|
|
|
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)
|
|
Title of each class
|
|
Name of each exchange on which registered
|
Dynegy’s common stock, $0.01 par value
|
|
New York Stock Exchange
|
Dynegy’s warrants, exercisable for common stock at an exercise price of $35 per share
|
|
New York Stock Exchange
|
|
|
None
|
|
|
|
|
(Title of Class)
|
|
|
Large accelerated filer
ý
|
|
Accelerated filer
o
|
Non-accelerated filer
o
|
|
Smaller reporting company
o
|
(Do not check if a smaller reporting company)
|
|
Emerging growth company
o
|
|
|
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.
|
||
|
|
|
ATSI
|
|
American Transmission Service, Inc.
|
CAA
|
|
Clean Air Act
|
CAISO
|
|
California Independent System Operator
|
CDD
|
|
Cooling Degree Days
|
CPUC
|
|
California Public Utility Commission
|
COMED
|
|
Commonwealth Edison
|
CT
|
|
Combustion Turbine
|
DEOK
|
|
Duke Energy Ohio Kentucky
|
EBITDA
|
|
Earnings Before Interest, Taxes, Depreciation and Amortization
|
EGU
|
|
Electric Generating Units
|
ELG
|
|
Effluent Limitation Guidelines
|
EMAAC
|
|
Eastern Mid-Atlantic Area Council
|
EPA
|
|
Environmental Protection Agency
|
ERCOT
|
|
Electric Reliability Council of Texas
|
FCA
|
|
Forward Capacity Auction
|
FERC
|
|
Federal Energy Regulatory Commission
|
FTR
|
|
Financial Transmission Rights
|
GW
|
|
Gigawatts
|
HAPs
|
|
Hazardous Air Pollutants, as defined by the Clean Air Act
|
HDD
|
|
Heating Degree Days
|
ICR
|
|
Installed Capacity Requirement
|
IMA
|
|
In-market Asset Availability
|
IPCB
|
|
Illinois Pollution Control Board
|
IPH
|
|
IPH, LLC (formerly known as Illinois Power Holdings, LLC)
|
ISO
|
|
Independent System Operator
|
ISO-NE
|
|
Independent System Operator New England
|
kW
|
|
Kilowatt
|
LIBOR
|
|
London Interbank Offered Rate
|
LMP
|
|
Locational Marginal Pricing
|
MAAC
|
|
Mid-Atlantic Area Council
|
MISO
|
|
Midcontinent Independent System Operator, Inc.
|
MMBtu
|
|
One Million British Thermal Units
|
Moody’s
|
|
Moody’s Investors Service, Inc.
|
MSCI
|
|
Morgan Stanley Capital International
|
MTM
|
|
Mark-to-market
|
MW
|
|
Megawatts
|
MWh
|
|
Megawatt Hour
|
NERC
|
|
North American Electric Reliability Corporation
|
NYISO
|
|
New York Independent System Operator
|
NYSE
|
|
New York Stock Exchange
|
PJM
|
|
PJM Interconnection, LLC
|
PPL
|
|
PPL Electric Utilities, Corp.
|
PRIDE
|
|
Producing Results through Innovation by Dynegy Employees
|
RCRA
|
|
Resource Conservation and Recovery Act of 1976
|
RGGI
|
|
Regional Greenhouse Gas Initiative
|
RTO
|
|
Regional Transmission Organization
|
S&P
|
|
Standard & Poor’s Ratings Services
|
SEC
|
|
U.S. Securities and Exchange Commission
|
ST
|
|
Steam Turbine
|
TWh
|
|
Terawatt Hour
|
Facility
|
|
Total Net
Generating Capacity (MW)(1) |
|
Primary
Fuel Type |
|
Technology
Type |
|
Location
|
|
Region
|
|
Calumet
|
|
380
|
|
|
Gas
|
|
CT
|
|
Chicago, IL
|
|
PJM
|
Dicks Creek
|
|
155
|
|
|
Gas
|
|
CT
|
|
Monroe, OH
|
|
PJM
|
Fayette
|
|
726
|
|
|
Gas
|
|
CCGT
|
|
Masontown, PA
|
|
PJM
|
Hanging Rock
|
|
1,430
|
|
|
Gas
|
|
CCGT
|
|
Ironton, OH
|
|
PJM
|
Hopewell
|
|
370
|
|
|
Gas
|
|
CCGT
|
|
Hopewell, VA
|
|
PJM
|
Kendall
|
|
1,288
|
|
|
Gas
|
|
CCGT
|
|
Minooka, IL
|
|
PJM
|
Killen (2)(3)
|
|
204
|
|
|
Coal
|
|
ST
|
|
Manchester, OH
|
|
PJM
|
Kincaid
|
|
1,108
|
|
|
Coal
|
|
ST
|
|
Kincaid, IL
|
|
PJM
|
Liberty
|
|
607
|
|
|
Gas
|
|
CCGT
|
|
Eddystone, PA
|
|
PJM
|
Miami Fort
|
|
1,020
|
|
|
Coal
|
|
ST
|
|
North Bend, OH
|
|
PJM
|
Miami Fort
|
|
77
|
|
|
Oil
|
|
CT
|
|
North Bend, OH
|
|
PJM
|
Northeastern
|
|
52
|
|
|
Waste Coal
|
|
ST
|
|
McAdoo, PA
|
|
PJM
|
Ontelaunee
|
|
600
|
|
|
Gas
|
|
CCGT
|
|
Reading, PA
|
|
PJM
|
Pleasants
|
|
388
|
|
|
Gas
|
|
CT
|
|
Saint Marys, WV
|
|
PJM
|
Richland
|
|
423
|
|
|
Gas
|
|
CT
|
|
Defiance, OH
|
|
PJM
|
Sayreville (2)(3)
|
|
170
|
|
|
Gas
|
|
CCGT
|
|
Sayreville, NJ
|
|
PJM
|
Stryker
|
|
16
|
|
|
Oil
|
|
CT
|
|
Stryker, OH
|
|
PJM
|
Stuart (2)(3)
|
|
679
|
|
|
Coal
|
|
ST
|
|
Aberdeen, OH
|
|
PJM
|
Washington
|
|
711
|
|
|
Gas
|
|
CCGT
|
|
Beverly, OH
|
|
PJM
|
Zimmer
|
|
1,300
|
|
|
Coal
|
|
ST
|
|
Moscow, OH
|
|
PJM
|
Total PJM Segment
|
|
11,704
|
|
|
|
|
|
|
|
|
|
Bellingham
|
|
566
|
|
|
Gas
|
|
CCGT
|
|
Bellingham, MA
|
|
ISO-NE
|
Bellingham NEA (2)(3)
|
|
157
|
|
|
Gas
|
|
CCGT
|
|
Bellingham, MA
|
|
ISO-NE
|
Blackstone
|
|
544
|
|
|
Gas
|
|
CCGT
|
|
Blackstone, MA
|
|
ISO-NE
|
Casco Bay
|
|
543
|
|
|
Gas
|
|
CCGT
|
|
Veazie, ME
|
|
ISO-NE
|
Independence
|
|
1,212
|
|
|
Gas
|
|
CCGT
|
|
Oswego, NY
|
|
NYISO
|
Lake Road
|
|
827
|
|
|
Gas
|
|
CCGT
|
|
Dayville, CT
|
|
ISO-NE
|
MASSPOWER
|
|
281
|
|
|
Gas
|
|
CCGT
|
|
Indian Orchard, MA
|
|
ISO-NE
|
Milford - Connecticut
|
|
600
|
|
|
Gas
|
|
CCGT
|
|
Milford, CT
|
|
ISO-NE
|
Total NY/NE Segment
|
|
4,730
|
|
|
|
|
|
|
|
|
|
Coleto Creek
|
|
650
|
|
|
Coal
|
|
ST
|
|
Goliad, TX
|
|
ERCOT
|
Ennis
|
|
366
|
|
|
Gas
|
|
CCGT
|
|
Ennis, TX
|
|
ERCOT
|
Hays
|
|
1,047
|
|
|
Gas
|
|
CCGT
|
|
San Marcos, TX
|
|
ERCOT
|
Midlothian
|
|
1,596
|
|
|
Gas
|
|
CCGT
|
|
Midlothian, TX
|
|
ERCOT
|
Wharton
|
|
83
|
|
|
Gas
|
|
CT
|
|
Boling, TX
|
|
ERCOT
|
Wise
|
|
787
|
|
|
Gas
|
|
CCGT
|
|
Poolville, TX
|
|
ERCOT
|
Total ERCOT Segment
|
|
4,529
|
|
|
|
|
|
|
|
|
|
Baldwin
|
|
1,185
|
|
|
Coal
|
|
ST
|
|
Baldwin, IL
|
|
MISO
|
Coffeen
|
|
915
|
|
|
Coal
|
|
ST
|
|
Coffeen, IL
|
|
MISO
|
Duck Creek
|
|
425
|
|
|
Coal
|
|
ST
|
|
Canton, IL
|
|
MISO
|
Edwards
|
|
585
|
|
|
Coal
|
|
ST
|
|
Bartonville, IL
|
|
MISO
|
Havana
|
|
434
|
|
|
Coal
|
|
ST
|
|
Havana, IL
|
|
MISO
|
Hennepin
|
|
294
|
|
|
Coal
|
|
ST
|
|
Hennepin, IL
|
|
MISO
|
Joppa/EEI (2)
|
|
802
|
|
|
Coal
|
|
ST
|
|
Joppa, IL
|
|
MISO
|
Joppa units 1-3
|
|
165
|
|
|
Gas
|
|
CT
|
|
Joppa, IL
|
|
MISO
|
Joppa units 4-5 (2)
|
|
56
|
|
|
Gas
|
|
CT
|
|
Joppa, IL
|
|
MISO
|
Newton
|
|
615
|
|
|
Coal
|
|
ST
|
|
Newton, IL
|
|
MISO
|
Total MISO Segment (4)
|
|
5,476
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Facility
|
|
Total Net
Generating
Capacity
(MW)(1)
|
|
Primary
Fuel Type
|
|
Technology
Type
|
|
Location
|
|
Region
|
|
Moss Landing
|
|
1,020
|
|
|
Gas
|
|
CCGT
|
|
Moss Landing, CA
|
|
CAISO
|
Oakland
|
|
165
|
|
|
Oil
|
|
CT
|
|
Oakland, CA
|
|
CAISO
|
Total CAISO Segment
|
|
1,185
|
|
|
|
|
|
|
|
|
|
Total Capacity
|
|
27,624
|
|
|
|
|
|
|
|
|
|
(1)
|
Unit capabilities are based on winter capacity and are reflected at our net ownership interest. We have not included units that have been retired or are out of operation.
|
(2)
|
Co-owned with other generation companies.
|
(3)
|
Facilities not operated by Dynegy.
|
(4)
|
We have transmission rights into PJM for certain of our MISO plants and currently offer power and capacity into PJM.
|
•
|
Operating our power plants more efficiently and driving higher operating margins;
|
•
|
Optimizing working capital and plant inventory levels; and
|
•
|
Leveraging the scale of our generation portfolio to drive cost savings.
|
•
|
On September 22, 2017, we sold our Dighton and Milford-MA facilities (356 MW) to comply with FERC mitigation requirements; and
|
•
|
limiting the utilization of Net Operating Losses (“NOLs”) arising after December 31, 2017 to
80 percent
of taxable income with an indefinite carryforward (existing NOLs can continue to be utilized at
100 percent
of taxable income with a 20 year carryforward), and
|
•
|
limiting the deduction of net business interest expense to
30 percent
of adjusted taxable income as defined in the TCJA.
|
|
|
2017-2018
|
|
2018-2019
|
|
2019-2020
|
|
2020-2021
|
|
2021-2022
|
Planning Reserve Margin (%)
|
|
15.7
|
|
16.1
|
|
15.9
|
|
15.9
|
|
15.8
|
|
|
2017-2018
|
|
2018-2019
|
Planning Reserve Margin (%)
|
|
18.1
|
|
18.2
|
|
|
2018-2019
|
|
2019-2020
|
|
2020-2021
|
|
2021-2022
|
ICR (%)
|
|
15.3
|
|
15.6
|
|
15.3
|
|
14.6
|
|
|
2018-2019
|
|
2019-2020
|
|
2020-2021
|
|
2021-2022
|
|
2022-2023
|
Planning Reserve Margin (%)
|
|
17.1
|
|
17.1
|
|
17.2
|
|
17.2
|
|
17.2
|
|
|
Year Ended December 31,
|
||||||||||||||||||||||
|
|
2017
|
|
2016
|
||||||||||||||||||||
(amounts in millions)
|
|
Total Expenditures
|
|
Capital Expenditures
|
|
Operating Expenses
|
|
Total Expenditures
|
|
Capital Expenditures
|
|
Operating Expenses
|
||||||||||||
PJM
|
|
$
|
65
|
|
|
$
|
1
|
|
|
$
|
64
|
|
|
$
|
62
|
|
|
$
|
6
|
|
|
$
|
56
|
|
NY/NE
|
|
10
|
|
|
—
|
|
|
10
|
|
|
17
|
|
|
—
|
|
|
17
|
|
||||||
ERCOT
|
|
2
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
MISO
|
|
53
|
|
|
6
|
|
|
47
|
|
|
61
|
|
|
17
|
|
|
44
|
|
||||||
CAISO
|
|
4
|
|
|
—
|
|
|
4
|
|
|
5
|
|
|
—
|
|
|
5
|
|
||||||
Other
|
|
3
|
|
|
—
|
|
|
3
|
|
|
11
|
|
|
—
|
|
|
11
|
|
||||||
Total
|
|
$
|
137
|
|
|
$
|
7
|
|
|
$
|
130
|
|
|
$
|
156
|
|
|
$
|
23
|
|
|
$
|
133
|
|
(amounts in millions)
|
|
Total Environmental Expenditures
|
|
Capital Expenditures
|
|
Operating Expenses
|
||||||
PJM
|
|
$
|
86
|
|
|
$
|
6
|
|
|
$
|
80
|
|
NY/NE
|
|
4
|
|
|
—
|
|
|
4
|
|
|||
ERCOT
|
|
4
|
|
|
1
|
|
|
3
|
|
|||
MISO
|
|
73
|
|
|
17
|
|
|
56
|
|
|||
CAISO
|
|
3
|
|
|
—
|
|
|
3
|
|
|||
Other
|
|
4
|
|
|
—
|
|
|
4
|
|
|||
Total
|
|
$
|
174
|
|
|
$
|
24
|
|
|
$
|
150
|
|
(amounts in millions)
|
|
Less than
1 Year |
|
1 - 3 Years (1)
|
|
3 - 5 Years
|
|
More than
5 Years |
|
Total
|
||||||||||
ELG expenditures
|
|
$
|
—
|
|
|
$
|
199
|
|
|
$
|
38
|
|
|
$
|
37
|
|
|
$
|
274
|
|
(1)
|
Includes $52 million for 2019 and $147 million for 2020.
|
|
|
|
|
Projected Obligation by Period
|
||||||||||||||||||||
(amounts in millions)
|
|
NPV
|
|
Less than
1 Year |
|
1 - 3 Years
|
|
3 - 5 Years
|
|
More than
5 Years |
|
Total
|
||||||||||||
CCR
|
|
$
|
242
|
|
|
$
|
28
|
|
|
$
|
59
|
|
|
$
|
97
|
|
|
$
|
134
|
|
|
$
|
318
|
|
Non-CCR
|
|
87
|
|
|
8
|
|
|
10
|
|
|
26
|
|
|
224
|
|
|
268
|
|
||||||
Total AROs
|
|
$
|
329
|
|
|
$
|
36
|
|
|
$
|
69
|
|
|
$
|
123
|
|
|
$
|
358
|
|
|
$
|
586
|
|
Customer
|
|
2017
|
|
2016
|
|
2015
|
PJM
|
|
27%
|
|
32%
|
|
28%
|
MISO
|
|
10%
|
|
16%
|
|
22%
|
ISO-NE
|
|
14%
|
|
10%
|
|
N/A
|
•
|
expectations regarding the Merger, including beliefs concerning stockholder and regulatory approvals;
|
•
|
the occurrence of any event that could give rise to the termination of the Merger Agreement, including a termination of the Merger Agreement under circumstances that could require us to pay a termination fee;
|
•
|
expectations regarding anticipated benefits of the Merger;
|
•
|
beliefs and assumptions about weather and general economic conditions;
|
•
|
beliefs, assumptions, and projections regarding the demand for power, generation volumes, and commodity pricing, including natural gas prices and the timing of a recovery in power market prices, if any;
|
•
|
beliefs and assumptions about market competition, generation capacity, and regional supply and demand characteristics of the wholesale and retail power markets, including the anticipation of plant retirements and higher market pricing over the longer term;
|
•
|
beliefs and assumptions about the benefits of state-based subsidies to our market competition, and the corresponding negative impacts on us;
|
•
|
sufficiency of, access to, and costs associated with coal, fuel oil, and natural gas inventories and transportation thereof;
|
•
|
the effects of, or changes to, the power and capacity procurement processes in the markets in which we operate;
|
•
|
expectations regarding, or impacts of, environmental matters, including costs of compliance, availability and adequacy of emission credits, and the impact of ongoing proceedings and potential regulations or changes to current regulations, including those relating to climate change, air emissions, cooling water intake structures, coal combustion byproducts, and other laws and regulations that we are, or could become, subject to, which could increase our costs, result in an impairment of our assets, cause us to limit or terminate the operation of certain of our facilities, or otherwise have a negative financial effect;
|
•
|
beliefs about the outcome of legal, administrative, legislative, and regulatory matters, including any impacts from the change in administration to these matters;
|
•
|
projected operating or financial results, including anticipated cash flows from operations, revenues, and profitability;
|
•
|
our focus on safety and our ability to efficiently operate our assets so as to capture revenue generating opportunities and operating margins;
|
•
|
our ability to mitigate forced outage risk, including managing risk associated with CP in PJM and performance incentives in ISO-NE;
|
•
|
our ability to optimize our assets through targeted investment in cost effective technology enhancements;
|
•
|
the effectiveness of our strategies to capture opportunities presented by changes in commodity prices and to manage our exposure to energy price volatility;
|
•
|
efforts to secure retail sales and the ability to grow the retail business;
|
•
|
efforts to identify opportunities to reduce congestion and improve busbar power prices;
|
•
|
ability to mitigate impacts associated with expiring reliability must run (“RMR”) and/or capacity contracts;
|
•
|
expectations regarding our compliance with the Credit Agreement, including collateral demands, interest expense, any applicable financial ratios, and other payments;
|
•
|
expectations regarding performance standards and capital and maintenance expenditures;
|
•
|
the timing and anticipated benefits to be achieved through our PRIDE and ECI initiatives;
|
•
|
expectations regarding strengthening the balance sheet, managing debt and improving Dynegy’s leverage profile;
|
•
|
anticipated timing, outcome, and impact of our expected retirements; and
|
•
|
beliefs about the costs and scope of ongoing demolition and site remediation efforts.
|
•
|
addition of new supplies of power from existing competitors or new market entrants as a result of the development of new generation plants, expansion of existing plants or additional transmission capacity;
|
•
|
uneconomic generation kept on line by utilities, aided by state-based subsidies;
|
•
|
environmental regulations and legislation;
|
•
|
weather conditions, including extreme weather conditions and seasonal fluctuations;
|
•
|
electric supply disruptions including plant outages;
|
•
|
basis risk from transmission losses and congestion and changes in power transmission infrastructure;
|
•
|
development of new technologies for the production of natural gas;
|
•
|
natural gas and coal supply disruptions;
|
•
|
fuel price volatility;
|
•
|
economic conditions;
|
•
|
capacity performance, or similar construct, requirements and penalties;
|
•
|
increased competition or price pressure driven by generation from renewable sources and other subsidized generation;
|
•
|
regulatory constraints on pricing (current or future), including RTO and ISO rules, policies and actions, or the functioning of the energy trading markets and energy trading generally;
|
•
|
the existence and effectiveness of demand-side management; and
|
•
|
conservation efforts and energy efficiency rules and the extent to which they impact electricity demand.
|
•
|
increasing our vulnerability to general economic and industry conditions;
|
•
|
requiring a substantial portion of our cash flow from operations to be dedicated to the payment of principal and interest on our indebtedness, therefore reducing our ability to use our cash flow to fund our operations, capital expenditures and future business opportunities;
|
•
|
limiting our ability to enter into long-term power sales or fuel purchases which require credit support;
|
•
|
limiting our ability to fund operations or future acquisitions;
|
•
|
restricting our ability to make certain distributions with respect to our capital stock and the ability of our subsidiaries to make certain distributions to us, in light of restricted payment and other financial covenants in our credit facilities and other financing agreements;
|
•
|
inhibiting the growth of our stock price;
|
•
|
exposing us to the risk of increased interest rates because certain of our borrowings, including borrowings under our revolving credit facility, are at variable rates of interest;
|
•
|
limiting our ability to obtain additional financing for working capital including collateral postings, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes; and
|
•
|
limiting our ability to adjust to changing market conditions and placing us at a competitive disadvantage compared to our competitors who may have less debt.
|
•
|
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.
|
|
|
High
|
|
Low
|
||||
2018:
|
|
|
|
|
||||
First Quarter (through February 8, 2018)
|
|
$
|
12.80
|
|
|
$
|
11.19
|
|
2017:
|
|
|
|
|
||||
Fourth Quarter
|
|
$
|
12.49
|
|
|
$
|
9.09
|
|
Third Quarter
|
|
$
|
9.93
|
|
|
$
|
7.38
|
|
Second Quarter
|
|
$
|
9.12
|
|
|
$
|
5.93
|
|
First Quarter
|
|
$
|
10.42
|
|
|
$
|
6.96
|
|
2016:
|
|
|
|
|
||||
Fourth Quarter
|
|
$
|
13.38
|
|
|
$
|
7.34
|
|
Third Quarter
|
|
$
|
18.09
|
|
|
$
|
12.04
|
|
Second Quarter
|
|
$
|
21.51
|
|
|
$
|
14.16
|
|
First Quarter
|
|
$
|
14.37
|
|
|
$
|
7.43
|
|
|
|
December 31, 2012
|
|
December 31, 2013
|
|
December 31, 2014
|
|
December 31, 2015
|
|
December 31, 2016
|
|
December 31, 2017
|
||||||||||||
Dynegy Inc.
|
|
$
|
100.00
|
|
|
$
|
112.49
|
|
|
$
|
158.65
|
|
|
$
|
70.05
|
|
|
$
|
44.22
|
|
|
$
|
61.94
|
|
S&P Midcap 400
|
|
$
|
100.00
|
|
|
$
|
133.50
|
|
|
$
|
146.54
|
|
|
$
|
143.35
|
|
|
$
|
173.08
|
|
|
$
|
201.20
|
|
2016 Peer Group
|
|
$
|
100.00
|
|
|
$
|
116.77
|
|
|
$
|
121.26
|
|
|
$
|
66.56
|
|
|
$
|
60.19
|
|
|
$
|
109.27
|
|
2017 Peer Group
|
|
$
|
100.00
|
|
|
$
|
116.77
|
|
|
$
|
121.26
|
|
|
$
|
66.56
|
|
|
$
|
60.19
|
|
|
$
|
91.97
|
|
|
|
Year Ended December 31,
|
||||||||||||||||||
(in millions, except per share data)
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
||||||||||
Statements of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues
|
|
$
|
4,842
|
|
|
$
|
4,318
|
|
|
$
|
3,870
|
|
|
$
|
2,497
|
|
|
$
|
1,466
|
|
Impairments
|
|
$
|
(148
|
)
|
|
$
|
(858
|
)
|
|
$
|
(99
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
General and administrative expense
|
|
$
|
(189
|
)
|
|
$
|
(161
|
)
|
|
$
|
(128
|
)
|
|
$
|
(114
|
)
|
|
$
|
(97
|
)
|
Operating income (loss)
|
|
$
|
(412
|
)
|
|
$
|
(640
|
)
|
|
$
|
64
|
|
|
$
|
(19
|
)
|
|
$
|
(318
|
)
|
Bankruptcy reorganization items, net
|
|
$
|
494
|
|
|
$
|
(96
|
)
|
|
$
|
—
|
|
|
$
|
3
|
|
|
$
|
(1
|
)
|
Interest expense and debt extinguishment costs
|
|
$
|
(695
|
)
|
|
$
|
(625
|
)
|
|
$
|
(546
|
)
|
|
$
|
(223
|
)
|
|
$
|
(108
|
)
|
Income tax benefit
|
|
$
|
610
|
|
|
$
|
45
|
|
|
$
|
474
|
|
|
$
|
1
|
|
|
$
|
58
|
|
Income (loss) from continuing operations
|
|
$
|
72
|
|
|
$
|
(1,244
|
)
|
|
$
|
47
|
|
|
$
|
(267
|
)
|
|
$
|
(359
|
)
|
Net income (loss) attributable to Dynegy Inc.
|
|
$
|
76
|
|
|
$
|
(1,240
|
)
|
|
$
|
50
|
|
|
$
|
(273
|
)
|
|
$
|
(356
|
)
|
Basic earnings (loss) per share attributable to Dynegy Inc. common stockholders
|
|
$
|
0.37
|
|
|
$
|
(9.78
|
)
|
|
$
|
0.22
|
|
|
$
|
(2.65
|
)
|
|
$
|
(3.56
|
)
|
Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash provided by operating activities
|
|
$
|
585
|
|
|
$
|
645
|
|
|
$
|
94
|
|
|
$
|
221
|
|
|
$
|
173
|
|
Net cash provided by (used in) investing activities
|
|
$
|
(2,759
|
)
|
|
$
|
(93
|
)
|
|
$
|
(6,368
|
)
|
|
$
|
(107
|
)
|
|
$
|
141
|
|
Net cash provided by (used in) financing activities
|
|
$
|
(1,299
|
)
|
|
$
|
2,742
|
|
|
$
|
(265
|
)
|
|
$
|
6,126
|
|
|
$
|
(154
|
)
|
Capital expenditures and acquisitions
|
|
$
|
(3,543
|
)
|
|
$
|
(293
|
)
|
|
$
|
(6,379
|
)
|
|
$
|
(125
|
)
|
|
$
|
138
|
|
Interest paid
|
|
$
|
557
|
|
|
$
|
558
|
|
|
$
|
503
|
|
|
$
|
129
|
|
|
$
|
94
|
|
|
|
December 31,
|
||||||||||||||||||
(amounts in millions)
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
||||||||||
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Current assets
|
|
$
|
1,524
|
|
|
$
|
2,987
|
|
|
$
|
1,932
|
|
|
$
|
2,664
|
|
|
$
|
1,682
|
|
Current liabilities
|
|
$
|
1,049
|
|
|
$
|
916
|
|
|
$
|
809
|
|
|
$
|
678
|
|
|
$
|
718
|
|
Property, plant and equipment, net
|
|
$
|
8,884
|
|
|
$
|
7,121
|
|
|
$
|
8,347
|
|
|
$
|
3,255
|
|
|
$
|
3,315
|
|
Total assets
|
|
$
|
11,771
|
|
|
$
|
13,053
|
|
|
$
|
11,459
|
|
|
$
|
11,154
|
|
|
$
|
5,264
|
|
Long-term debt (including current portion) (1)
|
|
$
|
8,433
|
|
|
$
|
8,979
|
|
|
$
|
7,209
|
|
|
$
|
7,028
|
|
|
$
|
1,965
|
|
Total equity
|
|
$
|
1,893
|
|
|
$
|
2,039
|
|
|
$
|
2,919
|
|
|
$
|
3,023
|
|
|
$
|
2,207
|
|
(1)
|
The
year ended December 31, 2016
includes a
$2 billion
seven-year Term Loan related to the ENGIE Acquisition. The year ended December 31, 2014 includes $5.1 billion related to our notes issued on October 27, 2014 related to the Duke Midwest and EquiPower acquisitions. Please read
Note 13—Debt
for further discussion.
|
•
|
prices for power, natural gas, coal and fuel oil, and related transportation, which in turn are largely driven by supply and demand. Demand for power can vary due to weather and general economic conditions, among other things. Power supplies similarly vary by region and are impacted significantly by available generating capacity, transmission capacity, and federal and state regulation;
|
•
|
the relationship between electricity prices and prices for natural gas and coal, commonly referred to as the “spark spread” and “dark spread,” respectively, which impacts the margin we earn on the electricity we generate; and
|
•
|
our ability to enter into commercial transactions to mitigate short- and medium-term earnings volatility and our ability to manage our liquidity requirements resulting from potential changes in collateral requirements as prices move.
|
•
|
transmission constraints, congestion, and other factors that can affect the price differential between the locations where we deliver generated power and the liquid market hub;
|
•
|
our ability to control capital expenditures, which primarily include maintenance, safety, environmental and reliability projects, and to control operating expenses through disciplined management;
|
•
|
our ability to optimize our assets by maintaining a high in-market availability, reliable run-time and safe, low-cost operations;
|
•
|
our ability to optimize our assets through targeted investment in cost effective technology enhancements, such as turbine uprates, or efficiency improvements;
|
•
|
our ability to operate and market production from our facilities during periods of planned/unplanned electric transmission outages;
|
•
|
our ability to post the collateral necessary to execute our commercial strategy;
|
•
|
the cost of compliance with existing and future environmental requirements that are likely to be more stringent and more comprehensive. Please read Item 1. Business—Environmental Matters for further discussion;
|
•
|
market supply conditions resulting from federal and regional renewable power mandates and initiatives or other state-led initiatives;
|
•
|
our ability to maintain coal inventory levels during critical winter and summer peak periods, which is dependent upon the reliable performance of the mines, railroads, and river transporters;
|
•
|
costs of transportation related to coal deliveries;
|
•
|
regional renewable energy mandates and initiatives that may alter supply conditions within an ISO and our generating units’ positions in the aggregate supply stack;
|
•
|
changes in market design or associated rules in the markets in which we operate, including the resulting effect on future capacity revenues from changes in the existing bilateral MISO capacity markets and the existing bilateral CAISO resource adequacy markets;
|
•
|
our ability to maintain and operate our plants in a manner that ensures we receive full capacity payments under our various tolling agreements;
|
•
|
our ability to mitigate forced outage risk, including managing risk associated with capacity performance in PJM and performance incentives in ISO-NE;
|
•
|
our ability to mitigate impacts associated with expiring RMR and/or capacity contracts;
|
•
|
access to capital markets on reasonable terms, interest rates and other costs of liquidity;
|
•
|
benefits from our PRIDE and ECI initiatives;
|
•
|
interest expense; and
|
•
|
income taxes, which will be impacted by our ability to realize value from our NOLs and AMT credits.
|
Revolving facilities and LC capacity (1)
|
|
$
|
1,650
|
|
Less:
|
|
|
||
Outstanding revolver draws
|
|
—
|
|
|
Outstanding LCs
|
|
(438
|
)
|
|
Revolving facilities and LC availability
|
|
1,212
|
|
|
Cash and cash equivalents
|
|
365
|
|
|
Total available liquidity
|
|
$
|
1,577
|
|
(1)
|
Includes
$1.545 billion
in senior secured revolving credit facilities and
$105 million
related to letter of credit facilities (“LCs”). Please read
Note 13—Debt
for further discussion.
|
•
|
Effective on the ENGIE Acquisition Closing Date, amended the Credit Agreement to (i) increase the revolver capacity by $120 million, (ii) extend the maturity date on
$450 million
in revolver capacity to 2021, (iii) reduce the interest rate applicable to the Term Loan by
75
basis points and exchanged the previous Term Loan for a new Term Loan.
|
•
|
Closed the ENGIE Acquisition for a base purchase price of $3.3 billion, paid the Energy Capital Partners (“ECP”) Buyout Price of $375 million and issued 13,711,152 common shares to Terawatt for $150 million.
|
•
|
Genco emerged from bankruptcy and, as a result, we eliminated $825 million of Genco senior notes in exchange for approximately $122 million cash, $188 million in Dynegy senior notes and 9 million 2017 Warrants with a fair value of $17 million.
|
•
|
Extended payment obligations of previously monetized capacity transactions (Forward Capacity Sales Agreement) by 24 months.
|
•
|
Received approximately $773 million in proceeds from assets sales. Troy and Armstrong facilities ($472 million); Lee facility ($176 million); and Dighton and Milford-MA facilities ($125 million).
|
•
|
Issued
$850 million
of 2026 Senior Notes. We used these proceeds, together with proceeds from asset sales and cash-on-hand to repurchase
$1.25 billion
of our
6.75 percent
senior notes due 2019 and repay
$200 million
of our Term Loan.
|
•
|
Amended the Credit Agreement to reduce the interest rate applicable to the Term Loan by 50 basis points through an exchange. This amendment is expected to save Dynegy approximately $63 million in interest costs over the next six years. Further interest rate reductions are available to us to the extent our credit ratings increase.
|
|
|
Year Ended December 31,
|
||||||||||
(amounts in millions)
|
|
2017
|
|
2016
|
|
2015
|
||||||
Net cash provided by operating activities
|
|
$
|
585
|
|
|
$
|
645
|
|
|
$
|
94
|
|
Net cash used in investing activities
|
|
$
|
(2,759
|
)
|
|
$
|
(93
|
)
|
|
$
|
(6,368
|
)
|
Net cash provided by (used in) financing activities
|
|
$
|
(1,299
|
)
|
|
$
|
2,742
|
|
|
$
|
(265
|
)
|
|
|
(in millions)
|
||
Increase in cash provided by our power generation facilities and retail operations
|
|
$
|
237
|
|
Increase in interest payments on our various debt agreements
|
|
(2
|
)
|
|
Increase in payments for acquisition-related costs
|
|
(36
|
)
|
|
Decrease in cash provided by changes in working capital and other
|
|
(259
|
)
|
|
|
|
$
|
(60
|
)
|
|
|
(in millions)
|
||
Increase in cash provided by our power generation facilities and retail operations
|
|
$
|
129
|
|
Increase in interest payments on our various debt agreements
|
|
(48
|
)
|
|
Decrease in payments for acquisition-related costs
|
|
96
|
|
|
Increase in cash provided by changes in working capital and other
|
|
391
|
|
|
Decrease in legal settlement received in 2015
|
|
(17
|
)
|
|
|
|
$
|
551
|
|
(amounts in millions)
|
|
December 31, 2017
|
|
|
December 31, 2016
|
|||
Cash (1)
|
|
$
|
92
|
|
|
$
|
124
|
|
LCs
|
|
438
|
|
|
382
|
|
||
Total
|
|
$
|
530
|
|
|
$
|
506
|
|
(1)
|
Includes broker margin as well as other collateral postings included in Prepayments and other current assets in our consolidated balance sheets. As of
December 31, 2017 and 2016
,
$47 million
and
$54 million
, respectively, of cash posted as collateral were netted against Liabilities from risk management activities in our consolidated balance sheets.
|
|
|
Year Ended December 31,
|
|
|
Estimated
|
||||||||||||
(amounts in millions)
|
|
2017
|
|
2016
|
|
2015
|
|
|
2018
|
||||||||
PJM
|
|
$
|
87
|
|
|
$
|
158
|
|
|
$
|
142
|
|
|
|
$
|
69
|
|
NY/NE
|
|
86
|
|
|
105
|
|
|
44
|
|
|
|
37
|
|
||||
ERCOT
|
|
33
|
|
|
—
|
|
|
—
|
|
|
|
69
|
|
||||
MISO
|
|
29
|
|
|
47
|
|
|
122
|
|
|
|
55
|
|
||||
CAISO
|
|
36
|
|
|
5
|
|
|
9
|
|
|
|
7
|
|
||||
Other
|
|
7
|
|
|
9
|
|
|
13
|
|
|
|
9
|
|
||||
Total capital expenditures incurred (1)
|
|
$
|
278
|
|
|
$
|
324
|
|
|
$
|
330
|
|
|
|
$
|
246
|
|
Non-cash investing activities (2)
|
|
(31
|
)
|
|
2
|
|
|
(55
|
)
|
|
|
N/A
|
|
||||
Capital work performed under prepaid long-term service agreement
|
|
(60
|
)
|
|
(121
|
)
|
|
(18
|
)
|
|
|
N/A
|
|
||||
Prepaid cash for long-term service agreements (3)
|
|
37
|
|
|
88
|
|
|
44
|
|
|
|
N/A
|
|
||||
Capital Expenditures - Statement of Cash Flows
|
|
$
|
224
|
|
|
$
|
293
|
|
|
$
|
301
|
|
|
|
N/A
|
|
(1)
|
Includes capitalized interest of
$2 million
,
$10 million
, and
$12 million
for the years ended
December 31, 2017, 2016 and 2015
, respectively.
|
(2)
|
Please read
Note 6—Cash Flow Information
for further details.
|
(3)
|
Prepaid cash reclassified into Investing Activities on the consolidated statements of cash flows.
|
(amounts in millions)
|
|
December 31, 2017
|
|
December 31, 2016
|
||||
Secured obligations:
|
|
|
|
|
||||
Term loan
|
|
$
|
2,018
|
|
|
$
|
2,224
|
|
Revolving Facility
|
|
—
|
|
|
—
|
|
||
Forward Capacity Agreement
|
|
241
|
|
|
219
|
|
||
Inventory Financing Agreements
|
|
48
|
|
|
129
|
|
||
Unsecured obligations (Amortizing Notes, Senior Notes, and Equipment Financing)
|
|
6,323
|
|
|
6,527
|
|
||
Unamortized discounts and issuance costs
|
|
(197
|
)
|
|
(120
|
)
|
||
Total long-term debt
|
|
$
|
8,433
|
|
|
$
|
8,979
|
|
|
|
Moody’s
|
|
S&P
|
Corporate Family Rating
|
|
B2
|
|
B+
|
Senior Secured
|
|
Ba3
|
|
BB
|
Senior Unsecured
|
|
B3
|
|
B+
|
|
|
Expiration by Period
|
||||||||||||||||||
(amounts in millions)
|
|
Total
|
|
Less than
1 Year |
|
1 - 3 Years
|
|
3 - 5 Years
|
|
More than
5 Years |
||||||||||
Long-term debt (including current portion) (1)
|
|
$
|
8,498
|
|
|
$
|
83
|
|
|
$
|
1,063
|
|
|
$
|
1,795
|
|
|
$
|
5,557
|
|
Interest payments on debt
|
|
3,316
|
|
|
566
|
|
|
1,050
|
|
|
979
|
|
|
721
|
|
|||||
Coal purchase commitments
|
|
802
|
|
|
402
|
|
|
400
|
|
|
—
|
|
|
—
|
|
|||||
Coal transportation
|
|
837
|
|
|
148
|
|
|
181
|
|
|
188
|
|
|
320
|
|
|||||
Contractual service agreements
|
|
788
|
|
|
118
|
|
|
283
|
|
|
347
|
|
|
40
|
|
|||||
Gas purchase commitments
|
|
212
|
|
|
212
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Gas transportation
|
|
183
|
|
|
48
|
|
|
73
|
|
|
28
|
|
|
34
|
|
|||||
Pension funding obligations
|
|
220
|
|
|
13
|
|
|
5
|
|
|
50
|
|
|
152
|
|
|||||
Operating leases
|
|
33
|
|
|
6
|
|
|
10
|
|
|
9
|
|
|
8
|
|
|||||
Other obligations
|
|
88
|
|
|
35
|
|
|
16
|
|
|
12
|
|
|
25
|
|
|||||
Total contractual obligations
|
|
14,977
|
|
|
1,631
|
|
|
3,081
|
|
|
3,408
|
|
|
6,857
|
|
|||||
Total ELG expenditures (2)
|
|
274
|
|
|
—
|
|
|
199
|
|
|
38
|
|
|
37
|
|
|||||
Total AROs (2)
|
|
586
|
|
|
36
|
|
|
69
|
|
|
123
|
|
|
358
|
|
|||||
Total contractual and other environmental obligations
|
|
$
|
15,837
|
|
|
$
|
1,667
|
|
|
$
|
3,349
|
|
|
$
|
3,569
|
|
|
$
|
7,252
|
|
(1)
|
Excludes
$132 million
of Equipment Financing Agreements which are included in Contractual service agreements.
