DYNEGY INC. (Form: 10-K, Received: 02/24/2017 11:30:02)

Generation volumes hedged (1)

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, 2016

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 7.00% Tangible Equity Units		New York Stock Exchange
Dynegy's 5.375% Series A Mandatory Convertible Preferred Stock, $0.01 par value		New York Stock Exchange
Dynegy’s warrants, exercisable for common stock at an exercise price of $40 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

Table of Contents

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. ¨

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



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

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

As of June 30, 2016, the aggregate market value of the Dynegy Inc. common stock held by non-affiliates of the registrant was $2,012,104,657 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, 131,016,337 shares outstanding as of February 7, 2017 .

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 2017 Annual Meeting of Stockholders, which the registrant intends to file no later than 120 days after December 31, 2016 . 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.

Table of Contents

DYNEGY INC.

FORM 10-K

TABLE OF CONTENTS



		Page
PART I

Definitions		1
Item 1.	Business	2
Item 1A.	Risk Factors	23
Item 1B.	Unresolved Staff Comments	32
Item 2.	Properties	32
Item 3.	Legal Proceedings	33
Item 4.	Mine Safety Disclosures	33
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	38
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	89
Item 8.	Financial Statements and Supplementary Data	90
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	90
Item 9A.	Controls and Procedures	91
Item 9B.	Other Information	91
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	92
Item 11.	Executive Compensation	92
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	92
Item 13.	Certain Relationships and Related Transactions, and Director Independence	92
Item 14.	Principal Accountant Fees and Services	93
PART IV
Item 15.	Exhibits and Financial Statement Schedules	94
Signatures		103

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. Discussions or areas of this report that apply only to Dynegy, Legacy Dynegy or Dynegy Holdings, LLC (“DH”) are clearly noted in such sections or areas and specific defined terms may be introduced for use only in those sections or areas. Further, as used in this Form 10-K, the abbreviations contained herein have the meanings set forth below.



CAA		Clean Air Act
CAISO		California Independent System Operator
CPUC		California Public Utility Commission
CT		Combustion Turbine
EBITDA		Earnings Before Interest, Taxes, Depreciation and Amortization
EGU		Electric Generating Units
ELG		Effluent Limitation Guidelines
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
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
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
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

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 50 power plants in 12 states totaling approximately 31,000 MW of generating capacity (including the assets acquired in the Delta Transaction, which closed on February 7, 2017 ). References to our net generation capacity throughout this Form 10-K include the impacts of the Delta Transaction.

We sell electric energy, capacity and ancillary services primarily on a wholesale basis from our power generation facilities. We also serve residential, municipal, commercial and industrial customers primarily in MISO and PJM through our Homefield Energy and Dynegy Energy Services retail businesses, through which we provide retail electricity to approximately 963,000 residential customers and approximately 42,000 commercial, industrial and municipal customers in Illinois, 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.

The two charts below show our net generation capacity as of February 7, 2017, and include our recent Delta Transaction.

The charts below include our 2016 wholesale generation, retail load, and Adjusted EBITDA contribution by fuel type (does not include our recent Delta Transaction).

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.

In the fourth quarter of 2016, Dynegy changed its organizational structure to manage its assets, make financial decisions, and allocate resources based upon the market areas in which our plants operate. As of December 31, 2016, we modified our reportable segments from a fuel-based segment structure to the following market areas: (i) PJM, (ii) ISO-NE/NYISO (“NY/NE”), (iii) MISO, (iv) IPH and (v) CAISO. Accordingly, the Company has recast data from prior periods to reflect this change in reportable segments to conform to the current year presentation. Our consolidated financial results also reflect corporate-level expenses such as general and administrative expense, interest expense and income tax benefit (expense). Additionally, beginning in 2017, as a result of the Delta Transaction, we also have an ERCOT segment. Please read Note 23—Segment Information for further discussion.

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.

Our Power Generation Portfolio

Our generating facilities are as follows (* denotes facilities acquired in the Delta Transaction):



Facility	Total Net Generating Capacity (MW)(1)	Primary Fuel Type	Technology Type	Location	Region
Armstrong*	753	Gas	CT	Shelocta, PA	PJM
Calumet*	380	Gas	CT	Chicago, IL	PJM
Conesville (2)(3)	312	Coal	ST	Conesville, OH	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
Lee	787	Gas	CT	Dixon, IL	PJM
Liberty	605	Gas	CCGT	Eddystone, PA	PJM
Miami Fort (2)	653	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)	904	Coal	ST	Aberdeen, OH	PJM
Troy*	770	Gas	CT	Luckey, OH	PJM
Washington	711	Gas	CCGT	Beverly, OH	PJM
Zimmer (2)	628	Coal	ST	Moscow, OH	PJM
Total PJM Segment	13,510
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
Brayton Point (4)	1,488	Coal	ST	Somerset, MA	ISO-NE
Casco Bay	543	Gas	CCGT	Veazie, ME	ISO-NE
Dighton	185	Gas	CCGT	Dighton, MA	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	569	Gas	CCGT	Milford, CT	ISO-NE
Milford - Massachusetts*	171	Gas	CCGT	Milford, MA	ISO-NE
Total NY/NE Segment	6,543
Coleto Creek*	635	Coal	ST	Goliad, TX	ERCOT
Ennis*	370	Gas	CCGT	Ennis, TX	ERCOT
Hays*	1,107	Gas	CCGT	San Marcos, TX	ERCOT
Midlothian*	1,712	Gas	CCGT	Midlothian, TX	ERCOT
Wharton*	85	Gas	CT	Boling, TX	ERCOT
Wise*	787	Gas	CCGT	Poolville, TX	ERCOT
Total ERCOT Segment	4,696
Baldwin	1,185	Coal	ST	Baldwin, IL	MISO
Havana	434	Coal	ST	Havana, IL	MISO
Hennepin	294	Coal	ST	Hennepin, IL	MISO
Total MISO Segment	1,913



Facility	Total Net Generating Capacity (MW)(1)	Primary Fuel Type	Technology Type	Location	Region
Coffeen	915	Coal	ST	Coffeen, IL	MISO
Duck Creek	425	Coal	ST	Canton, IL	MISO
Edwards	585	Coal	ST	Bartonville, 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 IPH Segment (5)	3,563
Moss Landing	1,020	Gas	CCGT	Moss Landing, CA	CAISO
Oakland	165	Oil	CT	Oakland, CA	CAISO
Total CAISO Segment	1,185
Total Capacity	31,410

________________________________________


(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)	Scheduled to be retired from service in June 2017.


(5)	We have transmission rights into PJM for certain of our IPH 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. We expect to expand our retail load in areas in which our generation is located, thereby further reducing our risk profile and the need to transact additional financial hedging products.

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.

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. Historical PRIDE results as well as our new 3-year targets are shown below. In 2016, we exceeded our balance sheet target of $200 million by $222 million, and exceeded our EBITDA target of $135 million by $15 million.

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 now focused on strengthening our balance sheet, managing debt maturities and improving our leverage profile through debt reduction primarily from operating cash flows, PRIDE initiatives and select asset sales.

Recent Developments

Delta Transaction

On February 7, 2017 , (“the Delta Transaction 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 “Delta Transaction”). Additionally, Dynegy paid Energy Capital Partners (“ECP”) $375 million (the “ECP Buyout Price”) and issued 13,711,152 shares of Dynegy common stock for $150 million. Please read Note 24—Subsequent Events for further discussion.

Sale of Elwood

On November 21, 2016, we sold our 50 percent equity interest in the Elwood Energy facility in Elwood, IL, to J-Power USA Development Co. Ltd. for approximately $173 million (the “Elwood Sale”). As part of the transaction, approximately $35 million of previously posted collateral has been returned to us, and the non-recourse, asset-level financing remains with the new owner. Please read Note 11—Unconsolidated Investments for further discussion.

2025 Senior Notes and Term Loan Repayment

On October 11, 2016, we issued, in a private placement transaction, $750 million of 8 percent unsecured senior notes due 2025 (the “2025 Senior Notes”). The 2025 Senior Notes do not provide registration rights but otherwise have terms and provisions similar to our approximately $5.6 billion in senior notes (“Dynegy Senior Notes”). On December 9, 2016, we voluntarily repaid $550 million of our $800 million seven -year senior secured term loan facility (the “Tranche B-2 Term Loan”). Please read Note 14—Debt for further discussion.

Term Loan Repricing

Upon the Delta Transaction Closing Date, we amended the Credit Agreement to, among other things, (1) reduce the interest rate by 75 basis points, and (2) extend the maturity of the existing Tranche B-2 Term Loans to 2024 through the exchange of the outstanding Initial Tranche B-2 Term Loans for Tranche C-1 Term Loans. The reduced interest rate is expected to save Dynegy approximately $100 million in interest costs over the next seven years.

Asset Sales

Troy facilities totaling 1,269 MW. The sale is expected to close in the second half of 2017 with the proceeds to be allocated to debt reduction.

Acquisition and Sale of Interests in Jointly Owned Facilities

On February 23, 2017, Dynegy reached an agreement with American Electric Power (“AEP”) to realign and consolidate each company’s ownership interests in the Conesville and Zimmer Power Stations in Ohio. Under the agreement, Dynegy will sell its 40 percent ownership interest in Conesville to AEP, and will acquire AEP‘s 25.4 percent ownership interest in Zimmer. As a result, Dynegy will own 71.9 percent of the Zimmer facility and will no longer have an ownership interest in the AEP operated Conesville facility. No cash will be exchanged in the transaction and no additional debt will be incurred by either party.

Genco Restructuring

On December 9, 2016, Illinois Power Generating Company (“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 prepackaged plan of reorganization (the “Genco Plan”) and Genco emerged from bankruptcy on February 2, 2017 (the “Emergence Date”). As a result, we eliminated $825 million of Genco Senior Notes. On the Emergence Date, we exchanged $757 million of the Genco Senior Notes for $113 million of cash, $182 million of new Dynegy seven-year unsecured notes, and 8.7 million Dynegy common stock warrants. Holders of Genco Senior Notes who did not receive a distribution under the Genco Plan on the Emergence Date have until July 17, 2017 (the 165th day after the Emergence Date) in order to exercise their rights to receive a distribution. Please read Note 22—Genco Chapter 11 Bankruptcy for further discussion.

Through the Emergence Date, IPH and its direct and indirect subsidiaries were organized into ring-fenced groups in order to maintain corporate separateness from Dynegy and our other legal entities. Certain of the entities in the IPH segment, including Genco, had an independent director whose consent was required for certain corporate actions, including material transactions with affiliates. Further, there were restrictions on pledging their assets for the benefit of certain other persons. These provisions restricted our ability to move cash out of these entities without meeting certain requirements as set forth in the governing documents. After the Emergence Date, these entities present themselves to the public as separate entities. They also maintain corporate formalities including separate books, records and bank accounts and separately appoint officers. Furthermore, they pay liabilities from their own funds and conduct business in their own names.

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 six segments on a consolidated basis: (i) PJM, (ii) NY/NE, (iii) ERCOT, (iv) MISO, (v) IPH, and (vi) CAISO. During 2016 we changed our segment structure. Please read Note 23—Segment Information for further information regarding revenues from external customers, operating income (loss) and total assets by segment. The discussion herein reflects capacities at our net ownership interest.

We continue to expect that, over the longer-term, power and capacity pricing will improve as natural gas prices increase, marginal generating units retire, and more stringent environmental regulations force the retirement of power generation units that have not invested in environmental upgrades. As a result, we believe our coal-fired fleets are well positioned to benefit from higher power and capacity prices in the Midwest. We also expect these same factors will benefit our combined-cycle units throughout the country through increased run-times and/or higher power prices as heat rates expand resulting in improved margins and cash flows.

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 bid 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 and PJM facilities.

PJM Segment

Our PJM segment is comprised of 23 power generation facilities located in Ohio (11), Pennsylvania (5), Illinois (4), Virginia (1), West Virginia (1) and New Jersey (1), totaling 13,510 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 2019-2020, which ends May 31, 2020. We also enter into bilateral capacity transactions. Beginning with Planning Year 2016-2017, PJM has started to transition to Capacity Performance (“CP”) rules. Full transition of the capacity market to these new rules will occur by Planning Year 2020-2021. 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. 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:



	2016-2017	2017-2018	2018-2019	2019-2020	2020-2021
Planning Reserve Margin (%)	15.6	15.7	15.7	16.5	16.6

NY/NE Segment

Our NY/NE segment is comprised of 11 power generation facilities located in Massachusetts (7), Connecticut (2), Maine (1) and New York (1), totaling 6,543 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. The actual amount of installed capacity is approximately seven percentage points above NYISO’s current Planning Reserve Margin. Planning Reserve Margins by Planning Year are as follows:



	2016-2017	2017-2018
Planning Reserve Margin (%)	17.4	18.1

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:



	2017-2018	2018-2019	2019-2020	2020-2021
ICR (%)	15.1	15.0	15.0	15.1

ERCOT Segment

Our ERCOT segment, new in 2017 as a result of the Delta Transaction, is comprised of six power generation facilities located in Texas, totaling 4,696 MW of electric generating capacity. Our ERCOT fleet is comprised of 3,976 MW of natural gas powered combined-cycle generation, 635 MW of Powder River Basin coal powered generation, and 85 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 2016 Capacity, Demand and Reserves (“CDR”) report, the Target Reserve Margin is 13.75 percent through 2021.

MISO & IPH Segments

Our MISO segment is comprised of three power generation facilities located in Illinois, totaling 1,913 MW of electric generating capacity. Beginning June 1, 2017, Hennepin will pseudo-tie and offer energy and capacity for 260 MW, or 14 percent of our MISO segment’s current capacity and energy, into PJM.

Our IPH segment is comprised of five coal-fired power generation facilities located in Illinois with a total generating capacity of 3,563 MW, and primarily operates in MISO. 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 IPH segment generating capacity and energy into PJM. As of June 1, 2016, our Coffeen, Duck Creek, E.D. Edwards and Newton facilities have 937 MW, or 26 percent of IPH’s current capacity and energy, electrically tied into PJM through pseudo-tie arrangements. IPH has secured firm transmission to export into PJM from our Joppa facility beginning June 1, 2017. As of June 1, 2017, IPH will have the capability to offer another 240 MW of capacity and energy into PJM for a total of 1,177 MW.

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:



	2017-2018	2018-2019	2019-2020	2020-2021	2021-2022
Planning Reserve Margin (%)	15.8	15.6	15.3	15.4	15.5

CAISO Segment

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

RTO/ISO Discussion

The CAISO market covers approximately 90 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 Standard 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.

Reserve Margins

The CPUC 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, Illinois Power Marketing Company (“IPM”), 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 2016, we filed a market power update with FERC for our CAISO assets.

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 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 17—Commitments and Contingencies for further discussion.

Our aggregate expenditures (both capitalized and those included in operating expense) by segment for compliance with laws and regulations related to the protection of the environment were as follows for the years ended December 31, 2016 and 2015:



	Year Ended December 31,
	2016						2015
(amounts in millions)	Total Expenditures		Capital Expenditures		Operating Expenses		Total Expenditures		Capital Expenditures		Operating Expenses
PJM	$	62	$	6	$	56	$	38	$	2	$	36
NY/NE	17		—		17		11		—		11
MISO	20		1		19		19		3		16
IPH	41		16		25		46		22		24
CAISO	5		—		5		2		—		2
Other	11		—		11		12		—		12
Total	$	156	$	23	$	133	$	128	$	27	$	101

Our estimated total expenditures, including capital expenditures and operating expenses, by segment for environmental compliance in 2017 are as follows (does not include Delta Transaction):



(amounts in millions)	Total Expenditures		Capital Expenditures		Operating Expenses
PJM	$	101	$	23	$	78
NY/NE	14		—		14
MISO	45		27		18
IPH	45		10		35
CAISO	5		—		5
Other	5		—		5
Total	$	215	$	60	$	155

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 (“SO ₂ ”) 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.

Multi-Pollutant Air Emission Initiatives

Cross-State Air Pollution Rule. The “Cross-State Air Pollution Rule” (“CSAPR”) to reduce emissions of SO ₂ 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 SO ₂ 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 (“PM2.5”) NAAQS.

Under the CSAPR, our generating facilities in Illinois, Ohio, New Jersey, New York, Pennsylvania, Texas 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 SO ₂ and NO _x . The CSAPR requirements applicable to SO ₂ emissions from our affected EGUs will be implemented in two stages with fewer SO ₂ emission allowances allocated in the second phase, which begins in 2017. In September 2016, the EPA issued a CSAPR update rule.

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, unless an extension was granted in accordance with the CAA. 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. Petitions for judicial review have been filed.

We are in compliance with the MATS rule emission limits and continue to monitor the 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 , SO ₂ and mercury emissions limits. We are in compliance with the MPS.

IPH Variance. The MPS SO ₂ limits started in 2010 for our IPH coal-fired facilities and would have declined in 2014 and 2015 and required compliance with the final SO ₂ limit beginning in 2017. However, the IPCB granted IPH a variance which provided additional time for economic recovery and related power price improvements necessary to support the installation of

FGD systems at the Newton facility such that the IPH coal-fired fleet can meet the MPS system-wide SO ₂ limit. In December 2015, the EPA approved the variance as part of the Illinois regional haze state implementation plan (“SIP”).

On September 2, 2016, IPH and Ameren Energy Medina Valley Cogen, LLC filed a motion with the IPCB to terminate the variance. On October 27, 2016, the IPCB granted the motion to terminate the variance.

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 ozone, SO ₂ and PM2.5. Each state is responsible for developing a plan (a SIP) that will attain and maintain the NAAQS. These plans may result in the imposition of emission limits on our facilities.

The EPA’s initial area designations for the 2010 one-hour SO ₂ NAAQS included designating as nonattainment the area where our IPH segment’s Edwards facility is located. In January 2015, Illinois Power Resources Generating, LLC (“IPRG”) entered a Memorandum of Agreement (“MOA”) with the Illinois EPA (“IEPA”) that voluntarily committed to early limits on Edwards’ allowable one-hour SO ₂ 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 SO ₂ 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.

The EPA will complete area designations for the 2010 one-hour SO ₂ NAAQS in up to three additional rounds over the period July 2016 to December 31, 2020. In July 2016, the EPA designated as unclassifiable/attainment the areas of our Newton, Hennepin, Joppa and Wood River facilities and our co-owned Zimmer facility.

The EPA issued a final rule in October 2015 lowering the ozone NAAQS from 75 to 70 parts per billion. The EPA anticipates designating attainment and nonattainment areas for the 2015 ozone NAAQS by October 2017. Various parties have filed lawsuits challenging the 2015 ozone NAAQS. In November 2016, the State of Maryland petitioned the EPA under CAA section 126 to impose additional NO _x emission control requirements on 36 EGUs in five upwind states, including our co-owned Zimmer facility, that the State alleges are contributing to nonattainment with the 2008 ozone NAAQS in Maryland. The EPA is required to act on the petition by July 15, 2017. In January 2017, the EPA proposed to deny a petition from nine northeastern states to add several states, including Illinois and Ohio, to the Ozone Transport Region.

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 nature and scope of potential future requirements concerning the 2010 one-hour SO ₂ 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.

Wood River CAA Section 114 Information Request. In 2014, we received an information request from the EPA concerning our Wood River facility’s compliance with the Illinois SIP and associated permits. We responded to the EPA’s request and believe that there are no issues with Wood River’s compliance, but we are unable to predict the EPA’s response, if any. As of June 1, 2016, our Wood River facility has been retired.

acid mist and heat input. The NOVs remain unresolved. In December 2014, the EPA also issued NOVs alleging violations of opacity standards at the Stuart and Killen facilities, which we jointly own but do not operate.

Coleto Creek Regional Haze/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 Coleto Creek to meet an SO ₂ 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, including motions to stay the FIP, in federal court. In July 2016, the United States Court of Appeals for the Fifth Circuit stayed the FIP pending completion of judicial review. The EPA subsequently requested a voluntary remand of the challenged portions of the FIP.

In January 2017, the EPA proposed a FIP for Texas that would impose Best Available Retrofit Technology (“BART”) emission limits for SO ₂ 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 SO ₂ 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.

Edwards CAA Citizen Suit . In April 2013, environmental groups filed a CAA citizen suit in the U.S. District Court for the Central District of Illinois alleging violations of opacity and particulate matter limits at our IPH segment’s Edwards facility. In August 2016, the District Court granted the plaintiffs’ motion for summary judgment on certain liability issues. We filed a motion seeking interlocutory appeal of the court’s summary judgment ruling. In February 2017, the appellate court denied our motion for interlocutory appeal. The District Court has not yet scheduled the remedy phase of the case. 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.

At this time, we estimate the cost of our compliance with the cooling water intake structure rule (excluding Delta Transaction) 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 $10 million in aggregate through 2020.

Effluent Limitation Guidelines. In September 2015, the EPA issued a final rule revising the ELG for steam electric power generation units. The ELG final rule establishes new or additional requirements for wastewater streams associated with steam electric power generation processes and byproducts. For EGUs greater than 50 MW, the final rule establishes a zero discharge standard for bottom ash transport water, fly ash transport water and flue gas mercury control wastewater. The rule also establishes effluent limits for flue gas desulfurization wastewaters. Various industry and environmental groups have filed petitions for judicial review of the ELG final rule.

We have evaluated the ELG final rule and at this time, we estimate the cost of our compliance with the ELG rule to be approximately $308 million . The majority of ELG compliance expenditures are expected to occur in the 2017-2023 timeframe. As planning and work progress, we continue to review our estimates as well as timing of our capital expenditures. The following table presents the projected capital expenditures by period for ELG compliance as of December 31, 2016 (does not include Delta Transaction):



(amounts in millions)	Less than 1 Year		1 - 3 Years		3 - 5 Years		More than 5 Years		Total
PJM segment	$	11	$	45	$	49	$	40	$	145
MISO segment	24		45		—		—		69
IPH segment	6		88		—		—		94
Total ELG expenditures	$	41	$	178	$	49	$	40	$	308

NPDES Permits. We are currently appealing certain requirements in the renewal NPDES permits at several of our facilities, including Joppa and Coffeen.

In January 2013, the Ohio EPA reissued the NPDES permit for the jointly owned Stuart facility. The operator of Stuart, The Dayton Power and Light Company, appealed various aspects of the permit, including provisions regarding thermal discharge limitations, to the Ohio Environmental Review Appeals Commission. Depending on the outcome of the appeal, the effects on Stuart’s operations could be material. At this time we are unable to make a reasonable estimate of the possible costs, or range of costs, that might be incurred to resolve this matter.

Coal Combustion Residuals

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 Coal Combustion Residuals (“CCR”) surface impoundment. At present, CCR is regulated by the states as solid waste.

EPA CCR Rule. The EPA’s CCR rule establishes minimum federal criteria that owners or operators of regulated CCR units must meet without the engagement of a state or federal regulatory authority. The CCR rule, which took effect in October 2015, establishes 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 have been filed.

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. At this time, we estimate the cost of our compliance will be approximately $234 million with the majority of the expenditures in the 2017-2023 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 Groundwater. In 2012, the IEPA issued violation notices alleging violations of groundwater standards onsite at our Baldwin and Vermilion facilities.

At Baldwin, with approval of the IEPA, we performed a comprehensive evaluation of the Baldwin CCR surface impoundment system beginning in 2013. Based on the results of that evaluation, we recommended to the IEPA in 2014 that the closure process for the inactive east CCR surface impoundment begin and that a geotechnical investigation of the existing soil cap on the inactive old east CCR surface impoundment be undertaken. We also submitted a supplemental groundwater modeling report that indicates no known offsite water supply wells will be impacted under the various Baldwin CCR surface impoundment closure scenarios modeled. In 2016, the IEPA approved our closure and post-closure care plans for the Baldwin old east, east, and west fly ash CCR surface impoundments. We are working towards implementation of the closure plan.

At our retired Vermilion facility, which is not subject to the CCR rule, we submitted proposed corrective action plans for two CCR surface impoundments (i.e., the old east and the north CCR surface impoundments) to the IEPA in 2012. Our hydrogeological investigation indicates that these two CCR surface impoundments impact groundwater quality onsite and that such groundwater migrate offsite to the north of the property and to the adjacent Middle Fork of the Vermilion River. The proposed corrective action plans recommend closure in place of both CCR surface impoundments and include an application to the IEPA to establish a groundwater management zone while impacts from the facility are mitigated. In 2014, we submitted a revised corrective action plan for the old east CCR surface impoundment. We await IEPA action on our proposed corrective action plans. Our estimated cost of the recommended closure alternative for both the Vermilion old east and north CCR surface impoundments, including post-closure care, is approximately $10 million .

If remediation measures concerning groundwater are necessary in the future at either Baldwin or Vermilion, we may incur significant costs that could have a material adverse effect on our financial condition, results of operations and cash flows. At this time we cannot reasonably estimate the costs, or range of costs, of remediation, if any, that ultimately may be required.

IPH Segment Groundwater. Groundwater monitoring results indicate that the CCR surface impoundments at each of the IPH segment facilities potentially impact onsite groundwater. In 2012, the IEPA issued violation notices alleging violations of groundwater standards at the Newton and Coffeen facilities’ CCR surface impoundments. In 2015, we submitted an assessment monitoring report to the IEPA that identifies the Newton facility’s inactive unlined landfill as the likely source of groundwater quality exceedances at the facility’s active CCR landfill. In August 2016, IEPA approved the report. We are monitoring groundwater in accordance with IEPA’s approval.

If remediation measures concerning groundwater are necessary at any of our IPH facilities, IPH may incur significant costs that could have a material adverse effect on its financial condition, results of operations and cash flows. At this time we cannot reasonably estimate the costs, or range of costs, of remediation, if any, that ultimately may be required.

Dam Safety Assessment Reports. In response to the failure at the Tennessee Valley Authority’s Kingston plant, the EPA initiated a nationwide investigation of the structural integrity of CCR surface impoundments in 2009. The EPA assessments found all of our surface impoundments to be in satisfactory or fair condition, with the exception of the surface impoundments at the Baldwin and Hennepin facilities.

In response to the Hennepin report, we made capital improvements to the Hennepin east CCR surface impoundment berms and notified the EPA of our intent to close the Hennepin west CCR surface impoundment. The preliminary estimated cost for closure of the west CCR surface impoundment, including post-closure monitoring, is approximately $5 million, which is reflected in our AROs. We performed further studies needed to support closure of the west CCR surface impoundment, submitted those studies to the IEPA in 2014 and await IEPA action.

In response to the Baldwin report, we notified the EPA in 2013 of our action plan, which included implementation of recommended operating practices and certain recommended studies. In 2014, we updated the EPA on the status of our Baldwin action plan, including the completion of certain studies and implementation of remedial measures and our ongoing evaluation of potential long-term measures in the context of our concurrent evaluation at Baldwin of groundwater corrective actions. At this time, to resolve the concerns raised in the EPA’s assessment report and as a result of the CCR rule, we plan to initiate closure of the Baldwin west fly ash CCR surface impoundment in 2017, which is reflected in our AROs.

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, 2016 (does not include Delta Transaction):



			Projected Obligation by Period
(amounts in millions)	NPV		Less than 1 Year		1 - 3 Years		3 - 5 Years		More than 5 Years		Total
CCR	$	195	$	13	$	69	$	51	$	101	$	234
Non-CCR	92		14		26		44		235		319
Total AROs	$	287	$	27	$	95	$	95	$	336	$	553

________________________________________

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 (“CO ₂ ” and equivalent carbon dioxide “CO _2e ”) and methane. Power generating facilities are a major source of GHG emissions. In 2016, our facilities emitted approximately 71 million tons of CO ₂ . The amounts of CO ₂ 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. In 2010, the EPA issued PSD and Title V Permitting Guidance for Greenhouse Gases, which focuses on steam turbine and boiler efficiency improvements as a reasonable best available control technology (“BACT”) requirement for coal-fired EGUs. 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 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. The Court also invalidated the EPA’s Tailoring Rule but concluded that the EPA may impose BACT requirements on GHG emissions if a facility is subject to BACT for other pollutants. The Court also determined that the EPA may establish a de minimis threshold below which BACT would not be required for GHG emissions, but left it open to the EPA to justify the appropriate threshold. 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 on the basis of 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, 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 expects that by 2030 when the Clean Power Plan is fully implemented, CO ₂ emissions from EGUs will be 32 percent below 2005 levels. States are required to develop plans to achieve interim CO ₂ emission rates reductions phased in over the period 2022 to 2029 and the final CO ₂ rate for their state by 2030. The state-specific CO ₂ 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 EPA’s 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 final rules establishing carbon standards for new, modified and reconstructed EGUs.

The nature and scope of CO ₂ emission reduction requirements that ultimately may be imposed on our facilities as a result of the EPA’s EGU CO ₂ 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. The new Presidential Administration has announced its intent to rescind the Clean Power Plan. We continue to monitor the status of the rule.

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 ninth joint allowance auction in November 2016 with current vintage auction allowances selling at a clearing price of $12.73 per metric ton and 2019 auction allowances selling at a clearing price of $12.73 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 August 2016, the CARB proposed amendments to its cap-and-trade regulations that would, among other things, extend the program beyond 2020 by establishing declining emission caps through 2030 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 2016. The cost of GHG allowances required to operate our units in California during 2016 was approximately $15 million. We estimate the cost of GHG allowances required to operate Moss Landing in California during 2017 will be approximately $17 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 CO ₂ 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 2016, RGGI held its thirty-fourth auction, in which approximately 15 million allowances were sold at a clearing price of $3.55 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.

Our generating facilities in Connecticut, Maine, Massachusetts, and New York emitted approximately 8 million tons of CO ₂ during 2016. The cost of RGGI allowances required to operate these facilities during 2016 was approximately $36 million. We estimate the cost of RGGI allowances required to operate our affected facilities during 2017 will be approximately $29 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 December 2016, Massachusetts proposed rules that would establish an aggregate GHG emission limit for existing and new electricity generating facilities. The proposed rules set facility-specific GHG emissions limits on EGUs, including our Bellingham, Blackstone, Dighton, Masspower and Milford facilities. The emissions limits would take effect beginning in 2018 and the aggregate GHG emission limit would decline each year by 2.5 percent of its 2018 value until 2050. For years 2018-2025, existing facility emissions limits would be determined based on the facility’s average portion of 2013-2015 electrical output.

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 a regional business that is diverse in terms of industry structure. Demand for power may be met by generation capacity based on several competing generation technologies, such as natural gas-fired, coal-fired or nuclear generation, as well as power generating facilities fueled by alternative energy sources, 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, other energy service companies, including retail power companies, and financial institutions in the regions in which we operate. We believe that our ability to compete effectively 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 the reliability of our generating facilities. Our ability to compete effectively will also be impacted by various governmental and regulatory activities designed to reduce GHG emissions and to promote lower emitting generation. For example, regulatory requirements for load-serving entities to acquire a percentage of their energy from renewable-fueled facilities 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 expand renewable energy development. Finally, certain of our competitors are set to receive subsidies from the states of New York and Illinois for their otherwise uneconomic nuclear plants. 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, specifically in NYISO, PJM and MISO.

SIGNIFICANT CUSTOMERS

For the years ended December 31, 2016, 2015 and 2014 , 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, 2016 , 2015 and 2014.



Customer	2016	2015	2014
PJM	32%	28%	N/A
MISO	16%	22%	33%
ISO-NE	10%	N/A	N/A
NYISO	N/A	N/A	14%

EMPLOYEES

At December 31, 2016 , we had approximately 340 employees at our corporate headquarters and approximately 2,117 employees at our facilities, including 219 field-based administrative employees who are part of our support and retail functions. Approximately 1,203 employees at our operating facilities are subject to collective bargaining agreements with various unions. In 2016, we reached an agreement to extend the expiration of the collective bargaining agreements with Local 51 representing our Dynegy Midwest Generation, LLC (“DMG”) facilities located in Illinois. Our collective bargaining agreement with IBEW Local 1347, which represents employees at our Miami Fort and Zimmer facilities, expires on April 1, 2017. We anticipate that we will successfully negotiate a new agreement with this union in the coming months. During 2016, the Company did not experience a labor stoppage or a labor dispute at any of its facilities.

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:


•	beliefs and assumptions about weather and general economic conditions;


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


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


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


•	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 company-wide improvement programs, including our PRIDE initiative;


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


•	efforts to divest assets and the associated timing of such divestitures, and anticipated use of proceeds from such divestitures;


•	anticipated timing, outcome, and impact of the expected retirement of Brayton Point;


•	beliefs about the costs and scope of the ongoing demolition and site remediation efforts at the Vermilion and Wood River facilities and any potential future remediation obligations at the South Bay facility; and


•	expectations regarding the synergies and anticipated benefits of the Delta Transaction.

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 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;


•	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.

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. Retail credit risk results when customers default on their contractual obligations. 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) 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 continuing 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 CO ₂ 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, 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.

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 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.

We may pursue acquisitions or combinations that could be unsuccessful or present unanticipated problems for our business in the future, which would adversely affect our ability to realize the anticipated benefits of those transactions.

We may enter into transactions that include acquiring or combining with other businesses. We may not be able to identify suitable acquisition or combination opportunities or financing to complete any particular acquisition or combination successfully. Furthermore, acquisitions and combinations involve a number of risks and challenges, including:


•	the ability to obtain required regulatory and other approvals;


•	the need to integrate acquired or combined operations with our operations;


•	potential loss of key employees;


•	difficulty in evaluating the assets, operating costs, infrastructure requirements, environmental and other liabilities and other factors beyond our control;


•	potential lack of operating experience in new geographic/power markets or with different fuel sources;


•	an increase in our expenses and working capital requirements;


•	management’s attention may be temporarily diverted; and


•	the possibility that we may be required to issue a substantial amount of additional equity and/or debt securities or assume additional debt in connection with any such transactions.

Any of these factors could adversely affect our ability to achieve anticipated levels of cash flows or realize synergies or other anticipated benefits from a strategic transaction. Furthermore, the market for transactions is highly competitive, which may adversely affect our ability to find transactions that fit our strategic objectives or increase the price we would be required to pay (which could decrease the benefit of the transaction or hinder our desire or ability to consummate the transaction). Consistent with industry practice, we routinely engage in discussions with industry participants regarding potential transactions, large and small. We intend to continue to engage in strategic discussions and will need to respond to potential opportunities quickly and decisively. As a result, strategic transactions may occur at any time and may be significant in size relative to our assets and operations.

Circumstances associated with potential divestitures could adversely affect our results of operations and financial condition.

In evaluating our business and the strategic fit of our various generation assets, we may determine to sell one or more of such assets. Despite a decision to divest an asset, we may encounter difficulty in finding a buyer willing to purchase the asset at an acceptable price and on acceptable terms and in a timely manner. In addition, a prospective buyer may have difficulty obtaining financing. Divestitures could involve additional risks, including:


•	difficulties in the separation of operations and personnel;


•	the need to provide significant ongoing post-closing transition support to a buyer;


•	management’s attention may be temporarily diverted;


•	the retention of certain current or future liabilities in order to induce a buyer to complete a divestiture;


•	the obligation to indemnify or reimburse a buyer for certain past liabilities of a divested asset;


•	the disruption of our business; and


•	potential loss of key employees.

We may not be successful in managing these or any other significant risks that we may encounter in divesting a generation asset, which could adversely affect our results of operations and financial condition.

We may be unable to successfully integrate the operations of the GSENA assets with our existing operations or to realize targeted cost savings, revenues and other anticipated benefits of the Delta Transaction.

The success of the Delta Transaction will depend, in part, on our ability to realize the anticipated benefits and synergies from integrating GSENA’s assets with our existing generation business. To realize these anticipated benefits, the businesses must be successfully combined.

We may be required to make unanticipated capital expenditures or investments in order to maintain, integrate, improve or sustain the assets’ operations, or take unexpected write-offs or impairment charges resulting from the transaction. Further, we may be subject to unanticipated or unknown liabilities relating to the assets. If any of these factors occur or limit our ability to integrate the businesses successfully or on a timely basis, the expectations regarding our future financial condition and results of operations following the transaction might not be met.

In addition, we continue to evaluate our estimates of synergies to be realized from, and refine the fair value accounting allocations associated with, the Delta Transaction. Accordingly, actual cost-savings, the costs required to realize the cost-savings, and the source of the cost-savings could differ materially from our estimates, and we cannot ensure that we will achieve the full amount of cost-savings on the schedule anticipated or at all.

Finally, we may not be able to achieve the targeted operating or long-term strategic benefits of the Delta Transaction. If the combined businesses are not able to achieve our objectives, or are not able to achieve our objectives on a timely basis, the anticipated benefits of the transaction may not be realized fully or at all. An inability to realize the full extent of, or any of, the anticipated benefits of the transaction, as well as any delays encountered in the integration process, could have an adverse effect on our financial condition, results of operations, and cash flows.

Terawatt owns approximately 15 percent of our common stock and may exert influence over matters requiring Board of Directors and/or stockholder approval.

On February 24, 2016, Dynegy entered into a Stock Purchase Agreement (the “PIPE Stock Purchase Agreement”) with Terawatt Holdings, LP (“Terawatt”), an affiliate of certain affiliated investment funds of Energy Capital Partners III, LLC (the “ECP Funds”), pursuant to which on the Delta Transaction Closing Date Dynegy issued to Terawatt 13,711,152 shares of Dynegy common stock (the “PIPE Shares”) for $150 million (the “PIPE Transaction”). Following the issuance, Terawatt beneficially owns approximately 15 percent of the outstanding shares of our common stock. In connection with the closing of the PIPE Transaction, Dynegy and Terawatt entered into an Investor Rights Agreement (the “Terawatt Investor Rights Agreement”). Under the Terawatt Investor Rights Agreement, Terawatt is entitled to certain rights including the right to appoint one member to our Board of Directors. As a result, Terawatt has appointed a director to our Board of directors and, as such, may be able to exercise influence over matters requiring approval by our Board of Directors and our stockholders.

The interests of Terawatt may conflict with the interests of our other stockholders. Terawatt may have an interest in having us pursue, or not pursue, acquisitions, divestitures, and other transactions that, in its judgment, could enhance its investment in us, even though such transactions might involve benefits or risks to other stockholders.

In addition, Terawatt and its affiliates engage in a broad spectrum of activities, including investments in the power generation industry. In the ordinary course of their business activities, Terawatt and its affiliates may engage in activities where their interests conflict with our interests or those of our stockholders. Further, Dynegy has agreed to renounce any interest in a corporate or business opportunity taken by Terawatt or its affiliates, unless such corporate or business opportunity is offered to the member of our Board of Directors appointed by Terawatt in his or her capacity as a director of Dynegy.

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, 2016 , we had approximately $9.1 billion of total indebtedness and approximately $7.3 billion of indebtedness net of cash. This amount excluded Genco’s long-term debt of $825 million which was reclassified to Liabilities subject to compromise in our consolidated balance sheet. 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;


•	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 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. We performed asset impairment analyses of certain of our facilities in 2016 and, as a result, recorded impairment charges of $56 million , $148 million , and $645 million for our Stuart, Newton and Baldwin facilities, respectively. Please read Note 9—Property, Plant and Equipment 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 net operating losses (“NOLs”) and alternative minimum tax (“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 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.

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. Substantially all the power generation facilities of the IPH segment were pledged as collateral to secure repayment of our debt obligations under the Credit Agreement upon the Emergence Date. Please read Note 14—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 17—Commitments and Contingencies —Legal Proceedings for a description of our material legal proceedings, which is incorporated herein by reference.

Item 4. Mine Safety Disclosures

Not applicable.

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 2,436 stockholders of record of our common stock as of February 7, 2017 . We also have 15.6 million five -year warrants outstanding (expiring October 2, 2017) to purchase shares of our common stock (the “2012 Warrants”). Each 2012 Warrant entitles the holder to a maximum of one share of common stock. The exercise price of each 2012 Warrant was set at $40 per warrant.

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 closing price of Dynegy’s common stock on the EquiPower Closing Date. Please read Note 3—Acquisitions for further discussion.

Upon the close of the Delta Transaction, 13,711,152 shares of common stock of Dynegy were issued to Terawatt for $150 million . Please read Note 24—Subsequent Events for further discussion.

On the Emergence Date, 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.

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
2017:
First Quarter (through February 8, 2017)	$	10.42	$	8.29
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
2015:
Fourth Quarter	$	23.70	$	10.02
Third Quarter	$	30.07	$	19.68
Second Quarter	$	34.16	$	29.25
First Quarter	$	31.43	$	26.06

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. The Terawatt Investor Rights Agreement also subjects Terawatt to a customary lock-up period with respect to dispositions of the PIPE Shares (other than dispositions of shares to certain affiliates) for a period of six months after the Delta Transaction Closing Date.

Terawatt is entitled to certain customary registration rights and piggyback registration rights under the Securities Act of 1933, as amended. Within six months of the Delta Transaction Closing Date, Dynegy shall file a resale shelf registration statement covering the PIPE Shares and use its reasonable best efforts to have such shelf registration statement declared effective. 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 Delta Transaction Closing Date.

Stockholder Return Performance Presentation. The following graph compares the cumulative total stockholder return from October 3, 2012, the date our common stock began trading following the Plan Effective Date, through December 31, 2016 , for our current existing common stock, the S&P Midcap 400 index and a customized peer group. Because the value of Legacy Dynegy’s old common stock bears no relation to the value of our existing common stock, the graph below reflects only our current existing common stock. The peer group for the fiscal year ended December 31, 2015, which we refer to as the “Old Peer Group,” is comprised of Calpine Corp., NRG Energy Inc. and Talen Energy Corporation (“Talen Energy”). The peer group for the fiscal years ended December 31, 2016, 2014 and prior periods, which we refer to as the “New Peer Group,” is comprised of Calpine Corp. and NRG Energy Inc.

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 October 3, 2012 through December 31, 2016 .



	October 3, 2012		December 31, 2012		December 31, 2013		December 31, 2014		December 31, 2015		December 31, 2016
Dynegy Inc.	$	100.00	$	99.12	$	111.50	$	157.25	$	69.43	$	43.83
S&P Midcap 400	$	100.00	$	104.44	$	139.42	$	153.04	$	149.71	$	180.76
Old Peer Group (1)	$	100.00	$	102.88	$	118.36	$	122.99	$	67.51	$	68.56
New Peer Group	$	100.00	$	102.88	$	118.36	$	122.99	$	67.51	$	61.05

__________________________________________


(1)	Talen Energy was added to Dynegy’s peer group for the fiscal year ended December 31, 2015. However, Talen was acquired in 2016 and thus removed from the 2016 peer group. With the exception of fiscal year ended December 31, 2015, the peer group was based upon the “New Peer Group”.

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, 2016 .

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.

Item 6. Selected Financial Data

The selected financial information presented below as of December 31, 2016 and 2015 and for the years ended December 31, 2016, 2015 and 2014 , 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.”

As a result of the application of fresh-start accounting as of October 1, 2012, following our reorganization, the financial statements on or prior to October 1, 2012 are not comparable with the financial statements after October 1, 2012. References to “Successor” refer to the Company after October 1, 2012, after giving effect to the application of fresh-start accounting. References to “Predecessor” refer to the Company on or prior to October 1, 2012.



	Successor															Predecessor
	Year Ended December 31, 2016			Year Ended December 31, 2015 (1)			Year Ended December 31, 2014			Year Ended December 31, 2013 (2)			October 2 Through December 31, 2012			January 1 Through October 1, 2012
(in millions, except per share data)	Year Ended December 31, 2016			Year Ended December 31, 2015 (1)			Year Ended December 31, 2014			Year Ended December 31, 2013 (2)			October 2 Through December 31, 2012			January 1 Through October 1, 2012
Statements of Operations Data:
Revenues	$	4,318		$	3,870		$	2,497		$	1,466		$	312		$	981
Impairments	$	(858	)	$	(99	)	$	—		$	—		$	—		$	—
General and administrative expense	$	(161	)	$	(128	)	$	(114	)	$	(97	)	$	(22	)	$	(56	)
Operating income (loss)	$	(640	)	$	64		$	(19	)	$	(318	)	$	(104	)	$	5
Bankruptcy reorganization items, net	$	(96	)	$	—		$	3		$	(1	)	$	(3	)	$	1,037
Interest expense	$	(625	)	$	(546	)	$	(223	)	$	(108	)	$	(16	)	$	(120	)
Income tax benefit	$	45		$	474		$	1		$	58		$	—		$	9
Income (loss) from continuing operations	$	(1,244	)	$	47		$	(267	)	$	(359	)	$	(113	)	$	130
Net income (loss) attributable to Dynegy Inc.	$	(1,240	)	$	50		$	(273	)	$	(356	)	$	(107	)	$	(32	)
Basic earnings (loss) per share attributable to Dynegy Inc. common stockholders	$	(9.78	)	$	0.22		$	(2.65	)	$	(3.56	)	$	(1.07	)	N/A
Cash Flow Data:
Net cash provided by (used in) operating activities	$	676		$	94		$	163		$	175		$	(44	)	$	(37	)
Net cash provided by (used in) investing activities	$	(2,147	)	$	(1,194	)	$	(5,262	)	$	474		$	265		$	278
Net cash provided by (used in) financing activities	$	2,742		$	(265	)	$	6,126		$	(154	)	$	(328	)	$	(184	)
Capital expenditures, acquisitions and investments	$	(326	)	$	(6,353	)	$	(132	)	$	136		$	(46	)	$	193
Interest paid	$	558		$	503		$	129		$	94		$	36		$	101



	December 31,
(amounts in millions)	2016		2015		2014		2013		2012
Balance Sheet Data:
Current assets	$	2,987	$	1,932	$	2,664	$	1,682	$	1,043
Current liabilities	$	916	$	809	$	678	$	718	$	347
Property, plant and equipment, net	$	7,121	$	8,347	$	3,255	$	3,315	$	3,022
Total assets	$	13,053	$	11,459	$	11,154	$	5,264	$	4,535
Long-term debt (including current portion) (3)(4)	$	8,979	$	7,209	$	7,028	$	1,965	$	1,415
Total equity	$	2,039	$	2,919	$	3,023	$	2,207	$	2,503

__________________________________________


(1)	Our 2015 financial statements only reflect the impacts of the EquiPower and Duke Midwest Acquisitions (collectively, the “Acquisitions”) subsequent to April 1, 2015 and April 2, 2015, respectively. Please read Note 3—Acquisitions for further discussion.


