10-K 1 dyn-20161231_10k.htm 10-K Document

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



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.

 



DYNEGY INC.
FORM 10-K
TABLE OF CONTENTS
 
Page
PART I
 
 
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
PART II
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
PART III
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
PART IV
Item 15.
 
 
 











ii


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

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Item 1.    Business
THE COMPANY
Dynegy began operations in 1984 and became incorporated in the State of Delaware in 2007. We are a holding company and conduct substantially all of our business operations through our subsidiaries. Our primary business is the production and sale of electric energy, capacity and ancillary services from our fleet of 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.
companymapa01.jpg
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.

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The two charts below show our net generation capacity as of February 7, 2017, and include our recent Delta Transaction.
gencapbysegmenta09.jpggencapbyfueltypea04.jpg


The charts below include our 2016 wholesale generation, retail load, and Adjusted EBITDA contribution by fuel type (does not include our recent Delta Transaction).    
wholesalegenbysega05.jpgwholesalegenbyfueltypea02.jpgrtlloada03.jpgaebitdabyfueltype2a01.jpg

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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.

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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

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

5


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

6


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.
pride5a01.jpg
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.

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    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.
stepchart2a04.jpg
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
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

8


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.

9


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.
electricitymapupdatedyellowm.jpg
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/

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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

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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.

12


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.

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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


14


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 (“SO2”) emissions and in some regions nitrogen oxide (“NOx”) 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-NOx 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 NOx and mercury emissions.
Multi-Pollutant Air Emission Initiatives
Cross-State Air Pollution Rule. The “Cross-State Air Pollution Rule” (“CSAPR”) to reduce emissions of SO2 and NOx from EGUs across the eastern U.S. took effect in 2015. The CSAPR imposes cap-and-trade programs within each affected state that limit emissions of SO2 and NOx 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 NOx from May 1 through September 30 and for annual emissions of SO2 and NOx. The CSAPR requirements applicable to SO2 emissions from our affected EGUs will be implemented in two stages with fewer SO2 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 NOx, SO2 and mercury emissions limits. We are in compliance with the MPS.
IPH Variance. The MPS SO2 limits started in 2010 for our IPH coal-fired facilities and would have declined in 2014 and 2015 and required compliance with the final SO2 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

15


FGD systems at the Newton facility such that the IPH coal-fired fleet can meet the MPS system-wide SO2 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, SO2 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 SO2 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 SO2 emission rate that, in conjunction with reductions to be imposed by the state on other sources, will enable the IEPA to demonstrate attainment with the one-hour SO2 NAAQS in the Edwards area. The IPCB subsequently approved an IEPA rule that included the emission limits on Edwards as agreed to in the MOA.
The EPA will complete area designations for the 2010 one-hour SO2 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 NOx 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 SO2 NAAQS, ozone NAAQS and SSM SIP rule cannot be predicted with confidence at this time. A future requirement for additional emission reductions at any of our coal-fired generating facilities may result in significantly increased compliance costs and could have a material adverse effect on our financial condition, results of operations and cash flows.
New Source Review and Clean Air Act Matters
New Source Review. Since 1999, the EPA has been engaged in a nationwide enforcement initiative to determine whether coal-fired power plants failed to comply with the requirements of the New Source Review and New Source Performance Standard provisions under the CAA when the plants implemented modifications. The EPA’s initiative focuses on whether projects performed at power plants triggered various permitting requirements, including the need to install pollution control equipment.
In August 2012, the EPA issued a Notice of Violation (“NOV”) alleging that projects performed in 1997, 2006 and 2007 at the Newton facility violated Prevention of Significant Deterioration (“PSD”), Title V permitting and other requirements. The NOV remains unresolved. We believe our defenses to the allegations described in the NOV are meritorious. A decision by the U.S. Court of Appeals for the Seventh Circuit in 2013 held that similar claims older than five years were barred by the statute of limitations. This decision may provide an additional defense to the allegations in the Newton facility NOV.
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.
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

16


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 SO2 emission limit of 0.04 lbs/MMBtu by February 2021, based on installation of a scrubber. Coleto Creek, other electricity generating companies and the State of Texas filed petitions for judicial review, 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 SO2 on numerous EGUs, including Coleto Creek. BART requirements for EGUs were not addressed in the EPA’s December 2015 regional haze FIP for Texas. The proposed FIP BART SO2 emissions limit for Coleto Creek is 0.04 lbs/MMBtu based on installation of a scrubber. Compliance would be required within five years from the effective date of a final rule.
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.

