10-K 1 dyn-20151231_10k.htm 10-K 10-K
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, 2015
 
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 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. x
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, 2015, the aggregate market value of the Dynegy Inc. common stock held by non-affiliates of the registrant was $3,478,775,830 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, 116,903,586 shares outstanding as of February 8, 2016.

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 2016 Annual Meeting of Stockholders, which the registrant intends to file no later than 120 days after December 31, 2015. 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
CT
 
Combustion Turbine
CPUC
 
California Public Utility Commission
DNE
 
Dynegy Northeast Generation, Inc.
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
HAPs
 
Hazardous Air Pollutants, as defined by the Clean Air Act
ICR
 
Installed Capacity Requirement
IMA
 
In Market 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
MW
 
Megawatts
MWh
 
Megawatt Hour
NERC
 
North American Electric Reliability Corporation
NM
 
Not Meaningful
NYISO
 
New York Independent System Operator
NYMEX
 
New York Mercantile Exchange
NYSE
 
New York Stock Exchange
OTC
 
Over-The-Counter
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
RMR
 
Reliability Must Run
RPM
 
Reliability Pricing Model
RTO
 
Regional Transmission Organization
S&P
 
Standard & Poor’s Ratings Services
SEC
 
U.S. Securities and Exchange Commission
VaR
 
Value at Risk

1


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 35 power plants in eight states totaling approximately 26,000 MW of generating capacity.
We operate a portfolio of generation assets that is diversified in terms of dispatch profile, fuel type and geography. Our Coal and IPH segments are fleets of baseload coal facilities, located in the Midwest and Massachusetts. Our Gas segment operates both intermediate and peaking natural gas plants, located in the Midwest, Northeast and California. The inherent cycling and dispatch characteristics of our intermediate combined cycle units allow us to take advantage of the volatility in market pricing in the day-ahead and hourly markets. This flexibility allows us to optimize our assets and provide incremental value. Peaking facilities are generally dispatched to serve load only during the highest periods of power demand, such as hot summer and cold winter days, or for local reliability needs. In addition to generating power, our generating facilities also receive capacity revenues through structured markets or bilateral tolling agreements, as local utilities and ISOs seek to ensure sufficient generation capacity is available to meet future market demands.
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 931,000 residential customers and approximately 41,000 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.
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.     
IPH and its direct and indirect subsidiaries are 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 Illinois Power Generating Company (“Genco”), have an independent director whose consent is required for certain corporate actions, including material transactions with affiliates. Further, entities within the IPH segment present themselves to the public as separate entities.  They maintain separate books, records and bank accounts and separately appoint officers.  Furthermore, they pay liabilities from their own funds, conduct business in their own names and have restrictions on pledging their assets for the benefit of certain other persons. 
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.

2


Our Power Generation Portfolio
Our generating facilities are as follows:
Facility
 
Total Net
Generating
Capacity
(MW)(1)
 
Primary
Fuel Type
 
Dispatch
Type
 
Location
 
Region
Baldwin
 
1,815

 
Coal
 
Baseload
 
Baldwin, IL
 
MISO
Havana
 
434

 
Coal
 
Baseload
 
Havana, IL
 
MISO
Hennepin
 
294

 
Coal
 
Baseload
 
Hennepin, IL
 
MISO
Wood River (2)
 
465

 
Coal
 
Baseload
 
Alton, IL
 
MISO
Conesville (3)(4)
 
312

 
Coal
 
Baseload
 
Conesville, OH
 
PJM
Killen (3)(4)
 
204

 
Coal
 
Baseload
 
Manchester, OH
 
PJM
Kincaid
 
1,108

 
Coal
 
Baseload
 
Kincaid, IL
 
PJM
Miami Fort (3)
 
653

 
Coal
 
Baseload
 
North Bend, OH
 
PJM
Miami Fort CT
 
75

 
Oil
 
Peaking
 
North Bend, OH
 
PJM
Stuart (3)(4)
 
904

 
Coal
 
Baseload
 
Aberdeen, OH
 
PJM
Zimmer (3)
 
628

 
Coal
 
Baseload
 
Moscow, OH
 
PJM
Brayton Point (5)
 
1,528

 
Coal
 
Baseload
 
Somerset, MA
 
ISO-NE
   Total Coal Segment
 
8,420

 
 
 
 
 
 
 
 
Coffeen
 
915

 
Coal
 
Baseload
 
Coffeen, IL
 
MISO
Joppa/EEI (3)
 
802

 
Coal
 
Baseload
 
Joppa, IL
 
MISO
Joppa CT Units 1-3
 
165

 
Gas
 
Peaking
 
Joppa, IL
 
MISO
Joppa CT Units 4-5 (3)
 
56

 
Gas
 
Peaking
 
Joppa, IL
 
MISO
Newton
 
1,230

 
Coal
 
Baseload
 
Newton, IL
 
MISO
Duck Creek
 
425

 
Coal
 
Baseload
 
Canton, IL
 
MISO
E.D. Edwards (6)
 
585

 
Coal
 
Baseload
 
Bartonville, IL
 
MISO
  Total IPH Segment (7)
 
4,178

 
 
 
 
 
 
 
 
Moss Landing Units 1-2
 
1,020

 
Gas
 
Intermediate
 
Moss Landing, CA
 
CAISO
                        Units 6-7
 
1,509

 
Gas
 
Peaking
 
Moss Landing, CA
 
CAISO
Oakland
 
165

 
Oil
 
Peaking
 
Oakland, CA
 
CAISO
Dicks Creek
 
143

 
Gas
 
Peaking
 
Monroe, OH
 
PJM
Elwood (3)
 
788

 
Gas
 
Peaking
 
Elwood, IL
 
PJM
Fayette
 
696

 
Gas
 
Intermediate
 
Masontown, PA
 
PJM
Hanging Rock
 
1,439

 
Gas
 
Intermediate
 
Ironton, OH
 
PJM
Kendall
 
1,236

 
Gas
 
Intermediate
 
Minooka, IL
 
PJM
Lee
 
757

 
Gas
 
Peaking
 
Dixon, IL
 
PJM
Liberty
 
598

 
Gas
 
Intermediate
 
Eddystone, PA
 
PJM
Ontelaunee
 
567

 
Gas
 
Intermediate
 
Reading, PA
 
PJM
Richland
 
418

 
Gas
 
Peaking
 
Defiance, OH
 
PJM
Stryker
 
17

 
Oil
 
Peaking
 
Stryker, OH
 
PJM
Washington
 
678

 
Gas
 
Intermediate
 
Beverly, OH
 
PJM
Casco Bay
 
538

 
Gas
 
Intermediate
 
Veazie, ME
 
ISO-NE
Dighton
 
185

 
Gas
 
Intermediate
 
Dighton, MA
 
ISO-NE
Lake Road
 
857

 
Gas
 
Intermediate
 
Dayville, CT
 
ISO-NE
Masspower
 
280

 
Gas
 
Intermediate
 
Indian Orchard, MA
 
ISO-NE
Milford
 
569

 
Gas
 
Intermediate
 
Milford, CT
 
ISO-NE
Independence
 
1,126

 
Gas
 
Intermediate
 
Oswego, NY
 
NYISO
  Total Gas Segment
 
13,586

 
 
 
 
 
 
 
 
Total Fleet Capacity
 
26,184

 
 
 
 
 
 
 
 

3


__________________________________________
(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 out of operation.
(2)
On November 5, 2015, we announced plans to retire the final two units of the Wood River Power Station in mid-2016, subject to the approval of MISO. 
(3)
Co-owned with other generation companies.
(4)
Facilities not operated by Dynegy.
(5)
Scheduled to be retired from service in June 2017.
(6)
Reflects the retirement of Edwards Unit 1 on January 1, 2016.
(7)
We have transmission rights into PJM for certain of our IPH plants and, therefore, also 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. Additionally, we seek to capture the intrinsic and extrinsic value of our generation portfolios. 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 to meet this objective.
Our retail marketing efforts focus on offering end-use customers energy products that range from fixed price and full requirements to flexible price and volume structures. Our goal is to deliver value beyond price by leveraging our experience in the energy markets to provide products that help customers make sound energy decisions. Establishing and maintaining strong relationships with retail energy channel partners is another key focus where personal service and transparent communication further build our retail brands as trusted suppliers. Our objective is to maximize the benefit to both Dynegy and our customers.
Dynegy operates in a complex and highly-regulated environment with multiple federal, state and local stakeholders, such as legislators, government agencies, industry groups, consumers and environmental advocates. Dynegy works with these stakeholders to encourage reasonable regulations, constructive market designs and balanced environmental policies. Our regulatory strategy includes a continuous process of advocacy, visibility, education and engagement. The ultimate goal is to find solutions that provide adequate cost recovery and incentivize investment, while providing 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 across all segments to maintain and improve the safety, reliability and efficiency of the fleet. The recent Acquisitions (as discussed below) are consistent with our commitment to operating safe, reliable, cost efficient and environmentally compliant power generation facilities, as these facilities have benefited from ongoing capital investment, preventative maintenance and rigorous inspection programs.
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. We launched “PRIDE Reloaded” in 2013 with a three-year target of

4


$135 million in operating improvements, and $165 million in balance sheet efficiencies, and subsequently accelerated our original three-year target from 2016 to the end of 2015 - a full year ahead of schedule. In 2015, we exceeded our balance sheet target of $73 million by $81 million, and met our earnings before interest, taxes, depreciation and amortization (“EBITDA”) target of $45 million.
On September 29, 2015, Dynegy announced “PRIDE Energized” - the next iteration of the Company’s PRIDE program - targeted to deliver an incremental $250 million in EBITDA and $400 million in balance sheet improvements over the next three years (2016-2018). The benefits of “PRIDE Energized” are in addition to Dynegy’s previously announced $130 million in acquisition synergies. The overall goal of the PRIDE program continues to be improving operating performance, cost structure and balance sheet efficiency to drive incremental cash flow benefits.
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, reducing debt 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 to support our ongoing liquidity needs.
Recent Developments
Acquisitions
On February 25, 2016, we announced the acquisition of certain power generation facilities from International Power, S.A., a wholly owned subsidiary of ENGIE, through a joint venture with Energy Capital Partners (“ECP”), for a purchase price of approximately $3.3 billion. The acquisition includes approximately 8,700 MW located in ERCOT, PJM and ISO-NE. Of the 8,700 MW, approximately 8,000 MW are modern, efficient natural gas facilities with the remaining 700 MW being environmentally compliant coal facilities. We expect the transaction to close in the fourth quarter of 2016 after meeting customary conditions, including regulatory approvals from FERC, the Public Utility Commission of Texas, and the expiration of Hart-Scott-Rodino waiting periods.
The joint venture will be approximately 65 percent owned by a subsidiary of Dynegy and approximately 35 percent by affiliates of ECP, and will be a non-recourse subsidiary of Dynegy. In addition to the joint venture, ECP will also purchase approximately $150 million of Dynegy common stock.    
Energy Capital Partners Purchase Agreements. On April 1, 2015 (the “EquiPower Closing Date”), pursuant to the terms of the stock purchase agreement dated August 21, 2014, as amended (the “ERC Purchase Agreement”), our wholly-owned subsidiary, Dynegy Resource II, LLC (the “ERC Purchaser”) purchased 100 percent of the equity interests in EquiPower Resources Corp. (“ERC”) from certain affiliates of Energy Capital Partners (collectively, the “ERC Sellers”) thereby acquiring (i) five combined cycle natural gas-fired facilities in Connecticut, Massachusetts and Pennsylvania, (ii) a partial interest in one natural gas-fired peaking facility in Illinois, (iii) two gas and oil-fired peaking facilities in Ohio, and (iv) one coal-fired facility in Illinois (the “ERC Acquisition”).
On the EquiPower Closing Date, in a related transaction, pursuant to a stock purchase agreement and plan of merger dated August 21, 2014, as amended (the “Brayton Purchase Agreement” and together with the ERC Purchase Agreement, the “ECP Purchase Agreements”), our wholly-owned subsidiary Dynegy Resource III, LLC (the “Brayton Purchaser” and together with the ERC Purchaser, the “ECP Purchasers”) purchased 100 percent of the equity interests in Brayton Point Holdings, LLC (“Brayton”) from certain affiliates of Energy Capital Partners (collectively, the “Brayton Sellers” and together with the ERC Sellers, the “ECP Sellers”), thereby acquiring a coal-fired facility in Massachusetts (the “Brayton Acquisition”).
The ERC Acquisition and the Brayton Acquisition (collectively, the “EquiPower Acquisition”) added approximately 6,300 MW of generation in Connecticut, Illinois, Massachusetts, Ohio and Pennsylvania for an aggregate base purchase price of approximately $3.35 billion in cash plus approximately $105 million in common stock of Dynegy, subject to certain adjustments. In aggregate, the resulting operations from the two coal-fired facilities acquired from the ECP Sellers are reported within our Coal segment, while related operations from the six natural gas-fired and two gas and oil-fired facilities are reported within our Gas segment. Please read Note 3—Acquisitions for further discussion.