(2)	We completed the acquisition of New Ameren Energy Resources, LLC (“AER”) effective December 2, 2013; therefore, the results of our IPH segment are only included subsequent to December 1, 2013.


(3)	The year ended December 31, 2016 includes a $2.0 billion seven-year Tranche C Term Loan related to the Delta Transaction. The year ended December 31, 2014 includes $5.1 billion related to our Notes issued on October 27, 2014. Please read Note 14—Debt for further discussion.


(4)	As a result of the Genco Chapter 11 Bankruptcy case, we reclassified approximately $825 million in long-term debt to Liabilities subject to compromise in our consolidated balance sheet. Please read Note 22—Genco Chapter 11 Bankruptcy for further discussion.

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 31,000 MW of generating capacity in twelve states and also provide retail electricity to 963,000 residential customers and 42,000 commercial, industrial, and municipal customers in Illinois, Ohio, and Pennsylvania. We report the results of our power generation business as five separate segments in our consolidated financial statements: (i) PJM, (ii) NY/NE, (iii) MISO, (iv) IPH and (v) CAISO. Upon the Delta Transaction Closing Date, we added the ERCOT segment to our reporting structure.

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;


•	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;


•	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.

We have used a significant portion of our balance sheet capacity to finance our previous acquisitions as we have transformed our fleet. We are now strongly focused on strengthening our balance sheet, managing debt and improving our leverage profile through debt reduction primarily from operating cash flows, PRIDE initiatives, and select asset sales.

Liquidity. The following table summarizes our liquidity position at December 31, 2016 and February 7, 2017 and excludes amounts classified as restricted cash.



	December 31, 2016									February 7, 2017 (2)
(amounts in millions)	Dynegy Inc.			IPH (1)			Consolidated			Consolidated
Revolving facilities and LC capacity (3)	$	1,480		$	44		$	1,524		$	1,650
Less:
Outstanding revolver amount	—			—			—			(300		)
Outstanding LCs	(357		)	(25		)	(382		)	(422		)
Revolving facilities and LC availability	1,123			19			1,142			928
Cash and cash equivalents	1,692			84			1,776			532
Total available liquidity	$	2,815		$	103		$	2,918		$	1,460

__________________________________________


(1)	Includes Cash and cash equivalents of $64 million related to Genco, which was operating as debtor-in-possession in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. Please read Note 22—Genco Chapter 11 Bankruptcy for further discussion.


(2)	The seller in the Delta Transaction provides certain transition credit support through February 7, 2019, and we will use the LC availability as this support terminates.


(3)	Dynegy Inc. includes $1.425 billion in senior secured revolving credit facilities and $55 million related to an LC. IPH consists of $44 million related to IPM LCs. The IPM LCs are collateralized by cash, and as of December 31, 2016 , IPM had $19 million deposited with the issuing banks. Please read Note 14—Debt —Letter of Credit Facilities for further discussion.

Liquidity Highlights:


•	March 2016 - Raised $198 million through a PJM Forward Capacity Agreement.


•	June 2016 - Issued $460 million of Tangible Equity Units (“TEUs”). Net proceeds received of $443 million.


•	June 2016 - Entered into new $2.0 billion, seven-year term loan. Proceeds were placed into escrow until the Delta Transaction Closing Date. Recorded as restricted cash as of December 31, 2016 .

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•	June 2016 - Amended credit agreement (Third Amendment) to increase revolver capacity by $75 million, and add a $2.0 billion Tranche C Term Loan, which was effective upon the Delta Transaction Closing Date.


•	October 2016 - Issued $750 million of the 2025 Senior Notes through a private placement.


•	November 2016 - Sold our 50% interest in the Elwood Facility for $173 million. $35 million of posted collateral also returned to Dynegy.


•	December 2016 - Repaid $550 million of existing Term Loan B, leaving remaining balance of $224 million.


•	January 2017 - Amended credit agreement (Fourth Amendment) to increase revolver capacity by $45 million and extend maturity date to 2021, which was effective upon the Delta Transaction Closing Date.


•	February 2017 - Amended credit agreement (Fifth Amendment) to increase the Tranche C Term Loan amount (June 2016) by $224 million and to reduce interest rate by 75 basis points, which was effective upon the Delta Transaction Closing Date. This is expected to save Dynegy approximately $100 million in interest costs over the next seven years.


•	February 2017 - Entered into new $50 million letter of credit, which was effective upon the Delta Transaction Closing Date.


•	February 2017 - Genco emerged from bankruptcy. We exchanged $757 million of the Genco Senior Notes for $113 million cash, $182 million in Dynegy Senior Notes and 8.7 million 2017 Warrants.


•	February 2017 - Closed the Delta Transaction for a base purchase price of $3.3 billion in cash.


•	February 2017 - Paid ECP $375 million for the ECP Buyout Price.


•	February 2017 - Issued 13,711,152 common shares to Terawatt Holdings, LP for $150 million.

Cash Flows

The following table presents net cash from operating, investing and financing activities for the years ended December 31, 2016, 2015 and 2014 :



	Year Ended December 31,
(amounts in millions)	2016			2015			2014
Net cash provided by operating activities	$	676		$	94		$	163
Net cash used in investing activities	$	(2,147	)	$	(1,194	)	$	(5,262	)
Net cash provided by (used in) financing activities	$	2,742		$	(265	)	$	6,126

Operating Activities

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 operation of 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	422
Decrease in legal settlement received in 2015	(17		)
	$	582

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Changes in net cash provided by operating activities for the year ended December 31, 2015 compared to December 31, 2014 were primarily due to:



	(in millions)
Increase in cash provided by operation of our power generation facilities and retail operations	$	437
Increase in interest payments on our various debt agreements	(297		)
Increase in payments for acquisition-related costs	(91		)
Decrease in cash provided by changes in working capital and other	(135		)
Legal settlement received in 2015	17
	$	(69	)

Future Operating Cash Flows . Our future operating cash flows will vary based on a number of factors, many of which are beyond our control, including the price of power, the prices of natural gas, coal, and fuel oil and their correlation to power prices, collateral requirements, the value of capacity and ancillary services, the run-time of our generating facilities, the effectiveness of our commercial strategy, legal, environmental and regulatory requirements, and our ability to achieve the cost savings contemplated in our “PRIDE Energized” initiative. Additionally, our future operating cash flows will also be impacted by the operations of the plants acquired in the Delta Transaction, and the interest on the related financing.

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 by legal entity at December 31, 2016 and 2015 :



(amounts in millions)	December 31, 2016		December 31, 2015
Dynegy Inc.:
Cash (1)	$	99	$	159
LCs	357		475
Total Dynegy Inc.	456		634

IPH:
Cash (1) (2)	25		11
LCs	25		45
Total IPH	50		56

Total	$	506	$	690

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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, 2016 and 2015 , $54 million and $106 million , respectively, of cash posted as collateral were netted against Liabilities from risk management activities in our consolidated balance sheets.


(2)	Includes cash of $8 million and $1 million related to Genco as of December 31, 2016 and 2015 , respectively.

Collateral postings decreased from December 31, 2015 to December 31, 2016 primarily due to reduced collateral requirements for exchange-traded commodity contracts, reduced collateral for tolls, and release of collateral related to jointly owned facilities. The fair value of our derivatives collateralized by first priority liens included liabilities of $136 million and $167 million at December 31, 2016 and 2015 , respectively.

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Investing Activities

Historical Investing Cash Flows. 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)
Restricted cash primarily related to the issuance of the Tranche C Term Loan and original issuance discount	$	(2,021	)
Decrease in cash paid for the Duke/ECP acquisitions in 2015	930
Increase in proceeds from asset sales, primarily related to the sale of our unconsolidated investment in Elwood	176
Increase in capital expenditures	(51		)
Increase in distributions received from our unconsolidated investment in Elwood and other investing activity	13
	$	(953	)

Changes in net cash used in investing activities for the year ended December 31, 2015 compared to December 31, 2014 were primarily due to:



	(in millions)
Release of restricted cash as a result of closing the Duke/ECP acquisitions in 2015	$	5,148
Cash paid for the Duke/ECP acquisitions	(930		)
Increase in capital expenditures	(143		)
Decrease in proceeds from asset sales, primarily related to the sale of Black Mountain in 2014	(18		)
Distributions received from our unconsolidated investment in Elwood and other investing activity	11
	$	4,068

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



	Year Ended December 31,						Estimated
(amounts in millions)	2016		2015		2014		2017 (2)(3)
PJM	$	180	$	93	$	24	$	134
NY/NE	79		41		2		83
ERCOT	—		—		—		117
MISO	12		56		39		34
IPH	40		63		45		76
CAISO	5		9		18		35
Other	10		13		4		11
Total (1)	$	326	$	275	$	132	$	490

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(1)	Includes capitalized interest of $10 million , $12 million , and $9 million for the years ended December 31, 2016, 2015 and 2014 , respectively.


(2)	Includes estimated expenditures of $186 million for the newly acquired assets related to the Delta Transaction.


(3)	Total 2017 includes approximately $96 million of timing impacts (cash prepayments and/or cash deferrals) due to contractual service agreements.

Capital spending in our PJM, MISO, and IPH segments primarily consisted of environmental and maintenance capital projects. Capital spending in our NY/NE and CAISO segments primarily consisted of only maintenance capital projects.

Future Investing Cash Flows. Capital expenditures for 2017 are noted above. The capital budget is subject to revision as opportunities arise or circumstances change. Additionally, our future investing cash flows will be reduced by funds used for the Delta Transaction.

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Financing Activities

Historical Financing Cash Flows. Changes in net cash provided by financing activities for the year ended December 31, 2016 compared to cash used in 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 primarily related the issuance of the Tranche C Term Loan, 2025 Senior Notes and forward capacity agreement	$	2,948
Increase in repayment of borrowings, primarily due to the early paydown of the Tranche B-2 term loan in 2016	(558		)
Increase in proceeds from issuance of equity, net of issuance costs primarily related to TEUs	365
Decrease of repurchases of common stock related to our share repurchase program in 2015	250
Other financing activity	2
	$	3,007

Changes in net cash provided by financing activities for the year ended December 31, 2015 compared to cash provided by financing activities for the year ended December 31, 2014 were primarily due to:



	(in millions)
Decrease in the proceeds from long-term borrowings, net of issuance costs primarily related to the $5.1B Senior Notes issued in 2014	$	(4,989	)
Decrease in proceeds from equity issuances, net of issuance costs primarily related to the Duke/ECP acquisitions	(1,112		)
Increase in repayments associated with our Tranche B-2 Term Loan and inventory financing agreements	(17		)
Repurchases of common stock related to our share repurchase program	(250		)
Dividend payments on our preferred stock issued in October 2014	(23		)
	$	(6,391	)

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, 2016 and 2015 :



(amounts in millions)	December 31, 2016			December 31, 2015
Dynegy Inc.:
Secured obligations (1)	$	2,224		$	780
Unsecured obligations	6,430			5,600
Inventory Financing Agreements	129			136
Equipment Financing Agreements	97			75
Forward Capacity Agreement	219			—
Unamortized discounts and issuance costs	(120		)	(96		)
Genco:
Unsecured obligations (2)	—			825
Unamortized discounts (2)	—			(111		)
Total long-term debt	$	8,979		$	7,209

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(1) At December 31, 2016, the $2 billion Finance IV term loan was secured by a first-priority lien on amounts in the applicable escrow account which was classified as long-term Restricted cash in our consolidated balance sheet. Upon the Delta Transaction Closing Date, this debt obligation became Dynegy Inc.’s general secured obligation. Please read Note 14—Debt for further discussion.


(2)	On December 9, 2016, Genco commenced a prepackaged plan of reorganization under Chapter 11 of the Bankruptcy Code. As a result, we reclassified the Genco unsecured obligations as Liabilities subject to compromise in our consolidated balance sheet as of December 31, 2016. See Note 22—Genco Chapter 11 Bankruptcy for further discussion.

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Future Financing Cash Flows. Our future cash flows from financing activities include:


•	Proceeds from our issuance of our common stock to ECP;


•	Principal payments on our debt instruments;


•	Periodic payments to settle our interest rate swap agreements;


•	Dividend payments on our mandatory convertible preferred stock;


•	Payments towards the ECP Buyout and the Genco Plan; and


•	Draws on our Revolving Facility to fund the Delta Transaction.

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 14—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). Beginning December 31, 2016 and thereafter, the Consolidated Senior Secured Net Debt to Consolidated Adjusted EBITDA ratio is 4.00:1.00. We were in compliance with these covenants as of and for the three year period ended December 31, 2016.

Under the terms of the Credit Agreement, existing balances under our Forward Capacity Agreement, Inventory Financing Agreements, and Equipment Financing Agreements are excluded from Net Debt. Further, the balance of the Tranche C Term Loan is excluded from Net Debt until the closing of the Delta Transaction, whereupon it becomes Dynegy Inc.’s secured obligation.

Please read Note 14—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 pay quarterly dividends on our Mandatory Convertible Preferred Stock on February 1, May 1, August 1, and November 1 of each year, if declared by our Board of Directors. For the years ended December 31, 2016 and 2015 , we paid an aggregate of $22 million and $23 million in dividends, respectively. No dividends were paid during 2014.

On January 3, 2017, our Board of Directors declared a dividend on our Mandatory Convertible Preferred Stock of $1.34 per share, or approximately $5 million in the aggregate. The dividend is for the period beginning on November 1, 2016 and ending on January 31, 2017. Such dividends were paid on February 1, 2017, to stockholders of record as of January 15, 2017.

Credit Ratings

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



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

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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 our operations and financing activities. Contractual obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements. These obligations may result from both general financing activities and from commercial arrangements that are directly supported by related revenue-producing activities. 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, 2016 . The table below does not include interest payment obligations related to the Genco Senior Notes or obligations associated with the Delta Transaction. 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)	$	9,002	$	188	$	2,395	$	264	$	6,155
Interest payments on debt	3,448		584		1,155		832		877
Coal purchase commitments	827		359		342		126		—
Coal transportation	823		101		164		167		391
Contractual service agreements	482		42		163		240		37
Gas purchase commitments	420		411		9		—		—
Gas transportation	173		36		53		37		47
Pension funding obligations	248		7		45		46		150
Operating leases	53		11		10		10		22
Other obligations	85		28		24		7		26
Total contractual obligations	15,561		1,767		4,360		1,729		7,705
Total ELG expenditures (1)	308		41		178		49		40
Total AROs (1)	553		27		95		95		336
Total contractual and other environmental obligations	$	16,422	$	1,835	$	4,633	$	1,873	$	8,081

_______________________________________


(1)	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 2025 Senior Notes, the Credit Agreement, the Finance IV Credit Agreement, the Inventory Financing Agreements, the Forward Capacity Agreement, and the Amortizing Notes. Amounts do not include unamortized discounts. Please read Note 14—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 2025 Senior Notes, the Credit Agreement, the Finance IV Credit Agreement, the Inventory Financing Agreements, and the Amortizing Notes. Amounts include the impact of interest rate swap agreements. Please read Note 14—Debt for further discussion.

Coal Purchase Commitments. At December 31, 2016 , 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.

Coal Transportation. At December 31, 2016 , 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. Recently 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, 2016 , our obligation with respect to these restructured agreements is limited to the termination payments, which are approximately $410

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million in the event all contracts are terminated by us. In addition during this year, we have committed to securing capital spares for our gas-fueled generation fleet to help minimize production disturbances. As of December 31, 2016 , we have obligations to purchase spare parts of $24 million with payments made through 2026, of which $11 million reflects spare parts received. Please read Note 17—Commitments and Contingencies —Other Commitments and Contingencies for further discussion.

Gas Purchase Commitments. At December 31, 2016 , 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 2026 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 2017 which would decrease future funding obligations. Please read Note 19—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. Also included in operating leases is one charter agreement previously utilized in our former global liquids business.

Other Obligations. Other obligations primarily include the following:


•	$31 million related to limestone purchase commitments;


•	$22 million related to interconnection services; and


•	other miscellaneous items which are individually insignificant.

Commitments and Contingencies

Please read Note 17—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, 2016 .

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, 2016, 2015 and 2014 . 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) MISO, (iv) IPH 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.

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 and liquidity. 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.

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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 and certain other costs such as those associated with acquisitions, and (iv) other material items. Beginning in 2016, Adjusted EBITDA also excludes non-cash compensation expense.

We believe EBITDA and Adjusted EBITDA provide meaningful representations of our operating performance. We consider EBITDA as another way to measure financial performance on an ongoing basis. Adjusted EBITDA is meant to reflect the operating performance of our entire power generation fleet for the period presented; consequently, it excludes the impact of mark-to-market accounting, impairment charges and other items that could be considered “non-operating” or “non-core” in nature. Because EBITDA and Adjusted EBITDA are financial measures that management uses to allocate resources, determine our ability to fund capital expenditures, assess performance against our peers, and evaluate overall financial performance, we believe they provide useful information for our investors. In addition, many analysts, fund managers and other stakeholders who communicate with us typically request our financial results in an EBITDA and Adjusted EBITDA format.

As prescribed by the SEC, when EBITDA or Adjusted EBITDA is discussed in reference to performance on a consolidated basis, the most directly comparable GAAP financial measure to EBITDA and Adjusted EBITDA is Net income (loss). Management does not analyze interest expense and income taxes on a segment level; therefore, the most directly comparable GAAP financial measure to EBITDA or Adjusted EBITDA when performance is discussed on a segment level is Operating income (loss).

Adjusted Free Cash Flow. We define Adjusted FCF as cash flow from operating activities adjusted for non-discretionary maintenance and environmental capital expenditures and the cash impact of acquisition-related costs. Adjusted FCF includes receipts or payments related to interest rate swaps, and excludes the impact of changes in collateral, working capital and other receipts and payments. In 2014, Adjusted FCF did not exclude working capital and other charges. The most directly comparable GAAP financial measure is cash flows from operating activities.

Dynegy’s non-GAAP liquidity measure 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 Dynegy’s non-GAAP liquidity measure is useful to investors and the company as a liquidity measure 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, 2016, 2015 and 2014 :



	Year Ended December 31,
(amounts in millions)	2016			2015			2014 (1)
Net cash provided by operating activities	$	676		$	94		$	163
Capital expenditures	(261		)	(225		)	(123		)
Acquisition related payments	73			207			65
Adjustment related to acquired derivatives	47			60			—
Interest rate swap settlement payments	(17		)	(17		)	(18		)
Collateral, working capital and other	(255		)	67			17
Adjusted Free Cash Flow	$	263		$	186		$	104

__________________________________________


(1)	Adjusted FCF for 2014 included working capital and other of $46 million; such amounts were excluded from Adjusted FCF in 2016 and 2015.

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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 —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			Favorable (Unfavorable) $ Change
Revenues
Energy	$	3,373		$	3,054		$	319
Capacity	773			671			102
Mark-to-market income, net	136			127			9
Contract amortization	(80		)	(83		)	3
Other	116			101			15
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	)

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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			IPH			CAISO			Other			Total
Revenues	$	2,202		$	837		$	383		$	754		$	142		$	—		$	4,318
Cost of sales, excluding depreciation expense	(985		)	(486		)	(291		)	(450		)	(69		)	—			(2,281		)
Gross margin	1,217			351			92			304			73			—			2,037
Operating and maintenance expense	(391		)	(165		)	(143		)	(204		)	(36		)	(1		)	(940		)
Depreciation expense	(346		)	(215		)	(49		)	(32		)	(42		)	(5		)	(689		)
Impairments	(65		)	—			(645		)	(148		)	—			—			(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)	(1		)	—			—			(16		)	—			—			(17		)
Operating income (loss)	$	414		$	(29	)	$	(745	)	$	(87	)	$	(5	)	$	(188	)	$	(640	)



	Year Ended December 31, 2015
(amounts in millions)	PJM			NY/NE			MISO			IPH			CAISO			Other			Total
Revenues	$	1,716		$	695		$	482		$	799		$	178		$	—		$	3,870
Cost of sales, excluding depreciation expense	(716		)	(414		)	(287		)	(506		)	(105		)	—			(2,028		)
Gross margin	1,000			281			195			293			73			—			1,842
Operating and maintenance expense	(296		)	(126		)	(174		)	(215		)	(32		)	4			(839		)
Depreciation expense	(281		)	(186		)	(39		)	(29		)	(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	)	$	(92	)	$	49		$	(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			IPH			CAISO			Total
Revenues, net of hedges, attributable to Duke Midwest and EquiPower plants for the first quarter of 2016	$	467		$	194		$	—		$	—		$	—		$	661
Higher (lower) power prices and spark spreads	(66		)	(26		)	(16		)	38			—			(70		)
Higher (lower) generation volumes (1)	122			(64		)	(37		)	(100		)	(39		)	(118		)
Higher (lower) capacity revenues	(36		)	(17		)	10			16			9			(18		)
Change in MTM value of derivative transactions	(61		)	41			(55		)	(8		)	(4		)	(87		)
Lower (higher) contract amortization	9			(4		)	—			12			(3		)	14
Other (2)	51			18			(1		)	(3		)	1			66
Total change in revenues	$	486		$	142		$	(99	)	$	(45	)	$	(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 lower gas prices.

(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			MISO			IPH			CAISO			Total
Cost of sales attributable to Duke Midwest and EquiPower plants for the first quarter of 2016	$	157		$	128		$	—		$	—		$	—		$	285
Lower prices	(95		)	(13		)	(2		)	(11		)	(7		)	(128		)
Higher (lower) generation volumes (1)	133			(23		)	(21		)	(83		)	(19		)	(13		)
Higher (lower) transportation costs (2)	3			(16		)	—			—			(1		)	(14		)
Lower (higher) contract amortization	20			(3		)	6			10			—			33
Other (3)	51			(1		)	21			28			(9		)	90
Total change in cost of sales	$	269		$	72		$	4		$	(56	)	$	(36	)	$	253

_______________________________________


(1)	Lower generation 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 increase d 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 increase d 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 increase d by $759 million due to the following (amounts in millions):



		Year Ended December 31,
Facility	Segment	2016		2015
Stuart	PJM	$	56	$	—
Elwood unconsolidated investment	PJM	9		—
Baldwin	MISO	645		—
Wood River	MISO	—		74
Newton FGD	IPH	148		—
Brayton Point	NY/NE	—		25
Total		$	858	$	99

Please read Note 9—Property, Plant and Equipment for further discussion.

General and Administrative Expense. General and administrative expense increase d by $33 million primarily due to higher overhead associated with the 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 22—Genco Chapter 11 Bankruptcy —Reorganization items for further discussion.

Acquisition and Integration Costs. Acquisition and integration costs decrease d 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 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 22—Genco Chapter 11 Bankruptcy —Reorganization items for further discussion.

Interest Expense. Interest expense increase d by $79 million primarily due to interest on our Tranche C Term Loan, 2025 Senior Notes, and Amortizing Notes. Please read Note 14—Debt for further discussion.

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



	(in millions)
Gain related to the PPE settlement (Note 17)	$	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. The net unfavorable change of $429 million was 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. Please read Note 3—Acquisitions for further discussion of the release of the 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 15—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.

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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			IPH			CAISO			Other			Total
Net loss attributable to Dynegy Inc.																			$	(1,240	)
Loss attributable to noncontrolling interest																			(4		)
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	)	$	(745	)	$	(87	)	$	(5	)	$	(188	)	$	(640	)
Depreciation and amortization expense	349			243			54			33			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			(691		)	(135		)	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		)	49			(2		)	—			(6		)	(95		)
Impairments	65			—			645			148			—			—			858
Loss (gain) on sale of assets, net	—			—			—			(1		)	—			2			1
Non-cash compensation expense	—			—			—			6			—			22			28
Other (1)	5			—			24			(4		)	(1		)	(1		)	23
Adjusted EBITDA	$	757		$	171		$	27		$	102		$	59		$	(109	)	$	1,007

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(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			IPH			CAISO			Other			Total
Net income attributable to Dynegy Inc.																			$	50
Loss attributable to noncontrolling interest																			(3		)
Income tax benefit																			(474		)
Other income and expense, net																			(54		)
Interest expense																			546
Earnings from unconsolidated investments																			(1		)
Operating income (loss)	$	423		$	(56	)	$	(92	)	$	49		$	(8	)	$	(252	)	$	64
Depreciation and amortization expense	275			195			38			35			55			4			602
Earnings from unconsolidated investments	1			—			—			—			—			—			1
Other income and expense, net	(2		)	—			1			—			—			55			54
EBITDA	697			139			(53		)	84			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			(6		)	(10		)	(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		$	27		$	77		$	44		$	(122	)	$	850

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(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			Favorable (Unfavorable) $ Change
Operating Revenues
Energy	$	1,692		$	1,266		$	426
Capacity	398			345			53
Mark-to-market income, net	118			105			13
Contract amortization	(47		)	(47		)	—
Other	41			47			(6		)
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		%
Average Market On-Peak Spark Spreads ($/MWh) (4):
PJM West	$	22.62		$	25.24		$	(2.62	)
AD Hub	$	22.52		$	28.22		$	(5.70	)
Average Market On-Peak Power Prices ($/MWh) (5):
PJM West	$	34.65		$	43.21		$	(8.56	)
AD Hub	$	32.93		$	37.52		$	(4.59	)
Average natural gas price—TetcoM3 ($/MMBtu) (6)	$	1.72		$	2.57		$	(0.85	)

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(1)	Reflects the activity for the period in which the 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 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.


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

Operating income decreased by $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			Favorable (Unfavorable) $ Change
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		%
Average Market On-Peak Spark Spreads ($/MWh) (4):
New York—Zone A	$	24.18		$	27.60		$	(3.42	)
Mass Hub	$	13.80		$	15.23		$	(1.43	)
Average Market On-Peak Power Prices ($/MWh) (5):
Mass Hub	$	35.52		$	48.96		$	(13.44	)
Average natural gas price—Algonquin Citygates ($/MMBtu) (6)	$	3.10		$	4.82		$	(1.72	)

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_______________________________________


(1)	Reflects the activity for the period in which the 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 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.


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

Operating loss decreased by $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			Favorable (Unfavorable) $ Change
Operating Revenues
Energy	$	404		$	458		$	(54	)
Capacity	27			17			10
Mark-to-market income (loss), net	(49		)	6			(55		)
Other	1			1			—
Total operating revenues	383			482			(99		)
Operating Costs
Cost of sales	(291		)	(293		)	2
Contract amortization	—			6			(6		)
Total operating costs	(291		)	(287		)	(4		)
Gross margin	92			195			(103		)
Operating and maintenance expense	(143		)	(174		)	31
Depreciation expense	(49		)	(39		)	(10		)
Impairments	(645		)	(74		)	(571		)
Operating loss	(745		)	(92		)	(653		)
Depreciation and amortization expense	54			38			16
Other income and expense, net	—			1			(1		)
EBITDA	(691		)	(53		)	(638		)
Mark-to-market adjustments	49			(6		)	55
Impairments	645			74			571
Other	24			12			12
Adjusted EBITDA (1)	$	27		$	27		$	—

Million Megawatt Hours Generated	14.4			15.9			(1.5		)
IMA for Coal-Fired Facilities (2)	89		%	87		%
Average Capacity Factor for Coal-Fired Facilities (3)	63		%	61		%
Average Market On-Peak Power Prices ($/MWh) (4):
Indiana (Indy Hub)	$	33.71		$	33.50		$	0.21
Commonwealth Edison (NI Hub)	$	31.98		$	33.98		$	(2.00	)

______________________________________


(1)	2015 is not adjusted for Wood River’s energy margin and O&M costs of $13 million which are excluded in 2016.


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

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Operating loss increased by $653 million primarily due to the following:



	(in millions)
Higher impairment charges on our Baldwin facility in 2016 compared to that on our Wood River facility in 2015	$	(571	)
Lower energy margin, net of hedges, due to lower generation volumes, lower power prices and higher fuel costs	$	(52	)
Change in MTM value of derivative transactions	$	(55	)
Lower O&M costs due to planned shutdowns and fewer planned outages	$	31

Adjusted EBITDA, excluding Wood River, was unchanged from 2015 but was impacted by the following:



	(in millions)
Lower energy margin, net of hedges, due to the following:
Higher fuel costs incurred in 2016 as a result of 2015 coal inventory management efforts and an inventory flyover adjustment	$	(13	)
Lower power prices as a result of mild winter weather	$	(4	)
Lower generation volumes as a result of mild winter weather and shutdowns	$	(8	)
Higher capacity revenues due to higher volumes	$	12
Lower O&M costs due to fewer planned outages	$	12

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IPH Segment

The following table provides summary financial data regarding our IPH 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			Favorable (Unfavorable) $ Change
Operating Revenues
Energy	$	619		$	681		$	(62	)
Capacity	140			124			16
Mark-to-market income, net	2			10			(8		)
Contract amortization	(13		)	(25		)	12
Other	6			9			(3		)
Total operating revenues	754			799			(45		)
Operating Costs
Cost of sales	(471		)	(537		)	66
Contract amortization	21			31			(10		)
Total operating costs	(450		)	(506		)	56
Gross margin	304			293			11
Operating and maintenance expense	(204		)	(215		)	11
Depreciation expense	(32		)	(29		)	(3		)
Impairments	(148		)	—			(148		)
Acquisition and integration costs	8			—			8
Gain on sale of assets, net	1			—			1
Other	(16		)	—			(16		)
Operating income (loss)	(87		)	49			(136		)
Depreciation and amortization expense	33			35			(2		)
Bankruptcy reorganization items	(96		)	—			(96		)
Other income and expense, net	15			—			15
EBITDA	(135		)	84			(219		)
Adjustment to exclude noncontrolling interest	2			3			(1		)
Acquisition, integration and restructuring costs	(8		)	—			(8		)
Bankruptcy reorganization items	96			—			96
Mark-to-market adjustments	(2		)	(10		)	8
Impairments	148			—			148
Gain on sale of assets, net	(1		)	—			(1		)
Non-cash compensation expense	6			—			6
Other	(4		)	—			(4		)
Adjusted EBITDA	$	102		$	77		$	25

Million Megawatt Hours Generated	15.4			18.5			(3.1		)
IMA for IPH Facilities (1)	89		%	89		%
Average Capacity Factor for IPH Facilities (2)	46		%	52		%
Average Market On-Peak Power Prices ($/MWh) (3):
Indiana (Indy Hub)	$	33.71		$	33.50		$	0.21
Commonwealth Edison (NI Hub)	$	31.98		$	33.98		$	(2.00	)

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________________________________________


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


(2)	Reflects actual production as a percentage of available capacity. The calculation excludes CTs.


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

Operating loss for 2016 was $87 million compared to operating income of $49 million for 2015. The $136 million decrease was primarily due to the following:



	(in millions)
Higher capacity revenues due to higher pricing and volumes	$	16
Lower O&M costs primarily due to fewer planned outages	$	11
Impairment charges incurred in 2016	$	(148	)

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



	(in millions)
Higher capacity revenues due to higher pricing and volumes	$	16
Lower O&M costs primarily due to fewer planned outages	$	15

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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			Favorable (Unfavorable) $ Change
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		%
Average Market On-Peak Spark Spreads ($/MWh) (3):
North of Path 15 (NP 15)	$	12.67		$	14.32		$	(1.65	)
Average natural gas price—PG&E Citygate ($/MMBtu) (4)	$	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 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.


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

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Operating loss decreased by $3 million primarily due to lower energy margin, net of hedges, of $7 million primarily due to lower generation volumes.

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

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Consolidated Summary Financial Information— Year Ended December 31, 2015 Compared to Year Ended December 31, 2014



	Year Ended December 31,						Favorable (Unfavorable) $ Change
(amounts in millions)	2015			2014			Favorable (Unfavorable) $ Change
Revenues
Energy	$	3,054		$	2,290		$	764
Capacity	671			293			378
Mark-to-market income (loss), net	127			(28		)	155
Contract amortization	(83		)	(111		)	28
Other	101			53			48
Total revenues	3,870			2,497			1,373
Cost of sales, excluding depreciation expense	(2,028		)	(1,661		)	(367		)
Gross margin	1,842			836			1,006
Operating and maintenance expense	(839		)	(477		)	(362		)
Depreciation expense	(587		)	(247		)	(340		)
Impairments	(99		)	—			(99		)
Gain (loss) on sale of assets, net	(1		)	18			(19		)
General and administrative expense	(128		)	(114		)	(14		)
Acquisition and integration costs	(124		)	(35		)	(89		)
Operating income (loss)	64			(19		)	83
Bankruptcy reorganization items	—			3			(3		)
Earnings from unconsolidated investments	1			10			(9		)
Interest expense	(546		)	(223		)	(323		)
Other income and expense, net	54			(39		)	93
Loss before income taxes	(427		)	(268		)	(159		)
Income tax benefit	474			1			473
Net income (loss)	47			(267		)	314
Less: Net income (loss) attributable to noncontrolling interest	(3		)	6			(9		)
Net income (loss) attributable to Dynegy Inc.	$	50		$	(273	)	$	323

The following tables provide summary financial data regarding our operating income (loss) by segment for the years ended December 31, 2015 and 2014 , respectively:



	Year Ended December 31, 2015
(amounts in millions)	PJM			NY/NE			MISO			IPH			CAISO			Other			Total
Revenues	$	1,716		$	695		$	482		$	799		$	178		$	—		$	3,870
Cost of sales, excluding depreciation expense	(716		)	(414		)	(287		)	(506		)	(105		)	—			(2,028		)
Gross margin	1,000			281			195			293			73			—			1,842
Operating and maintenance expense	(296		)	(126		)	(174		)	(215		)	(32		)	4			(839		)
Depreciation expense	(281		)	(186		)	(39		)	(29		)	(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	)	$	(92	)	$	49		$	(8	)	$	(252	)	$	64

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	Year Ended December 31, 2014
(amounts in millions)	PJM			NY/NE			MISO			IPH			CAISO			Other			Total
Revenues	$	331		$	457		$	605		$	846		$	258		$	—		$	2,497
Cost of sales, excluding depreciation expense	(215		)	(313		)	(346		)	(596		)	(191		)	—			(1,661		)
Gross margin	116			144			259			250			67			—			836
Operating and maintenance expense	(33		)	(39		)	(156		)	(199		)	(51		)	1			(477		)
Depreciation expense	(84		)	(26		)	(51		)	(37		)	(44		)	(5		)	(247		)
Gain on sale of assets, net	—			—			—			—			1			17			18
General and administrative expense	—			—			—			—			—			(114		)	(114		)
Acquisition and integration costs	—			—			—			(16		)	—			(19		)	(35		)
Operating income (loss)	$	(1	)	$	79		$	52		$	(2	)	$	(27	)	$	(120	)	$	(19	)

Discussion of Consolidated Results of Operations

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



(amounts in millions)	PJM			NY/NE			MISO			IPH			CAISO			Total
Revenues, net of hedges, attributable to newly acquired Duke Midwest and EquiPower plants in 2015	$	1,320		$	383		$	—		$	—		$	—		$	1,703
Lower revenues attributable to our legacy plants, including IPH:
Higher (lower) power prices and spark spreads (1)	(237		)	(92		)	10			(83		)	(53		)	(455		)
Higher (lower) generation volumes (1)	251			(17		)	(104		)	(114		)	(33		)	(17		)
Higher capacity revenues	14			27			12			82			3			138
Change in MTM value of derivative transactions	28			12			(38		)	48			3			53
Lower (higher) contract amortization	—			65			—			15			(2		)	78
Expiration of ConEd contract at Independence	—			(97		)	—			—			—			(97		)
Other (2)	9			(43		)	(3		)	5			2			(30		)
Total change in revenues	$	1,385		$	238		$	(123	)	$	(47	)	$	(80	)	$	1,373

_______________________________________


(1)	Decrease at our legacy plants, excluding PJM, due to lower demand in our generation areas as a result of milder temperatures.


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

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



(amounts in millions)	PJM			NY/NE			MISO			IPH			CAISO			Total
Cost of sales attributable to newly acquired Duke Midwest and EquiPower plants in 2015	$	510		$	254		$	—		$	—		$	—		$	764
Lower cost of sales attributable to our legacy plants, including IPH:
Lower prices	(107		)	(148		)	(2		)	(14		)	(59		)	(330		)
Higher (lower) generation volumes	81			(5		)	(54		)	(118		)	(17		)	(113		)
Higher (lower) transportation costs	1			(5		)	—			—			(7		)	(11		)
Lower contract amortization	—			1			—			16			—			17
Other (1)	16			4			(3		)	26			(3		)	40
Total change in cost of sales	$	501		$	101		$	(59	)	$	(90	)	$	(86	)	$	367

_______________________________________


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

Operating and Maintenance Expense. Operating and maintenance expense increase d by $362 million primarily due to $326 million in costs attributable to newly acquired Duke Midwest and EquiPower plants and $36 million in higher costs from our legacy plants as a result of more planned outages.

Depreciation Expense. Depreciation expense increase d by $340 million primarily attributable to newly acquired Duke Midwest and EquiPower plants.

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Impairments . Impairments increase d by $99 million due to charges in 2015 of $74 million at our MISO segment on our Wood River facility and $25 million at our NY/NE segment on our Brayton Point facility. Please read Note 9—Property, Plant and Equipment for further discussion.

Gain (Loss) on Sale of Assets, net. Gain (loss) on sale of assets, net decrease d by $19 million primarily due to a $17 million gain from the sale of our 50 percent ownership interest in Black Mountain in 2014, not repeated in 2015. Please read Note 11—Unconsolidated Investments for further discussion.

General and Administrative Expense. General and administrative expense increase d by $14 million primarily due to higher overhead associated with the Acquisitions and higher legal fees.

Acquisition and Integration Costs. Acquisition and integration costs increase d by $89 million due to $12 million in severance, retention and payroll costs and $48 million in Bridge Loan financing fees related to the Acquisitions in 2015, and $29 million in higher advisory and consulting fees. Please read Note 3—Acquisitions for further discussion.

Earnings from Unconsolidated Investments. Earnings from unconsolidated investments decrease d by $9 million primarily due to $10 million in cash distributions received from Black Mountain in 2014. Please read Note 11—Unconsolidated Investments for further discussion.

Interest Expense. Interest expense increase d by $323 million primarily due to the issuance of debt in October 2014 to finance the Acquisitions. Please read Note 14—Debt for further discussion.

Other Income and Expense, Net. Other income and expense, net increase d by $93 million primarily due to the change in the fair value of our common stock warrants.

Income Tax Benefit. Income tax benefit increased by $473 million primarily due to the release of $453 million of our valuation allowance as a result of increased net deferred tax liabilities related to the EquiPower Acquisition. In addition, we recorded an additional tax benefit of $21 million for discrete items including a state law change in Connecticut and the application of our effective state tax rates for jurisdictions for which we do not record a valuation allowance. Please read Note 3—Acquisitions for further discussion of the release of the valuation allowance.

As of December 31, 2015, 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 15—Income Taxes for further discussion.

Net Income (Loss) Attributable to Noncontrolling Interest. Net income (loss) attributable to noncontrolling interest decrease d by $9 million as a result of changes in our minority shareholder’s 20 percent interest in EEI.

Net income (Loss) Attributable to Dynegy Inc. The $323 million increase was primarily due to a $226 million contribution from newly acquired Duke Midwest and EquiPower plants and income from a $453 million deferred tax valuation allowance release, partially offset by $323 million higher interest expense primarily as a result of the issuance of debt in 2014 to finance the Acquisitions.

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Adjusted EBITDA — Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

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			IPH			CAISO			Other			Total
Net income attributable to Dynegy Inc.																			$	50
Loss attributable to noncontrolling interest																			(3		)
Income tax benefit																			(474		)
Other income and expense, net																			(54		)
Interest expense																			546
Earnings from unconsolidated investments																			(1		)
Operating income (loss)	$	423		$	(56	)	$	(92	)	$	49		$	(8	)	$	(252	)	$	64
Depreciation and amortization expense	275			195			38			35			55			4			602
Earnings from unconsolidated investments	1			—			—			—			—			—			1
Other income and expense, net	(2		)	—			1			—			—			55			54
EBITDA	697			139			(53		)	84			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			(6		)	(10		)	(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		$	27		$	77		$	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 .

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The following table provides summary financial data regarding our Adjusted EBITDA by segment for the year ended December 31, 2014 :



	Year Ended December 31, 2014
(amounts in millions)	PJM			NY/NE			MISO			IPH			CAISO			Other			Total
Net loss attributable to Dynegy Inc.																			$	(273	)
Income attributable to noncontrolling interest																			6
Income tax benefit																			(1		)
Other income and expense, net																			39
Interest expense																			223
Earnings from unconsolidated investments																			(10		)
Bankruptcy reorganization items																			(3		)
Operating income (loss)	$	(1	)	$	79		$	52		$	(2	)	$	(27	)	$	(120	)	$	(19	)
Depreciation and amortization expense	86			82			51			36			49			5			309
Bankruptcy reorganization items	—			—			—			—			—			3			3
Earnings from unconsolidated investments	—			—			—			—			—			10			10
Other income and expense, net	—			—			—			—			—			(39		)	(39		)
EBITDA	85			161			103			34			22			(141		)	264
Adjustment to exclude noncontrolling interest	—			—			—			(6		)	—			—			(6		)
Acquisition and integration costs	—			—			—			16			—			19			35
Bankruptcy reorganization items	—			—			—			—			—			(3		)	(3		)
Mark-to-market adjustments, including warrants	36			(1		)	(44		)	38			(1		)	40			68
Gain on sale of assets, net	—			—			—			—			(1		)	(17		)	(18		)
Other	—			—			3			1			—			3			7
Adjusted EBITDA (1)	$	121		$	160		$	62		$	83		$	20		$	(99	)	$	347

_______________________________________


(1)	Not adjusted for the following items which are excluded in 2016: (i) non-cash compensation expense of $19 million, and (ii) income attributable to Wood River’s energy margin and O&M costs of $37 million .

Adjusted EBITDA increased by $503 million primarily due to a $590 million contribution from newly acquired Duke Midwest and EquiPower plants in 2015. The offsetting $87 million decrease from our legacy plants was driven by lower energy margin, net of hedges, at the MISO, IPH, and CAISO segments primarily due to lower generation volumes as a result of mild temperatures, as well as the expiration of the ConEd contract at Independence at the NY/NE segment. This decrease was partially offset by higher capacity revenues across all segments and higher energy margin, net of hedges, at the PJM segment primarily as a result of higher spark spreads and run times. Please read Discussion of Segment Adjusted EBITDA for further information.

Table of Contents

Discussion of Segment Adjusted EBITDA — Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

PJM Segment

The following table provides summary financial data regarding our PJM segment results of operations for the years ended December 31, 2015 and 2014 , respectively:



	Year Ended December 31,						Favorable (Unfavorable) $ Change
(dollars in millions, except for price information)	2015			2014			Favorable (Unfavorable) $ Change
Operating Revenues
Energy	$	1,266		$	280		$	986
Capacity	345			70			275
Mark-to-market income (loss), net	105			(36		)	141
Contract amortization	(47		)	(2		)	(45		)
Other	47			19			28
Total operating revenues	1,716			331			1,385
Operating Costs
Cost of sales	(771		)	(215		)	(556		)
Contract amortization	55			—			55
Total operating costs	(716		)	(215		)	(501		)
Gross margin	1,000			116			884
Operating and maintenance expense	(296		)	(33		)	(263		)
Depreciation expense	(281		)	(84		)	(197		)
Operating income (loss)	423			(1		)	424
Depreciation and amortization expense	275			86			189
Earnings from unconsolidated investments	1			—			1
Other income and expense, net	(2		)	—			(2		)
EBITDA	697			85			612
Adjustment to reflect Adjusted EBITDA from unconsolidated investment	12			—			12
Mark-to-market adjustments	(58		)	36			(94		)
Other	(2		)	—			(2		)
Adjusted EBITDA	$	649		$	121		$	528

Million Megawatt Hours Generated (1)	40.4			5.8			34.6
IMA (1)(2):
Combined-Cycle Facilities	99		%	98		%
Coal-Fired Facilities	74		%	N/A
Average Capacity Factor (1)(3):
Combined-Cycle Facilities	75		%	38		%
Coal-Fired Facilities	51		%	N/A
Average Market On-Peak Spark Spreads ($/MWh) (4):
PJM West	$	25.24		$	26.82		$	(1.58	)
AD Hub	$	28.22		$	31.94		$	(3.72	)
Average Market On-Peak Power Prices ($/MWh) (5):
PJM West	$	43.21		$	62.71		$	(19.50	)
AD Hub	$	37.52		$	54.86		$	(17.34	)
Average natural gas price—TetcoM3 ($/MMBtu) (6)	$	2.57		$	5.13		$	(2.56	)

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_______________________________________


(1)	Reflects the activity for the period in which the 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 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.


