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NRG ENERGY, INC. - Quarter Report: 2017 September (Form 10-Q)

                                                                                            
                                

                                            
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
x
 
Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
 
 
 
 
 
For the Quarterly Period Ended: September 30, 2017
 
 
 
o
 
Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Commission File Number: 001-15891
NRG Energy, Inc.
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction
of incorporation or organization)
 
41-1724239
(I.R.S. Employer
Identification No.)
 
 
 
804 Carnegie Center, Princeton, New Jersey
(Address of principal executive offices)
 
08540
(Zip Code)
(609) 524-4500
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes x       No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes x       No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer x
 
Accelerated filer o
 
Non-accelerated filer o
 
Smaller reporting company o
Emerging growth company o
 
 
 
 
(Do not check if a smaller reporting company)
 
 
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  o  
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o       No x
As of October 31, 2017, there were 316,641,799 shares of common stock outstanding, par value $0.01 per share.
 




TABLE OF CONTENTS
Index



2



CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This Quarterly Report on Form 10-Q of NRG Energy, Inc., or NRG or the Company, includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or Exchange Act. The words "believes," "projects," "anticipates," "plans," "expects," "intends," "estimates" and similar expressions are intended to identify forward-looking statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause NRG's actual results, performance and achievements, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. These factors, risks and uncertainties include the factors described under Item 1A — Risk Factors Related to NRG Energy, Inc., in Part I, Item 1A of the Company's Annual Report on Form 10-K for the year ended December 31, 2016, and the following:
NRG's ability to achieve the expected benefits of its Transformation Plan;
The potential adverse effects of the GenOn Entities' filings under Chapter 11 of the Bankruptcy Code and restructuring transactions on NRG's operations, management and employees and the risks associated with operating NRG's business during the restructuring process;
Risks and uncertainties associated with the GenOn Entities' Chapter 11 Cases including the ability to achieve anticipated benefits therefrom;
NRG's ability to engage in successful mergers and acquisitions activity;
General economic conditions, changes in the wholesale power markets and fluctuations in the cost of fuel;
Volatile power supply costs and demand for power;
Hazards customary to the power production industry and power generation operations such as fuel and electricity price volatility, unusual weather conditions (including wind and solar conditions), catastrophic weather-related or other damage to facilities, unscheduled generation outages, maintenance or repairs, unanticipated changes to fuel supply costs or availability due to higher demand, shortages, transportation problems or other developments, environmental incidents, or electric transmission or gas pipeline system constraints and the possibility that NRG may not have adequate insurance to cover losses as a result of such hazards;
The effectiveness of NRG's risk management policies and procedures, and the ability of NRG's counterparties to satisfy their financial commitments;
Counterparties' collateral demands and other factors affecting NRG's liquidity position and financial condition;
NRG's ability to operate its businesses efficiently and generate earnings and cash flows from its asset-based businesses in relation to its debt and other obligations;
NRG's ability to enter into contracts to sell power and procure fuel on acceptable terms and prices;
The liquidity and competitiveness of wholesale markets for energy commodities;
Government regulation, including compliance with regulatory requirements and changes in market rules, rates, tariffs and environmental laws;
Changes in law, including judicial decisions;
Price mitigation strategies and other market structures employed by ISOs or RTOs that result in a failure to adequately and fairly compensate NRG's generation units;
NRG's ability to mitigate forced outage risk for units subject to capacity performance requirements in PJM, performance incentives in ISO-NE, and scarcity pricing in ERCOT;
NRG's ability to borrow funds and access capital markets, as well as NRG's substantial indebtedness and the possibility that NRG may incur additional indebtedness going forward;
Operating and financial restrictions placed on NRG and its subsidiaries that are contained in the indentures governing NRG's outstanding notes, in NRG's Senior Credit Facility, and in debt and other agreements of certain of NRG subsidiaries and project affiliates generally;
Cyber terrorism and inadequate cybersecurity, or the occurrence of a catastrophic loss and the possibility that NRG may not have adequate insurance to cover losses resulting from such hazards or the inability of NRG's insurers to provide coverage;
NRG's ability to develop and build new power generation facilities;
NRG's ability to develop and innovate new products as retail and wholesale markets continue to change and evolve;
NRG's ability to implement its strategy of finding ways to meet the challenges of climate change, clean air and protecting natural resources while taking advantage of business opportunities;
NRG's ability to increase cash from operations through operational and commercial initiatives, corporate efficiencies, asset strategy, and a range of other programs throughout NRG to reduce costs or generate revenues;

