortized from AOCI and recognized as components of net periodic benefit cost (gain) in 2018 are as follows:

(amounts in millions)	Pension Benefits			Other Benefits
Prior service credit	$	(3	)	$	(5	)
Actuarial gain	—			(1		)
	$	(3	)	$	(6	)

The amortization of prior service cost is determined using a straight line amortization of the cost over the average remaining service period of employees expected to receive benefits under the plans.

Components of Net Periodic Benefit Cost (Gain).  The components of net periodic benefit cost (gain) were as follows:

	Pension Benefits
	Year Ended December 31,
(amounts in millions)	2017			2016			2015
Service cost benefits earned during period	$	17		$	16		$	14
Interest cost on projected benefit obligation	20			20			18
Expected return on plan assets	(25		)	(22		)	(23		)
Amortization of:
Prior service credit	(2		)	(1		)	(1		)
Actuarial gain	—			—			—
Net periodic benefit cost	$	10		$	13		$	8

	Other Benefits
	Year Ended December 31,
(amounts in millions)	2017			2016			2015
Service cost benefits earned during period	$	—		$	1		$	1
Interest cost on projected benefit obligation	2			3			4
Expected return on plan assets	(2		)	(4		)	(4		)
Amortization of:
Prior service credit	(5		)	(4		)	(3		)
Actuarial gain	(1		)	—			—
Net periodic benefit gain	(6		)	(4		)	(2		)
Settlement cost (1)	—			6			—
Total benefit cost (gain)	$	(6	)	$	2		$	(2	)

__________________________________________

(1) The settlement cost for the year ended December 31, 2016 was related to EEI’s other post-employment benefit plan for EEI union employees.

Assumptions.  The following weighted average assumptions were used to determine benefit obligations:

	Pension Benefits				Other Benefits
	Year Ended December 31,
	2017		2016		2017		2016
Discount rate (1)	3.60	%	4.05	%	3.55	%	4.00	%
Rate of compensation increase (2)	3.50	%	3.50	%	3.50	%	3.50	%

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________________________________________

(1) We utilized a yield curve approach to determine the discount. Projected benefit payments for the plans were matched against the discount rates in the yield curve.

(2) The rate of compensation increase used for other post-employment benefits is specifically related to the EEI post-employment plans.

The following weighted average assumptions were used to determine net periodic benefit cost (gain):

	Pension Benefits						Other Benefits
	Year Ended December 31,
	2017		2016		2015		2017		2016		2015
Discount rate	3.60	%	4.05	%	4.35	%	3.55	%	4.00	%	4.35	%
Dynegy - Expected return on plan assets	6.20	%	5.60	%	5.70	%	N/A		N/A		N/A
EEI - Expected return on plan assets (1)	6.40	%	5.90	%	6.00	%	5.75	%	5.40	%	5.50	%
Rate of compensation increase (2)	3.50	%	3.50	%	3.50	%	3.50	%	3.50	%	3.50	%

__________________________________________

(1) The average expected return on EEI’s other post-employment plan assets was 5.75 percent, 5.40 percent, and 5.50 percent for the years ended December 31, 2017, 2016 and 2015, respectively. The expected return on EEI’s other post-employment plan assets was 6.90 percent, 6.30 percent, and 6.20 percent for EEI union employees for the years ended December 31, 2017, 2016 and 2015, respectively. The expected return on EEI’s other post-employment plan assets was 4.60 percent, 4.50 percent, and 4.80 percent for EEI salaried employees for the years ended December 31, 2017, 2016 and 2015, respectively.

(2) The rate of compensation increase used for other post-employment benefits for the years ended December 31, 2017, 2016 and 2015 is specifically related to the EEI post-employment plans.

Our expected long-term rate of return on Dynegy’s pension plan assets and EEI’s pension plan assets is 5.60 percent and 6.40 percent, respectively, for the year ended December 31, 2018. Our expected long-term rate of return on EEI’s other post-employment plan assets is 7.10 percent for EEI union employees and 4.50 percent for EEI salaried employees for the year ended December 31, 2018. This figure begins with a blend of asset class-level returns developed under a theoretical global capital asset pricing model methodology conducted by an outside consultant. In development of this figure, the historical relationships between equities and fixed income are preserved consistent with the widely accepted capital market principle that assets with higher volatility generate a greater return over the long term. Current market factors such as inflation and interest rates are also incorporated in the assumptions. This figure gives consideration towards the plan’s use of active management and favorable past experience. It is also net of plan expenses.