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

Operating income for 2015 was $423 million compared to operating loss of $1 million for 2014. The $424 million increase was primarily due to the following:



	(in millions)
Contribution from newly acquired Duke Midwest and EquiPower plants in 2015	$	375
Remaining increase attributable to our legacy plants:
Higher energy margin, net of hedges, due to higher run times partially offset by lower spark spreads	$	25
Change in MTM value of derivative transactions	$	28
Higher capacity revenues due to higher pricing	$	14

Adjusted EBITDA increased by $528 million primarily due to the following:



	(in millions)
Contribution from newly acquired Duke Midwest and EquiPower plants in 2015	$	510
Remaining increase attributable to our legacy plants:
Higher energy margin, net of hedges, due to the following:
Higher generation volumes due to higher run times	$	40
Lower spark spreads	$	(32	)
Higher capacity revenues due to higher pricing	$	14

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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, 2015 and 2014 , respectively:



	Year Ended December 31,						Favorable (Unfavorable) $ Change
(dollars in millions, except for price information)	2015			2014			Favorable (Unfavorable) $ Change
Operating Revenues
Energy	$	524		$	356		$	168
Capacity	154			148			6
Mark-to-market income, net	2			1			1
Contract amortization	(4		)	(64		)	60
Other	19			16			3
Total operating revenues	695			457			238
Operating Costs
Cost of sales	(410		)	(321		)	(89		)
Contract amortization	(4		)	8			(12		)
Total operating costs	(414		)	(313		)	(101		)
Gross margin	281			144			137
Operating and maintenance expense	(126		)	(39		)	(87		)
Depreciation expense	(186		)	(26		)	(160		)
Impairments	(25		)	—			(25		)
Operating income (loss)	(56		)	79			(135		)
Depreciation and amortization expense	195			82			113
EBITDA	139			161			(22		)
Mark-to-market adjustments	11			(1		)	12
Impairments	25			—			25
Adjusted EBITDA	$	175		$	160		$	15

Million Megawatt Hours Generated (1)	15.7			7.1			8.6
IMA for Combined-Cycle Facilities (1)(2)	98		%	100		%
Average Capacity Factor for Combined-Cycle Facilities (1)(3)	56		%	52		%
Average Market On-Peak Spark Spreads ($/MWh) (4):
New York—Zone A	$	27.60		$	34.64		$	(7.04	)
Mass Hub	$	15.23		$	20.08		$	(4.85	)
Average Market On-Peak Power Prices ($/MWh) (5):
Mass Hub	$	48.96		$	76.97		$	(28.01	)
Average natural gas price—Algonquin Citygates ($/MMBtu) (6)	$	4.82		$	8.13		$	(3.31	)

_______________________________________


(1)	Reflects the activity for the period in which the 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 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.


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

Table of Contents

Operating loss for 2015 was $56 million compared to operating income of $79 million for 2014. The $135 million decrease was primarily due to the following:



	(in millions)
Loss attributable to newly acquired Duke Midwest and EquiPower plants in 2015	$	(145	)
Remaining increase attributable to our legacy plants:
Expiration of the ConEd contract at Independence	$	(97	)
Change in MTM value of derivative transactions	$	12
Higher capacity revenues due to open market sales	$	27
Lower contract amortization	$	64

Adjusted EBITDA increased by $15 million primarily due to the following:



	(in millions)
Contribution from newly acquired Duke Midwest and EquiPower plants in 2015	$	80
Remaining decrease attributable to our legacy plants:
Expiration of the ConEd contract at Independence	$	(97	)
Higher capacity revenues due to open market sales	$	27

Table of Contents

MISO Segment

The following table provides summary financial data regarding our MISO segment results of operations for the years ended December 31, 2015 and 2014 , respectively:



	Year Ended December 31,						Favorable (Unfavorable) $ Change
(dollars in millions, except for price information)	2015			2014			Favorable (Unfavorable) $ Change
Operating Revenues
Energy	$	458		$	552		$	(94	)
Capacity	17			5			12
Mark-to-market income, net	6			44			(38		)
Other	1			4			(3		)
Total operating revenues	482			605			(123		)
Operating Costs
Cost of sales	(293		)	(352		)	59
Contract amortization	6			6			—
Total operating costs	(287		)	(346		)	59
Gross margin	195			259			(64		)
Operating and maintenance expense	(174		)	(156		)	(18		)
Depreciation expense	(39		)	(51		)	12
Impairments	(74		)	—			(74		)
Operating income (loss)	(92		)	52			(144		)
Depreciation and amortization expense	38			51			(13		)
Other income and expense, net	1			—			1
EBITDA	(53		)	103			(156		)
Mark-to-market adjustments	(6		)	(44		)	38
Impairments	74			—			74
Other	12			3			9
Adjusted EBITDA (1)	$	27		$	62		$	(35	)

Million Megawatt Hours Generated	15.9			19.1			(3.2		)
IMA for Coal-Fired Facilities (2)	87		%	88		%
Average Capacity Factor for Coal-Fired Facilities (3)	61		%	72		%
Average Market On-Peak Power Prices ($/MWh) (4):
Indiana (Indy Hub)	$	33.50		$	48.28		$	(14.78	)
Commonwealth Edison (NI Hub)	$	33.98		$	50.60		$	(16.62	)

_______________________________________


(1)	2015 and 2014 are not adjusted for Wood River’s energy margin and O&M costs of $13 million and $37 million respectively, which are excluded in 2016.


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

Table of Contents

Operating loss for 2015 was $92 million compared to operating income of $52 million for 2014. The $144 million decrease was primarily due to the following:



	(in millions)
Lower energy margin, net of hedges, primarily due to lower generation volumes	$	(36	)
Change in MTM value of derivative transactions	$	(38	)
Impairment charges incurred in 2015	$	(74	)

Adjusted EBITDA decreased by $35 million primarily due to the following:



	(in millions)
Lower energy margin, net of hedges, primarily due to lower generation volumes as a result of milder weather	$	(30	)
Higher capacity revenues as a result of higher pricing and volumes	$	12
Higher O&M costs due to planned and unplanned outages	$	(12	)

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IPH Segment

The following table provides summary financial data regarding our IPH segment results of operations for the years ended December 31, 2015 and 2014 , respectively.



	Year Ended December 31,						Favorable (Unfavorable) $ Change
(dollars in millions, except for price information)	2015			2014			Favorable (Unfavorable) $ Change
Operating Revenues
Energy	$	681		$	886		$	(205	)
Capacity	124			42			82
Mark-to-market income (loss), net	10			(38		)	48
Contract amortization	(25		)	(40		)	15
Other	9			(4		)	13
Total operating revenues	799			846			(47		)
Operating Costs
Cost of sales	(537		)	(643		)	106
Contract amortization	31			47			(16		)
Total operating costs	(506		)	(596		)	90
Gross margin	293			250			43
Operating and maintenance expense	(215		)	(199		)	(16		)
Depreciation expense	(29		)	(37		)	8
Acquisition and integration costs	—			(16		)	16
Operating income (loss)	49			(2		)	51
Depreciation and amortization expense	35			36			(1		)
EBITDA	84			34			50
Adjustments to exclude noncontrolling interest	3			(6		)	9
Acquisition, integration and restructuring costs	—			16			(16		)
Mark-to-market adjustments	(10		)	38			(48		)
Other	—			1			(1		)
Adjusted EBITDA	$	77		$	83		$	(6	)

Million Megawatt Hours Generated	18.5			23.7			(5.2		)
IMA for IPH Facilities (1)	89		%	89		%
Average Capacity Factor for IPH Facilities (2)	52		%	68		%
Average Market On-Peak Power Prices ($/MWh) (3):
Indiana (Indy Hub)	$	33.50		$	48.28		$	(14.78	)
Commonwealth Edison (NI Hub)	$	33.98		$	50.60		$	(16.62	)

________________________________________


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


(2)	Reflects actual production as a percentage of available capacity. The calculation excludes CTs.


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

Table of Contents

Operating income for 2015 was $49 million compared to an operating loss of $2 million for 2014 . The $51 million increase was primarily due to the following:



	(in millions)
Higher capacity revenues due to higher MISO and PJM pricing and volumes	$	82
Change in MTM value of derivative transactions	$	48
Acquisition and integration costs incurred in 2014	$	16
Lower energy margin, net of hedges, due to lower power prices and generation volumes	$	(75	)
Lower retail gross margin	$	(10	)

Adjusted EBITDA decreased by $6 million primarily due to the following:



	(in millions)
Lower energy margin, net of hedges, due to the following:
Lower realized power prices as a result of milder weather	$	(67	)
Lower generation volumes as a result of milder weather	$	(8	)
Higher capacity revenues due to higher MISO and PJM pricing and volumes	$	82
Higher O&M costs driven by planned outages	$	(11	)
Lower retail gross margin	$	(10	)

Table of Contents

CAISO Segment

The following table provides summary financial data regarding our CAISO segment results of operations for the years ended December 31, 2015 and 2014 , respectively:



	Year Ended December 31,						Favorable (Unfavorable) $ Change
(dollars in millions, except for price information)	2015			2014			Favorable (Unfavorable) $ Change
Operating Revenues
Energy	$	125		$	216		$	(91	)
Capacity	31			28			3
Mark-to-market income, net	4			1			3
Contract amortization	(7		)	(5		)	(2		)
Other	25			18			7
Total operating revenues	178			258			(80		)
Operating Costs
Cost of sales	(105		)	(191		)	86
Total operating costs	(105		)	(191		)	86
Gross margin	73			67			6
Operating and maintenance expense	(32		)	(51		)	19
Depreciation expense	(48		)	(44		)	(4		)
Gain (loss) on sale of assets, net	(1		)	1			(2		)
Operating loss	(8		)	(27		)	19
Depreciation and amortization expense	55			49			6
EBITDA	47			22			25
Mark-to-market adjustments	(4		)	(1		)	(3		)
Loss (gain) on sale of assets, net	1			(1		)	2
Adjusted EBITDA	$	44		$	20		$	24

Million Megawatt Hours Generated	4.0			4.2			(0.2		)
IMA for Combined-Cycle Facilities (1)	96		%	98		%
Average Capacity Factor for Combined-Cycle Facilities (2)	38		%	46		%
Average Market On-Peak Spark Spreads ($/MWh) (3):
North of Path 15 (NP 15)	$	14.32		$	17.18		$	(2.86	)
Average natural gas price—PG&E Citygate ($/MMBtu) (4)	$	2.99		$	4.85		$	(1.86	)

__________________________________________


(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 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.


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

Table of Contents

Operating loss decreased by $19 million primarily due to lower O&M costs related to the reversal of a legal accrual for station power at Moss Landing and lower plant retirement and remediation costs at Morro Bay.

Adjusted EBITDA increased by $24 million primarily due to the following:



	(in millions)
Higher capacity and tolling revenues due to higher volumes at Moss Landing	$	8
Lower O&M costs related to the reversal of a legal accrual for station power at Moss Landing and lower plant retirement and remediation costs at Morro Bay	$	18

Outlook

We expect that our future financial results will continue to be impacted by market structure and prices for electric energy, capacity, and ancillary services, including pricing at our plant locations relative to pricing at their respective trading hubs, the volatility of fuel and electricity prices, transportation and transmission logistics, weather conditions, and the availability of our plants. Further, there is a trend toward greater environmental regulation of all aspects of our business. As this trend continues, it is possible that we will experience additional costs related to water, air, and coal ash regulations.

The portions of our generation volumes sold, coal requirements contracted, coal requirements priced, and coal transportation requirements contracted, by segment, are discussed below. We look to procure and price additional coal and coal transportation opportunistically. For our gas-fired fleet, we hedge price risk by selling forward spark spreads which involves purchasing the required amount of natural gas at the same time as we sell power. We expect to continue our hedging program for energy over a one- to three-year period using various instruments, including retail sales in our PJM and IPH segments, and in accordance with our risk management policy.

Our Operating Segments

PJM Segment. The PJM segment is comprised of 23 power generation facilities located within the PJM region, with a total generating capacity of 13,510 MW.

In PJM, we are installing a total of 290 MW of uprates, which will be accomplished primarily through upgrades to the hot gas path components of our combined-cycle gas turbines. The uprates started in the Fall of 2015 and are expected to be completed in the Spring of 2017.

PJM introduced its new CP product beginning with the Planning Year 2016-2017 capacity auction. Beginning in Planning Year 2018-2019, PJM introduced Base, 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.

Our Kendall facility has one tolling agreement for 85 MW that expires in 2017. Effective as of the closing of the Delta Transaction, we acquired a 50% non-operating ownership interest in the Sayreville facility. In addition, we use our retail business to hedge a portion of the energy output from our facilities. Dynegy’s portfolio beyond the prompt year is primarily open to benefit from possible future power market pricing improvements.

The following table reflects our hedging activities as of February 7, 2017 :



	2017	2018	2019 to 2021
Generation volumes hedged	82%	37%	4%
Coal requirements contracted (1)	85%	70%	11%
Coal requirements priced (1)	85%	70%	—%
Coal transportation requirements contracted (1)	100%	100%	100%

__________________________________________


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

A new long-term coal transportation agreement for our Kincaid facility was completed in 2015. The contract, which commenced in 2017, reflects a reduction from the 2016 rate.

Table of Contents

PJM Capacity Market . Many of our facilities within PJM are located in subzones, which for capacity pricing purposes can constrain due to lack of transmission, mixed between Eastern Mid-Atlantic Area Council (“EMAAC”), Mid-Atlantic Area Council (“MAAC”), Commonwealth Edison (“COMED”), American Transmission Service, Inc. (“ATSI”), RTO, and PPL Electric Utilities, Corp. (“PPL”). PJM has begun the transition of the PJM capacity market to CP product. On August 26-27, 2015, PJM held a transitional auction to convert up to 60 percent of PJM’s capacity needs for Planning Year 2016-2017 from legacy capacity to CP. On September 3-4, 2015, PJM held a transitional auction to convert 70 percent of PJM’s capacity needs for Planning Year 2017-2018 from legacy capacity to CP. On August 10-14, 2015, PJM held the Base Residual Auction to procure CP for 80 percent and Base for 20 percent of PJM’s capacity needs for the Planning Year 2018-2019. On May 11-17, 2016, PJM held the Base Residual Auction to procure CP for 80 percent and Base for 20 percent of PJM’s capacity needs for the Planning Year 2019-2020. PJM will procure 100 percent CP beginning with Planning Year 2020-2021.

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



	2014-2015		2015-2016		2016-2017				2017-2018				2018-2019				2019-2020
	Legacy Capacity		Legacy Capacity		Legacy Capacity		CP		Legacy Capacity		CP		Base		CP		Base		CP
RTO zone, price per MW-day	$	125.99	$	136.00	$	59.37	$	134.00	$	120.00	$	151.50	$	149.98	$	164.77	$	80.00	$	100.00
MAAC zone, price per MW-day	$	136.50	$	167.46	$	119.13	$	134.00	$	120.00	$	151.50	$	149.98	$	164.77	$	80.00	$	100.00
EMAAC zone, price per MW-day	$	136.50	$	167.46	$	119.13	$	134.00	$	120.00	$	151.50	$	210.63	$	225.42	$	99.77	$	119.77
COMED zone, price per MW-day	$	125.99	$	136.00	$	59.37	$	134.00	$	120.00	$	151.50	$	200.21	$	215.00	$	182.77	$	202.77
ATSI zone, price per MW-day	$	125.99	$	357.00	$	114.23	$	134.00	$	120.00	$	151.50	$	149.98	$	164.77	$	80.00	$	100.00
PPL zone, price per MW-day	$	136.50	$	167.46	$	119.13	$	134.00	$	120.00	$	151.50	$	75.00	$	164.77	$	80.00	$	100.00

Our capacity sales, net of purchases, aggregated by Planning Year and capacity type through Planning Year 2019-2020, are as follows:



	2016-2017	2017-2018	2018-2019	2019-2020
Legacy/Base auction capacity sold, net (MW)	4,123	3,763	2,172	1,722
CP auction capacity sold, net (MW)	6,703	7,859	8,526	9,046
Bilateral capacity sold, net (MW)	85	—	295	200
Total segment capacity sold, net (MW)	10,911	11,622	10,993	10,968
Average price per MW-day	$120.35	$141.49	$179.06	$128.85

NY/NE Segment. The NY/NE segment is comprised of 11 power generation facilities located within the ISO-NE (5,331 MW) and NYISO (1,212 MW) regions, totaling 6,543 MW of electric generating capacity.

In New England, at our Lake Road and Milford-Connecticut facilities, we cleared 70 MW of new uprates in FCA-10, at a capacity rate of $7.03 per kW-month for seven years beginning with Planning Year 2019-2020 and extending through Planning Year 2025-2026. For FCA-11, we cleared a total of 34 MW of uprates at Lake Road and Casco Bay that did not qualify for a seven year rate lock. Milford-Massachusetts cleared an incremental 53 MW of new capacity in FCA-11 that qualified the entire plant for a seven year rate lock. Milford-Massachusetts will receive the FCA-11 clearing price of $5.30 per kW-month for 202 MW through Planning Year 2026-2027.

In New York, we completed uprate installations which are expected to result in 35 MW of additional summer capacity and 79 MW of additional winter capacity. In addition to the benefit of incremental output, both blocks have experienced improved efficiency as a result of the uprates.

In New England, almost all of our capacity sales are made through ISO-NE capacity auctions.

In New York, 66 percent of our Independence facility’s winter capacity had been sold bilaterally prior to the most recent auction, covering the Winter 2016-2017 planning period.

Our Brayton Point facility is expected to be retired in ISO-NE in June 2017.

Table of Contents

The following table reflects our hedging activities as of February 7, 2017 :

__________________________________________


(1)	Excludes our Brayton Point facility and volumes subject to tolling agreements.

ISO-NE Capacity Market . We have approximately 5,331 MW of power generation in ISO-NE. The most recent FCA results for ISO-NE Rest-of-Pool, in which most of our assets are located, are as follows for each Planning Year:



	2014-2015	2015-2016	2016-2017	2017-2018	2018-2019	2019-2020	2020-2021
Price per kW-month	$3.21	$3.43	$3.15	$7.03	$9.55	$7.03	$5.30

On February 6, 2017, ISO-NE conducted the capacity auction for Planning Year 2020-2021 (FCA-11). In this auction, Rest-of-Pool cleared at $5.30 per kW-month. Performance incentive rules will go into effect for Planning Year 2018-2019, having the potential to increase capacity payments for those resources that are providing excess energy or reserves during a shortage event, while penalizing those that produce less than the required level.

Our capacity sales, aggregated by Planning Year through Planning Year 2020-2021, are as follows:



	2016-2017	2017-2018	2018-2019	2019-2020	2020-2021
Auction capacity sold (MW)	3,915	3,433	3,471	3,500	3,595
Bilateral capacity sold (MW)	199	148	91	44	—
Total capacity sold (MW)	4,114	3,581	3,562	3,544	3,595
Average price per kW-month	$3.22	$6.98	$10.08	$7.02	$5.38

On January 2, 2017, the Casco Bay tolling agreement expired. Effective as of the closing of the Delta Transaction, we obtained a pre-existing tolling agreement and acquired a 50% non-operating ownership interest in the Bellingham NEA facility. The tolling agreement expires in the spring of 2017. The majority of our ISO-NE capacity sales are transacted through ISO-NE’s primary FCA. Dynegy continues to market and pursue longer term multi-year capacity transactions that extend past FCA-11.

NYISO Capacity Market. We have approximately 1,212 MW of power generation in NYISO. The most recent seasonal auction results for NYISO's Rest-of-State zones, in which the capacity for our Independence plant clears, are as follows for each planning period:



	Winter 2014-2015	Summer 2015	Winter 2015-2016	Summer 2016	Winter 2016-2017
Price per kW-month	$2.90	$3.50	$1.25	$3.62	$0.75

Our capacity sales, aggregated by season through Summer 2019, are as follows:



	Winter 2016-2017	Summer 2017	Winter 2017-2018	Summer 2018	Winter 2018-2019	Summer 2019
Auction capacity sold (MW)	362	—	—	—	—	—
Bilateral capacity sold (MW)	775	868	655	620	330	255
Total capacity sold (MW)	1,137	868	655	620	330	255
Average price per kW-month	$1.98	$3.44	$2.84	$3.66	$3.32	$3.39

Due to the short-term, seasonal nature of the NYISO capacity auctions, we monetize the majority of Independence’s capacity through bilateral trades.

ERCOT Segment. The ERCOT segment is comprised of six power generation facilities located within the ERCOT region, with a total generating capacity of 4,696 MW.

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The following table reflects our hedging activities as of February 7, 2017 :



	2017	2018	2019 to 2021
Generation volumes hedged	19%	10%	—%
Coal requirements contracted	100%	—%	—%
Coal requirements priced	100%	—%	—%
Coal transportation requirements contracted	100%	100%	—%

ERCOT Market. The energy and fuel hedges summarized in the table above are augmented by the forward sale of ancillary services.

MISO and IPH Segments.

MISO Segment. The MISO segment is comprised of three power generation facilities located within the MISO region, with a total generating capacity of 1,913 MW. On June 9, 2016, Dynegy announced that Hennepin will receive firm transmission service for a majority of the facility into the PJM control area beginning with Planning Year 2017-2018. Beginning June 1, 2017, Hennepin will pseudo-tie and offer energy and capacity for 260 MW, or 14 percent of our current MISO capacity and energy, into PJM. Hennepin’s remaining volume of approximately 34 MW will continue to be offered into MISO.

Dynegy’s portfolio beyond the prompt year is primarily open to benefit from possible future power market pricing improvements.

The following table reflects our hedging activities as of February 7, 2017 :



	2017	2018	2019 to 2021
Generation volumes hedged (1)	73%	42%	5%
Coal requirements contracted	90%	68%	40%
Coal requirements priced	90%	68%	—%
Coal transportation requirements contracted	100%	98%	96%

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(1)	Excludes Baldwin Unit 1 starting October 2018 and Hennepin Unit 1 starting June 2017.

IPH Segment. The IPH segment is comprised of five power generation facilities, totaling 3,563 MW and primarily operates in MISO. Joppa, which is within the Electric Energy, Inc. control area, is interconnected to Tennessee Valley Authority and Louisville Gas and Electric Company, but primarily sells its capacity and energy to MISO. We currently offer a portion of our IPH segment generating capacity and energy into PJM. As of June 1, 2016, our Coffeen, Duck Creek, E.D. Edwards, and Newton facilities have 937 MW, or 26 percent of IPH’s current capacity and energy, electrically tied into PJM through pseudo-tie arrangements. Additionally, IPH has secured firm transmission beginning June 1, 2017 to export 240 MW into PJM from our Joppa facility.

On February 24, 2016, IPM was awarded a three year capacity and energy sale contract for 959 MW with capacity revenue of $152 million. This contract supports 112 communities in Illinois represented by Good Energy, and commenced on June 1, 2016.

IPH will continue to use our retail business to hedge a portion of the output from our IPH facilities. The retail hedges are well correlated to our facilities due to the close proximity of the hedge and through participation in FTR markets.

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In 2015, we entered into a long-term coal transportation agreement for our Joppa facility which begins in 2018 and includes a reduction compared to the 2017 rate. Similarly, in the fourth quarter of 2016, we negotiated new long-term coal transportation agreements for our Edwards and Newton facilities which also begin in 2018 and include reductions compared to the 2017 rate. The following table reflects our hedging activities as of February 7, 2017 :



	2017	2018	2019 to 2021
Generation volumes hedged	75%	44%	20%
Coal requirements contracted	94%	49%	26%
Coal requirements priced	71%	45%	—%
Coal transportation requirements contracted	100%	100%	100%

MISO Capacity Market. We have approximately 5,476 MW of power generation in MISO. This includes the 937 MW related to PJM pseudo-tie arrangements from the IPH fleet which began June 1, 2016. With Joppa’s export capability and Hennepin’s pseudo-tie arrangement that will begin on June 1, 2017, we will have approximately 1,437 MW expected to be sold in PJM for Planning Year 2017-2018. The capacity auction results for MISO Local Resource Zone 4, in which our assets are located, are as follows for each Planning Year:

We cleared no volume in the MISO Planning Year 2014-2015 capacity auction. Our MISO and IPH segments cleared 398 MW and 155 MW, respectively, in the MISO Planning Year 2015-2016 capacity auction at $150 per MW-day, incremental to our retail load obligations. Our MISO and IPH segments cleared no incremental volumes, in excess of our retail load obligations, in the MISO Planning Year 2016-2017 capacity auction.

MISO capacity sales through Planning Year 2019-2020 are as follows:



	2016-2017	2017-2018	2018-2019	2019-2020
MISO Segment:
Bilateral capacity sold in MISO (MW)	1,011	1,075	242	185
Legacy/Base auction capacity sold in PJM (MW)	—	214	—	—
Total MISO segment capacity sold (MW)	1,011	1,289	242	185
Average price per kW-month	$2.75	$2.96	$2.68	$2.60

IPH Segment:
Bilateral capacity sold in MISO (MW)	2,246	2,250	1,837	570
Legacy/Base auction capacity sold in PJM (MW)	50	375	—	260
CP auction capacity sold in PJM (MW)	730	472	835	356
Total IPH segment capacity sold (MW)	3,026	3,097	2,672	1,186
Average price per kW-month	$4.26	$4.46	$4.98	$3.95

A majority of the Mercury and Air Toxic Standards related asset retirements will conclude this year; however, we expect economic retirements to continue reducing reserve margins in MISO.

CAISO Segment. The CAISO segment is comprised of two power generation facilities located within the CAISO region, with a total generating capacity of 1,185 MW.

In its 2015 Gas Transmission and Storage rate case, which sets gas transportation rates for 2015-2017, PG&E proposed revenue requirements and allocation proposals which would result in a significant increase in the rates for electric generators served by the local transmission system, including Moss Landing. Historically, after PG&E’s gas transportation rate structure was changed to unbundle the Backbone Transmission System (“BB”) rates, PG&E gas transmission and storage rate case settlements have included a bill credit for Moss Landing that effectively reduced the differential between rates for BB and local transmission system service, allowing the plant to compete against other power generators. Dynegy actively participated in the hearing process before the CPUC. However, on June 23, 2016, the CPUC approved a rate increase for local transmission customers, including Dynegy, of approximately 200 percent. Dynegy filed a request for rehearing of the CPUC’s unfavorable June 23, 2016 decision

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on August 1, 2016. The request for rehearing does not act as a stay on the rate increase, which went into effect on August 1, 2016. If Dynegy’s request for rehearing is denied, Dynegy will explore options for an appeal.

As a result of the offsetting risks of our other segments, we are able to reduce the costs associated with hedging with third parties by executing a portion of our natural gas hedges with an affiliate. We continue to manage our remaining commodity price exposure to changing fuel and power prices in accordance with our risk management policy. The following table reflects our hedging activities as of February 7, 2017 :

CAISO Capacity Market. On April 29, 2016, CAISO published the 2017 Local Capacity Technical Analysis—Final Report and Study Results, which identifies Local Capacity Requirements (“LCR”) and influences procurement decisions of Load Serving Entities. The Moss Landing area has been identified as a critical sub-area and will be included as part of the Greater Bay Area’s LCR criteria. Beginning in 2017, we will have the ability to sell Greater Bay Area RA capacity, in addition to CAISO System RA capacity, from the Moss Landing units.

We currently have approximately 1,185 MW of power generation in CAISO. The CAISO capacity market is a bilateral market in which Load Serving Entities are required to procure sufficient resources to meet their peak load plus a 15 percent reserve margin. We transact with investor owned utilities, municipalities, community choice aggregators, retail providers, and other marketers through Request for Offers solicitations, broker markets, and directly with bilateral transactions for both the Standard and Flexible RA capacity. Beginning on November 1, 2016, CAISO implemented the voluntary capacity auction for annual, monthly, and intra-month procurement to cover for deficiencies in the market. The voluntary competitive solicitation process FERC approved on October 1, 2015 is a modification to the 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.

Our capacity sales, including CPM designations, aggregated by calendar year for 2017 through 2019 for Moss Landing, are as follows:

We have also sold seasonal capacity for Moss Landing opportunistically. Our Oakland facility operated under an RMR contract with the CAISO for 2015 and was given notice of extension for 2016.

Other Market Developments

On January 25, 2016, the U.S. Supreme Court overturned the decision of the U.S. Court of Appeals for the District of Columbia Circuit and affirmed FERC’s jurisdiction over compensation to Demand Response providers in wholesale competitive markets and the compensation method as proscribed in FERC Order No. 745. The decision effectively maintains the status-quo with respect to Demand Response participation in the wholesale markets, because the ISOs/RTOs refrained from making changes to market design while the case was pending.

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”).

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:

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•	Revenue Recognition and Derivative Instruments;


•	Fair Value Measurements;


•	Accounting for Income Taxes;


•	Business Combinations;


•	Impairment of Long-Lived Assets; and


•	Goodwill Impairment.

Revenue Recognition and Derivative Instruments

We earn revenue from our facilities in three primary ways: (i) the sale of energy, including fuel, through both physical and financial transactions; (ii) sale of capacity; and (iii) 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” below 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 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 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. All derivative commodity contracts that do not qualify for, or for which we do not elect, the “normal purchase, normal sale” exception are recorded at fair value in risk management assets and liabilities in the consolidated balance sheets with the associated changes in fair value recorded currently to revenues. 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.

Entities may choose whether or not to offset related assets and liabilities and report the net amounts on their consolidated balance sheets if the right of offset exists. 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. As a result, our consolidated balance sheets present derivative assets and liabilities, as well as the related cash collateral paid or received, on a net basis.

Derivative Instruments—Financing Activities. We are exposed to changes in interest rate risk through our variable rate debt. In order to manage our interest rate risk, we enter into interest rate swap agreements that meet the definition of a derivative. All derivative instruments are recorded at their fair value on the consolidated balance sheets 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.

Fair Value Measurements

Fair Value Measurements. Accounting standards define fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. 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.

Our estimate of fair value reflects the 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, readily observable quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).

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Fair Value Measurements—Risk Management Activities. The determination of the fair value for each derivative contract 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 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.

Assets and liabilities from risk management activities may include exchange-traded derivative contracts and OTC derivative contracts. Exchange-traded derivatives, as discussed above, are generally classified as Level 1; however, some exchange-traded derivatives are valued using broker or dealer quotations or market transactions in either the listed or OTC markets. In such cases, these exchange-traded derivatives are classified within Level 2. OTC derivative instruments include swaps, forwards, and options. In certain instances, these instruments may utilize models to measure fair value. Generally, we use a similar model to value similar instruments. Valuation models utilize various inputs that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the asset or liability, and market-corroborated inputs. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. Other OTC derivatives trade in less active markets with a lower availability of pricing information. In addition, complex or structured transactions, such as heat-rate call options, can introduce the need for internally-developed model inputs that might not be observable in or corroborated by the market. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized in Level 3.

Changes to our assumptions for the fair value of our derivative instruments (primarily forward price curves, pricing risk, and credit risk) 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.

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.

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. These differences can result in deferred tax assets and liabilities, which are included within our consolidated balance sheets. 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.

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 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 requires 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.

We do not believe we will produce sufficient future taxable income, nor are there tax planning strategies available to realize the tax benefits from net deferred tax assets not otherwise realized by reversing existing taxable temporary differences. Therefore, we continue to recognize a valuation allowance against our net deferred tax assets as of December 31, 2016. Any change in the valuation allowance would impact our income tax benefit (expense) and net income (loss) in the period in which the change occurs.

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.

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We recognize accrued interest expense and penalties related to unrecognized tax benefits as income tax expense.

Please read Note 15—Income Taxes for further discussion of our accounting for income taxes, uncertain tax positions, and changes in our valuation allowance.

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. 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.

There is a significant amount of judgment in determining the fair value of the Acquisitions and in allocating value 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. Refer to Note 3—Acquisitions for further discussion of the Acquisitions.

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.

If we determine that an asset or asset group may have become impaired, then we will perform step one of the impairment analysis, which requires us to determine if the asset’s value is recoverable using forecasted undiscounted cash flows. 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. Some examples of the assumptions and estimates used include:


•	determination of 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 and 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;

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•	discount rates; and


•	inflation rates.

Changes in any of management’s assumptions and estimates could result in significantly different results than what we have reported herein.

We performed asset impairment analyses of certain of our facilities in 2016 and, as a result, recorded impairment charges of $56 million , $148 million , and $645 million for our Stuart, Newton, and Baldwin facilities, respectively. Please read Note 9—Property, Plant and Equipment for further discussion.

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. In the event management determines a triggering event has occurred or it is the period for the annual assessment, ASC 350 allows an entity to elect to qualitatively assess whether it is more likely than not that an impairment has occurred (step zero). If we determine that it is more likely than not that goodwill has become impaired, we utilize a two-step process to conclude if goodwill has become impaired and to calculate the impairment charge. Step one involves fair valuing the reporting units to which goodwill has been assigned and comparing that fair value to the book value of the reporting units, inclusive of goodwill. In the event the fair value of the reporting unit is less than its book value, inclusive of goodwill, step two must be performed, which compares the implied fair value of goodwill to its book value.

The assumptions and estimates used by management to determine the fair value of our reporting units and goodwill for step one and step two, respectively, are significant and may vary materially from the assumptions and estimates used by our peers. Some examples of the assumptions and estimates used include:


•	the highest and best use of the reporting units assets;


•	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.

At October 1, 2016, Dynegy performed its annual goodwill assessment and determined that no impairment was required. Changes in management’s assumptions and estimates regarding the fair value of these reporting units could result in a materially different result.

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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, 2016
Fair value of portfolio at December 31, 2015	$	(90	)
Risk management losses recognized through the statement of operations in the period, net	61
Contracts realized or otherwise settled during the period	87
Change in collateral/margin netting	(52		)
Fair value of portfolio at December 31, 2016	$	6

The net risk management asset of $6 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.

Risk Management Asset and Liability Disclosures. The following table provides an assessment of net contract values by year as of December 31, 2016 , based on our valuation methodology:

Net Fair Value of Risk Management Portfolio



(amounts in millions)	Total			2017			2018			2019			2020			2021		Thereafter
Market quotations (1) (2)	$	(50	)	$	(20	)	$	(25	)	$	(4	)	$	(1	)	$	—	$	—
Prices based on models (2)	2			—			—			1			1			—		—
Total (3)	$	(48	)	$	(20	)	$	(25	)	$	(3	)	$	—		$	—	$	—

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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 4—Risk Management Activities, Derivatives and Financial Instruments for further discussion.


(3)	Excludes $54 million of broker margin that has been netted against Risk management liabilities in our consolidated balance sheet. Please read Note 4—Risk Management Activities, Derivatives and Financial Instruments for further discussion.

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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 attempted to manage 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 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, 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.

The increase in the December 31, 2016 one day VaR compared to December 31, 2015 was primarily due to increased forward positions and increased price volatility.

Table of Contents

Daily and Average VaR for Risk-Management Portfolios



(amounts in millions)	December 31, 2016		December 31, 2015
One day VaR—95 percent confidence level	$	38	$	20
One day VaR—99 percent confidence level	$	53	$	29
Average VaR—95 percent confidence level for the rolling twelve months ended	$	14	$	8

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, 2016 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	$	10
Oil and gas producers	6
Utility and power generators	63
Total	$	79

Interest Rate Risk

We are exposed to fluctuating interest rates related to variable rate financial obligations, which consist of amounts outstanding under our Credit Agreement. We currently use interest rate swaps to mitigate this interest rate exposure. Our interest rate hedging instruments are recorded at their fair value. As a result of our outstanding interest rate derivatives, we do not have any significant exposure to changes in LIBOR.

The absolute notional amounts associated with our interest rate contracts were as follows at December 31, 2016 and December 31, 2015 , respectively:



	December 31, 2016			December 31, 2015
Interest rate swaps (in millions of U.S. dollars)	$	769		$	777
Fixed interest rate paid (percent)	3.19		%	3.19		%

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, 2016 .

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, 2016 . 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, 2016 .

The effectiveness of our internal control over financial reporting as of December 31, 2016 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, 2016 .

Item 9B. Other Information

Not applicable.

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 2017 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, 2016. 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 2017 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, 2016. 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 2017 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, 2016 . 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 2017 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, 2016 . 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, 2016 , 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)	5,248,580	$	19.01	2,268,505
Equity compensation plans not approved by security holders	—	—		—
Total	5,248,580	$	19.01	2,268,505

__________________________________________


(1)	The plan that is approved by our security holders is the 2012 Long Term Incentive Plan, as amended. Please read Note 18—Capital Stock —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 2017 annual meeting of stockholders under the headings “Transactions with Related Persons, Promoters

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, 2016. 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 2017 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, 2016. 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.

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 Common Stock, dated October 7, 2014, between Dynegy Inc. 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 underwriters (incorporated by reference to Exhibit 1.1 to the Current Report on Form 8-K of Dynegy Inc. filed on October 14, 2014, File No. 001-33443).
1.2			Underwriting Agreement relating to the Mandatory Convertible Preferred Stock, dated October 7, 2014, between Dynegy Inc. 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 underwriters (incorporated by reference to Exhibit 1.2 to the Current Report on Form 8-K of Dynegy Inc. filed on October 14, 2014 File No. 001-33443).
1.3			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).*
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			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. Sixth Amended and Restated Bylaws (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K of Dynegy Inc. filed on August 26, 2014 File No. 001-33443).
3.3			Certificate of Designations of the 5.375% Series A Mandatory Convertible Preferred Stock of Dynegy Inc., filed with the Secretary of State of the State of Delaware and effective October 14, 2014 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K of Dynegy Inc. filed on October 14, 2014 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.
***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.
4.9			Indenture dated as of November 1, 2000, from Illinois Power Generating Company to The Bank of New York Mellon Trust Company, N.A., as successor trustee (Genco Indenture) (incorporated by reference to Exhibit 4.1 to the Registration Statement on Form S-4 of Illinois Power Generating Company Filed March 6, 2001, File No. 333-56594).
4.10			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).
4.11			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).
4.12			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).



4.13			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).
4.14			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).
4.15			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).
***4.16			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.
***4.17			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.
4.18			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).
4.19			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).
4.20			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).
4.21			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).
4.22			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).
4.23			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).
***4.24			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.
***4.25			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.
4.26			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).
4.27			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).
4.28			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).



4.29			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).
4.30			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).
4.31			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).
***4.32			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.
***4.33			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.
4.34			2025 Notes Indenture, dated October 11, 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 October 11, 2016 File No. 001-33443).
***4.35			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.
***4.36			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.
4.37			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).
4.38			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).
4.39			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).
4.40			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).
***4.41			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.
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			2012 Long Term Incentive Plan (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc. filed on October 4, 2012, 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			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).††
10.17			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). ††
10.18			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). ††
10.19			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). ††
10.20			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). ††
10.21			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). ††
10.22			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). ††
10.23			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). ††
10.24			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). ††
10.25			Form of Stock Unit Award Agreement - Officers (2013 Awards) (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on March 22, 2013 File No. 001-33443). ††
10.26			Form of Stock Unit Award Agreement - Officers (2014 Awards) (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2014 of Dynegy Inc. File No. 001-33443). ††
10.27			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). ††



10.28			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). ††
10.29			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). ††
10.30			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). ††
10.31			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). ††
10.32			Form of Performance Award Agreement (2014 Awards) (for Managing Directors and Above)(incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2014 of Dynegy Inc. File No. 001-33443). ††
10.33			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). ††
10.34			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). ††
10.35			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). ††
10.36			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).
10.37			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).
10.38			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).
10.39			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).
10.40			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).
10.41			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).
10.42			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).
10.43			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).
10.45			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, 2016).
10.46			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).
10.47			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).
10.48			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).

100



10.49			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).
10.50			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).
10.51			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).
10.52			Revolving Promissory Note by and between Dynegy Inc., as Lender, and Illinois Power Resources, LLC (formerly New Ameren Energy Resources, LLC), as Borrower (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on December 4, 2013 File No. 001-33443).
****10.53			Warrant Agreement, dated October 1, 2012, by and among Dynegy Inc., Computershare Inc. and Computershare Trust Company, N.A., as warrant agent (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on October 4, 2012, File No. 001-33443).
10.54			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).
10.55			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).
10.56			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).
10.57			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).
10.58			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).
10.59			Equity Commitment Letter, dated as of February 24, 2016, by and among Dynegy Inc., Atlas Power, LLC and Atlas Power Finance, LLC (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on March 1, 2016 File No. 001-33443).
10.60			Amended and Restated Equity Commitment Letter, dated as of June 27, 2016, by and among Dynegy Inc., Atlas Power Finance, LLC and GDF SUEZ Energy North America, Inc. (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on June 28, 2016 File No. 001-33443).
10.61			Equity Commitment Letter, dated as of February 24, 2016, by and among Energy Capital Partners III, LP, Energy Capital Partners III-A, LP, Energy Capital Partners III-B, LP, Energy Capital Partners III-C, LP, Energy Capital Partners III-D, LP, Atlas Power, LLC and Atlas Power Finance, LLC (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on March 1, 2016 File No. 001-33443).
10.62			Limited Guarantee, dated February 24, 2016, by Dynegy Inc., for the benefit of GDF SUEZ Energy North America, Inc. (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc. filed on March 1, 2016 File No. 001-33443).
10.63			Stock Purchase Agreement, dated February 24, 2016, by and between Dynegy Inc. and Terawatt Holdings, LP (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K of Dynegy Inc. filed on March 1, 2016 File No. 001-33443).
10.64			Interim Sponsors Agreement, dated February 24, 2016, by and between Atlas Power, LLC, Dynegy Inc., Energy Capital Partners III, LP, Energy Capital Partners III-A, LP, Energy Capital Partners III-B, LP, Energy Capital Partners III-C, LP and Energy Capital Partners III-D, LP (incorporated by reference to Exhibit 10.5 to the Current Report on Form 8-K of Dynegy Inc. filed on March 1, 2016 File No. 001-33443).

101



10.65			Amended and Restated Interim Sponsors Agreement, dated as of June 14, 2016, by and between Atlas Power, LLC, Dynegy Inc., Energy Capital Partners III, LP, Energy Capital Partners III-A, LP, Energy Capital Partners III-B, LP, Energy Capital Partners III-C, LP, Energy Capital Partners III-D, LP, and Terawatt Holdings, LP (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc. filed on June 28, 2016 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			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).
10.68			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).
10.69			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).
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.
†32.1			Chief Executive Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
†32.2			Chief Financial Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
**101.INS			XBRL Instance Document
**101.SCH			XBRL Taxonomy Extension Schema Document
**101.CAL			XBRL Taxonomy Extension Calculation Linkbase Document
**101.DEF			XBRL Taxonomy Extension Definition 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.

102

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 24, 2017	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 24, 2017
/s/ CLINT C. FREELAND Clint C. Freeland	Executive Vice President and Chief Financial Officer (Principal Financial Officer)	February 24, 2017
/s/ J. CLINTON WALDEN J. Clinton Walden	Vice President and Chief Accounting Officer (Principal Accounting Officer)	February 24, 2017
/s/ PAT WOOD III Pat Wood III	Chairman of the Board	February 24, 2017
/s/ HILARY E. ACKERMANN Hilary E. Ackermann	Director	February 24, 2017
/s/ PAUL M. BARBAS Paul M. Barbas	Director	February 24, 2017
/s/ RICHARD LEE KUERSTEINER Richard Lee Kuersteiner	Director	February 24, 2017
/s/ TYLER REEDER Tyler Reeder	Director	February 24, 2017
/s/ JEFFREY S. STEIN Jeffrey S. Stein	Director	February 24, 2017
/s/ JOHN R. SULT John R. Sult	Director	February 24, 2017

103

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, 2016 and 2015		F-4
Consolidated Statements of Operations:
For the years ended December 31, 2016, 2015 and 2014		F-6
Consolidated Statements of Comprehensive Income (Loss):
For the years ended December 31, 2016, 2015 and 2014		F-7
Consolidated Statements of Cash Flows:
For the years ended December 31, 2016, 2015 and 2014		F-8
Consolidated Statements of Changes in Equity:
For the years ended December 31, 2016, 2015 and 2014		F-9
Notes to Consolidated Financial Statements		F-10

F-1

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Dynegy Inc.:

We have audited Dynegy Inc.’s internal control over financial reporting as of December 31, 2016 , 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). Dynegy Inc.’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 conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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.

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.

In our opinion, Dynegy Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016 , based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2016 consolidated financial statements of Dynegy Inc. and our report dated February 24, 2017 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

February 24, 2017

F-2

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Dynegy Inc.:

We have audited the accompanying consolidated balance sheets of Dynegy Inc. (the Company) as of December 31, 2016 and 2015 , 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, 2016 . These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Dynegy Inc. at December 31, 2016 and 2015 , and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2016 , 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), Dynegy Inc.’s internal control over financial reporting as of December 31, 2016 , 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 24, 2017 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

February 24, 2017

F-3

Item 1—FINANCIAL STATEMENTS

DYNEGY INC.

CONSOLIDATED BALANCE SHEETS

(in millions, except share data)



	December 31, 2016		December 31, 2015
ASSETS
Current Assets
Cash and cash equivalents	$	1,776	$	505
Restricted cash	62		39
Accounts receivable, net of allowance for doubtful accounts of $1 and $1, respectively	386		402
Inventory	445		597
Assets from risk management activities	130		100
Intangible assets	38		102
Prepayments and other current assets	150		187
Total Current Assets	2,987		1,932
Property, plant and equipment, net	7,121		8,347
Investment in unconsolidated affiliate	—		190
Restricted cash	2,000		—
Assets from risk management activities	16		18
Goodwill	799		797
Intangible assets	23		62
Other long-term assets	107		113
Total Assets	$	13,053	$	11,459

See the notes to consolidated financial statements.

F-4

Table of Contents

DYNEGY INC.