|
(2)
|
See Item 1. Business-Environmental Matters for further discussion.
|
•
|
$25 million
related to limestone and ash purchase commitments;
|
•
|
$17 million
related to interconnection services;
|
•
|
$23 million
related to water services; and
|
•
|
$23 million
related to other miscellaneous items which are individually insignificant.
|
|
|
Year Ended December 31,
|
||||||||||
(amounts in millions)
|
|
2017
|
|
2016
|
|
2015
|
||||||
Net cash provided by operating activities
|
|
$
|
585
|
|
|
$
|
645
|
|
|
$
|
94
|
|
Capital expenditures
|
|
(249
|
)
|
|
(228
|
)
|
|
(251
|
)
|
|||
Acquisition & integration related payments
|
|
55
|
|
|
73
|
|
|
272
|
|
|||
Adjustment related to acquired derivatives
|
|
42
|
|
|
47
|
|
|
60
|
|
|||
Interest rate swap settlement payments
|
|
(20
|
)
|
|
(17
|
)
|
|
(17
|
)
|
|||
Collateral, working capital and other
|
|
(39
|
)
|
|
(257
|
)
|
|
28
|
|
|||
Adjusted Free Cash Flow
|
|
$
|
374
|
|
|
$
|
263
|
|
|
$
|
186
|
|
|
|
Year Ended December 31,
|
|
Favorable (Unfavorable) $ Change
|
||||||||
(amounts in millions)
|
|
2017
|
|
2016
|
|
|||||||
Revenues
|
|
|
|
|
|
|
||||||
Energy
|
|
$
|
4,000
|
|
|
$
|
3,366
|
|
|
$
|
634
|
|
Capacity
|
|
978
|
|
|
769
|
|
|
209
|
|
|||
Mark-to-market income (loss), net
|
|
(243
|
)
|
|
136
|
|
|
(379
|
)
|
|||
Contract amortization
|
|
(33
|
)
|
|
(80
|
)
|
|
47
|
|
|||
Other
|
|
140
|
|
|
127
|
|
|
13
|
|
|||
Total revenues
|
|
4,842
|
|
|
4,318
|
|
|
524
|
|
|||
Cost of sales, excluding depreciation expense
|
|
(2,932
|
)
|
|
(2,281
|
)
|
|
(651
|
)
|
|||
Gross margin
|
|
1,910
|
|
|
2,037
|
|
|
(127
|
)
|
|||
Operating and maintenance expense
|
|
(995
|
)
|
|
(940
|
)
|
|
(55
|
)
|
|||
Depreciation expense
|
|
(811
|
)
|
|
(689
|
)
|
|
(122
|
)
|
|||
Impairments
|
|
(148
|
)
|
|
(858
|
)
|
|
710
|
|
|||
Loss on sale of assets, net
|
|
(122
|
)
|
|
(1
|
)
|
|
(121
|
)
|
|||
General and administrative expense
|
|
(189
|
)
|
|
(161
|
)
|
|
(28
|
)
|
|||
Acquisition and integration costs
|
|
(57
|
)
|
|
(11
|
)
|
|
(46
|
)
|
|||
Other
|
|
—
|
|
|
(17
|
)
|
|
17
|
|
|||
Operating loss
|
|
(412
|
)
|
|
(640
|
)
|
|
228
|
|
|||
Bankruptcy reorganization items
|
|
494
|
|
|
(96
|
)
|
|
590
|
|
|||
Earnings from unconsolidated investments
|
|
8
|
|
|
7
|
|
|
1
|
|
|||
Interest expense
|
|
(616
|
)
|
|
(625
|
)
|
|
9
|
|
|||
Loss on early extinguishment of debt
|
|
(79
|
)
|
|
—
|
|
|
(79
|
)
|
|||
Other income and expense, net
|
|
67
|
|
|
65
|
|
|
2
|
|
|||
Loss before income taxes
|
|
(538
|
)
|
|
(1,289
|
)
|
|
751
|
|
|||
Income tax benefit
|
|
610
|
|
|
45
|
|
|
565
|
|
|||
Net income (loss)
|
|
72
|
|
|
(1,244
|
)
|
|
1,316
|
|
|||
Less: Net loss attributable to noncontrolling interest
|
|
(4
|
)
|
|
(4
|
)
|
|
—
|
|
|||
Net income (loss) attributable to Dynegy Inc.
|
|
$
|
76
|
|
|
$
|
(1,240
|
)
|
|
$
|
1,316
|
|
|
|
Year Ended December 31, 2017
|
||||||||||||||||||||||||||
(amounts in millions)
|
|
PJM
|
|
NY/NE
|
|
ERCOT
|
|
MISO
|
|
CAISO
|
|
Other
|
|
Total
|
||||||||||||||
Revenues
|
|
$
|
2,262
|
|
|
$
|
1,029
|
|
|
$
|
277
|
|
|
$
|
1,152
|
|
|
$
|
122
|
|
|
$
|
—
|
|
|
$
|
4,842
|
|
Cost of sales, excluding depreciation expense
|
|
(1,217
|
)
|
|
(658
|
)
|
|
(256
|
)
|
|
(723
|
)
|
|
(78
|
)
|
|
—
|
|
|
(2,932
|
)
|
|||||||
Gross margin
|
|
1,045
|
|
|
371
|
|
|
21
|
|
|
429
|
|
|
44
|
|
|
—
|
|
|
1,910
|
|
|||||||
Operating and maintenance expense
|
|
(389
|
)
|
|
(170
|
)
|
|
(95
|
)
|
|
(300
|
)
|
|
(39
|
)
|
|
(2
|
)
|
|
(995
|
)
|
|||||||
Depreciation expense
|
|
(379
|
)
|
|
(224
|
)
|
|
(73
|
)
|
|
(75
|
)
|
|
(53
|
)
|
|
(7
|
)
|
|
(811
|
)
|
|||||||
Impairments
|
|
(49
|
)
|
|
—
|
|
|
—
|
|
|
(99
|
)
|
|
—
|
|
|
—
|
|
|
(148
|
)
|
|||||||
Gain (loss) on sale of assets, net
|
|
(36
|
)
|
|
(90
|
)
|
|
—
|
|
|
1
|
|
|
3
|
|
|
—
|
|
|
(122
|
)
|
|||||||
General and administrative expense
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(189
|
)
|
|
(189
|
)
|
|||||||
Acquisition and integration costs
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(57
|
)
|
|
(57
|
)
|
|||||||
Operating income (loss)
|
|
$
|
192
|
|
|
$
|
(113
|
)
|
|
$
|
(147
|
)
|
|
$
|
(44
|
)
|
|
$
|
(45
|
)
|
|
$
|
(255
|
)
|
|
$
|
(412
|
)
|
|
|
Year Ended December 31, 2016
|
||||||||||||||||||||||
(amounts in millions)
|
|
PJM
|
|
NY/NE
|
|
MISO
|
|
CAISO
|
|
Other
|
|
Total
|
||||||||||||
Revenues
|
|
$
|
2,202
|
|
|
$
|
837
|
|
|
$
|
1,137
|
|
|
$
|
142
|
|
|
$
|
—
|
|
|
$
|
4,318
|
|
Cost of sales, excluding depreciation expense
|
|
(985
|
)
|
|
(486
|
)
|
|
(741
|
)
|
|
(69
|
)
|
|
—
|
|
|
(2,281
|
)
|
||||||
Gross margin
|
|
1,217
|
|
|
351
|
|
|
396
|
|
|
73
|
|
|
—
|
|
|
2,037
|
|
||||||
Operating and maintenance expense
|
|
(391
|
)
|
|
(165
|
)
|
|
(347
|
)
|
|
(36
|
)
|
|
(1
|
)
|
|
(940
|
)
|
||||||
Depreciation expense
|
|
(346
|
)
|
|
(215
|
)
|
|
(81
|
)
|
|
(42
|
)
|
|
(5
|
)
|
|
(689
|
)
|
||||||
Impairments
|
|
(65
|
)
|
|
—
|
|
|
(793
|
)
|
|
—
|
|
|
—
|
|
|
(858
|
)
|
||||||
Gain (loss) on sale of assets, net
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
(2
|
)
|
|
(1
|
)
|
||||||
General and administrative expense
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(161
|
)
|
|
(161
|
)
|
||||||
Acquisition and integration costs
|
|
—
|
|
|
—
|
|
|
8
|
|
|
—
|
|
|
(19
|
)
|
|
(11
|
)
|
||||||
Other
|
|
(1
|
)
|
|
—
|
|
|
(16
|
)
|
|
—
|
|
|
—
|
|
|
(17
|
)
|
||||||
Operating income (loss)
|
|
$
|
414
|
|
|
$
|
(29
|
)
|
|
$
|
(832
|
)
|
|
$
|
(5
|
)
|
|
$
|
(188
|
)
|
|
$
|
(640
|
)
|
(amounts in millions)
|
|
PJM
|
|
NY/NE
|
|
ERCOT
|
|
MISO
|
|
CAISO
|
|
Total
|
||||||||||||
Revenues, attributable to newly acquired
ENGIE plants
|
|
$
|
203
|
|
|
$
|
227
|
|
|
$
|
277
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
707
|
|
Higher (lower) realized power prices, net of hedges
|
|
29
|
|
|
108
|
|
|
—
|
|
|
(47
|
)
|
|
27
|
|
|
117
|
|
||||||
Lower generation volumes (1)
|
|
(23
|
)
|
|
(51
|
)
|
|
—
|
|
|
(57
|
)
|
|
(8
|
)
|
|
(139
|
)
|
||||||
Higher (lower) capacity revenues
|
|
26
|
|
|
25
|
|
|
—
|
|
|
47
|
|
|
(22
|
)
|
|
76
|
|
||||||
Change in MTM value of derivative transactions
|
|
(200
|
)
|
|
(128
|
)
|
|
—
|
|
|
68
|
|
|
(7
|
)
|
|
(267
|
)
|
||||||
Lower contract amortization
|
|
24
|
|
|
4
|
|
|
—
|
|
|
7
|
|
|
10
|
|
|
45
|
|
||||||
Other (2)
|
|
1
|
|
|
7
|
|
|
—
|
|
|
(3
|
)
|
|
(20
|
)
|
|
(15
|
)
|
||||||
Total change in revenues
|
|
$
|
60
|
|
|
$
|
192
|
|
|
$
|
277
|
|
|
$
|
15
|
|
|
$
|
(20
|
)
|
|
$
|
524
|
|
(1)
|
Decrease due to mild winter weather which decreased demand across our key markets as well as planned outages and shutdowns.
|
(2)
|
Other primarily consists of ancillary, tolling, transmission and gas revenues.
|
(amounts in millions)
|
|
PJM
|
|
NY/NE
|
|
ERCOT
|
|
MISO
|
|
CAISO
|
|
Total
|
||||||||||||
Cost of sales attributable to newly acquired
ENGIE plants
|
|
$
|
91
|
|
|
$
|
119
|
|
|
$
|
256
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
466
|
|
Higher (lower) delivered fuel cost, primarily due to higher gas costs
|
|
117
|
|
|
142
|
|
|
—
|
|
|
(1
|
)
|
|
15
|
|
|
273
|
|
||||||
Lower burn volumes (1)
|
|
(39
|
)
|
|
(76
|
)
|
|
—
|
|
|
(12
|
)
|
|
(6
|
)
|
|
(133
|
)
|
||||||
Lower (higher) contract amortization
|
|
42
|
|
|
(18
|
)
|
|
—
|
|
|
13
|
|
|
—
|
|
|
37
|
|
||||||
Other (2)
|
|
21
|
|
|
5
|
|
|
—
|
|
|
(18
|
)
|
|
—
|
|
|
8
|
|
||||||
Total change in cost of sales
|
|
$
|
232
|
|
|
$
|
172
|
|
|
$
|
256
|
|
|
$
|
(18
|
)
|
|
$
|
9
|
|
|
$
|
651
|
|
(1)
|
Lower burn volumes primarily due to milder weather at our PJM, NY/NE, and MISO segments, unit shutdowns primarily at our MISO segment, and a plant retirement at our NY/NE segment.
|
(2)
|
Other primarily consists of transmission expenses and various non-recurring expenses.
|
|
|
Year Ended December 31,
|
||||||
Description
|
|
2017
|
|
2016
|
||||
Inventory
|
|
$
|
14
|
|
|
$
|
—
|
|
Property, plant and equipment
|
|
119
|
|
|
849
|
|
||
Equity investment
|
|
—
|
|
|
9
|
|
||
Assets held-for-sale, including $9 of allocated goodwill
|
|
15
|
|
|
—
|
|
||
Total
|
|
$
|
148
|
|
|
$
|
858
|
|
|
|
Year Ended December 31, 2017
|
||||||||||||||||||||||||||
(amounts in millions)
|
|
PJM
|
|
NY/NE
|
|
ERCOT
|
|
MISO
|
|
CAISO
|
|
Other
|
|
Total
|
||||||||||||||
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
72
|
|
||||||||||||
Income tax benefit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(610
|
)
|
|||||||||||||
Other income and expense, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(67
|
)
|
|||||||||||||
Loss on early extinguishment of debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
79
|
|
|||||||||||||
Interest expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
616
|
|
|||||||||||||
Earnings from unconsolidated investments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(8
|
)
|
|||||||||||||
Bankruptcy reorganization items
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(494
|
)
|
|||||||||||||
Operating income (loss)
|
|
$
|
192
|
|
|
$
|
(113
|
)
|
|
$
|
(147
|
)
|
|
$
|
(44
|
)
|
|
$
|
(45
|
)
|
|
$
|
(255
|
)
|
|
$
|
(412
|
)
|
Depreciation and amortization expense
|
|
390
|
|
|
232
|
|
|
74
|
|
|
91
|
|
|
57
|
|
|
7
|
|
|
851
|
|
|||||||
Bankruptcy reorganization items
|
|
—
|
|
|
—
|
|
|
—
|
|
|
494
|
|
|
—
|
|
|
—
|
|
|
494
|
|
|||||||
Earnings from unconsolidated investments
|
|
3
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8
|
|
|||||||
Loss on early extinguishment of debt
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(79
|
)
|
|
(79
|
)
|
|||||||
Other income and expense, net
|
|
16
|
|
|
—
|
|
|
—
|
|
|
26
|
|
|
—
|
|
|
25
|
|
|
67
|
|
|||||||
EBITDA
|
|
601
|
|
|
124
|
|
|
(73
|
)
|
|
567
|
|
|
12
|
|
|
(302
|
)
|
|
929
|
|
|||||||
Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude noncontrolling interest
|
|
5
|
|
|
2
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
9
|
|
|||||||
Acquisition, integration and restructuring costs
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
74
|
|
|
74
|
|
|||||||
Bankruptcy reorganization items
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(494
|
)
|
|
—
|
|
|
—
|
|
|
(494
|
)
|
|||||||
Mark-to-market adjustments, including warrants
|
|
125
|
|
|
75
|
|
|
99
|
|
|
(21
|
)
|
|
7
|
|
|
(16
|
)
|
|
269
|
|
|||||||
Impairments
|
|
49
|
|
|
—
|
|
|
—
|
|
|
99
|
|
|
—
|
|
|
—
|
|
|
148
|
|
|||||||
Loss (gain) on sale of assets, net
|
|
36
|
|
|
90
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
125
|
|
|||||||
Loss on early extinguishment of debt
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
79
|
|
|
79
|
|
|||||||
Non-cash compensation expense
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
20
|
|
|
21
|
|
|||||||
Other
|
|
2
|
|
|
2
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
(3
|
)
|
|
—
|
|
|||||||
Adjusted EBITDA
|
|
$
|
818
|
|
|
$
|
293
|
|
|
$
|
26
|
|
|
$
|
152
|
|
|
$
|
19
|
|
|
$
|
(148
|
)
|
|
$
|
1,160
|
|
|
|
Year Ended December 31, 2016
|
||||||||||||||||||||||
(amounts in millions)
|
|
PJM
|
|
NY/NE
|
|
MISO
|
|
CAISO
|
|
Other
|
|
Total
|
||||||||||||
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(1,244
|
)
|
||||||||||
Income tax benefit
|
|
|
|
|
|
|
|
|
|
|
|
(45
|
)
|
|||||||||||
Other income and expense, net
|
|
|
|
|
|
|
|
|
|
|
|
(65
|
)
|
|||||||||||
Interest expense
|
|
|
|
|
|
|
|
|
|
|
|
625
|
|
|||||||||||
Earnings from unconsolidated investments
|
|
|
|
|
|
|
|
|
|
|
|
(7
|
)
|
|||||||||||
Bankruptcy reorganization items
|
|
|
|
|
|
|
|
|
|
|
|
96
|
|
|||||||||||
Operating income (loss)
|
|
$
|
414
|
|
|
$
|
(29
|
)
|
|
$
|
(832
|
)
|
|
$
|
(5
|
)
|
|
$
|
(188
|
)
|
|
$
|
(640
|
)
|
Depreciation and amortization expense
|
|
349
|
|
|
243
|
|
|
87
|
|
|
53
|
|
|
5
|
|
|
737
|
|
||||||
Bankruptcy reorganization items
|
|
—
|
|
|
—
|
|
|
(96
|
)
|
|
—
|
|
|
—
|
|
|
(96
|
)
|
||||||
Earnings from unconsolidated investments
|
|
7
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
7
|
|
||||||
Other income and expense, net
|
|
9
|
|
|
1
|
|
|
15
|
|
|
12
|
|
|
28
|
|
|
65
|
|
||||||
EBITDA
|
|
779
|
|
|
215
|
|
|
(826
|
)
|
|
60
|
|
|
(155
|
)
|
|
73
|
|
||||||
Adjustments to reflect Adjusted EBITDA from unconsolidated investment and exclude noncontrolling interest
|
|
—
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
2
|
|
||||||
Acquisition, integration and restructuring costs
|
|
—
|
|
|
—
|
|
|
(8
|
)
|
|
—
|
|
|
29
|
|
|
21
|
|
||||||
Bankruptcy reorganization items
|
|
—
|
|
|
—
|
|
|
96
|
|
|
—
|
|
|
—
|
|
|
96
|
|
||||||
Mark-to-market adjustments, including warrants
|
|
(92
|
)
|
|
(44
|
)
|
|
47
|
|
|
—
|
|
|
(6
|
)
|
|
(95
|
)
|
||||||
Impairments
|
|
65
|
|
|
—
|
|
|
793
|
|
|
—
|
|
|
—
|
|
|
858
|
|
||||||
Loss (gain) on sale of assets, net
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
2
|
|
|
1
|
|
||||||
Non-cash compensation expense
|
|
—
|
|
|
—
|
|
|
6
|
|
|
—
|
|
|
22
|
|
|
28
|
|
||||||
Other (1)
|
|
5
|
|
|
—
|
|
|
20
|
|
|
(1
|
)
|
|
(1
|
)
|
|
23
|
|
||||||
Adjusted EBITDA
|
|
$
|
757
|
|
|
$
|
171
|
|
|
$
|
129
|
|
|
$
|
59
|
|
|
$
|
(109
|
)
|
|
$
|
1,007
|
|
(1)
|
Other includes an adjustment to exclude Wood River’s energy margin and O&M costs of $23 million.
|
|
|
Year Ended December 31,
|
|
Favorable (Unfavorable) $ Change
|
||||||||
(dollars in millions, except for price information)
|
|
2017 (1)
|
|
2016
|
|
|||||||
Operating Revenues
|
|
|
|
|
|
|
||||||
Energy
|
|
$
|
1,793
|
|
|
$
|
1,681
|
|
|
$
|
112
|
|
Capacity
|
|
493
|
|
|
398
|
|
|
95
|
|
|||
Mark-to-market income (loss), net
|
|
(83
|
)
|
|
118
|
|
|
(201
|
)
|
|||
Contract amortization
|
|
(18
|
)
|
|
(47
|
)
|
|
29
|
|
|||
Other
|
|
77
|
|
|
52
|
|
|
25
|
|
|||
Total operating revenues
|
|
2,262
|
|
|
2,202
|
|
|
60
|
|
|||
Operating Costs
|
|
|
|
|
|
|
||||||
Cost of sales
|
|
(1,228
|
)
|
|
(1,033
|
)
|
|
(195
|
)
|
|||
Contract amortization
|
|
11
|
|
|
48
|
|
|
(37
|
)
|
|||
Total operating costs
|
|
(1,217
|
)
|
|
(985
|
)
|
|
(232
|
)
|
|||
Gross margin
|
|
1,045
|
|
|
1,217
|
|
|
(172
|
)
|
|||
Operating and maintenance expense
|
|
(389
|
)
|
|
(391
|
)
|
|
2
|
|
|||
Depreciation expense
|
|
(379
|
)
|
|
(346
|
)
|
|
(33
|
)
|
|||
Impairments
|
|
(49
|
)
|
|
(65
|
)
|
|
16
|
|
|||
Loss on sale of assets, net
|
|
(36
|
)
|
|
—
|
|
|
(36
|
)
|
|||
Other
|
|
—
|
|
|
(1
|
)
|
|
1
|
|
|||
Operating income
|
|
192
|
|
|
414
|
|
|
(222
|
)
|
|||
Depreciation and amortization expense
|
|
390
|
|
|
349
|
|
|
41
|
|
|||
Earnings from unconsolidated investments
|
|
3
|
|
|
7
|
|
|
(4
|
)
|
|||
Other income and expense, net
|
|
16
|
|
|
9
|
|
|
7
|
|
|||
EBITDA
|
|
601
|
|
|
779
|
|
|
(178
|
)
|
|||
Adjustment to reflect Adjusted EBITDA from unconsolidated investment
|
|
5
|
|
|
—
|
|
|
5
|
|
|||
Mark-to-market adjustments
|
|
125
|
|
|
(92
|
)
|
|
217
|
|
|||
Impairments
|
|
49
|
|
|
65
|
|
|
(16
|
)
|
|||
Loss on sale of assets, net
|
|
36
|
|
|
—
|
|
|
36
|
|
|||
Other
|
|
2
|
|
|
5
|
|
|
(3
|
)
|
|||
Adjusted EBITDA
|
|
$
|
818
|
|
|
$
|
757
|
|
|
$
|
61
|
|
|
|
|
|
|
|
|
||||||
Million Megawatt Hours Generated (1)
|
|
52.8
|
|
|
52.8
|
|
|
—
|
|
|||
IMA (1)(2):
|
|
|
|
|
|
|
||||||
Combined-Cycle Facilities
|
|
95
|
%
|
|
97
|
%
|
|
|
||||
Coal-Fired Facilities
|
|
75
|
%
|
|
80
|
%
|
|
|
||||
Average Capacity Factor (1)(3):
|
|
|
|
|
|
|
||||||
Combined-Cycle Facilities
|
|
64
|
%
|
|
74
|
%
|
|
|
||||
Coal-Fired Facilities
|
|
56
|
%
|
|
53
|
%
|
|
|
||||
CDDs (4)
|
|
1,143
|
|
|
1,417
|
|
|
(274
|
)
|
|||
HDDs (4)
|
|
4,403
|
|
|
4,719
|
|
|
(316
|
)
|
|||
Average Market On-Peak Spark Spreads ($/MWh) (5):
|
|
|
|
|
|
|
||||||
PJM West
|
|
$
|
16.90
|
|
|
$
|
22.62
|
|
|
$
|
(5.72
|
)
|
AD Hub
|
|
$
|
19.22
|
|
|
$
|
22.52
|
|
|
$
|
(3.30
|
)
|
Average Market On-Peak Power Prices ($/MWh) (6):
|
|
|
|
|
|
|
||||||
PJM West
|
|
$
|
34.38
|
|
|
$
|
34.65
|
|
|
$
|
(0.27
|
)
|
AD Hub
|
|
$
|
34.00
|
|
|
$
|
32.93
|
|
|
$
|
1.07
|
|
Average natural gas price—TetcoM3 ($/MMBtu) (7)
|
|
$
|
2.50
|
|
|
$
|
1.72
|
|
|
$
|
0.78
|
|
(1)
|
Includes the activity of the assets acquired in the ENGIE Acquisition for our period of ownership. Million Megawatt Hours Generated and Average Capacity Factor include such activity for the full month of February. IMA excludes such activity for our period of ownership in February.
|
(2)
|
IMA is an internal measurement calculation that reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched. The calculation excludes certain events outside of management control such as weather related issues. The calculation excludes CTs.
|
(3)
|
Reflects actual production as a percentage of available capacity. The calculation excludes CTs.
|
(4)
|
Reflects CDDs or HDDs for the PJM Region based on National Oceanic and Atmospheric Association (“NOAA”) data.
|
(5)
|
Reflects the average of the on-peak spark spreads available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas at a daily cash market price and does not reflect spark spreads available to us.
|
(6)
|
Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.
|
(7)
|
Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us.
|
|
|
Year Ended December 31,
|
|
Favorable (Unfavorable) $ Change
|
||||||||
(dollars in millions, except for price information)
|
|
2017 (1)
|
|
2016
|
|
|||||||
Operating Revenues
|
|
|
|
|
|
|
||||||
Energy
|
|
$
|
813
|
|
|
$
|
570
|
|
|
$
|
243
|
|
Capacity
|
|
257
|
|
|
168
|
|
|
89
|
|
|||
Mark-to-market income (loss), net
|
|
(75
|
)
|
|
65
|
|
|
(140
|
)
|
|||
Contract amortization
|
|
(9
|
)
|
|
(10
|
)
|
|
1
|
|
|||
Other
|
|
43
|
|
|
44
|
|
|
(1
|
)
|
|||
Total operating revenues
|
|
1,029
|
|
|
837
|
|
|
192
|
|
|||
Operating Costs
|
|
|
|
|
|
|
||||||
Cost of sales
|
|
(660
|
)
|
|
(469
|
)
|
|
(191
|
)
|
|||
Contract amortization
|
|
2
|
|
|
(17
|
)
|
|
19
|
|
|||
Total operating costs
|
|
(658
|
)
|
|
(486
|
)
|
|
(172
|
)
|
|||
Gross margin
|
|
371
|
|
|
351
|
|
|
20
|
|
|||
Operating and maintenance expense
|
|
(170
|
)
|
|
(165
|
)
|
|
(5
|
)
|
|||
Depreciation expense
|
|
(224
|
)
|
|
(215
|
)
|
|
(9
|
)
|
|||
Loss on sale of assets, net
|
|
(90
|
)
|
|
—
|
|
|
(90
|
)
|
|||
Operating loss
|
|
(113
|
)
|
|
(29
|
)
|
|
(84
|
)
|
|||
Depreciation and amortization expense
|
|
232
|
|
|
243
|
|
|
(11
|
)
|
|||
Earnings from unconsolidated investments
|
|
5
|
|
|
—
|
|
|
5
|
|
|||
Other income and expense, net
|
|
—
|
|
|
1
|
|
|
(1
|
)
|
|||
EBITDA
|
|
124
|
|
|
215
|
|
|
(91
|
)
|
|||
Adjustments to reflect Adjusted EBITDA from unconsolidated investment
|
|
2
|
|
|
—
|
|
|
2
|
|
|||
Mark-to-market adjustments
|
|
75
|
|
|
(44
|
)
|
|
119
|
|
|||
Loss on sale of assets, net
|
|
90
|
|
|
—
|
|
|
90
|
|
|||
Other
|
|
2
|
|
|
—
|
|
|
2
|
|
|||
Adjusted EBITDA
|
|
$
|
293
|
|
|
$
|
171
|
|
|
$
|
122
|
|
|
|
|
|
|
|
|
||||||
Million Megawatt Hours Generated (1)
|
|
19.2
|
|
|
16.9
|
|
|
2.3
|
|
|||
IMA for Combined-Cycle Facilities (1)(2)
|
|
96
|
%
|
|
96
|
%
|
|
|
||||
Average Capacity Factor for Combined-Cycle Facilities (1)(3)
|
|
43
|
%
|
|
48
|
%
|
|
|
||||
CDDs (4)
|
|
721
|
|
|
884
|
|
|
(163
|
)
|
|||
HDDs (4)
|
|
5,495
|
|
|
5,593
|
|
|
(98
|
)
|
|||
Average Market On-Peak Spark Spreads ($/MWh) (5):
|
|
|
|
|
|
|
||||||
New York—Zone C
|
|
$
|
14.78
|
|
|
$
|
16.46
|
|
|
$
|
(1.68
|
)
|
Mass Hub
|
|
$
|
12.09
|
|
|
$
|
13.80
|
|
|
$
|
(1.71
|
)
|
Average Market On-Peak Power Prices ($/MWh) (6):
|
|
|
|
|
|
|
||||||
New York—Zone C
|
|
$
|
29.56
|
|
|
$
|
26.88
|
|
|
$
|
2.68
|
|
Mass Hub
|
|
$
|
37.83
|
|
|
$
|
35.52
|
|
|
$
|
2.31
|
|
Average natural gas price—Algonquin Citygates ($/MMBtu) (7)
|
|
$
|
3.68
|
|
|
$
|
3.10
|
|
|
$
|
0.58
|
|
(1)
|
Includes the activity of the assets acquired in the ENGIE Acquisition for our period of ownership. Million Megawatt Hours Generated and Average Capacity Factor include such activity for the full month of February. IMA excludes such activity for our period of ownership in February.
|
(2)
|
IMA is an internal measurement calculation that reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched. The calculation excludes certain events outside of management control such as weather related issues. The calculation excludes our Brayton Point facility.
|
(3)
|
Reflects actual production as a percentage of available capacity. The calculation excludes our Brayton Point facility.
|
(4)
|
Reflects CDDs or HDDs for the ISO-NE Region based on NOAA data.
|
(5)
|
Reflects the average of the on-peak spark spreads available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas at a daily cash market price and does not reflect spark spreads available to us.
|
(6)
|
Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.
|
(7)
|
Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us.
|
|
|
Year Ended December 31,
|
|
Favorable (Unfavorable) $ Change
|
||||||||
(dollars in millions, except for price information)
|
|
2017
|
|
2016
|
|
|||||||
Operating revenues
|
|
|
|
|
|
|
||||||
Energy
|
|
$
|
366
|
|
|
$
|
—
|
|
|
N/A
|
|
|
Mark-to-market loss, net
|
|
(99
|
)
|
|
—
|
|
|
N/A
|
|
|||
Other
|
|
10
|
|
|
—
|
|
|
N/A
|
|
|||
Total operating revenues
|
|
277
|
|
|
—
|
|
|
N/A
|
|
|||
Operating costs
|
|
|
|
|
|
|
||||||
Cost of sales
|
|
(256
|
)
|
|
—
|
|
|
N/A
|
|
|||
Total operating costs
|
|
(256
|
)
|
|
—
|
|
|
N/A
|
|
|||
Gross margin
|
|
21
|
|
|
—
|
|
|
N/A
|
|
|||
Operating and maintenance expense
|
|
(95
|
)
|
|
—
|
|
|
N/A
|
|
|||
Depreciation expense
|
|
(73
|
)
|
|
—
|
|
|
N/A
|
|
|||
Operating loss
|
|
(147
|
)
|
|
—
|
|
|
N/A
|
|
|||
Depreciation and amortization expense
|
|
74
|
|
|
—
|
|
|
N/A
|
|
|||
EBITDA
|
|
(73
|
)
|
|
—
|
|
|
N/A
|
|
|||
Mark-to-market adjustments
|
|
99
|
|
|
—
|
|
|
N/A
|
|
|||
Adjusted EBITDA
|
|
$
|
26
|
|
|
$
|
—
|
|
|
N/A
|
|
|
|
|
|
|
|
|
|
||||||
Million Megawatt Hours Generated (1)
|
|
11.0
|
|
|
—
|
|
|
N/A
|
|
|||
IMA (1)(2):
|
|
|
|
|
|
|
||||||
Combined-Cycle Facilities
|
|
94
|
%
|
|
—
|
%
|
|
|
||||
Coal-Fired Facility
|
|
96
|
%
|
|
—
|
%
|
|
|
||||
Average Capacity Factor (1)(3):
|
|
|
|
|
|
|
||||||
Combined-Cycle Facilities
|
|
25
|
%
|
|
—
|
%
|
|
|
||||
Coal-Fired Facility
|
|
67
|
%
|
|
—
|
%
|
|
|
||||
CDDs (4)
|
|
3,390
|
|
|
3,355
|
|
|
35
|
|
|||
HDDs (4)
|
|
1,090
|
|
|
1,222
|
|
|
(132
|
)
|
|||
Average Market On-Peak Spark Spreads ($/MWh) (5):
|
|
|
|
|
|
|
||||||
ERCOT North
|
|
$
|
7.79
|
|
|
$
|
9.79
|
|
|
$
|
(2.00
|
)
|
Average Market On-Peak Power Prices ($/MWh) (6):
|
|
|
|
|
|
|
||||||
ERCOT North
|
|
$
|
26.45
|
|
|
$
|
26.02
|
|
|
$
|
0.43
|
|
Average natural gas price—Waha Hub ($/MMBtu) (7)
|
|
$
|
2.67
|
|
|
$
|
2.32
|
|
|
$
|
0.35
|
|
(1)
|
Million Megawatt Hours Generated and Average Capacity Factor include such activity for the full month of February. IMA excludes such activity for our period of ownership in February.
|
(2)
|
IMA is an internal measurement calculation that reflects the percentage of generation available when market prices are such that these units could be profitably dispatched. The calculation excludes certain events outside of management control such as weather related issues. The calculation excludes CTs.
|
(3)
|
Reflects actual production as a percentage of available capacity. The calculation excludes CTs.
|
(4)
|
Reflects CDDs or HDDs for the ERCOT Region based on NOAA data.
|
(5)
|
Reflects the average of the on-peak spark spreads available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas at a daily cash market price and does not reflect spark spreads available to us.
|
(6)
|
Reflects the average of day-ahead settled prices for the periods presented and does not necessarily reflect prices we realized.
|
(7)
|
Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us.
|
|
|
Year Ended December 31,
|
|
Favorable (Unfavorable) $ Change
|
||||||||
(dollars in millions, except for price information)
|
|
2017
|
|
2016
|
|
|||||||
Operating Revenues
|
|
|
|
|
|
|
||||||
Energy
|
|
$
|
920
|
|
|
$
|
1,027
|
|
|
$
|
(107
|
)
|
Capacity
|
|
210
|
|
|
163
|
|
|
47
|
|
|||
Mark-to-market income (loss), net
|
|
21
|
|
|
(47
|
)
|
|
68
|
|
|||
Contract amortization
|
|
(6
|
)
|
|
(13
|
)
|
|
7
|
|
|||
Other
|
|
7
|
|
|
7
|
|
|
—
|
|
|||
Total operating revenues
|
|
1,152
|
|
|
1,137
|
|
|
15
|
|
|||
Operating Costs
|
|
|
|
|
|
|
||||||
Cost of sales
|
|
(731
|
)
|
|
(762
|
)
|
|
31
|
|
|||
Contract amortization
|
|
8
|
|
|
21
|
|
|
(13
|
)
|
|||
Total operating costs
|
|
(723
|
)
|
|
(741
|
)
|
|
18
|
|
|||
Gross margin
|
|
429
|
|
|
396
|
|
|
33
|
|
|||
Operating and maintenance expense
|
|
(300
|
)
|
|
(347
|
)
|
|
47
|
|
|||
Depreciation expense
|
|
(75
|
)
|
|
(81
|
)
|
|
6
|
|
|||
Impairments
|
|
(99
|
)
|
|
(793
|
)
|
|
694
|
|
|||
Gain on sale of assets, net
|
|
1
|
|
|
1
|
|
|
—
|
|
|||
Acquisition and integration costs
|
|
—
|
|
|
8
|
|
|
(8
|
)
|
|||
Other
|
|
—
|
|
|
(16
|
)
|
|
16
|
|
|||
Operating loss
|
|
(44
|
)
|
|
(832
|
)
|
|
788
|
|
|||
Depreciation and amortization expense
|
|
91
|
|
|
87
|
|
|
4
|
|
|||
Bankruptcy reorganization items
|
|
494
|
|
|
(96
|
)
|
|
590
|
|
|||
Other income and expense, net
|
|
26
|
|
|
15
|
|
|
11
|
|
|||
EBITDA
|
|
567
|
|
|
(826
|
)
|
|
1,393
|
|
|||
Adjustments to reflect Adjusted EBITDA from noncontrolling interest
|
|
2
|
|
|
2
|
|
|
—
|
|
|||
Acquisition, integration, restructuring and bankruptcy reorganization costs
|
|
—
|
|
|
(8
|
)
|
|
8
|
|
|||
Bankruptcy reorganization items
|
|
(494
|
)
|
|
96
|
|
|
(590
|
)
|
|||
Mark-to-market adjustments
|
|
(21
|
)
|
|
47
|
|
|
(68
|
)
|
|||
Impairments
|
|
99
|
|
|
793
|
|
|
(694
|
)
|
|||
Gain on sale of assets, net
|
|
(1
|
)
|
|
(1
|
)
|
|
—
|
|
|||
Non-cash compensation expense
|
|
1
|
|
|
6
|
|
|
(5
|
)
|
|||
Other (1)
|
|
(1
|
)
|
|
20
|
|
|
(21
|
)
|
|||
Adjusted EBITDA
|
|
$
|
152
|
|
|
$
|
129
|
|
|
$
|
23
|
|
|
|
|
|
|
|
|
||||||
Million Megawatt Hours Generated
|
|
29.1
|
|
|
29.8
|
|
|
(0.7
|
)
|
|||
IMA for Coal-Fired Facilities (2)
|
|
89
|
%
|
|
89
|
%
|
|
|
||||
Average Capacity Factor for Coal-Fired Facilities (3)
|
|
63
|
%
|
|
53
|
%
|
|
|
||||
CDDs (4)
|
|
1,272
|
|
|
1,652
|
|
|
(380
|
)
|
|||
HDDs (4)
|
|
4,534
|
|
|
4,662
|
|
|
(128
|
)
|
|||
Average Market On-Peak Power Prices ($/MWh) (5):
|
|
|
|
|
|
|
||||||
Indiana (Indy Hub)
|
|
$
|
34.36
|
|
|
$
|
33.71
|
|
|
$
|
0.65
|
|
Commonwealth Edison (NI Hub)
|
|
$
|
32.28
|
|
|
$
|
31.98
|
|
|
$
|
0.30
|
|
(1)
|
Other includes an adjustment to exclude Wood River’s energy margin and O&M costs of $23 million for the
year ended December 31, 2016
. Adjusted EBITDA did not include this adjustment for the
year ended December 31, 2017
.