3



NRG's ability to sell assets to NRG Yield, Inc. and to close drop-down transactions;
NRG's ability to achieve its strategy of regularly returning capital to stockholders;
NRG's ability to obtain and maintain retail market share;
NRG's ability to successfully evaluate investments and achieve intended financial results in new business and growth initiatives;
NRG's ability to successfully integrate, realize cost savings and manage any acquired businesses; and
NRG's ability to develop and maintain successful partnering relationships.
Forward-looking statements speak only as of the date they were made, and NRG undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors that could cause NRG's actual results to differ materially from those contemplated in any forward-looking statements included in this Quarterly Report on Form 10-Q should not be construed as exhaustive.

4



GLOSSARY OF TERMS
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:
2016 Form 10-K
 
NRG’s Annual Report on Form 10-K for the year ended December 31, 2016
2023 Term Loan Facility
 
The Company's $1.9 billion term loan facility due 2023, a component of the Senior Credit Facility
Adjusted EBITDA
 
Adjusted earnings before interest, taxes, depreciation and amortization
ASC
 
The FASB Accounting Standards Codification, which the FASB established as the source of authoritative GAAP
ASU
 
Accounting Standards Updates, which reflect updates to the ASC
Average realized prices
 
Volume-weighted average power prices, net of average fuel costs and reflecting the impact of settled hedges
BACT
 
Best Available Control Technology
Bankruptcy Code
 
Chapter 11 of Title 11 of the U.S. Bankruptcy Code
Bankruptcy Court
 
United States Bankruptcy Court for the Southern District of Texas, Houston Division
BETM
 
Boston Energy Trading and Marketing LLC
BTU
 
British Thermal Unit
CAA
 
Clean Air Act
CAIR
 
Clean Air Interstate Rule
CAISO
 
California Independent System Operator
CDD
 
Cooling Degree Day
CDWR
 
California Department of Water Resources
CEC
 
California Energy Commission
CenterPoint
 
CenterPoint Energy, Inc. and its subsidiaries, on and after August 31, 2002, and Reliant Energy, Incorporated and its subsidiaries prior to August 31, 2002
CFTC
 
U.S. Commodity Futures Trading Commission
Chapter 11 Cases
 
Voluntary cases commenced by the GenOn Entities under the Bankruptcy Code in the Bankruptcy Court
COD
 
Commercial Operation Date
ComEd
 
Commonwealth Edison
Company
 
NRG Energy, Inc.
CPP
 
Clean Power Plan
CPUC
 
California Public Utilities Commission
CSAPR
 
Cross-State Air Pollution Rule
CVSR
 
California Valley Solar Ranch
D.C. Circuit
 
U.S. Court of Appeals for the District of Columbia Circuit
DGPV Holdco 1
 
NRG DGPV Holdco 1 LLC
DGPV Holdco 2
 
NRG DGPV Holdco 2 LLC
Distributed Solar
 
Solar power projects that primarily sell power to customers for usage on site, or are interconnected to sell power into a local distribution grid
DSI
 
Dry Sorbent Injection
Economic gross margin
 
Sum of energy revenue, capacity revenue, retail revenue and other revenue, less cost of fuels and other cost of sales
ELG
 
Effluent Limitations Guidelines
El Segundo Energy Center
 
NRG West Holdings LLC, the subsidiary of Natural Gas Repowering LLC, which owns the El Segundo Energy Center project
EME
 