CONSOLIDATED BALANCE SHEETS

(in millions, except share data)



	December 31, 2016			December 31, 2015
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	332		$	292
Accrued interest	81			74
Intangible liabilities	21			85
Accrued liabilities and other current liabilities	133			125
Liabilities from risk management activities	97			103
Asset retirement obligations	51			50
Debt, current portion, net	201			80
Total Current Liabilities	916			809
Liabilities subject to compromise (Note 22)	832			—
Debt, long-term portion, net	8,778			7,129
Liabilities from risk management activities	43			105
Asset retirement obligations	236			230
Deferred income taxes	5			29
Intangible liabilities	34			55
Other long-term liabilities	170			183
Total Liabilities	11,014			8,540
Commitments and Contingencies (Note 17)

Stockholders’ Equity
Preferred Stock, $0.01 par value, 20,000,000 shares authorized:
Series A 5.375% mandatory convertible preferred stock, $0.01 par value; 4,000,000 shares issued and outstanding, respectively	400			400
Common stock, $0.01 par value, 420,000,000 shares authorized; 128,626,740 shares issued and 117,300,618 shares outstanding at December 31, 2016; 128,228,477 shares issued and 116,902,355 outstanding at December 31, 2015	1			1
Additional paid-in capital	3,547			3,187
Accumulated other comprehensive income, net of tax	21			19
Accumulated deficit	(1,927		)	(686		)
Total Dynegy Stockholders’ Equity	2,042			2,921
Noncontrolling interest	(3		)	(2		)
Total Equity	2,039			2,919
Total Liabilities and Equity	$	13,053		$	11,459

See the notes to consolidated financial statements.

F-5

Table of Contents

DYNEGY INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per share data)



	Year Ended December 31,
	2016			2015			2014
Revenues	$	4,318		$	3,870		$	2,497
Cost of sales, excluding depreciation expense	(2,281		)	(2,028		)	(1,661		)
Gross margin	2,037			1,842			836
Operating and maintenance expense	(940		)	(839		)	(477		)
Depreciation expense	(689		)	(587		)	(247		)
Impairments	(858		)	(99		)	—
Gain (loss) on sale of assets, net	(1		)	(1		)	18
General and administrative expense	(161		)	(128		)	(114		)
Acquisition and integration costs	(11		)	(124		)	(35		)
Other	(17		)	—			—
Operating income (loss)	(640		)	64			(19		)
Bankruptcy reorganization items (Note 22)	(96		)	—			3
Earnings from unconsolidated investments	7			1			10
Interest expense	(625		)	(546		)	(223		)
Other income and expense, net	65			54			(39		)
Loss before income taxes	(1,289		)	(427		)	(268		)
Income tax benefit (Note 15)	45			474			1
Net income (loss)	(1,244		)	47			(267		)
Less: Net income (loss) attributable to noncontrolling interest	(4		)	(3		)	6
Net income (loss) attributable to Dynegy Inc.	(1,240		)	50			(273		)
Less: Dividends on preferred stock	22			22			5
Net income (loss) attributable to Dynegy Inc. common stockholders	$	(1,262	)	$	28		$	(278	)

Earnings (Loss) Per Share (Note 16):
Basic and diluted earnings (loss) per share attributable to Dynegy Inc. common stockholders	$	(9.78	)	$	0.22		$	(2.65	)

Basic shares outstanding	129			125			105
Diluted shares outstanding	129			126			105

See the notes to consolidated financial statements.

F-6

Table of Contents

DYNEGY INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in millions)



	Year Ended December 31,
	2016			2015			2014
Net income (loss)	$	(1,244	)	$	47		$	(267	)
Other comprehensive income (loss) before reclassifications:
Actuarial gain (loss) and plan amendments (net of tax expense of $3, zero, and zero, respectively)	3			4			(36		)
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)	(5		)	(4		)	(5		)
Other comprehensive income (loss), net of tax	4			—			(41		)
Comprehensive income (loss)	(1,240		)	47			(308		)
Less: Comprehensive income (loss) attributable to noncontrolling interest	(2		)	(2		)	3
Total comprehensive income (loss) attributable to Dynegy Inc.	$	(1,238	)	$	49		$	(311	)

See the notes to consolidated financial statements.

F-7

Table of Contents

DYNEGY INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)



	Year Ended December 31,
	2016			2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(1,244	)	$	47		$	(267	)
Adjustments to reconcile net income (loss) to net cash flows from operating activities:
Depreciation expense	689			587			247
Non-cash interest expense	56			38			21
Amortization of intangibles	21			(11		)	45
Impairments	858			99			—
Risk management activities	(148		)	(130		)	26
(Gain) loss on sale of assets, net	1			1			(18		)
Earnings from unconsolidated investments	(7		)	(1		)	—
Deferred income taxes	(45		)	(477		)	(1		)
Change in value of common stock warrants	(6		)	(54		)	40
Bankruptcy reorganization items	96			—			—
Other	14			51			35
Changes in working capital:
Accounts receivable, net	42			(64		)	161
Inventory	154			(119		)	(20		)
Prepayments and other current assets	189			84			22
Accounts payable and accrued liabilities	84			90			(131		)
Distributions from unconsolidated investments	1			3			—
Changes in restricted cash	(2		)	(28		)	—
Changes in non-current assets	(105		)	(27		)	(4		)
Changes in non-current liabilities	28			5			7
Net cash provided by operating activities	676			94			163
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(326		)	(275		)	(132		)
Decrease (increase) in restricted cash	(2,021		)	5,148			(5,148		)
Acquisitions, net of cash acquired	—			(6,078		)	—
Distributions from unconsolidated affiliates	14			8			—
Proceeds from asset sales, net	176			—			18
Other investing	10			3			—
Net cash used in investing activities	(2,147		)	(1,194		)	(5,262		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of debt issuance costs	3,014			66			5,055
Repayments of borrowings	(589		)	(31		)	(14		)
Proceeds from issuance of equity, net of issuance costs	359			(6		)	1,106
Preferred stock dividends paid	(22		)	(23		)	—
Interest rate swap settlement payments	(17		)	(17		)	(18		)
Repurchase of common stock	—			(250		)	—
Other financing	(3		)	(4		)	(3		)
Net cash provided by (used in) financing activities	2,742			(265		)	6,126
Net increase (decrease) in cash and cash equivalents	1,271			(1,365		)	1,027
Cash and cash equivalents, beginning of period	505			1,870			843
Cash and cash equivalents, end of period	$	1,776		$	505		$	1,870

See the notes to consolidated financial statements.

F-8

Table of Contents

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, 2013	$	—	$	1	$	2,614		$	58		$	(463	)	$	2,210		$	(3	)	$	2,207
Net income (loss)	—		—		—			—			(273		)	(273		)	6			(267		)
Other comprehensive loss, net of tax	—		—		—			(38		)	—			(38		)	(3		)	(41		)
Share-based compensation expense, net of tax	—		—		17			—			—			17			—			17
Options exercised	—		—		1			—			—			1			—			1
Issuance of new equity interests (Note 18)	400		—		706			—			—			1,106			—			1,106
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 18)	—		—		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 18)	—		—		(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 18)	—		—		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

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. In the fourth quarter of 2016, we changed our organizational structure to manage our assets, make financial decisions, and allocate resources based upon the market areas in which our plants operate. As of December 31, 2016, we modified our reportable segments from a fuel-based segment structure to the following market areas: (i) PJM, (ii) ISO-NE/NYISO (“NY/NE”), (iii) MISO, (iv) IPH, and (v) CAISO. Accordingly, the Company has recast data from prior periods to reflect this change in reportable segments. Additionally, beginning in 2017, as a result of the Delta Transaction, we also have an ERCOT segment. Our consolidated financial results also reflect corporate-level expenses such as general and administrative expense, interest expense, and income tax benefit (expense). All significant intercompany transactions have been eliminated. Please read Note 23—Segment Information for further discussion.

On December 9, 2016, Illinois Power Generating Company (“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 prepackaged plan of reorganization (the “Genco Plan”) and Genco emerged from bankruptcy on February 2, 2017 (the “Emergence Date”). As a result, we eliminated $825 million of Genco Senior Notes. On the Emergence Date, we exchanged $757 million of these Genco Senior Notes for $113 million of cash, $182 million of new Dynegy seven year unsecured notes, and 8.7 million Dynegy common stock warrants. Holders of Genco Senior Notes who did not receive a distribution under the Genco Plan on the Emergence Date have until July 17, 2017 (the 165th day after the Emergence Date) in order to exercise their rights to receive a distribution. As of December 31, 2016, Genco remained a consolidated variable interest entity (“VIE”) within our consolidated financial statements. Please read Note 22—Genco Chapter 11 Bankruptcy for further discussion.

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 and VIEs 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.

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

F-10

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 assets and Asset Retirement Obligations (“AROs”), (v) assessing future tax exposure and the realization of deferred tax assets, (vi) determining amounts to accrue for contingencies, guarantees, and indemnifications, and (vii) 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, 2016 and 2015, the Company had the following restricted cash balances:



	Year Ended December 31,
(amounts in millions)	2016		2015
Restricted cash, current:
Cash deposits associated with certain letters of credit (1)	$	41	$	39
Pre-funded original issue discount on Tranche C Term Loan (2)	20		—
Interest earned on funds in escrow	1		—
	$	62	$	39
Restricted cash, long-term:
Restricted cash related to the issuance of the Tranche C Term Loan (2)	$	2,000	$	—

_________________________________________


(1)	Upon the Emergence Date, approximately $35 million of these deposits were returned to Dynegy.


(2)	Upon the close of the Delta Transaction, as defined herein, the proceeds from the issuance of the Tranche C Term Loan were released from escrow. Please read Note 14—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.

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		4 to 40
Office and other equipment		3 to 20

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. As a result of

F-11

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

impairment analyses performed in 2016, we determined that our Stuart, Newton, and Baldwin facilities were impaired resulting in an aggregate impairment charge of $849 million for the year ended December 31, 2016 . Please read Note 9—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 net assets acquired. The carrying amount of our goodwill is periodically reviewed, at least annually, for impairment and whenever events or changes in circumstances indicate that the carrying value may not be recoverable. 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 or we can directly perform a two-step impairment test. Once we determine that the fair value of a reporting unit is more likely than not (i.e., a likelihood of more than 50 percent ) to be less than its carrying amount, the two-step impairment test will be performed.

In the absence of sufficient qualitative factors, goodwill impairment is determined using a two-step process:


•	Step one—Identify potential impairment by comparing 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, proceed to step two.


•	Step two—Compare the implied fair value of the reporting unit’s goodwill to the book value of the reporting unit’s goodwill. If the book value of goodwill exceeds the implied fair value, an impairment charge is recognized for the excess.

As of October 1, 2016, we performed our annual goodwill assessment and no goodwill impairment was required.

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. 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)	2016			2015
Balance at beginning of year	$	280		$	224
Accretion expense	20			21
Liabilities incurred	—			4
Liabilities settled	(1		)	(4		)
Revision of previous estimate (1)	(12		)	(57		)
Acquisitions	—			92
Balance at end of year	$	287		$	280

__________________________________________


(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 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.

F-12

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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. Our preferred shares are mandatorily convertible, are not redeemable and are classified as stockholders’ equity. We present the gross proceeds from their issuance as a single line item within stockholders’ equity on the consolidated balance sheets. Dividends on the preferred shares are 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.

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 our current interest rate contracts are classified as either inflows or outflows from financing activities on the consolidated statements of cash flows due to an other-than-insignificant financing element at inception of these contracts. Please read Note 14—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 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:

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DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

•

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. IPH and its subsidiaries operate under a tax sharing agreement with Dynegy. 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.

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. We recognize accrued interest expense and penalties related to unrecognized tax benefits as income tax expense.

Please read Note 15—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

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DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 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. Please read Note 22—Genco Chapter 11 Bankruptcy for further discussion of our consolidated VIE.

Accounting Standards Adopted

Debt Issuance Costs. In 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-03 and ASU 2015-15-Interest-Imputation of Interest (Subtopic 835-30). These ASUs require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts and that costs associated with line-of-credit arrangements may be presented as an asset and subsequently amortized ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The recognition and measurement guidance for our debt issuance costs are not affected by the amendments.

We adopted these ASUs on January 1, 2016, on a retrospective basis affecting presentation on the consolidated balance sheets for all periods presented. Accordingly, we reclassified unamortized debt issuance costs of $13 million and $67 million from Prepayments and other current assets and Other long-term assets, respectively, to Debt, current portion, net and Debt, long-term portion, net of $3 million and $77 million within our consolidated balance sheet as of December 31, 2015.

Going Concern. In August 2014, the FASB issued ASU 2014-15-Presentation of Financial Statements-Going Concern (Subtopic 205-40). The amendments in this ASU require management, in connection with preparing financial statements for each annual and interim reporting period, to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued (or within one year after the date that the financial statements are available to be issued, when applicable). The guidance in this ASU is effective for fiscal years ending after December 15, 2016, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. The adoption of this ASU did not have a material impact on our consolidated financial statements.

Accounting Standards Not Yet Adopted

Goodwill. In January 2017, the FASB issued ASU 2017-04-Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment. To simplify the subsequent measure of goodwill, the amendments in this ASU eliminate Step two from the goodwill impairment test. An entity will no longer be required to calculate the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if the reporting unit had been acquired in a business combination to determine the impairment of goodwill. The amendments in this ASU will now require goodwill impairment to be measured by the amount by which the carrying value of the reporting unit exceeds its fair value. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. Upon adoption, an entity shall apply the guidance in this ASU prospectively with early adoption permitted for annual goodwill tests performed after January 1, 2017. We do not anticipate the adoption of this ASU to have a 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. 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 of this ASU will have on our consolidated financial statements.

In November 2016, the FASB issued ASU 2016-18-Statement of Cash Flows (Topic 230): Restricted Cash. The amendments in this ASU require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally 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. 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 of this ASU will have on our consolidated financial statements.

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DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Compensation. In March 2016, the FASB issued ASU 2016-09-Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. The amendments in this ASU simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. We are currently evaluating this ASU and any potential impacts the adoption of this ASU will have on our consolidated financial statements.

Leases. In February 2016, the FASB issued ASU 2016-02-Leases (Topic 842). The amendments in this ASU will mainly require lessees to recognize lease assets and lease liabilities, for those leases classified as operating leases under GAAP, in their balance sheet. The lease assets recognized in the balance sheet will represent a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The lease liability recognized in the balance sheet will represent the lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. We are currently evaluating this ASU and any potential impacts the adoption of this ASU will have on our consolidated financial statements.

Revenue from Contracts with Customers. In May 2014, the FASB issued ASU 2014-09-Revenue from Contracts with Customers (Topic 606). This ASU, and subsequently issued amendments to the standard, develop a common revenue standard removing inconsistencies and weaknesses in revenue requirements, providing a more robust framework for addressing revenue issues, improving comparability of revenue recognition practices, providing more useful information to users of financial statements, and simplifying the preparation of financial statements. The guidance in this ASU and its amendments is effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted for interim and annual periods beginning after December 15, 2016. We have established an implementation team to assess the impact the new accounting standard will have on our financial statements upon adoption. Our implementation team is currently assessing the impact of the standard by reviewing revenue earned from contracts to determine if changes in our policies are necessary. While our evaluation of the new accounting standard is still ongoing, we have not yet identified any significant changes to our existing policies.

Note 3—Acquisitions

EquiPower Acquisition. On April 1, 2015 (the “EquiPower Closing Date”), pursuant to the terms of a stock purchase agreement dated August 21, 2014, as amended, our wholly owned subsidiary, Dynegy Resource II, LLC purchased 100 percent of the equity interests in EquiPower Resources Corp. (“ERC”) from certain affiliates of ECP (collectively, the “ERC Sellers”) 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”).

On the EquiPower Closing Date, in a related transaction, pursuant to a stock purchase agreement and plan of merger dated August 21, 2014, as amended, our wholly owned subsidiary Dynegy Resource III, LLC purchased 100 percent of the equity interests in Brayton Point Holdings, LLC (“Brayton”) from certain affiliates of ECP (collectively, the “Brayton Sellers” and together with the ERC Sellers, the “ECP Sellers”), 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. In aggregate, the resulting operations from the two coal-fired, six natural gas-fired, and two gas- and oil-fired facilities acquired from the ECP Sellers are reported within our PJM and NY/NE segments .

Duke Midwest Acquisition. On April 2, 2015, pursuant to the terms of the purchase and sale agreement dated August 21, 2014, as amended, our wholly owned subsidiary Dynegy Resource I, LLC 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. We operate two of the five coal-fired facilities, the Miami Fort and Zimmer facilities, with other owners operating the three remaining facilities. The operations from the retail energy business, the five coal-fired, the one oil-fired, and the five natural gas-fired facilities acquired from Duke Energy are reported within our PJM segment.

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DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Business Combination Accounting

The EquiPower Acquisition and the Duke Midwest Acquisition (collectively, the “Acquisitions”) have been accounted for in accordance with ASC 805, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition dates, April 1, 2015 and April 2, 2015, respectively. The valuation of these assets and liabilities is classified as Level 3 within the fair value hierarchy.

To fair value working capital, we used available market information. AROs were recorded in accordance with ASC 410, Asset Retirement and Environmental Obligations. To fair value the acquired PP&E, we used a discounted cash flow (“DCF”) analysis based upon a debt-free, free cash flow model. The DCF model was created for each power generation facility based on its remaining useful life, and included gross margin forecasts for each facility using forward commodity market prices obtained from third party quotations for the years 2015 and 2016. For the years 2017 through 2024, 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 2024, we assumed a 2.5 percent growth rate. We also used management’s forecasts of operations and maintenance expense, general and administrative expense, and capital expenditures for the years 2015 through 2019 and assumed a 2.5 percent growth rate, based upon management’s view of future conditions, thereafter. The resulting cash flows were then discounted using plant specific discount rates of approximately 8 percent to 10 percent for gas-fired generation facilities and approximately 9 percent to 13 percent for coal-fired generation facilities, based upon the asset’s age, efficiency, region, and years until retirement. Contracts with terms that are not at current market prices were also valued using a DCF analysis. 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. The 3,460,053 shares of common stock of Dynegy, issued as part of the consideration for the EquiPower Acquisition, were valued at approximately $105 million based on the closing price of Dynegy’s common stock on the EquiPower Closing Date.

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DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

As of June 30, 2016, we completed our valuation of the assets acquired and liabilities assumed in connection with the Acquisitions. The following table summarizes the consideration paid and the fair value amounts recognized for the assets acquired and liabilities assumed related to the EquiPower Acquisition and the Duke Midwest Acquisition, as of the respective acquisition dates, April 1, 2015 and April 2, 2015:



(amounts in millions)	EquiPower Acquisition		Duke Midwest Acquisition			Total
Cash	$	3,350	$	2,800		$	6,150
Equity instruments (3,460,053 common shares of Dynegy)	105		—			105
Net working capital adjustment	206		(9		)	197
Fair value of total consideration transferred	$	3,661	$	2,791		$	6,452

Cash	$	267	$	—		$	267
Accounts receivable	49		126			175
Inventory	167		105			272
Assets from risk management activities (including current portion of $4 million and $30 million, respectively)	4		33			37
Prepayments and other current assets	32		69			101
Property, plant and equipment	2,773		2,734			5,507
Investment in unconsolidated affiliate	200		—			200
Intangible assets (including current portion of $67 million and $36 million, respectively)	111		84			195
Other long-term assets	28		35			63
Total assets acquired	3,631		3,186			6,817

Accounts payable	27		96			123
Accrued liabilities and other current liabilities	21		10			31
Debt, current portion	39		—			39
Liabilities from risk management activities (including current portion of $41 million and zero, respectively)	57		107			164
Asset retirement obligations	43		49			92
Intangible liabilities (including current portion of $24 million and $58 million, respectively)	73		93			166
Deferred income taxes, net	509		—			509
Other long-term liabilities	—		40			40
Total liabilities assumed	769		395			1,164
Identifiable net assets acquired	2,862		2,791			5,653
Goodwill	799		—			799
Net assets acquired	$	3,661	$	2,791		$	6,452

As a result of recording the stepped up fair market basis for GAAP purposes, but receiving primarily carryover basis for tax purposes in the EquiPower Acquisition, we initially recorded a net deferred tax liability of $537 million within our provisional valuation of the EquiPower Acquisition as of the acquisition date. As we had previously recorded a valuation allowance against our historical deferred tax assets, we released approximately $480 million of our valuation allowance as a result of these increased deferred tax liabilities during the second quarter of 2015. During the second half of 2015, we reduced the initially-recognized deferred tax liability by $31 million due to newly available information regarding the fair values of assets and liabilities acquired in the EquiPower Acquisition. This reduction to the deferred tax liability resulted primarily in a corresponding reduction to goodwill, as discussed below, and a $27 million reversal of the previously released valuation allowance discussed above. For the year ended December 31, 2015 , we recorded a net deferred tax liability of $506 million and released approximately $453 million of our valuation allowance related to the EquiPower Acquisition.

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DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Goodwill resulting from the EquiPower Acquisition reflects the excess of our purchase price over the fair value of the net assets acquired. We recorded initial goodwill of $837 million as of the acquisition date, and subsequently reduced the amount during the second half of 2015 by $40 million due to the newly available information discussed above. As of December 31, 2016 and 2015, we recognized goodwill of $799 million and $797 million , which was allocated to our segments as follows:



	Year Ended December 31,
(amounts in millions)	2016		2015
PJM	$	272	$	271
NY/NE	527		526
Total	$	799	$	797

None of the goodwill recognized is deductible for income tax purposes, and as such, no deferred taxes related to goodwill have been recorded. No goodwill was recognized as a result of the Duke Midwest Acquisition.

The following table summarizes acquisition costs incurred related to the Acquisitions, 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)	2016		2015		2014
Acquisition costs (1)	$	—	$	86	$	19
Revenues	$	2,280	$	1,703	N/A
Operating income	$	235	$	230	N/A

_________________________________________


(1)	The year ended December 31, 2015 , included $48 million of commitment fees associated with a temporary bridge facility, which were payable only upon the closing of the Acquisitions. No amounts were borrowed under the bridge facility, and the bridge facility was cancelled, as our permanent financing for the Acquisitions was executed.

Pro Forma Results. The unaudited pro forma financial results for the years ended December 31, 2015 and 2014 assume the EquiPower Acquisition and the Duke Midwest Acquisition 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 January 1, 2014, nor are they indicative of future results of operations.



	Year Ended December 31,
(amounts in millions)	2015			2014
Revenues	$	4,860		$	5,574
Net income (loss)	$	308		$	(613	)
Net income (loss) attributable to noncontrolling interest	$	(3	)	$	6
Net income (loss) attributable to Dynegy Inc.	$	311		$	(619	)

Note 4—Risk Management Activities, Derivatives and Financial Instruments

The nature of our business necessarily involves commodity market and financial risks. Specifically, we are exposed to commodity price variability related to our power generation business. Our commercial team manages these commodity price risks with financially and physically settled contracts consistent with our commodity risk management policy. Our treasury team manages our interest rate risk.

Our commodity risk management policy gives us the flexibility to sell energy and capacity and purchase fuel through a combination of spot market sales and near-term contractual arrangements (generally over a rolling one - to three -year time frame). Our commodity risk management goal is to protect cash flow in the near-term while keeping the ability to capture value longer-term.

Many of our contractual arrangements are derivative instruments and are accounted for at fair value as part of Revenues in our 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

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DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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, 2016 , 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)	(69	)	MWh	$	(115	)
Electricity basis derivatives (3)	(21	)	MWh	$	(4	)
Natural gas derivatives (2)	423		MMBtu	$	123
Natural gas basis derivatives	61		MMBtu	$	(12	)
Emissions derivatives	8		Metric Ton	$	(10	)
Interest rate swaps	769		U.S. Dollar	$	(30	)
Common stock warrants (4)	16		Warrant	$	(1	)

_________________________________________


(1)	Includes both asset and liability risk management positions, but excludes margin and collateral netting of $54 million .


(2)	Mainly comprised of swaps, options and physical forwards.


(3)	Comprised of FTRs and swaps.


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

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, 2016 and 2015 . As of December 31, 2016 and 2015 , there were no gross amounts available to be offset that were not offset in our consolidated balance sheets.



			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

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DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



			December 31, 2015
						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	$	403		$	(285	)	$		$	118
	Total derivative assets		$	403		$	(285	)	$	—	$	118

Derivative liabilities:
	Commodity contracts	Liabilities from risk management activities	$	(557	)	$	285		$	106	$	(166	)
	Interest rate contracts	Liabilities from risk management activities	(42		)	—			—		(42		)
	Common stock warrants	Other long-term liabilities	(7		)	—			—		(7		)
	Total derivative liabilities		$	(606	)	$	285		$	106	$	(215	)
Total derivatives			$	(203	)	$			$	106	$	(97	)

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, 2016 , the aggregate fair value of all commodity derivative instruments containing credit-risk-related contingent features which are in a liability position and not fully collateralized is $15 million for which we have posted $9 million in 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.

The following table summarizes our cash collateral posted as of December 31, 2016 and 2015 , 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, 2016		December 31, 2015
(amounts in millions)
Gross collateral posted with counterparties	$	116	$	162
Less: Collateral netted against risk management liabilities	54		106
Net collateral within Prepayments and other current assets	$	62	$	56

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, 2016, 2015 and 2014 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,
Derivatives Not Designated as Hedges	Location of Gain (Loss) Recognized in Income on Derivatives	2016			2015			2014
(amounts in millions)
Commodity contracts	Revenues	$	270		$	194		$	(183	)
Interest rate contracts	Interest expense	$	(5	)	$	(15	)	$	(15	)
Common stock warrants	Other income and (expense), net	$	6		$	54		$	(40	)

F-21

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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.

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, 2016 and 2015 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, 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	)

F-22

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



	Fair Value as of December 31, 2015
(amounts in millions)	Level 1			Level 2			Level 3			Total
Assets:
Assets from commodity risk management activities:
Electricity derivatives	$	—		$	308		$	40		$	348
Natural gas derivatives	—			40			2			42
Coal derivatives	—			10			3			13
Total assets from commodity risk management activities	$	—		$	358		$	45		$	403
Liabilities:
Liabilities from commodity risk management activities:
Electricity derivatives	$	—		$	(267	)	$	(58	)	$	(325	)
Natural gas derivatives	—			(158		)	(34		)	(192		)
Diesel derivatives	—			(4		)	—			(4		)
Coal derivatives	—			(35		)	(1		)	(36		)
Total liabilities from commodity risk management activities	—			(464		)	(93		)	(557		)
Liabilities from interest rate contracts	—			(42		)	—			(42		)
Liabilities from outstanding common stock warrants	(7		)	—			—			(7		)
Total liabilities	$	(7	)	$	(506	)	$	(93	)	$	(606	)

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 and heat rate derivative valuations are derived using a Black-Scholes spread model, which uses forward natural gas and power prices, market implied volatilities, and modeled correlation 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. The coal derivatives classified within Level 3 include financial swaps executed in illiquid trading locations.

Sensitivity to Changes in Significant Unobservable Inputs for Level 3 Valuations. The significant unobservable inputs used in the fair value measurement of our commodity instruments categorized within Level 3 of the fair value hierarchy include estimates of forward congestion, power price spreads, natural gas and coal pricing, and the difference between our plant locational prices to liquid hub prices. Power price spreads, natural gas and coal pricing, and the difference between our plant locational prices to liquid hub prices are generally based on observable markets where available, or derived from historical prices and forward market prices from similar observable markets when not available. Increases in the price of the spread on a buy or sell position in isolation would result in a higher/lower fair value measurement. The significant unobservable inputs used in the valuation of Dynegy’s contracts classified as Level 3 as of December 31, 2016 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)	(8	)	Million MWh	$	10		Basis spread + liquid location	Basis spread	$4.30 - $6.30
FTRs	(19	)	Million MWh	$	(2	)	Historical congestion	Forward price	$0 - $6.00
Natural gas derivatives (1)	73		Million MMBtu	$	(6	)	Illiquid location fixed price	Forward price	$2.00 - $2.50

__________________________________________


(1)	Represents forward financial and physical transactions at illiquid pricing locations and long-dated contracts.

F-23

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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, 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



	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
Acquisitions	(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



	Year Ended December 31, 2014
(amounts in millions)	Electricity Derivatives			Heat Rate Derivatives			Total
Balance at December 31, 2013	$	11		$	(1	)	$	10
Total gains (losses) included in earnings	(9		)	1			(8		)
Settlements (1)	(6		)	—			(6		)
Balance at December 31, 2014	$	(4	)	$	—		$	(4	)
Unrealized gains (losses) relating to instruments held as of December 31, 2014	$	(9	)	$	1		$	(8	)

__________________________________________


(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 transfers between Level 1, Level 2 and Level 3 for the years ended December 31, 2016 and 2015 .

Nonfinancial Assets and Liabilities. Nonfinancial assets and liabilities that are measured at fair value on a nonrecurring basis are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of such assets and liabilities and their placement within the fair value hierarchy.

During the year ended December 31, 2016 , as a result of impairment testing, we measured our Baldwin, Newton and Stuart facilities at fair value. During the year ended December 31, 2015 , as a result of impairment testing, we measured our Wood River Power Station and Brayton Point generation facilities at fair value. See Note 9—Property, Plant and Equipment for further discussion. During the year ended December 31, 2015 , we fair valued the EquiPower and Duke Midwest acquisitions. See Note 3—Acquisitions for further discussion. Each of these valuations is classified as Level 3 within the fair value hierarchy.

F-24

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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, 2016 and 2015 , respectively.



		December 31, 2016						December 31, 2015
(amounts in millions)	Fair Value Hierarchy	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Dynegy Inc.:
6.75% Senior Notes, due 2019 (1)	Level 2	$	(2,083	)	$	(2,137	)	$	(2,077	)	$	(1,985	)
Tranche B-2 Term Loan, due 2020 (1)	Level 2	$	(219	)	$	(225	)	$	(766	)	$	(754	)
Tranche C Term Loan, due 2023 (1)	Level 2	$	(1,994	)	$	(2,025	)	$	—		$	—
7.375% Senior Notes, due 2022 (1)	Level 2	$	(1,731	)	$	(1,665	)	$	(1,729	)	$	(1,531	)
5.875% Senior Notes, due 2023 (1)	Level 2	$	(492	)	$	(431	)	$	(491	)	$	(404	)
7.625% Senior Notes, due 2024 (1)	Level 2	$	(1,237	)	$	(1,156	)	$	(1,235	)	$	(1,078	)
8.00% Senior Notes, due 2025 (1)	Level 2	$	(738	)	$	(703	)	$	—		$	—
7.00% Amortizing Notes, due 2019 (1)	Level 2	$	(78	)	$	(90	)	$	—		$	—
Forward capacity agreement (1)	Level 3	$	(205	)	$	(205	)	$	—		$	—
Inventory financing agreements	Level 3	$	(129	)	$	(127	)	$	(136	)	$	(137	)
Equipment financing agreements (1)	Level 3	$	(73	)	$	(73	)	$	(61	)	$	(61	)
Genco:
7.00% Senior Notes Series H, due 2018 (1)	Level 2	$	—		$	—		$	(276	)	$	(204	)
6.30% Senior Notes Series I, due 2020 (1)	Level 2	$	—		$	—		$	(213	)	$	(148	)
7.95% Senior Notes Series F, due 2032 (1)	Level 2	$	—		$	—		$	(225	)	$	(162	)
Liabilities subject to compromise (2)	Level 3	$	(825	)	$	(366	)	$	—		$	—

__________________________________________


(1)	Carrying amounts include unamortized discounts and debt issuance costs. Please read Note 14—Debt for further discussion.


(2)	Carrying amounts represent the Genco senior notes that have been classified as liabilities subject to compromise as of December 31, 2016. The fair value of the senior notes was equal to the Genco Plan consideration and is a level 3 valuation due to a lack of observable inputs that make up the consideration. Please read Note 22—Genco Chapter 11 Bankruptcy 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, 2016 and 2015 , our credit exposure as it relates to the mark-to-market portion of our risk management portfolio totaled $79 million and $45 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, 2016 and 2015 , we had $62 million and $56 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, 2016 and 2015 , we were not holding any collateral received from counterparties.

F-25

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 6—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)	2016			2015			2014
Beginning of period	$	19		$	20		$	58
Other comprehensive income (loss) before reclassifications:
Actuarial gain (loss) and plan amendments (net of tax of $3, zero, and zero, respectively)	2			3			(33		)
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)	(5		)	(4		)	(5		)
Net current period other comprehensive income (loss), net of tax	2			(1		)	(38		)
End of period	$	21		$	19		$	20

__________________________________________


(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 19—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 19—Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans for further discussion.

Note 7—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)	2016			2015		2014
Interest paid (net of amount capitalized of $10, $12, and $9, respectively)	$	548		$	491	$	120
Taxes paid (net of refunds)	$	(1	)	$	2	$	—
Other non-cash investing and financing activity:
Change in capital expenditures included in accounts payable	$	(13	)	$	10	$	23
Change in capital expenditures pursuant to equipment financing agreements	$	11		$	61	$	—
Non-cash consideration transferred for acquisitions	$	—		$	105	$	—

Note 8—Inventory

A summary of our inventories is as follows:



(amounts in millions)	December 31, 2016		December 31, 2015
Materials and supplies	$	182	$	178
Coal (1)	238		350
Fuel oil (1)	17		17
Emissions allowances (2)	8		51
Other	—		1
Total	$	445	$	597

F-26

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

__________________________________________

(1)

At December 31, 2016 , approximately $44 million and $12 million of the coal and fuel oil inventory, respectively, are part of an inventory financing agreement. At December 31, 2015 , approximately $44 million and $16 million of the coal and fuel oil inventory, respectively, were part of an inventory financing agreement. Please read Note 14—Debt —Brayton Point Inventory Financing for further discussion.


(2)	At December 31, 2016 and December 31, 2015 , a portion of this inventory was held as collateral by one of our counterparties as part of an inventory financing agreement. Please read Note 14—Debt —Emissions Repurchase Agreements for further discussion.

Note 9—Property, Plant and Equipment

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



(amounts in millions)	December 31, 2016			December 31, 2015
Power generation	$	7,537		$	8,178
Buildings and improvements	944			956
Office and other equipment	98			101
Property, plant and equipment	8,579			9,235
Accumulated depreciation	(1,458		)	(888		)
Property, plant and equipment, net	$	7,121		$	8,347

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)	2016		2015		2014
Total interest costs incurred	$	556	$	487	$	187
Capitalized interest	$	10	$	12	$	9

Impairments

During the years ended December 31, 2016 and 2015 , we recognized the following impairments in our consolidated statements of operations:



Facility	Fair Value		2016		2015
Stuart (1)	$	—	$	56	$	—
Newton FGD (2)	$	—	148		—
Baldwin (3)	$	97	645		—
Wood River (4)	$	—	—		74
Brayton Point (5)	$	86	—		25
Total			$	849	$	99

_________________________________________


(1)	On-going required maintenance and environmental capital expenditures combined with consistently poor reliability and a determination that the facility would experience recurring negative cash flows.


(2)	The flue gas desulfurization (“FGD”) systems construction project at our Newton generation facility was terminated.


(3)	Units failed to recover their basic operating costs in the most recent MISO auction.


(4)	Primarily attributable to its uneconomic operation stemming from a poorly designed wholesale capacity market and increased environmental costs.


(5)	Temperate weather had a significant impact on the facility’s remaining cash flows, as the facility will retire in June 2017.

Valuation Methodology

We performed step two of the impairment analysis for each facility, excluding Newton, using a DCF model with a discount rate between 9 and 13 percent , assuming normal operations for the estimated remaining useful lives of the facilities. For the model, gross margin was based on forward commodity market prices obtained from third party quotations for the first two years, and for the subsequent eight years, we used commodity and capacity price curves developed internally using forward New York Mercantile

F-27

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Exchange natural gas prices and supply and demand factors. For each year of the remaining useful life of each facility beyond the first ten years, we assumed a 2.5 percent growth rate per year, based upon management’s view of future conditions. We also used management’s forecasts of operations and maintenance expense, general and administrative expense, and capital expenditures for five years and assumed a 2.5 percent growth rate. For the Newton facility, since the FGD project was abandoned, we wrote down the FGD assets to their salvage value, which was less than $1 million .

Note 10—Joint Ownership of Generating Facilities

We hold ownership interests in certain jointly owned generating facilities. We are entitled to the proportional share of the generating capacity and the output of each unit equal to our ownership interests. We pay our share of capital expenditures, fuel inventory purchases, and operating expenses, except in certain instances where agreements have been executed to limit certain joint owners’ maximum exposure to the additional costs. Our share of revenues and operating costs of the jointly owned generating facilities are included within the corresponding financial statement line items in our consolidated statements of operations.

The following tables present the ownership interests of the jointly owned facilities as of December 31, 2016 and 2015 included in our consolidated balance sheets. Each facility is co-owned with one or more other generation companies.



	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



	December 31, 2015
(dollars in millions)	Ownership Interest		Property, Plant and Equipment		Accumulated Depreciation			Construction Work in Progress		Total
Miami Fort	64.0	%	$	207	$	(16	)	$	3	$	194
Stuart (1)	39.0	%	$	32	$	(4	)	$	20	$	48
Conesville (1)	40.0	%	$	61	$	(2	)	$	4	$	63
Zimmer	46.5	%	$	99	$	(10	)	$	11	$	100
Killen (1)	33.0	%	$	17	$	(1	)	$	2	$	18

__________________________________________


(1)	Facilities not operated by Dynegy.

Note 11—Unconsolidated Investments

Equity Method Investments

Elwood. On November 21, 2016, Dynegy sold its 50 percent equity interest in the Elwood Energy facility to J-Power USA Development Co. Ltd. for approximately $173 million (the “Elwood Sale”). Elwood Energy owns a 1,580 MW natural gas-fired facility located in Elwood, Illinois. During the third quarter of 2016 , we recorded a charge of $9 million to Impairments in our consolidated statements of operations to write down our investment in Elwood to the sales price. Additionally, approximately $35 million of previously posted collateral was returned to Dynegy at closing.

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, respectively, 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 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 of investment. As of December 31, 2016 and 2015 , we have approximately zero and $3 million in accounts receivable due from Elwood, which is included in Accounts receivable in our consolidated balance sheets.

Black Mountain. On June 27, 2014, we completed the sale of our 50 percent partnership interest in Nevada Cogeneration Associates #2, a partnership that owns Black Mountain, an 85 MW ( 43 net MW) natural gas-fired combined-cycle gas turbine facility in Nevada. We received $17 million in cash proceeds upon the close of the transaction, which is reflected in Gain on sale

F-28

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

of assets, net in our consolidated statements of operations for the year ended December 31, 2014. In connection with the sale, our guarantee was terminated. Additionally, we received $10 million in cash distributions from Black Mountain, which is recorded as Earnings from unconsolidated investments in our consolidated statements of operations for the year ended December 31, 2014.

Note 12—Intangible Assets and Liabilities

The following table summarizes the components of our intangible assets and liabilities as of December 31, 2016 and 2015 :



	December 31, 2016									December 31, 2015
(amounts in millions)	Gross Carrying Amount			Accumulated Amortization			Net Carrying Amount			Gross Carrying Amount			Accumulated Amortization			Net Carrying Amount
Intangible Assets:
Electricity contracts	$	260		$	(206	)	$	54		$	260		$	(126	)	$	134
Gas transport contracts	13			(6		)	7			46			(16		)	30
Total intangible assets	$	273		$	(212	)	$	61		$	306		$	(142	)	$	164

Intangible Liabilities:
Electricity contracts	$	(28	)	$	26		$	(2	)	$	(30	)	$	19		$	(11	)
Coal contracts	(49		)	42			(7		)	(134		)	82			(52		)
Coal transport contracts	(86		)	73			(13		)	(104		)	64			(40		)
Gas transport contracts	(41		)	8			(33		)	(64		)	27			(37		)
Total intangible liabilities	$	(204	)	$	149		$	(55	)	$	(332	)	$	192		$	(140	)
Intangible assets and liabilities, net	$	69		$	(63	)	$	6		$	(26	)	$	50		$	24

The following table presents our amortization expense (revenue) of intangible assets and liabilities for the years ended December 31, 2016, 2015 and 2014 :



	Year Ended December 31,
(amounts in millions)	2016			2015			2014
Electricity contracts, net (1)	$	70		$	75		$	96
Coal contracts, net (2)	(41		)	(60		)	(14		)
Coal transport contracts, net (2)	(27		)	(32		)	(29		)
Gas transport contracts, net (2)	19			6			(8		)
Total	$	21		$	(11	)	$	45

__________________________________________


(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, 2016 is as follows: 2017 — $17 million , 2018 — $4 million , 2019 — $1 million , 2020 — ($1) million and 2021 — ($3) million .

Note 13—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 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”.

F-29

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 as follows:



VWAP of Dynegy Common Stock		Common Shares Issued
Equal to or greater than $19.92		5.0201 shares (minimum settlement rate)
Less than $19.92, but greater than $16.13		$100 divided by VWAP
Less than or equal to $16.13		6.1996 shares (maximum settlement rate)

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-30

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 14—Debt

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



(amounts in millions)	December 31, 2016			December 31, 2015
Secured Obligations:
Dynegy Inc.:
Tranche B-2 Term Loan, due 2020	$	224		$	780
Tranche C Term Loan, due 2023 (1)	2,000			—
Revolving Facility	—			—
Forward Capacity Agreement	219			—
Inventory Financing Agreements	129			136
Subtotal secured obligations	2,572			916
Unsecured Obligations:
Dynegy Inc.:
7.00% Amortizing Notes, due 2019 (TEUs)	80			—
6.75% Senior Notes, due 2019	2,100			2,100
7.375% Senior Notes, due 2022	1,750			1,750
5.875% Senior Notes, due 2023	500			500
7.625% Senior Notes, due 2024	1,250			1,250
8.00% Senior Notes, due 2025 (2)	750			—
Equipment Financing Agreements	97			75
Subtotal unsecured obligations	6,527			5,675
Total Dynegy Inc.	9,099			6,591
Genco Unsecured Obligations (3) :
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
Total Genco	—			825
Total debt obligations	9,099			7,416
Unamortized debt discounts and issuance costs (4)	(120		)	(207		)
	8,979			7,209
Less: Current maturities, including unamortized debt discounts and issuance costs, net	201			80
Total Long-term debt	$	8,778		$	7,129

__________________________________________

(1)

At December 31, 2016 , the escrowed term loan, under the Finance IV Credit Agreement, was secured by first-priority liens on amounts in the applicable escrow account which was classified as long-term Restricted cash in our consolidated balance sheet. Upon the close of the Delta Transaction, this debt obligation became Dynegy Inc.’s secured obligation. Please read Finance IV Credit Agreement below for further discussion.


(2)	The $750 million , 8 percent unsecured senior notes (the “2025 Senior Notes”) do not provide registration rights but otherwise have terms and provisions similar to our approximately $5.6 billion in senior notes (“Dynegy Senior Notes”).

(3)

On December 9, 2016, Genco filed a prepackaged plan of reorganization Chapter 11 Case (the “Chapter 11 Case”). As a result, we reclassified the Genco unsecured obligations as Liabilities subject to compromise in our December 31, 2016 consolidated balance sheet. Additionally, we wrote off approximately $94 million of remaining unamortized debt discount. See Note 22—Genco Chapter 11 Bankruptcy for further discussion.


(4)	Includes $111 million of unamortized debt discounts as of December 31, 2015 relating to the Genco unsecured obligations.

F-31

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Aggregate maturities of the principal amounts of all indebtedness, excluding unamortized discounts, as of December 31, 2016 are as follows:



	(in millions)
2017	$	210
2018	212
2019	2,200
2020	262
2021	31
Thereafter	6,184
Total	$	9,099

Credit Agreement and Finance IV Credit Agreement

As of December 31, 2016 , we had a $2.225 billion credit agreement, as amended, that consisted of (i) an $800 million seven -year senior secured term loan facility (the “Tranche B-2 Term Loan”) and (ii) $1.425 billion in senior secured revolving credit facilities (the “Revolving Facility,” and collectively with the Tranche B-2 Term Loan, the “Credit Agreement”). Additionally, we had a $2.0 billion , seven -year senior term loan, under the Finance IV Credit Agreement, as defined below.

During 2016, we made $6 million of required payments as well as a voluntary repayment in the amount of $550 million on the Tranche B-2 Term Loan.

At December 31, 2016 , there were no amounts drawn on the Revolving Facility; however, we had outstanding letters of credit (“LCs”) of approximately $302 million , which reduce the amount available under the Revolving Facility. The Credit Agreement contains customary events of default and affirmative and negative covenants, subject to certain specified exceptions, including a Senior Secured Leverage Ratio (as defined in the Credit Agreement) calculated on a rolling four quarters basis. Beginning December 31, 2016 and thereafter, the Consolidated Senior Secured Net Debt to Consolidated Adjusted EBITDA ratio is 4.00 :1.00. Based on the calculation outlined in the Credit Agreement, we are in compliance as of December 31, 2016 .

Finance IV Credit Agreement . On June 27, 2016 (the “Term Loan Closing Date”), Finance IV entered into a term loan credit agreement which provided for a $2.0 billion , seven -year Tranche C Term Loan, which would mature on June 27, 2023. The Tranche C Term Loan bore interest at either (i) 4 percent per annum plus LIBOR, subject to a floor of 1 percent with respect to any LIBOR Loan or (ii) 3 percent per annum plus the Base Rate with respect to any Base Rate Loan.

Proceeds of the term loan were placed into escrow pending the consummation of the Delta Transaction. Dynegy additionally contributed $70 million into escrow so that the aggregate funds in the Escrow Account would be sufficient to repay the term loan plus any interest that may accrue for a period of six months from the Term Loan Closing Date. The Finance IV Credit Agreement contained limited events of default and affirmative covenants and one negative covenant, which restricted the activities of Finance IV to those primarily relating to the Delta Transaction and financing. The obligations of Finance IV under the Finance IV Credit Agreement were secured by the related amounts placed in escrow from time to time.