The following summarizes our assumed health care cost trend rates:

	Year Ended December 31,
	2017		2016		2015
Health care cost trend rate assumed for next year	7.00	%	7.25	%	7.00	%
Ultimate trend rate	4.50	%	4.50	%	4.50	%
Year that the rate reaches the ultimate trend rate	2025		2025		2023

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. The impact of a one percent increase/decrease in assumed health care cost trend rates is as follows:

(amounts in millions)	Increase		Decrease
Aggregate impact on service cost and interest cost	$	—	$	—
Impact on accumulated post-employment benefit obligation	$	3	$	(2	)

Plan Assets.  We employ a total return investment approach whereby a mix of equity and fixed income investments are used to maximize the long-term return of plan assets for a prudent level of risk. The intent of this strategy is to minimize plan expenses by outperforming plan liabilities over the long run. Risk tolerance is established through careful consideration of plan liabilities, plan funded status and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed income investments. Furthermore, equity investments are diversified across U.S. and non-U.S. stocks as well as growth, value, and small and large capitalizations. The Dynegy plans have adopted a glide-path approach to de-risk the portfolio as funding levels increased. The target asset mix as of December 31, 2017 was approximately 46 percent to equity investments and

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

approximately 54 percent to fixed income investments. Dynegy plan assets are routinely monitored and rebalanced as circumstances warrant. The EEI plans have not adopted a glide-path approach. The target asset mix for EEI’s plan assets as of December 31, 2017 was approximately 60 percent to equity investments and approximately 40 percent to fixed income investments. EEI’s plan assets are routinely monitored and rebalanced as circumstances warrant.

Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives may not be used to leverage the portfolio beyond the market value of the underlying investment. Investment risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews, periodic asset/liability studies and annual liability measurements.

The following tables set forth by level within the fair value hierarchy assets that were accounted for at fair value related to our pension and other post-employment plans. These assets are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value as of December 31, 2017
(amounts in millions)	Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	7	$	—	$	—	$	7
Equity securities:
U.S. companies (1)	14		136		—		150
Non-U.S. companies (2)	1		19		—		20
International (3)	9		62		—		71
Fixed income securities (4)	63		169		—		232
Total	$	94	$	386	$	—	$	480

	Fair Value as of December 31, 2016
(amounts in millions)	Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	4	$	2	$	—	$	6
Equity securities:
U.S. companies (1)	18		129		—		147
Non-U.S. companies (2)	1		15		—		16
International (3)	8		58		—		66
Fixed income securities (4)	70		161		—		231
Total	$	101	$	365	$	—	$	466

________________________________________

(1) This category comprises a domestic common collective trust not actively managed that tracks the Dow Jones total U.S. stock market.

(2) This category comprises a common collective trust not actively managed that tracks the MSCI All Country World Ex-U.S. Index.

(3) This category comprises actively managed common collective trusts that hold U.S. and foreign equities. These trusts track the MSCI World Index.

(4) This category includes a mutual fund and a trust that invest primarily in investment grade corporate bonds.

Contributions and Payments.  Our required benefit contributions for our pension and other post-employment benefit plans are as follows:

(amounts in millions)	Pension Benefits		Other Benefits
2016	$	—	$	2
2017	$	4	$	2
2018	$	13	$	2

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Our expected benefit payments for future services for our pension and other post-employment benefits are as follows:

(amounts in millions)	Pension Benefits		Other Benefits
2018	$	39	$	3
2019	$	38	$	3
2020	$	38	$	3
2021	$	38	$	3
2022	$	38	$	2
2023 - 2027	$	190	$	11

Note 18—Quarterly Financial Information

The following is a summary of our unaudited quarterly financial information:

	Quarter Ended
(amounts in millions, except per share data)	March 31			June 30			September 30			December 31
2017
Revenues	$	1,247		$	1,164		$	1,437		$	994
Operating income (loss) (1)	$	(49	)	$	(182	)	$	58		$	(239	)
Net income (loss) (2)(3)(4)	$	596		$	(296	)	$	(133	)	$	(95	)
Net income (loss) attributable to Dynegy Inc. common stockholders (2)(3)(4)	$	592		$	(302	)	$	(137	)	$	(95	)
Net income (loss) per share attributable to Dynegy Inc. common stockholders—Basic (2)(3)(4)	$	4.00		$	(1.96	)	$	(0.89	)	$	(0.58	)
Net income (loss) per share attributable to Dynegy Inc. common stockholders—Diluted (2)(3)(4)	$	3.57		$	(1.96	)	$	(0.89	)	$	(0.58	)
2016
Revenues	$	1,123		$	904		$	1,184		$	1,107
Operating income (loss) (1)	$	145		$	(702	)	$	(117	)	$	34
Net loss	$	(10	)	$	(803	)	$	(249	)	$	(182	)
Net loss attributable to Dynegy Inc. common stockholders	$	(15	)	$	(807	)	$	(254	)	$	(186	)
Net loss per share attributable to Dynegy Inc. common stockholders—Basic	$	(0.13	)	$	(6.73	)	$	(1.81	)	$	(1.33	)
Net loss per share attributable to Dynegy Inc. common stockholders—Diluted	$	(0.13	)	$	(6.73	)	$	(1.81	)	$	(1.33	)

_____________________

(1) The results for the quarters ended March 31, 2017, June 30, 2017, and September 30, 2017, include impairment charges of $20 million, $99 million, and $29 million, respectively. The results for the quarters ended June 30, 2016, September 30, 2016, and December 31, 2016, include impairment charges of $645 million, $212 million, and $1 million, respectively. SeeNote 8—Property, Plant and Equipment for more information.

(2) The results for the quarters ended June 30, 2017, September 30, 2017, and December 31, 2017 include losses on sale of assets of $29 million, $78 million, and $15 million, respectively. See Note 3—Acquisitions and Divestitures and Note 9—Joint Ownership of Generating Facilities for more information.

(3) The results for the quarters ended March 31, 2017, June 30, 2017, and September 30, 2017, include income (loss) from bankruptcy reorganization items of $483 million, ($1) million, and $12 million, respectively. The results for the quarter ended December 31, 2016 include loss from Bankruptcy reorganization items of $96 million. See Note 20—Genco Chapter 11 Bankruptcy for more information.

(4) The results for the quarters ended March 31, 2017 and December 31, 2017 include a $317 million and $37 million income tax benefit, respectively, from the partial release of our valuation allowance as a result of the ENGIE Acquisition. The results for the quarter ended December 31, 2017 include a $223 million tax benefit related to the expected refund of its existing AMT Credits as provided for in the TCJA. See Note 14—Income Taxes for more information.

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Note 19—Condensed Consolidating Financial Information

Dynegy’s senior notes are guaranteed by certain, but not all, of our wholly owned subsidiaries. The following condensed consolidating financial statements as of and for the years ended December 31, 2017, 2016 and 2015 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 13—Debt for further discussion.

These statements should be read in conjunction with the 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. 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 December 31, 2017.

For purposes of the 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 December 31, 2017 and December 31, 2016.

Condensed Consolidating Balance Sheet for the Year Ended December 31, 2017

(amounts in millions)

	Parent		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Current Assets
Cash and cash equivalents	$	233	$	124		$	8		$	—		$	365
Accounts receivable, net	126		4,269			14			(3,896		)	513
Inventory	—		415			30			—			445
Other current assets	8		288			2			(97		)	201
Total Current Assets	367		5,096			54			(3,993		)	1,524
Property, plant and equipment, net	—		8,585			299			—			8,884
Investment in affiliates	16,132		—			—			(16,132		)	—
Investment in unconsolidated affiliates	—		123			—			—			123
Goodwill	—		772			—			—			772
Other long-term assets	244		185			39			—			468
Intercompany note receivable	46		—			—			(46		)	—
Total Assets	$	16,789	$	14,761		$	392		$	(20,171	)	$	11,771
Current Liabilities
Accounts payable	$	3,555	$	471		$	232		$	(3,891	)	$	367
Other current liabilities	156		520			108			(102		)	682
Total Current Liabilities	3,711		991			340			(3,993		)	1,049
Debt, long-term portion, net	8,045		256			27			—			8,328
Intercompany note payable	3,042		46			—			(3,088		)	—
Other long-term liabilities	90		367			44			—			501
Total Liabilities	14,888		1,660			411			(7,081		)	9,878
Stockholders’ Equity
Dynegy Stockholders’ Equity	1,901		16,151			(19		)	(16,132		)	1,901
Intercompany note receivable	—		(3,042		)	—			3,042			—
Total Dynegy Stockholders’ Equity	1,901		13,109			(19		)	(13,090		)	1,901
Noncontrolling interest	—		(8		)	—			—			(8		)
Total Equity	1,901		13,101			(19		)	(13,090		)	1,893
Total Liabilities and Equity	$	16,789	$	14,761		$	392		$	(20,171	)	$	11,771