|
(2)
|
IMA is an internal measurement calculation that reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched. The calculation excludes certain events outside of management control such as weather related issues.
|
(3)
|
Reflects actual production as a percentage of available capacity.
|
(4)
|
Reflects CDDs or HDDs for the MISO Region based on NOAA data.
|
(5)
|
Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.
|
|
|
Year Ended December 31,
|
|
Favorable (Unfavorable) $ Change
|
||||||||
(dollars in millions, except for price information)
|
|
2017
|
|
2016
|
|
|||||||
Operating Revenues
|
|
|
|
|
|
|
||||||
Energy
|
|
$
|
108
|
|
|
$
|
88
|
|
|
$
|
20
|
|
Capacity
|
|
18
|
|
|
40
|
|
|
(22
|
)
|
|||
Mark-to-market loss, net
|
|
(7
|
)
|
|
—
|
|
|
(7
|
)
|
|||
Contract amortization
|
|
—
|
|
|
(10
|
)
|
|
10
|
|
|||
Other
|
|
3
|
|
|
24
|
|
|
(21
|
)
|
|||
Total operating revenues
|
|
122
|
|
|
142
|
|
|
(20
|
)
|
|||
Operating Costs
|
|
|
|
|
|
|
||||||
Cost of sales
|
|
(78
|
)
|
|
(69
|
)
|
|
(9
|
)
|
|||
Total operating costs
|
|
(78
|
)
|
|
(69
|
)
|
|
(9
|
)
|
|||
Gross margin
|
|
44
|
|
|
73
|
|
|
(29
|
)
|
|||
Operating and maintenance expense
|
|
(39
|
)
|
|
(36
|
)
|
|
(3
|
)
|
|||
Depreciation expense
|
|
(53
|
)
|
|
(42
|
)
|
|
(11
|
)
|
|||
Gain on sale of assets, net
|
|
3
|
|
|
—
|
|
|
3
|
|
|||
Operating loss
|
|
(45
|
)
|
|
(5
|
)
|
|
(40
|
)
|
|||
Depreciation and amortization expense
|
|
57
|
|
|
53
|
|
|
4
|
|
|||
Other income and expense, net
|
|
—
|
|
|
12
|
|
|
(12
|
)
|
|||
EBITDA
|
|
12
|
|
|
60
|
|
|
(48
|
)
|
|||
Mark-to-market adjustments
|
|
7
|
|
|
—
|
|
|
7
|
|
|||
Other
|
|
—
|
|
|
(1
|
)
|
|
1
|
|
|||
Adjusted EBITDA
|
|
$
|
19
|
|
|
$
|
59
|
|
|
$
|
(40
|
)
|
|
|
|
|
|
|
|
||||||
Million Megawatt Hours Generated
|
|
2.3
|
|
|
2.6
|
|
|
(0.3
|
)
|
|||
IMA for Combined-Cycle Facilities (1)
|
|
92
|
%
|
|
96
|
%
|
|
|
||||
Average Capacity Factor for Combined-Cycle Facilities (2)
|
|
26
|
%
|
|
27
|
%
|
|
|
||||
CDDs (3)
|
|
1,337
|
|
|
1,211
|
|
|
126
|
|
|||
HDDs (3)
|
|
1,233
|
|
|
1,218
|
|
|
15
|
|
|||
Average Market On-Peak Spark Spreads ($/MWh) (4):
|
|
|
|
|
|
|
||||||
North of Path 15 (NP 15)
|
|
$
|
15.38
|
|
|
$
|
12.67
|
|
|
$
|
2.71
|
|
Average Market On-Peak Power Prices ($/MWh) (5):
|
|
|
|
|
|
|
||||||
North of Path 15 (NP 15)
|
|
$
|
38.02
|
|
|
$
|
31.60
|
|
|
$
|
6.42
|
|
Average natural gas price—PG&E Citygate ($/MMBtu) (6)
|
|
$
|
3.23
|
|
|
$
|
2.70
|
|
|
$
|
0.53
|
|
(1)
|
IMA is an internal measurement calculation that reflects the percentage of generation available when market prices are such that these units could be profitably dispatched. This calculation excludes certain events outside of management control such as weather related issues. The calculation excludes CTs.
|
(2)
|
Reflects actual production as a percentage of available capacity. The calculation excludes CTs.
|
(3)
|
Reflects CDDs or HDDs for the ISO-NE Region based on NOAA data.
|
(4)
|
Reflects the average of the on-peak spark spreads available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas at a daily cash market price and does not reflect spark spreads available to us.
|
(5)
|
Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.
|
(6)
|
Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us.
|
|
|
Year Ended December 31,
|
|
Favorable (Unfavorable) $ Change
|
||||||||
(amounts in millions)
|
|
2016
|
|
2015
|
|
|||||||
Revenues
|
|
|
|
|
|
|
||||||
Energy
|
|
$
|
3,366
|
|
|
$
|
3,083
|
|
|
$
|
283
|
|
Capacity
|
|
769
|
|
|
626
|
|
|
143
|
|
|||
Mark-to-market income, net
|
|
136
|
|
|
127
|
|
|
9
|
|
|||
Contract amortization
|
|
(80
|
)
|
|
(83
|
)
|
|
3
|
|
|||
Other
|
|
127
|
|
|
117
|
|
|
10
|
|
|||
Total revenues
|
|
4,318
|
|
|
3,870
|
|
|
448
|
|
|||
Cost of sales, excluding depreciation expense
|
|
(2,281
|
)
|
|
(2,028
|
)
|
|
(253
|
)
|
|||
Gross margin
|
|
2,037
|
|
|
1,842
|
|
|
195
|
|
|||
Operating and maintenance expense
|
|
(940
|
)
|
|
(839
|
)
|
|
(101
|
)
|
|||
Depreciation expense
|
|
(689
|
)
|
|
(587
|
)
|
|
(102
|
)
|
|||
Impairments
|
|
(858
|
)
|
|
(99
|
)
|
|
(759
|
)
|
|||
Loss on sale of assets, net
|
|
(1
|
)
|
|
(1
|
)
|
|
—
|
|
|||
General and administrative expense
|
|
(161
|
)
|
|
(128
|
)
|
|
(33
|
)
|
|||
Acquisition and integration costs
|
|
(11
|
)
|
|
(124
|
)
|
|
113
|
|
|||
Other
|
|
(17
|
)
|
|
—
|
|
|
(17
|
)
|
|||
Operating income (loss)
|
|
(640
|
)
|
|
64
|
|
|
(704
|
)
|
|||
Bankruptcy reorganization items
|
|
(96
|
)
|
|
—
|
|
|
(96
|
)
|
|||
Earnings from unconsolidated investments
|
|
7
|
|
|
1
|
|
|
6
|
|
|||
Interest expense
|
|
(625
|
)
|
|
(546
|
)
|
|
(79
|
)
|
|||
Other income and expense, net
|
|
65
|
|
|
54
|
|
|
11
|
|
|||
Loss before income taxes
|
|
(1,289
|
)
|
|
(427
|
)
|
|
(862
|
)
|
|||
Income tax benefit
|
|
45
|
|
|
474
|
|
|
(429
|
)
|
|||
Net income (loss)
|
|
(1,244
|
)
|
|
47
|
|
|
(1,291
|
)
|
|||
Less: Net loss attributable to noncontrolling interest
|
|
(4
|
)
|
|
(3
|
)
|
|
(1
|
)
|
|||
Net income (loss) attributable to Dynegy Inc.
|
|
$
|
(1,240
|
)
|
|
$
|
50
|
|
|
$
|
(1,290
|
)
|
|
|
Year Ended December 31, 2016
|
||||||||||||||||||||||
(amounts in millions)
|
|
PJM
|
|
NY/NE
|
|
MISO
|
|
CAISO
|
|
Other
|
|
Total
|
||||||||||||
Revenues
|
|
$
|
2,202
|
|
|
$
|
837
|
|
|
$
|
1,137
|
|
|
$
|
142
|
|
|
$
|
—
|
|
|
$
|
4,318
|
|
Cost of sales, excluding depreciation expense
|
|
(985
|
)
|
|
(486
|
)
|
|
(741
|
)
|
|
(69
|
)
|
|
—
|
|
|
(2,281
|
)
|
||||||
Gross margin
|
|
1,217
|
|
|
351
|
|
|
396
|
|
|
73
|
|
|
—
|
|
|
2,037
|
|
||||||
Operating and maintenance expense
|
|
(391
|
)
|
|
(165
|
)
|
|
(347
|
)
|
|
(36
|
)
|
|
(1
|
)
|
|
(940
|
)
|
||||||
Depreciation expense
|
|
(346
|
)
|
|
(215
|
)
|
|
(81
|
)
|
|
(42
|
)
|
|
(5
|
)
|
|
(689
|
)
|
||||||
Impairments
|
|
(65
|
)
|
|
—
|
|
|
(793
|
)
|
|
—
|
|
|
—
|
|
|
(858
|
)
|
||||||
Gain (loss) on sale of assets, net
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
(2
|
)
|
|
(1
|
)
|
||||||
General and administrative expense
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(161
|
)
|
|
(161
|
)
|
||||||
Acquisition and integration costs
|
|
—
|
|
|
—
|
|
|
8
|
|
|
—
|
|
|
(19
|
)
|
|
(11
|
)
|
||||||
Other
|
|
(1
|
)
|
|
—
|
|
|
(16
|
)
|
|
—
|
|
|
—
|
|
|
(17
|
)
|
||||||
Operating income (loss)
|
|
$
|
414
|
|
|
$
|
(29
|
)
|
|
$
|
(832
|
)
|
|
$
|
(5
|
)
|
|
$
|
(188
|
)
|
|
$
|
(640
|
)
|
|
|
Year Ended December 31, 2015
|
||||||||||||||||||||||
(amounts in millions)
|
|
PJM
|
|
NY/NE
|
|
MISO
|
|
CAISO
|
|
Other
|
|
Total
|
||||||||||||
Revenues
|
|
$
|
1,716
|
|
|
$
|
695
|
|
|
$
|
1,281
|
|
|
$
|
178
|
|
|
$
|
—
|
|
|
$
|
3,870
|
|
Cost of sales, excluding depreciation expense
|
|
(716
|
)
|
|
(414
|
)
|
|
(793
|
)
|
|
(105
|
)
|
|
—
|
|
|
(2,028
|
)
|
||||||
Gross margin
|
|
1,000
|
|
|
281
|
|
|
488
|
|
|
73
|
|
|
—
|
|
|
1,842
|
|
||||||
Operating and maintenance expense
|
|
(296
|
)
|
|
(126
|
)
|
|
(389
|
)
|
|
(32
|
)
|
|
4
|
|
|
(839
|
)
|
||||||
Depreciation expense
|
|
(281
|
)
|
|
(186
|
)
|
|
(68
|
)
|
|
(48
|
)
|
|
(4
|
)
|
|
(587
|
)
|
||||||
Impairments
|
|
—
|
|
|
(25
|
)
|
|
(74
|
)
|
|
—
|
|
|
—
|
|
|
(99
|
)
|
||||||
Loss on sale of assets, net
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
||||||
General and administrative expense
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(128
|
)
|
|
(128
|
)
|
||||||
Acquisition and integration costs
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(124
|
)
|
|
(124
|
)
|
||||||
Operating income (loss)
|
|
$
|
423
|
|
|
$
|
(56
|
)
|
|
$
|
(43
|
)
|
|
$
|
(8
|
)
|
|
$
|
(252
|
)
|
|
$
|
64
|
|
(amounts in millions)
|
|
PJM
|
|
NY/NE
|
|
MISO
|
|
CAISO
|
|
Total
|
||||||||||
Revenues, net of hedges, attributable to Duke Midwest and EquiPower plants for the first quarter of 2016
|
|
$
|
467
|
|
|
$
|
194
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
661
|
|
Lower power prices and spark spreads
|
|
(66
|
)
|
|
(26
|
)
|
|
(13
|
)
|
|
—
|
|
|
(105
|
)
|
|||||
Higher (lower) generation volumes (1)
|
|
122
|
|
|
(64
|
)
|
|
(139
|
)
|
|
(39
|
)
|
|
(120
|
)
|
|||||
Higher (lower) capacity revenues
|
|
(36
|
)
|
|
(17
|
)
|
|
67
|
|
|
9
|
|
|
23
|
|
|||||
Change in MTM value of derivative transactions
|
|
(61
|
)
|
|
41
|
|
|
(63
|
)
|
|
(4
|
)
|
|
(87
|
)
|
|||||
Lower (higher) contract amortization
|
|
9
|
|
|
(4
|
)
|
|
12
|
|
|
(3
|
)
|
|
14
|
|
|||||
Other (2)
|
|
51
|
|
|
18
|
|
|
(8
|
)
|
|
1
|
|
|
62
|
|
|||||
Total change in revenues
|
|
$
|
486
|
|
|
$
|
142
|
|
|
$
|
(144
|
)
|
|
$
|
(36
|
)
|
|
$
|
448
|
|
(1)
|
Decrease due to mild winter weather which decreased demand across our key markets as well as planned outages and shutdowns; PJM segment increased due to higher demand for gas-fired generation as a result of lower gas prices.
|
(2)
|
Other primarily consists of ancillary, tolling, transmission and gas revenues.
|
(amounts in millions)
|
|
PJM
|
|
NY/NE
|
|
MISO
|
|
CAISO
|
|
Total
|
||||||||||
Cost of sales attributable to Duke Midwest and EquiPower plants for the first quarter of 2016
|
|
$
|
157
|
|
|
$
|
128
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
285
|
|
Higher (lower) prices
|
|
(95
|
)
|
|
(13
|
)
|
|
23
|
|
|
(7
|
)
|
|
(92
|
)
|
|||||
Higher (lower) burn volumes (1)
|
|
133
|
|
|
(23
|
)
|
|
(101
|
)
|
|
(19
|
)
|
|
(10
|
)
|
|||||
Higher (lower) transportation costs (2)
|
|
3
|
|
|
(16
|
)
|
|
—
|
|
|
(1
|
)
|
|
(14
|
)
|
|||||
Lower (higher) contract amortization
|
|
20
|
|
|
(3
|
)
|
|
16
|
|
|
—
|
|
|
33
|
|
|||||
Other (3)
|
|
51
|
|
|
(1
|
)
|
|
10
|
|
|
(9
|
)
|
|
51
|
|
|||||
Total change in cost of sales
|
|
$
|
269
|
|
|
$
|
72
|
|
|
$
|
(52
|
)
|
|
$
|
(36
|
)
|
|
$
|
253
|
|
(1)
|
Lower burn volumes primarily due to mild winter weather which decreased demand across our key markets as well as planned outages and shutdowns; PJM segment increased as a result of higher plant availability and demand.
|
(2)
|
Lower transportation costs primarily at our NY/NE segment due to reduced demand charge payment at Independence.
|
(3)
|
Other primarily consists of transmission expenses, gas purchases, and various non-recurring expenses.
|
|
|
Year Ended December 31,
|
||||||
Description
|
|
2016
|
|
2015
|
||||
Property, plant and equipment
|
|
$
|
849
|
|
|
$
|
99
|
|
Equity investment
|
|
9
|
|
|
—
|
|
||
Total
|
|
$
|
858
|
|
|
$
|
99
|
|
|
|
Year Ended December 31, 2016
|
||||||||||||||||||||||
(amounts in millions)
|
|
PJM
|
|
NY/NE
|
|
MISO
|
|
CAISO
|
|
Other
|
|
Total
|
||||||||||||
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(1,244
|
)
|
||||||||||
Income tax benefit
|
|
|
|
|
|
|
|
|
|
|
|
(45
|
)
|
|||||||||||
Other income and expense, net
|
|
|
|
|
|
|
|
|
|
|
|
(65
|
)
|
|||||||||||
Interest expense
|
|
|
|
|
|
|
|
|
|
|
|
625
|
|
|||||||||||
Earnings from unconsolidated investments
|
|
|
|
|
|
|
|
|
|
|
|
(7
|
)
|
|||||||||||
Bankruptcy reorganization items
|
|
|
|
|
|
|
|
|
|
|
|
96
|
|
|||||||||||
Operating income (loss)
|
|
$
|
414
|
|
|
$
|
(29
|
)
|
|
$
|
(832
|
)
|
|
$
|
(5
|
)
|
|
$
|
(188
|
)
|
|
$
|
(640
|
)
|
Depreciation and amortization expense
|
|
349
|
|
|
243
|
|
|
87
|
|
|
53
|
|
|
5
|
|
|
737
|
|
||||||
Bankruptcy reorganization items
|
|
—
|
|
|
—
|
|
|
(96
|
)
|
|
—
|
|
|
—
|
|
|
(96
|
)
|
||||||
Earnings from unconsolidated investments
|
|
7
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
7
|
|
||||||
Other income and expense, net
|
|
9
|
|
|
1
|
|
|
15
|
|
|
12
|
|
|
28
|
|
|
65
|
|
||||||
EBITDA
|
|
779
|
|
|
215
|
|
|
(826
|
)
|
|
60
|
|
|
(155
|
)
|
|
73
|
|
||||||
Adjustments to reflect Adjusted EBITDA from unconsolidated investment and exclude noncontrolling interest
|
|
—
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
2
|
|
||||||
Acquisition and integration costs
|
|
—
|
|
|
—
|
|
|
(8
|
)
|
|
—
|
|
|
29
|
|
|
21
|
|
||||||
Bankruptcy reorganization items
|
|
—
|
|
|
—
|
|
|
96
|
|
|
—
|
|
|
—
|
|
|
96
|
|
||||||
Mark-to-market adjustments, including warrants
|
|
(92
|
)
|
|
(44
|
)
|
|
47
|
|
|
—
|
|
|
(6
|
)
|
|
(95
|
)
|
||||||
Impairments
|
|
65
|
|
|
—
|
|
|
793
|
|
|
—
|
|
|
—
|
|
|
858
|
|
||||||
Loss (gain) on sale of assets, net
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
2
|
|
|
1
|
|
||||||
Non-cash compensation expense
|
|
—
|
|
|
—
|
|
|
6
|
|
|
—
|
|
|
22
|
|
|
28
|
|
||||||
Other (1)
|
|
5
|
|
|
—
|
|
|
20
|
|
|
(1
|
)
|
|
(1
|
)
|
|
23
|
|
||||||
Adjusted EBITDA
|
|
$
|
757
|
|
|
$
|
171
|
|
|
$
|
129
|
|
|
$
|
59
|
|
|
$
|
(109
|
)
|
|
$
|
1,007
|
|
(1)
|
Other includes an adjustment to exclude Wood River’s energy margin and O&M costs of $23 million.
|
|
|
Year Ended December 31, 2015
|
||||||||||||||||||||||
(amounts in millions)
|
|
PJM
|
|
NY/NE
|
|
MISO
|
|
CAISO
|
|
Other
|
|
Total
|
||||||||||||
Net income
|
|
|
|
|
|
|
|
|
|
|
|
$
|
47
|
|
||||||||||
Income tax benefit
|
|
|
|
|
|
|
|
|
|
|
|
(474
|
)
|
|||||||||||
Other income and expense, net
|
|
|
|
|
|
|
|
|
|
|
|
(54
|
)
|
|||||||||||
Interest expense
|
|
|
|
|
|
|
|
|
|
|
|
546
|
|
|||||||||||
Earnings from unconsolidated investments
|
|
|
|
|
|
|
|
|
|
|
|
(1
|
)
|
|||||||||||
Operating income (loss)
|
|
$
|
423
|
|
|
$
|
(56
|
)
|
|
$
|
(43
|
)
|
|
$
|
(8
|
)
|
|
$
|
(252
|
)
|
|
$
|
64
|
|
Depreciation and amortization expense
|
|
275
|
|
|
195
|
|
|
73
|
|
|
55
|
|
|
4
|
|
|
602
|
|
||||||
Earnings from unconsolidated investments
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
||||||
Other income and expense, net
|
|
(2
|
)
|
|
—
|
|
|
1
|
|
|
—
|
|
|
55
|
|
|
54
|
|
||||||
EBITDA
|
|
697
|
|
|
139
|
|
|
31
|
|
|
47
|
|
|
(193
|
)
|
|
721
|
|
||||||
Adjustments to reflect Adjusted EBITDA from unconsolidated investment and exclude noncontrolling interest
|
|
12
|
|
|
—
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
15
|
|
||||||
Acquisition and integration costs
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
124
|
|
|
124
|
|
||||||
Mark-to-market adjustments, including warrants
|
|
(58
|
)
|
|
11
|
|
|
(16
|
)
|
|
(4
|
)
|
|
(54
|
)
|
|
(121
|
)
|
||||||
Impairments
|
|
—
|
|
|
25
|
|
|
74
|
|
|
—
|
|
|
—
|
|
|
99
|
|
||||||
Loss on sale of assets, net
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
||||||
Other (1)
|
|
(2
|
)
|
|
—
|
|
|
12
|
|
|
—
|
|
|
1
|
|
|
11
|
|
||||||
Adjusted EBITDA (2)
|
|
$
|
649
|
|
|
$
|
175
|
|
|
$
|
104
|
|
|
$
|
44
|
|
|
$
|
(122
|
)
|
|
$
|
850
|
|
(1)
|
Other includes an adjustment to exclude costs related to the Baldwin transformer project of $7 million.
|
(2)
|
Not adjusted for the following items which are excluded in 2016: (i) non-cash compensation expense of $27 million, and (ii) Wood River’s energy margin and O&M costs of $13 million.
|
|
|
Year Ended December 31,
|
|
Favorable (Unfavorable) $ Change
|
||||||||
(dollars in millions, except for price information)
|
|
2016
|
|
2015
|
|
|||||||
Operating Revenues
|
|
|
|
|
|
|
||||||
Energy
|
|
$
|
1,681
|
|
|
$
|
1,257
|
|
|
$
|
424
|
|
Capacity
|
|
398
|
|
|
345
|
|
|
53
|
|
|||
Mark-to-market income, net
|
|
118
|
|
|
105
|
|
|
13
|
|
|||
Contract amortization
|
|
(47
|
)
|
|
(47
|
)
|
|
—
|
|
|||
Other
|
|
52
|
|
|
56
|
|
|
(4
|
)
|
|||
Total operating revenues
|
|
2,202
|
|
|
1,716
|
|
|
486
|
|
|||
Operating Costs
|
|
|
|
|
|
|
||||||
Cost of sales
|
|
(1,033
|
)
|
|
(771
|
)
|
|
(262
|
)
|
|||
Contract amortization
|
|
48
|
|
|
55
|
|
|
(7
|
)
|
|||
Total operating costs
|
|
(985
|
)
|
|
(716
|
)
|
|
(269
|
)
|
|||
Gross margin
|
|
1,217
|
|
|
1,000
|
|
|
217
|
|
|||
Operating and maintenance expense
|
|
(391
|
)
|
|
(296
|
)
|
|
(95
|
)
|
|||
Depreciation expense
|
|
(346
|
)
|
|
(281
|
)
|
|
(65
|
)
|
|||
Impairments
|
|
(65
|
)
|
|
—
|
|
|
(65
|
)
|
|||
Other
|
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
|||
Operating income
|
|
414
|
|
|
423
|
|
|
(9
|
)
|
|||
Depreciation and amortization expense
|
|
349
|
|
|
275
|
|
|
74
|
|
|||
Earnings from unconsolidated investments
|
|
7
|
|
|
1
|
|
|
6
|
|
|||
Other income and expense, net
|
|
9
|
|
|
(2
|
)
|
|
11
|
|
|||
EBITDA
|
|
779
|
|
|
697
|
|
|
82
|
|
|||
Adjustment to reflect Adjusted EBITDA from unconsolidated investment
|
|
—
|
|
|
12
|
|
|
(12
|
)
|
|||
Mark-to-market adjustments
|
|
(92
|
)
|
|
(58
|
)
|
|
(34
|
)
|
|||
Impairments
|
|
65
|
|
|
—
|
|
|
65
|
|
|||
Other
|
|
5
|
|
|
(2
|
)
|
|
7
|
|
|||
Adjusted EBITDA
|
|
$
|
757
|
|
|
$
|
649
|
|
|
$
|
108
|
|
|
|
|
|
|
|
|
||||||
Million Megawatt Hours Generated (1)
|
|
52.8
|
|
|
40.4
|
|
|
12.4
|
|
|||
IMA (1)(2):
|
|
|
|
|
|
|
||||||
Combined-Cycle Facilities
|
|
97
|
%
|
|
99
|
%
|
|
|
||||
Coal-Fired Facilities
|
|
80
|
%
|
|
74
|
%
|
|
|
||||
Average Capacity Factor (1)(3):
|
|
|
|
|
|
|
||||||
Combined-Cycle Facilities
|
|
74
|
%
|
|
75
|
%
|
|
|
||||
Coal-Fired Facilities
|
|
53
|
%
|
|
51
|
%
|
|
|
||||
CDDs (4)
|
|
1,417
|
|
|
1,218
|
|
|
199
|
|
|||
HDDs (4)
|
|
4,719
|
|
|
4,992
|
|
|
(273
|
)
|
|||
Average Market On-Peak Spark Spreads ($/MWh) (5):
|
|
|
|
|
|
|
||||||
PJM West
|
|
$
|
22.62
|
|
|
$
|
25.24
|
|
|
$
|
(2.62
|
)
|
AD Hub
|
|
$
|
22.52
|
|
|
$
|
28.22
|
|
|
$
|
(5.70
|
)
|
Average Market On-Peak Power Prices ($/MWh) (6):
|
|
|
|
|
|
|
||||||
PJM West
|
|
$
|
34.65
|
|
|
$
|
43.21
|
|
|
$
|
(8.56
|
)
|
AD Hub
|
|
$
|
32.93
|
|
|
$
|
37.52
|
|
|
$
|
(4.59
|
)
|
Average natural gas price—TetcoM3 ($/MMBtu) (7)
|
|
$
|
1.72
|
|
|
$
|
2.57
|
|
|
$
|
(0.85
|
)
|
(1)
|
Reflects the activity for the period in which the EquiPower and Duke Midwest acquisitions were included in our consolidated results.
|
(2)
|
IMA is an internal measurement calculation that reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched. The calculation excludes certain events outside of management control such as weather related issues. The calculation excludes CTs.
|
(3)
|
Reflects actual production as a percentage of available capacity. The calculation excludes CTs.
|
(4)
|
Reflects CDDs or HDDs for the PJM Region based on NOAA data.
|
(5)
|
Reflects the average of the on-peak spark spreads available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas at a daily cash market price and does not reflect spark spreads available to us.
|
(6)
|
Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.
|
(7)
|
Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us.
|
|
|
Year Ended December 31,
|
|
Favorable (Unfavorable) $ Change
|
||||||||
(dollars in millions, except for price information)
|
|
2016
|
|
2015
|
|
|||||||
Operating Revenues
|
|
|
|
|
|
|
||||||
Energy
|
|
$
|
570
|
|
|
$
|
524
|
|
|
$
|
46
|
|
Capacity
|
|
168
|
|
|
154
|
|
|
14
|
|
|||
Mark-to-market income, net
|
|
65
|
|
|
2
|
|
|
63
|
|
|||
Contract amortization
|
|
(10
|
)
|
|
(4
|
)
|
|
(6
|
)
|
|||
Other
|
|
44
|
|
|
19
|
|
|
25
|
|
|||
Total operating revenues
|
|
837
|
|
|
695
|
|
|
142
|
|
|||
Operating Costs
|
|
|
|
|
|
|
||||||
Cost of sales
|
|
(469
|
)
|
|
(410
|
)
|
|
(59
|
)
|
|||
Contract amortization
|
|
(17
|
)
|
|
(4
|
)
|
|
(13
|
)
|
|||
Total operating costs
|
|
(486
|
)
|
|
(414
|
)
|
|
(72
|
)
|
|||
Gross margin
|
|
351
|
|
|
281
|
|
|
70
|
|
|||
Operating and maintenance expense
|
|
(165
|
)
|
|
(126
|
)
|
|
(39
|
)
|
|||
Depreciation expense
|
|
(215
|
)
|
|
(186
|
)
|
|
(29
|
)
|
|||
Impairments
|
|
—
|
|
|
(25
|
)
|
|
25
|
|
|||
Operating loss
|
|
(29
|
)
|
|
(56
|
)
|
|
27
|
|
|||
Depreciation and amortization expense
|
|
243
|
|
|
195
|
|
|
48
|
|
|||
Other income and expense, net
|
|
1
|
|
|
—
|
|
|
1
|
|
|||
EBITDA
|
|
215
|
|
|
139
|
|
|
76
|
|
|||
Mark-to-market adjustments
|
|
(44
|
)
|
|
11
|
|
|
(55
|
)
|
|||
Impairments
|
|
—
|
|
|
25
|
|
|
(25
|
)
|
|||
Adjusted EBITDA
|
|
$
|
171
|
|
|
$
|
175
|
|
|
$
|
(4
|
)
|
|
|
|
|
|
|
|
||||||
Million Megawatt Hours Generated (1)
|
|
16.9
|
|
|
15.7
|
|
|
1.2
|
|
|||
IMA for Combined-Cycle Facilities (1)(2)
|
|
96
|
%
|
|
98
|
%
|
|
|
||||
Average Capacity Factor for Combined-Cycle Facilities (1)(3)
|
|
48
|
%
|
|
56
|
%
|
|
|
||||
CDDs (4)
|
|
884
|
|
|
820
|
|
|
64
|
|
|||
HDDs (4)
|
|
5,593
|
|
|
6,056
|
|
|
(463
|
)
|
|||
Average Market On-Peak Spark Spreads ($/MWh) (5):
|
|
|
|
|
|
|
||||||
New York—Zone C
|
|
$
|
16.46
|
|
|
$
|
24.76
|
|
|
$
|
(8.30
|
)
|
Mass Hub
|
|
$
|
13.80
|
|
|
$
|
15.23
|
|
|
$
|
(1.43
|
)
|
Average Market On-Peak Power Prices ($/MWh) (6):
|
|
|
|
|
|
|
||||||
New York—Zone C
|
|
$
|
26.88
|
|
|
$
|
35.05
|
|
|
$
|
(8.17
|
)
|
Mass Hub
|
|
$
|
35.52
|
|
|
$
|
48.96
|
|
|
$
|
(13.44
|
)
|
Average natural gas price—Algonquin Citygates ($/MMBtu) (7)
|
|
$
|
3.10
|
|
|
$
|
4.82
|
|
|
$
|
(1.72
|
)
|
(1)
|
Reflects the activity for the period in which the EquiPower and Duke Midwest acquisitions were included in our consolidated results.
|
(2)
|
IMA is an internal measurement calculation that reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched. The calculation excludes certain events outside of management control such as weather related issues. The calculation excludes our Brayton Point facility.
|
(3)
|
Reflects actual production as a percentage of available capacity. The calculation excludes our Brayton Point facility.
|
(4)
|
Reflects CDDs or HDDs for the ISO-NE Region based on NOAA data.
|
(5)
|
Reflects the average of the on-peak spark spreads available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas at a daily cash market price and does not reflect spark spreads available to us.
|
(6)
|
Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.
|
(7)
|
Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us.
|
|
|
Year Ended December 31,
|
|
Favorable (Unfavorable) $ Change
|
||||||||
(dollars in millions, except for price information)
|
|
2016
|
|
2015
|
|
|||||||
Operating Revenues
|
|
|
|
|
|
|
||||||
Energy
|
|
$
|
1,027
|
|
|
$
|
1,177
|
|
|
$
|
(150
|
)
|
Capacity
|
|
163
|
|
|
96
|
|
|
67
|
|
|||
Mark-to-market income (loss), net
|
|
(47
|
)
|
|
16
|
|
|
(63
|
)
|
|||
Contract amortization
|
|
(13
|
)
|
|
(25
|
)
|
|
12
|
|
|||
Other
|
|
7
|
|
|
17
|
|
|
(10
|
)
|
|||
Total operating revenues
|
|
1,137
|
|
|
1,281
|
|
|
(144
|
)
|
|||
Operating Costs
|
|
|
|
|
|
|
||||||
Cost of sales
|
|
(762
|
)
|
|
(830
|
)
|
|
68
|
|
|||
Contract amortization
|
|
21
|
|
|
37
|
|
|
(16
|
)
|
|||
Total operating costs
|
|
(741
|
)
|
|
(793
|
)
|
|
52
|
|
|||
Gross margin
|
|
396
|
|
|
488
|
|
|
(92
|
)
|
|||
Operating and maintenance expense
|
|
(347
|
)
|
|
(389
|
)
|
|
42
|
|
|||
Depreciation expense
|
|
(81
|
)
|
|
(68
|
)
|
|
(13
|
)
|
|||
Impairments
|
|
(793
|
)
|
|
(74
|
)
|
|
(719
|
)
|
|||
Gain on sale of assets, net
|
|
1
|
|
|
—
|
|
|
1
|
|
|||
Acquisition and integration costs
|
|
8
|
|
|
—
|
|
|
8
|
|
|||
Other
|
|
(16
|
)
|
|
—
|
|
|
(16
|
)
|
|||
Operating loss
|
|
(832
|
)
|
|
(43
|
)
|
|
(789
|
)
|
|||
Depreciation and amortization expense
|
|
87
|
|
|
73
|
|
|
14
|
|
|||
Bankruptcy reorganization items
|
|
(96
|
)
|
|
—
|
|
|
(96
|
)
|
|||
Other income and expense, net
|
|
15
|
|
|
1
|
|
|
14
|
|
|||
EBITDA
|
|
(826
|
)
|
|
31
|
|
|
(857
|
)
|
|||
Adjustments to reflect Adjusted EBITDA from noncontrolling interest
|
|
2
|
|
|
3
|
|
|
(1
|
)
|
|||
Acquisition, integration and restructuring costs
|
|
(8
|
)
|
|
—
|
|
|
(8
|
)
|
|||
Bankruptcy reorganization items
|
|
96
|
|
|
—
|
|
|
96
|
|
|||
Mark-to-market adjustments
|
|
47
|
|
|
(16
|
)
|
|
63
|
|
|||
Impairments
|
|
793
|
|
|
74
|
|
|
719
|
|
|||
Gain on sale of assets, net
|
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
|||
Non-cash compensation expense
|
|
6
|
|
|
—
|
|
|
6
|
|
|||
Other (1)
|
|
20
|
|
|
12
|
|
|
8
|
|
|||
Adjusted EBITDA
|
|
$
|
129
|
|
|
$
|
104
|
|
|
$
|
25
|
|
|
|
|
|
|
|
|
||||||
Million Megawatt Hours Generated
|
|
29.8
|
|
|
34.4
|
|
|
(4.6
|
)
|
|||
IMA for Coal-Fired Facilities (2)
|
|
89
|
%
|
|
88
|
%
|
|
|
||||
Average Capacity Factor for Coal-Fired Facilities (3)
|
|
53
|
%
|
|
56
|
%
|
|
|
||||
CDDs (4)
|
|
1,652
|
|
|
1,425
|
|
|
227
|
|
|||
HDDs (4)
|
|
4,662
|
|
|
5,061
|
|
|
(399
|
)
|
|||
Average Market On-Peak Power Prices ($/MWh) (5):
|
|
|
|
|
|
|
||||||
Indiana (Indy Hub)
|
|
$
|
33.71
|
|
|
$
|
33.50
|
|
|
$
|
0.21
|
|
Commonwealth Edison (NI Hub)
|
|
$
|
31.98
|
|
|
$
|
33.98
|
|
|
$
|
(2.00
|
)
|
(1)
|
Other includes an adjustment to exclude Wood River’s energy margin and O&M costs of $23 million for the
year ended December 31, 2016
. Adjusted EBITDA did not include this adjustment for the
year ended December 31, 2015
.
|
(2)
|
IMA is an internal measurement calculation that reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched. The calculation excludes certain events outside of management control such as weather related issues.
|
(3)
|
Reflects actual production as a percentage of available capacity.
|
(4)
|
Reflects CDDs or HDDs for the MISO Region based on NOAA data.
|
(5)
|
Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.
|
|
|
Year Ended December 31,
|
|
Favorable (Unfavorable) $ Change
|
||||||||
(dollars in millions, except for price information)
|
|
2016
|
|
2015
|
|
|||||||
Operating Revenues
|
|
|
|
|
|
|
||||||
Energy
|
|
$
|
88
|
|
|
$
|
125
|
|
|
$
|
(37
|
)
|
Capacity
|
|
40
|
|
|
31
|
|
|
9
|
|
|||
Mark-to-market income, net
|
|
—
|
|
|
4
|
|
|
(4
|
)
|
|||
Contract amortization
|
|
(10
|
)
|
|
(7
|
)
|
|
(3
|
)
|
|||
Other
|
|
24
|
|
|
25
|
|
|
(1
|
)
|
|||
Total operating revenues
|
|
142
|
|
|
178
|
|
|
(36
|
)
|
|||
Operating Costs
|
|
|
|
|
|
|
||||||
Cost of sales
|
|
(69
|
)
|
|
(105
|
)
|
|
36
|
|
|||
Total operating costs
|
|
(69
|
)
|
|
(105
|
)
|
|
36
|
|
|||
Gross margin
|
|
73
|
|
|
73
|
|
|
—
|
|
|||
Operating and maintenance expense
|
|
(36
|
)
|
|
(32
|
)
|
|
(4
|
)
|
|||
Depreciation expense
|
|
(42
|
)
|
|
(48
|
)
|
|
6
|
|
|||
Loss on sale of assets, net
|
|
—
|
|
|
(1
|
)
|
|
1
|
|
|||
Operating loss
|
|
(5
|
)
|
|
(8
|
)
|
|
3
|
|
|||
Depreciation and amortization expense
|
|
53
|
|
|
55
|
|
|
(2
|
)
|
|||
Other income and expense, net
|
|
12
|
|
|
—
|
|
|
12
|
|
|||
EBITDA
|
|
60
|
|
|
47
|
|
|
13
|
|
|||
Mark-to-market adjustments
|
|
—
|
|
|
(4
|
)
|
|
4
|
|
|||
Loss on sale of assets, net
|
|
—
|
|
|
1
|
|
|
(1
|
)
|
|||
Other
|
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
|||
Adjusted EBITDA
|
|
$
|
59
|
|
|
$
|
44
|
|
|
$
|
15
|
|
|
|
|
|
|
|
|
||||||
Million Megawatt Hours Generated
|
|
2.6
|
|
|
4.0
|
|
|
(1.4
|
)
|
|||
IMA for Combined-Cycle Facilities (1)
|
|
96
|
%
|
|
96
|
%
|
|
|
||||
Average Capacity Factor for Combined-Cycle Facilities (2)
|
|
27
|
%
|
|
38
|
%
|
|
|
||||
CDDs (3)
|
|
$
|
1,211
|
|
|
$
|
1,480
|
|
|
$
|
(269
|
)
|
HDDs (3)
|
|
$
|
1,218
|
|
|
$
|
1,237
|
|
|
$
|
(19
|
)
|
Average Market On-Peak Spark Spreads ($/MWh) (4):
|
|
|
|
|
|
|
||||||
North of Path 15 (NP 15)
|
|
$
|
12.67
|
|
|
$
|
14.32
|
|
|
$
|
(1.65
|
)
|
Average Market On-Peak Power Prices ($/MWh) (5):
|
|
|
|
|
|
|
||||||
North of Path 15 (NP 15)
|
|
$
|
31.60
|
|
|
$
|
35.23
|
|
|
$
|
(3.63
|
)
|
Average natural gas price—PG&E Citygate ($/MMBtu) (6)
|
|
$
|
2.70
|
|
|
$
|
2.99
|
|
|
$
|
(0.29
|
)
|
(1)
|
IMA is an internal measurement calculation that reflects the percentage of generation available when market prices are such that these units could be profitably dispatched. This calculation excludes certain events outside of management control such as weather related issues. The calculation excludes CTs.