As of December 31, 2016 , we had $2.0 billion classified as long-term Restricted cash and $21 million classified as short-term Restricted cash in our consolidated balance sheet related to the Escrow Agreement.

Following the release of funds from escrow upon the satisfaction of the Delta Transaction Escrow Conditions, as defined in the Finance IV Credit Agreement (the “Escrow Release Date”), Finance IV was merged with and into Dynegy, with Dynegy as the surviving entity, and Dynegy used the amounts released from escrow to fund a portion of the Delta Transaction.

Interest Rate Swaps

During 2013, we amended our interest rate swaps to more closely match the terms of our Tranche B-2 Term Loan. The swaps have an aggregate notional value of approximately $769 million at an average fixed rate of 3.19 percent with a floor of one percent and expire during the second quarter of 2020. In lieu of paying the breakage fees related to terminating the old swaps and issuing the new swaps, the costs were incorporated into the terms of the new swaps. As a result, any cash flows related to the settlement of the swaps are reflected as a financing activity in our consolidated statements of cash flows.

F-32

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 of $1.75 (or, in the case of the installment payment due on October 1, 2016, $1.94 ) 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 13—Tangible Equity Units for further discussion.

The Indenture limits, among other things, the ability of Dynegy to consolidate, merge, sell, or dispose all or substantially all of its assets. If a fundamental change occurs, or if Dynegy elects to settle the SPCs early or to redeem the SPCs in connection with a termination of the Delta Stock Purchase Agreement, then the holders of the Amortizing Notes will have the right to require Dynegy to repurchase the Amortizing Notes at a repurchase price equal to the principal amount of the Amortizing Notes as of the repurchase date (as described in the supplemental indenture) plus accrued and unpaid interest. The Indenture also contains customary events of default which would permit the holders of the Amortizing Notes to declare those Amortizing Notes to be immediately due and payable if not cured within applicable grace periods, including the failure to make timely installment payments on the Amortizing Notes or other material indebtedness, the failure to satisfy covenants, and specified events of bankruptcy and insolvency.

Letter of Credit Facilities

Dynegy has an LC Reimbursement Agreement with Macquarie Bank Limited (“Macquarie Bank”), for an LC in an amount not to exceed $55 million . The expiry date of the facility was extended in August 2016 to September 19, 2017. At December 31, 2016 , there was $55 million outstanding under this LC.

Illinois Power Marketing Company (“IPM”) has LC and reimbursement agreements with issuing banks in which the issuing banks agree to issue standby LCs in stated amounts not to exceed $50 million , in aggregate, to support performance obligations and other general corporate activities of IPM and IPRG. As of December 31, 2016 , there were $25 million in LCs outstanding under these facilities. The IPM LC facilities are collateralized by cash, and as of December 31, 2016 , IPM had $19 million deposited with the issuing banks. Upon the Emergence Date, these LCs were released and cash was returned to Dynegy.

Forward Capacity Agreement

On March 18, 2016, we entered into a bilateral contract with a financial institution to sell a portion of our forward cleared PJM capacity auction volumes. In exchange, we received $198 million in cash proceeds during the first quarter of 2016. The buyer in this transaction will receive capacity payments from PJM during the Planning Years 2017-2018 and 2018-2019 in the amounts of $110 million and $109 million , respectively. Dynegy will continue to be subject to the performance obligations as well as any associated performance penalties and bonus payments for those planning years. The transaction is accounted for as a debt issuance of $219 million with an implied interest rate of 4.45 percent .

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.

As the materials are purchased and delivered to our facilities, our debt obligation and line of credit increase based on the then market rate of the materials, transportation costs, and other expenses. The debt obligation increases for 85 percent of the total cost of the coal and for 90 percent of the total cost of the fuel oil. The line of credit increases for the remaining 15 percent and 10 percent for coal and oil costs, respectively. We repay the debt obligation and line of credit from revenues received, at the then market price, for the amount of the materials consumed on a weekly basis.

As of December 31, 2016 , there was $51 million outstanding under this agreement. Both the debt obligation related to coal and the base level of fuel oil, as well as the line of credit, bear interest at an annual interest rate of the 3 -month LIBOR plus 5.6 percent . An availability fee is calculated on a per annum rate of 0.25 percent . Additionally, we had collateral postings of approximately zero . The Inventory Financing Agreement terminates, and the remaining obligation, if any, becomes due and payable, on May 31, 2017.

Emissions Repurchase Agreements. In August 2015, we entered into two repurchase transactions with a third party in which we sold approximately $78 million of RGGI inventory and received cash. We are obligated to repurchase a portion of the

F-33

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

inventory in February 2017 and the remaining inventory in February 2018 at a specified price with an annualized carry cost of approximately 3.49 percent . As of December 31, 2016 , there was $78 million , in aggregate, outstanding under these agreements.

In 2013, we entered into two repurchase transactions in which we sold $6 million in California Carbon Allowances (“CCA”) credits and $11 million of RGGI inventory and received cash. In the first quarter 2014, we entered into an additional repurchase agreement with a third party in which we sold $12 million of RGGI inventory and received cash. In October 2014, we repurchased all $6 million of the previously sold CCA credits, and in February 2015, we repurchased all $23 million of the previously sold RGGI inventory.

Equipment Financing Agreements

Under certain of our contractual service agreements in which we receive maintenance and capital improvements for our gas-fueled generation fleet, we have obtained parts and equipment intended to increase the output, efficiency and availability of our generation units. We have financed these parts and equipment under agreements with maturities ranging from 2017 to 2025. The portion of future payments attributable to principal will be classified as cash outflows from financing activities and the portion of future payments attributable to interest will be classified as cash outflows from operating activities in our consolidated statements of cash flows. The related assets were recorded at the net present value of the payments of $73 million . The $24 million discount is currently amortized as interest expense over the life of the payments.

Genco Senior Notes

Genco’s approximately $825 million in aggregate principal amount of unsecured senior notes (the “Genco Senior Notes”) were an obligation of Genco, a subsidiary of IPH. The Genco Senior Notes were non-recourse to Dynegy. Please read Note 1—Organization and Operations for further discussion.

On December 9, 2016, Genco filed a Bankruptcy Petition commencing a prepackaged Chapter 11 Case. Genco continued to operate its business as debtor-in possession until the Emergence Date. We reclassified the $825 million face value of the Genco unsecured obligations to Liabilities subject to compromise in our December 31, 2016 consolidated balance sheet and charged $94 million of unamortized debt discount to Bankruptcy reorganization items in our consolidated statement of operations. Please read Note 22—Genco Chapter 11 Bankruptcy for further discussion.

Note 15—Income Taxes

Income Tax Benefit. We are subject to U.S. federal and state income taxes on our operations.

Our losses from continuing operations before income taxes were $1.289 billion , $427 million and $268 million for the years ended December 31, 2016, 2015 and 2014 , respectively, which was solely from domestic sources.

Our components of income tax benefit related to income (loss) from continuing operations were as follows:



	Year Ended December 31,
(amounts in millions)	2016		2015			2014
Current tax benefit (expense)	$	15	$	(3	)	$	—
Deferred tax benefit	30		477			1
Income tax benefit	$	45	$	474		$	1

F-34

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, 2016, 2015 and 2014 were equivalent to effective rates of 3 percent , 111 percent , and zero 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)	2016			2015			2014
Expected tax benefit at U.S. statutory rate (35%)	$	451		$	149		$	94
State taxes	16			68			—
Permanent differences (1)	(4		)	16			(15		)
Valuation allowance (2)(3)	(404		)	271			(331		)
NOL reduction from acceleration of AMT Credits	(17		)	—			—
Uncertain tax position	—			—			244
Unconsolidated subsidiary adjustment	—			—			5
Adjustment to AMT credits	—			(26		)	—
Other	3			(4		)	4
Income tax benefit	$	45		$	474		$	1

__________________________________________

(1)

Permanent items for years ended December 31, 2016, 2015 and 2014 included a $2 million benefit, an $18 million benefit, and a $14 million expense, 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 year ended December 31, 2016 includes $5 million of Income tax expense for non-deductible legal fees related to the Genco Plan. Please read Note 22—Genco Chapter 11 Bankruptcy for further discussion.


(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)

On April 14, 2014, we received final notice from the Internal Revenue Service (“IRS”) that their audit of our 2012 tax year has been completed. In accordance with accounting guidance in ASC 740, Income Taxes (“ASC 740”), we recognized $270 million of net tax benefits for tax positions included in the 2012 tax return that had not previously met the “more likely than not” recognition threshold. These benefits were recognized in the second quarter of 2014 as a discrete item with a corresponding adjustment to the valuation allowance.

F-35

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)	2016			2015
Non-current deferred tax assets:
NOL carryforwards	$	1,629		$	1,533
AMT and state tax credit carryforwards	241			275
Reserves (legal, environmental and other)	7			17
Pension and other post-employment benefits	18			16
Asset retirement obligations	85			89
Deferred financing costs and intangible/other contracts	48			64
Derivative contracts	57			69
Other	46			27
Subtotal	2,131			2,090
Less: valuation allowance	(1,704		)	(1,276		)
Total non-current deferred tax assets	$	427		$	814
Non-current deferred tax liabilities:
Depreciation and other property differences	$	(371	)	$	(738	)
Investment in unconsolidated partnership	—			(27		)
Derivative contracts	(44		)	(4		)
Other	(17		)	(74		)
Total non-current deferred tax liabilities	$	(432	)	$	(843	)
Net non-current deferred tax liabilities	$	(5	)	$	(29	)

NOL Carryforwards. As of December 31, 2016 , we had approximately $4.2 billion of federal tax net operating loss carryforwards (“NOLs”) and $3.4 billion of state NOLs that can be used to offset future taxable income. The federal NOLs expire beginning in 2024 through 2036. 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. While our Alternative Minimum Tax (“AMT”) credits do not expire, the change in control that occurred on May 9, 2012 materially impacted our ability to utilize the AMT credits. The Company filed an amended 2009 tax return on April 8, 2015, as permitted by the IRS, which allows the Company to utilize more AMT NOLs. This relief resulted in a reduction of AMT credits of $26 million . For the year ended December 31, 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 $16 million .

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, 2016 , we have a valuation allowance against our net deferred assets including federal and state NOLs and AMT credit carryforwards. Additionally, at December 31, 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.

F-36

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The changes in the valuation allowance were as follows:



	Year Ended December 31,
	2016		2015			2014
Beginning of period	$	1,276	$	1,535		$	1,149
Changes in valuation allowance—continuing operations:
Charged to costs and expenses	428		(259		)	370
Charged to other accounts	—		—			16
End of period	$	1,704	$	1,276		$	1,535

Unrecognized Tax Benefits. We are complete with federal income tax audits by the IRS through 2013 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 2010 or earlier with few exceptions.

On April 14, 2014, we received final notice from the IRS that their audit of our 2012 tax year was completed. In accordance with accounting guidance in ASC 740, we recognized $270 million of net tax benefits for tax positions included in the 2012 tax return that had not previously met the “more likely than not” recognition threshold. These benefits were recognized in 2014 as a discrete item with a corresponding adjustment to the valuation allowance.

A reconciliation of our beginning and ending amounts of unrecognized tax benefits follows:



	Year Ended December 31,
amounts in millions	2016		2015			2014
Unrecognized tax benefits, beginning of period	$	3	$	4		$	274
Decrease due to settlements and payments	—		(1		)	(270		)
Unrecognized tax benefits, end of period	$	3	$	3		$	4

As of December 31, 2016 , approximately $3 million of unrecognized tax benefits would impact our effective tax rate if recognized.

Note 16—Earnings (Loss) Per Share

Basic earnings (loss) per share is based on the weighted average number of common shares outstanding during the period. Diluted earnings (loss) is based on the weighted average number of common shares used for the basic earnings (loss) per share computation, adjusted for the incremental issuance of shares of common stock assuming (i) our stock options and warrants are exercised, (ii) our restricted stock units and performance stock units are fully vested under the treasury stock method, and (iii) our mandatory convertible preferred stock and the SPCs are converted into common stock under the if converted method. Please read Note 18—Capital Stock and Note 13—Tangible Equity Units for further discussion.

F-37

DYNEGY INC.

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, 2016, 2015 and 2014 :



	Year Ended December 31,
(in millions, except per share amounts)	2016	2015		2014
Shares outstanding at the beginning of the period	117	124		100
Weighted-average shares during the period of:
Shares issuances	—	4		5
Shares repurchases	—	(3	)	—
Prepaid stock purchase contract (TEUs) (1)	12	—		—
Basic weighted-average shares	129	125		105
Dilution from potentially dilutive shares (2)	—	1		—
Diluted weighted-average shares	129	126		105

_________________________________________


(1)	The minimum settlement amount, or 23,092,460 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 13—Tangible Equity Units for further discussion.


(2)	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 years ended December 31, 2016 and 2014.

For the years ended December 31, 2016, 2015 and 2014 , 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)	2016	2015	2014
Stock options	2.8	0.5	1.4
Restricted stock units	1.3	—	1.0
Performance stock units	1.2	—	0.3
Warrants	15.6	15.6	15.6
Series A 5.375% mandatory convertible preferred stock	12.9	12.9	4.0
TEUs	5.4	—	—
Total	39.2	29.0	22.3

Note 17—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-

F-38

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

district litigation proceeding pending in the United States District Court for Nevada. At this time we cannot reasonably estimate a potential loss.

Illinova Generating Company Arbitration. In May 2007, our subsidiary Illinova Generating Company (“IGC”) received an adverse award in an arbitration brought by Ponderosa Pine Energy, LLC (“PPE”). The award required IGC to pay PPE $17 million , which IGC paid in June 2007 under protest while simultaneously seeking to vacate the award. On May 23, 2014, the Texas Supreme Court vacated the arbitration award based upon the evident partiality of one of the arbitrators. On November 20, 2014, PPE initiated a new arbitration against IGC and its co-respondents, but the Dallas District Court enjoined the arbitration from proceeding against IGC while any dispute over IGC’s $17 million payment remains pending. On December 16, 2014, the Dallas District Court entered a judgment requiring the return of the $17 million to IGC and an additional $2.5 million payment to IGC for interest. PPE paid the $17 million in principal and the $2.5 million in interest to IGC. On July 14, 2016, the Dallas Court of Appeals affirmed the judgment. PPE’s deadline to appeal the judgment to the Texas Supreme Court has expired. We recognized a gain of $20 million which is included in Other income and expense, net in our consolidated statements of operations for the year ended December 31, 2016.

Advatech Dispute. On September 2, 2016, Genco 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. Genco does not believe Advatech calculated the termination payment correctly, but does owe Advatech a final payment of $0.5 million as well as demobilization costs which Advatech claims are $0.7 million . On October 27, 2016, Advatech initiated the dispute resolution process under the Contract. Settlement discussions required under the dispute resolution process have been unsuccessful. The next step is arbitration, which has not been initiated yet. Dynegy views the risk of a material loss as remote.

Other Contingencies

MISO 2015-2016 Planning Resource Auction. In May 2015, three complaints were filed at FERC regarding the Zone 4 results for the 2015-2016 Planning Resource Auction (“PRA”) conducted by MISO. Dynegy is a named party in one of the complaints. The complainants, Public Citizen, Inc., the Illinois Attorney General, and Southwestern Electric Cooperative, Inc., have challenged the results of the PRA as unjust and unreasonable, requested rate relief/refunds, and requested changes to the MISO PRA structure going forward. Complainants have also alleged that Dynegy may have engaged in economic or physical withholding in Zone 4 constituting market manipulation in the 2015-2016 PRA. The Independent Market Monitor for MISO (“MISO IMM”), which was responsible for monitoring the MISO 2015-2016 PRA, determined that all offers were competitive and that no physical or economic withholding occurred. The MISO IMM also stated, in a filing responding to the complaints, that there is no basis for the proposed remedies. We filed our Answer to these complaints and believe that we complied fully with the terms of the MISO tariff in connection with the 2015-2016 PRA, disputed the allegations, and will defend our actions vigorously. In addition, the Illinois Industrial Energy Consumers filed a complaint at FERC against MISO on June 30, 2015 requesting prospective changes to the MISO tariff. Dynegy also responded to this complaint.

On October 1, 2015, FERC issued an order of non-public, formal investigation, stating that shortly after the conclusion of the 2015-2016 PRA, FERC’s Office of Enforcement began a non-public informal investigation into whether market manipulation or other potential violations of FERC orders, rules and regulations occurred before or during the PRA (the “Order”). The Order noted that the investigation is ongoing, and that the order converting the informal, non-public investigation to a formal, non-public investigation does not indicate that FERC has determined that any entity has engaged in market manipulation or otherwise violated any FERC order, rule, or regulation.

On December 31, 2015, FERC issued an order on the complaints requiring a number of prospective changes to the MISO tariff provisions associated with calculating Initial Reference Levels and Local Clearing Requirements, effective as of the 2016-2017 PRA. The order did not address the arguments of the complainants regarding the 2015-2016 PRA, and stated that those issues remain under consideration and will be addressed in a future order.

New Source Review and CAA Matters.

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

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limitations. This decision may provide an additional defense to the allegations in the Newton facility NOV. In September 2016, we retired Newton Unit 2.

Wood River CAA Section 114 Information Request. In 2014, we received an information request from the EPA concerning our Wood River facility’s compliance with the Illinois State Implementation Plan (“SIP”) and associated permits. We responded to the EPA’s request and believe that there are no issues with Wood River’s compliance, but we are unable to predict the EPA’s response, if any. As of June 1, 2016, our Wood River facility has been retired.

CAA Notices of Violation. In December 2014, the EPA issued an NOV alleging violation of opacity standards at the Zimmer facility, which we co-own and operate. The EPA previously had issued NOVs to Zimmer in 2008 and 2010 alleging violations of the CAA, the Ohio SIP and the station’s air permits involving standards applicable to opacity, sulfur dioxide, sulfuric acid mist, and heat input. The NOVs remain unresolved. In December 2014, the EPA also issued NOVs alleging violations of opacity standards at the Stuart and Killen facilities, which we jointly own but do not operate.

Edwards CAA Citizen Suit. In April 2013, environmental groups filed a CAA citizen suit in the U.S. District Court for the Central District of Illinois alleging violations of opacity and particulate matter limits at our IPH segment’s Edwards facility. In August 2016, the District Court granted the plaintiffs’ motion for summary judgment on certain liability issues. We filed a motion seeking interlocutory appeal of the court’s summary judgment ruling. In February 2017, the appellate court denied our motion for interlocutory appeal. The District Court has not yet scheduled the remedy phase of the case. We dispute the allegations and will defend the case vigorously.

Ultimate resolution of any of these CAA matters could have a material adverse impact on our future financial condition, results of operations and cash flows. A resolution could result in increased capital expenditures for the installation of pollution control equipment, increased operations and maintenance expenses, and penalties. At this time we are unable to make a reasonable estimate of the possible costs, or range of costs, that might be incurred to resolve these matters.

Stuart National Pollutant Discharge Elimination System (“NPDES”) Permit Appeal. In January 2013, the Ohio EPA reissued the NPDES permit for the jointly owned Stuart facility. The operator of Stuart, The Dayton Power and Light Company, appealed various aspects of the permit, including provisions regarding thermal discharge limitations, to the Ohio Environmental Review Appeals Commission. Depending on the outcome of the appeal, the effects on Stuart’s operations could be material. At this time we are unable to make a reasonable estimate of the possible costs, or range of costs, that might be incurred to resolve this matter.

MISO Segment Groundwater . In 2012, the Illinois EPA (“IEPA”) issued violation notices alleging violations of groundwater standards onsite at our Baldwin and Vermilion facilities.

We initiated an investigation at Baldwin in 2011 at the request of the IEPA to determine if the facility’s CCR surface impoundment system impacts offsite groundwater. Results of the offsite groundwater quality investigation, as submitted to the IEPA in 2012, indicate two localized areas where Class I groundwater standards were exceeded. Based on the data and groundwater flows, we do not believe that the exceedances are attributable to the Baldwin CCR surface impoundment system.

At our retired Vermilion facility, which is not subject to the CCR rule, we submitted proposed corrective action plans for two CCR surface impoundments (i.e., the old east and the north CCR surface impoundments) to the IEPA in 2012. Our hydrogeological investigation indicates that these two CCR surface impoundments impact groundwater quality onsite and that such groundwater migrates offsite to the north of the property and to the adjacent Middle Fork of the Vermilion River. The proposed corrective action plans recommend closure in place of both CCR surface impoundments and include an application to the IEPA to establish a groundwater management zone while impacts from the facility are mitigated. In 2014, we submitted a revised corrective action plan for the old east CCR surface impoundment. We await IEPA action on our proposed corrective action plans. Our estimated cost of the recommended closure alternative for both the Vermilion old east and north CCR surface impoundments, including post-closure care, is approximately $10 million .

If remediation measures concerning groundwater are necessary in the future at either Baldwin or Vermilion, we may incur significant costs that could have a material adverse effect on our financial condition, results of operations, and cash flows. At this time we cannot reasonably estimate the costs, or range of costs, of remediation, if any, that ultimately may be required.

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If remediation measures concerning groundwater are necessary at any of our IPH facilities, IPH may incur significant costs that could have a material adverse effect on its financial condition, results of operations, and cash flows. At this time we cannot reasonably estimate the costs, or range of costs, of remediation, if any, that ultimately may be required.

In response to the Hennepin report, we made capital improvements to the Hennepin east CCR surface impoundment berms and notified the EPA of our intent to close the Hennepin west CCR surface impoundment. The preliminary estimated cost for closure of the west CCR surface impoundment, including post-closure monitoring, is approximately $5 million , which is reflected in our AROs. We performed further studies needed to support closure of the west CCR surface impoundment, submitted those studies to the IEPA in 2014 and await IEPA action.

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, 2016 .

Coal Purchase Commitments. At December 31, 2016 , we had contracts in place to purchase coal for our generation facilities with aggregate minimum commitments of $827 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, 2016 , we had coal transportation contracts and rail car leases in place for our generation facilities with aggregate minimum commitments of $823 million .

Contractual Service Agreements. Contractual service agreements represent obligations with respect to long-term plant maintenance agreements. Recently we have undertaken several measures to restructure some of our existing maintenance service agreements with our turbine service providers. As of December 31, 2016 , our obligation with respect to these restructured agreements is limited to the termination payments, which are approximately $410 million in the event all contracts are terminated by us.

In addition, during this year we have committed to securing capital spares for our gas-fueled generation fleet to help minimize production disturbances. As of December 31, 2016 , we have obligations to purchase spare parts of $24 million with payments made through 2026, of which $11 million reflects spare parts received. 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, 2016 , we had contracts in place to purchase gas for our generation facilities with aggregate minimum commitments of $420 million .

Gas Transportation. At December 31, 2016 , 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 $173 million .

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Operating Leases.

Office Space, Equipment and Other Property. Minimum lease payment obligations, by year, associated with office space, equipment, land and other leases are $5 million per year for the years 2017-2021.

During the years ended December 31, 2016, 2015 and 2014 , we recognized rental expense of approximately $5 million , $5 million and $5 million , respectively.

Charter Agreement. The aggregate minimum base commitments of our charter party agreement are approximately $5 million for the year ended December 31, 2017. We are party to one charter agreement related to a very large gas carrier (“VLGC”) previously utilized in our former global liquids business. The primary term of the charter was through September 2014 but has been extended through September 2017 at the option of the counterparty. The VLGC has been sub-chartered to a wholly owned subsidiary of Transammonia Inc. on terms that are identical to the terms of the original charter agreement. To date, the subsidiary of Transammonia Inc. has complied with the terms of the sub-charter agreement and has not exercised the remaining optional extension.

Other Obligations. We have other obligations of $31 million for contracts in place to purchase limestone, $22 million for interconnection services and $32 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.

Note 18—Capital Stock

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. As of December 31, 2016 , there were 4 million shares of our Series A Mandatory Convertible Preferred Stock (as described below) issued and outstanding.

Series A Mandatory Convertible Preferred Stock. On October 14, 2014, we issued 4 million shares, $0.01 par value, pursuant to a registered public offering, of our 5.375% Series A Mandatory Convertible Preferred Stock (“Mandatory Convertible Preferred Stock”) at $100 per share, for gross proceeds of approximately $400 million , before underwriting discounts and commissions of $13 million (“Mandatory Convertible Preferred Stock Offering”). These issuance costs are included in Additional paid-in capital in our consolidated balance sheets.

The Mandatory Convertible Preferred Stock has a liquidation preference of $100 per share, or an aggregate preference of $400 million . Dividends accrue at 5.375 percent per annum on the liquidation preference and will be payable on a cumulative basis when and if declared by our Board of Directors. We may pay declared dividends in cash or, subject to certain limitations, in shares of our common stock or by delivery of any combination of cash and shares of our common stock on February 1, May 1, August 1 and November 1 of each year, commencing on February 1, 2015, and to, and including, November 1, 2017. In the first quarter of 2015, we paid a dividend of $1.64 per share. In each quarter from the second quarter of 2015 to the fourth quarter of 2016, we paid a dividend of $1.34 per share.

As long as we are not in default on our credit agreements, we are not restricted from paying dividends on the Mandatory Convertible Preferred Stock. During the years ended December 31, 2016 and 2015 , we paid an aggregate of $22 million and $23 million in dividends, respectively. We paid no dividends during 2014.

Each share of Mandatory Convertible Preferred Stock will, unless previously converted, automatically convert on November 1, 2017, into between 2.5806 and 3.2258 shares of our common stock, subject to anti-dilution and other adjustments. The Mandatory Convertible Preferred Stock is not redeemable by us. The holders of the Mandatory Convertible Preferred Stock generally have no voting rights except in the case of dividend arrearages. Holders are not entitled to participate in any dividends which may be declared and paid on our common stock.

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At any time prior to November 1, 2017, other than during a Fundamental Change Conversion Period (as defined in the Certificate of Designations for the Mandatory Convertible Preferred Stock (the “Certificate of Designations”)), holders of the Mandatory Convertible Preferred Stock have the right to elect to convert their shares in whole or in part at the Minimum Conversion Rate of 2.5806 shares of our common stock per share of Mandatory Convertible Preferred Stock. This Minimum Conversion Rate is subject to certain anti-dilution adjustments. The Certificate of Designations provides that during a Fundamental Change Conversion Period, the shares may be converted by the holder at the Fundamental Change Conversion Rate, as defined therein.

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 13—Tangible Equity Units for further discussion.

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, 2016, 2015 and 2014 :



	Shares outstanding balance as of December 31,
(in millions)	2016	2015		2014
Beginning of period	117	124		100
Common stock offering, including shares sold through underwriter's option	—	—		24
Shares issued as consideration for the ECP Acquisition	—	3		—
Shares repurchases (in treasury)	—	(11	)	—
Share issued under long-term compensation plans	—	1		—
End of period	117	117		124

Warrants. As of the Plan Effective Date, we issued to Legacy Dynegy 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 have a five -year term expiring on October 2, 2017 . If the exercise price of the 2012 Warrants is greater than the market price of Dynegy’s common stock upon the determination date of a Subject Transaction, such distributions are equivalent to $0.01 per warrant, or approximately $150 thousand for all 2012 Warrants outstanding. As a result of a potential fixed distribution, these warrants are classified as a liability in our consolidated financial statements 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 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 “A&R 2012 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 A&R 2012 LTIP. The A&R 2012 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 A&R 2012 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 A&R 2012 LTIP will expire no later than 10 years from the date of the grant.

All RSUs granted under the A&R 2012 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 1.5 million shares of RSU’s granted in 2016 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.

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All PSUs granted under the A&R 2012 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. Compensation expense related to options, RSUs and PSUs granted totaled $31 million , $28 million and $19 million for the years ended December 31, 2016, 2015 and 2014 , 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 $11 million , $10 million and $7 million for the years ended December 31, 2016, 2015 and 2014 , respectively. As of December 31, 2016 , $25 million of total unrecognized compensation expense related to options, RSUs and PSUs granted is expected to be recognized over a weighted-average period of 1.46 years. The total fair value of options, RSUs and PSUs vested was $27 million , $18 million and $14 million for the years ended December 31, 2016, 2015 and 2014 , respectively. We did not capitalize or use cash to settle any share-based compensation in the years ended December 31, 2016, 2015 and 2014 .

No options were exercised for the year ended December 31, 2016. Cash received from option exercises for the years ended December 31, 2015 and 2014 was $0.5 million and $1 million , respectively, and the tax benefit realized for the additional tax deduction from share-based payment awards totaled less than $1 million for the years ended December 31, 2015 and 2014.

The following summarizes our stock option activity:



	Year Ended December 31, 2016
	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	1,832		$	22.81
Granted	979		$	11.05
Forfeited	(6	)	$	29.56
Outstanding at end of period	2,805		$	18.69	8.11	$	—
Vested and unvested expected to vest	2,805		$	18.69	8.11	$	—
Exercisable at end of period	1,370		$	21.69	6.9	$	—

During the years ended December 31, 2016, 2015 and 2014 , 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, 2015 and 2014 was $27.43 and $23.03 , respectively. The intrinsic value of options exercised during the years ended December 31, 2015 and 2014 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,
	2016			2015			2014
Dividend Yield	$	—		$	—		$	—
Expected volatility (1)	41.19		%	27.70		%	23.96		%
Risk-free interest rate (2)	1.42		%	1.64		%	1.61		%
Expected option life (3)	5.5 years			5.5 years			5.5 years
Weighted average grant-date fair value	$	4.37		$	7.93		$	5.91

__________________________________________


(1)	For the years ended December 31, 2016, 2015 and 2014 , 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, 2016
	RSUs (in thousands)		Weighted Average Grant Date Fair Value
Outstanding at beginning of period	1,413		$	26.71
Granted	1,950		$	11.20
Vested and released	(607	)	$	25.01
Forfeited	(39	)	$	16.15
Outstanding at end of period	2,717		$	16.11

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, 2015 and 2014 was $28.93 and $23.36 , 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, 2016
	PSUs (in thousands)		Weighted Average Grant Date Fair Value
Outstanding at beginning of period	576		$	25.22
Granted	769		$	11.04
Vested and released	(1	)	$	27.24
Forfeited	(123	)	$	23.35
Outstanding at end of period	1,221		$	16.48

The weighted average grant date fair value of PSUs granted during the years ended December 31, 2015 and 2014 was $27.54 and $23.03 .

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 2016, the fair value is determined using TSR for one-half of the award and the other half using pre-determined 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.

Note 19—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, 2016, 2015 and 2014 , our contributions related to these plans were approximately $43 million , $50 million and $37 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.

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Phantom Stock Plan. Dynegy has issued phantom stock units under its 2009 Phantom Stock Plan. Units awarded under this plan are long term incentive awards that grant the participant the right to receive a cash payment based on the fair market value of Dynegy’s stock on the vesting date of the award. 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. Expense recognized in connection with these awards during the years ended December 31, 2016, 2015 and 2014 was $1 million , $1 million and $4 million , respectively.

Dynegy Inc. 401(k) Savings Plans. For the years ended December 31, 2016, 2015 and 2014 , 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 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, 2016 .

During the years ended December 31, 2016, 2015 and 2014 , we recognized aggregate costs related to our 401(k) Plans of $15 million , $10 million and $7 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 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 benefit obligations and the funded status of the affected plans and recorded a net-of-tax gain of approximately $17 million through accumulated other comprehensive income.

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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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)	2016			2015			2016			2015
Benefit obligation, beginning of the year	$	483		$	408		$	74		$	95
Service cost	16			14			1			1
Interest cost	20			18			3			4
Actuarial (gain) loss	23			(20		)	4			(12		)
Benefits paid	(32		)	(26		)	(6		)	(5		)
Plan change	(2		)	—			(17		)	(10		)
Settlements	—			—			(17		)	(1		)
Acquisitions	—			89			—			2
Benefit obligation, end of the year	$	508		$	483		$	42		$	74
Fair value of plan assets, beginning of the year	$	410		$	364		$	67		$	68
Actual return on plan assets	37			(13		)	2			2
Employer contributions	—			4			—			—
Benefits paid	(32		)	(26		)	(3		)	(3		)
Settlements	—			—			(17		)	—
Acquisitions	—			81			—			—
Fair value of plan assets, end of the year	$	415		$	410		$	49		$	67
Funded status	$	(93	)	$	(73	)	$	7		$	(7	)

Our accumulated benefit obligation related to pension plans was $501 million and $481 million as of December 31, 2016 and 2015 , respectively. Our accumulated benefit obligation related to other post-employment plans was $42 million and $74 million as of December 31, 2016 and 2015 , respectively.

Amounts recognized in the consolidated balance sheets consist of:



	Pension Benefits						Other Benefits
	Year Ended December 31,
(amounts in millions)	2016			2015			2016			2015
Non-current assets	$	7		$	5		$	32		$	23
Current liabilities	—			—			(2		)	(2		)
Non-current liabilities	(100		)	(78		)	(23		)	(28		)
Net amount recognized	$	(93	)	$	(73	)	$	7		$	(7	)

Pre-tax amounts recognized in AOCI consist of:



	Pension Benefits						Other Benefits
	Year Ended December 31,
(amounts in millions)	2016			2015			2016			2015
Prior service credit	$	(12	)	$	(11	)	$	(47	)	$	(34	)
Actuarial loss (gain)	2			(6		)	1			2
Net gain recognized	$	(10	)	$	(17	)	$	(46	)	$	(32	)

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, 2016, 2015 and 2014 for the defined benefit pension plans were $1 million , $1 million and $2 million , respectively. The net prior service credit that was amortized from AOCI into net periodic benefit cost during the years ended December 31, 2016, 2015 and 2014 for other post-employment benefit plans was $4 million , $3 million and $3 million , respectively.

F-47

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The expected amounts that will be amortized from AOCI and recognized as components of net periodic benefit cost (gain) in 2017 are as follows:



(amounts in millions)	Pension Benefits			Other Benefits
Prior service credit	$	(1	)	$	(5	)
Actuarial (gain) loss	—			—
Net gain recognized	$	(1	)	$	(5	)

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)	2016			2015			2014
Service cost benefits earned during period	$	16		$	14		$	12
Interest cost on projected benefit obligation	20			18			17
Expected return on plan assets	(22		)	(23		)	(21		)
Amortization of:
Prior service credit	(1		)	(1		)	(1		)
Actuarial gain	—			—			(1		)
Net periodic benefit cost	$	13		$	8		$	6



	Other Benefits
	Year Ended December 31,
(amounts in millions)	2016			2015			2014
Service cost benefits earned during period	$	1		$	1		$	1
Interest cost on projected benefit obligation	3			4			4
Expected return on plan assets	(4		)	(4		)	(4		)
Amortization of:
Prior service credit	(4		)	(3		)	(3		)
Net periodic benefit gain	(4		)	(2		)	(2		)
Settlement cost (1)	6			—			—
Total benefit cost (gain)	$	2		$	(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,
	2016		2015		2016		2015
Discount rate (1)	4.05	%	4.35	%	4.00	%	4.35	%
Rate of compensation increase (2)	3.50	%	3.50	%	3.50	%	3.50	%

________________________________________


(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.

F-48

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following weighted average assumptions were used to determine net periodic benefit cost (gain):



	Pension Benefits						Other Benefits
	Year Ended December 31,
	2016		2015		2014		2016		2015		2014
Discount rate	4.05	%	4.35	%	4.00	%	4.00	%	4.35	%	4.00	%
Dynegy - Expected return on plan assets	5.60	%	5.70	%	6.00	%	N/A		N/A		N/A
EEI - Expected return on plan assets (1)	5.90	%	6.00	%	6.25	%	5.40	%	5.50	%	6.00	%
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 5.40 percent , 5.50 percent , and 6 percent for the years ended December 31, 2016, 2015 and 2014 , respectively. The expected return on EEI’s other post-employment plan assets was 6.30 percent , 6.20 percent , and 6.50 percent for EEI union employees for the years ended December 31, 2016, 2015 and 2014 , respectively. The expected return on EEI’s other post-employment plan assets was 4.50 percent , 4.80 percent , and 5.50 percent for EEI salaried employees for the years ended December 31, 2016, 2015 and 2014 , respectively.


(2)	The rate of compensation increase used for other post-employment benefits for the years ended December 31, 2016, 2015 and 2014 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 6.20 percent and 6.40 percent , respectively, for the year ended December 31, 2017. Our expected long-term rate of return on EEI’s other post-employment plan assets is 6.90 percent for EEI union employees and 5.50 percent for EEI salaried employees for the year ended December 31, 2017. 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,
	2016		2015		2014
Health care cost trend rate assumed for next year	7.25	%	7.00	%	7.25	%
Ultimate trend rate	4.50	%	4.50	%	4.50	%
Year that the rate reaches the ultimate trend rate	2025		2023		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	$	1	$	—
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, 2016 was approximately 46 percent to equity investments and approximately 54 percent to fixed income investments. The target asset mix for EEI’s plan assets as of December 31, 2016 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

F-49

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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, 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
Trust asset receivable (5)	—		—		—		—
Total	$	101	$	365	$	—	$	466



	Fair Value as of December 31, 2015
(amounts in millions)	Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	1	$	1	$	—	$	2
Equity securities:
U.S. companies (1)	32		125		—		157
Non-U.S. companies (2)	—		10		—		10
International (3)	8		54		—		62
Fixed income securities (4)	83		152		—		235
Trust asset receivable (5)	—		11		—		11
Total	$	124	$	353	$	—	$	477

________________________________________


(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.


(5)	Relates to the pension and other post-employment plans transferred to Dynegy as a result of the Acquisitions.

Contributions and Payments. We were required to make no contributions and $4 million in contributions to our pension plans and $2 million and no contributions to our other post-employment benefit plans during the years ended December 31, 2016 and 2015, respectively. We are required to make contributions of $4 million to our pension plans and $2 million to our other post-employment benefit plans during 2017.

F-50

DYNEGY INC.

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
2017	$	35	$	4
2018	$	34	$	3
2019	$	35	$	3
2020	$	37	$	3
2021	$	37	$	3
2022 - 2026	$	193	$	13

Note 20—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
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	)
2015 (2)
Revenues	$	632		$	990		$	1,232		$	1,016
Operating income (loss) (3)	$	(40	)	$	10		$	107		$	(13	)
Net income (loss)	$	(181	)	$	386		$	(24	)	$	(134	)
Net income (loss) attributable to Dynegy Inc. common stockholders	$	(185	)	$	382		$	(29	)	$	(140	)
Net income (loss) per share attributable to Dynegy Inc. common stockholders—Basic	$	(1.49	)	$	2.98		$	(0.23	)	$	(1.18	)
Net income (loss) per share attributable to Dynegy Inc. common stockholders—Diluted	$	(1.49	)	$	2.73		$	(0.23	)	$	(1.18	)

_____________________


(1)	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. See Note 9—Property, Plant and Equipment and Note 11—Unconsolidated Investments for more information.


(2)	The unaudited quarterly information for the quarters ended June 30, 2015, September 30, 2015 and December 31, 2015 reflects the impact of the Acquisitions. Please read Note 3—Acquisitions for further discussion.


(3)	The results for the quarters ended September 30, 2015 and December 31, 2015, include impairment charges of $74 million and $25 million , respectively. See Note 9—Property, Plant and Equipment for more information.

Note 21—Condensed Consolidating Financial Information

Dynegy’s senior notes are guaranteed by certain of our wholly owned subsidiaries. Not all of Dynegy’s subsidiaries guaranteed the senior notes including Dynegy’s indirect, wholly owned subsidiary, IPH. The following condensed consolidating financial statements as of and for the year ended December 31, 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 condensed consolidating financial statements for the year ended December 31, 2014 present the Escrow Issuers as the finance issuer of the $5.1 billion senior notes issued in October 2014. With the close of the Acquisitions, the Escrow Issuers were merged into Dynegy.

F-51

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The 100 percent owned subsidiary guarantors, jointly, severally, fully, and unconditionally, guarantee the payment obligations under the senior notes.

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 became a guarantor to the senior notes.

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, 2016 and December 31, 2015 .