Edison Mission Energy
Energy Plus Holdings
 
Energy Plus Holdings LLC
EPA
 
U.S. Environmental Protection Agency

5



EPC
 
Engineering, Procurement and Construction
ERCOT
 
Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas
ESCO
 
Energy Service Company
ESP
 
Electrostatic Precipitator
ESPP
 
NRG Energy, Inc. Amended and Restated Employee Stock Purchase Plan
ESPS
 
Existing Source Performance Standards
Exchange Act
 
The Securities Exchange Act of 1934, as amended
FASB
 
Financial Accounting Standards Board
FERC
 
Federal Energy Regulatory Commission
FGD
 
Flue gas desulfurization
FTRs
 
Financial Transmission Rights
GAAP
 
Accounting principles generally accepted in the U.S.
GenConn
 
GenConn Energy LLC
GenOn
 
GenOn Energy, Inc.
GenOn Americas Generation
 
GenOn Americas Generation, LLC
GenOn Americas Generation Senior Notes
 
GenOn Americas Generation's $695 million outstanding unsecured senior notes consisting of $366 million of 8.5% senior notes due 2021 and $329 million of 9.125% senior notes due 2031
GenOn Entities
 
GenOn and certain of its wholly owned subsidiaries, including GenOn Americas Generation. that filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court on June 14, 2017
GenOn Senior Notes
 
GenOn's $1.8 billion outstanding unsecured senior notes consisting of $691 million of 7.875% senior notes due 2017, $649 million of 9.5% senior notes due 2018, and $489 million of 9.875% senior notes due 2020
GHG
 
Greenhouse Gas
GW
 
Gigawatt
GWh
 
Gigawatt Hour
HAP
 
Hazardous Air Pollutant
HDD
 
Heating Degree Day
Heat Rate
 
A measure of thermal efficiency computed by dividing the total BTU content of the fuel burned by the resulting kWhs generated. Heat rates can be expressed as either gross or net heat rates, depending whether the electricity output measured is gross or net generation and is generally expressed as BTU per net kWh
HLBV
 
Hypothetical Liquidation at Book Value
IASB
 
Independent Accounting Standards Board
IFRS
 
International Financial Reporting Standards
ILU
 
Illinois Union Insurance Company
ISO
 
Independent System Operator
ISO-NE
 
ISO New England Inc.
ITC
 
Investment Tax Credit
LaGen
 
Louisiana Generating, L.L.C.
LIBOR
 
London Inter-Bank Offered Rate
LTIPs
 
Collectively, the NRG Long-Term Incentive Plan, as amended, and the NRG GenOn Long-Term Incentive Plan
Marsh Landing
 
NRG Marsh Landing, LLC (formerly known as GenOn Marsh Landing, LLC)
Mass Market
 
Residential and small commercial customers
MATS
 
Mercury and Air Toxics Standards promulgated by the EPA
MDth
 
Thousand Dekatherms
Midwest Generation
 
Midwest Generation, LLC
MISO
 
Midcontinent Independent System Operator, Inc.

6



MMBtu
 
Million British Thermal Units
MW
 
Megawatts
MWh
 
Saleable megawatt hour net of internal/parasitic load megawatt-hour
MWt
 
Megawatts Thermal Equivalent
NAAQS
 
National Ambient Air Quality Standards
NEPOOL
 
New England Power Pool
NERC
 
North American Electric Reliability Corporation
Net Exposure
 
Counterparty credit exposure to NRG, net of collateral
Net Generation
 
The net amount of electricity produced, expressed in kWhs or MWhs, that is the total amount of electricity generated (gross) minus the amount of electricity used during generation
NOL
 
Net Operating Loss
NOx
 
Nitrogen Oxides
NPDES
 
National Pollutant Discharge Elimination System
NPNS
 
Normal Purchase Normal Sale
NRC
 
U.S. Nuclear Regulatory Commission
NRG
 
NRG Energy, Inc.
NRG Yield
 
Reporting segment including the projects owned by NRG Yield, Inc.
NRG Yield 2019 Convertible Notes
 
$345 million aggregate principal amount of 3.50% Convertible Senior Notes due 2019 issued by NRG Yield, Inc.
NRG Yield 2020 Convertible Notes
 
$287.5 million aggregate principal amount of 3.25% Convertible Notes due 2020 issued by NRG Yield, Inc.
NRG Yield, Inc.
 