|
(2)
|
Reflects actual production as a percentage of available capacity. The calculation excludes CTs.
|
(3)
|
Reflects CDDs or HDDs for the ISO-NE Region based on NOAA data.
|
(4)
|
Reflects the average of the on-peak spark spreads available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas at a daily cash market price and does not reflect spark spreads available to us.
|
(5)
|
Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.
|
(6)
|
Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us.
|
|
|
(in millions)
|
||
Lower energy margin, net of hedges, primarily due to lower generation volumes as a result of higher fuel costs
|
|
$
|
(7
|
)
|
Higher capacity revenues due to higher contracted volumes
|
|
$
|
9
|
|
|
|
2018
|
|
2019
|
|
2020 to 2022
|
Generation volumes hedged
|
|
78%
|
|
40%
|
|
5%
|
Coal requirements contracted (1)
|
|
99%
|
|
100%
|
|
33%
|
Coal requirements priced (1)
|
|
99%
|
|
58%
|
|
6%
|
Coal transportation requirements contracted (1)
|
|
100%
|
|
100%
|
|
100%
|
(1)
|
Excludes non-operated jointly-owned generating units.
|
|
|
2017-2018
|
|
2018-2019
|
|
2019-2020
|
|
2020-2021
|
||||||||||||||||||||
(price per MW-day)
|
|
Legacy Capacity
|
|
CP
|
|
Base
|
|
CP
|
|
Base
|
|
CP
|
|
CP
|
||||||||||||||
RTO zone (1)
|
|
$
|
120.00
|
|
|
$
|
151.50
|
|
|
$
|
149.98
|
|
|
$
|
164.77
|
|
|
$
|
80.00
|
|
|
$
|
100.00
|
|
|
$
|
88.32
|
|
MAAC zone
|
|
$
|
120.00
|
|
|
$
|
151.50
|
|
|
$
|
149.98
|
|
|
$
|
164.77
|
|
|
$
|
80.00
|
|
|
$
|
100.00
|
|
|
$
|
86.04
|
|
EMAAC zone
|
|
$
|
120.00
|
|
|
$
|
151.50
|
|
|
$
|
210.63
|
|
|
$
|
225.42
|
|
|
$
|
99.77
|
|
|
$
|
119.77
|
|
|
$
|
187.87
|
|
COMED zone
|
|
$
|
120.00
|
|
|
$
|
151.50
|
|
|
$
|
200.21
|
|
|
$
|
215.00
|
|
|
$
|
182.77
|
|
|
$
|
202.77
|
|
|
$
|
188.12
|
|
ATSI zone
|
|
$
|
120.00
|
|
|
$
|
151.50
|
|
|
$
|
149.98
|
|
|
$
|
164.77
|
|
|
$
|
80.00
|
|
|
$
|
100.00
|
|
|
$
|
76.53
|
|
PPL zone
|
|
$
|
120.00
|
|
|
$
|
151.50
|
|
|
$
|
75.00
|
|
|
$
|
164.77
|
|
|
$
|
80.00
|
|
|
$
|
100.00
|
|
|
$
|
86.04
|
|
(1)
|
Planning Year 2020-2021 includes DEOK zone which broke out from RTO zone at $130.00 per MW-day.
|
|
|
2017-2018
|
|
2018-2019
|
|
2019-2020
|
|
2020-2021
|
Legacy/Base auction capacity sold, net (MW)
|
|
2,920
|
|
1,910
|
|
1,413
|
|
—
|
CP auction capacity sold, net (MW)
|
|
7,276
|
|
7,804
|
|
8,159
|
|
8,558
|
Bilateral capacity sold, net (MW)
|
|
2
|
|
270
|
|
200
|
|
200
|
Total segment capacity sold, net (MW)
|
|
10,198
|
|
9,984
|
|
9,772
|
|
8,758
|
Average price per MW-day
|
|
$143.99
|
|
$180.72
|
|
$128.72
|
|
$130.13
|
|
|
2018
|
|
2019
|
|
2020 to 2022
|
Generation volumes hedged (1)
|
|
64%
|
|
19%
|
|
3%
|
(1)
|
Excludes volumes subject to tolling agreements.
|
|
|
Summer 2017
|
|
Winter 2017-2018
|
Price per kW-month
|
|
$3.00
|
|
$0.37
|
|
|
Winter 2017-2018
|
|
Summer 2018
|
|
Winter 2018-2019
|
|
Summer 2019
|
|
Winter 2019-2020
|
|
Summer 2020
|
Auction capacity sold (MW)
|
|
122
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
Bilateral capacity sold (MW)
|
|
1,088
|
|
855
|
|
605
|
|
305
|
|
210
|
|
75
|
Total capacity sold (MW)
|
|
1,210
|
|
855
|
|
605
|
|
305
|
|
210
|
|
75
|
Average price per kW-month
|
|
$1.79
|
|
$3.12
|
|
$2.19
|
|
$3.06
|
|
$2.57
|
|
$3.15
|
|
|
2017-2018
|
|
2018-2019
|
|
2019-2020
|
|
2020-2021
|
|
2021-2022
|
Price per kW-month
|
|
$7.03
|
|
$9.55
|
|
$7.03
|
|
$5.30
|
|
$4.63
|
|
|
2017-2018
|
|
2018-2019
|
|
2019-2020
|
|
2020-2021
|
|
2021-2022
|
Auction capacity sold (MW)
|
|
3,155
|
|
3,168
|
|
3,203
|
|
3,229
|
|
2,762
|
Bilateral capacity sold (MW)
|
|
148
|
|
86
|
|
30
|
|
—
|
|
—
|
Total capacity sold (MW)
|
|
3,303
|
|
3,254
|
|
3,233
|
|
3,229
|
|
2,762
|
Average price per kW-month
|
|
$6.92
|
|
$9.98
|
|
$7.02
|
|
$5.39
|
|
$4.79
|
|
|
2018
|
|
2019
|
|
2020 to 2022
|
Generation volumes hedged
|
|
74%
|
|
26%
|
|
—%
|
Coal requirements contracted
|
|
100%
|
|
—%
|
|
—%
|
Coal requirements priced
|
|
100%
|
|
—%
|
|
—%
|
Coal transportation requirements contracted
|
|
100%
|
|
—%
|
|
—%
|
|
|
2018
|
|
2019
|
|
2020 to 2022
|
Generation volumes hedged
|
|
75%
|
|
39%
|
|
17%
|
Coal requirements contracted
|
|
91%
|
|
74%
|
|
43%
|
Coal requirements priced
|
|
90%
|
|
6%
|
|
5%
|
Coal transportation requirements contracted
|
|
100%
|
|
100%
|
|
99%
|
|
|
2017-2018
|
Price per MW-day
|
|
$1.50
|
|
|
2017-2018
|
|
2018-2019
|
|
2019-2020
|
|
2020-2021
|
Bilateral capacity sold in MISO (MW)
|
|
3,506
|
|
2,269
|
|
1,978
|
|
1,520
|
Legacy/Base auction capacity sold in PJM (MW)
|
|
572
|
|
—
|
|
260
|
|
—
|
CP auction capacity sold in PJM (MW)
|
|
472
|
|
835
|
|
356
|
|
444
|
Total MISO segment capacity sold (MW)
|
|
4,550
|
|
3,104
|
|
2,594
|
|
1,964
|
Average price per kW-month
|
|
$4.01
|
|
$4.37
|
|
$3.72
|
|
$3.80
|
|
|
2018
|
|
2019
|
|
2020 to 2022
|
Generation volumes hedged
|
|
56%
|
|
24%
|
|
—%
|
|
|
2018
|
|
2019
|
|
2020
|
Bilateral capacity sold (Avg MW)
|
|
966
|
|
850
|
|
—
|
Description
|
|
Judgments and Uncertainties
|
|
Effect if Actual Results Differ From Assumptions
|
Derivative Instruments
|
|
|
|
|
Commodity contracts that meet the definition of a derivative are often entered into to mitigate or eliminate market and financial risks associated with our generation business. These contracts include forward contracts, which commit us to sell commodities in the future; futures contracts, which are generally broker-cleared standard commitments to purchase or sell a commodity; option contracts, which convey the right to buy or sell a commodity; and swap agreements, which require payments to or from counterparties based upon the differential between two prices for a predetermined quantity.
There are two different ways to account for these types of commodity contracts, as Dynegy does not elect hedge accounting for any of its derivative instruments: (i) as an accrual contract, if the criteria for the “normal purchase, normal sale” exception are met, documented, and elected; or (ii) as a mark-to-market contract with changes in fair value recognized in current period earnings.
Comparability of our financial statements to our peers for similar contracts may not be possible due to differences in electing the “normal purchase, normal sale” exception or electing hedge accounting.
We are exposed to changes in interest rate risk through our variable rate debt and enter into interest rate swaps to manage our interest rate risk with the changes in fair value recorded currently to interest expense. Our interest-based derivative instruments are not designated as hedges of our variable debt.
We elect to offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting agreement and we elect to offset the fair value of amounts recognized for the cash collateral paid or received against the fair value of amounts recognized for derivative instruments executed with the same counterparty under a master netting agreement.
|
|
We utilize market data or assumptions, including assumptions about risk and the risks inherent in the inputs to the valuation technique, primarily forward price curves, pricing risk, and credit risk. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. These inputs are classified into three levels of fair value hierarchy under GAAP and described as actively quoted market prices (Level 1), directly or indirectly observable (Level 2), or generally unobservable (Level 3).
Those inputs include not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), but also the impact of our nonperformance risk on our liabilities. Valuation adjustments are generally based on capital market implied ratings when assessing the credit standing of our counterparties, and when applicable, adjusted based on management’s estimates of assumptions market participants would use in determining fair value.
|
|
Changes to our assumptions for the fair value of our derivative instruments could result in a material change to the fair value of our risk management assets and liabilities recorded to our consolidated balance sheets and corresponding changes in fair value recorded to our consolidated statements of operations. Please read Note 5-Fair Value Measurements for further discussion of our assumptions.
|
Description
|
|
Judgments and Uncertainties
|
|
Effect if Actual Results Differ From Assumptions
|
Accounting for Income Taxes
|
|
|
|
|
We file a consolidated U.S. federal income tax return. We use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant differences. We also account for changes in the tax code when enacted. Because we operate and sell power in many different states, our effective annual state income tax rate may vary from period to period due to changes in our sales profile by state, as well as jurisdictional and legislative changes by state. As a result, changes in our estimated effective annual state income tax rate can have a significant impact on our measurement of temporary differences.
We conduct a valuation assessment on our deferred tax assets, which involves an extensive analysis of positive and negative evidence, to determine if it is more likely than not that they will not be realized.
|
|
As part of the process of preparing our consolidated financial statements, we are required to estimate our income taxes in each of the jurisdictions in which we operate. This process involves estimating our actual current tax payable and related tax expense together with assessing temporary differences resulting from differing tax and accounting treatment of certain items, such as depreciation, for tax and accounting purposes. We project the rates at which state tax temporary differences will reverse based upon estimates of revenues and operations in the respective jurisdictions in which we conduct business.
The guidance related to accounting for income taxes also require that a valuation allowance be established when it is more likely than not that all or a portion of a deferred tax asset will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income of the appropriate character during the periods in which those temporary differences are deductible. In making this determination, management considers all available positive and negative evidence affecting specific deferred tax assets, including our past and anticipated future performance, the reversal of deferred tax liabilities and the implementation of tax planning strategies.
|
|
Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
A change in the future taxable income assumptions used to determine our need for a valuation allowance can result in more or less deferred tax assets being recognized in our financial statements.
The ultimate tax outcome is uncertain and the assumptions used on the utilization of tax benefits in the future can change primarily as a consequence of newly enacted tax laws and management’s view of future taxable income. These changes can materially affect our overall financial results.
|
|
|
|
|
|
Accounting for uncertainty in income taxes requires that we determine whether it is more likely than not that a tax position we have taken will be sustained upon examination. If we determine that it is more likely than not that the position will be sustained, we recognize the largest amount of the benefit that is greater than 50 percent likely of being realized upon settlement.
|
|
There is a significant amount of judgment involved in assessing the likelihood that a tax position will be sustained upon examination and in determining the amount of the benefit that will ultimately be realized.
|
|
A change in our assumptions assessing the likelihood that a tax position will be sustained upon examination may change the amount of tax benefit that is recognized in our financial statements. Please read Note 14-Income Taxes for further discussion of our accounting for income taxes, uncertain tax positions, and changes in our valuation allowance.
|
Description
|
|
Judgments and Uncertainties
|
|
Effect if Actual Results Differ From Assumptions
|
Business Combinations
|
|
|
|
|
Accounting Standards Codification (“ASC”) 815, Business Combinations requires that the purchase price for a business combination be assigned and allocated to the identifiable assets acquired and liabilities assumed based upon their fair value. Generally, the amount recorded in the financial statements for an acquisition’s assets and liabilities is equal to the purchase price (the fair value of the consideration paid); however, a purchase price that exceeds the fair value of the net assets acquired will result in the recognition of goodwill. Conversely, a purchase price that is below the fair value of the net assets acquired will result in the recognition of a bargain purchase in the income statement.
In addition to the potential for the recognition of goodwill or a bargain purchase, differing fair values will impact the allocation of the purchase price to the individual assets and liabilities and can impact the gross amount and classification of assets and liabilities recorded in our consolidated balance sheets, which can impact the timing and amount of depreciation and amortization expense recorded in any given period.
|
|
In estimating fair value, we use discounted cash flow (“DCF”) projections, recent comparable market transactions, if available, or quoted prices. We consider assumptions that third parties would make in estimating fair value, including, but not limited to, the highest and best use of the asset. There is a significant amount of judgment involved in cash-flow estimates, including assumptions regarding market convergence, discount rates, commodity prices, useful lives and growth factors. The assumptions used by another party could differ significantly from our assumptions.
We utilize our best effort to make our determinations and review all information available, including estimated future cash flows and prices of similar assets when making our best estimate. We also may hire independent appraisers or valuation specialists to help us make this determination as we deem appropriate under the circumstances. Refer to Note 3—Acquisitions and Divestitures for further discussion of assumptions used in acquisitions.
|
|
There is a significant amount of judgment in determining the fair value of acquisitions and in allocating the purchase price to individual assets and liabilities. Had different assumptions been used, the fair value of the assets acquired and liabilities assumed could have been significantly higher or lower with a corresponding increase or reduction in recognized goodwill, or could have required recognition of a bargain purchase.
|
Description
|
|
Judgments and Uncertainties
|
|
Effect if Actual Results Differ From Assumptions
|
Impairment of Long-Lived Assets
|
|
|
|
|
ASC 360, Property, Plant and Equipment (“PP&E”) requires for an entity to assess whether the recorded values of PP&E and finite-lived intangible assets have become impaired when certain indicators of impairment exist. Examples of these indicators include, but are not limited to:
● a significant decrease in the market price of a long-lived asset (asset group);
● a significant adverse change in the extent or manner in which a long-lived asset (asset group) is being used, or in its physical condition;
● a significant adverse change in legal factors or in the business climate that could affect the value of a long-lived asset (asset group), including an adverse action or assessment by a regulator;
● an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset (asset group);
● a current-period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset (asset group); and
● a current expectation that it is more likely than not a long-lived asset (asset group) will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.
|
|
Determining whether an impairment trigger exists involves significant judgment by management which may result in a different answer if our peers were to consider the same facts and circumstances.
If it is determined that the asset’s value is not recoverable, then we will perform step two of the impairment analysis and fair value the asset using a DCF model and record an impairment charge to reduce the value of the asset to its fair value. The assumptions and estimates used by management to assess whether the asset may have become impaired, whether the asset’s value is recoverable, and to determine the fair value of the estimate are significant and may vary materially from the assumptions used by our peers.
Examples of the assumptions and estimates used by management include:
● determination of increases/decreases in the market price of an asset being a short-term or long-term, fundamental change;
● the highest and best use of the asset;
● forecasted environmental changes;
● forecasted regulatory changes;
● management’s fundamental view of the long-term pricing environment for energy and capacity;
● management’s forecast of gross margin, capital expenditures, and operations and maintenance costs;
● remaining useful life of our assets;
● salvage value;
● discount rates; and
● inflation rates.
The assumptions used in impairment analyses often include unobservable inputs that are based on management’s long-term view of our assets remaining useful lives, operating margin and capital requirements.
|
|
Changes in market economics and environmental requirements can alter previous assumptions and trigger impairment charges that can materially differ from the results we have reported herein.
|
Description
|
|
Judgments and Uncertainties
|
|
Effect if Actual Results Differ From Assumptions
|
Goodwill Impairment
|
|
|
|
|
We record goodwill when the purchase price for an acquisition classified as a business combination exceeds the estimated net fair value of the identifiable tangible and intangible assets acquired. The amount of goodwill which can be recognized as part of an acquisition can change materially based upon the assumptions used when determining the net fair value of those assets. We allocate goodwill to reporting units based on the relative fair value of the purchased operating assets assigned to those reporting units.
ASC 350, Intangibles-Goodwill and Other requires an entity to assess whether goodwill has become impaired at least annually, or when certain indicators of impairment exist on an interim basis. We have elected October 1 for our annual assessment. Examples of the indicators of impairment include, but are not limited to:
● a deterioration of general economic conditions, limitation on accessing capital, or other developments in equity and credit markets;
● increases in costs which have a negative effect on earnings and cash flows;
● overall financial performance such as negative or declining cash flows or a decline in actual or planned revenue or earnings;
● other relevant entity-specific events such as changes in management, key personnel, strategy, or customers, contemplation of bankruptcy, or litigation;
● a more likely than not expectation of selling or disposing all, or a portion, of a reporting unit; and,
● recognition of a goodwill impairment loss in the financial statements of a subsidiary that is a component of a reporting unit.
|
|
Determining whether a goodwill impairment trigger exists involves significant judgment by management, which may result in a different answer if our peers were to consider the same facts and circumstances.
The assumptions and estimates used by management to determine the fair value of our reporting units and goodwill for step one, and the fair value of our equity to reconcile to our market capitalization, are significant and require management judgment. Some examples of the assumptions and estimates used include:
● the highest and best use of the reporting units assets;
● recent comparable market transactions, if available, or quoted prices;
● management’s forecast of gross margin, capital expenditures, and operations and maintenance costs;
● forecasted environmental and regulatory changes;
● management’s fundamental view of the long-term pricing environment for energy and capacity;
● remaining useful life of our assets;
● salvage value;
● discount rates; and
● inflation rates.
|
|
Changes in management’s assumptions and estimates regarding the fair value of these reporting units could result in a materially different result.
The assumptions used in goodwill impairment analyses often include unobservable inputs that are based on management’s long-term view of the reporting unit asset’s remaining useful lives, operating margin and capital requirements. Changes in the reporting unit’s economics can alter previous assumptions and trigger impairment charges that can materially affect our financial results.
|
Description
|
|
Judgments and Uncertainties
|
|
Effect if Actual Results Differ From Assumptions
|
Goodwill Impairment (Continued)
|
|
|
|
|
In the event management determines an impairment indicator exists or is performing the annual assessment, ASC 350 allows an entity to elect to qualitatively assess whether it is more likely than not (a likelihood of more than 50 percent) that an impairment has occurred. If we determine that it is more likely than not that goodwill has become impaired, we will impair goodwill by the amount by which the carrying value of the reporting unit, including goodwill, exceeds its fair value that will be retained.
When we dispose of a reporting unit or a portion of a reporting unit that constitutes a business, we include goodwill associated with that business in the carrying amount of the business in order to determine the gain or loss on sale. The amount of goodwill to be included in that carrying amount is based on the relative fair value of the business to be disposed of as compared to the portion of the reporting unit that will be retained.
|
|
|
|
|
(amounts in millions)
|
|
As of and for the Year Ended December 31, 2017
|
||
Fair value of portfolio at December 31, 2016
|
|
$
|
6
|
|
Risk management losses recognized through the statement of operations in the period, net
|
|
(223
|
)
|
|
Contracts realized or otherwise settled during the period
|
|
16
|
|
|
Cash received related to option premiums
|
|
(3
|
)
|
|
Acquired derivatives
|
|
9
|
|
|
Change in collateral/margin netting
|
|
(7
|
)
|
|
Fair value of portfolio at December 31, 2017
|
|
$
|
(202
|
)
|
(amounts in millions)
|
|
Total
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
Thereafter
|
||||||||||||||
Market quotations (1)(2)
|
|
$
|
(224
|
)
|
|
$
|
(219
|
)
|
|
$
|
(21
|
)
|
|
$
|
3
|
|
|
$
|
4
|
|
|
$
|
4
|
|
|
$
|
5
|
|
Prices based on models (2)
|
|
(25
|
)
|
|
(25
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Total (3)
|
|
$
|
(249
|
)
|
|
$
|
(244
|
)
|
|
$
|
(21
|
)
|
|
$
|
3
|
|
|
$
|
4
|
|
|
$
|
4
|
|
|
$
|
5
|
|
(1)
|
Prices obtained from actively traded, liquid markets for commodities.
|
(2)
|
The market quotations category represents our transactions classified as Level 1 and Level 2. The prices based on models category represents transactions classified as Level 3. Please read
Note 5—Fair Value Measurements
for further discussion.
|
(3)
|
Excludes
$47 million
of broker margin that has been netted against Risk management liabilities in our consolidated balance sheets. Please read
Note 4—Risk Management Activities, Derivatives and Financial Instruments
for further discussion.
|
•
|
manage and hedge our fixed-price purchase and sales commitments;
|
•
|
reduce our exposure to the volatility of cash market prices; and
|
•
|
hedge our fuel requirements for our generating facilities.
|
•
|
commodity price risks result from exposures to changes in spot prices, forward prices and volatilities in commodities, such as electricity, natural gas, coal, fuel oil, emissions and other similar products; and
|
•
|
interest rate risks primarily result from exposures to changes in the level, slope and curvature of the yield curve and the volatility of interest rates.
|
(amounts in millions)
|
|
December 31, 2017
|
|
December 31, 2016
|
||||
One day VaR—95 percent confidence level
|
|
$
|
36
|
|
|
$
|
38
|
|
One day VaR—99 percent confidence level
|
|
$
|
53
|
|
|
$
|
53
|
|
Average VaR—95 percent confidence level for the rolling twelve months ended
|
|
$
|
13
|
|
|
$
|
14
|
|
(amounts in millions)
|
|
Investment
Grade Quality
|
||
Type of Business:
|
|
|
|
|
Financial institutions
|
|
$
|
1
|
|
Utility and power generators
|
|
6
|
|
|
Total
|
|
$
|
7
|
|
|
|
December 31, 2017
|
|
December 31, 2016
|
||||
Interest rate swaps (in millions of U.S. dollars)
|
|
$
|
1,961
|
|
|
$
|
769
|
|
Fixed interest rate paid (percent)
|
|
2.38
|
%
|
|
3.19
|
%
|
(i)
|
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;
|
(ii)
|
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of our company are being made only in accordance with authorizations of our management and directors; and
|
(iii)
|
provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.
|
Plan Category
|
|
Number of securities
to be issued upon
exercise of
outstanding options and rights (a)
|
|
Weighted-average
exercise price of
outstanding options and rights (b)
|
|
Number of securities
remaining available for
future issuance under
equity compensation
plans (excluding
securities reflected in
column (a)) (c)
|
||||
Equity compensation plans approved by security holders (1)
|
|
6,929,289
|
|
|
$
|
14.02
|
|
|
115,176
|
|
Equity compensation plans not approved by security holders
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total
|
|
6,929,289
|
|
|
$
|
14.02
|
|
|
115,176
|
|
(1)
|
The plan that is approved by our security holders is the 2012 Long Term Incentive Plan, as amended. Please read
Note 15—Stockholders’ Equity
—Stock Award Plans for further discussion.
|
Exhibit
Number
|
|
|
Description
|
1.1
|
|
|
Underwriting Agreement relating to the 4,000,000 7.00% Tangible Equity Units, dated as of June 15, 2016, among Dynegy Inc., Morgan Stanley & Co. LLC, and RBC Capital Markets, LLC
(incorporated by reference to Exhibit 1.1 to the Current Report on Form 8-K of Dynegy Inc. filed on June 21, 2016 File No. 001-33443).
|
2.1
|
|
|
Confirmation Order for Dynegy Inc. and Dynegy Holdings, LLC, as entered by the United States Bankruptcy Court for the Southern District of New York on September 10, 2012
(incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. and Dynegy Holdings, LLC filed on September 13, 2012 File No. 001-33443).
|
2.2
|
|
|
Purchase and Sale Agreement by and among Duke Energy SAM, LLC and Duke Energy Commercial Enterprises, Inc., as sellers, and Dynegy Resources I, LLC, as buyer, dated as of August 21, 2014
(incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. filed on August 26, 2014 File No. 001-33443).
*
|
2.3
|
|
|
Letter Agreement to Purchase and Sale Agreement by and among Duke Energy SAM, LLC and Duke Energy Commercial Enterprises, Inc., as sellers, and Dynegy Resources I, LLC, as buyer, dated as of October 24, 2014
(incorporated by reference to Exhibit 2.2 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2014 of Dynegy Inc. File No. 001-33443).
*
|
2.4
|
|
|
Stock Purchase Agreement by and among Energy Capital Partners II, LP, Energy Capital Partners II-A, LP, Energy Capital Partners II-B, LP, Energy Capital Partners II-C (Direct IP), LP, Energy Capital Partners II-D, LP and Energy Capital Partners II (EquiPower Co-Invest), LP, Energy Capital Partners II-C, LP, for the limited purposes set forth therein, EquiPower Resources Corp., Dynegy Resource II, LLC, and Dynegy Inc., for the limited purposes set forth therein, dated as of August 21, 2014
(incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K of Dynegy Inc. filed on August 26, 2014 File No. 001-33443).
*
|
2.5
|
|
|
Letter Agreement to Purchase and Sale Agreement by and among Energy Capital Partners II, LP, Energy Capital Partners II-A, LP, Energy Capital Partners II-B, LP, Energy Capital Partners II-C (Direct IP), LP, Energy Capital Partners II-D, LP and Energy Capital Partners II (EquiPower Co-Invest), LP, Energy Capital Partners II-C, LP, for the limited purposes set forth therein, EquiPower Resources Corp., Dynegy Resource II, LLC, and Dynegy Inc., for the limited purposes set forth therein, dated November 12, 2014
(incorporated by reference to Exhibit 2.5 to the Annual Report on Form 10-K for the Year Ended December 31, 2014 of Dynegy Inc. File No. 001-33443).
|
2.6
|
|
|
Letter Agreement to Purchase and Sale Agreement by and among Energy Capital Partners II, LP, Energy Capital Partners II-A, LP, Energy Capital Partners II-B, LP, Energy Capital Partners II-C (Direct IP), LP, Energy Capital Partners II-D, LP and Energy Capital Partners II (EquiPower Co-Invest), LP, Energy Capital Partners II-C, LP, for the limited purposes set forth therein, EquiPower Resources Corp., Dynegy Resource II, LLC, and Dynegy Inc., for the limited purposes set forth therein, dated March 30, 2015
(incorporated by reference to Exhibit 2.1 to the Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2015 of Dynegy Inc. File No. 001-33443).
*
|
2.7
|
|
|
Amendment to Stock Purchase Agreement, dated as of March 30, 2015, by and among Energy Capital Partners II, LP, Energy Capital Partners II-A, LP, Energy Capital Partners II-B, LP, Energy Capital Partners II-C (Direct IP), LP, Energy Capital Partners II-D, LP and Energy Capital Partners II (EquiPower Co-Invest), LP, Energy Capital Partners II-C, LP, for the limited purposes set forth therein, EquiPower Resources Corp., Dynegy Resource II, LLC, and Dynegy Inc., for the limited purposes set forth therein
(incorporated by reference to Exhibit 2.1 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on April 1, 2015).
|
2.8
|
|
|
Stock Purchase Agreement and Agreement and Plan of Merger by and among Energy Capital Partners GP II, LP, Energy Capital Partners II, LP, Energy Capital Partners II-A, LP, Energy Capital Partners II-B, LP, Energy Capital Partners II-D, LP, Energy Capital Partners II-C (Cayman), LP, Energy Capital Partners II-C, LP, for the limited purposes set forth therein, Brayton Point Holdings, LLC, Dynegy Resource III, LLC, Dynegy Resource III-A, LLC, and Dynegy Inc., for the limited purposes set forth therein, dated as of August 21, 2014
(incorporated by reference to Exhibit 2.3 to the Current Report on Form 8-K of Dynegy Inc. filed on August 26, 2014 File No. 001-33443).
*
|
2.9
|
|
|
Letter Agreement to Purchase and Sale Agreement by and among Energy Capital Partners II, LP, Energy Capital Partners II-A, LP, Energy Capital Partners II-B, LP, Energy Capital Partners II-C (Direct IP), LP, Energy Capital Partners II-D, LP and Energy Capital Partners II (EquiPower Co-Invest), LP, Energy Capital Partners II-C, LP, for the limited purposes set forth therein, EquiPower Resources Corp., Dynegy Resource II, LLC, and Dynegy Inc., for the limited purposes set forth therein, and Stock Purchase Agreement and Agreement and Plan of Merger by and among Energy Capital Partners GP II, LP, Energy Capital Partners II, LP, Energy Capital Partners II-A, LP, Energy Capital Partners II-B, LP, Energy Capital Partners II-D, LP, Energy Capital Partners II-C (Cayman), LP, Energy Capital Partners II-C, LP, for the limited purposes set forth therein, Brayton Point Holdings, LLC, Dynegy Resource III, LLC, Dynegy Resource III-A, LLC, and Dynegy Inc., for the limited purposes set forth therein dated November 25, 2014
(incorporated by reference to Exhibit 2.7 to the Annual Report on Form 10-K for the Year Ended December 31, 2014 of Dynegy Inc. File No. 001-33443).
|
2.10
|
|
|
Revised Attachment A to the Letter Agreement to Purchase and Sale Agreement by and among Energy Capital Partners II, LP, Energy Capital Partners II-A, LP, Energy Capital Partners II-B, LP, Energy Capital Partners II-C (Direct IP), LP, Energy Capital Partners II-D, LP and Energy Capital Partners II (EquiPower Co-Invest), LP, Energy Capital Partners II-C, LP, for the limited purposes set forth therein, EquiPower Resources Corp., Dynegy Resource II, LLC, and Dynegy Inc., for the limited purposes set forth therein, and Stock Purchase Agreement and Agreement and Plan of Merger by and among Energy Capital Partners GP II, LP, Energy Capital Partners II, LP, Energy Capital Partners II-A, LP, Energy Capital Partners II-B, LP, Energy Capital Partners II-D, LP, Energy Capital Partners II-C (Cayman), LP, Energy Capital Partners II-C, LP, for the limited purposes set forth therein, Brayton Point Holdings, LLC, Dynegy Resource III, LLC, Dynegy Resource III-A, LLC, and Dynegy Inc., for the limited purposes set forth therein dated February 4, 2015
(incorporated by reference to Exhibit 2.8 to the Annual Report on Form 10-K for the Year Ended December 31, 2014 of Dynegy Inc. File No. 001-33443).
|
2.11
|
|
|
Stock Purchase Agreement, dated February 24, 2016, by and between Atlas Power Finance, LLC, GDF SUEZ Energy North America, Inc. and International Power, S.A.
(incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. filed on March 1, 2016 File No. 001-33443).
*
|
2.12
|
|
|
First Amendment Stock Purchase Agreement, dated May 2, 2016, by and between Atlas Power Finance, LLC, GDF SUEZ Energy North America, Inc. and International Power, S.A.
(incorporated by reference to Exhibit 2.2 to the Quarterly Report on Form 10-Q of Dynegy Inc. for the Quarter Ended March 31, 2016 File No. 001-33443).
*
|
2.13
|
|
|
Amended and Restated Stock Purchase Agreement, dated as of June 27, 2016, by and among Atlas Power Finance, LLC, GDF SUEZ Energy North America, Inc. and International Power, S.A.
(incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. filed on June 28, 2016 File No. 001-33443).
*
|
2.14
|
|
|
First Amendment to Amended and Restated Stock Purchase Agreement, dated January 24, 2017, by and among Atlas Power Finance, LLC, GDF SUEZ Energy North America, Inc. and International Power, S.A.
(incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K of Dynegy Inc. filed on February 8, 2017 File No. 001-33443).
*
|
2.15
|
|
|
Membership Interest Purchase Agreement, dated as of August 3, 2016, by and among Elwood Expansion Holdings, LLC, Elwood Energy Holdings, LLC, Tomcat Power, LLC, Elwood Energy Holdings II, LLC and J-POWER USA Development Co., Ltd.
(incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. filed on August 4, 2016 File No. 001-33443).
*
|
2.16
|
|
|
Confirmation Order for Dynegy Northeast Generation, Inc., Hudson Power, L.L.C., Dynegy Danskammer, L.L.C., and Dynegy Roseton, L.L.C., as entered by the United States Bankruptcy Court for the Southern District of New York on March 15, 2013
(incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. filed on March 19, 2013 File No. 001-33443).
|
2.17
|
|
|
Membership Interest Purchase Agreement, dated as of February 23, 2017, by and between Dynegy Inc. and Spruce Generation, LLC
(incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. filed on February 28, 2017 File No. 001-33443).
*
|
2.18
|
|
|
Asset Purchase Agreement, dated as of February 23, 2017, by and between AEP Generation Resources Inc. and Dynegy Zimmer, LLC
(incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K of Dynegy Inc. filed on February 28, 2017 File No. 001-33443).
*
|
2.19
|
|
|
Asset Purchase Agreement, dated February 23, 2017, by and between Dynegy Conesville, LLC and AEP Generation Resources Inc.
(incorporated by reference to Exhibit 2.3 to the Current Report on Form 8-K of Dynegy Inc. filed on February 28, 2017 File No. 001-33443).
*
|
2.20
|
|
|
Asset Purchase Agreement dated April 21, 2017, by and among Dynegy Zimmer, LLC, Dynegy Miami Fort, LLC, AES Ohio Generation, LLC and The Dayton Power and Light Company
(incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. filed on April 24, 2017 File No. 001-33443).
*
|
2.21
|
|
|
Membership Interest Purchase Agreement, dated as of July 10, 2017, by and between Dynegy Inc. and Bruce Power, LLC
(incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. filed on July 12, 2017 File No. 001-33443).
*
|
2.22
|
|
|
Purchase and Sale Agreement, dated July 10, 2017, by and among Dynegy Resources Generating Holdco, LLC, ANP Funding I, LLC and Marco DM Holdings, L.L.C.
(incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. filed on July 13, 2017 File No. 001-33443).
*
|
2.23
|
|
|
Agreement and Plan of Merger, dated as of October 29, 2017, by and between Dynegy Inc. and Vistra Energy Corp.
(incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. filed on October 30, 2017 File No. 001-33443).