5


Duke Midwest Purchase Agreement. On April 2, 2015 (the “Duke Midwest Closing Date”), pursuant to the terms of the purchase and sale agreement dated August 21, 2014, as amended (the “Duke Midwest Purchase Agreement”), our wholly-owned subsidiary Dynegy Resource I, LLC (“DRI”) purchased 100 percent of the membership interests in Duke Energy Commercial Asset Management, LLC and Duke Energy Retail Sales, LLC, from two affiliates of Duke Energy Corporation (collectively, “Duke Energy”), thereby acquiring approximately 6,200 MW of generation including (i) three combined cycle natural gas-fired facilities located in Ohio and Pennsylvania, (ii) two natural gas-fired peaking facilities located in Ohio and Illinois, (iii) one oil-fired peaking facility located in Ohio, (iv) partial interests in five coal-fired facilities located in Ohio, and (v) a retail energy business for a base purchase price of approximately $2.8 billion in cash (the “Duke Midwest Acquisition”), subject to certain adjustments. We operate two of the five coal-fired facilities, the Miami Fort and Zimmer facilities, with other owners operating the three remaining facilities. The operations from the retail energy business, and the five coal-fired and the one oil-fired facilities, acquired from Duke Energy are reported within our Coal segment, while related operations from the five natural gas-fired facilities are reported within our Gas segment. Please read Note 3—Acquisitions for further discussion.
Share Repurchase Program
On August 3, 2015, our Board of Directors authorized a share repurchase program for up to $250 million, which was initiated in the third quarter of 2015 and completed in the fourth quarter of 2015. The shares were purchased in the open market at prevailing market prices. Please read Note 17—Capital Stock for further discussion.
Wood River Retirement
On November 5, 2015, Dynegy announced that it expects to retire the final two units at the 465-megawatt Wood River Power Station in Alton, Illinois in mid-2016, subject to the approval of MISO.  The decision to retire the Wood River facility was the result of a strategic review performed in the third quarter of 2015, and was primarily attributable to its uneconomic operation stemming from a poorly designed wholesale capacity market.
PJM Capacity Performance
On June 9, 2015, FERC conditionally approved PJM’s proposed Capacity Performance (“CP”) product, and on July 22, 2015, FERC directed PJM to include CP-eligible demand response and energy efficiency products into the transitional auctions. CP was developed by PJM in response to concerns about plant performance and system reliability. CP features increased availability and flexibility requirements, incentives for performance, significant penalties for non-performance and the ability to bid in a risk premium and recover costs previously disallowed by PJM and the independent market monitor. In August and September of 2015, PJM conducted its capacity auctions for its new CP product. Please read Outlook for further discussion.
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 three segments on a consolidated basis: (i) Coal, (ii) IPH and (iii) Gas. Please read Note 23—Segment Information for further information regarding revenues from external customers, operating income (loss) and total assets by segment. 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 baseload 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. The discussion herein reflects capacities at our net ownership interest.
Coal Segment
Our Coal segment is comprised of 11 coal-fired power generation facilities located in Illinois, Massachusetts, and Ohio with a total generating capacity of 8,420 MW. Baldwin, Havana, Hennepin, and Wood River facilities, located in Illinois, operate in MISO with an aggregate net generating capacity of 3,008 MW. Conesville, Killen, Kincaid, Miami Fort, Stuart and Zimmer facilities, located in Illinois and Ohio, operate in PJM with an aggregate net generating capacity of 3,884 MW. Brayton Point facility, located in Massachusetts operates in ISO-NE and has an aggregate net generating capacity of 1,528 MW. Upon the completion of the planned retirements of our Brayton Point and Wood River facilities, our Coal segment will include 6,427 MW of generation capacity, of which 2,543 MW will operate in MISO and 3,884 MW will operate in PJM.
IPH Segment
Our IPH segment is comprised of five coal-fired power generation facilities located in Illinois with a total generating capacity of 4,178 MW, and primarily operates in MISO. Joppa, which is within the Electric Energy, Inc. (“EEI”) control area, is

6


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 into PJM. As of June 1, 2016, our Coffeen, Duck Creek, E.D. Edwards and Newton facilities will have 937 MW, or 22 percent of IPH’s capacity, that is electrically tied into PJM through pseudo-tie arrangements.
Gas Segment
Our Gas segment is comprised of 19 power generation facilities located in California, Illinois, Ohio, Pennsylvania, New York, Massachusetts, Connecticut and Maine, totaling 13,586 MW of electric generating capacity. Our Dicks Creek, Elwood, Fayette, Hanging Rock, Kendall, Lee, Liberty, Ontelaunee, Richland, Stryker and Washington facilities, located in Illinois, Ohio and Pennsylvania, operate in PJM with an aggregate net generating capacity of 7,337 MW. Our Casco Bay, Dighton, Lake Road, Masspower and Milford facilities, located in Maine, Massachusetts, and Connecticut, operate in ISO-NE and have an aggregate net generating capacity of 2,429 MW. Our Moss Landing and Oakland facilities, located in California, operate in CAISO with an aggregate net generating capacity of 2,694 MW. Our Independence facility, located in New York, operates in the Rest of State market and has an aggregate net generating capacity of 1,126 MW.
NERC Regions, RTOs and ISOs
  In discussing our business, we often refer to NERC regions. The NERC and its regional reliability entities were formed to ensure the reliability and security of the electricity system. The regional reliability entities set standards for reliable operation and maintenance of power generation facilities and transmission systems. For example, each NERC region establishes a minimum operating reserve requirement to ensure there is sufficient generating capacity to meet expected demand within its region. Each NERC region reports seasonally and annually on the status of generation and transmission in such region.
Separately, RTOs and ISOs administer the transmission infrastructure and markets across a regional footprint in most of the markets in which we operate. They are responsible for dispatching all generation facilities in their respective footprints and are responsible for both maximum utilization and reliable and efficient operation of the transmission system. RTOs and ISOs administer energy and ancillary service markets in the short term, usually day-ahead and real-time markets. Several RTOs and ISOs also ensure long-term planning reserves through monthly, semi-annual, annual and multi-year capacity markets. The RTOs and ISOs that oversee most of the wholesale power markets in which we operate currently impose, and will likely continue to impose, bid and price limits or other similar mechanisms. NERC regions and RTOs/ISOs often have different geographic footprints, and while there may be geographic overlap between NERC regions and RTOs/ISOs, their respective roles and responsibilities do not generally overlap.
In RTO and ISO regions with centrally dispatched market structures, all generators selling into the centralized market receive the same price for energy sold based on the bid price associated with the production of the last MWh that is needed to balance supply with demand within a designated zone or at a given location. Different zones or locations within the same RTO/ISO may produce different prices respective to other zones within the same RTO/ISO due to transmission losses and congestion. For example, a less efficient and/or less economical natural gas-fired unit may be needed in some hours to meet demand. If this unit’s production is required to meet demand on the margin, its bid price will set the market clearing price that will be paid for all dispatched generation in the same zone or location (although the price paid at other zones or locations may vary because of transmission losses and congestion), regardless of the price that any other unit may have offered into the market. In RTO and ISO regions with centrally dispatched market structures and location-based marginal price clearing structures (e.g. PJM, NYISO, MISO, CAISO and ISO-NE), 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.
MISO.  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 an LMP system which calculates a price for every generator and load point within MISO. 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. 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.
The MISO’s tariff provisions provide for a full planning year capacity product (June 1 - May 31) and recognize zonal deliverability capacity requirements. We anticipate that the potential retirement of marginal MISO coal capacity due to poor

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economics or expected environmental mandates and confirmed future capacity exports from MISO to PJM will affect MISO capacity and energy pricing for future planning years.
We participate in the MISO’s 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.
In May 2015, three complaints were filed at FERC regarding the Zone 4 results for the 2015-2016 Planning Resource Auction (“PRA”) conducted by MISO. Dynegy is a named party in one of the complaints. The complainants, Public Citizen, Inc., the Illinois Attorney General, and Southwestern Electric Cooperative, Inc., have challenged the results of the PRA as unjust and unreasonable, requested rate relief/refunds and requested changes to the MISO PRA structure going forward. Complainants have also alleged that Dynegy may have engaged in economic or physical withholding in Zone 4 constituting market manipulation in the 2015-2016 PRA. The Independent Market Monitor for MISO (“MISO IMM”), which was responsible for monitoring the MISO 2015-2016 PRA, determined that all offers were competitive and that no physical or economic withholding occurred.  The MISO IMM also stated, in a filing responding to the complaints, that there is no basis for the proposed remedies.  Dynegy complied fully with the terms of the MISO Tariff in connection with the 2015-2016 PRA. In addition, the Illinois Industrial Energy Consumers filed a complaint at FERC against MISO on June 30, 2015 requesting prospective changes to the MISO tariff.
On October 1, 2015, FERC issued an order of non-public, formal investigation, stating that shortly after the conclusion of the 2015-2016 PRA, FERC’s Office of Enforcement began a non-public informal investigation into whether market manipulation or other potential violations of FERC orders, rules and regulations occurred before or during the PRA. The Order noted that the investigation is ongoing, and that the order converting the informal, non-public investigation to a formal, non-public investigation does not indicate that FERC has determined that any entity has engaged in market manipulation or otherwise violated any FERC order, rule, or regulation. Further, FERC held a Staff-led technical conference on October 20, 2015 to obtain further information concerning potential changes to the MISO PRA structure going forward, including proposals made by complainants. The technical conference did not address the ongoing Office of Enforcement investigation.
On December 31, 2015, FERC issued an order on the complaints requiring a number of prospective changes to the MISO Tariff provisions associated with calculating Initial Reference Levels and Local Clearing Requirements, effective as of the 2016-2017 PRA. Under the order, FERC found that the existing tariff provision which bases Initial Reference Levels for capacity supply offers on the estimated opportunity cost of exporting capacity to a neighboring region (for example, PJM) are no longer just and reasonable. Accordingly, FERC required MISO to set the Initial Reference Level for capacity at $0 per MW-day for the 2016-2017 PRA.  Capacity suppliers may also request a facility-specific reference level from the MISO IMM. The order did not address the other arguments of the complainants regarding the 2015-2016 Auction, and stated that those issues remain under consideration and will be addressed in a future order.
PJM.  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 a similar LMP system as described in MISO above. 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 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 2018-2019, which ends May 31, 2019. We also enter into bilateral capacity transactions. Beginning with Planning year 2016-2017, PJM has started to transition to Capacity Performance 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. An independent market monitor continually monitors PJM markets to ensure a robust, competitive market and to identify any improper behavior by any entity.
PJM, like MISO, dispatches power plants to meet system energy and reliability needs, and settles physical power deliveries at LMPs. This value is determined by an ISO-administered auction process. The ISO-administered LMP energy markets consist of two separate and characteristically distinct settlement time frames, both of which are financially settled. The first is a day-ahead market and the second is a real-time dispatch and balancing market. Prices paid in these LMP energy markets, however, are affected by, among other things, (i) market mitigation measures, which can result in lower prices associated with certain generating units that are mitigated by shifting to a cost curve because they are deemed to have the potential to exercise locational market power, and (ii) the existing $1,000/MWh energy market price caps that are in place.
NYISO.  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