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Balance Sheet for the Year Ended 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
Other long-term assets	2		109			35		—			146
Goodwill	—		799			—		—			799
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

F-54

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statements of Operations for the Year Ended December 31, 2017

(amounts in millions)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	4,557		$	422		$	(137	)	$	4,842
Cost of sales, excluding depreciation expense	—			(2,790		)	(279		)	137			(2,932		)
Gross margin	—			1,767			143			—			1,910
Operating and maintenance expense	—			(881		)	(114		)	—			(995		)
Depreciation expense	—			(757		)	(54		)	—			(811		)
Impairments	—			(148		)	—			—			(148		)
Gain (loss) on sale of assets, net	—			(123		)	1			—			(122		)
General and administrative expense	(28		)	(155		)	(6		)	—			(189		)
Acquisition and integration costs	(54		)	(3		)	—			—			(57		)
Operating loss	(82		)	(300		)	(30		)	—			(412		)
Bankruptcy reorganization items	(18		)	512			—			—			494
Earnings from unconsolidated investments	—			8			—			—			8
Equity in losses from investments in affiliates	824			—			—			(824		)	—
Interest expense	(597		)	(20		)	(13		)	14			(616		)
Loss on early extinguishment of debt	(79		)	—			—			—			(79		)
Other income and expense, net	28			53			—			(14		)	67
Income (loss) before income taxes	76			253			(43		)	(824		)	(538		)
Income tax benefit (Note 14)	—			610			—			—			610
Net income (loss)	76			863			(43		)	(824		)	72
Less: Net loss attributable to noncontrolling interest	—			(4		)	—			—			(4		)
Net income (loss) attributable to Dynegy Inc.	$	76		$	867		$	(43	)	$	(824	)	$	76

Condensed Consolidating Statements of Operations for the Year Ended December 31, 2016

(amounts in millions)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	3,942		$	468		$	(92	)	$	4,318
Cost of sales, excluding depreciation expense	—			(2,112		)	(261		)	92			(2,281		)
Gross margin	—			1,830			207			—			2,037
Operating and maintenance expense	—			(796		)	(144		)	—			(940		)
Depreciation expense	—			(612		)	(77		)	—			(689		)
Impairments	—			(858		)	—			—			(858		)
Gain (loss) on sale of assets, net	(2		)	1			—			—			(1		)
General and administrative expense	(7		)	(148		)	(6		)	—			(161		)
Acquisition and integration costs	(10		)	(1		)	—			—			(11		)
Other	—			(9		)	(8		)	—			(17		)
Operating loss	(19		)	(593		)	(28		)	—			(640		)
Bankruptcy reorganization items	—			(96		)	—			—			(96		)
Earnings from unconsolidated investments	—			7			—			—			7
Equity in losses from investments in affiliates	(715		)	—			—			715			—
Interest expense	(538		)	(83		)	(9		)	5			(625		)
Other income and expense, net	32			38			—			(5		)	65
Loss before income taxes	(1,240		)	(727		)	(37		)	715			(1,289		)
Income tax benefit (Note 14)	—			45			—			—			45
Net loss	(1,240		)	(682		)	(37		)	715			(1,244		)
Less: Net loss attributable to noncontrolling interest	—			(4		)	—			—			(4		)
Net loss attributable to Dynegy Inc.	$	(1,240	)	$	(678	)	$	(37	)	$	715		$	(1,240	)

F-55

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statements of Operations for the Year Ended December 31, 2015