*
|
2.24
|
|
|
Confirmation Order for Illinois Power Generating Company, as entered by the United States Bankruptcy Court for the Southern District of Texas on January 25, 2017
(incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K of Dynegy Inc. filed on January 30, 2017 File No. 001-33443).
|
3.1
|
|
|
Dynegy Inc. Third Amended and Restated Certificate of Incorporation
(incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K of Dynegy Inc. filed on October 4, 2012 File No. 001-33443).
|
3.2
|
|
|
Dynegy Inc. Seventh Amended and Restated Bylaws
(incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K of Dynegy Inc. filed on March 3, 2017 File No. 001-33443).
|
4.1
|
|
|
Indenture, dated May 20, 2013, among Dynegy Inc., the Guarantors and Wilmington Trust, National Association as Trustee (5.875% Senior Notes due 2023) (2023 Notes Indenture)
(incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K of Dynegy Inc. filed on May 21, 2013 File No. 001-33443).
|
4.2
|
|
|
First Supplemental Indenture to the 2023 Notes Indenture, dated as of December 5, 2014, among Dynegy Inc., the Guarantors and Wilmington Trust, National Association as Trustee
(incorporated by reference to Exhibit 4.3 to the Annual Report on Form 10-K for the Year Ended December 31, 2013 of Dynegy Inc. File No. 001-33443).
|
4.3
|
|
|
Second Supplemental Indenture to the 2023 Notes Indenture, dated April 1, 2015, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association as Trustee
(incorporated by reference to Exhibit 4.20 to the Current Report on Form 8-K of Dynegy Inc. filed April 7, 2015 File No. 001-33443).
|
4.4
|
|
|
Third Supplemental Indenture to the 2023 Notes Indenture, dated April 2, 2015, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association as Trustee, pursuant to which the Subsidiary Guarantors are added to the 2023 Notes Indenture
(incorporated by reference to Exhibit 4.28 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on April 8, 2015).
|
4.5
|
|
|
Fourth Supplemental Indenture to the 2023 Notes Indenture, dated May 11, 2015, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association as Trustee, adding Dynegy Resource Holdings, LLC as a guarantor
(incorporated by reference to Exhibit 4.4 to the Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2015 of Dynegy Inc. File No. 001-33443).
|
4.6
|
|
|
Fifth Supplemental Indenture to the 2023 Notes Indenture, dated September 21, 2015, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association as Trustee, adding Dynegy Resource Holdings, LLC as a guarantor
(incorporated by reference to Exhibit 4.4 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2015 of Dynegy Inc. File No. 001-33443).
|
4.7
|
|
|
Sixth Supplemental Indenture to the 2023 Notes Indenture, dated February 2, 2017, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association as Trustee, adding certain IPH entities as guarantors
(incorporated by reference to Exhibit 4.7 to the Annual Report on Form 10-K for the Year Ended December 31, 2016 of Dynegy Inc. File No. 001-33443).
|
4.8
|
|
|
Seventh Supplemental Indenture to the 2023 Notes Indenture, dated February 7, 2017, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association as Trustee, adding Delta Transaction entities as guarantors
(incorporated by reference to Exhibit 4.8 to the Annual Report on Form 10-K for the Year Ended December 31, 2016 of Dynegy Inc. File No. 001-33443).
|
4.9
|
|
|
2019 Notes Indenture, dated October 27, 2014, among Dynegy Finance II, Inc. and Wilmington Trust, National Association, as trustee (2019 Notes Indenture)
(incorporated by reference to Exhibit 4.7 to the Current Report on Form 8-K of Dynegy Inc. filed on October 30, 2014 File No. 001-33443).
|
4.10
|
|
|
First Supplemental Indenture to the 2019 Notes Indenture, dated April 1, 2015, between Dynegy Inc. and Wilmington Trust, National Association, as trustee
(incorporated by reference to Exhibit 4.8 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on April 7, 2015).
|
4.11
|
|
|
Second Supplemental Indenture to the 2019 Notes Indenture, dated April 1, 2015, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee
(incorporated by reference to Exhibit 4.9 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on April 7, 2015).
|
4.12
|
|
|
Third Supplemental Indenture to the 2019 Notes Indenture, dated April 2, 2015, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee, adding the Duke Acquired Entities as guarantors
(incorporated by reference to Exhibit 4.13 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on April 8, 2015).
|
4.13
|
|
|
Fourth Supplemental Indenture to the 2019 Notes Indenture, dated May 11, 2015, among Dynegy Inc., the Subsidiary Guarantors, (as defined therein) and Wilmington Trust, National Association, as trustee, adding Dynegy Resource Holdings, LLC as a guarantor
(incorporated by reference to Exhibit 4.1 to the Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2015 of Dynegy Inc. File No. 001-33443).
|
4.14
|
|
|
Fifth Supplemental Indenture to the 2019 Notes Indenture, dated September 21, 2015, among Dynegy Inc., the Subsidiary Guarantors, (as defined therein) and Wilmington Trust, National Association, as trustee, adding Dynegy Resource Holdings, LLC as a guarantor
(incorporated by reference to Exhibit 4.1 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2015 of Dynegy Inc. File No. 001-33443).
|
4.15
|
|
|
Sixth Supplemental Indenture to the 2019 Notes Indenture, dated February 2, 2017, among Dynegy Inc., the Subsidiary Guarantors, (as defined therein) and Wilmington Trust, National Association, as trustee, adding certain IPH entities as guarantors
(incorporated by reference to Exhibit 4.16 to the Annual Report on Form 10-K for the Year Ended December 31, 2016 of Dynegy Inc. File No. 001-33443).
|
4.16
|
|
|
Seventh Supplemental Indenture to the 2019 Notes Indenture, dated February 7, 2017, among Dynegy Inc., the Subsidiary Guarantors, (as defined therein) and Wilmington Trust, National Association, as trustee, adding Delta Transaction entities as guarantors
(incorporated by reference to Exhibit 4.17 to the Annual Report on Form 10-K for the Year Ended December 31, 2016 of Dynegy Inc. File No. 001-33443).
|
4.17
|
|
|
2022 Notes Indenture, dated October 27, 2014, among Dynegy Finance II, Inc. and Wilmington Trust, National Association, as trustee (2022 Notes Indenture)
(incorporated by reference to Exhibit 4.8 to the Current Report on Form 8-K of Dynegy Inc. filed on October 30, 2014 File No. 001-33443).
|
4.18
|
|
|
First Supplemental Indenture to the 2022 Notes Indenture, dated April 1, 2015, between Dynegy Inc. and Wilmington Trust, National Association, as trustee
(incorporated by reference to Exhibit 4.11 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on April 7, 2015).
|
4.19
|
|
|
Second Supplemental Indenture to the 2022 Notes Indenture, dated April 1, 2015, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee
(incorporated by reference to Exhibit 4.12 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on April 7, 2015).
|
4.20
|
|
|
Third Supplemental Indenture to the 2022 Notes Indenture, dated April 2, 2015, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee, adding the Duke Acquired Entities as guarantors
(incorporated by reference to Exhibit 4.17 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on April 8, 2015).
|
4.21
|
|
|
Fourth Supplemental Indenture to the 2022 Notes Indenture, dated May 11, 2015, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee, adding Dynegy Resource Holdings, LLC as a guarantor
(incorporated by reference to Exhibit 4.2 to the Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2015 of Dynegy Inc. File No. 001-33443).
|
4.22
|
|
|
Fifth Supplemental Indenture to the 2022 Notes Indenture, dated September 21, 2015, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee, adding Dynegy Resource Holdings, LLC as a guarantor
(incorporated by reference to Exhibit 4.2 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2015 of Dynegy Inc. File No. 001-33443).
|
4.23
|
|
|
Sixth Supplemental Indenture to the 2022 Notes Indenture, dated February 2, 2017, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee, adding certain IPH entities as guarantors
(incorporated by reference to Exhibit 4.24 to the Annual Report on Form 10-K for the Year Ended December 31, 2016 of Dynegy Inc. File No. 001-33443).
|
4.24
|
|
|
Seventh Supplemental Indenture to the 2022 Notes Indenture, dated February 7, 2017, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee, adding Delta Transaction entities as guarantors
(incorporated by reference to Exhibit 4.25 to the Annual Report on Form 10-K for the Year Ended December 31, 2016 of Dynegy Inc. File No. 001-33443).
|
4.25
|
|
|
7.625% 2024 Notes Indenture, dated October 27, 2014, among Dynegy Finance II, Inc. and Wilmington Trust, National Association, as trustee (2024 Notes Indenture)
(incorporated by reference to Exhibit 4.9 to the Current Report on Form 8-K of Dynegy Inc. filed on October 30, 2014 File No. 001-33443).
|
4.26
|
|
|
First Supplemental Indenture to the 7.625% 2024 Notes Indenture, dated April 1, 2015, between Dynegy Inc. and Wilmington Trust, National Association, as trustee
(incorporated by reference to Exhibit 4.14 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on April 7, 2015).
|
4.27
|
|
|
Second Supplemental Indenture to the 7.625% 2024 Notes Indenture, dated April 1, 2015, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee
(incorporated by reference to Exhibit 4.15 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on April 7, 2015).
|
4.28
|
|
|
Third Supplemental Indenture to the 7.625% 2024 Notes Indenture, dated April 2, 2015, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee, adding the Duke Acquired Entities as guarantors
(incorporated by reference to Exhibit 4.21 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on April 8, 2015).
|
4.29
|
|
|
Fourth Supplemental Indenture to the 7.625% 2024 Notes Indenture, dated May 11, 2015, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee, adding Dynegy Resource Holdings, LLC as a guarantor
(incorporated by reference to Exhibit 4.2 to the Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2015 of Dynegy Inc. File No. 001-33443).
|
4.30
|
|
|
Fifth Supplemental Indenture to the 7.625% 2024 Notes Indenture, dated September 21, 2015, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee, adding Dynegy Resource Holdings, LLC as a guarantor
(incorporated by reference to Exhibit 4.3 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2015 of Dynegy Inc. File No. 001-33443).
|
4.31
|
|
|
Sixth Supplemental Indenture to the 7.625% 2024 Notes Indenture, dated February 2, 2017, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee, adding certain IPH entities as guarantors
(incorporated by reference to Exhibit 4.32 to the Annual Report on Form 10-K for the Year Ended December 31, 2016 of Dynegy Inc. File No. 001-33443).
|
4.32
|
|
|
Seventh Supplemental Indenture to the 7.625% 2024 Notes Indenture, dated February 7, 2017, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee, adding Delta Transaction entities as guarantors
(incorporated by reference to Exhibit 4.33 to the Annual Report on Form 10-K for the Year Ended December 31, 2016 of Dynegy Inc. File No. 001-33443).
|
4.33
|
|
|
2025 Notes Indenture, dated October 11, 2016, between Dynegy Inc. and Wilmington Trust, National Association (2025 Notes Indenture)
(incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K of Dynegy Inc. filed on October 11, 2016 File No. 001-33443).
|
4.34
|
|
|
First Supplemental Indenture to the 2025 Notes Indenture, dated February 2, 2017, between Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee, adding certain IPH entities as guarantors
(incorporated by reference to Exhibit 4.35 to the Annual Report on Form 10-K for the Year Ended December 31, 2016 of Dynegy Inc. File No. 001-33443).
|
4.35
|
|
|
Second Supplemental Indenture to the 2025 Notes Indenture, dated February 7, 2017, between Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee, adding Delta Transaction entities as guarantors
(incorporated by reference to Exhibit 4.36 to the Annual Report on Form 10-K for the Year Ended December 31, 2016 of Dynegy Inc. File No. 001-33443).
|
4.36
|
|
|
Indenture (TEU), dated June 21, 2016, between Dynegy Inc. and Wilmington Trust, National Association
(incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K of Dynegy Inc. filed on June 21, 2016 File No. 001-33443).
|
4.37
|
|
|
First Supplemental Indenture to the Indenture (TEU), dated June 21, 2016, between Dynegy Inc. and Wilmington Trust, National Association
(incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K of Dynegy Inc. filed on June 21, 2016 File No. 001-33443).
|
4.38
|
|
|
Purchase Contract Agreement (TEU), dated June 21, 2016, between Dynegy Inc. and Wilmington Trust, National Association
(incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K of Dynegy Inc. filed on June 21, 2016 File No. 001-33443).
|
4.39
|
|
|
Indenture to the 8.034% Notes due 2024, dated February 2, 2017, by and among Dynegy Inc., the guarantors party thereto and Wilmington Trust, National Association, as trustee
(incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K of Dynegy Inc. filed on February 7, 2017 File No. 001-33443).
|
10.39
|
|
|
Form of Performance Award Agreement (EVP) (2017 Awards)
(incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2017 of Dynegy Inc. File No. 001-33443).
††
|
10.40
|
|
|
Form of Acknowledgment between Dynegy Inc. and certain executive officers
(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on December 21, 2017 File No. 001-33443).
|
10.41
|
|
|
Credit Agreement, dated as of April 23, 2013, among Dynegy Inc., as borrower and the guarantors, lenders and other parties thereto
(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on April 24, 2013 File No. 001-33443).
|
10.42
|
|
|
Guarantee and Collateral Agreement, dated as of April 23, 2013 among Dynegy Inc., the subsidiaries of the borrower from time to time party thereto and Credit Suisse AG, Cayman Islands Branch, as Collateral Trustee
(incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on April 24, 2013 File No. 001-33443).
|
10.43
|
|
|
Collateral Trust and Intercreditor Agreement, dated as of April 23, 2013 among Dynegy, the Subsidiary Guarantors (as defined therein), Credit Suisse AG, Cayman Islands Branch and each person party thereto from time to time
(incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc. filed on April 24, 2013 File No. 001-33443).
|
10.44
|
|
|
First Amendment to Credit Agreement, dated as of April 1, 2015, among Dynegy Inc., as borrower, and the guarantors, lenders and other parties thereto
(incorporated by reference to Exhibit 10.4 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on April 7, 2015).
|
10.45
|
|
|
Second Amendment to Credit Agreement, dated as of April 2, 2015, among Dynegy Inc., as borrower, and the guarantors, lenders and other parties thereto
(incorporated by reference to Exhibit 10.5 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on April 8, 2015).
|
10.46
|
|
|
Third Amendment to Credit Agreement, dated as of June 27, 2016, among Dynegy Inc., as borrower, and the guarantors, lenders and other parties thereto
(incorporated by reference to Exhibit 10.4 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on June 28, 2016).
|
10.47
|
|
|
Waiver to Credit Agreement, dated as of June 27, 2016, among Dynegy Inc., as borrower, and the lenders party thereto
(incorporated by reference to Exhibit 10.5 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on June 28, 2016).
|
10.48
|
|
|
Waiver and Consent to Credit Agreement, dated as of December 13, 2016, among Dynegy Inc., as borrower, and the guarantors, lenders and other parties thereto
(incorporated by reference to Exhibit 10.1 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on December 14, 2016).
|
10.49
|
|
|
Fourth Amendment to the Credit Agreement, dated January 10, 2017, among Dynegy Inc., as borrower and the guarantors, lenders and other parties thereto
(incorporated by reference to Exhibit 10.3 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on January 17, 2017).
|
10.50
|
|
|
Fifth Amendment to the Credit Agreement, dated February 7, 2017, among Dynegy Inc., as borrower and the guarantors, lenders and other parties thereto
(incorporated by reference to Exhibit 10.2 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on February 9, 2017).
|
10.51
|
|
|
Sixth Amendment to the Credit Agreement, dated December 20, 2017, among Dynegy Inc., as borrower and the guarantors, lenders and other parties thereto
(incorporated by reference to Exhibit 10.2 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on December 20, 2017).
|
10.52
|
|
|
Letter of Credit Reimbursement Agreement, dated as of February 7, 2017, between Dynegy Inc. and Goldman Sachs Bank USA
(incorporated by reference to Exhibit 10.3 to Dynegy Inc.’s Current Report on Form 8-K filed with the SEC on February 9, 2017).
|
10.53
|
|
|
Letter of Credit Reimbursement Agreement, dated as of September 18, 2014 among Dynegy Inc., Macquarie Bank Limited, and Macquarie Energy LLC
(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on September 22, 2014 File No. 001-33443).
|
10.54
|
|
|
First Amendment to the Letter of Credit Reimbursement Agreement, dated August 10, 2016 among Dynegy Inc., Macquarie Bank Limited and Macquarie Energy LLC
(incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q of Dynegy Inc. for the Quarter Ended September 30, 2016 File No. 001-33443).
|
10.55
|
|
|
Second Amendment to Letter of Credit Reimbursement Agreement, dated July 13, 2017, between Dynegy Inc. and Macquarie Bank Limited
(incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the Quarter ended June 30, 2017 of Dynegy Inc. File No. 001-33443).
|
10.56
|
|
|
Purchase Agreement, dated May 15, 2013, among Dynegy Inc., the Guarantors, Morgan Stanley and Credit Suisse
(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on May 21, 2013 File No. 001-33443).
|
10.57
|
|
|
Purchase Agreement, dated October 10, 2014, among Dynegy Inc., Dynegy Finance I, Inc., Dynegy Finance II, Inc., the guarantors identified therein and Morgan Stanley & Co. LLC, Barclays Capital Inc., Credit Suisse Securities (USA) LLC, RBC Capital Markets, LLC and UBS Securities LLC, as representatives of the initial purchasers
(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on October 14, 2014 File No. 001-33443).
|
10.58
|
|
|
Warrant Agreement, dated February 2, 2017, by and among Dynegy Inc., Computershare Inc. and Computershare Trust Company, N.A., as warrant agent
(incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K of Dynegy Inc. filed on February 7, 2017 File No. 001-33443).
|
10.59
|
|
|
Letter of Credit and Reimbursement Agreement, dated as of January 29, 2014 between Illinois Power Marketing Company and Union Bank, N.A.
(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. and Illinois Power Generating Company filed on February 4, 2014 File No. 001-33443).
|
10.60
|
|
|
Waiver and Amendment No. 1 to Letter of Credit and Reimbursement Agreement by and between Illinois Power Marketing Company and Union Bank, N.A.
(incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2014 of Dynegy Inc. File No. 001-33443).
|
10.61
|
|
|
Amendment No. 2 to Letter of Credit and Reimbursement Agreement by and between Illinois Power Marketing Company and Union Bank, N.A.
(incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2015 of Dynegy Inc. File No. 001-33443).
|
10.62
|
|
|
Amendment No. 3 to Letter of Credit and Reimbursement Agreement by and between Illinois Power Marketing Company and Union Bank, N.A.
(incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2016 of Dynegy Inc. File No. 001-33443).
|
10.63
|
|
|
Amendment and Waiver Agreement, dated February 2, 2017, to the Letter of Credit and Reimbursement Agreement by and between Illinois Power Marketing Company and MUFG Union Bank, N.A.
(incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2017 of Dynegy Inc. File No. 001-33443).
|
10.64
|
|
|
Amendment Agreement, dated March 8, 2017, to the Letter of Credit and Reimbursement Agreement by and between Illinois Power Marketing Company and MUFG Union Bank, N.A.
(incorporated by reference to Exhibit 10.8 to the Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2017 of Dynegy Inc. File No. 001-33443).
|
10.65
|
|
|
Second Amendment Agreement, dated April 21, 2017, to the Letter of Credit and Reimbursement Agreement by and between Illinois Power Marketing Company and MUFG Union Bank, N.A
(incorporated by reference to Exhibit 10.9 to the Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2017 of Dynegy Inc. File No. 001-33443).
|
10.66
|
|
|
Investor Rights Agreement, dated as of February 7, 2017, by and between Dynegy Inc. and Terawatt Holdings, LP
(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on February 8, 2017 File No. 001-33443)
.
|
10.67
|
|
|
Amendment No. 1 to the Investor Rights Agreement by and between Dynegy Inc. and Terawatt Holdings, LP
(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on September 6, 2017 File No. 001-33443).
|
10.68
|
|
|
Guaranty, dated as of August 3, 2016, by Dynegy Inc., for the benefit of J-POWER USA Development Co., Ltd.
(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on August 4, 2016 File No. 001-33443).
|
10.69
|
|
|
Restructuring Support Agreement dated October 14, 2016
(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on October 14, 2016 File No. 001-33443).
|
10.70
|
|
|
Amendment to Restructuring Support Agreement dated October 21, 2016
(incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2016 of Dynegy Inc. File No. 001-33443).
|
10.71
|
|
|
Merger Support Agreement, dated as of October 29, 2017, by and between Dynegy Inc. and Stockholders of Vistra Energy Corp. Party Thereto
(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on October 30, 2017 File No. 001-33443).
|
14.1
|
|
|
Dynegy Inc. Code of Ethics for Senior Financial Professionals, as amended on July 23, 2013
(incorporated by reference to Exhibit 14.1 to the Annual Report on Form 10-K for the Year Ended December 31, 2013 of Dynegy Inc. File No. 001-33443).
|
***21.1
|
|
|
|
***23.1
|
|
|
|
***31.1
|
|
|
|
***31.2
|
|
|
†32.1
|
|
|
|
†32.2
|
|
|
|
***95
|
|
|
|
**101.INS
|
|
|
XBRL Instance Document
|
**101.SCH
|
|
|
XBRL Taxonomy Extension Schema Document
|
**101.CAL
|
|
|
XBRL Taxonomy Extension Calculation Linkbase Document
|
**101.DEF
|
|
|
XBRL Taxonomy Extension Definition Linkbase Document
|
**101.LAB
|
|
|
XBRL Taxonomy Extension Label Linkbase Document
|
**101.PRE
|
|
|
XBRL Taxonomy Extension Presentation Linkbase Document
|
*
|
Pursuant to Item 6.01(b)(2) of Regulation S-K exhibits and schedules are omitted. Dynegy agrees to furnish to the Commission supplementally a copy of any omitted schedule or exhibit upon request of the Commission.
|
**
|
XBRL information is furnished and not filed for purposes of Section 11 and 12 of the Securities Act of 1933 and Section 18 of the Securities Exchange Act of 1934, and is not subject to liability under those sections, is not part of any registration statement or prospectus to which it relates and is not incorporated or deemed to be incorporated by reference into any registration statement, prospectus or other document.
|
***
|
Filed herewith.
|
****
|
Pursuant to a request for confidential treatment, portions of this Exhibit have been redacted and filed separately with the SEC as required by Rule 24b-2 under the Securities Exchange Act of 1934, as amended.
|
†
|
Pursuant to Securities and Exchange Commission Release No. 33-8238, this certification will be treated as “accompanying” this report and not “filed” as part of such report for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or the Exchange Act, or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Exchange Act.
|
††
|
Management contract or compensation plan.
|
|
|
|
|
|
|
|
DYNEGY INC.
|
||
Date:
|
February 22, 2018
|
By:
|
|
/s/ ROBERT C. FLEXON
Robert C. Flexon
President and Chief Executive Officer
|
|
|
|
|
|
/s/ ROBERT C. FLEXON
Robert C. Flexon
|
|
President and Chief Executive Officer & Director (Principal Executive Officer)
|
|
February 22, 2018
|
/s/ CLINT C. FREELAND
Clint C. Freeland
|
|
Executive Vice President and Chief Financial Officer (Principal Financial Officer)
|
|
February 22, 2018
|
/s/ J. CLINTON WALDEN
J. Clinton Walden |
|
Vice President and Chief Accounting Officer (Principal Accounting Officer)
|
|
February 22, 2018
|
/s/ PAT WOOD III
Pat Wood III
|
|
Chairman of the Board
|
|
February 22, 2018
|
/s/ HILARY E. ACKERMANN
Hilary E. Ackermann
|
|
Director
|
|
February 22, 2018
|
/s/ PAUL M. BARBAS
Paul M. Barbas
|
|
Director
|
|
February 22, 2018
|
/s/ RICHARD LEE KUERSTEINER
Richard Lee Kuersteiner
|
|
Director
|
|
February 22, 2018
|
/s/ JEFFREY S. STEIN
Jeffrey S. Stein
|
|
Director
|
|
February 22, 2018
|
/s/ JOHN R. SULT
John R. Sult
|
|
Director
|
|
February 22, 2018
|
|
|
|
|
|
|
|
|
|
|
|
Page
|
|
Consolidated Financial Statements
|
|
|
|
|
|
||
Consolidated Balance Sheets:
|
|
|
|
|
|
||
Consolidated Statements of Operations:
|
|
|
|
|
|
||
Consolidated Statements of Comprehensive Income (Loss):
|
|
|
|
|
|
||
Consolidated Statements of Cash Flows:
|
|
|
|
|
|
||
Consolidated Statements of Changes in Equity:
|
|
|
|
|
|
||
|
|
|
|
December 31, 2017
|
|
December 31, 2016
|
||||
ASSETS
|
|
|
|
|
|
|
||
Current Assets
|
|
|
|
|
|
|
||
Cash and cash equivalents
|
|
$
|
365
|
|
|
$
|
1,776
|
|
Restricted cash
|
|
—
|
|
|
62
|
|
||
Accounts receivable, net of allowance for doubtful accounts of $1 and $1, respectively
|
|
513
|
|
|
386
|
|
||
Inventory
|
|
445
|
|
|
445
|
|
||
Assets from risk management activities
|
|
32
|
|
|
130
|
|
||
Intangible assets
|
|
25
|
|
|
38
|
|
||
Prepayments and other current assets
|
|
144
|
|
|
150
|
|
||
Total Current Assets
|
|
1,524
|
|
|
2,987
|
|
||
Property, plant and equipment, net
|
|
8,884
|
|
|
7,121
|
|
||
Investment in unconsolidated affiliate
|
|
123
|
|
|
—
|
|
||
Restricted cash
|
|
—
|
|
|
2,000
|
|
||
Assets from risk management activities
|
|
26
|
|
|
16
|
|
||
Goodwill
|
|
772
|
|
|
799
|
|
||
Intangible assets
|
|
39
|
|
|
23
|
|
||
Other long-term assets
|
|
403
|
|
|
107
|
|
||
Total Assets
|
|
$
|
11,771
|
|
|
$
|
13,053
|
|
|
|
December 31, 2017
|
|
December 31, 2016
|
||||
LIABILITIES AND EQUITY
|
|
|
|
|
|
|
||
Current Liabilities
|
|
|
|
|
|
|
||
Accounts payable
|
|
$
|
367
|
|
|
$
|
332
|
|
Accrued interest
|
|
115
|
|
|
81
|
|
||
Intangible liabilities
|
|
14
|
|
|
21
|
|
||
Accrued taxes
|
|
64
|
|
|
45
|
|
||
Accrued liabilities and other current liabilities
|
|
109
|
|
|
88
|
|
||
Liabilities from risk management activities
|
|
229
|
|
|
97
|
|
||
Asset retirement obligations
|
|
46
|
|
|
51
|
|
||
Debt, current portion, net
|
|
105
|
|
|
201
|
|
||
Total Current Liabilities
|
|
1,049
|
|
|
916
|
|
||
Liabilities subject to compromise (Note 20)
|
|
—
|
|
|
832
|
|
||
Debt, long-term portion, net
|
|
8,328
|
|
|
8,778
|
|
||
Other Liabilities
|
|
|
|
|
|
|
||
Liabilities from risk management activities
|
|
31
|
|
|
43
|
|
||
Asset retirement obligations
|
|
283
|
|
|
236
|
|
||
Deferred income taxes
|
|
7
|
|
|
5
|
|
||
Intangible liabilities
|
|
34
|
|
|
34
|
|
||
Other long-term liabilities
|
|
146
|
|
|
170
|
|
||
Total Liabilities
|
|
9,878
|
|
|
11,014
|
|
||
Commitments and Contingencies (Note 16)
|
|
|
|
|
|
|
||
|
|
|
|
|
||||
Stockholders’ Equity
|
|
|
|
|
||||
Preferred Stock, $0.01 par value, 20,000,000 shares authorized:
|
|
|
|
|
||||
Series A 5.375% mandatory convertible preferred stock, $0.01 par value; 4,000,000 shares issued and outstanding at December 31, 2016
|
|
—
|
|
|
400
|
|
||
Common stock, $0.01 par value, 420,000,000 shares authorized; 155,710,613 shares issued and 144,384,491 shares outstanding at December 31, 2017; 128,626,740 shares issued and 117,300,618 outstanding at December 31, 2016
|
|
1
|
|
|
1
|
|
||
Additional paid-in capital
|
|
3,719
|
|
|
3,547
|
|
||
Accumulated other comprehensive income, net of tax
|
|
32
|
|
|
21
|
|
||
Accumulated deficit
|
|
(1,851
|
)
|
|
(1,927
|
)
|
||
Total Dynegy Stockholders’ Equity
|
|
1,901
|
|
|
2,042
|
|
||
Noncontrolling interest
|
|
(8
|
)
|
|
(3
|
)
|
||
Total Equity
|
|
1,893
|
|
|
2,039
|
|
||
Total Liabilities and Equity
|
|
$
|
11,771
|
|
|
$
|
13,053
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
Revenues
|
|
$
|
4,842
|
|
|
$
|
4,318
|
|
|
$
|
3,870
|
|
Cost of sales, excluding depreciation expense
|
|
(2,932
|
)
|
|
(2,281
|
)
|
|
(2,028
|
)
|
|||
Gross margin
|
|
1,910
|
|
|
2,037
|
|
|
1,842
|
|
|||
Operating and maintenance expense
|
|
(995
|
)
|
|
(940
|
)
|
|
(839
|
)
|
|||
Depreciation expense
|
|
(811
|
)
|
|
(689
|
)
|
|
(587
|
)
|
|||
Impairments
|
|
(148
|
)
|
|
(858
|
)
|
|
(99
|
)
|
|||
Loss on sale of assets, net
|
|
(122
|
)
|
|
(1
|
)
|
|
(1
|
)
|
|||
General and administrative expense
|
|
(189
|
)
|
|
(161
|
)
|
|
(128
|
)
|
|||
Acquisition and integration costs
|
|
(57
|
)
|
|
(11
|
)
|
|
(124
|
)
|
|||
Other
|
|
—
|
|
|
(17
|
)
|
|
—
|
|
|||
Operating income (loss)
|
|
(412
|
)
|
|
(640
|
)
|
|
64
|
|
|||
Bankruptcy reorganization items (Note 20)
|
|
494
|
|
|
(96
|
)
|
|
—
|
|
|||
Earnings from unconsolidated investments
|
|
8
|
|
|
7
|
|
|
1
|
|
|||
Interest expense
|
|
(616
|
)
|
|
(625
|
)
|
|
(546
|
)
|
|||
Loss on early extinguishment of debt (Note 13)
|
|
(79
|
)
|
|
—
|
|
|
—
|
|
|||
Other income and expense, net
|
|
67
|
|
|
65
|
|
|
54
|
|
|||
Loss before income taxes
|
|
(538
|
)
|
|
(1,289
|
)
|
|
(427
|
)
|
|||
Income tax benefit (Note 14)
|
|
610
|
|
|
45
|
|
|
474
|
|
|||
Net income (loss)
|
|
72
|
|
|
(1,244
|
)
|
|
47
|
|
|||
Less: Net loss attributable to noncontrolling interest
|
|
(4
|
)
|
|
(4
|
)
|
|
(3
|
)
|
|||
Net income (loss) attributable to Dynegy Inc.
|
|
76
|
|
|
(1,240
|
)
|
|
50
|
|
|||
Less: Dividends on preferred stock
|
|
18
|
|
|
22
|
|
|
22
|
|
|||
Net income (loss) attributable to Dynegy Inc. common stockholders
|
|
$
|
58
|
|
|
$
|
(1,262
|
)
|
|
$
|
28
|
|
|
|
|
|
|
|
|
||||||
Earnings (Loss) Per Share (Note 15):
|
|
|
|
|
|
|
||||||
Basic earnings (loss) per share attributable to Dynegy Inc. common stockholders
|
|
$
|
0.37
|
|
|
$
|
(9.78
|
)
|
|
$
|
0.22
|
|
|
|
|
|
|
|
|
|
|
||||
Diluted earnings (loss) per share attributable to Dynegy Inc. common stockholders
|
|
$
|
0.36
|
|
|
$
|
(9.78
|
)
|
|
$
|
0.22
|
|
|
|
|
|
|
|
|
|
|
||||
Basic shares outstanding
|
|
155
|
|
|
129
|
|
|
125
|
|
|||
Diluted shares outstanding
|
|
162
|
|
|
129
|
|
|
126
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
Net income (loss)
|
|
$
|
72
|
|
|
$
|
(1,244
|
)
|
|
$
|
47
|
|
Other comprehensive income before reclassifications:
|
|
|
|
|
|
|
||||||
Actuarial gain and plan amendments (net of tax of $5, $3, and zero, respectively)
|
|
19
|
|
|
3
|
|
|
4
|
|
|||
Amounts reclassified from accumulated other comprehensive income:
|
|
|
|
|
|
|
||||||
Settlement cost (net of tax of zero)
|
|
—
|
|
|
6
|
|
|
—
|
|
|||
Amortization of unrecognized prior service credit and actuarial gain (net of tax of zero, zero, and zero, respectively)
|
|
(8
|
)
|
|
(5
|
)
|
|
(4
|
)
|
|||
Other comprehensive income, net of tax
|
|
11
|
|
|
4
|
|
|
—
|
|
|||
Comprehensive income (loss)
|
|
83
|
|
|
(1,240
|
)
|
|
47
|
|
|||
Less: Comprehensive loss attributable to noncontrolling interest
|
|
(4
|
)
|
|
(2
|
)
|
|
(2
|
)
|
|||
Total comprehensive income (loss) attributable to Dynegy Inc.
|
|
$
|
87
|
|
|
$
|
(1,238
|
)
|
|
$
|
49
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
CASH FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
||||||
Net income (loss)
|
|
$
|
72
|
|
|
$
|
(1,244
|
)
|
|
$
|
47
|
|
Adjustments to reconcile net income (loss) to net cash flows from operating activities:
|
|
|
|
|
|
|
||||||
Depreciation expense
|
|
811
|
|
|
689
|
|
|
587
|
|
|||
Loss on early extinguishment of debt
|
|
79
|
|
|
—
|
|
|
—
|
|
|||
Non-cash interest expense
|
|
44
|
|
|
56
|
|
|
38
|
|
|||
Amortization of intangibles
|
|
12
|
|
|
21
|
|
|
(11
|
)
|
|||
Bankruptcy reorganization items
|
|
(494
|
)
|
|
96
|
|
|
—
|
|
|||
Impairments
|
|
148
|
|
|
858
|
|
|
99
|
|
|||
Risk management activities
|
|
207
|
|
|
(148
|
)
|
|
(130
|
)
|
|||
Loss on sale of assets, net
|
|
122
|
|
|
1
|
|
|
1
|
|
|||
Earnings from unconsolidated investments
|
|
(8
|
)
|
|
(7
|
)
|
|
(1
|
)
|
|||
Deferred income taxes
|
|
(610
|
)
|
|
(45
|
)
|
|
(477
|
)
|
|||
Change in value of common stock warrants
|
|
(16
|
)
|
|
(6
|
)
|
|
(54
|
)
|
|||
Other
|
|
81
|
|
|
14
|
|
|
51
|
|
|||
Changes in working capital:
|
|
|
|
|
|
|
||||||
Accounts receivable, net
|
|
(47
|
)
|
|
42
|
|
|
(64
|
)
|
|||
Inventory
|
|
110
|
|
|
154
|
|
|
(119
|
)
|
|||
Prepayments and other current assets
|
|
26
|
|
|
94
|
|
|
94
|
|
|||
Accounts payable and accrued liabilities
|
|
46
|
|
|
84
|
|
|
25
|
|
|||
Distributions from unconsolidated investments
|
|
5
|
|
|
1
|
|
|
3
|
|
|||
Changes in non-current assets
|
|
(12
|
)
|
|
(43
|
)
|
|
—
|
|
|||
Changes in non-current liabilities
|
|
9
|
|
|
28
|
|
|
5
|
|
|||
Net cash provided by operating activities
|
|
585
|
|
|
645
|
|
|
94
|
|
|||
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
||||||
Capital expenditures
|
|
(224
|
)
|
|
(293
|
)
|
|
(301
|
)
|
|||
Acquisitions, net of cash acquired
|
|
(3,319
|
)
|
|
—
|
|
|
(6,078
|
)
|
|||
Distributions from unconsolidated investments
|
|
12
|
|
|
14
|
|
|
8
|
|
|||
Proceeds from asset sales, net
|
|
772
|
|
|
176
|
|
|
—
|
|
|||
Other investing
|
|
—
|
|
|
10
|
|
|
3
|
|
|||
Net cash used in investing activities
|
|
(2,759
|
)
|
|
(93
|
)
|
|
(6,368
|
)
|
|||
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
||||||
Proceeds from long-term borrowings, net of debt issuance costs
|
|
1,743
|
|
|
3,014
|
|
|
66
|
|
|||
Repayments of borrowings
|
|
(2,589
|
)
|
|
(589
|
)
|
|
(31
|
)
|
|||
Proceeds from issuance of equity, net of issuance costs
|
|
150
|
|
|
359
|
|
|
(6
|
)
|
|||
Payments of debt extinguishment costs
|
|
(50
|
)
|
|
—
|
|
|
—
|
|
|||
Preferred stock dividends paid
|
|
(22
|
)
|
|
(22
|
)
|
|
(23
|
)
|
|||
Interest rate swap settlement payments
|
|
(20
|
)
|
|
(17
|
)
|
|
(17
|
)
|
|||
Acquisition of noncontrolling interest
|
|
(375
|
)
|
|
—
|
|
|
—
|
|
|||
Payments related to bankruptcy settlement
|
|
(133
|
)
|
|
—
|
|
|
—
|
|
|||
Repurchase of common stock
|
|
—
|
|
|
—
|
|
|
(250
|
)
|
|||
Other financing
|
|
(3
|
)
|
|
(3
|
)
|
|
(4
|
)
|
|||
Net cash provided by (used in) financing activities
|
|
(1,299
|
)
|
|
2,742
|
|
|
(265
|
)
|
|||
Net increase (decrease) in cash, cash equivalents and restricted cash
|
|
(3,473
|
)
|
|
3,294
|
|
|
(6,539
|
)
|
|||
Cash, cash equivalents and restricted cash, beginning of period
|
|
3,838
|
|
|
544
|
|
|
7,083
|
|
|||
Cash, cash equivalents and restricted cash, end of period
|
|
$
|
365
|
|
|
$
|
3,838
|
|
|
$
|
544
|
|
|
Preferred Stock
|
|
Common Stock
|
|
Additional Paid-In Capital
|
|
AOCI
|
|
Accumulated Deficit
|
|
Total Controlling Interests
|
|
Noncontrolling Interest
|
|
Total
|
||||||||||||||||
December 31, 2014
|
$
|
400
|
|
|
$
|
1
|
|
|
$
|
3,338
|
|
|
$
|
20
|
|
|
$
|
(736
|
)
|
|
$
|
3,023
|
|
|
$
|
—
|
|
|
$
|
3,023
|
|
Net income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
50
|
|
|
50
|
|
|
(3
|
)
|
|
47
|
|
||||||||
Equity issuance for acquisition, net (Note 15)
|
—
|
|
|
—
|
|
|
99
|
|
|
—
|
|
|
—
|
|
|
99
|
|
|
—
|
|
|
99
|
|
||||||||
Other comprehensive income (loss), net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
|
1
|
|
|
—
|
|
||||||||
Share-based compensation expense, net of tax
|
—
|
|
|
—
|
|
|
22
|
|
|
—
|
|
|
—
|
|
|
22
|
|
|
—
|
|
|
22
|
|
||||||||
Options exercised
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
||||||||
Dividends Paid
|
—
|
|
|
—
|
|
|
(23
|
)
|
|
—
|
|
|
—
|
|
|
(23
|
)
|
|
—
|
|
|
(23
|
)
|
||||||||
Repurchases of common stock (Note 15)
|
—
|
|
|
—
|
|
|
(250
|
)
|
|
—
|
|
|
—
|
|
|
(250
|
)
|
|
—
|
|
|
(250
|
)
|
||||||||
December 31, 2015
|
400
|
|
|
1
|
|
|
3,187
|
|
|
19
|
|
|
(686
|
)
|
|
2,921
|
|
|
(2
|
)
|
|
2,919
|
|
||||||||
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,240
|
)
|
|
(1,240
|
)
|
|
(4
|
)
|
|
(1,244
|
)
|
||||||||
TEUs (Note 12)
|
—
|
|
|
—
|
|
|
359
|
|
|
—
|
|
|
—
|
|
|
359
|
|
|
—
|
|
|
359
|
|
||||||||
Other comprehensive income, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
2
|
|
|
2
|
|
|
4
|
|
||||||||
Share-based compensation expense, net of tax
|
—
|
|
|
—
|
|
|
22
|
|
|
—
|
|
|
—
|
|
|
22
|
|
|
—
|
|
|
22
|
|
||||||||
Dividends paid
|
—
|
|
|
—
|
|
|
(22
|
)
|
|
—
|
|
|
—
|
|
|
(22
|
)
|
|
—
|
|
|
(22
|
)
|
||||||||
Other
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
1
|
|
|
1
|
|
||||||||
December 31, 2016
|
400
|
|
|
1
|
|
|
3,547
|
|
|
21
|
|
|
(1,927
|
)
|
|
2,042
|
|
|
(3
|
)
|
|
2,039
|
|
||||||||
Net income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
76
|
|
|
76
|
|
|
(4
|
)
|
|
72
|
|
||||||||
Equity issuance for acquisition, net (Note 15)
|
—
|
|
|
—
|
|
|
150
|
|
|
—
|
|
|
—
|
|
|
150
|
|
|
—
|
|
|
150
|
|
||||||||
Preferred stock conversion
|
(400
|
)
|
|
—
|
|
|
400
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Other comprehensive income, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
11
|
|
|
—
|
|
|
11
|
|
|
—
|
|
|
11
|
|
||||||||
Share-based compensation expense, net of tax
|
—
|
|
|
—
|
|
|
19
|
|
|
—
|
|
|
—
|
|
|
19
|
|
|
—
|
|
|
19
|
|
||||||||
Acquisition of non-controlling interest
|
—
|
|
|
—
|
|
|
(375
|
)
|
|
—
|
|
|
—
|
|
|
(375
|
)
|
|
—
|
|
|
(375
|
)
|
||||||||
Dividends paid
|
—
|
|
|
—
|
|
|
(22
|
)
|
|
—
|
|
|
—
|
|
|
(22
|
)
|
|
—
|
|
|
(22
|
)
|
||||||||
Other
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
(1
|
)
|
||||||||
December 31, 2017
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
3,719
|
|
|
$
|
32
|
|
|
$
|
(1,851
|
)
|
|
$
|
1,901
|
|
|
$
|
(8
|
)
|
|
$
|
1,893
|
|
(1)
|
Upon the emergence of Genco from bankruptcy, approximately
$35 million
of these deposits were returned to Dynegy.