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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 OTC 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.
ISO-NE.  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 included removal of the price floor and implementation of a minimum offer price rule for new resources to prevent buy-side market power. Additionally, a downward sloping demand curve as well as a “performance incentive” mechanism that will penalize underperforming units and reward overperforming units was implemented for FCA-9.
CAISO.  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 system 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. On October 1, 2015, FERC approved CAISO’s request to create a voluntary competitive solicitation process that will replace the existing Capacity Procurement Mechanism (“CPM”) process to meet capacity deficiencies in the market. The CAISO plans to implement the competitive solicitation process by hosting monthly and intra-month voluntary auctions beginning on May 1, 2016. The first annual voluntary auction will take place in the fall of 2016 for 2017 RA capacity compliance period.
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.
MISO.  MISO has a Planning Reserve Margin of 15.2 percent and has forecasted reserve margins of 16.1 percent for Planning Year 2016-2017. MISO has forecasted reserve margins of 16.6 percent for Planning Year 2017-2018, 16.0 percent for Planning Year 2018-2019, 15.2 percent for Planning Year 2019-2020, and 14.7 percent for Planning Year 2020-2021.
PJM.  The Planning Reserve Margin is reviewed by PJM on an annual basis and is 15.6 percent for Planning Years 2016-2017. PJM has forecasted reserve margins based on deliverable capacity of 20.2 percent for Planning Year 2015-2016, 21.1 percent for Planning Year 2016-2017, 19.7 percent for Planning Years 2017-2018 and 19.8 percent for Planning Year 2018-2019.
NYISO.  A Planning Reserve Margin of 17 percent was filed with the FERC for the New York Control Area for the period beginning May 1, 2015 and ending April 30, 2016.  A Planning Reserve Margin of 17.5 percent for the period beginning May 1, 2016 and ending April 30, 2017 was filed with the FERC in January 2016.  The actual amount of installed capacity is approximately 7 percentage points above NYISO’s current Planning Reserve Margin.
ISO-NE.  Similar to PJM, ISO-NE will publish on an annual basis the Planning Reserve Margin, which ISO-NE calls 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. For Planning Year 2016-2017, the ICR is 15.6 percent based on data from the third Annual Reconfiguration Auction (ARA3).  Forecasted margin for Planning Year 2016-2017 is approximately 25.2 percent based on ARA3 data. For Planning Years 2017-2018, 2018-2019 and 2019-2020, the ICRs are 15.1 percent (ARA2), 14.9 percent (ARA1) and 14.4 percent (FCA10), respectively.
CAISO.  The CPUC requires a Planning Reserve Margin of at least 15 percent, and as of the latest summer assessment for the region in May 2015, the forecasted reserve margin was approximately 25.3 percent. 
Contracted Capacity and Energy    
We commercialize our Gas, Coal and IPH 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.

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MISO. Coal has contracted 913 MW of bilateral capacity transactions, while IPH has contracted 460 MW under wholesale agreements and 700 MW through retail sales for Planning Year 2016-2017. Our IPH segment has also sold a portion of its capacity into the PJM market, including 867 MW for Planning Year 2016-2017, 847 MW for Planning Year 2017-2018, and 835 MW for Planning Year 2018-2019.
PJM.  Our Kendall facility has one tolling agreement for 85 MW that expires in 2017, and a 95 MW bilateral capacity transaction in Planning Year 2018-2019. Our Elwood facility has two 150 MW tolling agreements which expire in 2017. Our Ontelaunee facility has a five year 200 MW bilateral capacity transaction beginning in 2018.
NYISO.   Due to the short-term, seasonal nature of the NYISO capacity auctions, we monetize the majority of Independence’s capacity through bilateral trades.  We have sold 1,124 MW of capacity for the Winter 2015-2016 planning period; 822 MW for the Summer 2016 planning period; 653 MW for the Winter 2016-2017 planning period; and 705 MW for the Summer 2017 planning period. Independence also supplies thermal energy to a third party through 2021.
ISO-NE.  During the fourth quarter of 2015, Dynegy entered into a three year 75 MW bilateral capacity transaction covering Planning Years 2019-2020, 2020-2021, and 2021-2022. Dynegy also entered into a tolling agreement on its Casco Bay facility for the facility’s full output for the calendar year 2016.
CAISO.  We contracted RA capacity for Moss Landing Units 1 and 2, averaging 63 MW, 650 MW, 400 MW, and 850 MW for calendar years 2016, 2017, 2018, and 2019, respectively.  We have also sold seasonal capacity for Moss Landing Units 1 and 2 opportunistically. Our Moss Landing Units 6 and 7 are contracted under tolling agreements and RA capacity contracts through 2016. Our Oakland facility operated under an RMR contract with the CAISO for 2015 and was given notice of extension for 2016.        
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 will file a market power update with FERC for our Southwest Region (CAISO) assets.
The Dodd-Frank Act. The U.S. Commodity Futures Trading Commission (“CFTC”) has regulatory oversight authority over the trading of electricity and gas commodities, including financial products and derivatives, under the Commodity Exchange Act. On July 21, 2010, President Obama signed the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”). The Dodd-Frank Act increased the CFTC’s regulatory authority on matters related to OTC derivatives, market clearing, position reporting and capital requirements. Dynegy has systems in place in order to monitor our swap activity and comply with Non-Swap Dealer/Major Swap Participant reporting requirements.  We will continue to monitor all relevant developments and rulemakings that could impact our business.
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

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and regulations or with resolution of these judicial and administrative proceedings.  For additional information regarding our pending environmental judicial and administrative proceedings, please read Note 16—Commitments and Contingencies for further discussion.
Our aggregate Coal segment expenditures (both capitalized and those included in operating expense) for compliance with laws and regulations related to the protection of the environment were approximately $72 million in 2015 compared to approximately $30 million in 2014. We estimate that our Coal segment’s total expenditures for environmental compliance in 2016 will be approximately $126 million, with approximately $16 million in capital expenditures and $110 million in operating expenses.
Our aggregate IPH segment expenditures (both capitalized and those included in operating expense) for compliance with laws and regulations related to the protection of the environment were approximately $46 million in 2015 compared to approximately $50 million in 2014. We estimate that our IPH segment’s total expenditures for environmental compliance in 2016 will be approximately $82 million, with approximately $50 million in capital expenditures and $32 million in operating expenses.
Our aggregate Gas segment expenditures for environmental compliance were approximately $9 million in 2015 compared to approximately $5 million in 2014. We estimate that our Gas segment’s total expenditures for environmental compliance in 2016 will be approximately $15 million, with approximately $3 million in capital expenditures and $12 million in operating expenses.
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 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 York and Pennsylvania 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 will begin in 2017.
In July 2015, the U.S. Court of Appeals for the District of Columbia Circuit remanded to the EPA for reconsideration certain CSAPR emissions budgets for select states.  The court rejected all other challenges to the CSAPR. In November 2015, the EPA issued a proposed CSAPR update rule to address the court’s remand decision regarding the CSAPR ozone-season NOx emissions budgets and to reduce those budgets beginning in 2017 to attain and maintain compliance with the 2008 ozone NAAQS. Reduced ozone-season NOx allowance allocations generally will require affected facilities to reduce NOx emissions or acquire additional allowances. While the cost of our compliance with the proposed CSAPR update rule is uncertain at this time, the rule is anticipated to increase the compliance costs of our coal-fired EGUs in Illinois and Ohio.
Based on our current projections of emissions for 2016, we anticipate that our Coal segment facilities will have an adequate number of SO2 and NOx (ozone season and annual) allowances allocated in 2016 under the CSAPR, and that our IPH segment facilities will have an adequate number of SO2 allowances, but will need to acquire a limited number of NOx (ozone season and annual) allowances. We anticipate that our Gas segment facilities will need to acquire a limited number of NOx (ozone season and annual) and SO2 allowances.
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.

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In June 2015, the U.S. Supreme Court found that the EPA failed to properly consider costs when it promulgated the MATS rule. The U.S. Court of Appeals for the District of Columbia Circuit then remanded the MATS rule to the EPA without vacating the rule. In December 2015, the EPA issued a proposed supplemental finding that the consideration of cost does not alter the Agency’s conclusion that it is appropriate and necessary to regulate coal- and oil-fired EGUs under CAA section 112. The EPA anticipates making a final finding regarding costs under the MATS rule by April 2016. We believe the EPA’s reconsideration of the MATS rule costs will have little or no bearing on the power markets, given that the majority of EGU retirement and investment decisions related to the MATS rule have already been made or are in process. Furthermore, EGUs are or will be subject to a number of other environmental regulations that also affect retirement and investment decisions, such as the Coal Combustion Residuals (“CCR”) rule, the CSAPR, the ELG rule and the Clean Power Plan.
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. In accordance with our MISO tariff obligations, we requested a one-year extension of the MATS compliance deadline for Edwards Unit 1, which the Illinois EPA approved in April 2015. We previously had committed to retire Edwards Unit 1 as soon as the MISO allowed, which occurred on January 1, 2016.
The EPA revised the MATS rule in November 2014 to require use of the extensive startup and shutdown monitoring instrumentation. Because installation of such instrumentation by April 2015 was not possible, we filed MATS extension requests regarding the startup and shutdown instrumentation requirements for each of our Illinois and Ohio coal-fired facilities. However, in January 2015, the EPA proposed to correct its November 2014 MATS rule revisions in a manner that, if adopted, would eliminate the need for our startup and shutdown instrumentation extension requests.
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 has granted IPH a variance which provides additional time for economic recovery and related power price improvements necessary to support the installation of flue gas desulfurization (“FGD”) systems at the Newton facility such that the IPH coal-fired fleet can meet the MPS system-wide SO2 limit. The IPCB approved the proposed plan to restrict the SO2 emissions through 2014 to levels lower than those required by the MPS to offset any environmental impact from the variance. The IPCB’s order also included a schedule of milestones for completion of various aspects of the installation of the Newton FGD systems. The first milestone relating to the engineering design was completed in July 2015, while the last milestone relates to major equipment components being placed into final position on or before September 1, 2019. The variance also requires additional environmental protections in the form of enforceable commitments to cap IPH’s SO2 emissions through December 31, 2020, retire Edwards Unit 1 as soon as permitted by the MISO, and, during the variance period, use only low sulfur coal at the Newton, Edwards and Joppa facilities and maintain operation of the existing scrubbers at the Duck Creek and Coffeen facilities to achieve a 98 percent annual average SO2 removal rate. In December 2015, the EPA approved the variance as part of the Illinois regional haze state implementation plan (“SIP”). In February 2016, Genco issued a notice to the third party contractor constructing the FGD systems directing them to temporarily suspend a portion of the work being performed.
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 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 Illinois EPA to demonstrate attainment with the one-hour SO2 NAAQS in the Edwards area. In October 2015, the IPCB approved the Illinois EPA’s proposed rule to meet the SO2 NAAQS, which 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. The round of area designations due by July 2016 includes areas involving our Newton, Hennepin, Joppa and Wood River facilities and our co-owned Zimmer facility. In February 2016, the EPA provided notice of its intent to designate the areas where each of these facilities is located as unclassifiable/attainment.

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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 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”). Affected states are 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, 2015 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 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. If not overturned, 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. We plan to retire our Wood River facility in mid-2016, subject to the approval of MISO.
CAA Notices of Violation. In December 2014, the EPA issued a 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, SO2, sulfuric acid mist and heat input. The NOVs remain unresolved. In December 2014, the EPA also issued NOVs alleging violations of opacity standards at the Stuart and Killen facilities, which we co-own but do not operate.
Edwards CAA Citizen Suit. In 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. The District Court has scheduled the trial date for October 2016. We dispute the allegations and will defend the case vigorously.
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 limited to five years in duration but can be renewed.
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 will be approximately $17 million, with the majority of spend in the 2020-2023 timeframe. This estimate excludes Moss Landing, which is discussed

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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. Compliance with the Policy, as adopted, would be required at our Gas segment’s Moss Landing facility by December 31, 2017.
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 all four units at Moss Landing from December 31, 2017 to December 31, 2020. Under the settlement agreement, we are required to implement 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 for Units 1 and 2 by year end 2016. In addition, we must evaluate and install supplemental control technology at Units 1 and 2 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. Operation of Moss Landing Units 6 and 7 beyond 2020 would be allowed only if those units comply with the Policy’s impingement mortality and entrainment standards.
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 the CCR rule in light of our current management of CCR, including beneficial reuse. At this time, we estimate the cost of our compliance with the ELG rule to be approximately $290 million to $350 million. The majority of ELG compliance expenditures are expected to occur in the 2016-2023 timeframe.
NPDES Permits. We are currently appealing certain requirements in the renewal NPDES permits at several of our facilities, including Baldwin and Joppa.
The operator of the co-owned Stuart facility has appealed various aspects of the Stuart NPDES 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.
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 CCR surface impoundment. At present, CCR is regulated by the states as solid waste.
EPA CCR Rule. 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.
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. Affected facilities are required to notify the state of actions taken to comply with requirements of the rule and to maintain a publicly accessible internet site that will document the facility’s compliance with the rule’s requirements. The rule regulates CCR as a non-hazardous waste under RCRA subtitle D, but defers a final determination on whether regulation of CCR as a hazardous waste is necessary until additional information is available. Several businesses, industry groups and environmental organizations filed petitions for judicial review of the CCR rule.