(amounts in millions)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	3,508		$	525		$	(163	)	$	3,870
Cost of sales, excluding depreciation expense	—			(1,874		)	(317		)	163			(2,028		)
Gross margin	—			1,634			208			—			1,842
Operating and maintenance expense	—			(717		)	(122		)	—			(839		)
Depreciation expense	—			(505		)	(82		)	—			(587		)
Impairments	—			(74		)	(25		)	—			(99		)
Loss on sale of assets, net	—			(1		)	—			—			(1		)
General and administrative expense	(6		)	(116		)	(6		)	—			(128		)
Acquisition and integration costs	—			(124		)	—			—			(124		)
Operating income (loss)	(6		)	97			(27		)	—			64
Earnings from unconsolidated investments	—			1			—			—			1
Equity in earnings from investments in affiliates	476			—			—			(476		)	—
Interest expense	(475		)	(69		)	(4		)	2			(546		)
Other income and expense, net	55			1			—			(2		)	54
Income (loss) before income taxes	50			30			(31		)	(476		)	(427		)
Income tax benefit (Note 14)	—			472			2			—			474
Net income (loss)	50			502			(29		)	(476		)	47
Less: Net income attributable to noncontrolling interest	—			(3		)	—			—			(3		)
Net income (loss) attributable to Dynegy Inc.	$	50		$	505		$	(29	)	$	(476	)	$	50

Condensed Consolidating Statements of Comprehensive Income (Loss) for the Year Ended December 31, 2017

(amounts in millions)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net income (loss)	$	76		$	863		$	(43	)	$	(824	)	$	72
Other comprehensive income (loss) before reclassifications:
Actuarial gain (loss) and plan amendments, net of tax of $5	22			(3		)	—			—			19
Amounts reclassified from accumulated other comprehensive income:
Amortization of unrecognized prior service credit, net of tax of zero	(7		)	—			(1		)	—			(8		)
Other comprehensive loss from investment in affiliates	(4		)	—			—			4			—
Other comprehensive income (loss), net of tax	11			(3		)	(1		)	4			11
Comprehensive income (loss)	87			860			(44		)	(820		)	83
Less: Comprehensive loss attributable to noncontrolling interest	—			(4		)	—			—			(4		)
Total comprehensive income (loss) attributable to Dynegy Inc.	$	87		$	864		$	(44	)	$	(820	)	$	87

F-56

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statements of Comprehensive Loss for the Year Ended December 31, 2016

(amounts in millions)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net loss	$	(1,240	)	$	(682	)	$	(37	)	$	715		$	(1,244	)
Other comprehensive income (loss) before reclassifications:
Actuarial gain (loss) and plan amendments, net of tax of $3	(4		)	1			6			—			3
Amounts reclassified from accumulated other comprehensive income:
Settlement cost, net of tax of zero	—			—			6			—			6
Amortization of unrecognized prior service credit, net of tax of zero	(4		)	—			(1		)	—			(5		)
Other comprehensive income from investment in affiliates	12			—			—			(12		)	—
Other comprehensive income, net of tax	4			1			11			(12		)	4
Comprehensive loss	(1,236		)	(681		)	(26		)	703			(1,240		)
Less: Comprehensive income (loss) attributable to noncontrolling interest	2			(2		)	—			(2		)	(2		)
Total comprehensive loss attributable to Dynegy Inc.	$	(1,238	)	$	(679	)	$	(26	)	$	705		$	(1,238	)

Condensed Consolidating Statements of Comprehensive Income (Loss) for the Year Ended December 31, 2015

(amounts in millions)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net income (loss)	$	50		$	502		$	(29	)	$	(476	)	$	47
Other comprehensive income (loss) before reclassifications:
Actuarial gain (loss) and plan amendments, net of tax of zero	(8		)	7			5			—			4
Amounts reclassified from accumulated other comprehensive income (loss):
Amortization of unrecognized prior service credit and actuarial gain, net of tax of zero	(3		)	—			(1		)	—			(4		)
Other comprehensive loss from investment in affiliates	11			—			—			(11		)	—
Other comprehensive income, net of tax	—			7			4			(11		)	—
Comprehensive income (loss)	50			509			(25		)	(487		)	47
Less: Comprehensive income (loss) attributable to noncontrolling interest	1			(2		)	—			(1		)	(2		)
Total comprehensive income (loss) attributable to Dynegy Inc.	$	49		$	511		$	(25	)	$	(486	)	$	49

F-57

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statements of Cash Flow for the Year Ended December 31, 2017