|
(2)
|
Upon the close of the ENGIE Acquisition, as defined herein, the proceeds from the issuance of the Term Loan were released from escrow. Please read
Note 13—Debt
for further information.
|
Asset Group
|
|
Range of
Years
|
Power generation
|
|
1 to 36
|
Buildings and improvements
|
|
1 to 40
|
Office and other equipment
|
|
1 to 28
|
|
|
Year Ended December 31,
|
||||||
(amounts in millions)
|
|
2017
|
|
2016
|
||||
Balance at beginning of year
|
|
$
|
287
|
|
|
$
|
280
|
|
Accretion expense
|
|
20
|
|
|
20
|
|
||
Liabilities settled
|
|
(8
|
)
|
|
(1
|
)
|
||
Revision of previous estimate (1)
|
|
22
|
|
|
(12
|
)
|
||
Acquisitions
|
|
24
|
|
|
—
|
|
||
Divestitures
|
|
(16
|
)
|
|
—
|
|
||
Balance at end of year
|
|
$
|
329
|
|
|
$
|
287
|
|
(1)
|
Based on management’s review and assessment of CCR compliance timing and site-specific analysis.
|
•
|
Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed equities, and U.S. government treasury securities.
|
•
|
Level 2—Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using industry-standard models or other valuation methodologies in which substantially all assumptions are observable in the marketplace throughout the full term of the instrument, and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as over the counter forwards, options, and swaps.
|
•
|
Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to our needs. At each balance sheet date, we perform an analysis of all instruments and include in Level 3 all of those whose fair value is based on significant unobservable inputs.
|
(amounts in millions)
|
|
December 31, 2017
|
|
December 31, 2016
|
|
December 31, 2015
|
||||||
Cash and cash equivalents
|
|
$
|
365
|
|
|
$
|
1,776
|
|
|
$
|
505
|
|
Restricted cash included in current assets (1)
|
|
—
|
|
|
62
|
|
|
39
|
|
|||
Restricted cash included in long-term assets (2)
|
|
—
|
|
|
2,000
|
|
|
—
|
|
|||
Total cash, cash equivalents and restricted cash
|
|
$
|
365
|
|
|
$
|
3,838
|
|
|
$
|
544
|
|
(1)
|
Year ended December 31, 2016, includes
$41 million
related to collateral and
$21 million
placed in escrow for the issuance of the Term Loan (
$20 million
of pre-funded original issue discount and
$1 million
interest income earned). Year ended December 31, 2015, includes
$39 million
related to collateral.
|
(2)
|
Relates to amounts placed into escrow for the issuance of the Term Loan.
|
•
|
Working capital was valued using available market information (Level 2).
|
•
|
Acquired PP&E, excluding those assets classified as held-for-sale, was valued using a discounted cash flow (“DCF”) analysis based upon a debt-free, free cash flow model (Level 3). The DCF model was created for each power generation facility based on its remaining useful life, and:
|
◦
|
for the years 2017 and 2018, included gross margin forecasts using quoted forward commodity market prices;
|
◦
|
for the years 2019 through 2026, we used gross margin forecasts based upon commodity and capacity price curves developed internally using forward New York Mercantile Exchange natural gas prices and supply and demand factors;
|
◦
|
for periods beyond 2026, we assumed a
2.5 percent
growth rate.
|
•
|
Acquired PP&E classified as held-for-sale was valued based upon the sale price of the assets (Level 3).
|
•
|
Acquired derivatives were valued using the methods described in
Note 5—Fair Value Measurements
(Level 2 or Level 3).
|
•
|
Contracts with terms that were not at current market prices were also valued using a DCF analysis (Level 3). The cash flows generated by the contracts were compared with their cash flows based on current market prices with the resulting difference recorded as either an intangible asset or liability.
|
•
|
AROs were recorded in accordance with ASC 410, Asset Retirement and Environmental Obligations (Level 3).
|
(amounts in millions)
|
|
|
||
Base purchase price
|
|
$
|
3,300
|
|
Working capital adjustments and other
|
|
(31
|
)
|
|
Fair value of total consideration transferred
|
|
$
|
3,269
|
|
|
|
|
||
Cash
|
|
$
|
20
|
|
Accounts receivable
|
|
22
|
|
|
Inventory
|
|
95
|
|
|
Prepayments and other current assets
|
|
3
|
|
|
Assets from risk management activities (including current portion of $21 million)
|
|
25
|
|
|
Property, plant and equipment
|
|
2,775
|
|
|
Investment in unconsolidated affiliate
|
|
132
|
|
|
Intangible assets (including current portion of $7 million)
|
|
50
|
|
|
Assets held-for-sale
|
|
472
|
|
|
Other long-term assets
|
|
131
|
|
|
Total assets acquired
|
|
3,725
|
|
|
|
|
|
||
Accounts payable
|
|
18
|
|
|
Liabilities from risk management activities (including current portion of $13 million)
|
|
16
|
|
|
Asset retirement obligations
|
|
19
|
|
|
Intangible liabilities (including current portion of $16 million)
|
|
30
|
|
|
Deferred income taxes, net
|
|
372
|
|
|
Other long-term liabilities
|
|
1
|
|
|
Total liabilities assumed
|
|
456
|
|
|
Net assets acquired
|
|
$
|
3,269
|
|
|
|
Year Ended December 31,
|
||||||||||
(amounts in millions)
|
|
2017
|
|
2016
|
|
2015
|
||||||
Acquisition costs
|
|
$
|
38
|
|
|
$
|
5
|
|
|
$
|
86
|
|
Revenues
|
|
$
|
3,079
|
|
|
$
|
2,280
|
|
|
$
|
1,703
|
|
Operating income
|
|
$
|
86
|
|
|
$
|
235
|
|
|
$
|
230
|
|
|
|
Year Ended December 31,
|
||||||||||
(amounts in millions)
|
|
2017
|
|
2016
|
|
2015
|
||||||
Revenues
|
|
$
|
4,899
|
|
|
$
|
5,046
|
|
|
$
|
4,860
|
|
Net income (loss)
|
|
$
|
77
|
|
|
$
|
(1,361
|
)
|
|
$
|
308
|
|
Net loss attributable to noncontrolling interest
|
|
$
|
(4
|
)
|
|
$
|
(4
|
)
|
|
$
|
(3
|
)
|
Net income (loss) attributable to Dynegy Inc.
|
|
$
|
81
|
|
|
$
|
(1,357
|
)
|
|
$
|
311
|
|
Contract Type
|
|
Quantity
|
|
Unit of Measure
|
|
Fair Value (1)
|
|||
(dollars and quantities in millions)
|
|
Purchases (Sales)
|
|
|
|
Asset (Liability)
|
|||
Commodity contracts:
|
|
|
|
|
|
|
|||
Electricity derivatives (2)
|
|
(62
|
)
|
|
MWh
|
|
$
|
(150
|
)
|
Electricity basis derivatives (3)
|
|
(25
|
)
|
|
MWh
|
|
$
|
(4
|
)
|
Natural gas derivatives (2)
|
|
404
|
|
|
MMBtu
|
|
$
|
(4
|
)
|
Natural gas basis derivatives
|
|
120
|
|
|
MMBtu
|
|
$
|
(1
|
)
|
Physical heat rate derivatives (4)
|
|
177/(17)
|
|
|
MMBtu/MWh
|
|
$
|
(95
|
)
|
Heat rate option
|
|
6/(1)
|
|
|
MMBtu/MWh
|
|
$
|
(4
|
)
|
Emissions derivatives
|
|
8
|
|
|
Metric Ton
|
|
$
|
2
|
|
Interest rate swaps
|
|
1,961
|
|
|
U.S. Dollar
|
|
$
|
7
|
|
Common stock warrants (5)
|
|
9
|
|
|
Warrant
|
|
$
|
(2
|
)
|
(1)
|
Includes both asset and liability risk management positions but excludes margin and collateral netting of
$47 million
.
|
(2)
|
Mainly comprised of swaps and physical forwards.
|
(3)
|
Comprised of FTRs and swaps.
|
(4)
|
Comprised of swaps which settle on the relationship of power pricing to natural gas pricing.
|
(5)
|
Each warrant is convertible into
one
share of Dynegy common stock.
|
|
|
|
|
|
December 31, 2017
|
||||||||||||||
|
|
|
|
|
|
|
Gross amounts offset in the balance sheet
|
|
|
||||||||||
Contract Type
|
|
Balance Sheet Location
|
|
Gross Fair Value
|
|
Contract Netting
|
|
Collateral or Margin Received or Paid
|
|
Net Fair Value
|
|||||||||
(amounts in millions)
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Derivative assets:
|
|
|
|
|
|
|
|
|
|
|
|||||||||
|
Commodity contracts
|
|
Assets from risk management activities
|
|
$
|
155
|
|
|
$
|
(112
|
)
|
|
$
|
—
|
|
|
$
|
43
|
|
|
Interest rate contracts
|
|
Assets from risk management activities
|
|
20
|
|
|
(5
|
)
|
|
—
|
|
|
15
|
|
||||
|
Total derivative assets
|
|
|
|
$
|
175
|
|
|
$
|
(117
|
)
|
|
$
|
—
|
|
|
$
|
58
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Derivative liabilities:
|
|
|
|
|
|
|
|
|
|
|
|||||||||
|
Commodity contracts
|
|
Liabilities from risk management activities
|
|
$
|
(411
|
)
|
|
$
|
112
|
|
|
$
|
47
|
|
|
$
|
(252
|
)
|
|
Interest rate contracts
|
|
Liabilities from risk management activities
|
|
(13
|
)
|
|
5
|
|
|
—
|
|
|
(8
|
)
|
||||
|
Common stock warrants
|
|
Accrued liabilities and other current liabilities and other long-term liabilities
|
|
(2
|
)
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
||||
|
Total derivative liabilities
|
|
|
|
$
|
(426
|
)
|
|
$
|
117
|
|
|
$
|
47
|
|
|
$
|
(262
|
)
|
Total derivatives
|
|
|
|
$
|
(251
|
)
|
|
$
|
—
|
|
|
$
|
47
|
|
|
$
|
(204
|
)
|
|
|
|
|
|
December 31, 2016
|
||||||||||||||
|
|
|
|
|
|
|
Gross amounts offset in the balance sheet
|
|
|
||||||||||
Contract Type
|
|
Balance Sheet Location
|
|
Gross Fair Value
|
|
Contract Netting
|
|
Collateral or Margin Received or Paid
|
|
Net Fair Value
|
|||||||||
(amounts in millions)
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Derivative assets:
|
|
|
|
|
|
|
|
|
|
|
|||||||||
|
Commodity contracts
|
|
Assets from risk management activities
|
|
$
|
311
|
|
|
$
|
(165
|
)
|
|
$
|
—
|
|
|
$
|
146
|
|
|
Total derivative assets
|
|
|
|
$
|
311
|
|
|
$
|
(165
|
)
|
|
$
|
—
|
|
|
$
|
146
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Derivative liabilities:
|
|
|
|
|
|
|
|
|
|
|
|||||||||
|
Commodity contracts
|
|
Liabilities from risk management activities
|
|
$
|
(329
|
)
|
|
$
|
165
|
|
|
$
|
54
|
|
|
$
|
(110
|
)
|
|
Interest rate contracts
|
|
Liabilities from risk management activities
|
|
(30
|
)
|
|
—
|
|
|
—
|
|
|
(30
|
)
|
||||
|
Common stock warrants
|
|
Accrued liabilities and other current liabilities
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
||||
|
Total derivative liabilities
|
|
|
|
$
|
(360
|
)
|
|
$
|
165
|
|
|
$
|
54
|
|
|
$
|
(141
|
)
|
Total derivatives
|
|
|
|
$
|
(49
|
)
|
|
$
|
—
|
|
|
$
|
54
|
|
|
$
|
5
|
|
Location on Balance Sheet
|
|
December 31, 2017
|
|
December 31, 2016
|
||||
(amounts in millions)
|
|
|
|
|
||||
Gross collateral posted with counterparties
|
|
$
|
92
|
|
|
$
|
116
|
|
Less: Collateral netted against risk management liabilities
|
|
47
|
|
|
54
|
|
||
Net collateral within Prepayments and other current assets
|
|
$
|
45
|
|
|
$
|
62
|
|
Derivatives Not Designated as Hedges
|
|
Location of Gain (Loss) Recognized in Income on Derivatives
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||||
(amounts in millions)
|
|
|
|
|
|
|
|
|
||||||
Commodity contracts
|
|
Revenues
|
|
$
|
(58
|
)
|
|
$
|
270
|
|
|
$
|
194
|
|
Interest rate contracts
|
|
Interest expense
|
|
$
|
16
|
|
|
$
|
(5
|
)
|
|
$
|
(15
|
)
|
Common stock warrants
|
|
Other income and (expense), net
|
|
$
|
16
|
|
|
$
|
6
|
|
|
$
|
54
|
|
|
|
Fair Value as of December 31, 2017
|
||||||||||||||
(amounts in millions)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Assets from commodity risk management activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Electricity derivatives
|
|
$
|
—
|
|
|
$
|
71
|
|
|
$
|
6
|
|
|
$
|
77
|
|
Natural gas derivatives
|
|
—
|
|
|
62
|
|
|
10
|
|
|
72
|
|
||||
Physical heat rate derivatives
|
|
—
|
|
|
4
|
|
|
—
|
|
|
4
|
|
||||
Emissions derivatives
|
|
—
|
|
|
2
|
|
|
—
|
|
|
2
|
|
||||
Total assets from commodity risk management activities
|
|
—
|
|
|
139
|
|
|
16
|
|
|
155
|
|
||||
Assets from interest rate contracts
|
|
—
|
|
|
20
|
|
|
—
|
|
|
20
|
|
||||
Total assets
|
|
$
|
—
|
|
|
$
|
159
|
|
|
$
|
16
|
|
|
$
|
175
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Liabilities from commodity risk management activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Electricity derivatives
|
|
$
|
—
|
|
|
$
|
(200
|
)
|
|
$
|
(31
|
)
|
|
$
|
(231
|
)
|
Natural gas derivatives
|
|
—
|
|
|
(71
|
)
|
|
(6
|
)
|
|
(77
|
)
|
||||
Physical heat rate derivatives
|
|
—
|
|
|
(99
|
)
|
|
—
|
|
|
(99
|
)
|
||||
Heat rate option
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
|
(4
|
)
|
||||
Total liabilities from commodity risk management activities
|
|
—
|
|
|
(370
|
)
|
|
(41
|
)
|
|
(411
|
)
|
||||
Liabilities from interest rate contracts
|
|
—
|
|
|
(13
|
)
|
|
—
|
|
|
(13
|
)
|
||||
Liabilities from outstanding common stock warrants
|
|
(2
|
)
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
||||
Total liabilities
|
|
$
|
(2
|
)
|
|
$
|
(383
|
)
|
|
$
|
(41
|
)
|
|
$
|
(426
|
)
|
|
|
Fair Value as of December 31, 2016
|
||||||||||||||
(amounts in millions)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Assets from commodity risk management activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Electricity derivatives
|
|
$
|
—
|
|
|
$
|
118
|
|
|
$
|
20
|
|
|
$
|
138
|
|
Natural gas derivatives
|
|
—
|
|
|
169
|
|
|
4
|
|
|
173
|
|
||||
Total assets from commodity risk management activities
|
|
$
|
—
|
|
|
$
|
287
|
|
|
$
|
24
|
|
|
$
|
311
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Liabilities from commodity risk management activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Electricity derivatives
|
|
$
|
—
|
|
|
$
|
(245
|
)
|
|
$
|
(12
|
)
|
|
$
|
(257
|
)
|
Natural gas derivatives
|
|
—
|
|
|
(52
|
)
|
|
(10
|
)
|
|
(62
|
)
|
||||
Emissions derivatives
|
|
—
|
|
|
(10
|
)
|
|
—
|
|
|
(10
|
)
|
||||
Total liabilities from commodity risk management activities
|
|
—
|
|
|
(307
|
)
|
|
(22
|
)
|
|
(329
|
)
|
||||
Liabilities from interest rate contracts
|
|
—
|
|
|
(30
|
)
|
|
—
|
|
|
(30
|
)
|
||||
Liabilities from outstanding common stock warrants
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
||||
Total liabilities
|
|
$
|
(1
|
)
|
|
$
|
(337
|
)
|
|
$
|
(22
|
)
|
|
$
|
(360
|
)
|
Transaction Type
|
|
Quantity
|
|
Unit of Measure
|
|
Net Fair Value
|
|
Valuation Technique
|
|
Significant Unobservable Input
|
|
Significant Unobservable Input Range
|
|||
(dollars in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Electricity derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Forward contracts—power (1)
|
|
(14
|
)
|
|
Million MWh
|
|
$
|
(23
|
)
|
|
Basis spread + liquid location
|
|
Basis spread
|
|
$4.25 - $6.25
|
FTRs
|
|
(22
|
)
|
|
Million MWh
|
|
$
|
(2
|
)
|
|
Historical congestion
|
|
Forward price
|
|
$0 - $6.00
|
Physical heat rate derivatives
|
|
4/0
|
|
|
Million MMBtu
/Million MWh |
|
$
|
—
|
|
|
Discounted Cash Flow
|
|
Forward price
|
|
$2.00 - $2.80 / $22 - $27
|
Heat rate option
|
|
6/1
|
|
|
Million MMBtu
/Million MWh |
|
$
|
(4
|
)
|
|
Option models
|
|
Power price volatility
Gas/Power price correlation |
|
30% - 50% / 70% - 100%
|
Natural gas derivatives (1)
|
|
95
|
|
|
Million MMBtu
|
|
$
|
4
|
|
|
Illiquid location fixed price
|
|
Forward price
|
|
$2.00 - $2.45
|
(1)
|
Represents forward financial and physical transactions at illiquid pricing locations and long-dated contracts.
|
|
|
Year Ended December 31, 2017
|
||||||||||||||
(amounts in millions)
|
|
Electricity
Derivatives |
|
Natural Gas Derivatives
|
|
Heat Rate Option
|
|
Total
|
||||||||
Balance at December 31, 2016
|
|
$
|
8
|
|
|
$
|
(6
|
)
|
|
$
|
—
|
|
|
$
|
2
|
|
Total gains (losses) included in earnings
|
|
(30
|
)
|
|
5
|
|
|
—
|
|
|
(25
|
)
|
||||
Settlements (1)
|
|
(4
|
)
|
|
5
|
|
|
—
|
|
|
1
|
|
||||
Option premiums received
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
|
(4
|
)
|
||||
Acquired derivatives
|
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
||||
Balance at December 31, 2017
|
|
$
|
(25
|
)
|
|
$
|
4
|
|
|
$
|
(4
|
)
|
|
$
|
(25
|
)
|
Unrealized gains (losses) relating to instruments held as of December 31, 2017
|
|
$
|
(30
|
)
|
|
$
|
5
|
|
|
$
|
—
|
|
|
$
|
(25
|
)
|
|
|
Year Ended December 31, 2016
|
||||||||||||||
(amounts in millions)
|
|
Electricity
Derivatives |
|
Natural Gas Derivatives
|
|
Coal Derivatives
|
|
Total
|
||||||||
Balance at December 31, 2015
|
|
$
|
(18
|
)
|
|
$
|
(32
|
)
|
|
$
|
2
|
|
|
$
|
(48
|
)
|
Total gains (losses) included in earnings
|
|
59
|
|
|
49
|
|
|
(4
|
)
|
|
104
|
|
||||
Settlements (1)
|
|
(33
|
)
|
|
(23
|
)
|
|
2
|
|
|
(54
|
)
|
||||
Balance at December 31, 2016
|
|
$
|
8
|
|
|
$
|
(6
|
)
|
|
$
|
—
|
|
|
$
|
2
|
|
Unrealized gains (losses) relating to instruments held as of December 31, 2016
|
|
$
|
59
|
|
|
$
|
49
|
|
|
$
|
(4
|
)
|
|
$
|
104
|
|
|
|
Year Ended December 31, 2015
|
||||||||||||||||||
(amounts in millions)
|
|
Electricity Derivatives
|
|
Natural Gas Derivatives
|
|
Heat Rate Derivatives
|
|
Coal Derivatives
|
|
Total
|
||||||||||
Balance at December 31, 2014
|
|
$
|
(4
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(4
|
)
|
Total gains included in earnings
|
|
39
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
42
|
|
|||||
Settlements (1)
|
|
1
|
|
|
28
|
|
|
9
|
|
|
(2
|
)
|
|
36
|
|
|||||
Acquired derivatives
|
|
(54
|
)
|
|
(63
|
)
|
|
(9
|
)
|
|
4
|
|
|
(122
|
)
|
|||||
Balance at December 31, 2015
|
|
$
|
(18
|
)
|
|
$
|
(32
|
)
|
|
$
|
—
|
|
|
$
|
2
|
|
|
$
|
(48
|
)
|
Unrealized gains relating to instruments held as of December 31, 2015
|
|
$
|
39
|
|
|
$
|
3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
42
|
|
(1)
|
For purposes of these tables, we define settlements as the beginning of period fair value of contracts that settled during the period.
|
|
|
|
|
December 31, 2017
|
|
December 31, 2016
|
||||||||||||
(amounts in millions)
|
|
Fair Value Hierarchy
|
|
Carrying
Amount
|
|
Fair
Value
|
|
Carrying
Amount
|
|
Fair
Value
|
||||||||
Dynegy Inc.:
|
|
|
|
|
|
|
|
|
|
|
||||||||
Term Loan, due 2024 (1)
|
|
Level 2
|
|
$
|
(1,944
|
)
|
|
$
|
(2,021
|
)
|
|
$
|
(2,213
|
)
|
|
$
|
(2,250
|
)
|
Revolving Facility (1)
|
|
Level 2
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
6.75% Senior Notes, due 2019 (1)
|
|
Level 2
|
|
$
|
(845
|
)
|
|
$
|
(873
|
)
|
|
$
|
(2,083
|
)
|
|
$
|
(2,137
|
)
|
7.375% Senior Notes, due 2022 (1)
|
|
Level 2
|
|
$
|
(1,734
|
)
|
|
$
|
(1,844
|
)
|
|
$
|
(1,731
|
)
|
|
$
|
(1,665
|
)
|
5.875% Senior Notes, due 2023 (1)
|
|
Level 2
|
|
$
|
(493
|
)
|
|
$
|
(508
|
)
|
|
$
|
(492
|
)
|
|
$
|
(431
|
)
|
7.625% Senior Notes, due 2024 (1)
|
|
Level 2
|
|
$
|
(1,237
|
)
|
|
$
|
(1,344
|
)
|
|
$
|
(1,237
|
)
|
|
$
|
(1,156
|
)
|
8.034% Senior Notes, due 2024 (1)
|
|
Level 2
|
|
$
|
(188
|
)
|
|
$
|
(198
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
8.00% Senior Notes, due 2025 (1)
|
|
Level 2
|
|
$
|
(739
|
)
|
|
$
|
(812
|
)
|
|
$
|
(738
|
)
|
|
$
|
(703
|
)
|
8.125% Senior Notes, due 2026 (1)
|
|
Level 2
|
|
$
|
(842
|
)
|
|
$
|
(933
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
7.00% Amortizing Notes, due 2019 (TEUs) (1)
|
|
Level 2
|
|
$
|
(51
|
)
|
|
$
|
(54
|
)
|
|
$
|
(78
|
)
|
|
$
|
(90
|
)
|
Forward capacity agreement (1)
|
|
Level 3
|
|
$
|
(215
|
)
|
|
$
|
(215
|
)
|
|
$
|
(205
|
)
|
|
$
|
(205
|
)
|
Inventory financing agreements
|
|
Level 3
|
|
$
|
(48
|
)
|
|
$
|
(48
|
)
|
|
$
|
(129
|
)
|
|
$
|
(127
|
)
|
Equipment financing agreements (1)
|
|
Level 3
|
|
$
|
(97
|
)
|
|
$
|
(97
|
)
|
|
$
|
(73
|
)
|
|
$
|
(73
|
)
|
Genco:
|
|
|
|
|
|
|
|
|
|
|
||||||||
Liabilities subject to compromise (2)
|
|
Level 3
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(825
|
)
|
|
$
|
(366
|
)
|
(1)
|
Carrying amounts include unamortized discounts and debt issuance costs. Please read
Note 13—Debt
for further discussion.
|
(2)
|
Carrying amounts represent the Genco senior notes that were classified as liabilities subject to compromise as of December 31, 2016. The fair value of the senior notes was equal to the Genco Plan consideration and is a Level 3 valuation due to a lack of observable inputs that make up the consideration. Please read
Note 20—Genco Chapter 11 Bankruptcy
for further details.
|
|
|
Year Ended December 31,
|
||||||||||
(amounts in millions)
|
|
2017
|
|
2016
|
|
2015
|
||||||
Interest paid (net of amount capitalized of $2, $10, and $12, respectively)
|
|
$
|
555
|
|
|
$
|
548
|
|
|
$
|
491
|
|
Taxes paid (net of refunds)
|
|
$
|
(5
|
)
|
|
$
|
(1
|
)
|
|
$
|
2
|
|
Other non-cash investing and financing activity:
|
|
|
|
|
|
|
||||||
Change in capital expenditures included in accounts payable
|
|
$
|
7
|
|
|
$
|
(13
|
)
|
|
$
|
(8
|
)
|
Change in capital expenditures pursuant to equipment financing agreements
|
|
$
|
24
|
|
|
$
|
11
|
|
|
$
|
63
|
|
Issuance of 2017 Warrants
|
|
$
|
17
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Issuance of senior notes related to the Genco restructuring
|
|
$
|
188
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Sale of interest in Conesville facility
|
|
$
|
(58
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
Acquisition of interest in Zimmer facility
|
|
$
|
27
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Non-cash consideration transferred for acquisitions
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
105
|
|
(amounts in millions)
|
|
December 31, 2017
|
|
December 31, 2016
|
||||
Materials and supplies
|
|
$
|
242
|
|
|
$
|
182
|
|
Coal
|
|
166
|
|
|
238
|
|
||
Fuel oil
|
|
15
|
|
|
17
|
|
||
Natural gas
|
|
9
|
|
|
—
|
|
||
Emissions allowances (1)
|
|
13
|
|
|
8
|
|
||
Total
|
|
$
|
445
|
|
|
$
|
445
|
|
(1)
|
At
December 31, 2017
and
December 31, 2016
, a portion of this inventory was held as collateral by one of our counterparties as part of an inventory financing agreement. Please read
Note 13—Debt
—Emissions Repurchase Agreements for further discussion.
|
(amounts in millions)
|
|
December 31, 2017
|
|
December 31, 2016
|
||||
Power generation
|
|
$
|
9,998
|
|
|
$
|
7,537
|
|
Buildings and improvements
|
|
955
|
|
|
944
|
|
||
Office and other equipment
|
|
115
|
|
|
98
|
|
||
Property, plant and equipment
|
|
11,068
|
|
|
8,579
|
|
||
Accumulated depreciation
|
|
(2,184
|
)
|
|
(1,458
|
)
|
||
Property, plant and equipment, net
|
|
$
|
8,884
|
|
|
$
|
7,121
|
|
|
|
Year Ended December 31,
|
||||||||||
(amounts in millions)
|
|
2017
|
|
2016
|
|
2015
|
||||||
Total interest costs incurred
|
|
$
|
576
|
|
|
$
|
556
|
|
|
$
|
487
|
|
Capitalized interest
|
|
$
|
2
|
|
|
$
|
10
|
|
|
$
|
12
|
|
Facility
|
|
Fair Value
|
|
2017
|
|
2016
|
|
2015
|
||||||||
Baldwin (1)
|
|
$
|
97
|
|
|
$
|
—
|
|
|
$
|
645
|
|
|
$
|
—
|
|
Stuart (2)
|
|
$
|
—
|
|
|
—
|
|
|
56
|
|
|
—
|
|
|||
Newton FGD (3)
|
|
$
|
—
|
|
|
—
|
|
|
148
|
|
|
—
|
|
|||
Killen (4)
|
|
$
|
—
|
|
|
20
|
|
|
—
|
|
|
—
|
|
|||
Hennepin (1)
|
|
$
|
16
|
|
|
10
|
|
|
—
|
|
|
—
|
|
|||
Havana (1)
|
|
$
|
37
|
|
|
89
|
|
|
—
|
|
|
—
|
|
|||
Wood River (5)
|
|
$
|
—
|
|
|
—
|
|
|
—
|
|
|
74
|
|
|||
Brayton Point (6)
|
|
$
|
86
|
|
|
—
|
|
|
—
|
|
|
25
|
|
|||
Total PP&E Impairments
|
|
|
|
$
|
119
|
|
|
$
|
849
|
|
|
$
|
99
|
|
||
Inventory
|
|
$
|
—
|
|
|
14
|
|
|
—
|
|
|
—
|
|
|||
Equity investment
|
|
$
|
173
|
|
|
—
|
|
|
9
|
|
|
—
|
|
|||
Assets held-for-sale, including $9 of allocated goodwill
|
|
$
|
176
|
|
|
15
|
|
|
—
|
|
|
—
|
|
|||
Total Impairments
|
|
|
|
$
|
148
|
|
|
$
|
858
|
|
|
$
|
99
|
|
(1)
|
Units failed to recover their basic operating costs in the MISO capacity auctions. The impairment was measured using a DCF model. As part of our impairment analysis, we changed the remaining useful lives of certain of our facilities.
|
(2)
|
We determined that the facility would experience recurring negative cash flows due to on-going required maintenance and environmental capital expenditures, combined with consistently poor reliability. The impairment was measured using a DCF model.
|
(3)
|
We terminated the flue gas desulfurization (“FGD”) systems construction project at our Newton generation facility. The impairment charge was equal to the capitalized cost of the project.
|
(4)
|
In first quarter 2017, Dayton Power and Light Co., the partner and operator of Killen, announced the shutdown of the Killen generation facility by June 2018. As a result, the DCF model for the facility indicated negative cash flows, resulting in an impairment charge equal to its book value.
|
(5)
|
Primarily attributable to its uneconomic operation stemming from a poorly designed wholesale capacity market and increased environmental costs. The impairment was measured using a DCF model.
|
(6)
|
Temperate weather had a significant impact on the facility’s remaining cash flows, as the facility retired in May 2017. The impairment was measured using a DCF model.
|
|
|
December 31, 2017
|
|||||||||||||||||
(dollars in millions)
|
|
Ownership Interest
|
|
Property, Plant and Equipment
|
|
Accumulated Depreciation
|
|
Construction Work in Progress
|
|
Total
|
|||||||||
Stuart (1)(2)
|
|
39.0
|
%
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1
|
|
Killen (1)(2)
|
|
33.0
|
%
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
December 31, 2016
|
|||||||||||||||||
(dollars in millions)
|
|
Ownership Interest
|
|
Property, Plant and Equipment
|
|
Accumulated Depreciation
|
|
Construction Work in Progress
|
|
Total
|
|||||||||
Miami Fort
|
|
64.0
|
%
|
|
$
|
207
|
|
|
$
|
(39
|
)
|
|
$
|
4
|
|
|
$
|
172
|
|
Stuart (1)
|
|
39.0
|
%
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
4
|
|
|
$
|
4
|
|
Conesville (1)
|
|
40.0
|
%
|
|
$
|
61
|
|
|
$
|
(3
|
)
|
|
$
|
6
|
|
|
$
|
64
|
|
Zimmer
|
|
46.5
|
%
|
|
$
|
115
|
|
|
$
|
(25
|
)
|
|
$
|
6
|
|
|
$
|
96
|
|
Killen (1)
|
|
33.0
|
%
|
|
$
|
19
|
|
|
$
|
(2
|
)
|
|
$
|
3
|
|
|
$
|
20
|
|
(1)
|
Facilities not operated by Dynegy.
|
(2)
|
Stuart Unit 1 was retired early on September 30, 2017, with remaining Stuart and Killen units scheduled to be retired by mid-2018.
|
|
|
December 31, 2017
|
|
December 31, 2016
|
||||||||||||||||||||
(amounts in millions)
|
|
Gross Carrying Amount
|
|
Accumulated Amortization
|
|
Net Carrying Amount
|
|
Gross Carrying Amount
|
|
Accumulated Amortization
|
|
Net Carrying Amount
|
||||||||||||
Intangible Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Electricity contracts
|
|
$
|
178
|
|
|
$
|
(131
|
)
|
|
$
|
47
|
|
|
$
|
260
|
|
|
$
|
(206
|
)
|
|
$
|
54
|
|
Gas transport contracts
|
|
30
|
|
|
(13
|
)
|
|
17
|
|
|
13
|
|
|
(6
|
)
|
|
7
|
|
||||||
Total intangible assets
|
|
$
|
208
|
|
|
$
|
(144
|
)
|
|
$
|
64
|
|
|
$
|
273
|
|
|
$
|
(212
|
)
|
|
$
|
61
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Intangible Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Electricity contracts
|
|
$
|
(11
|
)
|
|
$
|
7
|
|
|
$
|
(4
|
)
|
|
$
|
(28
|
)
|
|
$
|
26
|
|
|
$
|
(2
|
)
|
Coal contracts
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(49
|
)
|
|
42
|
|
|
(7
|
)
|
||||||
Coal transport contracts
|
|
(48
|
)
|
|
44
|
|
|
(4
|
)
|
|
(86
|
)
|
|
73
|
|
|
(13
|
)
|
||||||
Gas transport contracts
|
|
(58
|
)
|
|
19
|
|
|
(39
|
)
|
|
(41
|
)
|
|
8
|
|
|
(33
|
)
|
||||||
Gas storage contracts
|
|
(2
|
)
|
|
1
|
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total intangible liabilities
|
|
$
|
(119
|
)
|
|
$
|
71
|
|
|
$
|
(48
|
)
|
|
$
|
(204
|
)
|
|
$
|
149
|
|
|
$
|
(55
|
)
|
Intangible assets and liabilities, net
|
|
$
|
89
|
|
|
$
|
(73
|
)
|
|
$
|
16
|
|
|
$
|
69
|
|
|
$
|
(63
|
)
|
|
$
|
6
|
|
|
|
Year Ended December 31,
|
||||||||||
(amounts in millions)
|
|
2017
|
|
2016
|
|
2015
|
||||||
Electricity contracts, net (1)
|
|
$
|
32
|
|
|
$
|
70
|
|
|
$
|
75
|
|
Coal contracts, net (2)
|
|
(5
|
)
|
|
(41
|
)
|
|
(60
|
)
|
|||
Coal transport contracts, net (2)
|
|
(9
|
)
|
|
(27
|
)
|
|
(32
|
)
|
|||
Gas transport contracts, net (2)
|
|
(5
|
)
|
|
19
|
|
|
6
|
|
|||
Gas storage contracts, net (2)
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|||
Total
|
|
$
|
12
|
|
|
$
|
21
|
|
|
$
|
(11
|
)
|
(1)
|
The amortization of these contracts is recognized in Revenues or Cost of sales in our consolidated statements of operations.
|
(2)
|
The amortization of these contracts is recognized in Cost of sales in our consolidated statements of operations.
|
(amounts in millions)
|
|
Gross Carrying Amount
|
|
Weighted-Average Amortization Period (months)
|
||
Intangible Assets:
|
|
|
|
|
||
Electricity contracts
|
|
$
|
34
|
|
|
39
|
Gas transport contracts
|
|
16
|
|
|
47
|
|
Total intangible assets
|
|
$
|
50
|
|
|
41
|
|
|
|
|
|
||
Intangible Liabilities:
|
|
|
|
|
||
Electricity contracts
|
|
$
|
(11
|
)
|
|
32
|
Gas contracts
|
|
—
|
|
|
1
|
|
Gas transport contracts
|
|
(17
|
)
|
|
35
|
|
Gas storage contracts
|
|
(2
|
)
|
|
13
|
|
Total intangible liabilities
|
|
$
|
(30
|
)
|
|
33
|
Total intangible assets and liabilities, net
|
|
$
|
20
|
|
|
|
(in millions, except price per TEU)
|
|
SPC
|
|
Amortizing Note
|
|
Total
|
||||||
Price per TEU
|
|
$
|
81
|
|
|
$
|
19
|
|
|
$
|
100
|
|
|
|
|
|
|
|
|
||||||
Gross proceeds
|
|
$
|
373
|
|
|
$
|
87
|
|
|
$
|
460
|
|
Less: Issuance costs
|
|
(14
|
)
|
|
(3
|
)
|
|
(17
|
)
|
|||
Net proceeds
|
|
$
|
359
|
|
|
$
|
84
|
|
|
$
|
443
|
|
(amounts in millions)
|
|
December 31, 2017
|
|
December 31, 2016
|
||||
Secured Obligations:
|
|
|
|
|
||||
Term Loan, due 2024
|
|
$
|
2,018
|
|
|
$
|
2,224
|
|
Revolving Facility
|
|
—
|
|
|
—
|
|
||
Forward Capacity Agreement
|
|
241
|
|
|
219
|
|
||
Inventory Financing Agreements
|
|
48
|
|
|
129
|
|
||
Subtotal secured obligations
|
|
2,307
|
|
|
2,572
|
|
||
Unsecured Obligations:
|
|
|
|
|
||||
7.00% Amortizing Notes, due 2019 (TEUs)
|
|
53
|
|
|
80
|
|
||
6.75% Senior Notes, due 2019
|
|
850
|
|
|
2,100
|
|
||
7.375% Senior Notes, due 2022
|
|
1,750
|
|
|
1,750
|
|
||
5.875% Senior Notes, due 2023
|
|
500
|
|
|
500
|
|
||
7.625% Senior Notes, due 2024
|
|
1,250
|
|
|
1,250
|
|
||
8.034% Senior Notes, due 2024
|
|
188
|
|
|
—
|
|
||
8.00% Senior Notes, due 2025
|
|
750
|
|
|
750
|
|
||
8.125% Senior Notes, due 2026
|
|
850
|
|
|
—
|
|
||
Equipment Financing Agreements
|
|
132
|
|
|
97
|
|
||
Subtotal unsecured obligations
|
|
6,323
|
|
|
6,527
|
|
||
Total debt obligations
|
|
8,630
|
|
|
9,099
|
|
||
Unamortized debt discounts and issuance costs
|
|
(197
|
)
|
|
(120
|
)
|
||
|
|
8,433
|
|
|
8,979
|
|
||
Less: Current maturities, including unamortized debt discounts and issuance costs, net
|
|
105
|
|
|
201
|
|
||
Total long-term debt
|
|
$
|
8,328
|
|
|
$
|
8,778
|
|
•
|
During 2017, we amended the Credit Agreement to increase the revolver capacity by
$120 million
and to extend the maturity date on
$450 million
in revolver capacity to 2021, which was effective upon the ENGIE Acquisition Closing Date.
|
•
|
On the ENGIE Acquisition Closing Date, we amended the Credit Agreement to (i) reduce the interest rate applicable to the Term Loan by
75
basis points and (ii) exchange our previous Term Loan for the current Term Loan.