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At this time, we estimate the cost of our compliance will be approximately $210 million to $260 million with the majority of the expenditures in the 2016-2023 timeframe. This estimate is reflected in our AROs. Pursuant to the CCR rule, we filed notices of intent with the Illinois EPA in November 2015 to close eleven inactive surface impoundments located at our Baldwin, Hennepin, Wood River, Coffeen and Duck Creek facilities.
Illinois CCR Rule. In 2013, the Illinois EPA 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 2015, the IPCB stayed the rulemaking proceeding through early March 2016 to allow consideration of the EPA CCR rule, including the impact of legal and legislative actions concerning that rule.
Coal Segment Groundwater. In 2012, the Illinois EPA issued violation notices alleging violations of groundwater standards onsite at our Baldwin and Vermilion facilities.
At Baldwin, with approval of the Illinois EPA, 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 Illinois EPA 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. We await Illinois EPA action on our proposed action plan and recommendations. Please read “EPA CCR Rule” above for further discussion.
We initiated an investigation at Baldwin in 2011 at the request of the Illinois EPA to determine if the facility’s CCR surface impoundment system impacts offsite groundwater. Results of the offsite groundwater quality investigation, as submitted to the Illinois EPA in 2012, indicate two localized areas where Class I groundwater standards were exceeded. The cause of the exceedances is uncertain.
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 Illinois EPA in 2012. Our hydrogeologic investigation indicates that these two CCR surface impoundments impact groundwater quality onsite and that such groundwater migrates offsite to the north of the property and to the adjacent Middle Fork of the Vermilion River.  The proposed corrective action plans recommend closure in place of both CCR surface impoundments and include an application to the Illinois EPA 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 Illinois EPA action on our proposed corrective action plans. In June 2015, we advised the Illinois EPA that the additional analyses requested by the Agency would be performed upon receipt of a riverbank stabilization permit from the U.S. Army Corps of Engineers. 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 Illinois EPA issued violation notices alleging violations of groundwater standards at the Newton and Coffeen facilities’ CCR surface impoundments. In April 2015, we submitted an assessment monitoring report to the Illinois EPA concerning previously reported groundwater quality standard exceedances at the Newton facility’s active CCR landfill. The report identifies the Newton facility’s inactive unlined landfill as the likely source of the exceedances and recommends various measures to minimize the effects of that source on the groundwater monitoring results of the active landfill.
If remediation measures concerning groundwater are necessary at any of our IPH facilities, we may incur significant costs that could have a material adverse effect on our financial condition, results of operations and cash flows. At this time we cannot reasonably estimate the costs, or range of costs, of remediation, if any, that ultimately may be required.
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

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reflected in our ARO. We performed further studies needed to support closure of the west CCR surface impoundment, submitted those studies to the Illinois EPA in 2014 and await Illinois EPA 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.
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 methane. Power generating facilities are a major source of GHG emissions. In 2015, our Coal, IPH and Gas segment facilities emitted approximately 53 million, 21 million and 24 million tons of Equivalent Carbon Dioxide (“CO2e”), respectively. The amounts of CO2e 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.
Paris Agreement. In December 2015, over 190 countries, including the U.S., reached an agreement (“Paris Agreement”) that establishes a global framework to reduce GHG emissions. The Paris Agreement seeks to keep warming below two degrees Celsius with a goal to limit increases in temperature to 1.5 degrees Celsius. The Paris Agreement directs all countries to prepare and communicate non-binding, nationally determined climate targets every five years starting in 2020.    
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. States must submit final plans by September 6, 2016, unless a state makes certain demonstrations justifying a two-year extension for submittal of a final plan by September 2018.  
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. Judicial challenges also have been filed against the EPA’s final rules establishing carbon standards for new, modified and reconstructed EGUs.
Many states where we operate generation facilities have started efforts aimed at developing plans to implement the Clean Power Plan. We are monitoring and, as appropriate, participating in those state efforts. We also continue to analyze the EPA’s final rules to reduce EGU CO2 emissions, the potential impacts on our power generation facilities, and how the rules intersect with electricity market design.

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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.
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.
Our generating facilities in California emitted approximately 2 million tons of GHGs during 2015. As a result of the tolling agreement for Moss Landing Units 6 and 7 under which GHG allowance costs are passed through to the tolling counterparty, we were required in 2015 to acquire allowances covering the GHG emissions of only Moss Landing Units 1 and 2. The cost of GHG allowances required to operate our units in California during 2015 was approximately $18 million. 
We estimate the cost of GHG allowances required to operate our units in California during 2016 will be approximately $12 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. Due to the tolling agreement for Moss Landing Units 6 and 7, we expect only to acquire allowances covering the GHG emissions of Moss Landing Units 1 and 2.
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 to reduce CO2 emissions by at least 10 percent of 2009 emission levels by 2018. Compliance with RGGI can be achieved by reducing emissions, purchasing or trading allowances, or securing offset allowances from an approved offset project. While RGGI allowances are sold by year, actual compliance is measured across a three-year control period.
Following a program review, the RGGI states implemented a new 2014 CO2 emissions cap, which then declines by 2.5 percent each year from 2015 to 2020. 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.
Our generating facilities in Connecticut, Maine, Massachusetts and New York emitted approximately 10 million tons of CO2 during 2015. The cost of RGGI allowances required to operate these facilities during 2015 was approximately $67 million. We estimate the cost of RGGI allowances required to operate our affected facilities during 2016 will be approximately $81 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.
Remedial Laws
We are subject to environmental requirements relating to handling and disposal of toxic and hazardous materials, including provisions of the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) and RCRA and similar state laws. CERCLA imposes strict liability for contributions to contaminated sites resulting from the release of “hazardous substances” into the environment. CERCLA or RCRA could impose remedial obligations with respect to a variety of our facilities and operations.
A number of our older facilities contain quantities of asbestos-containing materials, lead-based paint and/or other regulated materials. Existing state and federal rules require the proper management and disposal of these materials. We have developed a plan that includes proper maintenance of existing non-friable asbestos installations and removal and abatement of asbestos-containing materials where necessary because of maintenance, repairs, replacement or damage to the asbestos itself.
COMPETITION
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. The power generation business is a regional business that is diverse in terms of industry structure. Our Coal, IPH and Gas power generation businesses compete 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

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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 recent extension of federal renewable energy tax credit programs is expected to further expand renewable energy development.
SIGNIFICANT CUSTOMERS
For the year ended December 31, 2015, approximately 28 percent and 22 percent of our consolidated revenues were derived from transactions with PJM and MISO, respectively. For the year ended December 31, 2014, approximately 33 percent and 14 percent of our consolidated revenues were derived from transactions with MISO and NYISO, respectively. For the year ended December 31, 2013, approximately 36 percent, 19 percent, 16 percent and 15 percent of our consolidated revenues were derived from transactions with MISO, PJM, NYISO and CAISO, respectively. No other customer accounted for more than 10 percent of our consolidated revenues during the years ended December 31, 2015, 2014 and 2013.
EMPLOYEES
At December 31, 2015, we had approximately 321 employees at our corporate headquarters and approximately 2,270 employees at our facilities, including field-based administrative employees. The field-based employees, who operate our facilities, are divided across our three reportable segments, Coal, IPH and Gas, employing approximately 1,116 employees, 549 employees and 397 employees, respectively. In addition, there are approximately 208 field-based administrative employees who are part of our support and retail functions. Approximately 1,330 employees at our operating facilities are subject to collective bargaining agreements with various unions. In 2015, we reached an agreement on new collective bargaining agreements with the three unions representing our IPH facilities. These agreements cover approximately 400 represented employees located in Illinois and expire between 2018 and 2020. During 2015, 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
Please note that any risk, uncertainty or other factor that has a material adverse effect on the financial position, results of operations or cash flows of our IPH segment may not result in a material adverse effect on the financial position, results of operations or cash flows of Dynegy on a consolidated basis due to the relative size of the IPH segment as well as the ring-fenced structuring of IPH and its subsidiaries.  However, you should review the risk factor regarding the IPH ring-fenced structure and the risk that a creditor of IPH, or a bankruptcy trustee if any entity of the IPH segment were to become a debtor in bankruptcy, may nevertheless be successful in subjecting Dynegy to the claims of IPH and its subsidiaries.
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 natural gas 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, MISO, PJM, CAISO, NYISO or ISO-NE power and capacity procurement processes;
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;
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 new performance incentives in ISO-NE;
our ability to optimize our assets through targeted investment in cost effective technology enhancements;
the effectiveness of our strategies to capture opportunities presented by changes in commodity prices and to manage our exposure to energy price volatility;
efforts to secure retail sales and the ability to grow the retail business;
efforts to identify opportunities to reduce congestion and improve busbar power prices;
ability to mitigate impacts associated with expiring RMR and/or capacity contracts;
expectations regarding our compliance with the Credit Agreement, including collateral demands, interest expense, any applicable financial ratios and other payments;
expectations regarding performance standards and capital and maintenance expenditures;
the timing and anticipated benefits to be achieved through our company-wide improvement programs, including our PRIDE initiative;
anticipated timing, outcomes and impacts of the expected retirements of Brayton Point and Wood River;
beliefs about the costs and scope of the ongoing demolition and site remediation efforts at the Vermilion facility and any potential future remediation obligations at the South Bay facility; and

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beliefs regarding redevelopment efforts for the Morro Bay facility.    
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
Because 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 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

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portfolio is not sufficient to meet the requirements of our customers, we must purchase power in the wholesale power markets. Our financial results may be negatively affected if we are unable to manage the power portfolio and cost-effectively meet the requirements of our customers.
A decline in market liquidity and our ability to manage our counterparty credit risk could adversely affect us.
Our supplier 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.
Moreover, profitable operation of many of our coal-fired generation facilities is highly dependent on coal prices and coal transportation rates.  We mitigate our price exposure to coal and related transportation by entering into long-term contracts. Transportation of coal can also be affected by rail equipment availability, extreme weather or natural disasters, each of which may slow or stop the delivery from the mine to the facility. In addition, certain of our coal suppliers have filed for bankruptcy protection, which could negatively impact our coal supply. 
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, significant penalties. 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 results of operations, financial condition and cash flows.
Our costs of compliance with existing environmental requirements are significant, and costs of compliance with new environmental requirements or factors could materially adversely affect our financial condition, results of operations and cash flows.
Our business is subject to extensive and frequently changing environmental regulation by federal, state and local authorities. Such environmental regulation imposes, among other things, capital and operating expenditures, restrictions, liabilities and obligations in connection with the generation, handling, use, transportation, treatment, storage and disposal of certain substances and wastes, including CCR, and in connection with spills, releases and emissions of various substances (including carbon emissions) into the environment, as well as environmental impacts associated with cooling water intake structures. Existing environmental laws and regulations may be revised or reinterpreted, new laws and regulations may be adopted or may become applicable to us or our facilities, and litigation or enforcement proceedings could be commenced against us. Proposals being considered by federal and state authorities (including proposals regarding cooling water intake structures and carbon) could, if and when adopted or

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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 generally.
Regulators, politicians, non-governmental organizations and other private parties have expressed concern about greenhouse gas, or 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 or anticipated federal and state legislation and regulations intended to address climate change. These activities, and the highly politicized nature of climate change, suggest a trend toward increased regulation of GHG that could result in a material adverse effect on our financial condition, results of operations and cash flows. Existing and anticipated federal and state regulations intended to address climate change may significantly increase the cost of providing electric power, resulting in far-reaching and significant impacts on us and others in the power generation industry over time. It is possible that federal and state actions intended to address climate change could result in costs assigned to GHG emissions that we would not be able to fully recover through market pricing or otherwise. If capital and/or operating costs related to compliance with regulations intended to address climate change become great enough to render the operations of certain plants uneconomical, we could, at our option and subject to any applicable financing agreements or other obligations, reduce operations or cease to operate such plants and forego such capital and/or operating costs. Though we consider our largest risk related to climate change to be legislative and regulatory changes, we are subject to physical risks inherent in industrial operations including severe weather events such as hurricanes and tornadoes. To the extent that changes in climate effect changes in weather patterns (such as more severe weather events) or changes in sea level where we have generating facilities, we could be adversely affected.