NRG Yield, Inc., the owner of 53.7% of the economic interests of NRG Yield LLC with a controlling interest, and issuer of publicly held shares of Class A and Class C common stock
NSR
 
New Source Review
Nuclear Decommissioning Trust Fund
 
NRG's nuclear decommissioning trust fund assets, which are for the Company's portion of the decommissioning of the STP, units 1 & 2
NYAG
 
State of New York Office of Attorney General
NYISO
 
New York Independent System Operator
NYSPSC
 
New York State Public Service Commission
OCI/OCL
 
Other Comprehensive Income/(Loss)
Peaking
 
Units expected to satisfy demand requirements during the periods of greatest or peak load on the system
PER
 
Peak Energy Rent
Petition Date
 
June 14, 2017
PG&E
 
Pacific Gas and Electric Company
PJM
 
PJM Interconnection, LLC
PM
 
Particulate Matter
PPA
 
Power Purchase Agreement
PSD
 
Prevention of Significant Deterioration
PTC
 
Production Tax Credit
PUCT
 
Public Utility Commission of Texas
RAPA
 
Resource Adequacy Purchase Agreement
RCRA
 
Resource Conservation and Recovery Act of 1976
REMA
 
NRG REMA LLC, which leases a 100% interest in the Shawville generating facility and 16.7% and 16.5% interests in the Keystone and Conemaugh generating facilities, respectively
Repowering
 
Technologies utilized to replace, rebuild, or redevelop major portions of an existing electrical generating facility to achieve a substantial emissions reduction, increase facility capacity and improve system efficiency
Restructuring Support Agreement
 
Restructuring Support and Lock-Up Agreement, dated as of June 12, 2017 and as amended on October 2, 2017, by and among GenOn Energy, Inc., GenOn Americas Generation, LLC, the subsidiaries signatory thereto, NRG Energy, Inc. and the noteholders signatory thereto

7



Retail
 
Reporting segment that includes NRG's residential and small commercial businesses which go to market as Reliant, NRG and other brands owned by NRG, as well as Business Solutions
Revolving Credit Facility
 
The Company’s $2.5 billion revolving credit facility, a component of the Senior Credit Facility. The revolving credit facility consists of $289 million of Tranche A Revolving Credit Facility, due 2018, and $2.2 billion of Tranche B Revolving Credit Facility, due 2021

Prior to June 30, 2016, the Company's $2.5 billion revolving credit facility due 2018, a component of the Senior Credit Facility. On June 30, 2016, the Company replaced the Senior Credit Facility, including the Revolving Credit Facility
RGGI
 
Regional Greenhouse Gas Initiative
RMR
 
Reliability Must-Run
ROFO Agreement
 
Second Amended and Restated Right of First Offer Agreement between the Company and NRG Yield, Inc.
RPV Holdco
 
NRG RPV Holdco 1 LLC
RTO
 
Regional Transmission Organization
SCE
 
Southern California Edison
SDG&E
 
San Diego Gas & Electric Company
SEC
 
U.S. Securities and Exchange Commission
Securities Act
 
The Securities Act of 1933, as amended
Senior Credit Facility
 
NRG's senior secured credit facility, compromised of the Revolving Credit Facility and the 2023 Term Loan Facility

Prior to June 30, 2016, the Company's senior secured facility, comprised of the Term Loan Facility and the Revolving Credit Facility. On June 30, 2016, the Company replaced the Senior Credit Facility
Senior Notes
 
As of September 30, 2017, the Company’s $5.4 billion outstanding unsecured senior notes, consisting of $398 million of 7.625% senior notes due 2018, $207 million of 7.875% senior notes due 2021, $992 million of 6.25% senior notes due 2022, $869 million of 6.625% senior notes due 2023, $733 million of 6.25% senior notes due 2024, $1.0 billion of 7.25% senior notes due 2026 and $1.25 billion of 6.625% senior notes due 2027
Services Agreement
 