As a result of this exchange, we recorded a loss on early extinguishment of debt of approximatel
y
$7 million
in our consolidated statements of operations in the first quarter of 2017, of which approximately
$5 million
was r
elated to the write-off of unamortized deferred financing costs and approximately
$2 million
was related to the write-off of unamortized debt discount.
|
•
|
On August 22, 2017, we repaid
$200 million
of our Term Loan. As a result of this transaction, we recorded a loss on early extinguishment of debt of approximately
$8 million
in our consolidated statements of operations for the
year ended December 31, 2017
, of which
$6 million
was related to the write-off of unamortized deferred financing costs and
$2 million
was related to the write-off of unamortized debt discount.
|
•
|
On December 20, 2017, we amended the Credit Agreement to reduce interest rate margins applicable to the Term Loan from
2.25 percent
to
1.75 percent
with respect to base rate borrowings and from
3.25 percent
to
2.75 percent
with respect to LIBOR borrowings through an exchange. Additional reductions from
2.25 percent
to
1.50 percent
with respect to base rate borrowings and from
2.75 percent
to
2.50 percent
with respect to LIBOR borrowings are available to the Company based on certain corporate ratings or corporate family ratings from Moody’s and S&P. As a result of this exchange, we recorded a loss on early extinguishment of debt of approximately
$6 million
in our consolidated statements of operations in the fourth quarter of 2017, of which approximately
$4 million
was related to the write-off of unamortized deferred financing costs, approximately
$1 million
was related to the write-off of unamortized debt discount, and approximately
$1 million
related to fees.
|
•
|
reductions in the corporate federal income tax rate from
35 percent
to
21 percent
,
|
•
|
repeal of the corporate Alternative Minimum Tax (“AMT”) providing for refunds of excess AMT credits,
|
•
|
limiting the utilization of Net Operating Losses (“NOLs”) arising after
December 31, 2017
to
80 percent
of taxable income with an indefinite carryforward (existing NOLs can continue to be utilized at
100 percent
of taxable income with a 20-year carryforward), and
|
•
|
limiting the deduction of net business interest expense to
30 percent
of adjusted taxable income as defined in the TCJA.
|
|
|
Year Ended December 31,
|
||||||||||
(amounts in millions)
|
|
2017
|
|
2016
|
|
2015
|
||||||
Current tax benefit (expense)
|
|
$
|
233
|
|
|
$
|
15
|
|
|
$
|
(3
|
)
|
Deferred tax benefit
|
|
377
|
|
|
30
|
|
|
477
|
|
|||
Income tax benefit
|
|
$
|
610
|
|
|
$
|
45
|
|
|
$
|
474
|
|
|
|
Year Ended December 31,
|
||||||||||
(amounts in millions)
|
|
2017
|
|
2016
|
|
2015
|
||||||
Expected tax benefit at U.S. statutory rate (35%)
|
|
$
|
189
|
|
|
$
|
451
|
|
|
$
|
149
|
|
State taxes
|
|
35
|
|
|
16
|
|
|
68
|
|
|||
Permanent differences (1)
|
|
(21
|
)
|
|
(4
|
)
|
|
16
|
|
|||
Non-deductible goodwill
|
|
(10
|
)
|
|
—
|
|
|
—
|
|
|||
Valuation allowance (2)(3)
|
|
879
|
|
|
(404
|
)
|
|
271
|
|
|||
NOL adjustments from use limitations
|
|
(13
|
)
|
|
(17
|
)
|
|
—
|
|
|||
Adjustment to AMT credits
|
|
(17
|
)
|
|
—
|
|
|
(26
|
)
|
|||
Change in federal tax rate as included in TCJA
|
|
(429
|
)
|
|
—
|
|
|
—
|
|
|||
Other
|
|
(3
|
)
|
|
3
|
|
|
(4
|
)
|
|||
Income tax benefit
|
|
$
|
610
|
|
|
$
|
45
|
|
|
$
|
474
|
|
(1)
|
Permanent items for
years ended December 31, 2017, 2016 and 2015
included a benefit of less than
$1 million
, a benefit of
$2 million
, and a benefit of
$18 million
, respectively, for the change in the fair value of warrants during the year that were not deductible for income taxes. Income tax benefit for the years ended
December 31, 2017 and 2016
includes
$8 million
and
$5 million
, respectively, of income tax expense for non-deductible fees related to the Genco Plan. Please read
Note 20—Genco Chapter 11 Bankruptcy
for further discussion. Income tax benefit for the year ended
December 31, 2017
, includes
$22 million
for non-deductible legal fees related to the ENGIE Acquisition.
|
(2)
|
The EquiPower Acquisition on April 1, 2015 caused a change in the attributes and impacted our estimate of the realizability of our deferred tax assets. As a result, we recorded a
$453 million
reduction to our valuation allowance in 2015 and
$3 million
in 2016.
|
(3)
|
The ENGIE Acquisition on February 7, 2017 caused a change in the attributes and impacted our estimate of the realizability of our deferred tax assets. As a result, we recorded a
$354 million
reduction to our valuation allowance in 2017. We also recorded a benefit for the repeal of the corporate AMT in the amount of
$223 million
as included in the TCJA.
|
|
|
Year Ended December 31,
|
||||||
(amounts in millions)
|
|
2017
|
|
2016
|
||||
Non-current deferred tax assets:
|
|
|
|
|
||||
NOL carryforwards
|
|
$
|
1,195
|
|
|
$
|
1,629
|
|
AMT, state, and other tax credit carryforwards
|
|
25
|
|
|
241
|
|
||
Reserves (legal, environmental and other)
|
|
4
|
|
|
7
|
|
||
Pension and other post-employment benefits
|
|
11
|
|
|
18
|
|
||
Asset retirement obligations
|
|
68
|
|
|
85
|
|
||
Deferred financing costs and intangible/other contracts
|
|
22
|
|
|
48
|
|
||
Derivative contracts
|
|
69
|
|
|
57
|
|
||
Other
|
|
29
|
|
|
46
|
|
||
Subtotal
|
|
1,423
|
|
|
2,131
|
|
||
Less: valuation allowance
|
|
(852
|
)
|
|
(1,704
|
)
|
||
Total non-current deferred tax assets
|
|
$
|
571
|
|
|
$
|
427
|
|
Non-current deferred tax liabilities:
|
|
|
|
|
||||
Depreciation and other property differences
|
|
$
|
(560
|
)
|
|
$
|
(371
|
)
|
Derivative contracts
|
|
(7
|
)
|
|
(44
|
)
|
||
Other
|
|
(11
|
)
|
|
(17
|
)
|
||
Total non-current deferred tax liabilities
|
|
$
|
(578
|
)
|
|
$
|
(432
|
)
|
Net non-current deferred tax liabilities
|
|
$
|
(7
|
)
|
|
$
|
(5
|
)
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
Beginning of period
|
|
$
|
1,704
|
|
|
$
|
1,276
|
|
|
$
|
1,535
|
|
Changes in valuation allowance—continuing operations:
|
|
|
|
|
|
|
||||||
Charged to costs and expenses
|
|
(854
|
)
|
|
428
|
|
|
(259
|
)
|
|||
Charged to other accounts
|
|
2
|
|
|
—
|
|
|
—
|
|
|||
End of period
|
|
$
|
852
|
|
|
$
|
1,704
|
|
|
$
|
1,276
|
|
|
|
Year Ended December 31,
|
||||||||||
amounts in millions
|
|
2017
|
|
2016
|
|
2015
|
||||||
Unrecognized tax benefits, beginning of period
|
|
$
|
3
|
|
|
$
|
3
|
|
|
$
|
4
|
|
Increase due to ENGIE acquisition
|
|
63
|
|
|
—
|
|
|
—
|
|
|||
Decrease due to rate changes
|
|
(26
|
)
|
|
—
|
|
|
—
|
|
|||
Decrease due to settlements and payments
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|||
Unrecognized tax benefits, end of period
|
|
$
|
40
|
|
|
$
|
3
|
|
|
$
|
3
|
|
|
|
Shares outstanding balance as of December 31,
|
|||||||
(in millions)
|
|
2017
|
|
2016
|
|
2015
|
|||
Shares outstanding at the beginning of the period
|
|
117
|
|
|
117
|
|
|
124
|
|
Shares issued under the PIPE Transaction
|
|
14
|
|
|
—
|
|
|
—
|
|
Shares issued as consideration for the EquiPower Acquisition
|
|
—
|
|
|
—
|
|
|
3
|
|
Shares repurchases (in treasury)
|
|
—
|
|
|
—
|
|
|
(11
|
)
|
Shares issued from conversion of preferred stock
|
|
13
|
|
|
—
|
|
|
—
|
|
Shares issued under long-term compensation plans
|
|
—
|
|
|
—
|
|
|
1
|
|
Shares outstanding at the end of period
|
|
144
|
|
|
117
|
|
|
117
|
|
|
Year Ended December 31, 2017
|
|||||||||||
|
Options
(in thousands)
|
|
Weighted Average
Exercise Price
|
|
Weighted Average Remaining Contractual Life
(in years)
|
|
Aggregate Intrinsic Value
(amounts in millions) |
|||||
Outstanding at beginning of period
|
2,805
|
|
|
$
|
18.69
|
|
|
|
|
|
||
Granted
|
1,454
|
|
|
$
|
8.02
|
|
|
|
|
|
||
Forfeited
|
(10
|
)
|
|
$
|
27.24
|
|
|
|
|
|
||
Expired
|
(42
|
)
|
|
$
|
21.79
|
|
|
|
|
|
||
Outstanding at end of period
|
4,207
|
|
|
$
|
14.95
|
|
|
7.65
|
|
$
|
6.4
|
|
Vested and unvested expected to vest
|
4,207
|
|
|
$
|
14.95
|
|
|
7.65
|
|
$
|
6.4
|
|
Exercisable at end of period
|
2,023
|
|
|
$
|
20.02
|
|
|
6.40
|
|
$
|
0.5
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
Dividend Yield
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Expected volatility (1)
|
|
48.50
|
%
|
|
41.19
|
%
|
|
27.70
|
%
|
|||
Risk-free interest rate (2)
|
|
2.07
|
%
|
|
1.42
|
%
|
|
1.64
|
%
|
|||
Expected option life (3)
|
|
5.5 years
|
|
|
5.5 years
|
|
|
5.5 years
|
|
|||
Weighted average grant-date fair value
|
|
$
|
3.71
|
|
|
$
|
4.37
|
|
|
$
|
7.93
|
|
(1)
|
For the
years ended December 31, 2017, 2016 and 2015
, the expected volatility was calculated based on the historical volatilities of our stock since October 3, 2012.
|
(2)
|
The risk-free interest rate was calculated based upon observed interest rates appropriate for the term of our employee stock options.
|
(3)
|
Currently, we calculate the expected option life using the simplified methodology suggested by authoritative guidance issued by the SEC.
|
|
|
Year Ended December 31, 2017
|
|||||
|
|
RSUs
(in thousands)
|
|
Weighted Average Grant Date Fair Value
|
|||
Outstanding at beginning of period
|
|
2,717
|
|
|
$
|
16.11
|
|
Granted
|
|
3,177
|
|
|
$
|
7.99
|
|
Vested and released
|
|
(1,241
|
)
|
|
$
|
19.04
|
|
Forfeited
|
|
(107
|
)
|
|
$
|
11.08
|
|
Outstanding at end of period
|
|
4,546
|
|
|
$
|
9.75
|
|
|
|
Year Ended December 31, 2017
|
|||||
|
|
PSUs
(in thousands)
|
|
Weighted Average Grant Date Fair Value
|
|||
Outstanding at beginning of period
|
|
1,221
|
|
|
$
|
16.48
|
|
Granted
|
|
583
|
|
|
$
|
8.02
|
|
Vested and released
|
|
(3
|
)
|
|
$
|
26.66
|
|
Forfeited
|
|
(186
|
)
|
|
$
|
23.10
|
|
Outstanding at end of period
|
|
1,615
|
|
|
$
|
12.65
|
|
•
|
Three
-year performance period;
|
•
|
Payout opportunity of
0
-
200
percent of target (
100
percent), intended to be settled in shares;
|
•
|
Cumulative TSR percentile ranking calculated at end of performance period and applied to the payout scale to determine the number of earned/vested PSUs; and
|
•
|
If absolute TSR is negative, PSU award payouts will be capped at
100 percent
of the target number of PSUs granted, regardless of relative TSR positioning.
|
|
|
Year Ended December 31,
|
|||||||
(in millions, except per share amounts)
|
|
2017
|
|
2016
|
|
2015
|
|||
Shares outstanding at the beginning of the period
|
|
140
|
|
|
117
|
|
|
124
|
|
Weighted-average shares during the period of:
|
|
|
|
|
|
|
|||
Shares issuances
|
|
13
|
|
|
—
|
|
|
4
|
|
Shares converted from preferred stock
|
|
2
|
|
|
—
|
|
|
—
|
|
Shares repurchases
|
|
—
|
|
|
—
|
|
|
(3
|
)
|
Prepaid stock purchase contract (TEUs) (1)
|
|
—
|
|
|
12
|
|
|
—
|
|
Basic weighted-average shares
|
|
155
|
|
|
129
|
|
|
125
|
|
Dilution from potentially dilutive shares (2)
|
|
7
|
|
|
—
|
|
|
1
|
|
Diluted weighted-average shares (3)
|
|
162
|
|
|
129
|
|
|
126
|
|
(1)
|
The minimum settlement amount, or
23.1 million
shares, are considered to be outstanding since June 21, 2016, and are included in the computation of basic earnings (loss) per share. Please read
Note 12—Tangible Equity Units
for further discussion.
|
(2)
|
Shares included in the computation of diluted earnings per share for the year ended December 31, 2017 consist of:
|
•
|
5.4 million
additional shares upon settlement of the TEUs - which reflects the difference between the minimum settlement amount included in basic weighted-average shares outstanding and the maximum settlement amount (
28.5 million
shares); and
|
•
|
1.9 million
additional shares attributable to restricted stock units and performance stock units.
|
(3)
|
Entities with a net loss from continuing operations are prohibited from including potential common shares in the computation of diluted per share amounts. Accordingly, we have utilized the basic shares outstanding amount to calculate both basic and diluted loss per share for the year ended December 31, 2016.
|
|
|
Year Ended December 31,
|
|||||||
(in millions of shares)
|
|
2017
|
|
2016
|
|
2015
|
|||
Stock options
|
|
2.8
|
|
|
2.8
|
|
|
0.5
|
|
Restricted stock units
|
|
—
|
|
|
1.3
|
|
|
—
|
|
Performance stock units
|
|
—
|
|
|
1.2
|
|
|
—
|
|
Warrants (1)
|
|
9.0
|
|
|
15.6
|
|
|
15.6
|
|
Series A 5.375% mandatory convertible preferred stock (2)
|
|
—
|
|
|
12.9
|
|
|
12.9
|
|
TEUs
|
|
—
|
|
|
5.4
|
|
|
—
|
|
Total
|
|
11.8
|
|
|
39.2
|
|
|
29.0
|
|
(1)
|
During 2017, we issued
9.0 million
warrants to
eligible holders of Genco senior notes as a result of the Genco Chapter 11 Bankruptcy.
Warrants to purchase
15.6 million
shares of our Common Stock expired on October 2, 2017.
|
(2)
|
On November 1, 2017, our outstanding Preferred Stock was converted to approximately
12.9 million
shares of Common Stock.
|
|
|
Year Ended December 31,
|
||||||||||
(amounts in millions)
|
|
2017
|
|
2016
|
|
2015
|
||||||
Beginning of period
|
|
$
|
21
|
|
|
$
|
19
|
|
|
$
|
20
|
|
Other comprehensive income before reclassifications:
|
|
|
|
|
|
|
||||||
Actuarial gain and plan amendments (net of tax of $5, $3, and zero, respectively)
|
|
19
|
|
|
2
|
|
|
3
|
|
|||
Amounts reclassified from accumulated other comprehensive income:
|
|
|
|
|
|
|
||||||
Settlement cost (net of tax of zero) (1)
|
|
—
|
|
|
5
|
|
|
—
|
|
|||
Amortization of unrecognized prior service credit and actuarial gain (net of tax of zero, zero, and zero, respectively) (2)
|
|
(8
|
)
|
|
(5
|
)
|
|
(4
|
)
|
|||
Net current period other comprehensive income (loss), net of tax
|
|
11
|
|
|
2
|
|
|
(1
|
)
|
|||
End of period
|
|
$
|
32
|
|
|
$
|
21
|
|
|
$
|
19
|
|
(1)
|
Amount is related to the EEI other post-employment benefit plan settlement cost and was recorded in Operating and maintenance expense in our consolidated statements of operations. Please read
Note 17—Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans
for further discussion.
|
(2)
|
Amounts are associated with our defined benefit pension and other post-employment benefit plans and are included in the computation of net periodic pension cost. Please read
Note 17—Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans
for further discussion.
|
•
|
Dynegy 401(k) Plan.
This plan and the related trust fund are established and maintained for the exclusive benefit of participating employees in the U.S. Generally, all employees of designated Dynegy subsidiaries are eligible to participate in this plan. Except for certain represented employees, employee pre-tax and Roth contributions to the plan are matched by the Company at
100 percent
, up to a maximum of
five percent
of base pay (subject to IRS limitations) and vesting in company contributions is based on years of service with
50 percent
vesting per full year of service. This plan also allows for a discretionary contribution to eligible employee accounts for each plan year, subject to the sole discretion of the Compensation and Human Resources Committee of the Board of Directors.
No
discretionary contributions were made for any of the years in the three-year period ended
December 31, 2017
.
|
|
|
Pension Benefits
|
|
Other Benefits
|
||||||||||||
|
|
Year Ended December 31,
|
||||||||||||||
(amounts in millions)
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
||||||||
Benefit obligation, beginning of the year
|
|
$
|
508
|
|
|
$
|
483
|
|
|
$
|
42
|
|
|
$
|
74
|
|
Service cost
|
|
17
|
|
|
16
|
|
|
—
|
|
|
1
|
|
||||
Interest cost
|
|
20
|
|
|
20
|
|
|
2
|
|
|
3
|
|
||||
Actuarial loss
|
|
28
|
|
|
23
|
|
|
1
|
|
|
4
|
|
||||
Benefits paid
|
|
(36
|
)
|
|
(32
|
)
|
|
(4
|
)
|
|
(6
|
)
|
||||
Plan change
|
|
(10
|
)
|
|
(2
|
)
|
|
(1
|
)
|
|
(17
|
)
|
||||
Settlements
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(17
|
)
|
||||
Acquisitions
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Divestitures
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Benefit obligation, end of the year
|
|
$
|
527
|
|
|
$
|
508
|
|
|
$
|
40
|
|
|
$
|
42
|
|
Fair value of plan assets, beginning of the year
|
|
$
|
415
|
|
|
$
|
410
|
|
|
$
|
49
|
|
|
$
|
67
|
|
Actual return on plan assets
|
|
65
|
|
|
37
|
|
|
4
|
|
|
2
|
|
||||
Employer contributions
|
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Benefits paid
|
|
(36
|
)
|
|
(32
|
)
|
|
(2
|
)
|
|
(3
|
)
|
||||
Settlements
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(17
|
)
|
||||
Acquisitions
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Divestitures
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Transfers Out (1)
|
|
—
|
|
|
—
|
|
|
(19
|
)
|
|
—
|
|
||||
Fair value of plan assets, end of the year
|
|
$
|
448
|
|
|
$
|
415
|
|
|
$
|
32
|
|
|
$
|
49
|
|
Funded status
|
|
$
|
(79
|
)
|
|
$
|
(93
|
)
|
|
$
|
(8
|
)
|
|
$
|
7
|
|
(1)
|
As permitted by EEI’s other post-employment plan for EEI union employees, part of the overfunded portion of the plan assets was segregated in 2017 to offset the employer cost of the active EEI employees’ health and welfare benefits.
|
|
|
Pension Benefits
|
|
Other Benefits
|
||||||||||||
|
|
Year Ended December 31,
|
||||||||||||||
(amounts in millions)
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
||||||||
Non-current assets
|
|
$
|
—
|
|
|
$
|
7
|
|
|
$
|
33
|
|
|
$
|
32
|
|
Current liabilities
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
(2
|
)
|
||||
Non-current liabilities
|
|
(79
|
)
|
|
(100
|
)
|
|
(20
|
)
|
|
(23
|
)
|
||||
Net amount recognized
|
|
$
|
(79
|
)
|
|
$
|
(93
|
)
|
|
$
|
11
|
|
|
$
|
7
|
|
|
|
Pension Benefits
|
|
Other Benefits
|
||||||||||||
|
|
Year Ended December 31,
|
||||||||||||||
(amounts in millions)
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
||||||||
Prior service credit
|
|
$
|
(19
|
)
|
|
$
|
(12
|
)
|
|
$
|
(43
|
)
|
|
$
|
(47
|
)
|
Actuarial loss (gain)
|
|
(8
|
)
|
|
2
|
|
|
1
|
|
|
1
|
|
||||
Net gain recognized
|
|
$
|
(27
|
)
|
|
$
|
(10
|
)
|
|
$
|
(42
|
)
|
|
$
|
(46
|
)
|
(amounts in millions)
|
|
Pension Benefits
|
|
Other Benefits
|
||||
Prior service credit
|
|
$
|
(3
|
)
|
|
$
|
(5
|
)
|
Actuarial gain
|
|
—
|
|
|
(1
|
)
|
||
|
|
$
|
(3
|
)
|
|
$
|
(6
|
)
|
|
|
Pension Benefits
|
||||||||||
|
|
Year Ended December 31,
|
||||||||||
(amounts in millions)
|
|
2017
|
|
2016
|
|
2015
|
||||||
Service cost benefits earned during period
|
|
$
|
17
|
|
|
$
|
16
|
|
|
$
|
14
|
|
Interest cost on projected benefit obligation
|
|
20
|
|
|
20
|
|
|
18
|
|
|||
Expected return on plan assets
|
|
(25
|
)
|
|
(22
|
)
|
|
(23
|
)
|
|||
Amortization of:
|
|
|
|
|
|
|
||||||
Prior service credit
|
|
(2
|
)
|
|
(1
|
)
|
|
(1
|
)
|
|||
Actuarial gain
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Net periodic benefit cost
|
|
$
|
10
|
|
|
$
|
13
|
|
|
$
|
8
|
|
|
|
Other Benefits
|
||||||||||
|
|
Year Ended December 31,
|
||||||||||
(amounts in millions)
|
|
2017
|
|
2016
|
|
2015
|
||||||
Service cost benefits earned during period
|
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
1
|
|
Interest cost on projected benefit obligation
|
|
2
|
|
|
3
|
|
|
4
|
|
|||
Expected return on plan assets
|
|
(2
|
)
|
|
(4
|
)
|
|
(4
|
)
|
|||
Amortization of:
|
|
|
|
|
|
|
||||||
Prior service credit
|
|
(5
|
)
|
|
(4
|
)
|
|
(3
|
)
|
|||
Actuarial gain
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|||
Net periodic benefit gain
|
|
(6
|
)
|
|
(4
|
)
|
|
(2
|
)
|
|||
Settlement cost (1)
|
|
—
|
|
|
6
|
|
|
—
|
|
|||
Total benefit cost (gain)
|
|
$
|
(6
|
)
|
|
$
|
2
|
|
|
$
|
(2
|
)
|
(1)
|
The settlement cost for the year ended December 31, 2016 was related to EEI’s other post-employment benefit plan for EEI union employees.
|
|
|
Pension Benefits
|
|
Other Benefits
|
||||||||
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
||||
Discount rate (1)
|
|
3.60
|
%
|
|
4.05
|
%
|
|
3.55
|
%
|
|
4.00
|
%
|
Rate of compensation increase (2)
|
|
3.50
|
%
|
|
3.50
|
%
|
|
3.50
|
%
|
|
3.50
|
%
|
(1)
|
We utilized a yield curve approach to determine the discount. Projected benefit payments for the plans were matched against the discount rates in the yield curve.
|
(2)
|
The rate of compensation increase used for other post-employment benefits is specifically related to the EEI post-employment plans.
|
|
|
Pension Benefits
|
|
Other Benefits
|
||||||||||||||
|
|
Year Ended December 31,
|
||||||||||||||||
|
|
2017
|
|
2016
|
|
2015
|
|
2017
|
|
2016
|
|
2015
|
||||||
Discount rate
|
|
3.60
|
%
|
|
4.05
|
%
|
|
4.35
|
%
|
|
3.55
|
%
|
|
4.00
|
%
|
|
4.35
|
%
|
Dynegy - Expected return on plan assets
|
|
6.20
|
%
|
|
5.60
|
%
|
|
5.70
|
%
|
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
EEI - Expected return on plan assets (1)
|
|
6.40
|
%
|
|
5.90
|
%
|
|
6.00
|
%
|
|
5.75
|
%
|
|
5.40
|
%
|
|
5.50
|
%
|
Rate of compensation increase (2)
|
|
3.50
|
%
|
|
3.50
|
%
|
|
3.50
|
%
|
|
3.50
|
%
|
|
3.50
|
%
|
|
3.50
|
%
|
(1)
|
The average expected return on EEI’s other post-employment plan assets was
5.75 percent
,
5.40 percent
, and
5.50 percent
for the years ended
December 31, 2017, 2016 and 2015
, respectively. The expected return on EEI’s other post-employment plan assets was
6.90 percent
,
6.30 percent
, and
6.20 percent
for EEI union employees for the years ended
December 31, 2017, 2016 and 2015
, respectively. The expected return on EEI’s other post-employment plan assets was
4.60 percent
,
4.50 percent
, and
4.80 percent
for EEI salaried employees for the years ended
December 31, 2017, 2016 and 2015
, respectively.
|
(2)
|
The rate of compensation increase used for other post-employment benefits for the years ended
December 31, 2017, 2016 and 2015
is specifically related to the EEI post-employment plans.
|
|
|
Year Ended December 31,
|
|||||||
|
|
2017
|
|
2016
|
|
2015
|
|||
Health care cost trend rate assumed for next year
|
|
7.00
|
%
|
|
7.25
|
%
|
|
7.00
|
%
|
Ultimate trend rate
|
|
4.50
|
%
|
|
4.50
|
%
|
|
4.50
|
%
|
Year that the rate reaches the ultimate trend rate
|
|
2025
|
|
|
2025
|
|
|
2023
|
|
(amounts in millions)
|
|
Increase
|
|
Decrease
|
||||
Aggregate impact on service cost and interest cost
|
|
$
|
—
|
|
|
$
|
—
|
|
Impact on accumulated post-employment benefit obligation
|
|
$
|
3
|
|
|
$
|
(2
|
)
|
|
|
Fair Value as of December 31, 2017
|
||||||||||||||
(amounts in millions)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
Cash and cash equivalents
|
|
$
|
7
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
7
|
|
Equity securities:
|
|
|
|
|
|
|
|
|
||||||||
U.S. companies (1)
|
|
14
|
|
|
136
|
|
|
—
|
|
|
150
|
|
||||
Non-U.S. companies (2)
|
|
1
|
|
|
19
|
|
|
—
|
|
|
20
|
|
||||
International (3)
|
|
9
|
|
|
62
|
|
|
—
|
|
|
71
|
|
||||
Fixed income securities (4)
|
|
63
|
|
|
169
|
|
|
—
|
|
|
232
|
|
||||
Total
|
|
$
|
94
|
|
|
$
|
386
|
|
|
$
|
—
|
|
|
$
|
480
|
|
|
|
Fair Value as of December 31, 2016
|
||||||||||||||
(amounts in millions)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
Cash and cash equivalents
|
|
$
|
4
|
|
|
$
|
2
|
|
|
$
|
—
|
|
|
$
|
6
|
|
Equity securities:
|
|
|
|
|
|
|
|
|
||||||||
U.S. companies (1)
|
|
18
|
|
|
129
|
|
|
—
|
|
|
147
|
|
||||
Non-U.S. companies (2)
|
|
1
|
|
|
15
|
|
|
—
|
|
|
16
|
|
||||
International (3)
|
|
8
|
|
|
58
|
|
|
—
|
|
|
66
|
|
||||
Fixed income securities (4)
|
|
70
|
|
|
161
|
|
|
—
|
|
|
231
|
|
||||
Total
|
|
$
|
101
|
|
|
$
|
365
|
|
|
$
|
—
|
|
|
$
|
466
|
|
(1)
|
This category comprises a domestic common collective trust not actively managed that tracks the Dow Jones total U.S. stock market.
|
(2)
|
This category comprises a common collective trust not actively managed that tracks the MSCI All Country World Ex-U.S. Index.
|
(3)
|
This category comprises actively managed common collective trusts that hold U.S. and foreign equities. These trusts track the MSCI World Index.
|
(4)
|
This category includes a mutual fund and a trust that invest primarily in investment grade corporate bonds.
|
(amounts in millions)
|
|
Pension Benefits
|
|
Other Benefits
|
||||
2016
|
|
$
|
—
|
|
|
$
|
2
|
|
2017
|
|
$
|
4
|
|
|
$
|
2
|
|
2018
|
|
$
|
13
|
|
|
$
|
2
|
|
(amounts in millions)
|
|
Pension Benefits
|
|
Other Benefits
|
||||
2018
|
|
$
|
39
|
|
|
$
|
3
|
|
2019
|
|
$
|
38
|
|
|
$
|
3
|
|
2020
|
|
$
|
38
|
|
|
$
|
3
|
|
2021
|
|
$
|
38
|
|
|
$
|
3
|
|
2022
|
|
$
|
38
|
|
|
$
|
2
|
|
2023 - 2027
|
|
$
|
190
|
|
|
$
|
11
|
|
|
|
Quarter Ended
|
||||||||||||||
(amounts in millions, except per share data)
|
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
||||||||
2017
|
|
|
|
|
|
|
|
|
||||||||
Revenues
|
|
$
|
1,247
|
|
|
$
|
1,164
|
|
|
$
|
1,437
|
|
|
$
|
994
|
|
Operating income (loss) (1)
|
|
$
|
(49
|
)
|
|
$
|
(182
|
)
|
|
$
|
58
|
|
|
$
|
(239
|
)
|
Net income (loss) (2)(3)(4)
|
|
$
|
596
|
|
|
$
|
(296
|
)
|
|
$
|
(133
|
)
|
|
$
|
(95
|
)
|
Net income (loss) attributable to Dynegy Inc. common stockholders (2)(3)(4)
|
|
$
|
592
|
|
|
$
|
(302
|
)
|
|
$
|
(137
|
)
|
|
$
|
(95
|
)
|
Net income (loss) per share attributable to Dynegy Inc. common stockholders—Basic (2)(3)(4)
|
|
$
|
4.00
|
|
|
$
|
(1.96
|
)
|
|
$
|
(0.89
|
)
|
|
$
|
(0.58
|
)
|
Net income (loss) per share attributable to Dynegy Inc. common stockholders—Diluted (2)(3)(4)
|
|
$
|
3.57
|
|
|
$
|
(1.96
|
)
|
|
$
|
(0.89
|
)
|
|
$
|
(0.58
|
)
|
2016
|
|
|
|
|
|
|
|
|
||||||||
Revenues
|
|
$
|
1,123
|
|
|
$
|
904
|
|
|
$
|
1,184
|
|
|
$
|
1,107
|
|
Operating income (loss) (1)
|
|
$
|
145
|
|
|
$
|
(702
|
)
|
|
$
|
(117
|
)
|
|
$
|
34
|
|
Net loss
|
|
$
|
(10
|
)
|
|
$
|
(803
|
)
|
|
$
|
(249
|
)
|
|
$
|
(182
|
)
|
Net loss attributable to Dynegy Inc. common stockholders
|
|
$
|
(15
|
)
|
|
$
|
(807
|
)
|
|
$
|
(254
|
)
|
|
$
|
(186
|
)
|
Net loss per share attributable to Dynegy Inc. common stockholders—Basic
|
|
$
|
(0.13
|
)
|
|
$
|
(6.73
|
)
|
|
$
|
(1.81
|
)
|
|
$
|
(1.33
|
)
|
Net loss per share attributable to Dynegy Inc. common stockholders—Diluted
|
|
$
|
(0.13
|
)
|
|
$
|
(6.73
|
)
|
|
$
|
(1.81
|
)
|
|
$
|
(1.33
|
)
|
(1)
|
The results for the quarters ended March 31, 2017, June 30, 2017, and September 30, 2017, include impairment charges of
$20 million
,
$99 million
, and
$29 million
, respectively. The results for the quarters ended June 30, 2016, September 30, 2016, and December 31, 2016, include impairment charges of
$645 million
,
$212 million
, and
$1 million
, respectively. See
Note 8—Property, Plant and Equipment
for more information.
|
(2)
|
The results for the quarters ended June 30, 2017, September 30, 2017, and December 31, 2017 include losses on sale of assets of
$29 million
,
$78 million
, and
$15 million
, respectively. See
Note 3—Acquisitions and Divestitures
and
Note 9—Joint Ownership of Generating Facilities
for more information.
|
(3)
|
The results for the quarters ended March 31, 2017, June 30, 2017, and September 30, 2017, include income (loss) from bankruptcy reorganization items of
$483 million
,
($1) million
, and
$12 million
, respectively. The results for the quarter ended December 31, 2016 include loss from Bankruptcy reorganization items of
$96 million
. See
Note 20—Genco Chapter 11 Bankruptcy
for more information.
|
(4)
|
The results for the quarters ended March 31, 2017 and December 31, 2017 include a
$317 million
and
$37 million
income tax benefit, respectively, from the partial release of our valuation allowance as a result of the ENGIE Acquisition. The results for the quarter ended December 31, 2017 include a
$223 million
tax benefit related to the expected refund of its existing AMT Credits as provided for in the TCJA. See
Note 14—Income Taxes
for more information.