22


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 the age of certain of our generation facilities, 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. In addition, certain of our current facilities are relatively old. Newer plants owned by competitors may be more efficient than some of our plants, which may put these plants at a competitive disadvantage. Over time, some of our plants may become unable to compete because of subsidized generation, including public utility commission supported PPAs, 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. Taken as a whole, the potential disadvantages of our aging fleet could result in lower run-times or even early asset retirement.
Other factors may contribute to increased competition in wholesale power markets. New forms of capital and competitors have entered the industry, including financial investors who perceive that asset values are at levels below their true replacement value. As a result, a number of generation facilities in the U.S. are now owned by lenders and investment companies. Furthermore, mergers and asset reallocations in the industry could create powerful new competitors. Under any scenario, we anticipate that we will face competition from numerous companies in the industry.
In addition, our retail marketing efforts compete for customers in a competitive environment, which impacts the margins that we can earn on the volumes we are able to serve. Further, with retail competition, residential customers where we serve load can switch to and from competitive electric generation suppliers for their energy needs. If fewer customers switch to another supplier than anticipated, the load we must serve will be greater and, if market prices have increased, our costs will increase due to the need to go to the market to cover the incremental supply obligation. If more customers switch to another supplier than anticipated, the load we must serve will be lower and, if market prices have decreased, we could lose opportunities in the market. To the extent that competition increases, our financial condition, results of operations and cash flows may be materially adversely affected.
Generally, we do not own or control transmission facilities required to sell wholesale power from our generation facilities. If transmission services are inadequate, our ability to sell and deliver wholesale power may be materially adversely affected. Furthermore, RTOs and ISOs administer the transmission infrastructure and market, which are subject to changes in structure and operation and impose various pricing limitations. These changes and pricing limitations may affect our ability to deliver power to the market that would, in turn, adversely affect the profitability of our generation facilities.
With the exception of EEI, which owns and controls transmission lines interconnecting the Joppa facility in EEI’s control area to MISO, Tennessee Valley Authority (“TVA”) and Louisville Gas and Electric Company (“LGE”), 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

23


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 for us.
Our risk management policies cannot fully eliminate the risk associated with our commodity hedging activities.
Our asset-based power position as well as our power marketing, fuel procurement and other commodity hedging activities expose us to risks of commodity price movements. We attempt to manage this exposure through enforcement of established risk limits and risk management procedures. These risk limits and risk management procedures may not work as planned and cannot eliminate all risks associated with these activities. Even when our policies and procedures are followed, and decisions are made based on projections and estimates of future performance, results of operations may be diminished if the judgments and assumptions underlying those decisions prove to be incorrect. Factors, such as future prices and demand for power and other energy-related commodities, become more difficult to predict and the calculations become less reliable the further into the future estimates are made. As a result, we cannot fully predict the impact that our commodity hedging activities and risk management decisions may have on our business and/or financial condition, results of operations and cash flows.
Strikes, work stoppages or an inability to negotiate future collective bargaining agreements on commercially reasonable terms could have a material adverse effect on our financial condition, results of operations and cash flows.    
A majority of the employees at our facilities are subject to collective bargaining agreements with various unions. Additionally, unionization activities, including votes for union certification, could occur at the non-union generating facilities in our fleet. If union employees strike, participate in a work stoppage or slowdown or engage in other forms of labor strike or disruption, we could experience reduced power generation or outages if replacement labor is not procured. The ability to procure such replacement labor is uncertain. Strikes, work stoppages or an inability to negotiate future collective bargaining agreements on commercially reasonable terms could have a material adverse effect on our financial condition, results of operations and cash flows.
The IPH segment’s ring-fencing structure may not work as planned and Dynegy may be subject to the claims of the creditors of IPH and its subsidiaries.
In connection with the 2013 acquisition of New Ameren Energy Resources, LLC (“AER”) and its subsidiaries (the “AER Acquisition”), IPH and its direct and indirect subsidiaries were organized into ring-fenced groups. The entities within the IPH

24


ring-fenced structure maintain corporate separateness from our other current legal entities. This structure was implemented, in part, to minimize the risk that creditors of IPH, or a bankruptcy trustee if any entity of the IPH segment were to become a debtor in a bankruptcy case, would attempt to assert claims against Dynegy for payment of IPH’s obligations. The ring-fenced structure should preclude any corporate veil-piercing or other similar claims of IPH’s creditors but, if any such claims were successful, it could have a material adverse effect on our financial position, results of operations and cash flows.  The ring-fenced structure should also preclude any bankruptcy court from ordering the substantive consolidation of Dynegy’s assets and liabilities with the assets and liabilities of any IPH debtor in bankruptcy.  However, bankruptcy courts have broad equitable powers and, as a result, outcomes in bankruptcy proceedings are inherently difficult to predict. To the extent a bankruptcy court were to determine that substantive consolidation was appropriate under the facts and circumstances, it could have a material adverse effect on our financial position, 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.

25


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, 2015, we had approximately $7.4 billion of total indebtedness and approximately $6.9 billion of indebtedness net of cash. Our debt could have negative consequences for our financial condition including:
increasing our vulnerability to general economic and industry conditions;
requiring a substantial portion of our cash flow from operations to be dedicated to the payment of principal and interest on our indebtedness, therefore reducing our ability to use our cash flow to fund our operations, capital expenditures and future business opportunities;
limiting our ability to enter into long-term power sales or fuel purchases which require credit support;
limiting our ability to fund operations or future acquisitions;
restricting our ability to make certain distributions with respect to our capital stock and the ability of our subsidiaries to make certain distributions to us, in light of restricted payment and other financial covenants in our credit facilities and other financing agreements;
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.

26


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, and slower growth rates in the energy industry, as well as a sustained decrease in the price of our common stock.
We have performed the test for goodwill impairment and concluded that a goodwill impairment loss has not occurred at this time. 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 all facilities in 2015 and determined that no impairment charges were required, other than for our Wood River and Brayton Point facilities. 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 assets of the Coal and Gas segments, including the majority of power generation facilities owned by Dynegy Midwest Generation, LLC (“DMG”) and Dynegy Power, LLC (“DPC”), two of our wholly-owned subsidiaries, are pledged as collateral to secure the repayment of, and our other obligations under, the Credit Agreement. None of the power generation facilities of the IPH segment are pledged as collateral to secure repayment of any of our debt obligations; however, there are certain restrictions on property sales. Please read Note 13—Debt for further discussion.

27


Our principal executive office located in Houston, Texas, is held under a lease that expires in 2022. We also lease additional offices in Illinois and Ohio.
Item 3. Legal Proceedings
Please read Note 16—Commitments and Contingencies—Legal Proceedings for a description of our material legal proceedings, which is incorporated herein by reference.
Item 4.    Mine Safety Disclosures
Not applicable.

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”), which was administered under the Joint Chapter 11 Plan of Reorganization as of the Plan Effective Date (the “Plan”). Based on information provided by our transfer agent, there were 2,542 stockholders of record of our common stock as of February 8, 2016. Also, following the Plan Effective Date we issued 15.6 million five-year warrants to purchase shares of our common stock (the “Warrants”). Each Warrant entitles the holder to a maximum of one share of common stock. The exercise price of each Warrant was set at $40 per warrant. Further, on the Plan Effective Date, approximately 6.1 million shares of our common stock were available for issuance under our 2012 Long Term Incentive Plan.
On October 14, 2014, we issued 22.5 million shares, pursuant to the Common Stock Offering at $31.00 per share. On November 13, 2014, we issued an additional 1.5 million shares, pursuant to the exercise by the underwriters of their 30 day option to purchase up to 3.375 million additional shares of our common stock, at $31.00 per share. 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. On August 3, 2015, our Board of Directors authorized a share repurchase program for up to $250 million, which was initiated in the third quarter of 2015 and completed in the fourth quarter of 2015. As of December 31, 2015, we repurchased 11,326,122 shares at an aggregate cost of $250 million. Please read Note 17—Capital Stock for additional information.     
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
2016:
 
 
 
 
First Quarter (through February 8, 2016)
 
$
13.09

 
$
9.88

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

2014:
 
 
 
 
Fourth Quarter
 
$
34.76

 
$
27.13

Third Quarter
 
$
34.28

 
$
26.55

Second Quarter
 
$
36.14

 
$
24.80

First Quarter
 
$
24.94

 
$
19.57

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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Registration Rights Agreement. Commensurate on the Plan Effective Date, we entered into a registration rights agreement (the “Registration Rights Agreement”) with Franklin Advisers, Inc. At any time prior to the five-year anniversary of the Plan Effective Date, any one or more holders of Registrable Securities, as defined in the Registration Rights Agreement, may request to sell all or any portion of their Registrable Securities in an underwritten offering, subject to certain exceptions provided for in the Registration Rights Agreement. In addition, holders of Registrable Securities may request to sell all or any portion of their Registrable Securities in a non-underwritten offering by providing notice to us no later than two business days (or in certain circumstances five business days) prior to the expected date of such an offering, subject to certain exceptions. Further, when we propose to offer shares in an underwritten 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 registration rights granted in the Registration Rights Agreement are subject to customary indemnification and contribution provisions, as well as customary restrictions such as minimums, blackout periods and, if a registration is for an underwritten offering, limitations on the number of shares to be included in the underwritten offering may be imposed by the managing underwriter. Registrable Securities shall cease to constitute Registrable Securities upon the earliest to occur of: (i) the date on which such securities are disposed of pursuant to an effective registration statement under the Securities Act of 1933, as amended (the “Securities Act”); (ii) the date on which such securities are disposed of pursuant to Rule 144 (or any successor provision) promulgated under the Securities Act; (iii) with respect to the Registrable Securities held by any Holder (as defined in the Registration Rights Agreement), any time that such Holder beneficially owns (as defined in Rule 13d-3 under Securities Exchange Act of 1934, as amended (the “Exchange Act”)) Registrable Securities representing less than one percent of the then outstanding common stock and is permitted to sell such Registrable Securities under Rule 144(b)(1); and (iv) the date on which such securities cease to be outstanding.
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, 2015, 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 “New Peer Group,” is comprised of Calpine Corp., NRG Energy Inc. and Talen Energy Corporation (“Talen Energy”). The peer group for the fiscal year ended December 31, 2014 and prior periods, which we refer to as the “Old Peer Group,” is comprised of Calpine Corp. and NRG Energy Inc.

29


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, 2015.
 
 
October 3, 2012
 
December 31, 2012
 
December 31, 2013
 
December 31, 2014
 
December 31, 2015
Dynegy Inc.
 
$
100.00

 
$
99.12

 
$
111.50

 
$
157.25

 
$
69.43

S&P Midcap 400
 
$
100.00

 
$
104.44

 
$
139.42

 
$
153.04

 
$
149.71

Old Peer Group
 
$
100.00

 
$
102.88

 
$
118.36

 
$
122.99

 
$
67.51

New Peer Group (1)
 
$
100.00

 
$
102.88

 
$
118.36

 
$
122.99

 
$
67.51

__________________________________________
(1)
Talen Energy was added to Dynegy’s peer group for the fiscal year ended December 31, 2015.  However, as it became publicly traded effective May 18, 2015, it had no market capitalization as of December 31, 2014, and the stock performance of the New Peer Group, as calculated, was equivalent to that of the Old 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.

30


Purchases of Equity Securities. The following table sets forth certain information with respect to repurchases of our common stock during the quarter ended December 31, 2015:
Period
 
(a)
Total Number of Shares Purchased
 
(b)
Average
Price Paid
per Share
 
(c)
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1)
 
(d)
Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
October 1 - October 31
 
2,629,056

 
$
22.82

 
2,629,056

 
$

November 1 - November 30
 
3,700,767

 
$
17.09

 
3,700,767

 
$

December 1 - December 31
 

 
$

 

 
$

Total
 
6,329,823

 
$
19.47

 
6,329,823

 
$

__________________________________________
(1)
On August 3, 2015, our Board of Directors authorized a share repurchase program for up to $250 million, which was initiated in the third quarter of 2015 and completed in the fourth quarter of 2015. The shares were purchased in the open market at prevailing market prices.
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, 2015 and 2014 and for the years ended December 31, 2015, 2014 and 2013, 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.