17


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.

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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.

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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 (“CO2” and equivalent carbon dioxide “CO2e”) and methane. Power generating facilities are a major source of GHG emissions. In 2016, our facilities emitted approximately 71 million tons of CO2. The amounts of CO2 emitted from our facilities during any time period will depend upon their dispatch rates during the period. We believe that the focus of any federal program attempting to address climate change should include three critical, interrelated elements: (i) the environment, (ii) the economy and (iii) energy security.
Federal Regulation of GHGs.  The EPA has issued several rules concerning GHGs as directly relevant to our facilities since the U.S. Supreme Court’s 2007 decision in Massachusetts v. EPA, which held that GHGs meet the definition of a pollutant under the CAA and that regulation of GHG emissions is authorized by the CAA. We have implemented processes and procedures to report our GHG emissions. 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 CO2e 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, CO2 emissions from EGUs will be 32 percent below 2005 levels.  States are required to develop plans to achieve interim CO2 emission rates reductions phased in over the period 2022 to 2029 and the final CO2 rate for their state by 2030.  The state-specific CO2 emission performance rates reflect the EPA’s determination that the best system of emission reduction is comprised of three building blocks: increasing the operational efficiency of existing coal-fired EGUs, shifting electricity generation to natural gas-fired EGUs, and increasing electricity generation from renewable sources. Emission trading programs are permitted.
Numerous states, industry associations and labor groups filed lawsuits challenging the 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.

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The nature and scope of CO2 emission reduction requirements that ultimately may be imposed on our facilities as a result of the EPA’s EGU CO2 reduction rules are uncertain at this time, but may result in significantly increased compliance costs and could have a material adverse effect on our financial condition, results of operations and cash flows. 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 CO2 emissions from power plants. The participating RGGI states implemented a cap-and-trade program. Compliance with RGGI can be achieved by reducing emissions, purchasing or trading allowances, or securing offset allowances from an approved offset project. We are required to hold allowances equal to at least 50 percent of emissions in each of the first two years of the three-year control period. In 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 CO2 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

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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.

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Item 1A.    Risk Factors
FORWARD-LOOKING STATEMENTS
This Form 10-K includes statements reflecting assumptions, expectations, projections, intentions or beliefs about future events that are intended as “forward-looking statements.” All statements included or incorporated by reference in this annual report, other than statements of historical fact, that address activities, events, or developments that we expect, believe, or anticipate will or may occur in the future are forward-looking statements. These statements represent our reasonable judgment of the future based on various factors and using numerous assumptions and are subject to known and unknown risks, uncertainties, and other factors that could cause our actual results and financial position to differ materially from those contemplated by the statements. You can identify these statements by the fact that they do not relate strictly to historical or current facts. They use words such as “anticipate,” “estimate,” “project,” “forecast,” “plan,” “may,” “will,” “should,” “expect,” and other words of similar meaning. In particular, these include, but are not limited to, statements relating to the following:
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.

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

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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.

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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 CO2 and methane. As discussed in Item 1. Business-Environmental Matters, at the federal and state levels, rules are in effect and policies are under development to regulate GHG emissions, thereby effectively putting a cost on such emissions in order to create financial incentives to reduce them. Power generating facilities are a major source of GHG emissions. We cannot confidently predict the final outcome of the current debate on climate change nor can we predict with confidence the ultimate requirements of proposed, anticipated or existing federal and state legislation and regulations

26


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.

27


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

28


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;

29


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.

30


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.

31


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.

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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.

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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.

34


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.
totalreturnchart2016.jpg
 
 
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.

35


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)
 
 
 
 
 
 
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



36


 
 
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.

37


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;

38


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.

39


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


40


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

__________________________________________
(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.

41


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

__________________________________________
(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.

42


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