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	$	139		$	108		$	—		$	1,776
Restricted cash	—		—			62			—			62
Accounts receivable, net	141		2,539			136			(2,430		)	386
Inventory	—		236			209			—			445
Other current assets	12		275			32			(1		)	318
Total Current Assets	1,682		3,189			547			(2,431		)	2,987
Property, plant and equipment, net	—		6,593			528			—			7,121
Investment in affiliates	12,125		—			—			(12,125		)	—
Restricted cash	—		—			2,000			—			2,000
Goodwill	—		799			—			—			799
Other long-term assets	2		89			55			—			146
Intercompany note receivable	—		—			8			(8		)	—
Total Assets	$	13,809	$	10,670		$	3,138		$	(14,564	)	$	13,053
Current Liabilities
Accounts payable	$	1,914	$	295		$	553		$	(2,430	)	$	332
Other current liabilities	128		348			109			(1		)	584
Total Current Liabilities	2,042		643			662			(2,431		)	916
Liabilities subject to compromise	—		—			832			—			832
Debt, long-term portion, net	6,551		216			2,011			—			8,778
Intercompany note payable	3,042		—			—			(3,042		)	—
Other long-term liabilities	132		235			129			(8		)	488
Total Liabilities	11,767		1,094			3,634			(5,481		)	11,014
Stockholders’ Equity
Dynegy Stockholders’ Equity	2,042		12,618			(493		)	(12,125		)	2,042
Intercompany note receivable	—		(3,042		)	—			3,042			—
Total Dynegy Stockholders’ Equity	2,042		9,576			(493		)	(9,083		)	2,042
Noncontrolling interest	—		—			(3		)	—			(3		)
Total Equity	2,042		9,576			(496		)	(9,083		)	2,039
Total Liabilities and Equity	$	13,809	$	10,670		$	3,138		$	(14,564	)	$	13,053

F-52

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Balance Sheet for the Year Ended December 31, 2015

(amounts in millions)



	Parent		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Current Assets
Cash and cash equivalents	$	327	$	94		$	84		$	—		$	505
Restricted cash	—		—			39			—			39
Accounts receivable, net	499		1,292			130			(1,519		)	402
Inventory	—		326			271			—			597
Other current assets	13		322			68			(14		)	389
Total Current Assets	839		2,034			592			(1,533		)	1,932
Property, plant and equipment, net	—		7,670			677			—			8,347
Investment in affiliates	13,017		190			—			(13,017		)	190
Other long-term assets	10		133			50			—			193
Goodwill	—		797			—			—			797
Intercompany note receivable	17		—			—			(17		)	—
Total Assets	$	13,883	$	10,824		$	1,319		$	(14,567	)	$	11,459
Current Liabilities
Accounts payable	$	1,388	$	234		$	189		$	(1,519	)	$	292
Other current liabilities	92		272			167			(14		)	517
Total Current Liabilities	1,480		506			356			(1,533		)	809
Debt, long-term portion, net	6,293		105			731			—			7,129
Intercompany note payable	3,042		—			17			(3,059		)	—
Other long-term liabilities	147		317			138			—			602
Total Liabilities	10,962		928			1,242			(4,592		)	8,540
Stockholders’ Equity
Dynegy Stockholders’ Equity	2,921		12,938			79			(13,017		)	2,921
Intercompany note receivable	—		(3,042		)	—			3,042			—
Total Dynegy Stockholders’ Equity	2,921		9,896			79			(9,975		)	2,921
Noncontrolling interest	—		—			(2		)	—			(2		)
Total Equity	2,921		9,896			77			(9,975		)	2,919
Total Liabilities and Equity	$	13,883	$	10,824		$	1,319		$	(14,567	)	$	11,459

F-53

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statements of Operations for the Year Ended December 31, 2016

(amounts in millions)



	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	3,317		$	1,093		$	(92	)	$	4,318
Cost of sales, excluding depreciation expense	—			(1,737		)	(636		)	92			(2,281		)
Gross margin	—			1,580			457			—			2,037
Operating and maintenance expense	—			(637		)	(303		)	—			(940		)
Depreciation expense	—			(590		)	(99		)	—			(689		)
Impairments	—			(710		)	(148		)	—			(858		)
Gain on sale of assets, net	(2		)	—			1			—			(1		)
General and administrative expense	(7		)	(117		)	(37		)	—			(161		)
Acquisition and integration costs	(10		)	(3		)	2			—			(11		)
Other	—			(1		)	(16		)	—			(17		)
Operating loss	(19		)	(478		)	(143		)	—			(640		)
Bankruptcy reorganization items	—			—			(96		)	—			(96		)
Earnings from unconsolidated investments	—			7			—			—			7
Equity in losses from investments in affiliates	(765		)	—			—			765			—
Interest expense	(485		)	(10		)	(132		)	2			(625		)
Other income and expense, net	29			20			18			(2		)	65
Loss before income taxes	(1,240		)	(461		)	(353		)	765			(1,289		)
Income tax benefit (expense) (Note 15)	—			86			(41		)	—			45
Net loss	(1,240		)	(375		)	(394		)	765			(1,244		)
Less: Net loss attributable to noncontrolling interest	—			—			(4		)	—			(4		)
Net loss attributable to Dynegy Inc.	$	(1,240	)	$	(375	)	$	(390	)	$	765		$	(1,240	)

Condensed Consolidating Statements of Operations for the Year Ended December 31, 2015

(amounts in millions)



	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	2,713		$	1,161		$	(4	)	$	3,870
Cost of sales, excluding depreciation expense	—			(1,322		)	(710		)	4			(2,028		)
Gross margin	—			1,391			451			—			1,842
Operating and maintenance expense	—			(549		)	(290		)	—			(839		)
Depreciation expense	—			(487		)	(100		)	—			(587		)
Impairments	—			(74		)	(25		)	—			(99		)
Loss on sale of assets, net	—			(1		)	—			—			(1		)
General and administrative expense	(6		)	(91		)	(31		)	—			(128		)
Acquisition and integration costs	—			(124		)	—			—			(124		)
Operating income (loss)	(6		)	65			5			—			64
Earnings from unconsolidated investments	—			1			—			—			1
Equity in earnings from investments in affiliates	476			—			—			(476		)	—
Interest expense	(475		)	(1		)	(70		)	—			(546		)
Other income and expense, net	55			(1		)	—			—			54
Income (loss) before income taxes	50			64			(65		)	(476		)	(427		)
Income tax benefit (Note 15)	—			471			3			—			474
Net income (loss)	50			535			(62		)	(476		)	47
Less: Net loss attributable to noncontrolling interest	—			—			(3		)	—			(3		)
Net income (loss) attributable to Dynegy Inc.	$	50		$	535		$	(59	)	$	(476	)	$	50

F-54

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statements of Operations for the Year Ended December 31, 2014

(amounts in millions)



	Parent			Escrow Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	—		$	1,184		$	1,313		$	—		$	2,497
Cost of sales, excluding depreciation expense	—			—			(702		)	(959		)	—			(1,661		)
Gross margin	—			—			482			354			—			836
Operating and maintenance expense	—			—			(258		)	(219		)	—			(477		)
Depreciation expense	—			—			(195		)	(52		)	—			(247		)
Gain on sale of assets, net	—			—			18			—			—			18
General and administrative expense	(9		)	—			(60		)	(45		)	—			(114		)
Acquisition and integration costs	—			—			(19		)	(16		)	—			(35		)
Operating income (loss)	(9		)	—			(32		)	22			—			(19		)
Bankruptcy reorganization items	3			—			—			—			—			3
Earnings from unconsolidated investments	—			—			10			—			—			10
Equity in losses from investments in affiliates	(131		)	—			—			—			131			—
Interest expense	(89		)	(67		)	—			(68		)	1			(223		)
Other income and expense, net	(39		)	—			1			—			(1		)	(39		)
Loss before income taxes	(265		)	(67		)	(21		)	(46		)	131			(268		)
Income tax benefit (expense) (Note 15)	(8		)	—			—			9			—			1
Net loss	(273		)	(67		)	(21		)	(37		)	131			(267		)
Less: Net income attributable to noncontrolling interest	—			—			—			6			—			6
Net loss attributable to Dynegy Inc.	$	(273	)	$	(67	)	$	(21	)	$	(43	)	$	131		$	(273	)

Condensed Consolidating Statements of Comprehensive Income (Loss) for the Year Ended December 31, 2016

(amounts in millions)



	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net loss	$	(1,240	)	$	(375	)	$	(394	)	$	765		$	(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		)	(374		)	(383		)	753			(1,240		)
Less: Comprehensive income (loss) attributable to noncontrolling interest	2			—			(2		)	(2		)	(2		)
Total comprehensive loss attributable to Dynegy Inc.	$	(1,238	)	$	(374	)	$	(381	)	$	755		$	(1,238	)

F-55

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statements of Comprehensive Loss for the Year Ended December 31, 2015

(amounts in millions)



	Parent			Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net income (loss)	$	50		$	535	$	(62	)	$	(476	)	$	47
Other comprehensive income (loss) before reclassifications:
Actuarial gain (loss) and plan amendments, net of tax of zero	(8		)	2		10			—			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	—			2		9			(11		)	—
Comprehensive income (loss)	50			537		(53		)	(487		)	47
Less: Comprehensive income (loss) attributable to noncontrolling interest	1			—		(2		)	(1		)	(2		)
Total comprehensive income (loss) attributable to Dynegy Inc.	$	49		$	537	$	(51	)	$	(486	)	$	49

Condensed Consolidating Statements of Comprehensive Loss for the Year Ended December 31, 2014

(amounts in millions)



	Parent			Escrow Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net income (loss)	$	(273	)	(67		)	$	(21	)	$	(37	)	$	131		$	(267	)
Other comprehensive income before reclassifications:
Actuarial loss and plan amendments, net of tax of zero	(20		)	—			—			(16		)	—			(36		)
Amounts reclassified from accumulated other comprehensive income (loss):
Amortization of unrecognized prior service credit and actuarial gain, net of tax of zero	(5		)	—			—			—			—			(5		)
Other comprehensive loss from investment in affiliates	(16		)	—			—			—			16			—
Other comprehensive loss, net of tax	(41		)	—			—			(16		)	16			(41		)
Comprehensive income (loss)	(314		)	(67		)	(21		)	(53		)	147			(308		)
Less: comprehensive income attributable to noncontrolling interest	3			—			—			3			(3		)	3
Total comprehensive income (loss) attributable to Dynegy Inc.	$	(317	)	$	(67	)	$	(21	)	$	(56	)	$	150		$	(311	)

F-56

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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	$	(425	)	$	1,081		$	20		$	—		$	676
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	—			(239		)	(87		)	—			(326		)
Increase in restricted cash	—			—			(2,021		)	—			(2,021		)
Distributions from unconsolidated affiliate	—			14			—			—			14
Proceeds from sales of assets, net	171			2			3			—			176
Net intercompany transfers	880			—			—			(880		)	—
Other investing	—			10			—			—			10
Net cash provided by (used in) investing activities	1,051			(213		)	(2,105		)	(880		)	(2,147		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of debt issuance costs	822			198			1,994			—			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	—			(1,006		)	126			880			—
Other financing	(3		)	—			—			—			(3		)
Net cash provided by (used in) financing activities	576			(823		)	2,109			880			2,742
Net increase in cash and cash equivalents	1,202			45			24			—			1,271
Cash and cash equivalents, beginning of period	327			94			84			—			505
Cash and cash equivalents, end of period	$	1,529		$	139		$	108		$	—		$	1,776

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	$	(367	)	$	507		$	(46	)	$	—		$	94
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	—			(211		)	(64		)	—			(275		)
Decrease in restricted cash	5,148			—			—			—			5,148
Acquisitions, net of cash acquired	(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	(609		)	(171		)	36			(450		)	(1,194		)
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	—			(351		)	(99		)	450			—
Other financing	(4		)	—			—			—			(4		)
Net cash provided by (used in) financing activities	(339		)	(296		)	(80		)	450			(265		)
Net increase (decrease) in cash and cash equivalents	(1,315		)	40			(90		)	—			(1,365		)
Cash and cash equivalents, beginning of period	1,642			54			174			—			1,870
Cash and cash equivalents, end of period	$	327		$	94		$	84		$	—		$	505

F-57

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statements of Cash Flow for the Year Ended December 31, 2014

(amounts in millions)



	Parent			Escrow Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$	(70	)	$	(62	)	$	200		$	95		$	—		$	163
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	—			—			(86		)	(46		)	—			(132		)
Increase in restricted cash	—			(5,148		)	—			—			—			(5,148		)
Proceeds from sales of assets, net	—			—			18			—			—			18
Net intercompany transfers	162			—			—			—			(162		)	—
Net cash provided by (used in) investing activities	162			(5,148		)	(68		)	(46		)	(162		)	(5,262		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of debt issuance costs	(1		)	5,044			12			—			—			5,055
Repayments of borrowings	(8		)	—			(6		)	—			—			(14		)
Proceeds from issuance of equity, net of issuance costs	1,106			—			—			—			—			1,106
Interest rate swap settlement payments	(18		)	—			—			—			—			(18		)
Net intercompany transfers	—			166			(238		)	(90		)	162			—
Other financing	(3		)	—			—			—			—			(3		)
Net cash provided by (used in) financing activities	1,076			5,210			(232		)	(90		)	162			6,126
Net increase in cash and cash equivalents	1,168			—			(100		)	(41		)	—			1,027
Cash and cash equivalents, beginning of period	474			—			154			215			—			843
Cash and cash equivalents, end of period	$	1,642		$	—		$	54		$	174		$	—		$	1,870

Note 22—Genco Chapter 11 Bankruptcy

On October 14, 2016, we entered into a restructuring support agreement (“RSA”) with Genco and an ad hoc group of Genco bondholders (the “Ad Hoc Group”) to restructure the Genco Senior Notes either through (a) out-of-court exchanges (the “Exchange Offer”) or (b) if the Exchange Offer was not successful, the Genco Plan. Under the RSA, the $825 million of existing Genco Senior Notes were to be exchanged for up to $210 million in new seven -year Dynegy unsecured notes, up to $139 million of cash consideration (including a $9 million RSA payment, as described below (the “RSA Payment”)) funded with existing IPH cash balances and an expected return of collateral of approximately $61 million , and up to 10 million of Dynegy warrants with a seven -year term for an exercise price of $35 per share. Dynegy, Genco, and the Ad Hoc Group agreed that holders of the Genco Senior Notes who entered into the RSA on or before October 21, 2016, would be paid their pro rata share of the RSA Payment in cash upon consummation of a restructuring, with such pro rata share determined as the proportion that the amount of Genco Senior Notes held by each such holder bears to the aggregate amount of Genco Senior Notes held by all holders entitled to receive a share of the RSA Payment. Genco made its interest payment that was due on December 1, 2016 and such payment was netted against the cash consideration.

The Exchange Offer was launched in November 2016 and on December 9, 2016, Dynegy and Genco announced (i) that they received the required number and amount of votes in favor of the Genco Plan, (ii) that Genco subsequently filed the Bankruptcy Petition for reorganization under the Bankruptcy Code in the Bankruptcy Court, and (iii) that the previously announced Exchange Offer was terminated because the required participation threshold of 97 percent of the aggregate principal amount of Genco Senior Notes was not satisfied. Genco continued to operate its business as “debtor-in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court until the Emergence Date. On the Emergence Date, we exchanged $757 million of these Genco Senior notes for $113 million of cash, $182 million of new Dynegy seven year unsecured notes, and warrants to purchase up to 8.7 million of common stock for an exercise price of $35 per share (the “2017 Warrants”). The 2017 Warrants have a seven -year term expiring on February 2, 2024. Holders of Genco Senior Notes who did not receive a distribution under the Genco Plan on the Emergence Date have until July 17, 2017 (the 165th day after the Emergence Date) in order to exercise their rights to receive a distribution.

The filing of the prepackaged Chapter 11 Case constituted or may have constituted an event of default or otherwise triggered or may have triggered repayment obligations under the express terms of certain instruments and agreements relating to direct financial obligations of Genco or obligations under off-balance sheet arrangements (the “Debt Documents”). As a result of such an event of default or triggering event, all obligations under the Debt Documents, by terms of the Debt Documents, have or may have become due and payable, but were subject to the provisions of the Bankruptcy Code. Such event of default would

F-58

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

not be an event of default for Dynegy’s other indebtedness, as the Genco Senior Notes were nonrecourse to Dynegy. The material Debt Documents are the Genco Senior Notes.

As a result of filing 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 represent the allowed claims to be resolved in connection with our Chapter 11 proceedings. Differences between liabilities we have estimated and the claims filed, or to be filed, will be investigated and resolved in connection with the claims resolution process. We will continue to evaluate these liabilities throughout the Chapter 11 process and adjust amounts as necessary. 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

We have incurred costs associated with the reorganization prior to and after Genco’s filing of the Bankruptcy Petition. 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. We stopped accruing interest on the Genco Senior Notes on December 9, 2016. Approximately $4 million of interest expense would have been recognized in our consolidated statement of operations for the year ended December 31, 2016 had we not stopped accruing interest on these notes.

Condensed Financial Statements of Debtor-in-Possession

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.

The condensed financial statements of Genco, as the debtor-in-possession, as of December 31, 2016 and for the period from December 10, 2016 to December 31, 2016, presented below reflect the amounts included in Dynegy’s consolidated financial statements as of and for the year ended December 31, 2016.

F-59

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Balance Sheet As of December 31, 2016



(amounts in millions)	Genco, as Debtor-in-Possession			Intercompany Eliminations			Amounts included in Dynegy’s Consolidated Financial Statements
Cash	$	49		$	—		$	49
Intercompany and affiliate receivables	184			(184		)	—
Other current assets	76			—			76
Property, plant & equipment	59			—			59
Other non-current assets	3			—			3
Total Assets	$	371		$	(184	)	$	187

Current liabilities	$	64		$	(31	)	$	33
Liabilities subject to compromise	832			—			832
Asset retirement obligations	37			—			37
Other non-current liabilities	5			(5		)	—
Total Liabilities	$	938		$	(36	)	$	902

Total stockholder deficit	$	(552	)	$	(148	)	(700		)
Noncontrolling Interest	(15		)	—			(15		)
Total Deficit	$	(567	)	$	(148	)	$	(715	)

Total Liabilities and Deficit	$	371		$	(184	)	$	187

Condensed Statement of Operations and Comprehensive Loss

For the Period from December 10, 2016 to December 31, 2016



(amounts in millions)	Genco, as Debtor-in-Possession			Intercompany Eliminations			Amounts included in Dynegy’s Consolidated Financial Statements
Revenues	$	19		$	(19	)	$	—
Cost of sales, excluding depreciation expense	(11		)	—			(11		)
Gross margin	8			(19		)	(11		)
Operating and maintenance expense	(6		)	—			(6		)
Other operating costs	(4		)	1			(3		)
Operating loss	(2		)	(18		)	(20		)
Bankruptcy reorganization items	(96		)	—			(96		)
Net loss attributable to Stockholder	(98		)	(18		)	(116		)
Other Comprehensive loss, net of tax	—			—			—
Comprehensive loss	$	(98	)	$	(18	)	$	(116	)

Condensed Statement of Cash Flows

For the Period from December 10, 2016 to December 31, 2016



(amounts in millions)	Genco, as Debtor-in-Possession		Intercompany Eliminations		Amounts included in Dynegy’s Consolidated Financial Statements
Net cash provided by operating activities	$	3	$	—	$	3
Net increase in cash and cash equivalents	3		—		3
Cash and cash equivalents, beginning of period	46		—		46
Cash and cash equivalents, end of period	$	49	$	—	$	49

F-60

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 23—Segment Information

In the fourth quarter of 2016, Dynegy changed its organizational structure to manage its assets, make financial decisions, and allocate resources based upon the market areas in which our plants operate. As of December 31, 2016, we modified our reportable segments from a fuel-based segment structure to the following market areas: (i) PJM, (ii) NY/NE, (iii) MISO, (iv) IPH and (v) CAISO. The Company has recast data from prior periods to reflect this change in reportable segments to conform to the current year presentation. PJM also includes our Dynegy Energy Services retail business in Ohio and Pennsylvania. The IPH segment includes Genco, and Illinois Power Resources Generating, LLC (“IPRG”), which also own, directly and indirectly, certain of our coal-fired power generation facilities, which are all in MISO. IPH also includes our Homefield Energy retail business in Illinois. Our consolidated financial results also reflect corporate-level expenses such as General and administrative expense, Interest expense and Income tax benefit (expense).

Reportable segment information, including intercompany transactions accounted for at prevailing market rates, for the years ended December 31, 2016, 2015 and 2014 is presented below:

Segment Data as of and for the Year Ended December 31, 2016

(amounts in millions)



	PJM			NY/NE			MISO			IPH			CAISO			Other and Eliminations			Total
Domestic:
Unaffiliated revenues	$	2,147		$	836		$	410		$	755		$	142		$	—		$	4,290
Intercompany and affiliate revenues	55			1			(27		)	(1		)	—			—			28
Total revenues	$	2,202		$	837		$	383		$	754		$	142		$	—		$	4,318

Depreciation expense	$	(346	)	$	(215	)	$	(49	)	$	(32	)	$	(42	)	$	(5	)	$	(689	)
Impairments	(65		)	—			(645		)	(148		)	—			—			(858		)
Gain 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	)	$	(745	)	$	(87	)	$	(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 expense	—			—			—			—			—			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		$	352		$	713		$	485		$	3,795		$	13,053
Capital expenditures	$	(180	)	$	(79	)	$	(12	)	$	(40	)	$	(5	)	$	(10	)	$	(326	)

F-61

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			IPH			CAISO			Other and Eliminations			Total
Domestic:
Unaffiliated revenues	$	1,708		$	705		$	475		$	804		$	178		$	—		$	3,870
Intercompany revenues	8			(10		)	7			(5		)	—			—			—
Total revenues	$	1,716		$	695		$	482		$	799		$	178		$	—		$	3,870

Depreciation expense	$	(281	)	$	(186	)	$	(39	)	$	(29	)	$	(48	)	$	(4	)	$	(587	)
Impairments	—			(25		)	(74		)	—			—			—			(99		)
Gain on sale of assets, net	—			—			—			—			(1		)	—			(1		)
General and administrative expense	—			—			—			—			—			(128		)	(128		)
Acquisition and integration costs	—			—			—			—			—			(124		)	(124		)

Operating income (loss)	$	423		$	(56	)	$	(92	)	$	49		$	(8	)	$	(252	)	$	64

Earnings from unconsolidated investments	1			—			—			—			—			—			1
Interest expense	—			—			—			—			—			(546		)	(546		)
Other income and expense, net	(2		)	—			1			—			—			55			54
Loss 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		$	1,098		$	897		$	534		$	486		$	11,459
Investment in unconsolidated affiliate	$	190		$	—		$	—		$	—		$	—		$	—		$	190
Capital expenditures	$	(93	)	$	(41	)	$	(56	)	$	(63	)	$	(9	)	$	(13	)	$	(275	)

F-62

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Segment Data as of and for the Year Ended December 31, 2014

(amounts in millions)



	PJM			NY/NE			MISO			IPH			CAISO			Other and Eliminations			Total
Domestic:
Unaffiliated revenues	$	340		$	466		$	584		$	850		$	257		$	—		$	2,497
Intercompany revenues	(9		)	(9		)	21			(4		)	1			—			—
Total revenues	$	331		$	457		$	605		$	846		$	258		$	—		$	2,497

Depreciation expense	$	(84	)	$	(26	)	$	(51	)	$	(37	)	$	(44	)	$	(5	)	$	(247	)
Gain on sale of assets, net	—			—			—			—			1			17			18
General and administrative expense	—			—			—			—			—			(114		)	(114		)
Acquisition and integration costs	—			—			—			(16		)	—			(19		)	(35		)

Operating income (loss)	$	(1	)	$	79		$	52		$	(2	)	$	(27	)	$	(120	)	$	(19	)

Bankruptcy reorganization items	—			—			—			—			—			3			3
Earnings from unconsolidated investments	—			—			—			—			—			10			10
Interest expense	—			—			—			—			—			(223		)	(223		)
Other income and expense, net	—			—			—			—			—			(39		)	(39		)
Loss from continuing operations before income taxes																			(268		)
Income tax benefit	—			—			—			—			—			1			1
Net loss																			(267		)
Less: Net income attributable to noncontrolling interest																			6
Net loss attributable to Dynegy Inc.																			$	(273	)

Total assets—domestic	$	1,055		$	363		$	1,166		$	1,039		$	584		$	6,947		$	11,154
Capital expenditures	$	(24	)	$	(2	)	$	(39	)	$	(45	)	$	(18	)	$	(4	)	$	(132	)

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, 2016, 2015 and 2014 are presented below:



(amounts in millions)	Revenues
Customers	2016		2015		2014		Segment(s)
PJM	$	1,366	$	1,088	N/A		PJM, IPH
MISO	$	688	$	842	$	836	MISO, IPH
ISO-NE	$	437	N/A		N/A		NY/NE
NYISO	N/A		N/A		$	342	NY/NE

Employee Concentrations

As of December 31, 2016, approximately 49% of our employees are covered by a collective bargaining agreement.

Note 24—Subsequent Events

Delta Transaction. On February 7, 2017 (the “Delta Transaction Closing Date”), pursuant to the terms of the 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 “Delta Transaction”). On February 2, 2017, FERC issued an order accepting the December 27, 2016 Compliance

F-63

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Filing of Atlas Power Finance, LLC, Dynegy, and ECP (collectively, “Applicants”), which proposed mitigation measures in response to market power concerns identified by FERC in its December 22, 2016 order conditionally authorizing the Delta Transaction. In this order, FERC accepted, among other commitments, Applicants’ proposal to divest at least 224 MW in the SENE capacity zone in ISO-NE. Additionally, Dynegy paid Energy Capital Partners (“ECP”) $375 million (the “ECP Buyout Price”).

We incurred acquisition costs of $5 million for the year ended December 31, 2016, related to the Delta Transaction, which are included in Acquisition and integration costs in our consolidated statement of operations.

We are currently in the process of valuing the assets acquired and liabilities assumed in the Delta Transaction. We are currently unable to provide pro forma financial results or the amounts recognized for the major classes of assets acquired and liabilities assumed in the Delta Transaction as of the Delta Transaction Closing Date. We will provide these disclosures in our quarterly report on Form 10-Q for the first quarter of 2017.

Stock Purchase Agreement-Terawatt. On February 24, 2016, Dynegy entered into a Stock Purchase Agreement with Terawatt Holdings, LP (“Terawatt”), an affiliate of the ECP Funds (the “PIPE Stock Purchase Agreement”), pursuant to which at the Delta Transaction Closing Date, Dynegy issued to Terawatt 13,711,152 shares (the “PIPE Shares”) of Dynegy common stock for $150 million (the “PIPE Transaction”). In connection with the closing of the PIPE Transaction, Dynegy and Terawatt entered into an Investor Rights Agreement, (the “Investor Rights Agreement”). Under the Investor Rights Agreement, Terawatt is entitled to certain rights, including certain registration rights, rights of first refusal with respect to certain issuances of our equity and the designation of one individual to serve on our Board of Directors as long as Terawatt and its affiliates own at least 10 percent of our common stock. Further, the Investor Rights Agreement subjects Terawatt to certain obligations, including certain voting obligations and customary standstill and lock-up periods.

Credit Agreement Amendments

Third Amendment. On June 27, 2016, we entered into the Third Amendment to the Credit Agreement which provided, upon the Escrow Release Date relating to the Escrow Agreement described in Note 14—Debt , for (1) a $75 million increase to the Revolving Facility, which will mature on April 2, 2020 and (2) upon the merger of Finance IV with and into Dynegy, a $2.0 billion , seven -year senior secured Tranche C Term Loan with terms substantially the same as the Finance IV Credit Agreement.

Fourth Amendment. On January 10, 2017, we entered into the Fourth Amendment to the Credit Agreement which was effective upon the Delta Transaction Closing Date. The Fourth Amendment provided that, among other things, (1) the Initial Revolving Loan Maturity Date (as defined in the Existing Credit Agreement), with respect to certain of the Initial Revolving Loan Commitments (as defined in the Existing Credit Agreement), will be extended from April 23, 2018 to April 23, 2021 (the “Extended Maturity Date” and such extended Initial Revolving Loan Commitments, the “Extended Revolving Loan Commitments”), and (2) the tranche of Extended Revolving Loan Commitments will increase in an aggregate principal amount of $45 million .

Fifth Amendment . Upon the Delta Transaction Closing Date, we entered into the Fifth Amendment to the Credit Agreement which provided that, among other things, (1) the interest rate applicable to the Tranche C Term Loans was reduced by 75 basis points through the exchange of the Tranche C Term Loans for Tranche C-1 Term Loans otherwise having the same terms (except as otherwise provided in the Fifth Amendment) as the Tranche C Term Loans, and (2) the extension of the maturity to 2024 of the existing Tranche B-2 Term Loans through the exchange of the outstanding Initial Tranche B-2 Term Loans for Tranche C-1 Term Loans.

Letter of Credit Facilities

Following the Delta Transaction Closing Date, Dynegy entered into a Letter of Credit Reimbursement Agreement with an issuing bank, pursuant to which the issuing bank agreed to provide letters of credit in an amount not to exceed $50 million . The facility has a one -year tenor and may be extended at the Lender’s discretion for up to four additional one -year terms.

Asset Sales

On February 23, 2017, Dynegy reached an agreement with LS Power for the sale of two peaking facilities in PJM for $480 million in cash. The assets to be sold, which were recently acquired in the Delta Transaction, include the Armstrong and Troy facilities totaling 1,269 MW. The sale is expected to close in the second half of 2017 with the proceeds to be allocated to debt reduction.

F-64

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Acquisition and Sale of Interests in Jointly Owned Facilities

On February 23, 2017, Dynegy reached an agreement with American Electric Power (“AEP”) to realign and consolidate each company’s ownership interests in the Conesville and Zimmer Power Stations in Ohio. Under the agreement, Dynegy will sell its 40 percent ownership interest in Conesville to AEP, and will acquire AEP’s 25.4 percent ownership interest in Zimmer. As a result, Dynegy will own 71.9 percent of the Zimmer facility and will no longer have an ownership interest in the AEP operated Conesville facility. No cash will be exchanged in the transaction and no additional debt will be incurred by either party.

F-65

Exhibit 4.7

EXECUTION VERSION

SIXTH SUPPLEMENTAL INDENTURE

SUBSIDIARY GUARANTEES

SIXTH SUPPLEMENTAL INDENTURE (this “ Supplemental Indenture ”), dated as of February 2, 2017, among the Subsidiary Guarantors listed on Schedule I (the “ Guaranteeing Subsidiaries ”), each a wholly-owned domestic subsidiary of Dynegy Inc. (or its permitted successor), a Delaware corporation (the “ Company ”), the Company, the other Subsidiary Guarantors (as defined in the Indenture referred to herein) and Wilmington Trust, National Association, as trustee under the Indenture referred to herein (the “ Trustee ”).

W I T N E S S E T H

WHEREAS, the Company has heretofore executed and delivered to the Trustee an indenture (the “ Indenture ”), dated as of May 20, 2013, among the Company, the Subsidiary Guarantors named therein and the Trustee, providing for the original issuance of an aggregate principal amount of $500,000,000 of 5.875% Senior Notes due 2023 (the “ Notes ”), and, subject to the terms of the Indenture, future unlimited issuances of 5.875% Senior Notes due 2023 (the “ Additional Notes ” and, together with the Initial Notes, the “ Notes ”);

WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiaries shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiaries shall unconditionally guarantee all of the Company’s Obligations under the Notes and the Indenture (the “ Subsidiary Guarantees ”); and

WHEREAS, pursuant to Section 4.07 of the Indenture, the Trustee, the Company and the other Subsidiary Guarantors are authorized and required to execute and deliver this Supplemental Indenture without the consent of any Holders of Notes.

NOW THEREFORE, in consideration of the foregoing and for good and valuable consideration, the receipt of which is hereby acknowledged, the Guaranteeing Subsidiaries, the Trustee, the Company and the other Subsidiary Guarantors mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

1. Capitalized Terms . Unless otherwise defined in this Supplemental Indenture, capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

2. Agreement to be Bound; Guarantees . Each of the Guaranteeing Subsidiaries hereby becomes a party to the Indenture as a Subsidiary Guarantor and as such will have all of the rights and be subject to all of the Obligations and agreements of a Subsidiary Guarantor under the Indenture. Each of the Guaranteeing Subsidiaries hereby agrees to be bound by all of the provisions of the Indenture applicable to a Subsidiary Guarantor and to perform all of the Obligations and agreements of a Subsidiary Guarantor under the Supplemental Indenture. In furtherance of the foregoing, each of the Guaranteeing Subsidiaries shall be deemed a Subsidiary Guarantor for purposes of Article 10 of the Indenture, including, without limitation, Section 10.02 thereof.

3. NEW YORK LAW TO GOVERN . THE INDENTURE, THE NOTES AND THE SUBSIDIARY GUARANTEES SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK.

4. Counterparts . The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.



Americas 92202010 v5

Exhibit 4.7

5 . Effect of Headings . The Section headings herein are for convenience only and shall not affect the construction hereof.

6. The Trustee . The Trustee shall not be responsible or liable in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiaries and the Company.

7. Ratification of Indenture; Supplemental Indenture Part of Indenture . Except as expressly amended hereby, the Indenture is in all respects ratified and confirmed and all the terms, conditions and provisions thereof shall remain in full force and effect. This Supplemental Indenture shall form a part of the Indenture for all purposes, and every Holder of Notes heretofore or hereafter authenticated and delivered shall be bound hereby.

[ Signature Page Follows ]



Americas 92202010 v5

Exhibit 4.7

IN WITNESS WHEREOF, we have hereunto signed our names as of the date set forth below.

Dated: February 2, 2017

DYNEGY INC.

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer



	BLACK MOUNTAIN COGEN, INC. BLUE RIDGE GENERATION LLC CASCO BAY ENERGY COMPANY, LLC DIGHTON POWER, LLC DYNEGY ADMINISTRATIVE SERVICES COMPANY DYNEGY COAL GENERATION, LLC DYNEGY COAL HOLDCO, LLC DYNEGY COAL INVESTMENTS HOLDINGS, LLC DYNEGY COAL TRADING & TRANSPORTATION, L.L.C. DYNEGY COMMERCIAL ASSET MANAGEMENT, LLC DYNEGY CONESVILLE, LLC DYNEGY DICKS CREEK, LLC DYNEGY ENERGY SERVICES (EAST), LLC DYNEGY ENERGY SERVICES, LLC DYNEGY EQUIPMENT, LLC DYNEGY FAYETTE II, LLC DYNEGY GAS GENERATION, LLC DYNEGY GAS HOLDCO, LLC DYNEGY GAS IMPORTS, LLC DYNEGY GAS INVESTMENTS HOLDINGS, LLC DYNEGY GAS INVESTMENTS, LLC DYNEGY GASCO HOLDINGS, LLC DYNEGY GENERATION HOLDCO, LLC DYNEGY GLOBAL LIQUIDS, INC. DYNEGY HANGING ROCK II, LLC DYNEGY KENDALL ENERGY, LLC DYNEGY KILLEN, LLC DYNEGY LEE II, LLC DYNEGY MARKETING AND TRADE, LLC DYNEGY MIAMI FORT, LLC DYNEGY MIDWEST GENERATION, LLC DYNEGY MORRO BAY, LLC DYNEGY MOSS LANDING, LLC DYNEGY OAKLAND, LLC DYNEGY OPERATING COMPANY DYNEGY POWER GENERATION INC. DYNEGY POWER MARKETING, LLC DYNEGY POWER, LLC

[Signature Page to the Sixth Supplemental Indenture (2023 Notes)]



Americas 92202010 v5

Exhibit 4.7



DYNEGY RESOURCE HOLDINGS, LLC DYNEGY RESOURCE I, LLC DYNEGY RESOURCE II, LLC DYNEGY RESOURCE III, LLC DYNEGY RESOURCES GENERATING HOLDCO, LLC DYNEGY RESOURCES HOLDCO I, LLC DYNEGY RESOURCES HOLDCO II, LLC DYNEGY RESOURCES MANAGEMENT, LLC DYNEGY SOUTH BAY, LLC DYNEGY STUART, LLC DYNEGY WASHINGTON II, LLC DYNEGY ZIMMER, LLC ELWOOD ENERGY HOLDINGS II, LLC ELWOOD ENERGY HOLDINGS, LLC ELWOOD EXPANSION HOLDINGS, LLC EQUIPOWER RESOURCES CORP. HAVANA DOCK ENTERPRISES, LLC ILLINOVA CORPORATION KINCAID ENERGY SERVICES COMPANY, LLC KINCAID GENERATION, L.L.C. KINCAID HOLDINGS, LLC LAKE ROAD GENERATING COMPANY, LLC LIBERTY ELECTRIC POWER, LLC MASSPOWER HOLDCO, LLC MASSPOWER PARTNERS I, LLC MASSPOWER PARTNERS II, LLC MILFORD POWER COMPANY, LLC ONTELAUNEE POWER OPERATING COMPANY, LLC RICHLAND GENERATION EXPANSION, LLC RICHLAND-STRYKER GENERATION LLC RSG POWER, LLC SITHE ENERGIES, INC. SITHE/INDEPENDENCE LLC TOMCAT POWER, LLC

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the Sixth Supplemental Indenture (2023 Notes)]



Americas 92202010 v5

Exhibit 4.7

MASSPOWER , a Massachusetts general partnership

By: Masspower Partner II, LLC, its Managing Partner

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the Sixth Supplemental Indenture (2023 Notes)]



Americas 92202010 v5

Exhibit 4.7

MASSPOWER , a Massachusetts general partnership

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the Sixth Supplemental Indenture (2023 Notes)]



Americas 92202010 v5

Exhibit 4.7

SUBSIDIARY GUARANTORS:

COFFEEN AND WESTERN RAILROAD COMPANY

ILLINOIS POWER FUELS AND SERVICES COMPANY

ILLINOIS POWER GENERATING COMPANY

ILLINOIS POWER MARKETING COMPANY

ILLINOIS POWER RESOURCES GENERATING, LLC

ILLINOIS POWER RESOURCES, LLC

IPH II, LLC

IPH, LLC

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the Sixth Supplemental Indenture (2023 Notes)]



Americas 92202010 v5

Exhibit 4.7

WILMINGTON TRUST, NATIONAL ASSOCIATION,

as Trustee

By: /s/ Shawn Goffinet

Name: Shawn Goffinet
Title: Assistant Vice President

[Signature Page to the Sixth Supplemental Indenture (2023 Notes)]



Americas 92202010 v5

Exhibit 4.7

SCHEDULE I

SUBSIDIARY GUARANTEES

COFFEEN AND WESTERN RAILROAD COMPANY

ILLINOIS POWER FUELS AND SERVICES COMPANY

ILLINOIS POWER GENERATING COMPANY

ILLINOIS POWER MARKETING COMPANY

ILLINOIS POWER RESOURCES GENERATING, LLC

ILLINOIS POWER RESOURCES, LLC

IPH II, LLC

IPH, LLC



Americas 92202010 v5

Exhibit 4.8

EXECUTION VERSION

SEVENTH SUPPLEMENTAL INDENTURE

SUBSIDIARY GUARANTEES

SEVENTH SUPPLEMENTAL INDENTURE (this “ Supplemental Indenture ”), dated as of February 7, 2017, among the Subsidiary Guarantors listed on Schedule I (the “ Guaranteeing Subsidiaries ”), each a wholly-owned domestic subsidiary of Dynegy Inc. (or its permitted successor), a Delaware corporation (the “ Company ”), the Company, the other Subsidiary Guarantors (as defined in the Indenture referred to herein) and Wilmington Trust, National Association, as trustee under the Indenture referred to herein (the “ Trustee ”).

W I T N E S S E T H

WHEREAS, the Company has heretofore executed and delivered to the Trustee an indenture (the “ Indenture ”), dated as of May 20, 2013, among the Company, the Subsidiary Guarantors named therein and the Trustee, providing for the original issuance of an aggregate principal amount of $500,000,000 of 5.875% Senior Notes due 2023 (the “ Initial Notes ”), and, subject to the terms of the Indenture, future unlimited issuances of 5.875% Senior Notes due 2023 (the “ Additional Notes ” and, together with the Initial Notes, the “ Notes ”);

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee, the Company and the other Subsidiary Guarantors are authorized and required to execute and deliver this Supplemental Indenture without the consent of any Holders of Notes.

1. Capitalized Terms . Unless otherwise defined in this Supplemental Indenture, capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

3. NEW YORK LAW TO GOVERN . THE INDENTURE, THE NOTES AND THE SUBSIDIARY GUARANTEES SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK.

4. Counterparts . The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

5 . Effect of Headings . The Section headings herein are for convenience only and shall not affect the construction hereof.

[ Signature Page Follows ]



Americas 92260896 v6

Exhibit 4.8



Americas 92260896 v6

Exhibit 4.8

IN WITNESS WHEREOF, we have hereunto signed our names as of the date set forth below.

Dated: February 7, 2017

DYNEGY INC.

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer



	BLACK MOUNTAIN COGEN, INC. BLUE RIDGE GENERATION LLC CASCO BAY ENERGY COMPANY, LLC DIGHTON POWER, LLC DYNEGY ADMINISTRATIVE SERVICES COMPANY DYNEGY COAL GENERATION, LLC DYNEGY COAL HOLDCO, LLC DYNEGY COAL INVESTMENTS HOLDINGS, LLC DYNEGY COAL TRADING & TRANSPORTATION, L.L.C. DYNEGY COMMERCIAL ASSET MANAGEMENT, LLC DYNEGY CONESVILLE, LLC DYNEGY DICKS CREEK, LLC DYNEGY ENERGY SERVICES (EAST), LLC DYNEGY ENERGY SERVICES, LLC DYNEGY EQUIPMENT, LLC DYNEGY FAYETTE II, LLC DYNEGY GAS GENERATION, LLC DYNEGY GAS HOLDCO, LLC DYNEGY GAS IMPORTS, LLC DYNEGY GAS INVESTMENTS HOLDINGS, LLC DYNEGY GAS INVESTMENTS, LLC DYNEGY GASCO HOLDINGS, LLC DYNEGY GENERATION HOLDCO, LLC DYNEGY GLOBAL LIQUIDS, INC. DYNEGY HANGING ROCK II, LLC DYNEGY KENDALL ENERGY, LLC DYNEGY KILLEN, LLC DYNEGY LEE II, LLC DYNEGY MARKETING AND TRADE, LLC DYNEGY MIAMI FORT, LLC DYNEGY MIDWEST GENERATION, LLC DYNEGY MORRO BAY, LLC DYNEGY MOSS LANDING, LLC DYNEGY OAKLAND, LLC DYNEGY OPERATING COMPANY DYNEGY POWER GENERATION INC. DYNEGY POWER MARKETING, LLC DYNEGY POWER, LLC

[Signature Page to the Seventh Supplemental Indenture (2023 Notes)]



Americas 92260896 v6

Exhibit 4.8



DYNEGY RESOURCE HOLDINGS, LLC DYNEGY RESOURCE I, LLC DYNEGY RESOURCE II, LLC DYNEGY RESOURCE III, LLC DYNEGY RESOURCES GENERATING HOLDCO, LLC DYNEGY RESOURCES HOLDCO I, LLC DYNEGY RESOURCES HOLDCO II, LLC DYNEGY RESOURCES MANAGEMENT, LLC DYNEGY SOUTH BAY, LLC DYNEGY STUART, LLC DYNEGY WASHINGTON II, LLC DYNEGY ZIMMER, LLC ELWOOD ENERGY HOLDINGS II, LLC ELWOOD ENERGY HOLDINGS, LLC ELWOOD EXPANSION HOLDINGS, LLC EQUIPOWER RESOURCES CORP. HAVANA DOCK ENTERPRISES, LLC ILLINOVA CORPORATION KINCAID ENERGY SERVICES COMPANY, LLC KINCAID GENERATION, L.L.C. KINCAID HOLDINGS, LLC LAKE ROAD GENERATING COMPANY, LLC LIBERTY ELECTRIC POWER, LLC MASSPOWER HOLDCO, LLC MASSPOWER PARTNERS I, LLC MASSPOWER PARTNERS II, LLC MILFORD POWER COMPANY, LLC ONTELAUNEE POWER OPERATING COMPANY, LLC RICHLAND GENERATION EXPANSION, LLC RICHLAND-STRYKER GENERATION LLC RSG POWER, LLC SITHE ENERGIES, INC. SITHE/INDEPENDENCE LLC TOMCAT POWER, LLC

COFFEEN AND WESTERN RAILROAD COMPANY

ILLINOIS POWER FUELS AND SERVICES COMPANY

ILLINOIS POWER GENERATING COMPANY

ILLINOIS POWER MARKETING COMPANY

ILLINOIS POWER RESOURCES GENERATING, LLC

ILLINOIS POWER RESOURCES, LLC

IPH II, LLC

IPH, LLC

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the Seventh Supplemental Indenture (2023 Notes)]



Americas 92260896 v6

Exhibit 4.8

MASSPOWER , a Massachusetts general partnership

By: Masspower Partner II, LLC, its Managing Partner

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

MASSPOWER , a Massachusetts general partnership

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the Seventh Supplemental Indenture (2023 Notes)]



Americas 92260896 v6

Exhibit 4.8

SUBSIDIARY GUARANTORS:

ANP BELLINGHAM ENERGY COMPANY, LLC

ANP BLACKSTONE ENERGY COMPANY, LLC

ANP ERCOT ACQUISITION, LLC

ANP FUEL SERVICES, INC.

ANP FUNDING I, LLC

ARMSTRONG POWER, LLC

ATLAS ADMINISTRATIVE SERVICES, LLC

ATLAS FINANCE MERGECO, LLC

ATLAS I MARKETING AND TRADE, LLC

ATLAS POWER FINANCE, LLC

ATLAS POWER, LLC

CALUMET ENERGY TEAM, LLC

COLETO CREEK POWER LP

COLETO GP, LLC

COLETO LP, LLC

DYNEGY ATLAS HOLDINGS, LLC

ENNIS POWER COMPANY, LLC

DYNEGY GENERATION NA, INC. (F/K/A GDF SUEZ ENERGY GENERATION NA, INC.)

DYNEGY ENERGY GENERATION NA, LLC (F/K/A GDF SUEZ ENERGY GENERATION NA, LLC)

DYNEGY NORTH AMERICA, INC. (F/K/A GDF SUEZ ENERGY NORTH AMERICA, INC.)

HAYS ENERGY, LLC

HOPEWELL COGENERATION LIMITED PARTNERSHIP

HOPEWELL COGENERATION, LLC

DYNEGY POWER AMERICA, INC. (F/K/A INTERNATIONAL POWER AMERICA, INC.)

DP GENERATION, LLC (F/K/A IPA APT GENERATION, LLC)

DP CENTRAL, LLC (F/K/A IPA CENTRAL, LLC)

DP HOLDING, INC. (F/K/A IPA HOLDING, INC.)

DP OPERATIONS, INC. (F/K/A IPA OPERATIONS, INC.)

MIDLOTHIAN ENERGY, LLC

MILFORD POWER, LLC

NEPCO SERVICES COMPANY

NORTHEASTERN POWER COMPANY

PLEASANTS ENERGY, LLC

PRINCE GEORGE ENERGY COMPANY, LLC

T-FUELS, LLC

TNA MERCHANT PROJECTS, INC.

DYNEGY ASSOCIATES NORTHEAST LP, INC. (F/K/A TRACTEBEL ASSOCIATES NORTHEAST LP, INC.)

DYNEGY NORTHEAST GENERATION GP, INC. (F/K/A TRACTEBEL NORTHEAST GENERATION GP, INC.)

TROY ENERGY, LLC

WHARTON COUNTY GENERATION, LLC

WISE COUNTY POWER COMPANY, LLC

WISE-FUELS PIPELINE, INC.

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the Seventh Supplemental Indenture (2023 Notes)]



Americas 92260896 v6

Exhibit 4.8

WILMINGTON TRUST, NATIONAL ASSOCIATION,

as Trustee

By: /s/ Shawn Goffinet

Name: Shawn Goffinet
Title: Assistant Vice President

[Signature Page to the Seventh Supplemental Indenture (2023 Notes)]



Americas 92260896 v6

Exhibit 4.8

SCHEDULE I

SUBSIDIARY GUARANTEES

ANP BELLINGHAM ENERGY COMPANY, LLC

ANP BLACKSTONE ENERGY COMPANY, LLC

ANP ERCOT ACQUISITION, LLC

ANP FUEL SERVICES, INC.

ANP FUNDING I, LLC

ARMSTRONG POWER, LLC

ATLAS ADMINISTRATIVE SERVICES, LLC

ATLAS FINANCE MERGECO, LLC

ATLAS I MARKETING AND TRADE, LLC

ATLAS POWER FINANCE, LLC

ATLAS POWER, LLC

CALUMET ENERGY TEAM, LLC

COLETO CREEK POWER LP

COLETO GP, LLC

COLETO LP, LLC

DYNEGY ATLAS HOLDINGS, LLC

ENNIS POWER COMPANY, LLC

DYNEGY GENERATION NA, INC. (F/K/A GDF SUEZ ENERGY GENERATION NA, INC.)

DYNEGY ENERGY GENERATION NA, LLC (F/K/A GDF SUEZ ENERGY GENERATION NA, LLC)

DYNEGY NORTH AMERICA, INC. (F/K/A GDF SUEZ ENERGY NORTH AMERICA, INC.)

HAYS ENERGY, LLC

HOPEWELL COGENERATION LIMITED PARTNERSHIP

HOPEWELL COGENERATION, LLC

DYNEGY POWER AMERICA, INC. (F/K/A INTERNATIONAL POWER AMERICA, INC.)

DP GENERATION, LLC (F/K/A IPA APT GENERATION, LLC)

DP CENTRAL, LLC (F/K/A IPA CENTRAL, LLC)

DP HOLDING, INC. (F/K/A IPA HOLDING, INC.)

DP OPERATIONS, INC. (F/K/A IPA OPERATIONS, INC.)

MIDLOTHIAN ENERGY, LLC

MILFORD POWER, LLC

NEPCO SERVICES COMPANY

NORTHEASTERN POWER COMPANY

PLEASANTS ENERGY, LLC

PRINCE GEORGE ENERGY COMPANY, LLC

T-FUELS, LLC

TNA MERCHANT PROJECTS, INC.

DYNEGY ASSOCIATES NORTHEAST LP, INC. (F/K/A TRACTEBEL ASSOCIATES NORTHEAST LP, INC.)

DYNEGY NORTHEAST GENERATION GP, INC. (F/K/A TRACTEBEL NORTHEAST GENERATION GP, INC.)

TROY ENERGY, LLC

WHARTON COUNTY GENERATION, LLC

WISE COUNTY POWER COMPANY, LLC

WISE-FUELS PIPELINE, INC.