(amounts in millions)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$	(427	)	$	899		$	113		$	—		$	585
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	—			(208		)	(16		)	—			(224		)
Acquisitions, net of cash acquired/divestitures	(3,244		)	(75		)	—			—			(3,319		)
Distributions from unconsolidated affiliate	—			12			—			—			12
Proceeds from sales of assets, net	775			(4		)	1			—			772
Net intercompany transfers	691			—			—			(691		)	—
Net cash used in investing activities	(1,778		)	(275		)	(15		)	(691		)	(2,759		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of debt issuance costs	1,743			—			—			—			1,743
Repayments of borrowings	(2,487		)	(46		)	(56		)	—			(2,589		)
Proceeds from issuance of equity, net of issuance costs	150			—			—			—			150
Payments of debt extinguishment costs	(50		)	—			—			—			(50		)
Preferred stock dividends paid	(22		)	—			—			—			(22		)
Interest rate swap settlement payments	(20		)	—			—			—			(20		)
Acquisition of noncontrolling interest	(375		)	—			—			—			(375		)
Payments related to bankruptcy settlement	(128		)	(5		)	—			—			(133		)
Net intercompany transfers	—			(631		)	(60		)	691			—
Intercompany borrowings, net of repayments	80			(80		)	—			—			—
Other financing	(3		)	—			—			—			(3		)
Net cash provided by (used in) financing activities	(1,112		)	(762		)	(116		)	691			(1,299		)
Net decrease in cash and cash equivalents	(3,317		)	(138		)	(18		)	—			(3,473		)
Cash, cash equivalents and restricted cash, beginning of period	3,550			262			26			—			3,838
Cash, cash equivalents and restricted cash, end of period	$	233		$	124		$	8		$	—		$	365

Condensed Consolidating Statements of Cash Flow for the Year Ended December 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	$	(476	)	$	1,090		$	31		$	—		$	645
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	—			(243		)	(50		)	—			(293		)
Proceeds from sales of assets, net	171			5			—			—			176
Distributions from unconsolidated affiliate	—			14			—			—			14
Net intercompany transfers	958			—			—			(958		)	—
Other investing	—			10			—			—			10
Net cash provided by (used in) investing activities	1,129			(214		)	(50		)	(958		)	(93		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of debt issuance costs	2,816			198			—			—			3,014
Repayments of borrowings	(563		)	(15		)	(11		)	—			(589		)
Proceeds from issuance of equity, net of issuance costs	359			—			—			—			359
Preferred stock dividends paid	(22		)	—			—			—			(22		)
Interest rate swap settlement payments	(17		)	—			—			—			(17		)
Net intercompany transfers	—			(991		)	33			958			—
Other financing	(3		)	—			—			—			(3		)
Net cash provided by (used in) financing activities	2,570			(808		)	22			958			2,742
Net increase in cash and cash equivalents	3,223			68			3			—			3,294
Cash, cash equivalents and restricted cash, beginning of period	327			194			23			—			544
Cash, cash equivalents and restricted cash, end of period	$	3,550		$	262		$	26		$	—		$	3,838

F-58

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statements of Cash Flow for the Year Ended December 31, 2015

(amounts in millions)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$	(432	)	$	682		$	(156	)	$	—		$	94
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	—			(290		)	(11		)	—			(301		)
Acquisitions, net of cash acquired/divestitures	(6,207		)	29			100			—			(6,078		)
Distributions from unconsolidated affiliate	—			8			—			—			8
Net intercompany transfers	450			—			—			(450		)	—
Other investing	—			3			—			—			3
Net cash provided by (used in) investing activities	(5,757		)	(250		)	89			(450		)	(6,368		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of debt issuance costs	(31		)	78			19			—			66
Repayments of borrowings	(8		)	(23		)	—			—			(31		)
Proceeds from issuance of equity, net of issuance costs	(6		)	—			—			—			(6		)
Preferred stock dividends paid	(23		)	—			—			—			(23		)
Interest rate swap settlement payments	(17		)	—			—			—			(17		)
Repurchase of common stock	(250		)	—			—			—			(250		)
Net intercompany transfers	—			(347		)	(103		)	450			—
Other financing	(4		)	—			—			—			(4		)
Net cash provided by (used in) financing activities	(339		)	(292		)	(84		)	450			(265		)
Net increase (decrease) in cash and cash equivalents	(6,528		)	140			(151		)	—			(6,539		)
Cash, cash equivalents and restricted cash, beginning of period	6,855			54			174			—			7,083
Cash, cash equivalents and restricted cash, end of period	$	327		$	194		$	23		$	—		$	544

Note 20—Genco Chapter 11 Bankruptcy

On October 14, 2016, we entered into a restructuring support agreement with Genco and an ad hoc group of Genco bondholders to restructure the Genco senior notes. As a result of filing a prepackaged plan of reorganization (the “Genco Plan”), we reclassified the Genco senior notes as Liabilities subject to compromise in our consolidated balance sheet as of December 31, 2016. The amounts represented the allowed claims to be resolved in connection with our Chapter 11 proceedings. A summary of our liabilities subject to compromise as of December 31, 2016 is as follows:

(amounts in millions)	December 31, 2016
Genco senior notes:
7.00% Senior Notes Series H, due 2018	$	300
6.30% Senior Notes Series I, due 2020	250
7.95% Senior Notes Series F, due 2032	275
Interest accrued	7
Total liabilities subject to compromise	$	832

Costs associated with the reorganization incurred prior to the Bankruptcy Petition of approximately $10 million have been recorded in General and administrative expense in our consolidated statement of operations for the year ended December 31, 2016. Costs post Genco’s Bankruptcy Petition of approximately $96 million have been recorded to Bankruptcy reorganization items in our consolidated statement of operations for the year ended December 31, 2016, and primarily include the write-off of the remaining unamortized discount related to the Genco senior notes and legal expenses incurred.

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 approximately $122 million of cash, $188 million of new seven-year unsecured notes, and 2017 Warrants to purchase up to 9 million shares of common stock with a fair value of $17 million.

F-59

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 December 31, 2017.

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 year ended December 31, 2017:

(amounts in millions)
Liabilities subject to compromise, which were terminated	$	832
Less:
Seven-year unsecured notes	188
Cash consideration	122
2017 Warrants, at fair value	17
Legal and consulting fees	11
Bankruptcy reorganization items	$	494

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.

During 2016, upon Genco’s petition for bankruptcy under Chapter 11, we analyzed Genco as a VIE. Based on the analysis, it was determined that Dynegy was the primary beneficiary of Genco and continued to receive the benefits and controlled the significant activities of Genco. As a result, Genco was consolidated by Dynegy as a VIE as of December 31, 2016.

Note 21—Segment Information

We report the results of our operations in the following five segments based upon the market areas in which our plants operate: (i) PJM, (ii) NY/NE, (iii) ERCOT, (iv) MISO and (v) CAISO. Our consolidated financial results also reflect corporate-level expenses such as general and administrative expense, interest expense and income tax benefit (expense). In the fourth quarter of 2017, we combined our previous MISO and IPH segments into a single MISO segment to better align our IPH assets, which reside within the MISO market area. Accordingly, the Company has recast data from prior periods to conform to the current year segment presentation. PJM also includes our Dynegy Energy Services retail business in Ohio and Pennsylvania. NY/NE also includes our Dynegy Energy Services retail business in Massachusetts. MISO also includes our Homefield Energy retail business in Illinois.

F-60

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Reportable segment information, including intercompany transactions accounted for at prevailing market rates, for the years ended December 31, 2017, 2016 and 2015 is presented below:

Segment Data as of and for the Year Ended December 31, 2017

(amounts in millions)

	PJM			NY/NE			ERCOT			MISO			CAISO			Other and Eliminations			Total
Domestic:
Unaffiliated revenues	$	2,352		$	1,031		$	276		$	1,061		$	122		$	—		$	4,842
Intercompany and affiliate revenues	(90		)	(2		)	1			91			—			—			—
Total revenues	$	2,262		$	1,029		$	277		$	1,152		$	122		$	—		$	4,842
Depreciation expense	$	(379	)	$	(224	)	$	(73	)	$	(75	)	$	(53	)	$	(7	)	$	(811	)
Impairments	(49		)	—			—			(99		)	—			—			(148		)
Gain (loss) on sale of assets, net	(36		)	(90		)	—			1			3			—			(122		)
General and administrative expense	—			—			—			—			—			(189		)	(189		)
Acquisition and integration costs	—			—			—			—			—			(57		)	(57		)
Operating income (loss)	$	192		$	(113	)	$	(147	)	$	(44	)	$	(45	)	$	(255	)	$	(412	)
Bankruptcy reorganization items	—			—			—			494			—			—			494
Earnings from unconsolidated investments	3			5			—			—			—			—			8
Interest expense	—			—			—			—			—			(616		)	(616		)
Loss on early extinguishment of debt	—			—			—			—			—			(79		)	(79		)
Other income and expense, net	16			—			—			26			—			25			67
Loss before income taxes																			(538		)
Income tax benefit	—			—			—			—			—			610			610
Net Income																			72
Less: Net loss attributable to noncontrolling interest																			(4		)
Net Income attributable to Dynegy Inc.																			$	76
Total assets—domestic	$	4,912		$	3,374		$	1,563		$	812		$	455		$	655		$	11,771
Investment in unconsolidated affiliate	$	67		$	56		$	—		$	—		$	—		$	—		$	123
Capital expenditures	$	(103	)	$	(50	)	$	(26	)	$	(26	)	$	(12	)	$	(7	)	$	(224	)