NRG provides GenOn with various management, personnel and other services, which include human resources, regulatory and public affairs, accounting, tax, legal, information systems, treasury, risk management, commercial operations, and asset management, as set forth in the services agreement with GenOn
Settlement Agreement
 
A settlement agreement and any other documents necessary to effectuate the settlement among NRG, GenOn, and certain holders of senior unsecured notes of GenOn Americas Generation and GenOn, and certain of GenOn's direct and indirect subsidiaries
Seward
 
The Seward Power Generating Station, a 525 MW coal-fired facility in Pennsylvania
Shelby
 
The Shelby County Generating Station, a 352 MW natural gas-fired facility in Illinois
SO2
 
Sulfur Dioxide
SPP
 
Solar Power Partners
STP
 
South Texas Project — nuclear generating facility located near Bay City, Texas in which NRG owns a 44% interest
S&P
 
Standard & Poor's
TCPA
 
Telephone Consumer Protection Act
Term Loan Facility
 
Prior to June 30, 2016, the Company's $2.0 billion term loan facility due 2018, a component of the Senior Credit Facility.
TSA
 
Transportation Services Agreement
TWCC
 
Texas Westmoreland Coal Co.
U.S.
 
United States of America
U.S. DOE
 
U.S. Department of Energy
Utility Scale Solar
 
Solar power projects, typically 20 MW or greater in size (on an alternating current basis), that are interconnected into the transmission or distribution grid to sell power at a wholesale level
VaR
 
Value at Risk
VIE
 
Variable Interest Entity

8



Walnut Creek
 
NRG Walnut Creek, LLC, the operating subsidiary of WCEP Holdings, LLC, which owns the Walnut Creek project
WST
 
Washington-St. Tammany Electric Cooperative, Inc.

9



PART I — FINANCIAL INFORMATION
ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
 
Three months ended September 30,
 
Nine months ended September 30,
(In millions, except for per share amounts)
2017
 
2016
 
2017
 
2016
Operating Revenues

 

 
 
 
 
Total operating revenues
$
3,049


$
3,421


$
8,132


$
8,328

Operating Costs and Expenses







Cost of operations
2,156


2,440


5,852


5,711

Depreciation and amortization
272


298


789


826

Impairment losses
14


9


77


65

Selling, general and administrative
213


277


697


801

Reorganization
18




18



Development activity expenses
14


21


49


65

Total operating costs and expenses
2,687


3,045


7,482


7,468

   Other income - affiliate
14


48


104


144

   Gain/(loss) on sale of assets


4


4


(79
)
Operating Income
376


428


758


925

Other Income/(Expense)







Equity in earnings of unconsolidated affiliates
27


16


29


13

Impairment loss on investment


(8
)



(147
)
Other income, net
15


7


33


29

Loss on debt extinguishment, net
(1
)

(50
)

(3
)

(119
)
Interest expense
(221
)

(237
)

(692
)

(718
)
Total other expense
(180
)

(272
)

(633
)

(942
)
Income/(Loss) from Continuing Operations Before Income Taxes
196


156


125


(17
)
Income tax expense
6


28


5


75

Income/(Loss) from Continuing Operations
190


128


120


(92
)
(Loss)/Income from discontinued operations, net of income tax
(27
)

265


(802
)

256

Net Income/(Loss)
163


393


(682
)

164

Less: Net loss attributable to noncontrolling interest and redeemable noncontrolling interests
(8
)

(9
)

(63
)

(49
)
Net Income/(Loss) Attributable to NRG Energy, Inc.
171


402


(619
)

213

Dividends for preferred shares






5

Gain on redemption of preferred shares






(78
)
Net Income/(Loss) Available for Common Stockholders
$
171


$
402


$
(619
)

$
286

Income/(Loss) per Share Attributable to NRG Energy, Inc. Common Stockholders







Weighted average number of common shares outstanding — basic
317


316


317


315

Income from continuing operations per weighted average common share — basic
$
0.63