Americas 92260896 v6

Exhibit 4.16

EXECUTION VERSION

SIXTH SUPPLEMENTAL INDENTURE
SUBSIDIARY GUARANTEES

SIXTH SUPPLEMENTAL INDENTURE (this “ Supplemental Indenture ”), dated as of February 2, 2017, among the Subsidiary Guarantors listed on Schedule I hereto (the “ Guaranteeing Subsidiaries ”), each a wholly-owned domestic subsidiary of Dynegy Inc. (or its permitted successor), a Delaware corporation (the “ Company ”), the Company, the other Subsidiary Guarantors (as defined in the Indenture referred to herein) and Wilmington Trust, National Association, as trustee under the indentures referred to below (the “ Trustee ”).

W I T N E S S E T H

WHEREAS, the Company (as successor by merger to Dynegy Finance II, Inc.) has heretofore executed and delivered to the Trustee an indenture (as supplemented, the “ Indenture ”), dated as of October 27, 2014, between the Company and the Trustee, providing for the original issuance of an aggregate principal amount of $1,260,000,000 of 6.75% Senior Notes due 2019 (the “ Initial Notes ”) and, subject to the terms of the Indenture, future unlimited issuances of 6.75% Senior Notes due 2019 (the “ Additional Notes , and together with the Initial Notes, the “ Notes ”);

WHEREAS, pursuant to Section 4.07 of the Indenture, the Trustee, the Company and the other Subsidiary Guarantors are authorized and required to execute and deliver this Supplemental Indenture.

1. Capitalized Terms . Unless otherwise defined in this Supplemental Indenture, capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

2. Agreement to be Bound; Guarantee . Each of the Guaranteeing Subsidiaries hereby become a party to the Indenture as a Subsidiary Guarantor and as such will have all of the rights and be subject to all of the Obligations and agreements of a Subsidiary Guarantor under the Indenture. Each of the Guaranteeing Subsidiaries hereby agree to be bound by all of the provisions of the Indenture applicable to a Subsidiary Guarantor and to perform all of the Obligations and agreements of a Subsidiary Guarantor under the Indenture. In furtherance of the foregoing, each of the Guaranteeing Subsidiaries shall be deemed a Subsidiary Guarantor for purposes of Article 10 of the Indenture, including, without limitation, Section 10.02 thereof.

3. NEW YORK LAW TO GOVERN . THE INDENTURE, THE NOTES, THIS SUPPLEMENTAL INDENTURE AND THE SUBSIDIARY GUARANTEES SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK.

4. Counterparts . The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

5. Effect of Headings . The Section headings herein are for convenience only and shall not affect the construction hereof.

6. The Trustee . The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiaries and the Company.



Americas 92201989 v5

Exhibit 4.16

[ Signature Page Follows ]



Americas 92201989 v5

Exhibit 4.16

IN WITNESS WHEREOF, we have hereunto signed our names as of the date set forth below.

Dated: February 2, 2017

DYNEGY INC.

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer



	BLACK MOUNTAIN COGEN, INC. BLUE RIDGE GENERATION LLC CASCO BAY ENERGY COMPANY, LLC DIGHTON POWER, LLC DYNEGY ADMINISTRATIVE SERVICES COMPANY DYNEGY COAL GENERATION, LLC DYNEGY COAL HOLDCO, LLC DYNEGY COAL INVESTMENTS HOLDINGS, LLC DYNEGY COAL TRADING & TRANSPORTATION, L.L.C. DYNEGY COMMERCIAL ASSET MANAGEMENT, LLC DYNEGY CONESVILLE, LLC DYNEGY DICKS CREEK, LLC DYNEGY ENERGY SERVICES (EAST), LLC DYNEGY ENERGY SERVICES, LLC DYNEGY EQUIPMENT, LLC DYNEGY FAYETTE II, LLC DYNEGY GAS GENERATION, LLC DYNEGY GAS HOLDCO, LLC DYNEGY GAS IMPORTS, LLC DYNEGY GAS INVESTMENTS HOLDINGS, LLC DYNEGY GAS INVESTMENTS, LLC DYNEGY GASCO HOLDINGS, LLC DYNEGY GENERATION HOLDCO, LLC DYNEGY GLOBAL LIQUIDS, INC. DYNEGY HANGING ROCK II, LLC DYNEGY KENDALL ENERGY, LLC DYNEGY KILLEN, LLC DYNEGY LEE II, LLC DYNEGY MARKETING AND TRADE, LLC DYNEGY MIAMI FORT, LLC DYNEGY MIDWEST GENERATION, LLC DYNEGY MORRO BAY, LLC DYNEGY MOSS LANDING, LLC DYNEGY OAKLAND, LLC DYNEGY OPERATING COMPANY DYNEGY POWER GENERATION INC. DYNEGY POWER MARKETING, LLC DYNEGY POWER, LLC

[Signature Page to the Sixth Supplemental Indenture (2019 Notes)]



Americas 92201989 v5

Exhibit 4.16



DYNEGY RESOURCE HOLDINGS, LLC DYNEGY RESOURCE I, LLC DYNEGY RESOURCE II, LLC DYNEGY RESOURCE III, LLC DYNEGY RESOURCES GENERATING HOLDCO, LLC DYNEGY RESOURCES HOLDCO I, LLC DYNEGY RESOURCES HOLDCO II, LLC DYNEGY RESOURCES MANAGEMENT, LLC DYNEGY SOUTH BAY, LLC DYNEGY STUART, LLC DYNEGY WASHINGTON II, LLC DYNEGY ZIMMER, LLC ELWOOD ENERGY HOLDINGS II, LLC ELWOOD ENERGY HOLDINGS, LLC ELWOOD EXPANSION HOLDINGS, LLC EQUIPOWER RESOURCES CORP. HAVANA DOCK ENTERPRISES, LLC ILLINOVA CORPORATION KINCAID ENERGY SERVICES COMPANY, LLC KINCAID GENERATION, L.L.C. KINCAID HOLDINGS, LLC LAKE ROAD GENERATING COMPANY, LLC LIBERTY ELECTRIC POWER, LLC MASSPOWER HOLDCO, LLC MASSPOWER PARTNERS I, LLC MASSPOWER PARTNERS II, LLC MILFORD POWER COMPANY, LLC ONTELAUNEE POWER OPERATING COMPANY, LLC RICHLAND GENERATION EXPANSION, LLC RICHLAND-STRYKER GENERATION LLC RSG POWER, LLC SITHE ENERGIES, INC. SITHE/INDEPENDENCE LLC TOMCAT POWER, LLC

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the Sixth Supplemental Indenture (2019 Notes)]



Americas 92201989 v5

Exhibit 4.16

MASSPOWER , a Massachusetts general partnership

By: Masspower Partner II, LLC, its Managing Partner

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the Sixth Supplemental Indenture (2019 Notes)]



Americas 92201989 v5

Exhibit 4.16

MASSPOWER , a Massachusetts general partnership

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the Sixth Supplemental Indenture (2019 Notes)]



Americas 92201989 v5

Exhibit 4.16

SUBSIDIARY GUARANTORS:

COFFEEN AND WESTERN RAILROAD COMPANY

ILLINOIS POWER FUELS AND SERVICES COMPANY

ILLINOIS POWER GENERATING COMPANY

ILLINOIS POWER MARKETING COMPANY

ILLINOIS POWER RESOURCES GENERATING, LLC

ILLINOIS POWER RESOURCES, LLC

IPH II, LLC

IPH, LLC

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

WILMINGTON TRUST, NATIONAL ASSOCIATION,

as Trustee

By: /s/ Shawn Goffinet

Name: Shawn Goffinet
Title: Assistant Vice President

[Signature Page to the Sixth Supplemental Indenture (2019 Notes)]



Americas 92201989 v5

Exhibit 4.16

SCHEDULE I

SUBSIDIARY GUARANTEES

COFFEEN AND WESTERN RAILROAD COMPANY

ILLINOIS POWER FUELS AND SERVICES COMPANY

ILLINOIS POWER GENERATING COMPANY

ILLINOIS POWER MARKETING COMPANY

ILLINOIS POWER RESOURCES GENERATING, LLC

ILLINOIS POWER RESOURCES, LLC

IPH II, LLC

IPH, LLC



Americas 92201989 v5

Exhibit 4.17

EXECUTION VERSION

SEVENTH SUPPLEMENTAL INDENTURE
SUBSIDIARY GUARANTEES

SEVENTH SUPPLEMENTAL INDENTURE (this “ Supplemental Indenture ”), dated as of February 7, 2017, among the Subsidiary Guarantors listed on Schedule I hereto (the “ Guaranteeing Subsidiaries ”), each a wholly-owned domestic subsidiary of Dynegy Inc. (or its permitted successor), a Delaware corporation (the “ Company ”), the Company, the other Subsidiary Guarantors (as defined in the Indenture referred to herein) and Wilmington Trust, National Association, as trustee under the indenture referred to below (the “ Trustee ”).

W I T N E S S E T H

WHEREAS, the Company (as successor by merger to Dynegy Finance II, Inc.) has heretofore executed and delivered to the Trustee an indenture (as supplemented, the “ Indenture ”), dated as of October 27, 2014, between the Company and the Trustee, providing for the original issuance of an aggregate principal amount of $1,260,000,000 of 6.75% Senior Notes due 2019 (the “ Initial Notes ”) and, subject to the terms of the Indenture, future unlimited issuances of 6.75% Senior Notes due 2019 (the “ Additional Notes ” and, together with the Initial Notes, the “ Notes ”);

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee, the Company and the other Subsidiary Guarantors are authorized and required to execute and deliver this Supplemental Indenture.

1. Capitalized Terms . Unless otherwise defined in this Supplemental Indenture, capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

4. Counterparts . The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

5. Effect of Headings . The Section headings herein are for convenience only and shall not affect the construction hereof.



Americas 92260838 v6

Exhibit 4.17

[ Signature Page Follows ]



Americas 92260838 v6

Exhibit 4.17

IN WITNESS WHEREOF, we have hereunto signed our names as of the date set forth below.

Dated: February 7, 2017

DYNEGY INC.

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer



	BLACK MOUNTAIN COGEN, INC. BLUE RIDGE GENERATION LLC CASCO BAY ENERGY COMPANY, LLC DIGHTON POWER, LLC DYNEGY ADMINISTRATIVE SERVICES COMPANY DYNEGY COAL GENERATION, LLC DYNEGY COAL HOLDCO, LLC DYNEGY COAL INVESTMENTS HOLDINGS, LLC DYNEGY COAL TRADING & TRANSPORTATION, L.L.C. DYNEGY COMMERCIAL ASSET MANAGEMENT, LLC DYNEGY CONESVILLE, LLC DYNEGY DICKS CREEK, LLC DYNEGY ENERGY SERVICES (EAST), LLC DYNEGY ENERGY SERVICES, LLC DYNEGY EQUIPMENT, LLC DYNEGY FAYETTE II, LLC DYNEGY GAS GENERATION, LLC DYNEGY GAS HOLDCO, LLC DYNEGY GAS IMPORTS, LLC DYNEGY GAS INVESTMENTS HOLDINGS, LLC DYNEGY GAS INVESTMENTS, LLC DYNEGY GASCO HOLDINGS, LLC DYNEGY GENERATION HOLDCO, LLC DYNEGY GLOBAL LIQUIDS, INC. DYNEGY HANGING ROCK II, LLC DYNEGY KENDALL ENERGY, LLC DYNEGY KILLEN, LLC DYNEGY LEE II, LLC DYNEGY MARKETING AND TRADE, LLC DYNEGY MIAMI FORT, LLC DYNEGY MIDWEST GENERATION, LLC DYNEGY MORRO BAY, LLC DYNEGY MOSS LANDING, LLC DYNEGY OAKLAND, LLC DYNEGY OPERATING COMPANY DYNEGY POWER GENERATION INC. DYNEGY POWER MARKETING, LLC DYNEGY POWER, LLC

[Signature Page to the Seventh Supplemental Indenture (2019 Notes)]



Americas 92260838 v6

Exhibit 4.17



DYNEGY RESOURCE HOLDINGS, LLC DYNEGY RESOURCE I, LLC DYNEGY RESOURCE II, LLC DYNEGY RESOURCE III, LLC DYNEGY RESOURCES GENERATING HOLDCO, LLC DYNEGY RESOURCES HOLDCO I, LLC DYNEGY RESOURCES HOLDCO II, LLC DYNEGY RESOURCES MANAGEMENT, LLC DYNEGY SOUTH BAY, LLC DYNEGY STUART, LLC DYNEGY WASHINGTON II, LLC DYNEGY ZIMMER, LLC ELWOOD ENERGY HOLDINGS II, LLC ELWOOD ENERGY HOLDINGS, LLC ELWOOD EXPANSION HOLDINGS, LLC EQUIPOWER RESOURCES CORP. HAVANA DOCK ENTERPRISES, LLC ILLINOVA CORPORATION KINCAID ENERGY SERVICES COMPANY, LLC KINCAID GENERATION, L.L.C. KINCAID HOLDINGS, LLC LAKE ROAD GENERATING COMPANY, LLC LIBERTY ELECTRIC POWER, LLC MASSPOWER HOLDCO, LLC MASSPOWER PARTNERS I, LLC MASSPOWER PARTNERS II, LLC MILFORD POWER COMPANY, LLC ONTELAUNEE POWER OPERATING COMPANY, LLC RICHLAND GENERATION EXPANSION, LLC RICHLAND-STRYKER GENERATION LLC RSG POWER, LLC SITHE ENERGIES, INC. SITHE/INDEPENDENCE LLC TOMCAT POWER, LLC

COFFEEN AND WESTERN RAILROAD COMPANY

ILLINOIS POWER FUELS AND SERVICES COMPANY

ILLINOIS POWER GENERATING COMPANY

ILLINOIS POWER MARKETING COMPANY

ILLINOIS POWER RESOURCES GENERATING, LLC

ILLINOIS POWER RESOURCES, LLC

IPH II, LLC

IPH, LLC

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the Seventh Supplemental Indenture (2019 Notes)]



Americas 92260838 v6

Exhibit 4.17

MASSPOWER , a Massachusetts general partnership

By: Masspower Partner II, LLC, its Managing Partner

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the Seventh Supplemental Indenture (2019 Notes)]



Americas 92260838 v6

Exhibit 4.17

MASSPOWER , a Massachusetts general partnership

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the Seventh Supplemental Indenture (2019 Notes)]



Americas 92260838 v6

Exhibit 4.17

SUBSIDIARY GUARANTORS:

ANP BELLINGHAM ENERGY COMPANY, LLC

ANP BLACKSTONE ENERGY COMPANY, LLC

ANP ERCOT ACQUISITION, LLC

ANP FUEL SERVICES, INC.

ANP FUNDING I, LLC

ARMSTRONG POWER, LLC

ATLAS ADMINISTRATIVE SERVICES, LLC

ATLAS FINANCE MERGECO, LLC

ATLAS I MARKETING AND TRADE, LLC

ATLAS POWER FINANCE, LLC

ATLAS POWER, LLC

CALUMET ENERGY TEAM, LLC

COLETO CREEK POWER LP

COLETO GP, LLC

COLETO LP, LLC

DYNEGY ATLAS HOLDINGS, LLC

ENNIS POWER COMPANY, LLC

DYNEGY GENERATION NA, INC. (F/K/A GDF SUEZ ENERGY GENERATION NA, INC.)

DYNEGY ENERGY GENERATION NA, LLC (F/K/A GDF SUEZ ENERGY GENERATION NA, LLC)

DYNEGY NORTH AMERICA, INC. (F/K/A GDF SUEZ ENERGY NORTH AMERICA, INC.)

HAYS ENERGY, LLC

HOPEWELL COGENERATION LIMITED PARTNERSHIP

HOPEWELL COGENERATION, LLC

DYNEGY POWER AMERICA, INC. (F/K/A INTERNATIONAL POWER AMERICA, INC.)

DP GENERATION, LLC (F/K/A IPA APT GENERATION, LLC)

DP CENTRAL, LLC (F/K/A IPA CENTRAL, LLC)

DP HOLDING, INC. (F/K/A IPA HOLDING, INC.)

DP OPERATIONS, INC. (F/K/A IPA OPERATIONS, INC.)

MIDLOTHIAN ENERGY, LLC

MILFORD POWER, LLC

NEPCO SERVICES COMPANY

NORTHEASTERN POWER COMPANY

PLEASANTS ENERGY, LLC

PRINCE GEORGE ENERGY COMPANY, LLC

T-FUELS, LLC

TNA MERCHANT PROJECTS, INC.

DYNEGY ASSOCIATES NORTHEAST LP, INC. (F/K/A TRACTEBEL ASSOCIATES NORTHEAST LP, INC.)

DYNEGY NORTHEAST GENERATION GP, INC. (F/K/A TRACTEBEL NORTHEAST GENERATION GP, INC.)

TROY ENERGY, LLC

WHARTON COUNTY GENERATION, LLC

WISE COUNTY POWER COMPANY, LLC

WISE-FUELS PIPELINE, INC.

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the Seventh Supplemental Indenture (2019 Notes)]



Americas 92260838 v6

Exhibit 4.17

WILMINGTON TRUST, NATIONAL ASSOCIATION,

as Trustee

By: /s/ Shawn Goffinet

Name: Shawn Goffinet
Title: Assistant Vice President

[Signature Page to the Seventh Supplemental Indenture (2019 Notes)]



Americas 92260838 v6

Exhibit 4.17

SCHEDULE I

SUBSIDIARY GUARANTEES

ANP BELLINGHAM ENERGY COMPANY, LLC

ANP BLACKSTONE ENERGY COMPANY, LLC

ANP ERCOT ACQUISITION, LLC

ANP FUEL SERVICES, INC.

ANP FUNDING I, LLC

ARMSTRONG POWER, LLC

ATLAS ADMINISTRATIVE SERVICES, LLC

ATLAS FINANCE MERGECO, LLC

ATLAS I MARKETING AND TRADE, LLC

ATLAS POWER FINANCE, LLC

ATLAS POWER, LLC

CALUMET ENERGY TEAM, LLC

COLETO CREEK POWER LP

COLETO GP, LLC

COLETO LP, LLC

DYNEGY ATLAS HOLDINGS, LLC

ENNIS POWER COMPANY, LLC

DYNEGY GENERATION NA, INC. (F/K/A GDF SUEZ ENERGY GENERATION NA, INC.)

DYNEGY ENERGY GENERATION NA, LLC (F/K/A GDF SUEZ ENERGY GENERATION NA, LLC)

DYNEGY NORTH AMERICA, INC. (F/K/A GDF SUEZ ENERGY NORTH AMERICA, INC.)

HAYS ENERGY, LLC

HOPEWELL COGENERATION LIMITED PARTNERSHIP

HOPEWELL COGENERATION, LLC

DYNEGY POWER AMERICA, INC. (F/K/A INTERNATIONAL POWER AMERICA, INC.)

DP GENERATION, LLC (F/K/A IPA APT GENERATION, LLC)

DP CENTRAL, LLC (F/K/A IPA CENTRAL, LLC)

DP HOLDING, INC. (F/K/A IPA HOLDING, INC.)

DP OPERATIONS, INC. (F/K/A IPA OPERATIONS, INC.)

MIDLOTHIAN ENERGY, LLC

MILFORD POWER, LLC

NEPCO SERVICES COMPANY

NORTHEASTERN POWER COMPANY

PLEASANTS ENERGY, LLC

PRINCE GEORGE ENERGY COMPANY, LLC

T-FUELS, LLC

TNA MERCHANT PROJECTS, INC.

DYNEGY ASSOCIATES NORTHEAST LP, INC. (F/K/A TRACTEBEL ASSOCIATES NORTHEAST LP, INC.)

DYNEGY NORTHEAST GENERATION GP, INC. (F/K/A TRACTEBEL NORTHEAST GENERATION GP, INC.)

TROY ENERGY, LLC

WHARTON COUNTY GENERATION, LLC

WISE COUNTY POWER COMPANY, LLC

WISE-FUELS PIPELINE, INC.



Americas 92260838 v6

Exhibit 4.24

EXECUTION VERSION

SIXTH SUPPLEMENTAL INDENTURE
SUBSIDIARY GUARANTEES

W I T N E S S E T H

WHEREAS, the Company (as successor by merger to Dynegy Finance II, Inc.) has heretofore executed and delivered to the Trustee an indenture (as supplemented, the “ Indenture ”), dated as of October 27, 2014, between the Company and the Trustee, providing for the original issuance of an aggregate principal amount of $1,050,000,000 of 7.375% Senior Notes due 2022 (the “ Initial Notes ”) and, subject to the terms of the Indenture, future unlimited issuances of 7.375% Senior Notes due 2022 (the “ Additional Notes , and together with the Initial Notes, the “ Notes ”);

WHEREAS, pursuant to Section 4.07 of the Indenture, the Trustee, the Company and the other Subsidiary Guarantors are authorized and required to execute and deliver this Supplemental Indenture.

1. Capitalized Terms . Unless otherwise defined in this Supplemental Indenture, capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

4. Counterparts . The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.



Americas 92202005 v5

Exhibit 4.24

5. Effect of Headings . The Section headings herein are for convenience only and shall not affect the construction hereof.

[ Signature Page Follows ]



Americas 92202005 v5

Exhibit 4.24

IN WITNESS WHEREOF, we have hereunto signed our names as of the date set forth below.

Dated: February 2, 2017

DYNEGY INC.

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer



	BLACK MOUNTAIN COGEN, INC. BLUE RIDGE GENERATION LLC CASCO BAY ENERGY COMPANY, LLC DIGHTON POWER, LLC DYNEGY ADMINISTRATIVE SERVICES COMPANY DYNEGY COAL GENERATION, LLC DYNEGY COAL HOLDCO, LLC DYNEGY COAL INVESTMENTS HOLDINGS, LLC DYNEGY COAL TRADING & TRANSPORTATION, L.L.C. DYNEGY COMMERCIAL ASSET MANAGEMENT, LLC DYNEGY CONESVILLE, LLC DYNEGY DICKS CREEK, LLC DYNEGY ENERGY SERVICES (EAST), LLC DYNEGY ENERGY SERVICES, LLC DYNEGY EQUIPMENT, LLC DYNEGY FAYETTE II, LLC DYNEGY GAS GENERATION, LLC DYNEGY GAS HOLDCO, LLC DYNEGY GAS IMPORTS, LLC DYNEGY GAS INVESTMENTS HOLDINGS, LLC DYNEGY GAS INVESTMENTS, LLC DYNEGY GASCO HOLDINGS, LLC DYNEGY GENERATION HOLDCO, LLC DYNEGY GLOBAL LIQUIDS, INC. DYNEGY HANGING ROCK II, LLC DYNEGY KENDALL ENERGY, LLC DYNEGY KILLEN, LLC DYNEGY LEE II, LLC DYNEGY MARKETING AND TRADE, LLC DYNEGY MIAMI FORT, LLC DYNEGY MIDWEST GENERATION, LLC DYNEGY MORRO BAY, LLC DYNEGY MOSS LANDING, LLC DYNEGY OAKLAND, LLC DYNEGY OPERATING COMPANY DYNEGY POWER GENERATION INC. DYNEGY POWER MARKETING, LLC DYNEGY POWER, LLC

[Signature Page to the Sixth Supplemental Indenture (2022 Notes)]



Americas 92202005 v5

Exhibit 4.24



DYNEGY RESOURCE HOLDINGS, LLC DYNEGY RESOURCE I, LLC DYNEGY RESOURCE II, LLC DYNEGY RESOURCE III, LLC DYNEGY RESOURCES GENERATING HOLDCO, LLC DYNEGY RESOURCES HOLDCO I, LLC DYNEGY RESOURCES HOLDCO II, LLC DYNEGY RESOURCES MANAGEMENT, LLC DYNEGY SOUTH BAY, LLC DYNEGY STUART, LLC DYNEGY WASHINGTON II, LLC DYNEGY ZIMMER, LLC ELWOOD ENERGY HOLDINGS II, LLC ELWOOD ENERGY HOLDINGS, LLC ELWOOD EXPANSION HOLDINGS, LLC EQUIPOWER RESOURCES CORP. HAVANA DOCK ENTERPRISES, LLC ILLINOVA CORPORATION KINCAID ENERGY SERVICES COMPANY, LLC KINCAID GENERATION, L.L.C. KINCAID HOLDINGS, LLC LAKE ROAD GENERATING COMPANY, LLC LIBERTY ELECTRIC POWER, LLC MASSPOWER HOLDCO, LLC MASSPOWER PARTNERS I, LLC MASSPOWER PARTNERS II, LLC MILFORD POWER COMPANY, LLC ONTELAUNEE POWER OPERATING COMPANY, LLC RICHLAND GENERATION EXPANSION, LLC RICHLAND-STRYKER GENERATION LLC RSG POWER, LLC SITHE ENERGIES, INC. SITHE/INDEPENDENCE LLC TOMCAT POWER, LLC

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the Sixth Supplemental Indenture (2022 Notes)]



Americas 92202005 v5

Exhibit 4.24

MASSPOWER , a Massachusetts general partnership

By: Masspower Partner II, LLC, its Managing Partner

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the Sixth Supplemental Indenture (2022 Notes)]



Americas 92202005 v5

Exhibit 4.24

MASSPOWER , a Massachusetts general partnership

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the Sixth Supplemental Indenture (2022 Notes)]



Americas 92202005 v5

Exhibit 4.24

SUBSIDIARY GUARANTORS:

COFFEEN AND WESTERN RAILROAD COMPANY

ILLINOIS POWER FUELS AND SERVICES COMPANY

ILLINOIS POWER GENERATING COMPANY

ILLINOIS POWER MARKETING COMPANY

ILLINOIS POWER RESOURCES GENERATING, LLC

ILLINOIS POWER RESOURCES, LLC

IPH II, LLC

IPH, LLC

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the Sixth Supplemental Indenture (2022 Notes)]



Americas 92202005 v5

Exhibit 4.24

WILMINGTON TRUST, NATIONAL ASSOCIATION,

as Trustee

By: /s/ Shawn Goffinet

Name: Shawn Goffinet
Title: Assistant Vice President

[Signature Page to the Sixth Supplemental Indenture (2022 Notes)]



Americas 92202005 v5

Exhibit 4.24

SCHEDULE I

SUBSIDIARY GUARANTEES

COFFEEN AND WESTERN RAILROAD COMPANY

ILLINOIS POWER FUELS AND SERVICES COMPANY

ILLINOIS POWER GENERATING COMPANY

ILLINOIS POWER MARKETING COMPANY

ILLINOIS POWER RESOURCES GENERATING, LLC

ILLINOIS POWER RESOURCES, LLC

IPH II, LLC

IPH, LLC



Americas 92202005 v5

Exhibit 4.25

EXECUTION VERSION

SEVENTH SUPPLEMENTAL INDENTURE
SUBSIDIARY GUARANTEES

W I T N E S S E T H

WHEREAS, the Company (as successor by merger to Dynegy Finance II, Inc.) has heretofore executed and delivered to the Trustee an indenture (as supplemented, the “ Indenture ”), dated as of October 27, 2014, between the Company and the Trustee, providing for the original issuance of an aggregate principal amount of $1,050,000,000 of 7.375% Senior Notes due 2022 (the “ Initial Notes ”) and, subject to the terms of the Indenture, future unlimited issuances of 7.375% Senior Notes due 2022 (the “ Additional Notes ” and, together with the Initial Notes, the “ Notes ”);

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee, the Company and the other Subsidiary Guarantors are authorized and required to execute and deliver this Supplemental Indenture.

1. Capitalized Terms . Unless otherwise defined in this Supplemental Indenture, capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

4. Counterparts . The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

5. Effect of Headings . The Section headings herein are for convenience only and shall not affect the construction hereof.



Americas 92260868 v6

Exhibit 4.25

[ Signature Page Follows ]



Americas 92260868 v6

Exhibit 4.25

IN WITNESS WHEREOF, we have hereunto signed our names as of the date set forth below.

Dated: February 7, 2017

DYNEGY INC.

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer



	BLACK MOUNTAIN COGEN, INC. BLUE RIDGE GENERATION LLC CASCO BAY ENERGY COMPANY, LLC DIGHTON POWER, LLC DYNEGY ADMINISTRATIVE SERVICES COMPANY DYNEGY COAL GENERATION, LLC DYNEGY COAL HOLDCO, LLC DYNEGY COAL INVESTMENTS HOLDINGS, LLC DYNEGY COAL TRADING & TRANSPORTATION, L.L.C. DYNEGY COMMERCIAL ASSET MANAGEMENT, LLC DYNEGY CONESVILLE, LLC DYNEGY DICKS CREEK, LLC DYNEGY ENERGY SERVICES (EAST), LLC DYNEGY ENERGY SERVICES, LLC DYNEGY EQUIPMENT, LLC DYNEGY FAYETTE II, LLC DYNEGY GAS GENERATION, LLC DYNEGY GAS HOLDCO, LLC DYNEGY GAS IMPORTS, LLC DYNEGY GAS INVESTMENTS HOLDINGS, LLC DYNEGY GAS INVESTMENTS, LLC DYNEGY GASCO HOLDINGS, LLC DYNEGY GENERATION HOLDCO, LLC DYNEGY GLOBAL LIQUIDS, INC. DYNEGY HANGING ROCK II, LLC DYNEGY KENDALL ENERGY, LLC DYNEGY KILLEN, LLC DYNEGY LEE II, LLC DYNEGY MARKETING AND TRADE, LLC DYNEGY MIAMI FORT, LLC DYNEGY MIDWEST GENERATION, LLC DYNEGY MORRO BAY, LLC DYNEGY MOSS LANDING, LLC DYNEGY OAKLAND, LLC DYNEGY OPERATING COMPANY DYNEGY POWER GENERATION INC. DYNEGY POWER MARKETING, LLC DYNEGY POWER, LLC

[Signature Page to the Seventh Supplemental Indenture (2022 Notes)]



Americas 92260868 v6

Exhibit 4.25



DYNEGY RESOURCE HOLDINGS, LLC DYNEGY RESOURCE I, LLC DYNEGY RESOURCE II, LLC DYNEGY RESOURCE III, LLC DYNEGY RESOURCES GENERATING HOLDCO, LLC DYNEGY RESOURCES HOLDCO I, LLC DYNEGY RESOURCES HOLDCO II, LLC DYNEGY RESOURCES MANAGEMENT, LLC DYNEGY SOUTH BAY, LLC DYNEGY STUART, LLC DYNEGY WASHINGTON II, LLC DYNEGY ZIMMER, LLC ELWOOD ENERGY HOLDINGS II, LLC ELWOOD ENERGY HOLDINGS, LLC ELWOOD EXPANSION HOLDINGS, LLC EQUIPOWER RESOURCES CORP. HAVANA DOCK ENTERPRISES, LLC ILLINOVA CORPORATION KINCAID ENERGY SERVICES COMPANY, LLC KINCAID GENERATION, L.L.C. KINCAID HOLDINGS, LLC LAKE ROAD GENERATING COMPANY, LLC LIBERTY ELECTRIC POWER, LLC MASSPOWER HOLDCO, LLC MASSPOWER PARTNERS I, LLC MASSPOWER PARTNERS II, LLC MILFORD POWER COMPANY, LLC ONTELAUNEE POWER OPERATING COMPANY, LLC RICHLAND GENERATION EXPANSION, LLC RICHLAND-STRYKER GENERATION LLC RSG POWER, LLC SITHE ENERGIES, INC. SITHE/INDEPENDENCE LLC TOMCAT POWER, LLC

COFFEEN AND WESTERN RAILROAD COMPANY

ILLINOIS POWER FUELS AND SERVICES COMPANY

ILLINOIS POWER GENERATING COMPANY

ILLINOIS POWER MARKETING COMPANY

ILLINOIS POWER RESOURCES GENERATING, LLC

ILLINOIS POWER RESOURCES, LLC

IPH II, LLC

IPH, LLC

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the Seventh Supplemental Indenture (2022 Notes)]



Americas 92260868 v6

Exhibit 4.25

MASSPOWER , a Massachusetts general partnership

By: Masspower Partner II, LLC, its Managing Partner

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the Seventh Supplemental Indenture (2022 Notes)]



Americas 92260868 v6

Exhibit 4.25

MASSPOWER , a Massachusetts general partnership

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the Seventh Supplemental Indenture (2022 Notes)]



Americas 92260868 v6

Exhibit 4.25

SUBSIDIARY GUARANTORS:

ANP BELLINGHAM ENERGY COMPANY, LLC

ANP BLACKSTONE ENERGY COMPANY, LLC

ANP ERCOT ACQUISITION, LLC

ANP FUEL SERVICES, INC.

ANP FUNDING I, LLC

ARMSTRONG POWER, LLC

ATLAS ADMINISTRATIVE SERVICES, LLC

ATLAS FINANCE MERGECO, LLC

ATLAS I MARKETING AND TRADE, LLC

ATLAS POWER FINANCE, LLC

ATLAS POWER, LLC

CALUMET ENERGY TEAM, LLC

COLETO CREEK POWER LP

COLETO GP, LLC

COLETO LP, LLC

DYNEGY ATLAS HOLDINGS, LLC

ENNIS POWER COMPANY, LLC

DYNEGY GENERATION NA, INC. (F/K/A GDF SUEZ ENERGY GENERATION NA, INC.)

DYNEGY ENERGY GENERATION NA, LLC (F/K/A GDF SUEZ ENERGY GENERATION NA, LLC)

DYNEGY NORTH AMERICA, INC. (F/K/A GDF SUEZ ENERGY NORTH AMERICA, INC.)

HAYS ENERGY, LLC

HOPEWELL COGENERATION LIMITED PARTNERSHIP

HOPEWELL COGENERATION, LLC

DYNEGY POWER AMERICA, INC. (F/K/A INTERNATIONAL POWER AMERICA, INC.)

DP GENERATION, LLC (F/K/A IPA APT GENERATION, LLC)

DP CENTRAL, LLC (F/K/A IPA CENTRAL, LLC)

DP HOLDING, INC. (F/K/A IPA HOLDING, INC.)

DP OPERATIONS, INC. (F/K/A IPA OPERATIONS, INC.)

MIDLOTHIAN ENERGY, LLC

MILFORD POWER, LLC

NEPCO SERVICES COMPANY

NORTHEASTERN POWER COMPANY

PLEASANTS ENERGY, LLC

PRINCE GEORGE ENERGY COMPANY, LLC

T-FUELS, LLC

TNA MERCHANT PROJECTS, INC.

DYNEGY ASSOCIATES NORTHEAST LP, INC. (F/K/A TRACTEBEL ASSOCIATES NORTHEAST LP, INC.)

DYNEGY NORTHEAST GENERATION GP, INC. (F/K/A TRACTEBEL NORTHEAST GENERATION GP, INC.)

TROY ENERGY, LLC

WHARTON COUNTY GENERATION, LLC

WISE COUNTY POWER COMPANY, LLC

WISE-FUELS PIPELINE, INC.

By: /s/ Clint C. Freeland

[Signature Page to the Seventh Supplemental Indenture (2022 Notes)]



Americas 92260868 v6

Exhibit 4.25

Name: Clint C. Freeland
Title: Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

WILMINGTON TRUST, NATIONAL ASSOCIATION,

as Trustee

By: /s/ Shawn Goffinet

Name: Shawn Goffinet
Title: Assistant Vice President

[Signature Page to the Seventh Supplemental Indenture (2022 Notes)]



Americas 92260868 v6

Exhibit 4.25

SCHEDULE I

SUBSIDIARY GUARANTEES

ANP BELLINGHAM ENERGY COMPANY, LLC

ANP BLACKSTONE ENERGY COMPANY, LLC

ANP ERCOT ACQUISITION, LLC

ANP FUEL SERVICES, INC.

ANP FUNDING I, LLC

ARMSTRONG POWER, LLC

ATLAS ADMINISTRATIVE SERVICES, LLC

ATLAS FINANCE MERGECO, LLC

ATLAS I MARKETING AND TRADE, LLC

ATLAS POWER FINANCE, LLC

ATLAS POWER, LLC

CALUMET ENERGY TEAM, LLC

COLETO CREEK POWER LP

COLETO GP, LLC

COLETO LP, LLC

DYNEGY ATLAS HOLDINGS, LLC

ENNIS POWER COMPANY, LLC

DYNEGY GENERATION NA, INC. (F/K/A GDF SUEZ ENERGY GENERATION NA, INC.)

DYNEGY ENERGY GENERATION NA, LLC (F/K/A GDF SUEZ ENERGY GENERATION NA, LLC)

DYNEGY NORTH AMERICA, INC. (F/K/A GDF SUEZ ENERGY NORTH AMERICA, INC.)

HAYS ENERGY, LLC

HOPEWELL COGENERATION LIMITED PARTNERSHIP

HOPEWELL COGENERATION, LLC

DYNEGY POWER AMERICA, INC. (F/K/A INTERNATIONAL POWER AMERICA, INC.)

DP GENERATION, LLC (F/K/A IPA APT GENERATION, LLC)

DP CENTRAL, LLC (F/K/A IPA CENTRAL, LLC)

DP HOLDING, INC. (F/K/A IPA HOLDING, INC.)

DP OPERATIONS, INC. (F/K/A IPA OPERATIONS, INC.)

MIDLOTHIAN ENERGY, LLC

MILFORD POWER, LLC

NEPCO SERVICES COMPANY

NORTHEASTERN POWER COMPANY

PLEASANTS ENERGY, LLC

PRINCE GEORGE ENERGY COMPANY, LLC

T-FUELS, LLC

TNA MERCHANT PROJECTS, INC.

DYNEGY ASSOCIATES NORTHEAST LP, INC. (F/K/A TRACTEBEL ASSOCIATES NORTHEAST LP, INC.)

DYNEGY NORTHEAST GENERATION GP, INC. (F/K/A TRACTEBEL NORTHEAST GENERATION GP, INC.)

TROY ENERGY, LLC

WHARTON COUNTY GENERATION, LLC

WISE COUNTY POWER COMPANY, LLC

WISE-FUELS PIPELINE, INC.



Americas 92260868 v6

Exhibit 4.32

EXECUTION VERSION

SIXTH SUPPLEMENTAL INDENTURE
SUBSIDIARY GUARANTEES

W I T N E S S E T H

WHEREAS, the Company (as successor by merger to Dynegy Finance II, Inc.) has heretofore executed and delivered to the Trustee an indenture (as supplemented, the “ Indenture ”), dated as of October 27, 2014, between the Company and the Trustee, providing for the original issuance of an aggregate principal amount of $750,000,000 of 7.625% Senior Notes due 2024 (the “ Initial Notes ”) and, subject to the terms of the Indenture, future unlimited issuances of 7.625% Senior Notes due 2024 (the “ Additional Notes ,” and together with the Initial Notes, the “ Notes ”);

WHEREAS, pursuant to Section 4.07 of the Indenture, the Trustee, the Company and the other Subsidiary Guarantors are authorized and required to execute and deliver this Supplemental Indenture.

1. Capitalized Terms . Unless otherwise defined in this Supplemental Indenture, capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

4. Counterparts . The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

5. Effect of Headings . The Section headings herein are for convenience only and shall not affect the construction hereof.



Americas 92202015 v5

Exhibit 4.32

[ Signature Page Follows ]



Americas 92202015 v5

Exhibit 4.32

IN WITNESS WHEREOF, we have hereunto signed our names as of the date set forth below.

Dated: February 2, 2017

DYNEGY INC.

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer



	BLACK MOUNTAIN COGEN, INC. BLUE RIDGE GENERATION LLC CASCO BAY ENERGY COMPANY, LLC DIGHTON POWER, LLC DYNEGY ADMINISTRATIVE SERVICES COMPANY DYNEGY COAL GENERATION, LLC DYNEGY COAL HOLDCO, LLC DYNEGY COAL INVESTMENTS HOLDINGS, LLC DYNEGY COAL TRADING & TRANSPORTATION, L.L.C. DYNEGY COMMERCIAL ASSET MANAGEMENT, LLC DYNEGY CONESVILLE, LLC DYNEGY DICKS CREEK, LLC DYNEGY ENERGY SERVICES (EAST), LLC DYNEGY ENERGY SERVICES, LLC DYNEGY EQUIPMENT, LLC DYNEGY FAYETTE II, LLC DYNEGY GAS GENERATION, LLC DYNEGY GAS HOLDCO, LLC DYNEGY GAS IMPORTS, LLC DYNEGY GAS INVESTMENTS HOLDINGS, LLC DYNEGY GAS INVESTMENTS, LLC DYNEGY GASCO HOLDINGS, LLC DYNEGY GENERATION HOLDCO, LLC DYNEGY GLOBAL LIQUIDS, INC. DYNEGY HANGING ROCK II, LLC DYNEGY KENDALL ENERGY, LLC DYNEGY KILLEN, LLC DYNEGY LEE II, LLC DYNEGY MARKETING AND TRADE, LLC DYNEGY MIAMI FORT, LLC DYNEGY MIDWEST GENERATION, LLC DYNEGY MORRO BAY, LLC DYNEGY MOSS LANDING, LLC DYNEGY OAKLAND, LLC DYNEGY OPERATING COMPANY DYNEGY POWER GENERATION INC. DYNEGY POWER MARKETING, LLC DYNEGY POWER, LLC

[Signature Page to the Sixth Supplemental Indenture (2024 Notes)]



Americas 92202015 v5

Exhibit 4.32



DYNEGY RESOURCE HOLDINGS, LLC DYNEGY RESOURCE I, LLC DYNEGY RESOURCE II, LLC DYNEGY RESOURCE III, LLC DYNEGY RESOURCES GENERATING HOLDCO, LLC DYNEGY RESOURCES HOLDCO I, LLC DYNEGY RESOURCES HOLDCO II, LLC DYNEGY RESOURCES MANAGEMENT, LLC DYNEGY SOUTH BAY, LLC DYNEGY STUART, LLC DYNEGY WASHINGTON II, LLC DYNEGY ZIMMER, LLC ELWOOD ENERGY HOLDINGS II, LLC ELWOOD ENERGY HOLDINGS, LLC ELWOOD EXPANSION HOLDINGS, LLC EQUIPOWER RESOURCES CORP. HAVANA DOCK ENTERPRISES, LLC ILLINOVA CORPORATION KINCAID ENERGY SERVICES COMPANY, LLC KINCAID GENERATION, L.L.C. KINCAID HOLDINGS, LLC LAKE ROAD GENERATING COMPANY, LLC LIBERTY ELECTRIC POWER, LLC MASSPOWER HOLDCO, LLC MASSPOWER PARTNERS I, LLC MASSPOWER PARTNERS II, LLC MILFORD POWER COMPANY, LLC ONTELAUNEE POWER OPERATING COMPANY, LLC RICHLAND GENERATION EXPANSION, LLC RICHLAND-STRYKER GENERATION LLC RSG POWER, LLC SITHE ENERGIES, INC. SITHE/INDEPENDENCE LLC TOMCAT POWER, LLC

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the Sixth Supplemental Indenture (2024 Notes)]



Americas 92202015 v5

Exhibit 4.32

MASSPOWER , a Massachusetts general partnership

By: Masspower Partner II, LLC, its Managing Partner

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the Sixth Supplemental Indenture (2024 Notes)]



Americas 92202015 v5

Exhibit 4.32

MASSPOWER , a Massachusetts general partnership

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the Sixth Supplemental Indenture (2024 Notes)]



Americas 92202015 v5

Exhibit 4.32

SUBSIDIARY GUARANTORS:

COFFEEN AND WESTERN RAILROAD COMPANY

ILLINOIS POWER FUELS AND SERVICES COMPANY

ILLINOIS POWER GENERATING COMPANY

ILLINOIS POWER MARKETING COMPANY

ILLINOIS POWER RESOURCES GENERATING, LLC

ILLINOIS POWER RESOURCES, LLC

IPH II, LLC

IPH, LLC

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the Sixth Supplemental Indenture (2024 Notes)]



Americas 92202015 v5

Exhibit 4.32

WILMINGTON TRUST, NATIONAL ASSOCIATION,

as Trustee

By: /s/ Shawn Goffinet

Name: Shawn Goffinet
Title: Assistant Vice President

[Signature Page to the Sixth Supplemental Indenture (2024 Notes)]



Americas 92202015 v5

Exhibit 4.32

SCHEDULE I

SUBSIDIARY GUARANTEES

COFFEEN AND WESTERN RAILROAD COMPANY

ILLINOIS POWER FUELS AND SERVICES COMPANY

ILLINOIS POWER GENERATING COMPANY

ILLINOIS POWER MARKETING COMPANY

ILLINOIS POWER RESOURCES GENERATING, LLC

ILLINOIS POWER RESOURCES, LLC

IPH II, LLC

IPH, LLC



Americas 92202015 v5

Exhibit 4.33

EXECUTION VERSION

SEVENTH SUPPLEMENTAL INDENTURE
SUBSIDIARY GUARANTEES

W I T N E S S E T H

WHEREAS, the Company (as successor by merger to Dynegy Finance II, Inc.) has heretofore executed and delivered to the Trustee an indenture (as supplemented, the “ Indenture ”), dated as of October 27, 2014, between the Company and the Trustee, providing for the original issuance of an aggregate principal amount of $750,000,000 of 7.625% Senior Notes due 2024 (the “ Initial Notes ”) and, subject to the terms of the Indenture, future unlimited issuances of 7.625% Senior Notes due 2024 (the “ Additional Notes ” and, together with the Initial Notes, the “ Notes ”);

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee, the Company and the other Subsidiary Guarantors are authorized and required to execute and deliver this Supplemental Indenture.

1. Capitalized Terms . Unless otherwise defined in this Supplemental Indenture, capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

4. Counterparts . The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

5. Effect of Headings . The Section headings herein are for convenience only and shall not affect the construction hereof.



Americas 92260932 v6

Exhibit 4.33

[ Signature Page Follows ]



Americas 92260932 v6

Exhibit 4.33

IN WITNESS WHEREOF, we have hereunto signed our names as of the date set forth below.

Dated: February 7, 2017

DYNEGY INC.