|
|
Parent
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Current Assets
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash and cash equivalents
|
$
|
233
|
|
|
$
|
124
|
|
|
$
|
8
|
|
|
$
|
—
|
|
|
$
|
365
|
|
Accounts receivable, net
|
126
|
|
|
4,269
|
|
|
14
|
|
|
(3,896
|
)
|
|
513
|
|
|||||
Inventory
|
—
|
|
|
415
|
|
|
30
|
|
|
—
|
|
|
445
|
|
|||||
Other current assets
|
8
|
|
|
288
|
|
|
2
|
|
|
(97
|
)
|
|
201
|
|
|||||
Total Current Assets
|
367
|
|
|
5,096
|
|
|
54
|
|
|
(3,993
|
)
|
|
1,524
|
|
|||||
Property, plant and equipment, net
|
—
|
|
|
8,585
|
|
|
299
|
|
|
—
|
|
|
8,884
|
|
|||||
Investment in affiliates
|
16,132
|
|
|
—
|
|
|
—
|
|
|
(16,132
|
)
|
|
—
|
|
|||||
Investment in unconsolidated affiliates
|
—
|
|
|
123
|
|
|
—
|
|
|
—
|
|
|
123
|
|
|||||
Goodwill
|
—
|
|
|
772
|
|
|
—
|
|
|
—
|
|
|
772
|
|
|||||
Other long-term assets
|
244
|
|
|
185
|
|
|
39
|
|
|
—
|
|
|
468
|
|
|||||
Intercompany note receivable
|
46
|
|
|
—
|
|
|
—
|
|
|
(46
|
)
|
|
—
|
|
|||||
Total Assets
|
$
|
16,789
|
|
|
$
|
14,761
|
|
|
$
|
392
|
|
|
$
|
(20,171
|
)
|
|
$
|
11,771
|
|
Current Liabilities
|
|
|
|
|
|
|
|
|
|
||||||||||
Accounts payable
|
$
|
3,555
|
|
|
$
|
471
|
|
|
$
|
232
|
|
|
$
|
(3,891
|
)
|
|
$
|
367
|
|
Other current liabilities
|
156
|
|
|
520
|
|
|
108
|
|
|
(102
|
)
|
|
682
|
|
|||||
Total Current Liabilities
|
3,711
|
|
|
991
|
|
|
340
|
|
|
(3,993
|
)
|
|
1,049
|
|
|||||
Debt, long-term portion, net
|
8,045
|
|
|
256
|
|
|
27
|
|
|
—
|
|
|
8,328
|
|
|||||
Intercompany note payable
|
3,042
|
|
|
46
|
|
|
—
|
|
|
(3,088
|
)
|
|
—
|
|
|||||
Other long-term liabilities
|
90
|
|
|
367
|
|
|
44
|
|
|
—
|
|
|
501
|
|
|||||
Total Liabilities
|
14,888
|
|
|
1,660
|
|
|
411
|
|
|
(7,081
|
)
|
|
9,878
|
|
|||||
Stockholders’ Equity
|
|
|
|
|
|
|
|
|
|
||||||||||
Dynegy Stockholders’ Equity
|
1,901
|
|
|
16,151
|
|
|
(19
|
)
|
|
(16,132
|
)
|
|
1,901
|
|
|||||
Intercompany note receivable
|
—
|
|
|
(3,042
|
)
|
|
—
|
|
|
3,042
|
|
|
—
|
|
|||||
Total Dynegy Stockholders’ Equity
|
1,901
|
|
|
13,109
|
|
|
(19
|
)
|
|
(13,090
|
)
|
|
1,901
|
|
|||||
Noncontrolling interest
|
—
|
|
|
(8
|
)
|
|
—
|
|
|
—
|
|
|
(8
|
)
|
|||||
Total Equity
|
1,901
|
|
|
13,101
|
|
|
(19
|
)
|
|
(13,090
|
)
|
|
1,893
|
|
|||||
Total Liabilities and Equity
|
$
|
16,789
|
|
|
$
|
14,761
|
|
|
$
|
392
|
|
|
$
|
(20,171
|
)
|
|
$
|
11,771
|
|
|
Parent
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Current Assets
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash and cash equivalents
|
$
|
1,529
|
|
|
$
|
221
|
|
|
$
|
26
|
|
|
$
|
—
|
|
|
$
|
1,776
|
|
Restricted cash
|
21
|
|
|
41
|
|
|
—
|
|
|
—
|
|
|
62
|
|
|||||
Accounts receivable, net
|
141
|
|
|
2,604
|
|
|
39
|
|
|
(2,398
|
)
|
|
386
|
|
|||||
Inventory
|
—
|
|
|
326
|
|
|
119
|
|
|
—
|
|
|
445
|
|
|||||
Other current assets
|
12
|
|
|
408
|
|
|
2
|
|
|
(104
|
)
|
|
318
|
|
|||||
Total Current Assets
|
1,703
|
|
|
3,600
|
|
|
186
|
|
|
(2,502
|
)
|
|
2,987
|
|
|||||
Property, plant and equipment, net
|
—
|
|
|
6,772
|
|
|
349
|
|
|
—
|
|
|
7,121
|
|
|||||
Investment in affiliates
|
12,175
|
|
|
—
|
|
|
—
|
|
|
(12,175
|
)
|
|
—
|
|
|||||
Restricted cash
|
2,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,000
|
|
|||||
Other long-term assets
|
2
|
|
|
109
|
|
|
35
|
|
|
—
|
|
|
146
|
|
|||||
Goodwill
|
—
|
|
|
799
|
|
|
—
|
|
|
—
|
|
|
799
|
|
|||||
Intercompany note receivable
|
—
|
|
|
8
|
|
|
—
|
|
|
(8
|
)
|
|
—
|
|
|||||
Total Assets
|
$
|
15,880
|
|
|
$
|
11,288
|
|
|
$
|
570
|
|
|
$
|
(14,685
|
)
|
|
$
|
13,053
|
|
Current Liabilities
|
|
|
|
|
|
|
|
|
|
||||||||||
Accounts payable
|
$
|
1,990
|
|
|
$
|
443
|
|
|
$
|
297
|
|
|
$
|
(2,398
|
)
|
|
$
|
332
|
|
Other current liabilities
|
143
|
|
|
377
|
|
|
168
|
|
|
(104
|
)
|
|
584
|
|
|||||
Total Current Liabilities
|
2,133
|
|
|
820
|
|
|
465
|
|
|
(2,502
|
)
|
|
916
|
|
|||||
Liabilities subject to compromise
|
—
|
|
|
832
|
|
|
—
|
|
|
—
|
|
|
832
|
|
|||||
Debt, long-term portion, net
|
8,531
|
|
|
216
|
|
|
31
|
|
|
—
|
|
|
8,778
|
|
|||||
Intercompany note payable
|
3,042
|
|
|
—
|
|
|
—
|
|
|
(3,042
|
)
|
|
—
|
|
|||||
Other long-term liabilities
|
132
|
|
|
313
|
|
|
51
|
|
|
(8
|
)
|
|
488
|
|
|||||
Total Liabilities
|
13,838
|
|
|
2,181
|
|
|
547
|
|
|
(5,552
|
)
|
|
11,014
|
|
|||||
Stockholders’ Equity
|
|
|
|
|
|
|
|
|
|
||||||||||
Dynegy Stockholders’ Equity
|
2,042
|
|
|
12,152
|
|
|
23
|
|
|
(12,175
|
)
|
|
2,042
|
|
|||||
Intercompany note receivable
|
—
|
|
|
(3,042
|
)
|
|
—
|
|
|
3,042
|
|
|
—
|
|
|||||
Total Dynegy Stockholders’ Equity
|
2,042
|
|
|
9,110
|
|
|
23
|
|
|
(9,133
|
)
|
|
2,042
|
|
|||||
Noncontrolling interest
|
—
|
|
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
(3
|
)
|
|||||
Total Equity
|
2,042
|
|
|
9,107
|
|
|
23
|
|
|
(9,133
|
)
|
|
2,039
|
|
|||||
Total Liabilities and Equity
|
$
|
15,880
|
|
|
$
|
11,288
|
|
|
$
|
570
|
|
|
$
|
(14,685
|
)
|
|
$
|
13,053
|
|
|
Parent
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Revenues
|
$
|
—
|
|
|
$
|
4,557
|
|
|
$
|
422
|
|
|
$
|
(137
|
)
|
|
$
|
4,842
|
|
Cost of sales, excluding depreciation expense
|
—
|
|
|
(2,790
|
)
|
|
(279
|
)
|
|
137
|
|
|
(2,932
|
)
|
|||||
Gross margin
|
—
|
|
|
1,767
|
|
|
143
|
|
|
—
|
|
|
1,910
|
|
|||||
Operating and maintenance expense
|
—
|
|
|
(881
|
)
|
|
(114
|
)
|
|
—
|
|
|
(995
|
)
|
|||||
Depreciation expense
|
—
|
|
|
(757
|
)
|
|
(54
|
)
|
|
—
|
|
|
(811
|
)
|
|||||
Impairments
|
—
|
|
|
(148
|
)
|
|
—
|
|
|
—
|
|
|
(148
|
)
|
|||||
Gain (loss) on sale of assets, net
|
—
|
|
|
(123
|
)
|
|
1
|
|
|
—
|
|
|
(122
|
)
|
|||||
General and administrative expense
|
(28
|
)
|
|
(155
|
)
|
|
(6
|
)
|
|
—
|
|
|
(189
|
)
|
|||||
Acquisition and integration costs
|
(54
|
)
|
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
(57
|
)
|
|||||
Operating loss
|
(82
|
)
|
|
(300
|
)
|
|
(30
|
)
|
|
—
|
|
|
(412
|
)
|
|||||
Bankruptcy reorganization items
|
(18
|
)
|
|
512
|
|
|
—
|
|
|
—
|
|
|
494
|
|
|||||
Earnings from unconsolidated investments
|
—
|
|
|
8
|
|
|
—
|
|
|
—
|
|
|
8
|
|
|||||
Equity in losses from investments in affiliates
|
824
|
|
|
—
|
|
|
—
|
|
|
(824
|
)
|
|
—
|
|
|||||
Interest expense
|
(597
|
)
|
|
(20
|
)
|
|
(13
|
)
|
|
14
|
|
|
(616
|
)
|
|||||
Loss on early extinguishment of debt
|
(79
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(79
|
)
|
|||||
Other income and expense, net
|
28
|
|
|
53
|
|
|
—
|
|
|
(14
|
)
|
|
67
|
|
|||||
Income (loss) before income taxes
|
76
|
|
|
253
|
|
|
(43
|
)
|
|
(824
|
)
|
|
(538
|
)
|
|||||
Income tax benefit (Note 14)
|
—
|
|
|
610
|
|
|
—
|
|
|
—
|
|
|
610
|
|
|||||
Net income (loss)
|
76
|
|
|
863
|
|
|
(43
|
)
|
|
(824
|
)
|
|
72
|
|
|||||
Less: Net loss attributable to noncontrolling interest
|
—
|
|
|
(4
|
)
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
|||||
Net income (loss) attributable to Dynegy Inc.
|
$
|
76
|
|
|
$
|
867
|
|
|
$
|
(43
|
)
|
|
$
|
(824
|
)
|
|
$
|
76
|
|
|
Parent
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Revenues
|
$
|
—
|
|
|
$
|
3,942
|
|
|
$
|
468
|
|
|
$
|
(92
|
)
|
|
$
|
4,318
|
|
Cost of sales, excluding depreciation expense
|
—
|
|
|
(2,112
|
)
|
|
(261
|
)
|
|
92
|
|
|
(2,281
|
)
|
|||||
Gross margin
|
—
|
|
|
1,830
|
|
|
207
|
|
|
—
|
|
|
2,037
|
|
|||||
Operating and maintenance expense
|
—
|
|
|
(796
|
)
|
|
(144
|
)
|
|
—
|
|
|
(940
|
)
|
|||||
Depreciation expense
|
—
|
|
|
(612
|
)
|
|
(77
|
)
|
|
—
|
|
|
(689
|
)
|
|||||
Impairments
|
—
|
|
|
(858
|
)
|
|
—
|
|
|
—
|
|
|
(858
|
)
|
|||||
Gain (loss) on sale of assets, net
|
(2
|
)
|
|
1
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|||||
General and administrative expense
|
(7
|
)
|
|
(148
|
)
|
|
(6
|
)
|
|
—
|
|
|
(161
|
)
|
|||||
Acquisition and integration costs
|
(10
|
)
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
(11
|
)
|
|||||
Other
|
—
|
|
|
(9
|
)
|
|
(8
|
)
|
|
—
|
|
|
(17
|
)
|
|||||
Operating loss
|
(19
|
)
|
|
(593
|
)
|
|
(28
|
)
|
|
—
|
|
|
(640
|
)
|
|||||
Bankruptcy reorganization items
|
—
|
|
|
(96
|
)
|
|
—
|
|
|
—
|
|
|
(96
|
)
|
|||||
Earnings from unconsolidated investments
|
—
|
|
|
7
|
|
|
—
|
|
|
—
|
|
|
7
|
|
|||||
Equity in losses from investments in affiliates
|
(715
|
)
|
|
—
|
|
|
—
|
|
|
715
|
|
|
—
|
|
|||||
Interest expense
|
(538
|
)
|
|
(83
|
)
|
|
(9
|
)
|
|
5
|
|
|
(625
|
)
|
|||||
Other income and expense, net
|
32
|
|
|
38
|
|
|
—
|
|
|
(5
|
)
|
|
65
|
|
|||||
Loss before income taxes
|
(1,240
|
)
|
|
(727
|
)
|
|
(37
|
)
|
|
715
|
|
|
(1,289
|
)
|
|||||
Income tax benefit (Note 14)
|
—
|
|
|
45
|
|
|
—
|
|
|
—
|
|
|
45
|
|
|||||
Net loss
|
(1,240
|
)
|
|
(682
|
)
|
|
(37
|
)
|
|
715
|
|
|
(1,244
|
)
|
|||||
Less: Net loss attributable to noncontrolling interest
|
—
|
|
|
(4
|
)
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
|||||
Net loss attributable to Dynegy Inc.
|
$
|
(1,240
|
)
|
|
$
|
(678
|
)
|
|
$
|
(37
|
)
|
|
$
|
715
|
|
|
$
|
(1,240
|
)
|
|
Parent
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Revenues
|
$
|
—
|
|
|
$
|
3,508
|
|
|
$
|
525
|
|
|
$
|
(163
|
)
|
|
$
|
3,870
|
|
Cost of sales, excluding depreciation expense
|
—
|
|
|
(1,874
|
)
|
|
(317
|
)
|
|
163
|
|
|
(2,028
|
)
|
|||||
Gross margin
|
—
|
|
|
1,634
|
|
|
208
|
|
|
—
|
|
|
1,842
|
|
|||||
Operating and maintenance expense
|
—
|
|
|
(717
|
)
|
|
(122
|
)
|
|
—
|
|
|
(839
|
)
|
|||||
Depreciation expense
|
—
|
|
|
(505
|
)
|
|
(82
|
)
|
|
—
|
|
|
(587
|
)
|
|||||
Impairments
|
—
|
|
|
(74
|
)
|
|
(25
|
)
|
|
—
|
|
|
(99
|
)
|
|||||
Loss on sale of assets, net
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|||||
General and administrative expense
|
(6
|
)
|
|
(116
|
)
|
|
(6
|
)
|
|
—
|
|
|
(128
|
)
|
|||||
Acquisition and integration costs
|
—
|
|
|
(124
|
)
|
|
—
|
|
|
—
|
|
|
(124
|
)
|
|||||
Operating income (loss)
|
(6
|
)
|
|
97
|
|
|
(27
|
)
|
|
—
|
|
|
64
|
|
|||||
Earnings from unconsolidated investments
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|||||
Equity in earnings from investments in affiliates
|
476
|
|
|
—
|
|
|
—
|
|
|
(476
|
)
|
|
—
|
|
|||||
Interest expense
|
(475
|
)
|
|
(69
|
)
|
|
(4
|
)
|
|
2
|
|
|
(546
|
)
|
|||||
Other income and expense, net
|
55
|
|
|
1
|
|
|
—
|
|
|
(2
|
)
|
|
54
|
|
|||||
Income (loss) before income taxes
|
50
|
|
|
30
|
|
|
(31
|
)
|
|
(476
|
)
|
|
(427
|
)
|
|||||
Income tax benefit (Note 14)
|
—
|
|
|
472
|
|
|
2
|
|
|
—
|
|
|
474
|
|
|||||
Net income (loss)
|
50
|
|
|
502
|
|
|
(29
|
)
|
|
(476
|
)
|
|
47
|
|
|||||
Less: Net income attributable to noncontrolling interest
|
—
|
|
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
(3
|
)
|
|||||
Net income (loss) attributable to Dynegy Inc.
|
$
|
50
|
|
|
$
|
505
|
|
|
$
|
(29
|
)
|
|
$
|
(476
|
)
|
|
$
|
50
|
|
|
Parent
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Net income (loss)
|
$
|
76
|
|
|
$
|
863
|
|
|
$
|
(43
|
)
|
|
$
|
(824
|
)
|
|
$
|
72
|
|
Other comprehensive income (loss) before reclassifications:
|
|
|
|
|
|
|
|
|
|
||||||||||
Actuarial gain (loss) and plan amendments, net of tax of $5
|
22
|
|
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
19
|
|
|||||
Amounts reclassified from accumulated other comprehensive income:
|
|
|
|
|
|
|
|
|
|
||||||||||
Amortization of unrecognized prior service credit, net of tax of zero
|
(7
|
)
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
(8
|
)
|
|||||
Other comprehensive loss from investment in affiliates
|
(4
|
)
|
|
—
|
|
|
—
|
|
|
4
|
|
|
—
|
|
|||||
Other comprehensive income (loss), net of tax
|
11
|
|
|
(3
|
)
|
|
(1
|
)
|
|
4
|
|
|
11
|
|
|||||
Comprehensive income (loss)
|
87
|
|
|
860
|
|
|
(44
|
)
|
|
(820
|
)
|
|
83
|
|
|||||
Less: Comprehensive loss attributable to noncontrolling interest
|
—
|
|
|
(4
|
)
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
|||||
Total comprehensive income (loss) attributable to Dynegy Inc.
|
$
|
87
|
|
|
$
|
864
|
|
|
$
|
(44
|
)
|
|
$
|
(820
|
)
|
|
$
|
87
|
|
|
Parent
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Net loss
|
$
|
(1,240
|
)
|
|
$
|
(682
|
)
|
|
$
|
(37
|
)
|
|
$
|
715
|
|
|
$
|
(1,244
|
)
|
Other comprehensive income (loss) before reclassifications:
|
|
|
|
|
|
|
|
|
|
||||||||||
Actuarial gain (loss) and plan amendments, net of tax of $3
|
(4
|
)
|
|
1
|
|
|
6
|
|
|
—
|
|
|
3
|
|
|||||
Amounts reclassified from accumulated other comprehensive income:
|
|
|
|
|
|
|
|
|
|
||||||||||
Settlement cost, net of tax of zero
|
—
|
|
|
—
|
|
|
6
|
|
|
—
|
|
|
6
|
|
|||||
Amortization of unrecognized prior service credit, net of tax of zero
|
(4
|
)
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
(5
|
)
|
|||||
Other comprehensive income from investment in affiliates
|
12
|
|
|
—
|
|
|
—
|
|
|
(12
|
)
|
|
—
|
|
|||||
Other comprehensive income, net of tax
|
4
|
|
|
1
|
|
|
11
|
|
|
(12
|
)
|
|
4
|
|
|||||
Comprehensive loss
|
(1,236
|
)
|
|
(681
|
)
|
|
(26
|
)
|
|
703
|
|
|
(1,240
|
)
|
|||||
Less: Comprehensive income (loss) attributable to noncontrolling interest
|
2
|
|
|
(2
|
)
|
|
—
|
|
|
(2
|
)
|
|
(2
|
)
|
|||||
Total comprehensive loss attributable to Dynegy Inc.
|
$
|
(1,238
|
)
|
|
$
|
(679
|
)
|
|
$
|
(26
|
)
|
|
$
|
705
|
|
|
$
|
(1,238
|
)
|
|
Parent
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Net income (loss)
|
$
|
50
|
|
|
$
|
502
|
|
|
$
|
(29
|
)
|
|
$
|
(476
|
)
|
|
$
|
47
|
|
Other comprehensive income (loss) before reclassifications:
|
|
|
|
|
|
|
|
|
|
||||||||||
Actuarial gain (loss) and plan amendments, net of tax of zero
|
(8
|
)
|
|
7
|
|
|
5
|
|
|
—
|
|
|
4
|
|
|||||
Amounts reclassified from accumulated other comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
||||||||||
Amortization of unrecognized prior service credit and actuarial gain, net of tax of zero
|
(3
|
)
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
(4
|
)
|
|||||
Other comprehensive loss from investment in affiliates
|
11
|
|
|
—
|
|
|
—
|
|
|
(11
|
)
|
|
—
|
|
|||||
Other comprehensive income, net of tax
|
—
|
|
|
7
|
|
|
4
|
|
|
(11
|
)
|
|
—
|
|
|||||
Comprehensive income (loss)
|
50
|
|
|
509
|
|
|
(25
|
)
|
|
(487
|
)
|
|
47
|
|
|||||
Less: Comprehensive income (loss) attributable to noncontrolling interest
|
1
|
|
|
(2
|
)
|
|
—
|
|
|
(1
|
)
|
|
(2
|
)
|
|||||
Total comprehensive income (loss) attributable to Dynegy Inc.
|
$
|
49
|
|
|
$
|
511
|
|
|
$
|
(25
|
)
|
|
$
|
(486
|
)
|
|
$
|
49
|
|
|
Parent
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Net cash provided by (used in) operating activities
|
$
|
(427
|
)
|
|
$
|
899
|
|
|
$
|
113
|
|
|
$
|
—
|
|
|
$
|
585
|
|
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
||||||||||
Capital expenditures
|
—
|
|
|
(208
|
)
|
|
(16
|
)
|
|
—
|
|
|
(224
|
)
|
|||||
Acquisitions, net of cash acquired/divestitures
|
(3,244
|
)
|
|
(75
|
)
|
|
—
|
|
|
—
|
|
|
(3,319
|
)
|
|||||
Distributions from unconsolidated affiliate
|
—
|
|
|
12
|
|
|
—
|
|
|
—
|
|
|
12
|
|
|||||
Proceeds from sales of assets, net
|
775
|
|
|
(4
|
)
|
|
1
|
|
|
—
|
|
|
772
|
|
|||||
Net intercompany transfers
|
691
|
|
|
—
|
|
|
—
|
|
|
(691
|
)
|
|
—
|
|
|||||
Net cash used in investing activities
|
(1,778
|
)
|
|
(275
|
)
|
|
(15
|
)
|
|
(691
|
)
|
|
(2,759
|
)
|
|||||
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
||||||||||
Proceeds from long-term borrowings, net of debt issuance costs
|
1,743
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,743
|
|
|||||
Repayments of borrowings
|
(2,487
|
)
|
|
(46
|
)
|
|
(56
|
)
|
|
—
|
|
|
(2,589
|
)
|
|||||
Proceeds from issuance of equity, net of issuance costs
|
150
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
150
|
|
|||||
Payments of debt extinguishment costs
|
(50
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(50
|
)
|
|||||
Preferred stock dividends paid
|
(22
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(22
|
)
|
|||||
Interest rate swap settlement payments
|
(20
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(20
|
)
|
|||||
Acquisition of noncontrolling interest
|
(375
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(375
|
)
|
|||||
Payments related to bankruptcy settlement
|
(128
|
)
|
|
(5
|
)
|
|
—
|
|
|
—
|
|
|
(133
|
)
|
|||||
Net intercompany transfers
|
—
|
|
|
(631
|
)
|
|
(60
|
)
|
|
691
|
|
|
—
|
|
|||||
Intercompany borrowings, net of repayments
|
80
|
|
|
(80
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Other financing
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3
|
)
|
|||||
Net cash provided by (used in) financing activities
|
(1,112
|
)
|
|
(762
|
)
|
|
(116
|
)
|
|
691
|
|
|
(1,299
|
)
|
|||||
Net decrease in cash and cash equivalents
|
(3,317
|
)
|
|
(138
|
)
|
|
(18
|
)
|
|
—
|
|
|
(3,473
|
)
|
|||||
Cash, cash equivalents and restricted cash, beginning of period
|
3,550
|
|
|
262
|
|
|
26
|
|
|
—
|
|
|
3,838
|
|
|||||
Cash, cash equivalents and restricted cash, end of period
|
$
|
233
|
|
|
$
|
124
|
|
|
$
|
8
|
|
|
$
|
—
|
|
|
$
|
365
|
|
|
Parent
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash provided by (used in) operating activities
|
$
|
(476
|
)
|
|
$
|
1,090
|
|
|
$
|
31
|
|
|
$
|
—
|
|
|
$
|
645
|
|
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
||||||||||
Capital expenditures
|
—
|
|
|
(243
|
)
|
|
(50
|
)
|
|
—
|
|
|
(293
|
)
|
|||||
Proceeds from sales of assets, net
|
171
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
176
|
|
|||||
Distributions from unconsolidated affiliate
|
—
|
|
|
14
|
|
|
—
|
|
|
—
|
|
|
14
|
|
|||||
Net intercompany transfers
|
958
|
|
|
—
|
|
|
—
|
|
|
(958
|
)
|
|
—
|
|
|||||
Other investing
|
—
|
|
|
10
|
|
|
—
|
|
|
—
|
|
|
10
|
|
|||||
Net cash provided by (used in) investing activities
|
1,129
|
|
|
(214
|
)
|
|
(50
|
)
|
|
(958
|
)
|
|
(93
|
)
|
|||||
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
||||||||||
Proceeds from long-term borrowings, net of debt issuance costs
|
2,816
|
|
|
198
|
|
|
—
|
|
|
—
|
|
|
3,014
|
|
|||||
Repayments of borrowings
|
(563
|
)
|
|
(15
|
)
|
|
(11
|
)
|
|
—
|
|
|
(589
|
)
|
|||||
Proceeds from issuance of equity, net of issuance costs
|
359
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
359
|
|
|||||
Preferred stock dividends paid
|
(22
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(22
|
)
|
|||||
Interest rate swap settlement payments
|
(17
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(17
|
)
|
|||||
Net intercompany transfers
|
—
|
|
|
(991
|
)
|
|
33
|
|
|
958
|
|
|
—
|
|
|||||
Other financing
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3
|
)
|
|||||
Net cash provided by (used in) financing activities
|
2,570
|
|
|
(808
|
)
|
|
22
|
|
|
958
|
|
|
2,742
|
|
|||||
Net increase in cash and cash equivalents
|
3,223
|
|
|
68
|
|
|
3
|
|
|
—
|
|
|
3,294
|
|
|||||
Cash, cash equivalents and restricted cash, beginning of period
|
327
|
|
|
194
|
|
|
23
|
|
|
—
|
|
|
544
|
|
|||||
Cash, cash equivalents and restricted cash, end of period
|
$
|
3,550
|
|
|
$
|
262
|
|
|
$
|
26
|
|
|
$
|
—
|
|
|
$
|
3,838
|
|
|
Parent
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash provided by (used in) operating activities
|
$
|
(432
|
)
|
|
$
|
682
|
|
|
$
|
(156
|
)
|
|
$
|
—
|
|
|
$
|
94
|
|
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
||||||||||
Capital expenditures
|
—
|
|
|
(290
|
)
|
|
(11
|
)
|
|
—
|
|
|
(301
|
)
|
|||||
Acquisitions, net of cash acquired/divestitures
|
(6,207
|
)
|
|
29
|
|
|
100
|
|
|
—
|
|
|
(6,078
|
)
|
|||||
Distributions from unconsolidated affiliate
|
—
|
|
|
8
|
|
|
—
|
|
|
—
|
|
|
8
|
|
|||||
Net intercompany transfers
|
450
|
|
|
—
|
|
|
—
|
|
|
(450
|
)
|
|
—
|
|
|||||
Other investing
|
—
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|||||
Net cash provided by (used in) investing activities
|
(5,757
|
)
|
|
(250
|
)
|
|
89
|
|
|
(450
|
)
|
|
(6,368
|
)
|
|||||
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
||||||||||
Proceeds from long-term borrowings, net of debt issuance costs
|
(31
|
)
|
|
78
|
|
|
19
|
|
|
—
|
|
|
66
|
|
|||||
Repayments of borrowings
|
(8
|
)
|
|
(23
|
)
|
|
—
|
|
|
—
|
|
|
(31
|
)
|
|||||
Proceeds from issuance of equity, net of issuance costs
|
(6
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6
|
)
|
|||||
Preferred stock dividends paid
|
(23
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(23
|
)
|
|||||
Interest rate swap settlement payments
|
(17
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(17
|
)
|
|||||
Repurchase of common stock
|
(250
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(250
|
)
|
|||||
Net intercompany transfers
|
—
|
|
|
(347
|
)
|
|
(103
|
)
|
|
450
|
|
|
—
|
|
|||||
Other financing
|
(4
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
|||||
Net cash provided by (used in) financing activities
|
(339
|
)
|
|
(292
|
)
|
|
(84
|
)
|
|
450
|
|
|
(265
|
)
|
|||||
Net increase (decrease) in cash and cash equivalents
|
(6,528
|
)
|
|
140
|
|
|
(151
|
)
|
|
—
|
|
|
(6,539
|
)
|
|||||
Cash, cash equivalents and restricted cash, beginning of period
|
6,855
|
|
|
54
|
|
|
174
|
|
|
—
|
|
|
7,083
|
|
|||||
Cash, cash equivalents and restricted cash, end of period
|
$
|
327
|
|
|
$
|
194
|
|
|
$
|
23
|
|
|
$
|
—
|
|
|
$
|
544
|
|
(amounts in millions)
|
|
December 31, 2016
|
||
Genco senior notes:
|
|
|
||
7.00% Senior Notes Series H, due 2018
|
|
$
|
300
|
|
6.30% Senior Notes Series I, due 2020
|
|
250
|
|
|
7.95% Senior Notes Series F, due 2032
|
|
275
|
|
|
Interest accrued
|
|
7
|
|
|
Total liabilities subject to compromise
|
|
$
|
832
|
|
(amounts in millions)
|
|
|
||
Liabilities subject to compromise, which were terminated
|
|
$
|
832
|
|
Less:
|
|
|
||
Seven-year unsecured notes
|
|
188
|
|
|
Cash consideration
|
|
122
|
|
|
2017 Warrants, at fair value
|
|
17
|
|
|
Legal and consulting fees
|
|
11
|
|
|
Bankruptcy reorganization items
|
|
$
|
494
|
|
|
|
PJM
|
|
NY/NE
|
|
ERCOT
|
|
MISO
|
|
CAISO
|
|
Other and
Eliminations
|
|
Total
|
||||||||||||||
Domestic:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Unaffiliated revenues
|
|
$
|
2,352
|
|
|
$
|
1,031
|
|
|
$
|
276
|
|
|
$
|
1,061
|
|
|
$
|
122
|
|
|
$
|
—
|
|
|
$
|
4,842
|
|
Intercompany and affiliate revenues
|
|
(90
|
)
|
|
(2
|
)
|
|
1
|
|
|
91
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Total revenues
|
|
$
|
2,262
|
|
|
$
|
1,029
|
|
|
$
|
277
|
|
|
$
|
1,152
|
|
|
$
|
122
|
|
|
$
|
—
|
|
|
$
|
4,842
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Depreciation expense
|
|
$
|
(379
|
)
|
|
$
|
(224
|
)
|
|
$
|
(73
|
)
|
|
$
|
(75
|
)
|
|
$
|
(53
|
)
|
|
$
|
(7
|
)
|
|
$
|
(811
|
)
|
Impairments
|
|
(49
|
)
|
|
—
|
|
|
—
|
|
|
(99
|
)
|
|
—
|
|
|
—
|
|
|
(148
|
)
|
|||||||
Gain (loss) on sale of assets, net
|
|
(36
|
)
|
|
(90
|
)
|
|
—
|
|
|
1
|
|
|
3
|
|
|
—
|
|
|
(122
|
)
|
|||||||
General and administrative expense
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(189
|
)
|
|
(189
|
)
|
|||||||
Acquisition and integration costs
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(57
|
)
|
|
(57
|
)
|
|||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Operating income (loss)
|
|
$
|
192
|
|
|
$
|
(113
|
)
|
|
$
|
(147
|
)
|
|
$
|
(44
|
)
|
|
$
|
(45
|
)
|
|
$
|
(255
|
)
|
|
$
|
(412
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Bankruptcy reorganization items
|
|
—
|
|
|
—
|
|
|
—
|
|
|
494
|
|
|
—
|
|
|
—
|
|
|
494
|
|
|||||||
Earnings from unconsolidated investments
|
|
3
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8
|
|
|||||||
Interest expense
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(616
|
)
|
|
(616
|
)
|
|||||||
Loss on early extinguishment of debt
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(79
|
)
|
|
(79
|
)
|
|||||||
Other income and expense, net
|
|
16
|
|
|
—
|
|
|
—
|
|
|
26
|
|
|
—
|
|
|
25
|
|
|
67
|
|
|||||||
Loss before income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(538
|
)
|
|||||||||
Income tax benefit
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
610
|
|
|
610
|
|
|||||||
Net Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
72
|
|
|||||||||||||
Less: Net loss attributable to noncontrolling interest
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4
|
)
|
|||||||||||||
Net Income attributable to Dynegy Inc.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
76
|
|
||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Total assets—domestic
|
|
$
|
4,912
|
|
|
$
|
3,374
|
|
|
$
|
1,563
|
|
|
$
|
812
|
|
|
$
|
455
|
|
|
$
|
655
|
|
|
$
|
11,771
|
|
Investment in unconsolidated affiliate
|
|
$
|
67
|
|
|
$
|
56
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
123
|
|
Capital expenditures
|
|
$
|
(103
|
)
|
|
$
|
(50
|
)
|
|
$
|
(26
|
)
|
|
$
|
(26
|
)
|
|
$
|
(12
|
)
|
|
$
|
(7
|
)
|
|
$
|
(224
|
)
|
|
|
PJM
|
|
NY/NE
|
|
MISO
|
|
CAISO
|
|
Other and
Eliminations
|
|
Total
|
||||||||||||
Domestic:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Unaffiliated revenues
|
|
$
|
2,147
|
|
|
$
|
836
|
|
|
$
|
1,165
|
|
|
$
|
142
|
|
|
$
|
—
|
|
|
$
|
4,290
|
|
Intercompany revenues
|
|
55
|
|
|
1
|
|
|
(28
|
)
|
|
—
|
|
|
—
|
|
|
28
|
|
||||||
Total revenues
|
|
$
|
2,202
|
|
|
$
|
837
|
|
|
$
|
1,137
|
|
|
$
|
142
|
|
|
$
|
—
|
|
|
$
|
4,318
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Depreciation expense
|
|
$
|
(346
|
)
|
|
$
|
(215
|
)
|
|
$
|
(81
|
)
|
|
$
|
(42
|
)
|
|
$
|
(5
|
)
|
|
$
|
(689
|
)
|
Impairments
|
|
(65
|
)
|
|
—
|
|
|
(793
|
)
|
|
—
|
|
|
—
|
|
|
(858
|
)
|
||||||
Gain (loss) on sale of assets, net
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
(2
|
)
|
|
(1
|
)
|
||||||
General and administrative expense
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(161
|
)
|
|
(161
|
)
|
||||||
Acquisition and integration costs
|
|
—
|
|
|
—
|
|
|
8
|
|
|
—
|
|
|
(19
|
)
|
|
(11
|
)
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Operating income (loss)
|
|
$
|
414
|
|
|
$
|
(29
|
)
|
|
$
|
(832
|
)
|
|
$
|
(5
|
)
|
|
$
|
(188
|
)
|
|
$
|
(640
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Bankruptcy reorganization items
|
|
—
|
|
|
—
|
|
|
(96
|
)
|
|
—
|
|
|
—
|
|
|
(96
|
)
|
||||||
Earnings from unconsolidated investments
|
|
7
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
7
|
|
||||||
Interest expense
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(625
|
)
|
|
(625
|
)
|
||||||
Other income and expense, net
|
|
9
|
|
|
1
|
|
|
15
|
|
|
12
|
|
|
28
|
|
|
65
|
|
||||||
Loss before income taxes
|
|
|
|
|
|
|
|
|
|
|
|
(1,289
|
)
|
|||||||||||
Income tax benefit
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
45
|
|
|
45
|
|
||||||
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
(1,244
|
)
|
|||||||||||
Less: Net loss attributable to noncontrolling interest
|
|
|
|
|
|
|
|
|
|
|
|
(4
|
)
|
|||||||||||
Net loss attributable to Dynegy Inc.
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(1,240
|
)
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Total assets—domestic
|
|
$
|
4,939
|
|
|
$
|
2,769
|
|
|
$
|
1,065
|
|
|
$
|
485
|
|
|
$
|
3,795
|
|
|
$
|
13,053
|
|
Capital expenditures
|
|
$
|
(160
|
)
|
|
$
|
(64
|
)
|
|
$
|
(52
|
)
|
|
$
|
(7
|
)
|
|
$
|
(10
|
)
|
|
$
|
(293
|
)
|
|
|
PJM
|
|
NY/NE
|
|
MISO
|
|
CAISO
|
|
Other and
Eliminations
|
|
Total
|
||||||||||||
Domestic:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Unaffiliated revenues
|
|
$
|
1,708
|
|
|
$
|
705
|
|
|
$
|
1,279
|
|
|
$
|
178
|
|
|
$
|
—
|
|
|
$
|
3,870
|
|
Intercompany revenues
|
|
8
|
|
|
(10
|
)
|
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total revenues
|
|
$
|
1,716
|
|
|
$
|
695
|
|
|
$
|
1,281
|
|
|
$
|
178
|
|
|
$
|
—
|
|
|
$
|
3,870
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Depreciation expense
|
|
$
|
(281
|
)
|
|
$
|
(186
|
)
|
|
$
|
(68
|
)
|
|
$
|
(48
|
)
|
|
$
|
(4
|
)
|
|
$
|
(587
|
)
|
Impairments
|
|
—
|
|
|
(25
|
)
|
|
(74
|
)
|
|
—
|
|
|
—
|
|
|
(99
|
)
|
||||||
Loss on sale of assets, net
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
||||||
General and administrative expense
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(128
|
)
|
|
(128
|
)
|
||||||
Acquisition and integration costs
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(124
|
)
|
|
(124
|
)
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Operating income (loss)
|
|
$
|
423
|
|
|
$
|
(56
|
)
|
|
$
|
(43
|
)
|
|
$
|
(8
|
)
|
|
$
|
(252
|
)
|
|
$
|
64
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Earnings from unconsolidated investments
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
||||||
Interest expense
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(546
|
)
|
|
(546
|
)
|
||||||
Other income and expense, net
|
|
(2
|
)
|
|
—
|
|
|
1
|
|
|
—
|
|
|
55
|
|
|
54
|
|
||||||
Loss from continuing operations before income taxes
|
|
|
|
|
|
|
|
|
|
|
|
(427
|
)
|
|||||||||||
Income tax benefit
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
474
|
|
|
474
|
|
||||||
Net income
|
|
|
|
|
|
|
|
|
|
|
|
47
|
|
|||||||||||
Less: Net loss attributable to noncontrolling interest
|
|
|
|
|
|
|
|
|
|
|
|
(3
|
)
|
|||||||||||
Net income attributable to Dynegy Inc.
|
|
|
|
|
|
|
|
|
|
|
|
$
|
50
|
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Total assets—domestic
|
|
$
|
5,474
|
|
|
$
|
2,970
|
|
|
$
|
1,995
|
|
|
$
|
534
|
|
|
$
|
486
|
|
|
$
|
11,459
|
|
Investment in unconsolidated affiliate
|
|
$
|
190
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
190
|
|
Capital expenditures
|
|
$
|
(106
|
)
|
|
$
|
(52
|
)
|
|
$
|
(119
|
)
|
|
$
|
(11
|
)
|
|
$
|
(13
|
)
|
|
$
|
(301
|
)
|
(amounts in millions)
|
|
Revenues
|
|
|
||||||||||
Customers
|
|
2017
|
|
2016
|
|
2015
|
|
Segment(s)
|
||||||
PJM
|
|
$
|
1,313
|
|
|
$
|
1,366
|
|
|
$
|
1,088
|
|
|
PJM, MISO
|
MISO
|
|
$
|
506
|
|
|
$
|
688
|
|
|
$
|
842
|
|
|
MISO
|
ISO-NE
|
|
$
|
669
|
|
|
$
|
437
|
|
|
N/A
|
|
|
MISO, NY/NE
|
SUBSIDIARY
|
|
STATE OR COUNTRY OF INCORPORATION OR ORGANIZATION
|
||
1.
|
|
Dynegy Gas Investments, LLC
|
|
Delaware
|
2.
|
|
Illinova Corporation
|
|
Illinois
|
3.
|
|
Dynegy Resource Holdings, LLC
|
|
Delaware
|
4.
|
|
Dynegy Coal Holdco, LLC
|
|
Delaware
|
(1)
|
Registration Statement (Form S-8 No. 333-211734) pertaining to the 2012 Amended and Restated Long Term Incentive Plan of Dynegy Inc.
|
(2)
|
Registration Statement (Form S-3 No. 333-222164) of Dynegy Inc.
|
(3)
|
Registration Statement (Form S-4, as amended by Amendment no. 1 No. 333-222049) of Vistra Energy Corp
|
1.
|
I have reviewed this report on Form 10-K of Dynegy Inc.;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
Date:
|
February 22, 2018
|
By:
|
/s/ R
OBERT
C
.
F
LEXON
|
|
|
|
Robert C. Flexon
President and Chief Executive Officer
|
1.
|
I have reviewed this report on Form 10-K of Dynegy Inc.;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
Date:
|
February 22, 2018
|
By:
|
/s/ C
LINT
C. F
REELAND
|
|
|
|
Clint C. Freeland
Executive Vice President and Chief Financial Officer
|
(1)
|
the Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, and
|
(2)
|
the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company at the dates and for the periods indicated.
|
Date:
|
February 22, 2018
|
By:
|
/s/ ROBERT C. FLEXON
|
|
|
|
Robert C. Flexon
President and Chief Executive Officer
|
(1)
|
the Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, and
|
(2)
|
the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company at the dates and for the periods indicated.
|
Date:
|
February 22, 2018
|
By:
|
/s/ C
LINT
C. F
REELAND
|
|
|
|
Clint C. Freeland
Executive Vice President and Chief Financial Officer
|
Mine or Operating Name/MSHA Identification Number
|
|
Section 104 S&S Citations (#)
|
|
Section 104(b) Orders (#)
|
|
Section 104(d) Citations and Orders (#)
|
|
Section 110(b)(2) Violations (#)
|
|
Section 107(a) Orders (#)
|
|
Total Dollar Value of MHSA Assessments Proposed ($)
|
|||||||
Honeybrook Refuse Operation/36-08595
|
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
116
|
|
NEPCO CO - Generation Facility/36-08064
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
148
|
|
Mine or Operating Name/MSHA Identification Number
|
|
Total Number of Mining Related Fatalities (#)
|
|
Received Notice of Pattern of Violations Under Section 104(e) (yes/no)
|
|
Received Notice of Potential to Have Pattern Under Section 104(e) (yes/no)
|
|
Legal Actions Pending as of Last day of Period (#)
|
|
Legal Actions Initiated During Period (#)
|
|
Legal Actions Resolved During Period (#)
|
||||
Honeybrook Refuse Operation/36-08595
|
|
—
|
|
|
No
|
|
No
|
|
—
|
|
|
—
|
|
|
—
|
|
NEPCO CO - Generation Facility/36-08064
|
|
—
|
|
|
No
|
|
No
|
|
—
|
|
|
—
|
|
|
—
|
|