F-61

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Segment Data as of and for the Year Ended December 31, 2016

(amounts in millions)

	PJM			NY/NE			MISO			CAISO			Other and Eliminations			Total
Domestic:
Unaffiliated revenues	$	2,147		$	836		$	1,165		$	142		$	—		$	4,290
Intercompany revenues	55			1			(28		)	—			—			28
Total revenues	$	2,202		$	837		$	1,137		$	142		$	—		$	4,318
Depreciation expense	$	(346	)	$	(215	)	$	(81	)	$	(42	)	$	(5	)	$	(689	)
Impairments	(65		)	—			(793		)	—			—			(858		)
Gain (loss) on sale of assets, net	—			—			1			—			(2		)	(1		)
General and administrative expense	—			—			—			—			(161		)	(161		)
Acquisition and integration costs	—			—			8			—			(19		)	(11		)
Operating income (loss)	$	414		$	(29	)	$	(832	)	$	(5	)	$	(188	)	$	(640	)
Bankruptcy reorganization items	—			—			(96		)	—			—			(96		)
Earnings from unconsolidated investments	7			—			—			—			—			7
Interest expense	—			—			—			—			(625		)	(625		)
Other income and expense, net	9			1			15			12			28			65
Loss before income taxes																(1,289		)
Income tax benefit	—			—			—			—			45			45
Net loss																(1,244		)
Less: Net loss attributable to noncontrolling interest																(4		)
Net loss attributable to Dynegy Inc.																$	(1,240	)
Total assets—domestic	$	4,939		$	2,769		$	1,065		$	485		$	3,795		$	13,053
Capital expenditures	$	(160	)	$	(64	)	$	(52	)	$	(7	)	$	(10	)	$	(293	)

F-62

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Segment Data as of and for the Year Ended December 31, 2015

(amounts in millions)

	PJM			NY/NE			MISO			CAISO			Other and Eliminations			Total
Domestic:
Unaffiliated revenues	$	1,708		$	705		$	1,279		$	178		$	—		$	3,870
Intercompany revenues	8			(10		)	2			—			—			—
Total revenues	$	1,716		$	695		$	1,281		$	178		$	—		$	3,870
Depreciation expense	$	(281	)	$	(186	)	$	(68	)	$	(48	)	$	(4	)	$	(587	)
Impairments	—			(25		)	(74		)	—			—			(99		)
Loss on sale of assets, net	—			—			—			(1		)	—			(1		)
General and administrative expense	—			—			—			—			(128		)	(128		)
Acquisition and integration costs	—			—			—			—			(124		)	(124		)
Operating income (loss)	$	423		$	(56	)	$	(43	)	$	(8	)	$	(252	)	$	64
Earnings from unconsolidated investments	1			—			—			—			—			1
Interest expense	—			—			—			—			(546		)	(546		)
Other income and expense, net	(2		)	—			1			—			55			54
Loss from continuing operations before income taxes																(427		)
Income tax benefit	—			—			—			—			474			474
Net income																47
Less: Net loss attributable to noncontrolling interest																(3		)
Net income attributable to Dynegy Inc.																$	50
Total assets—domestic	$	5,474		$	2,970		$	1,995		$	534		$	486		$	11,459
Investment in unconsolidated affiliate	$	190		$	—		$	—		$	—		$	—		$	190
Capital expenditures	$	(106	)	$	(52	)	$	(119	)	$	(11	)	$	(13	)	$	(301	)

Significant Customers

Our total revenues for customers who individually accounted for more than 10 percent of our consolidated revenues, and the segments impacted, for the years ended December 31, 2017, 2016 and 2015 are presented below:

(amounts in millions)	Revenues
Customers	2017		2016		2015		Segment(s)
PJM	$	1,313	$	1,366	$	1,088	PJM, MISO
MISO	$	506	$	688	$	842	MISO
ISO-NE	$	669	$	437	N/A		MISO, NY/NE

Employee Concentrations

As of December 31, 2017, approximately 40 percent of our employees are covered by a collective bargaining agreement.

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