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer



	BLACK MOUNTAIN COGEN, INC. BLUE RIDGE GENERATION LLC CASCO BAY ENERGY COMPANY, LLC DIGHTON POWER, LLC DYNEGY ADMINISTRATIVE SERVICES COMPANY DYNEGY COAL GENERATION, LLC DYNEGY COAL HOLDCO, LLC DYNEGY COAL INVESTMENTS HOLDINGS, LLC DYNEGY COAL TRADING & TRANSPORTATION, L.L.C. DYNEGY COMMERCIAL ASSET MANAGEMENT, LLC DYNEGY CONESVILLE, LLC DYNEGY DICKS CREEK, LLC DYNEGY ENERGY SERVICES (EAST), LLC DYNEGY ENERGY SERVICES, LLC DYNEGY EQUIPMENT, LLC DYNEGY FAYETTE II, LLC DYNEGY GAS GENERATION, LLC DYNEGY GAS HOLDCO, LLC DYNEGY GAS IMPORTS, LLC DYNEGY GAS INVESTMENTS HOLDINGS, LLC DYNEGY GAS INVESTMENTS, LLC DYNEGY GASCO HOLDINGS, LLC DYNEGY GENERATION HOLDCO, LLC DYNEGY GLOBAL LIQUIDS, INC. DYNEGY HANGING ROCK II, LLC DYNEGY KENDALL ENERGY, LLC DYNEGY KILLEN, LLC DYNEGY LEE II, LLC DYNEGY MARKETING AND TRADE, LLC DYNEGY MIAMI FORT, LLC DYNEGY MIDWEST GENERATION, LLC DYNEGY MORRO BAY, LLC DYNEGY MOSS LANDING, LLC DYNEGY OAKLAND, LLC DYNEGY OPERATING COMPANY DYNEGY POWER GENERATION INC. DYNEGY POWER MARKETING, LLC DYNEGY POWER, LLC

[Signature Page to the Seventh Supplemental Indenture (2024 Notes)]



Americas 92260932 v6

Exhibit 4.33



DYNEGY RESOURCE HOLDINGS, LLC DYNEGY RESOURCE I, LLC DYNEGY RESOURCE II, LLC DYNEGY RESOURCE III, LLC DYNEGY RESOURCES GENERATING HOLDCO, LLC DYNEGY RESOURCES HOLDCO I, LLC DYNEGY RESOURCES HOLDCO II, LLC DYNEGY RESOURCES MANAGEMENT, LLC DYNEGY SOUTH BAY, LLC DYNEGY STUART, LLC DYNEGY WASHINGTON II, LLC DYNEGY ZIMMER, LLC ELWOOD ENERGY HOLDINGS II, LLC ELWOOD ENERGY HOLDINGS, LLC ELWOOD EXPANSION HOLDINGS, LLC EQUIPOWER RESOURCES CORP. HAVANA DOCK ENTERPRISES, LLC ILLINOVA CORPORATION KINCAID ENERGY SERVICES COMPANY, LLC KINCAID GENERATION, L.L.C. KINCAID HOLDINGS, LLC LAKE ROAD GENERATING COMPANY, LLC LIBERTY ELECTRIC POWER, LLC MASSPOWER HOLDCO, LLC MASSPOWER PARTNERS I, LLC MASSPOWER PARTNERS II, LLC MILFORD POWER COMPANY, LLC ONTELAUNEE POWER OPERATING COMPANY, LLC RICHLAND GENERATION EXPANSION, LLC RICHLAND-STRYKER GENERATION LLC RSG POWER, LLC SITHE ENERGIES, INC. SITHE/INDEPENDENCE LLC TOMCAT POWER, LLC

COFFEEN AND WESTERN RAILROAD COMPANY

ILLINOIS POWER FUELS AND SERVICES COMPANY

ILLINOIS POWER GENERATING COMPANY

ILLINOIS POWER MARKETING COMPANY

ILLINOIS POWER RESOURCES GENERATING, LLC

ILLINOIS POWER RESOURCES, LLC

IPH II, LLC

IPH, LLC

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the Seventh Supplemental Indenture (2024 Notes)]



Americas 92260932 v6

Exhibit 4.33

MASSPOWER , a Massachusetts general partnership

By: Masspower Partner II, LLC, its Managing Partner

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the Seventh Supplemental Indenture (2024 Notes)]



Americas 92260932 v6

Exhibit 4.33

MASSPOWER , a Massachusetts general partnership

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the Seventh Supplemental Indenture (2024 Notes)]



Americas 92260932 v6

Exhibit 4.33

SUBSIDIARY GUARANTORS:

ANP BELLINGHAM ENERGY COMPANY, LLC

ANP BLACKSTONE ENERGY COMPANY, LLC

ANP ERCOT ACQUISITION, LLC

ANP FUEL SERVICES, INC.

ANP FUNDING I, LLC

ARMSTRONG POWER, LLC

ATLAS ADMINISTRATIVE SERVICES, LLC

ATLAS FINANCE MERGECO, LLC

ATLAS I MARKETING AND TRADE, LLC

ATLAS POWER FINANCE, LLC

ATLAS POWER, LLC

CALUMET ENERGY TEAM, LLC

COLETO CREEK POWER LP

COLETO GP, LLC

COLETO LP, LLC

DYNEGY ATLAS HOLDINGS, LLC

ENNIS POWER COMPANY, LLC

DYNEGY GENERATION NA, INC. (F/K/A GDF SUEZ ENERGY GENERATION NA, INC.)

DYNEGY ENERGY GENERATION NA, LLC (F/K/A GDF SUEZ ENERGY GENERATION NA, LLC)

DYNEGY NORTH AMERICA, INC. (F/K/A GDF SUEZ ENERGY NORTH AMERICA, INC.)

HAYS ENERGY, LLC

HOPEWELL COGENERATION LIMITED PARTNERSHIP

HOPEWELL COGENERATION, LLC

DYNEGY POWER AMERICA, INC. (F/K/A INTERNATIONAL POWER AMERICA, INC.)

DP GENERATION, LLC (F/K/A IPA APT GENERATION, LLC)

DP CENTRAL, LLC (F/K/A IPA CENTRAL, LLC)

DP HOLDING, INC. (F/K/A IPA HOLDING, INC.)

DP OPERATIONS, INC. (F/K/A IPA OPERATIONS, INC.)

MIDLOTHIAN ENERGY, LLC

MILFORD POWER, LLC

NEPCO SERVICES COMPANY

NORTHEASTERN POWER COMPANY

PLEASANTS ENERGY, LLC

PRINCE GEORGE ENERGY COMPANY, LLC

T-FUELS, LLC

TNA MERCHANT PROJECTS, INC.

DYNEGY ASSOCIATES NORTHEAST LP, INC. (F/K/A TRACTEBEL ASSOCIATES NORTHEAST LP, INC.)

DYNEGY NORTHEAST GENERATION GP, INC. (F/K/A TRACTEBEL NORTHEAST GENERATION GP, INC.)

TROY ENERGY, LLC

WHARTON COUNTY GENERATION, LLC

WISE COUNTY POWER COMPANY, LLC

WISE-FUELS PIPELINE, INC.

[Signature Page to the Seventh Supplemental Indenture (2024 Notes)]



Americas 92260932 v6

Exhibit 4.33

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the Seventh Supplemental Indenture (2024 Notes)]



Americas 92260932 v6

Exhibit 4.33

WILMINGTON TRUST, NATIONAL ASSOCIATION,

as Trustee

By: /s/ Shawn Goffinet

Name: Shawn Goffinet
Title: Assistant Vice President

[Signature Page to the Seventh Supplemental Indenture (2024 Notes)]



Americas 92260932 v6

Exhibit 4.33

SCHEDULE I

SUBSIDIARY GUARANTEES

ANP BELLINGHAM ENERGY COMPANY, LLC

ANP BLACKSTONE ENERGY COMPANY, LLC

ANP ERCOT ACQUISITION, LLC

ANP FUEL SERVICES, INC.

ANP FUNDING I, LLC

ARMSTRONG POWER, LLC

ATLAS ADMINISTRATIVE SERVICES, LLC

ATLAS FINANCE MERGECO, LLC

ATLAS I MARKETING AND TRADE, LLC

ATLAS POWER FINANCE, LLC

ATLAS POWER, LLC

CALUMET ENERGY TEAM, LLC

COLETO CREEK POWER LP

COLETO GP, LLC

COLETO LP, LLC

DYNEGY ATLAS HOLDINGS, LLC

ENNIS POWER COMPANY, LLC

DYNEGY GENERATION NA, INC. (F/K/A GDF SUEZ ENERGY GENERATION NA, INC.)

DYNEGY ENERGY GENERATION NA, LLC (F/K/A GDF SUEZ ENERGY GENERATION NA, LLC)

DYNEGY NORTH AMERICA, INC. (F/K/A GDF SUEZ ENERGY NORTH AMERICA, INC.)

HAYS ENERGY, LLC

HOPEWELL COGENERATION LIMITED PARTNERSHIP

HOPEWELL COGENERATION, LLC

DYNEGY POWER AMERICA, INC. (F/K/A INTERNATIONAL POWER AMERICA, INC.)

DP GENERATION, LLC (F/K/A IPA APT GENERATION, LLC)

DP CENTRAL, LLC (F/K/A IPA CENTRAL, LLC)

DP HOLDING, INC. (F/K/A IPA HOLDING, INC.)

DP OPERATIONS, INC. (F/K/A IPA OPERATIONS, INC.)

MIDLOTHIAN ENERGY, LLC

MILFORD POWER, LLC

NEPCO SERVICES COMPANY

NORTHEASTERN POWER COMPANY

PLEASANTS ENERGY, LLC

PRINCE GEORGE ENERGY COMPANY, LLC

T-FUELS, LLC

TNA MERCHANT PROJECTS, INC.

DYNEGY ASSOCIATES NORTHEAST LP, INC. (F/K/A TRACTEBEL ASSOCIATES NORTHEAST LP, INC.)

DYNEGY NORTHEAST GENERATION GP, INC. (F/K/A TRACTEBEL NORTHEAST GENERATION GP, INC.)

TROY ENERGY, LLC

WHARTON COUNTY GENERATION, LLC

WISE COUNTY POWER COMPANY, LLC

WISE-FUELS PIPELINE, INC.



Americas 92260932 v6

Exhibit 4.35

EXECUTION VERSION

FIRST SUPPLEMENTAL INDENTURE

SUBSIDIARY GUARANTEES

FIRST SUPPLEMENTAL INDENTURE (this “ Supplemental Indenture ”), dated as of February 2, 2017, among the Subsidiary Guarantors listed on Schedule I (the “ Guaranteeing Subsidiaries ”), each a wholly-owned domestic subsidiary of Dynegy Inc. (or its permitted successor), a Delaware corporation (the “ Company ”), the Company, the other Subsidiary Guarantors (as defined in the Indenture referred to herein) and Wilmington Trust, National Association, as trustee under the Indenture referred to herein (the “ Trustee ”).

W I T N E S S E T H

WHEREAS, the Company has heretofore executed and delivered to the Trustee an indenture (the “ Indenture ”), dated as of October 11, 2016, among the Company, the Subsidiary Guarantors named therein and the Trustee, providing for the original issuance of an aggregate principal amount of $750,000,000 of 8.000% Senior Notes due 2025 (the “ Notes ”), and, subject to the terms of the Indenture, future unlimited issuances of 8.000% Senior Notes due 2025 (the “ Additional Notes ,” and together with the Initial Notes, the “ Notes ”);

WHEREAS, pursuant to Section 4.07 of the Indenture, the Trustee, the Company and the other

Subsidiary Guarantors are authorized and required to execute and deliver this Supplemental Indenture without the consent of any Holders of Notes.

1. Capitalized Terms . Unless otherwise defined in this Supplemental Indenture, capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

3. NEW YORK LAW TO GOVERN . THE INDENTURE, THE NOTES AND THE SUBSIDIARY GUARANTEES SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK.

4. Counterparts . The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

5. Effect of Headings . The Section headings herein are for convenience only and shall not affect the construction hereof.



Americas 92203420 v5

Exhibit 4.35

[ Signature Page Follows ]



Americas 92203420 v5

Exhibit 4.35

IN WITNESS WHEREOF, we have hereunto signed our names as of the date set forth below.

Dated: February 2, 2017

DYNEGY INC.

By: /s/ Clint C. Freeland
Name: Clint C. Freeland
Title: Executive Vice President and Chief Financial Officer



	BLACK MOUNTAIN COGEN, INC. BLUE RIDGE GENERATION LLC CASCO BAY ENERGY COMPANY, LLC DIGHTON POWER, LLC DYNEGY ADMINISTRATIVE SERVICES COMPANY DYNEGY COAL GENERATION, LLC DYNEGY COAL HOLDCO, LLC DYNEGY COAL INVESTMENTS HOLDINGS, LLC DYNEGY COAL TRADING & TRANSPORTATION, L.L.C. DYNEGY COMMERCIAL ASSET MANAGEMENT, LLC DYNEGY CONESVILLE, LLC DYNEGY DICKS CREEK, LLC DYNEGY ENERGY SERVICES (EAST), LLC DYNEGY ENERGY SERVICES, LLC DYNEGY EQUIPMENT, LLC DYNEGY FAYETTE II, LLC DYNEGY GAS GENERATION, LLC DYNEGY GAS HOLDCO, LLC DYNEGY GAS IMPORTS, LLC DYNEGY GAS INVESTMENTS HOLDINGS, LLC DYNEGY GAS INVESTMENTS, LLC DYNEGY GASCO HOLDINGS, LLC DYNEGY GENERATION HOLDCO, LLC DYNEGY GLOBAL LIQUIDS, INC. DYNEGY HANGING ROCK II, LLC DYNEGY KENDALL ENERGY, LLC DYNEGY KILLEN, LLC DYNEGY LEE II, LLC DYNEGY MARKETING AND TRADE, LLC DYNEGY MIAMI FORT, LLC DYNEGY MIDWEST GENERATION, LLC DYNEGY MORRO BAY, LLC DYNEGY MOSS LANDING, LLC DYNEGY OAKLAND, LLC DYNEGY OPERATING COMPANY DYNEGY POWER GENERATION INC. DYNEGY POWER MARKETING, LLC DYNEGY POWER, LLC

[Signature Page to the First Supplemental Indenture (2025 Notes)]



Americas 92203420 v5

Exhibit 4.35



DYNEGY RESOURCE HOLDINGS, LLC DYNEGY RESOURCE I, LLC DYNEGY RESOURCE II, LLC DYNEGY RESOURCE III, LLC DYNEGY RESOURCES GENERATING HOLDCO, LLC DYNEGY RESOURCES HOLDCO I, LLC DYNEGY RESOURCES HOLDCO II, LLC DYNEGY RESOURCES MANAGEMENT, LLC DYNEGY SOUTH BAY, LLC DYNEGY STUART, LLC DYNEGY WASHINGTON II, LLC DYNEGY ZIMMER, LLC ELWOOD ENERGY HOLDINGS II, LLC ELWOOD ENERGY HOLDINGS, LLC ELWOOD EXPANSION HOLDINGS, LLC EQUIPOWER RESOURCES CORP. HAVANA DOCK ENTERPRISES, LLC ILLINOVA CORPORATION KINCAID ENERGY SERVICES COMPANY, LLC KINCAID GENERATION, L.L.C. KINCAID HOLDINGS, LLC LAKE ROAD GENERATING COMPANY, LLC LIBERTY ELECTRIC POWER, LLC MASSPOWER HOLDCO, LLC MASSPOWER PARTNERS I, LLC MASSPOWER PARTNERS II, LLC MILFORD POWER COMPANY, LLC ONTELAUNEE POWER OPERATING COMPANY, LLC RICHLAND GENERATION EXPANSION, LLC RICHLAND-STRYKER GENERATION LLC RSG POWER, LLC SITHE ENERGIES, INC. SITHE/INDEPENDENCE LLC TOMCAT POWER, LLC

By: /s/ Clint C. Freeland
Name: Clint C. Freeland
Title: Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the First Supplemental Indenture (2025 Notes)]



Americas 92203420 v5

Exhibit 4.35

MASSPOWER , a Massachusetts general partnership

By: Masspower Partner II, LLC, its Managing Partner

By: /s/ Clint C. Freeland

Name: Clint C. Freeland
Title: Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the First Supplemental Indenture (2025 Notes)]



Americas 92203420 v5

Exhibit 4.35

MASSPOWER , a Massachusetts general partnership

By: /s/ Clint C. Freeland________
Name: Clint C. Freeland
Title: Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the First Supplemental Indenture (2025 Notes)]



Americas 92203420 v5

Exhibit 4.35

SUBSIDIARY GUARANTORS:

COFFEEN AND WESTERN RAILROAD COMPANY

ILLINOIS POWER FUELS AND SERVICES COMPANY

ILLINOIS POWER GENERATING COMPANY

ILLINOIS POWER MARKETING COMPANY

ILLINOIS POWER RESOURCES GENERATING, LLC

ILLINOIS POWER RESOURCES, LLC

IPH II, LLC

IPH, LLC

By: /s/ Clint C. Freeland________

Name: Clint C. Freeland
Title: Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the First Supplemental Indenture (2025 Notes)]



Americas 92203420 v5

Exhibit 4.35

WILMINGTON TRUST, NATIONAL ASSOCIATION,

as Trustee

By: /s/ Shawn Goffinet

Name: Shawn Goffinet
Title: Assistant Vice President

[Signature Page to the First Supplemental Indenture (2025 Notes)]



Americas 92203420 v5

Exhibit 4.35

SCHEDULE I

SUBSIDIARY GUARANTEES

COFFEEN AND WESTERN RAILROAD COMPANY

ILLINOIS POWER FUELS AND SERVICES COMPANY

ILLINOIS POWER GENERATING COMPANY

ILLINOIS POWER MARKETING COMPANY

ILLINOIS POWER RESOURCES GENERATING, LLC

ILLINOIS POWER RESOURCES, LLC

IPH II, LLC

IPH, LLC



Americas 92203420 v5

Exhibit 4.36

EXECUTION VERSION

SECOND SUPPLEMENTAL INDENTURE

SUBSIDIARY GUARANTEES

SECOND SUPPLEMENTAL INDENTURE (this “ Supplemental Indenture ”), dated as of February 7, 2017, among the Subsidiary Guarantors listed on Schedule I (the “ Guaranteeing Subsidiaries ”), each a wholly-owned domestic subsidiary of Dynegy Inc. (or its permitted successor), a Delaware corporation (the “ Company ”), the Company, the other Subsidiary Guarantors (as defined in the Indenture referred to herein) and Wilmington Trust, National Association, as trustee under the Indenture referred to herein (the “ Trustee ”).

W I T N E S S E T H

WHEREAS, the Company has heretofore executed and delivered to the Trustee an indenture (the “ Indenture ”), dated as of October 11, 2016, among the Company, the Subsidiary Guarantors named therein and the Trustee, providing for the original issuance of an aggregate principal amount of $750,000,000 of 8.000% Senior Notes due 2025 (the “ Initial Notes ”), and, subject to the terms of the Indenture, future unlimited issuances of 8.000% Senior Notes due 2025 (the “ Additional Notes ” and, together with the Initial Notes, the “ Notes ”);

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee, the Company and the other

Subsidiary Guarantors are authorized and required to execute and deliver this Supplemental Indenture without the consent of any Holders of Notes.

1. Capitalized Terms . Unless otherwise defined in this Supplemental Indenture, capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

3. NEW YORK LAW TO GOVERN . THE INDENTURE, THE NOTES AND THE SUBSIDIARY GUARANTEES SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK.

4. Counterparts . The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

5. Effect of Headings . The Section headings herein are for convenience only and shall not affect the construction hereof.



Americas 92260805 v6

Exhibit 4.36

[ Signature Page Follows ]



Americas 92260805 v6

Exhibit 4.36

IN WITNESS WHEREOF, we have hereunto signed our names as of the date set forth below.

Dated: February 7, 2017

DYNEGY INC.

By: /s/ Clint C. Freeland

Name: Clint C. Freeland
Title: Executive Vice President and Chief Financial Officer



	BLACK MOUNTAIN COGEN, INC. BLUE RIDGE GENERATION LLC CASCO BAY ENERGY COMPANY, LLC DIGHTON POWER, LLC DYNEGY ADMINISTRATIVE SERVICES COMPANY DYNEGY COAL GENERATION, LLC DYNEGY COAL HOLDCO, LLC DYNEGY COAL INVESTMENTS HOLDINGS, LLC DYNEGY COAL TRADING & TRANSPORTATION, L.L.C. DYNEGY COMMERCIAL ASSET MANAGEMENT, LLC DYNEGY CONESVILLE, LLC DYNEGY DICKS CREEK, LLC DYNEGY ENERGY SERVICES (EAST), LLC DYNEGY ENERGY SERVICES, LLC DYNEGY EQUIPMENT, LLC DYNEGY FAYETTE II, LLC DYNEGY GAS GENERATION, LLC DYNEGY GAS HOLDCO, LLC DYNEGY GAS IMPORTS, LLC DYNEGY GAS INVESTMENTS HOLDINGS, LLC DYNEGY GAS INVESTMENTS, LLC DYNEGY GASCO HOLDINGS, LLC DYNEGY GENERATION HOLDCO, LLC DYNEGY GLOBAL LIQUIDS, INC. DYNEGY HANGING ROCK II, LLC DYNEGY KENDALL ENERGY, LLC DYNEGY KILLEN, LLC DYNEGY LEE II, LLC DYNEGY MARKETING AND TRADE, LLC DYNEGY MIAMI FORT, LLC DYNEGY MIDWEST GENERATION, LLC DYNEGY MORRO BAY, LLC DYNEGY MOSS LANDING, LLC DYNEGY OAKLAND, LLC DYNEGY OPERATING COMPANY DYNEGY POWER GENERATION INC. DYNEGY POWER MARKETING, LLC DYNEGY POWER, LLC

[Signature Page to the Second Supplemental Indenture (2025 Notes)]



Americas 92260805 v6

Exhibit 4.36



DYNEGY RESOURCE HOLDINGS, LLC DYNEGY RESOURCE I, LLC DYNEGY RESOURCE II, LLC DYNEGY RESOURCE III, LLC DYNEGY RESOURCES GENERATING HOLDCO, LLC DYNEGY RESOURCES HOLDCO I, LLC DYNEGY RESOURCES HOLDCO II, LLC DYNEGY RESOURCES MANAGEMENT, LLC DYNEGY SOUTH BAY, LLC DYNEGY STUART, LLC DYNEGY WASHINGTON II, LLC DYNEGY ZIMMER, LLC ELWOOD ENERGY HOLDINGS II, LLC ELWOOD ENERGY HOLDINGS, LLC ELWOOD EXPANSION HOLDINGS, LLC EQUIPOWER RESOURCES CORP. HAVANA DOCK ENTERPRISES, LLC ILLINOVA CORPORATION KINCAID ENERGY SERVICES COMPANY, LLC KINCAID GENERATION, L.L.C. KINCAID HOLDINGS, LLC LAKE ROAD GENERATING COMPANY, LLC LIBERTY ELECTRIC POWER, LLC MASSPOWER HOLDCO, LLC MASSPOWER PARTNERS I, LLC MASSPOWER PARTNERS II, LLC MILFORD POWER COMPANY, LLC ONTELAUNEE POWER OPERATING COMPANY, LLC RICHLAND GENERATION EXPANSION, LLC RICHLAND-STRYKER GENERATION LLC RSG POWER, LLC SITHE ENERGIES, INC. SITHE/INDEPENDENCE LLC TOMCAT POWER, LLC

COFFEEN AND WESTERN RAILROAD COMPANY

ILLINOIS POWER FUELS AND SERVICES COMPANY

ILLINOIS POWER GENERATING COMPANY

ILLINOIS POWER MARKETING COMPANY

ILLINOIS POWER RESOURCES GENERATING, LLC

ILLINOIS POWER RESOURCES, LLC

IPH II, LLC

IPH, LLC

By: /s/ Clint C. Freeland
Name: Clint C. Freeland
Title: Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the Second Supplemental Indenture (2025 Notes)]



Americas 92260805 v6

Exhibit 4.36

MASSPOWER , a Massachusetts general partnership

By: Masspower Partner II, LLC, its Managing Partner

By: /s/ Clint C. Freeland
Name: Clint C. Freeland
Title: Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the Second Supplemental Indenture (2025 Notes)]



Americas 92260805 v6

Exhibit 4.36

MASSPOWER , a Massachusetts general partnership

By: /s/ Clint C. Freeland
Name: Clint C. Freeland
Title: Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the Second Supplemental Indenture (2025 Notes)]



Americas 92260805 v6

Exhibit 4.36

SUBSIDIARY GUARANTORS:

ANP BELLINGHAM ENERGY COMPANY, LLC

ANP BLACKSTONE ENERGY COMPANY, LLC

ANP ERCOT ACQUISITION, LLC

ANP FUEL SERVICES, INC.

ANP FUNDING I, LLC

ARMSTRONG POWER, LLC

ATLAS ADMINISTRATIVE SERVICES, LLC

ATLAS FINANCE MERGECO, LLC

ATLAS I MARKETING AND TRADE, LLC

ATLAS POWER FINANCE, LLC

ATLAS POWER, LLC

CALUMET ENERGY TEAM, LLC

COLETO CREEK POWER LP

COLETO GP, LLC

COLETO LP, LLC

DYNEGY ATLAS HOLDINGS, LLC

ENNIS POWER COMPANY, LLC

DYNEGY GENERATION NA, INC. (F/K/A GDF SUEZ ENERGY GENERATION NA, INC.)

DYNEGY ENERGY GENERATION NA, LLC (F/K/A GDF SUEZ ENERGY GENERATION NA, LLC)

DYNEGY NORTH AMERICA, INC. (F/K/A GDF SUEZ ENERGY NORTH AMERICA, INC.)

HAYS ENERGY, LLC

HOPEWELL COGENERATION LIMITED PARTNERSHIP

HOPEWELL COGENERATION, LLC

DYNEGY POWER AMERICA, INC. (F/K/A INTERNATIONAL POWER AMERICA, INC.)

DP GENERATION, LLC (F/K/A IPA APT GENERATION, LLC)

DP CENTRAL, LLC (F/K/A IPA CENTRAL, LLC)

DP HOLDING, INC. (F/K/A IPA HOLDING, INC.)

DP OPERATIONS, INC. (F/K/A IPA OPERATIONS, INC.)

MIDLOTHIAN ENERGY, LLC

MILFORD POWER, LLC

NEPCO SERVICES COMPANY

NORTHEASTERN POWER COMPANY

PLEASANTS ENERGY, LLC

PRINCE GEORGE ENERGY COMPANY, LLC

T-FUELS, LLC

TNA MERCHANT PROJECTS, INC.

DYNEGY ASSOCIATES NORTHEAST LP, INC. (F/K/A TRACTEBEL ASSOCIATES NORTHEAST LP, INC.)

DYNEGY NORTHEAST GENERATION GP, INC. (F/K/A TRACTEBEL NORTHEAST GENERATION GP, INC.)

TROY ENERGY, LLC

WHARTON COUNTY GENERATION, LLC

WISE COUNTY POWER COMPANY, LLC

WISE-FUELS PIPELINE, INC.

By: /s/ Clint C. Freeland
Name: Clint C. Freeland
Title: Executive Vice President and Chief Financial Officer

[Signature Page to the Second Supplemental Indenture (2025 Notes)]



Americas 92260805 v6

Exhibit 4.36

[SIGNATURE PAGES CONTINUE]

[Signature Page to the Second Supplemental Indenture (2025 Notes)]



Americas 92260805 v6

Exhibit 4.36

WILMINGTON TRUST, NATIONAL ASSOCIATION,

as Trustee

By: /s/ Shawn Goffinet

Name: Shawn Goffinet
Title: Assistant Vice President

[Signature Page to the Second Supplemental Indenture (2025 Notes)]



Americas 92260805 v6

Exhibit 4.36

SCHEDULE I

SUBSIDIARY GUARANTEES

ANP BELLINGHAM ENERGY COMPANY, LLC

ANP BLACKSTONE ENERGY COMPANY, LLC

ANP ERCOT ACQUISITION, LLC

ANP FUEL SERVICES, INC.

ANP FUNDING I, LLC

ARMSTRONG POWER, LLC

ATLAS ADMINISTRATIVE SERVICES, LLC

ATLAS FINANCE MERGECO, LLC

ATLAS I MARKETING AND TRADE, LLC

ATLAS POWER FINANCE, LLC

ATLAS POWER, LLC

CALUMET ENERGY TEAM, LLC

COLETO CREEK POWER LP

COLETO GP, LLC

COLETO LP, LLC

DYNEGY ATLAS HOLDINGS, LLC

ENNIS POWER COMPANY, LLC

DYNEGY GENERATION NA, INC. (F/K/A GDF SUEZ ENERGY GENERATION NA, INC.)

DYNEGY ENERGY GENERATION NA, LLC (F/K/A GDF SUEZ ENERGY GENERATION NA, LLC)

DYNEGY NORTH AMERICA, INC. (F/K/A GDF SUEZ ENERGY NORTH AMERICA, INC.)

HAYS ENERGY, LLC

HOPEWELL COGENERATION LIMITED PARTNERSHIP

HOPEWELL COGENERATION, LLC

DYNEGY POWER AMERICA, INC. (F/K/A INTERNATIONAL POWER AMERICA, INC.)

DP GENERATION, LLC (F/K/A IPA APT GENERATION, LLC)

DP CENTRAL, LLC (F/K/A IPA CENTRAL, LLC)

DP HOLDING, INC. (F/K/A IPA HOLDING, INC.)

DP OPERATIONS, INC. (F/K/A IPA OPERATIONS, INC.)

MIDLOTHIAN ENERGY, LLC

MILFORD POWER, LLC

NEPCO SERVICES COMPANY

NORTHEASTERN POWER COMPANY

PLEASANTS ENERGY, LLC

PRINCE GEORGE ENERGY COMPANY, LLC

T-FUELS, LLC

TNA MERCHANT PROJECTS, INC.

DYNEGY ASSOCIATES NORTHEAST LP, INC. (F/K/A TRACTEBEL ASSOCIATES NORTHEAST LP, INC.)

DYNEGY NORTHEAST GENERATION GP, INC. (F/K/A TRACTEBEL NORTHEAST GENERATION GP, INC.)

TROY ENERGY, LLC

WHARTON COUNTY GENERATION, LLC

WISE COUNTY POWER COMPANY, LLC

WISE-FUELS PIPELINE, INC.



Americas 92260805 v6

Exhibit 4.41

EXECUTION VERSION

FIRST SUPPLEMENTAL INDENTURE

SUBSIDIARY GUARANTEES

FIRST SUPPLEMENTAL INDENTURE (this “ Supplemental Indenture ”), dated as of February 7, 2017, among the Subsidiary Guarantors listed on Schedule I (the “ Guaranteeing Subsidiaries ”), each a wholly-owned domestic subsidiary of Dynegy Inc. (or its permitted successor), a Delaware corporation (the “ Company ”), the Company, the other Subsidiary Guarantors (as defined in the Indenture referred to herein) and Wilmington Trust, National Association, as trustee under the Indenture referred to herein (the “ Trustee ”).

W I T N E S S E T H

WHEREAS, the Company has heretofore executed and delivered to the Trustee an indenture (the “ Indenture ”), dated as of February 2, 2017, among the Company, the Subsidiary Guarantors named therein and the Trustee, providing for the original issuance of an aggregate principal amount of $181,685,509 of 8.034% Senior Notes due 2024 (the “ Initial Notes ”), and, subject to the terms of the Indenture, future unlimited issuances of 8.034% Senior Notes due 2024 (the “ Additional Notes ” and, together with the Initial Notes, the “ Notes ”);

1. Capitalized Terms . Unless otherwise defined in this Supplemental Indenture, capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

3. NEW YORK LAW TO GOVERN . THE INDENTURE, THE NOTES AND THE SUBSIDIARY GUARANTEES SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK.

4. Counterparts . The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.



Americas 92491485 v3

Exhibit 4.41

5 . Effect of Headings . The Section headings herein are for convenience only and shall not affect the construction hereof.

[ Signature Page Follows ]



Americas 92491485 v3

Exhibit 4.41

IN WITNESS WHEREOF, we have hereunto signed our names as of the date set forth below.

Dated: February 7, 2017

DYNEGY INC.

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer



	BLACK MOUNTAIN COGEN, INC. BLUE RIDGE GENERATION LLC CASCO BAY ENERGY COMPANY, LLC DIGHTON POWER, LLC DYNEGY ADMINISTRATIVE SERVICES COMPANY DYNEGY COAL GENERATION, LLC DYNEGY COAL HOLDCO, LLC DYNEGY COAL INVESTMENTS HOLDINGS, LLC DYNEGY COAL TRADING & TRANSPORTATION, L.L.C. DYNEGY COMMERCIAL ASSET MANAGEMENT, LLC DYNEGY CONESVILLE, LLC DYNEGY DICKS CREEK, LLC DYNEGY ENERGY SERVICES (EAST), LLC DYNEGY ENERGY SERVICES, LLC DYNEGY EQUIPMENT, LLC DYNEGY FAYETTE II, LLC DYNEGY GAS GENERATION, LLC DYNEGY GAS HOLDCO, LLC DYNEGY GAS IMPORTS, LLC DYNEGY GAS INVESTMENTS HOLDINGS, LLC DYNEGY GAS INVESTMENTS, LLC DYNEGY GASCO HOLDINGS, LLC DYNEGY GENERATION HOLDCO, LLC DYNEGY GLOBAL LIQUIDS, INC. DYNEGY HANGING ROCK II, LLC DYNEGY KENDALL ENERGY, LLC DYNEGY KILLEN, LLC DYNEGY LEE II, LLC DYNEGY MARKETING AND TRADE, LLC DYNEGY MIAMI FORT, LLC DYNEGY MIDWEST GENERATION, LLC DYNEGY MORRO BAY, LLC DYNEGY MOSS LANDING, LLC DYNEGY OAKLAND, LLC DYNEGY OPERATING COMPANY DYNEGY POWER GENERATION INC. DYNEGY POWER MARKETING, LLC DYNEGY POWER, LLC

[Signature Page to the First Supplemental Indenture (8.034% 2024 Notes)]



Americas 92491485 v3

Exhibit 4.41



DYNEGY RESOURCE HOLDINGS, LLC DYNEGY RESOURCE I, LLC DYNEGY RESOURCE II, LLC DYNEGY RESOURCE III, LLC DYNEGY RESOURCES GENERATING HOLDCO, LLC DYNEGY RESOURCES HOLDCO I, LLC DYNEGY RESOURCES HOLDCO II, LLC DYNEGY RESOURCES MANAGEMENT, LLC DYNEGY SOUTH BAY, LLC DYNEGY STUART, LLC DYNEGY WASHINGTON II, LLC DYNEGY ZIMMER, LLC ELWOOD ENERGY HOLDINGS II, LLC ELWOOD ENERGY HOLDINGS, LLC ELWOOD EXPANSION HOLDINGS, LLC EQUIPOWER RESOURCES CORP. HAVANA DOCK ENTERPRISES, LLC ILLINOVA CORPORATION KINCAID ENERGY SERVICES COMPANY, LLC KINCAID GENERATION, L.L.C. KINCAID HOLDINGS, LLC LAKE ROAD GENERATING COMPANY, LLC LIBERTY ELECTRIC POWER, LLC MASSPOWER HOLDCO, LLC MASSPOWER PARTNERS I, LLC MASSPOWER PARTNERS II, LLC MILFORD POWER COMPANY, LLC ONTELAUNEE POWER OPERATING COMPANY, LLC RICHLAND GENERATION EXPANSION, LLC RICHLAND-STRYKER GENERATION LLC RSG POWER, LLC SITHE ENERGIES, INC. SITHE/INDEPENDENCE LLC TOMCAT POWER, LLC

COFFEEN AND WESTERN RAILROAD COMPANY

ILLINOIS POWER FUELS AND SERVICES COMPANY

ILLINOIS POWER GENERATING COMPANY

ILLINOIS POWER MARKETING COMPANY

ILLINOIS POWER RESOURCES GENERATING, LLC

ILLINOIS POWER RESOURCES, LLC

IPH II, LLC

IPH, LLC

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the First Supplemental Indenture (8.034% 2024 Notes)]



Americas 92491485 v3

Exhibit 4.41

MASSPOWER , a Massachusetts general partnership

By: Masspower Partner II, LLC, its Managing Partner

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the First Supplemental Indenture (8.034% 2024 Notes)]



Americas 92491485 v3

Exhibit 4.41

MASSPOWER , a Massachusetts general partnership

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the First Supplemental Indenture (8.034% 2024 Notes)]



Americas 92491485 v3

Exhibit 4.41

SUBSIDIARY GUARANTORS:

ANP BELLINGHAM ENERGY COMPANY, LLC

ANP BLACKSTONE ENERGY COMPANY, LLC

ANP ERCOT ACQUISITION, LLC

ANP FUEL SERVICES, INC.

ANP FUNDING I, LLC

ARMSTRONG POWER, LLC

ATLAS ADMINISTRATIVE SERVICES, LLC

ATLAS FINANCE MERGECO, LLC

ATLAS I MARKETING AND TRADE, LLC

ATLAS POWER FINANCE, LLC

ATLAS POWER, LLC

CALUMET ENERGY TEAM, LLC

COLETO CREEK POWER LP

COLETO GP, LLC

COLETO LP, LLC

DYNEGY ATLAS HOLDINGS, LLC

ENNIS POWER COMPANY, LLC

DYNEGY GENERATION NA, INC. (F/K/A GDF SUEZ ENERGY GENERATION NA, INC.)

DYNEGY ENERGY GENERATION NA, LLC (F/K/A GDF SUEZ ENERGY GENERATION NA, LLC)

DYNEGY NORTH AMERICA, INC. (F/K/A GDF SUEZ ENERGY NORTH AMERICA, INC.)

HAYS ENERGY, LLC

HOPEWELL COGENERATION LIMITED PARTNERSHIP

HOPEWELL COGENERATION, LLC

DYNEGY POWER AMERICA, INC. (F/K/A INTERNATIONAL POWER AMERICA, INC.)

DP GENERATION, LLC (F/K/A IPA APT GENERATION, LLC)

DP CENTRAL, LLC (F/K/A IPA CENTRAL, LLC)

DP HOLDING, INC. (F/K/A IPA HOLDING, INC.)

DP OPERATIONS, INC. (F/K/A IPA OPERATIONS, INC.)

MIDLOTHIAN ENERGY, LLC

MILFORD POWER, LLC

NEPCO SERVICES COMPANY

NORTHEASTERN POWER COMPANY

PLEASANTS ENERGY, LLC

PRINCE GEORGE ENERGY COMPANY, LLC

T-FUELS, LLC

TNA MERCHANT PROJECTS, INC.

DYNEGY ASSOCIATES NORTHEAST LP, INC. (F/K/A TRACTEBEL ASSOCIATES NORTHEAST LP, INC.)

DYNEGY NORTHEAST GENERATION GP, INC. (F/K/A TRACTEBEL NORTHEAST GENERATION GP, INC.)

TROY ENERGY, LLC

WHARTON COUNTY GENERATION, LLC

WISE COUNTY POWER COMPANY, LLC

WISE-FUELS PIPELINE, INC.

[Signature Page to the First Supplemental Indenture (8.034% 2024 Notes)]



Americas 92491485 v3

Exhibit 4.41

By: /s/ Clint C. Freeland
Name:     Clint C. Freeland
Title:     Executive Vice President and Chief Financial Officer

[SIGNATURE PAGES CONTINUE]

[Signature Page to the First Supplemental Indenture (8.034% 2024 Notes)]



Americas 92491485 v3

Exhibit 4.41

WILMINGTON TRUST, NATIONAL ASSOCIATION,

as Trustee

By: /s/ Shawn Goffinet

Name: Shawn Goffinet
Title: Assistant Vice President

[Signature Page to the First Supplemental Indenture (8.034% 2024 Notes)]



Americas 92491485 v3

Exhibit 4.41

SCHEDULE I

SUBSIDIARY GUARANTEES

ANP BELLINGHAM ENERGY COMPANY, LLC

ANP BLACKSTONE ENERGY COMPANY, LLC

ANP ERCOT ACQUISITION, LLC

ANP FUEL SERVICES, INC.

ANP FUNDING I, LLC

ARMSTRONG POWER, LLC

ATLAS ADMINISTRATIVE SERVICES, LLC

ATLAS FINANCE MERGECO, LLC

ATLAS I MARKETING AND TRADE, LLC

ATLAS POWER FINANCE, LLC

ATLAS POWER, LLC

CALUMET ENERGY TEAM, LLC

COLETO CREEK POWER LP

COLETO GP, LLC

COLETO LP, LLC

DYNEGY ATLAS HOLDINGS, LLC

ENNIS POWER COMPANY, LLC

DYNEGY GENERATION NA, INC. (F/K/A GDF SUEZ ENERGY GENERATION NA, INC.)

DYNEGY ENERGY GENERATION NA, LLC (F/K/A GDF SUEZ ENERGY GENERATION NA, LLC)

DYNEGY NORTH AMERICA, INC. (F/K/A GDF SUEZ ENERGY NORTH AMERICA, INC.)

HAYS ENERGY, LLC

HOPEWELL COGENERATION LIMITED PARTNERSHIP

HOPEWELL COGENERATION, LLC

DYNEGY POWER AMERICA, INC. (F/K/A INTERNATIONAL POWER AMERICA, INC.)

DP GENERATION, LLC (F/K/A IPA APT GENERATION, LLC)

DP CENTRAL, LLC (F/K/A IPA CENTRAL, LLC)

DP HOLDING, INC. (F/K/A IPA HOLDING, INC.)

DP OPERATIONS, INC. (F/K/A IPA OPERATIONS, INC.)

MIDLOTHIAN ENERGY, LLC

MILFORD POWER, LLC

NEPCO SERVICES COMPANY

NORTHEASTERN POWER COMPANY

PLEASANTS ENERGY, LLC

PRINCE GEORGE ENERGY COMPANY, LLC

T-FUELS, LLC

TNA MERCHANT PROJECTS, INC.

DYNEGY ASSOCIATES NORTHEAST LP, INC. (F/K/A TRACTEBEL ASSOCIATES NORTHEAST LP, INC.)

DYNEGY NORTHEAST GENERATION GP, INC. (F/K/A TRACTEBEL NORTHEAST GENERATION GP, INC.)

TROY ENERGY, LLC

WHARTON COUNTY GENERATION, LLC

WISE COUNTY POWER COMPANY, LLC

WISE-FUELS PIPELINE, INC.



Americas 92491485 v3

Exhibit 21.1

Significant Subsidiaries of Dynegy Inc

As of December 31, 2016



SUBSIDIARY		STATE OR COUNTRY OF INCORPORATION OR ORGANIZATION
1.	Dynegy Gas Investments, LLC	Delaware
2.	Illinova Corporation	Illinois
3.	Dynegy Resource Holdings, LLC	Delaware
4.	Dynegy Finance IV, Inc. (1)	Delaware
5.	Dynegy Coal Holdco, LLC	Delaware

_______________________________________


(1)	Effective with the closing of Delta Transaction on February 7, 2017 , Dynegy Finance IV, Inc. merged into Dynegy Inc.

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the following Registration Statements:


(1)	Registration Statement (Form S-8 No. 333-211734) pertaining to the 2012 Long Term Incentive Plan of Dynegy Inc.


(2)	Registration Statement (Form S-3 No. 333-199179) of Dynegy Inc.

of our reports dated February 24, 2017 , with respect to the consolidated financial statements of Dynegy Inc. and the effectiveness of internal control over financial reporting of Dynegy Inc., included in this Annual Report (Form 10-K) of Dynegy Inc. for the year ended December 31, 2016 .

/s/ Ernst & Young LLP

Houston, Texas

February 24, 2017

Exhibit 31.1

SECTION 302 CERTIFICATION

I, Robert C. Flexon, certify that:


1.	I have reviewed this report on Form 10-K of Dynegy Inc.;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;


(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):


(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



Date:	February 24, 2017	By:	/s/ R OBERT C . F LEXON
			Robert C. Flexon President and Chief Executive Officer

Exhibit 31.2

SECTION 302 CERTIFICATION

I, Clint C. Freeland, certify that:


1.	I have reviewed this report on Form 10-K of Dynegy Inc.;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;


(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):


(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



Date:	February 24, 2017	By:	/s/ C LINT C. F REELAND
			Clint C. Freeland Executive Vice President and Chief Financial Officer

Exhibit 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350

(ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002)

In connection with the report of Dynegy Inc. (the “Company”) on Form 10-K for the year ended December 31, 2016 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert C. Flexon, President and Chief Executive Officer of the Company, hereby certify as of the date hereof, solely for the purposes of Title 18, Chapter 63, Section 1350 of the United States Code, that to the best of my knowledge:


(1)	the Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, and


(2)	the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company at the dates and for the periods indicated.



Date:	February 24, 2017	By:	/s/ ROBERT C. FLEXON
			Robert C. Flexon President and Chief Executive Officer

Exhibit 32.2

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350

(ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002)

In connection with the report of Dynegy Inc. (the “Company”) on Form 10-K for the year ended December 31, 2016 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Clint C. Freeland, Executive Vice President and Chief Financial Officer of the Company, hereby certify as of the date hereof, solely for the purposes of Title 18, Chapter 63, Section 1350 of the United States Code, that to the best of my knowledge:


(1)	the Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, and


(2)	the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company at the dates and for the periods indicated.



Date:	February 24, 2017	By:	/s/ C LINT C. F REELAND
			Clint C. Freeland Executive Vice President and Chief Financial Officer