31


 
 
Successor
 
 
Predecessor
 
 
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 (3)(4)
 
Year Ended December 31, 2011 (5)
(in millions, except per share data)
 
 
 
 
 
 
Statements of Operations Data:
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
$
3,870

 
$
2,497

 
$
1,466

 
$
312

 
 
$
981

 
$
1,333

Depreciation expense
 
$
(587
)
 
$
(247
)
 
$
(216
)
 
$
(45
)
 
 
$
(110
)
 
$
(295
)
Impairments
 
$
(99
)
 
$

 
$

 
$

 
 
$

 
$
(5
)
General and administrative expense
 
$
(128
)
 
$
(114
)
 
$
(97
)
 
$
(22
)
 
 
$
(56
)
 
$
(102
)
Operating income (loss)
 
$
64

 
$
(19
)
 
$
(318
)
 
$
(104
)
 
 
$
5

 
$
(189
)
Bankruptcy reorganization items, net
 
$

 
$
3

 
$
(1
)
 
$
(3
)
 
 
$
1,037

 
$
(52
)
Interest expense and debt extinguishment costs (6)
 
$
(546
)
 
$
(223
)
 
$
(108
)
 
$
(16
)
 
 
$
(120
)
 
$
(369
)
Income tax benefit
 
$
474

 
$
1

 
$
58

 
$

 
 
$
9

 
$
144

Income (loss) from continuing operations
 
$
47

 
$
(267
)
 
$
(359
)
 
$
(113
)
 
 
$
130

 
$
(431
)
Income (loss) from discontinued operations, net of taxes (7)
 
$

 
$

 
$
3

 
$
6

 
 
$
(162
)
 
$
(509
)
Net income (loss)
 
$
47

 
$
(267
)
 
$
(356
)
 
$
(107
)
 
 
$
(32
)
 
$
(940
)
Net income (loss) attributable to Dynegy Inc.
 
$
50

 
$
(273
)
 
$
(356
)
 
$
(107
)
 
 
$
(32
)
 
$
(940
)
Basic earnings (loss) per share from continuing operations attributable to Dynegy Inc. common stockholders (8)
 
$
0.22

 
$
(2.65
)
 
$
(3.59
)
 
$
(1.13
)
 
 
N/A

 
N/A

Basic earnings per share from discontinued operations attributable to Dynegy Inc. common stockholders (8)
 
$

 
$

 
$
0.03

 
$
0.06

 
 
N/A

 
N/A

Basic earnings (loss) per share attributable to Dynegy Inc. common stockholders (8)
 
$
0.22

 
$
(2.65
)
 
$
(3.56
)
 
$
(1.07
)
 
 
N/A

 
N/A

Cash Flow Data:
 
 
 
 
 
 
 
 
 
 
 
 
 
Net cash provided by (used in) operating activities
 
$
94

 
$
163

 
$
175

 
$
(44
)
 
 
$
(37
)
 
$
(1
)
Net cash provided by (used in) investing activities
 
$
(1,194
)
 
$
(5,262
)
 
$
474

 
$
265

 
 
$
278

 
$
(229
)
Net cash provided by (used in) financing activities
 
$
(265
)
 
$
6,126

 
$
(154
)
 
$
(328
)
 
 
$
(184
)
 
$
375

Capital expenditures, acquisitions and investments
 
$
(6,353
)
 
$
(132
)
 
$
136

 
$
(46
)
 
 
$
193

 
$
(21
)

 
 
Successor
 
 
Predecessor
 
 
December 31,
 
 
December 31, 2011
(amounts in millions)
 
2015 (1)
 
2014
 
2013
 
2012
 
 
Balance Sheet Data:
 
 
 
 
 
 
 
 
 
 
 
Current assets
 
$
1,945

 
$
2,674

 
$
1,685

 
$
1,043

 
 
$
3,569

Current liabilities
 
$
812

 
$
681

 
$
721

 
$
347

 
 
$
3,051

Property, plant and equipment, net
 
$
8,347

 
$
3,255

 
$
3,315

 
$
3,022

 
 
$
2,821

Total assets
 
$
11,539

 
$
11,232

 
$
5,291

 
$
4,535

 
 
$
8,311

Current portion of long-term debt
 
$
83

 
$
31

 
$
13

 
$
29

 
 
$
7

Long-term debt (excluding current portion) (9)
 
$
7,206

 
$
7,075

 
$
1,979

 
$
1,386

 
 
$
1,069

Total equity
 
$
2,919

 
$
3,023

 
$
2,207

 
$
2,503

 
 
$
32


32


__________________________________________
(1)
Our 2015 financial statements only reflect the impacts of the EquiPower and Duke Midwest 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 AER effective December 2, 2013; therefore, the results of our IPH segment are only included subsequent to December 1, 2013. Please read Note 3—Acquisitions for further discussion.
(3)
We completed the acquisition of DMG effective June 5, 2012; therefore, the results of our Coal segment are only included subsequent to June 5, 2012.
(4)
The results of operations for the Predecessor period January 1, 2012 through October 1, 2012 include the effects of the Plan.
(5)
We completed the transfer of DMG effective September 1, 2011; therefore, the results of our Coal segment are only included prior to September 1, 2011.
(6)
The years ended December 31, 2013 and 2011 include $11 million and $21 million of debt extinguishment costs, respectively.
(7)
Discontinued operations include the results of operations from the debtor entities of DNE. Please read Note 21—Discontinued Operations for further discussion of the sale of the DNE facilities.
(8)
Although Legacy Dynegy’s shares were publicly traded, DH did not have any publicly traded shares prior to the merger; therefore, no earnings (loss) per share is presented for the Predecessor.
(9)
The years ended December 31, 2015 and 2014 include $5.1 billion related to our Notes issued on October 27, 2014. Please read Note 13—Debt for further discussion of Acquisitions.

33


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 report the results of our power generation business as three separate segments in our consolidated financial statements: (i) Coal, (ii) IPH and (iii) Gas.
On April 1, 2015, we completed the acquisition of EquiPower Resources Corp. and Brayton Point Holdings, LLC from Energy Capital Partners for an aggregate base purchase price of approximately $3.35 billion in cash plus $105 million in common stock of Dynegy (the “EquiPower Acquisition”), subject to certain adjustments. On April 2, 2015, we completed the acquisition of Duke Energy’s commercial generation assets and retail business in the Midwest for a base purchase price of approximately $2.8 billion in cash (the “Duke Midwest Acquisition”), subject to certain adjustments. With these transactions, we own approximately 26,000 MW of generating capacity in eight states and also provide retail electricity to approximately 931,000 residential customers and approximately 41,000 commercial, industrial and municipal customers in Illinois, Ohio and Pennsylvania.
On August 3, 2015, our Board of Directors authorized a share repurchase program for up to $250 million, initiated in the third quarter of 2015, which was completed in the fourth quarter of 2015. The shares were purchased in the open market at prevailing market prices. As of December 31, 2015, we repurchased 11,326,122 shares at an aggregate cost of $250 million.
On November 5, 2015, Dynegy announced that it expects to retire the final two units at the 465-megawatt Wood River Power Station in Alton, Illinois in mid-2016, subject to the approval of MISO.  The decision to retire the Wood River facility was the result of a strategic review performed in the third quarter of 2015, and was primarily attributable to its uneconomic operation stemming from a poorly designed wholesale capacity market.
Business Discussion
We generate earnings and cash flows in the three 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, 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;

34


our ability to appropriately manage our coal inventory levels, which are dependent upon the continued performance of the mines, railroads and barges for deliveries of coal in a consistent and timely manner, and its impact on our ability to serve the critical winter and summer on-peak loads;
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 MISO, PJM, CAISO and ISO-NE market design or associated rules, including the resulting effect on future capacity revenues from changes in the existing bilateral MISO capacity markets and the existing bilateral CAISO resource adequacy markets;
our ability to maintain and operate our plants in a manner that ensures we receive full capacity payments under our various tolling agreements;
our ability to mitigate forced outage risk, including managing risk associated with capacity performance in PJM and new 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
In this section, we describe our liquidity and capital requirements including our sources and uses of liquidity and capital resources.  Our liquidity and capital requirements are primarily a function of our debt maturities and debt service requirements, contractual obligations, capital expenditures (including required environmental expenditures) and working capital needs.  Examples of working capital needs include purchases and sales of commodities and associated margin and collateral requirements, facility maintenance costs and other costs such as payroll. Our primary sources of liquidity are cash flows from operations, cash on hand and amounts available under our revolver and letter of credit (“LC”) facilities.
IPH and its direct and indirect subsidiaries are 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, have an independent director whose consent is required for certain corporate actions, including material transactions with affiliates. Further, entities within the IPH segment present themselves to the public as separate entities.  They maintain separate books, records and bank accounts and separately appoint officers.  Furthermore, they pay liabilities from their own funds, conduct business in their own names and have restrictions on pledging their assets for the benefit of certain other persons.  These provisions restrict our ability to move cash out of these entities without meeting certain requirements as set forth in the governing documents.
In connection with the closings of the Acquisitions, we entered into amendments to the Credit Agreement which provide for incremental revolving credit facilities that expand the credit available to us by an aggregate of $950 million which is used to support our collateral and liquidity requirements. The loans issued pursuant to these facilities bear interest, initially, at either (i) 2.75 percent per annum plus LIBOR with respect to any LIBOR Loan or (ii) 1.75 percent per annum plus the Base Rate with respect to any Base Rate Loan, with steps down based on a Senior Secured Leverage Ratio. As of November 10, 2015, our interest rate margin on our Revolving Facility was decreased from 2.75 percent to 2.25 percent per annum and the commitment fees on the unutilized portion of the facility decreased from 0.5 percent to 0.375 percent.
On March 27, 2015, IPM entered into a letter of credit facility with an issuing bank for up to $25 million. The facility, which is collateralized by receivables, has a two-year tenor and may be extended if agreed to by both parties for one additional year.  Interest on the facility is LIBOR plus 500 basis points on issued letters of credit. At December 31, 2015, there was approximately $25 million outstanding under this letter of credit facility. Please read Note 13—Debt—Letter of Credit Facilities for further discussion.

35


Liquidity.  The following table summarizes our liquidity position at December 31, 2015.
 
 
December 31, 2015
(amounts in millions)
 
Dynegy Inc.
 
IPH (1) (2)
 
Total
Revolving Facility and LC capacity (3)
 
$
1,480

 
$
48

 
$
1,528

 Less: Outstanding letters of credit
 
(475
)
 
(45
)
 
(520
)
Revolving Facility and LC availability
 
1,005

 
3

 
1,008

Cash and cash equivalents
 
443

 
62

 
505

Total available liquidity (4)
 
$
1,448

 
$
65

 
$
1,513

__________________________________________
(1)
Includes Cash and cash equivalents of $61 million related to Genco.
(2)
As previously discussed, due to the ring-fenced nature of IPH, cash at the IPH and Genco entities may not be moved out of these entities without meeting certain criteria. However, cash at these entities is available to support current operations of these entities.
(3)
Dynegy Inc. includes (i) $950 million of aggregate available capacity related to our incremental revolving credit facilities, (ii) $475 million of available capacity related to the five-year senior secured revolving credit facility and (iii) $55 million related to a letter of credit. IPH includes (i) $25 million related to the two-year secured letter of credit facility and (ii) $23 million related to our fully cash collateralized letter of credit and reimbursement agreement. Please read Note 13—Debt—Letter of Credit Facilities for further discussion.
(4)
On December 2, 2013, Dynegy and Illinois Power Resources, LLC entered into an intercompany revolving promissory note of $25 million. At December 31, 2015, there was $25 million outstanding on the note, which is not reflected in the table above.
The following table presents net cash from operating, investing and financing activities for the years ended December 31, 2015, 2014 and 2013:
 
 
Year Ended December 31,
(amounts in millions)
 
2015
 
2014
 
2013
Net cash provided by operating activities
 
$
94

 
$
163

 
$
175

Net cash provided by (used in) investing activities
 
$
(1,194
)
 
$
(5,262
)
 
$
474

Net cash provided by (used in) financing activities
 
$
(265
)
 
$
6,126

 
$
(154
)
Operating Activities
     Historical Operating Cash Flows.  Cash provided by operations totaled $94 million for the year ended December 31, 2015.  During the period, our power generation business provided cash of $888 million primarily due to the operation of our power generation facilities and our retail operations. Corporate and other activities used cash of $588 million primarily due to interest payments on our various debt agreements of $490 million and payments for acquisition-related costs of $115 million, offset by $17 million related to the Ponderosa Pine Energy, LLC cash receipt. Changes in working capital and other, including general and administrative expenses, used cash of $206 million, net, during the period.
Cash provided by operations totaled $163 million for the year ended December 31, 2014.  During the period, our power generation business provided cash of $451 million primarily due to the operation of our power generation facilities and our retail operations. Corporate and other activities used cash of $230 million primarily due to interest payments on our various debt agreements of $193 million and payments for acquisition-related costs of $24 million. In addition, changes in working capital and other, including general and administrative expenses, used cash of approximately $58 million.
Cash provided by operations totaled $175 million for the year ended December 31, 2013.  During the period, our power generation business provided cash of $199 million primarily due to the operation of our power generation facilities, partially offset by interest payments to service debt related to the DPC and DMG credit agreements. Corporate and other activities used cash of approximately $80 million primarily due to interest payments related to our Credit Agreement and Senior Notes, payments to advisors, employee-related payments and other general and administrative expenses. In addition, we had $56 million in positive working capital and other changes, which includes $34 million for the return of collateral.
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

36


contemplated in our PRIDE initiative.
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, 2015 and 2014:
(amounts in millions)
 
December 31, 2015

 
December 31, 2014
Dynegy Inc.:
 
 
 
 
Cash (1)
 
$
159

 
$
14

Letters of credit
 
475

 
178

Total Dynegy Inc.
 
634

 
192

 
 
 
 
 
IPH:
 
 
 
 
Cash (1) (2)
 
11

 
32

Letters of credit (3) (4)
 
45

 
10

Total IPH
 
56

 
42

 
 
 
 
 
Total
 
$
690

 
$
234

__________________________________________
(1)
Includes broker margin as well as other collateral postings included in Prepayments and other current assets on our consolidated balance sheets. As of December 31, 2015 and 2014, $106 million and $9 million of cash posted as collateral were netted against Liabilities from risk management activities on our consolidated balance sheets, respectively.
(2)
Includes cash of $1 million and $5 million related to Genco as of December 31, 2015 and 2014, respectively.
(3)
Includes letters of credit of approximately $20 million and $10 million outstanding as of December 31, 2015 and 2014 related to the cash-backed LC facility at IPM. Please read Note 13—Debt—Letter of Credit Facilities for further discussion.
(4)
Includes letters of credit of approximately $25 million related to the two-year secured letter of credit facility entered into by IPM and collateralized by receivables.
Collateral postings increased from December 31, 2014 to December 31, 2015 primarily due to acquisition-related collateral requirements. In addition to cash and letters of credit posted as collateral, we have increased the number of counterparties that participate in our first priority lien program. The additional liens were granted as collateral under certain of our derivative agreements in order to reduce the cash collateral and letters of credit that we would otherwise be required to provide to the counterparties under such agreements. The fair value of our derivatives collateralized by first priority liens included liabilities of $167 million and $141 million at December 31, 2015 and 2014, respectively.
We expect counterparties’ future collateral demands to continue to reflect changes in commodity prices, including seasonal changes in weather-related demand, as well as their views of our creditworthiness. Our ability to use economic hedging instruments in the future could be limited due to the potential collateral requirements of such instruments.
Investing Activities
     Capital Expenditures.  Our capital spending by reportable segment was as follows:
 
 
Year Ended December 31,
(amounts in millions)
 
2015
 
2014
 
2013
Coal
 
$
87

 
$
39

 
$
42

IPH
 
63

 
45

 
1

Gas
 
112

 
44

 
53

Other
 
13

 
4

 
2

Total (1)
 
$
275

 
$
132

 
$
98

__________________________________________
(1)
Includes capitalized interest of $12 million, $9 million, and $2 million for the years ended December 31, 2015, 2014 and 2013, respectively.
Capital spending in our Coal and IPH segments primarily consisted of environmental and maintenance capital projects. Capital spending in our Gas segment primarily consisted of maintenance projects.

37


Other Investing Activities. During the year ended December 31, 2015, we paid $6.078 billion in cash, net of cash acquired, in connection with the Acquisitions. In addition, there was a $5.148 billion cash inflow related to the release of restricted cash as a result of closing the Acquisitions. We also received a distribution of $11 million from our unconsolidated investment in Elwood Energy LLC, of which $8 million is considered a return of capital. Please read Note 13—Debt and Note 3—Acquisitions for further discussion.
During the year ended December 31, 2014, there was a $5.148 billion cash outflow related to restricted cash balances due to escrow requirements associated with the Notes issued in 2014, offset by an $18 million cash inflow primarily related to cash proceeds received from the sale of our 50 percent interest in Nevada Cogeneration #2, a partnership that owns Black Mountain. Please read Note 13—Debt and Note 11—Unconsolidated Investments for further discussion.
During the year ended December 31, 2013, there was a $335 million cash inflow related to restricted cash balances due to the release of cash collateral associated with the DPC LC and DMG LC facilities. A portion of these proceeds were used to repay in full and terminate commitments under the DMG and DPC credit agreements as further discussed below. As a result of repaying these credit agreements, all of our restricted cash was released. In addition, in connection with the AER Acquisition, we acquired $234 million in cash. Please read Note 3—Acquisitions for further discussion.
Future Cash Flow from Investing Activities. We expect capital expenditures for 2016 to be approximately $361 million, which is comprised of $72 million, $88 million, $193 million and $8 million in Coal, IPH, Gas, and Other, respectively. The capital budget is subject to revision as opportunities arise or circumstances change.
Financing Activities
     Historical Cash Flow from Financing Activities. Cash used in financing activities totaled $265 million for the year ended December 31, 2015 primarily due to (i) $250 million of payments related to our share repurchase program, (ii) $37 million in financing costs related to our debt and equity issuances, (iii) $31 million in repayments associated with our inventory financing agreements and term loan, (iv) $23 million in dividend payments on our Mandatory Convertible Preferred Stock and (v) $17 million in interest rate swap settlement payments, offset by $97 million in proceeds received related to inventory financing agreements. Please read Note 13—Debt and Note 17—Capital Stock for further discussion.
Cash provided by financing activities totaled $6.126 billion during the year ended December 31, 2014 primarily due to (i) $5.1 billion in proceeds from borrowings on the Notes issued in 2014, (ii) $744 million and $400 million in proceeds, net of underwriting discounts and commissions, from the Common Stock Offering and the Mandatory Convertible Preferred Stock Offering, respectively and (iii) $6 million in net proceeds received related to the emissions repurchase agreements, offset by (i) $57 million in financing costs in connection with the Notes issued in 2014, the Credit Agreement, the Senior Notes and a letter of credit with an issuing bank, (ii) $18 million in interest rate swap settlement payments and (iii) $8 million in principal payments of borrowings on the seven-year senior secured term loan B facility (the “Tranche B-2 Term Loan”). Please read Note 13—Debt and Note 17—Capital Stock for further discussion. 
Cash used in financing activities totaled $154 million during the year ended December 31, 2013 due to (i) $1.913 billion in repayments of borrowings in full on the DMG and DPC Credit Agreements and the Tranche B-1 Term Loan, including $59 million in prepayment penalties associated with the early termination of the DMG and DPC Credit Agreements, (ii) $4 million in principal payments of borrowings on the Tranche B-2 Term Loan and (iii) $5 million in interest rate swap settlement payments during the fourth quarter 2013, offset by (i) $1.751 billion in proceeds from borrowings on the Credit Agreement and Senior Notes, net of financing costs and (ii) $17 million in proceeds associated with the emissions repurchase agreements. Please read Note 13—Debt for further discussion.    

38


     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, 2015 and 2014:
(amounts in millions)
 
December 31, 2015
 
December 31, 2014
Dynegy Inc.:
 
 
 
 
Secured obligations
 
$
780

 
$
788

Unsecured obligations (1)
 
5,600

 
500

Inventory Financing Agreements
 
136

 
23

Equipment Financing Agreements
 
75

 

Unamortized discount
 
(16
)
 
(3
)
Dynegy Finance I, Inc.:
 
 
 
 
Secured obligations (1)
 

 
2,040

Dynegy Finance II, Inc.:
 
 
 
 
Secured obligations (1)
 

 
3,060

Genco:
 
 
 
 
Unsecured obligations
 
825

 
825

Unamortized discount
 
(111
)
 
(127
)
Total long-term debt
 
$
7,289

 
$
7,106

__________________________________________
(1)   At December 31, 2014, the Finance I Notes and the Finance II Notes were secured by first-priority liens on amounts in the applicable escrow account which was classified as long-term Restricted cash in our consolidated balance sheet. Upon closing of the Acquisitions, these debt obligations became Dynegy Inc.’s general unsecured obligations. Please read Note 13—Debt for further discussion.
Future Cash Flow from Financing Activities. As a result of our issuance of $400 million of mandatory convertible preferred stock on October 14, 2014, we are obligated to pay dividends of $5.4 million quarterly on a cumulative basis when declared by our Board of Directors or upon conversion. We may pay declared dividends in cash or, subject to certain limitations, in shares of our common stock or by delivery of any combination of cash and shares of our common stock. Our future cash flows from financing activities will include principal payments on our debt instruments as they become due, as well as periodic payments to settle our interest rate swap agreements. Please read Note 17—Capital Stock for further discussion.
Financing Trigger Events.  Our debt instruments and certain of our other financial obligations and all the Genco Senior Notes include provisions which, if not met, could require early payment, additional collateral support or similar actions.  The trigger events include the violation of covenants (including, in the case of the Credit Agreement under certain circumstances, the senior secured leverage ratio covenant discussed below), defaults on scheduled principal or interest payments, including any indebtedness to the extent linked to it by reason of cross-default or cross-acceleration provisions, insolvency events, acceleration of other financial obligations and, in the case of the Credit Agreement, change of control provisions.  We do not have any trigger events tied to specified credit ratings or stock price in our debt instruments and are not party to any contracts that require us to issue equity based on credit ratings or other trigger events.  Please read Note 13—Debt for further discussion.

39


Financial Covenants 
Credit Agreement. On April 23, 2013, we entered into the Credit Agreement. The Credit Agreement contains customary events of default and affirmative and negative covenants, subject to certain specified exceptions, including a financial covenant specifying required thresholds for our senior secured leverage ratio calculated on a rolling four quarters basis.  Under the Credit Agreement, if Dynegy uses 25 percent or more of its Revolving Facility, Dynegy must be in compliance with the following ratios for the respective periods: 
Compliance Period
 
Consolidated Senior Secured Net Debt to Consolidated Adjusted EBITDA (1)
September 30, 2013 through December 31, 2013
 
5.00: 1.00
March 31, 2014 through December 31, 2014
 
4.00: 1.00
March 31, 2015 through December 31, 2015
 
4.75: 1.00
March 31, 2016 through December 31, 2016
 
3.75: 1.00
March 31, 2017 and Thereafter
 
3.00: 1.00
__________________________________________
(1)   For purposes of calculating Net Debt, as defined within the Credit Agreement, we may only apply a maximum of $150 million in cash to our outstanding secured debt.
Our revolver usage at December 31, 2015 was 29 percent of the aggregate revolver commitment due to outstanding letters of credit; therefore, we were required to test the covenant. Based on the calculation outlined in the Credit Agreement, we are in compliance at December 31, 2015.
Genco Senior Notes. Genco’s indenture includes provisions that require Genco to maintain certain interest coverage and debt-to-capital ratios in order for Genco to pay dividends, to make principal or interest payments on subordinated borrowings, to make loans to or investments in affiliates or to incur additional external, third-party indebtedness.
The following table summarizes these required ratios:
 
 
Required Ratio
Restricted payment interest coverage ratio (1)
 
≥1.75
Additional indebtedness interest coverage ratio (2)
 
≥2.50
Additional indebtedness debt-to-capital ratio (2)
 
≤60%
__________________________________________
(1)
As of the date of a restricted payment, as defined, the minimum ratio must have been achieved for the most recently ended four fiscal quarters and projected by management to be achieved for each of the subsequent four six-month periods.
(2)
Ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and the related interest expense. Other borrowings from third-party external sources are included in the definition of indebtedness and are subject to these incurrence tests.
Based on December 31, 2015 calculations, Genco’s interest coverage ratios are less than the minimum ratios required for Genco to pay dividends and borrow additional funds from external, third-party sources.
Please read Note 13—Debt for further discussion.
Dividends. We have paid no cash dividends on our common stock and have no current intention of doing so. Any future determinations to pay cash dividends will be at the discretion of our Board of Directors, subject to applicable limitations under Delaware law, and will be dependent upon our results of operations, financial condition, contractual restrictions and other factors deemed relevant by our Board of Directors.
We pay quarterly dividends on our Mandatory Convertible Preferred Stock on February 1, May 1, August 1, and November 1 of each year, if declared by our Board of Directors. For the year ended December 31, 2015, we paid an aggregate of $23 million in dividends. We paid no dividends during 2014.
On January 5, 2016, our Board of Directors declared a dividend on our Mandatory Convertible Preferred Stock of $1.34 per share, or approximately $5 million in the aggregate.

40


Credit Ratings
     Our current ratings are as follows:
 
 
Moody’s
 
S&P
Dynegy Inc.:
 
 
 
 
Corporate Family Rating
 
B2
 
B+
Senior Secured
 
Ba3
 
BB
Senior Unsecured
 
B3
 
B+
Genco:
 
 
 
 
Senior Unsecured
 
B3
 
CCC+
 Disclosure of Contractual Obligations
     We have incurred various contractual obligations and financial commitments in the normal course of our operations and financing activities.  Contractual obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements.  These obligations may result from both general financing activities and from commercial arrangements that are directly supported by related revenue-producing activities.      
The following table summarizes the contractual obligations of the Company and its consolidated subsidiaries as of December 31, 2015. Cash obligations reflected are not discounted and do not include accretion or dividends.
 
 
Expiration by Period
(amounts in millions)
 
Total
 
Less than
1 Year
 
1 - 3 Years
 
3 - 5 Years
 
More than
5 Years
Long-term debt (including current portion)
 
$
7,341

 
$
66

 
$
394

 
$
3,106

 
$
3,775

Interest payments on debt
 
3,293

 
523

 
1,024

 
792

 
954

Coal purchase commitments
 
1,447

 
638

 
532

 
277

 

Coal transportation
 
904

 
131

 
158

 
160

 
455

Contractual service agreements
 
541

 
154

 
165

 
192

 
30

Gas purchase commitments
 
254

 
200

 
54

 

 

Gas transportation
 
205

 
37

 
60

 
49

 
59

Environmental compliance obligations
 
186

 
29

 
95

 
62

 

Pension funding obligations
 
232

 

 
33

 
47

 
152

Operating leases
 
62

 
16

 
11

 
10

 
25

Other obligations
 
105

 
24

 
44

 
7

 
30

Total contractual obligations
 
$
14,570

 
$
1,818

 
$
2,570

 
$
4,702

 
$
5,480

Long-Term Debt (including Current Portion).  Long-term debt includes amounts related to the Notes, the Senior Notes, the Credit Agreement, the Genco Senior Notes, and the Inventory Financing Agreements. Amounts do not include unamortized discounts. Please read Note 13—Debt for further discussion.
Interest Payments on Debt.  Interest payments on debt represent estimated periodic interest payment obligations associated with the Notes, the Senior Notes, the Credit Agreement, the Genco Senior Notes, and the Inventory Financing Agreements. Amounts include the impact of interest rate swap agreements. Please read Note 13—Debt for further discussion.
Coal Purchase Commitments.  At December 31, 2015, our subsidiaries had contracts in place to purchase coal for various generation facilities. The amounts in the table reflect our minimum purchase obligations. To the extent forecasted volumes have not been priced but are subject to a price collar structure, the obligations have been calculated using the minimum purchase price of the collar.
Coal Transportation.  At December 31, 2015, we had long-term coal transportation contracts in place. We also had long-term rail car leases in place. The amounts included in Coal transportation reflect our minimum purchase obligations based on the terms of the contracts.
Contractual Service Agreements.  Contractual service agreements represent obligations with respect to long-term plant maintenance agreements. Under certain of our contractual service agreements in which we receive maintenance and capital

41


improvements for our gas-fueled generation fleet, we have obligations to purchase uprate equipment. We currently estimate these agreements will be in effect for a period of 15 or more years. Either party can terminate the agreements based on certain events as specified in the contracts. The table above includes our current estimate of payments under the contracts through 2020 based on anticipated timing of outages and are subject to change as outage dates move. As of December 31, 2015, our minimum obligation with respect to these agreements is limited to the termination payments, which are approximately $356 million and $431 million in the event all contracts are terminated by us or the counterparty, respectively. Please read Note 16—Commitments and Contingencies—Other Commitments and Contingencies for further discussion.
Gas Purchase Commitments.  At December 31, 2015, our subsidiaries had contracts in place to purchase gas for various generation facilities. The amounts in the table reflect our minimum purchase obligations.
Gas Transportation.  Gas transportation includes fixed transport capacity obligations associated with fuel procurement for our gas plants.
Environmental Compliance Obligations. The table above includes estimated costs under a third party contract, excluding capitalized interest, for the completion of scheduled milestones related to the installation of the Newton facility scrubber systems, such that the IPH fleet will comply with certain SO2 emission limits approved in the variance granted by the IPCB in November 2013. Please read Business—Environmental Matters—IPH Variance for further discussion. The first milestone relating to the engineering design was completed in July 2015, while the last milestone relates to major equipment components being placed into final position on or before September 1, 2019. We currently estimate this contract will be in effect for a period of four or more years. We are currently scheduled to complete the Newton scrubber project by the end of 2019 with minimal costs anticipated in 2020. Either party can terminate this contract based on certain events as specified in the contract. In February 2016, Genco issued a notice to the third party contractor constructing the scrubber systems directing them to temporarily suspend a portion of the work being performed.
Pension Funding Obligations. Amounts include our minimum required contributions to our defined benefit pension plans through 2025 as determined by our actuary and are subject to change based on actual results of the plan. We may elect to make voluntary contributions in 2016 which would decrease future funding obligations. Please read Note 18—Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans for further discussion.    
Operating Leases.  Operating leases include minimum lease payment obligations associated with office space, office equipment, and land leases. Also included in operating leases are two charter agreements previously utilized in our former global liquids business.
Other Obligations.  Other obligations primarily include the following:
$48 million related to limestone purchase commitments;
$23 million related to interconnection services; and
Other miscellaneous items which are individually insignificant.
Commitments and Contingencies
Please read Note 16—Commitments and Contingencies, which is incorporated herein by reference, for further discussion of our material commitments and contingencies.
Off-Balance Sheet Arrangements
We had no off-balance sheet arrangements at December 31, 2015.
RESULTS OF OPERATIONS
Overview and Discussion of Comparability of Results. In this section, we discuss our results of operations, both on a consolidated basis and, where appropriate, by segment, for the years ended December 31, 2015, 2014 and 2013. At the end of this section, we have included our business outlook for each segment.
We report the results of our power generation business primarily as three separate segments in our consolidated financial statements: (i) Coal, (ii) IPH and (iii) Gas. Our consolidated financial results also reflect corporate-level expenses such as general and administrative expense, interest expense and income tax benefit (expense). All references to hedging within this Form 10-K relate to economic hedging activities as we do not elect hedge accounting.
On December 2, 2013, we completed the AER Acquisition; therefore, the results of our IPH segment are included in our 2013 consolidated results for the period of December 2, 2013 through December 31, 2013. Please read Note 3—Acquisitions—AER Transaction Agreement for further discussion.

42


We completed the EquiPower Acquisition and Duke Midwest Acquisition on April 1, 2015 and April 2, 2015, respectively; therefore, the results of our newly acquired plants within our Coal and Gas segments are included in our 2015 consolidated results from the respective acquisition date through December 31, 2015. Please read Note 3—Acquisitions—ECP Purchase Agreements and Duke Midwest Purchase Agreement for further discussion.    
Non-GAAP Performance Measures. In analyzing and planning for our business, we supplement our use of GAAP financial measures with non-GAAP financial measures, including EBITDA and Adjusted EBITDA. These non-GAAP financial measures reflect an additional way of viewing aspects of our business that, when viewed with our GAAP results and the accompanying reconciliations to corresponding GAAP financial measures included in the tables below, may provide a more complete understanding of factors and trends affecting our business. These non-GAAP financial measures should not be relied upon to the exclusion of GAAP financial measures and are by definition an incomplete understanding of Dynegy and must be considered in conjunction with GAAP measures.
We believe that the historical non-GAAP measures disclosed in our filings are only useful as an additional tool to help management and investors make informed decisions about our financial and operating performance. By definition, non-GAAP measures do not give a full understanding of Dynegy; therefore, to be truly valuable, they must be used in conjunction with the comparable GAAP measures. In addition, non-GAAP financial measures are not standardized; therefore, it may not be possible to compare these financial measures with other companies’ non-GAAP financial measures having the same or similar names. We strongly encourage investors to review our consolidated financial statements and publicly filed reports in their entirety and not rely on any single financial measure.
EBITDA and Adjusted EBITDA. We define EBITDA as earnings (loss) before interest expense, income tax expense (benefit) and depreciation and amortization expense. We define Adjusted EBITDA as EBITDA adjusted to exclude (i) gains or losses on the sale of certain assets, (ii) the impacts of mark-to-market changes on derivatives related to our generation portfolio, as well as interest rate swaps and warrants, (iii) the impact of impairment charges and certain other costs such as those associated with acquisitions, and (iv) other material items.
We believe EBITDA and Adjusted EBITDA provide meaningful representations of our operating performance. We consider EBITDA as another way to measure financial performance on an ongoing basis. Adjusted EBITDA is meant to reflect the operating performance of our entire power generation fleet for the period presented; consequently, it excludes the impact of mark-to-market accounting, impairment charges and other items that could be considered “non-operating” or “non-core” in nature. Because EBITDA and Adjusted EBITDA are financial measures that management uses to allocate resources, determine our ability to fund capital expenditures, assess performance against our peers and evaluate overall financial performance, we believe they provide useful information for our investors. In addition, many analysts, fund managers and other stakeholders that communicate with us typically request our financial results in an EBITDA and Adjusted EBITDA format.
As prescribed by the SEC, when EBITDA or Adjusted EBITDA is discussed in reference to performance on a consolidated basis, the most directly comparable GAAP financial measure to EBITDA and Adjusted EBITDA is Net income (loss). Management does not analyze interest expense and income taxes on a segment level; therefore, the most directly comparable GAAP financial measure to EBITDA or Adjusted EBITDA when performance is discussed on a segment level is Operating income (loss). 

43


Consolidated Summary Financial Information—Year Ended December 31, 2015 Compared to Year Ended December 31, 2014
The following table provides summary financial data regarding our consolidated results of operations for the years ended December 31, 2015 and 2014, respectively: 
 
 
Year Ended December 31,
 
Favorable (Unfavorable) $ Change
 
Favorable (Unfavorable) % Change
(amounts in millions)
 
2015
 
2014
 
 
Revenues
 
 
 
 
 
 
 
 
Energy
 
$
3,054

 
$
2,290

 
$
764

 
33
 %
Capacity
 
671

 
293

 
378

 
129
 %
Mark-to-market income (loss), net
 
127

 
(28
)
 
155

 
NM

Contract amortization
 
(83
)
 
(111
)
 
28

 
25
 %
Other (1)
 
101

 
53

 
48

 
91
 %
Total revenues
 
3,870

 
2,497

 
1,373

 
55
 %
Cost of sales, excluding depreciation expense
 
(2,028
)
 
(1,661
)
 
(367
)
 
(22
)%
Gross margin
 
1,842

 
836

 
1,006

 
120
 %
Operating and maintenance expense
 
(839
)
 
(477
)
 
(362
)
 
(76
)%
Depreciation expense
 
(587
)
 
(247
)
 
(340
)
 
(138
)%
Impairments
 
(99
)
 

 
(99
)
 
NM

Gain (loss) on sale of assets, net
 
(1
)
 
18

 
(19
)
 
(106
)%
General and administrative expense
 
(128
)
 
(114
)
 
(14
)
 
(12
)%
Acquisition and integration costs
 
(124
)
 
(35
)
 
(89
)
 
NM

Operating income (loss)
 
64

 
(19
)
 
83

 
NM

Bankruptcy reorganization items, net
 

 
3

 
(3
)
 
(100
)%
Earnings from unconsolidated investments
 
1

 
10

 
(9
)
 
(90
)%
Interest expense
 
(546
)
 
(223
)
 
(323
)
 
(145
)%
Other income and expense, net
 
54

 
(39
)
 
93

 
238
 %
Loss from continuing operations before income taxes
 
(427
)
 
(268
)
 
(159
)
 
(59
)%
Income tax benefit
 
474

 
1

 
473

 
NM

Income (loss) from continuing operations
 
47

 
(267
)
 
314

 
118
 %
Income from discontinued operations, net of tax
 

 

 

 
NM

Net income (loss)
 
47

 
(267
)
 
314

 
118
 %
Less: Net income (loss) attributable to noncontrolling interest
 
(3