$
0.43


$
0.58


$
0.10

(Loss)/Income from discontinued operations per weighted average common share — basic
$
(0.09
)

$
0.84


$
(2.53
)

$
0.81

Income/(Loss) per Weighted Average Common Share — Basic
$
0.54


$
1.27


$
(1.95
)

$
0.91

Weighted average number of common shares outstanding — diluted
322


317


317


316

Income from continuing operations per weighted average common share — diluted
$
0.61


$
0.43


$
0.58


$
0.10

(Loss)/Income from discontinued operations per weighted average common share — diluted
$
(0.08
)

$
0.84


$
(2.53
)

$
0.81

Income/(Loss) per Weighted Average Common Share — Diluted
$
0.53


$
1.27


$
(1.95
)

$
0.91

Dividends Per Common Share
$
0.03


$
0.03


$
0.09


$
0.21

See accompanying notes to condensed consolidated financial statements.

10




NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)
(Unaudited)
 
Three months ended September 30,
 
Nine months ended September 30,
 
2017
 
2016
 
2017
 
2016
 
(In millions)
Net income/(loss)
$
163

 
$
393

 
$
(682
)

$
164

Other comprehensive income/(loss), net of tax

 

 



Unrealized gain/(loss) on derivatives, net of income tax (benefit)/expense of $0, $(1), $1, and $1
7


27


6


(8
)
Foreign currency translation adjustments, net of income tax expense of $0, $0, $0, and $0
2


3


10


6

Available-for-sale securities, net of income tax expense of $0, $0, $0, and $0
1




2


1

Defined benefit plans, net of income tax expense of $0, $0, $0, and $0
(1
)

31


26


32

Other comprehensive income
9


61


44


31

Comprehensive income/(loss)
172


454


(638
)

195

Less: Comprehensive loss attributable to noncontrolling interest and redeemable noncontrolling interests
(5
)

(2
)

(61
)

(70
)
Comprehensive income/(loss) attributable to NRG Energy, Inc.
177


456


(577
)

265

Dividends for preferred shares






5

Gain on redemption of preferred shares

 

 


(78
)
Comprehensive income/(loss) available for common stockholders
$
177


$
456


$
(577
)

$
338

See accompanying notes to condensed consolidated financial statements.

11





NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
 
September 30, 2017
 
December 31, 2016
(In millions, except shares)
 
 
 
ASSETS
 
 
 
Current Assets
 
 
 
Cash and cash equivalents
$
1,223


$
938

Funds deposited by counterparties
31


2

Restricted cash
537


446

Accounts receivable, net
1,274


1,058

Inventory
630


721

Derivative instruments
475


1,067

Cash collateral posted in support of energy risk management activities
203


150

Current assets - held for sale
33


9

Prepayments and other current assets
354


404

Current assets - discontinued operations


1,919

Total current assets
4,760


6,714

Property, plant and equipment, net
15,332


15,369

Other Assets
 

 
Equity investments in affiliates
1,138


1,120

Notes receivable, less current portion
5


16

Goodwill
662


662

 Intangible assets, net
1,838


1,973

Nuclear decommissioning trust fund
670


610

Derivative instruments
206


181

Deferred income taxes
205


225

Non-current assets held-for-sale
10


10

Other non-current assets
644


841

Non-current assets - discontinued operations


2,961

Total other assets
5,378


8,599

Total Assets
$
25,470


$
30,682

LIABILITIES AND STOCKHOLDERS’ EQUITY
 

 
Current Liabilities
 

 
Current portion of long-term debt and capital leases
$
1,247


$
516

Accounts payable
911


813

Derivative instruments
522


1,092

Cash collateral received in support of energy risk management activities
31


81

Accrued expenses and other current liabilities
830


990

Accrued expenses and other current liabilities - affiliate
164



Current liabilities - discontinued operations


1,210

Total current liabilities
3,705


4,702

Other Liabilities
 

 
Long-term debt and capital leases
15,658


15,957

Nuclear decommissioning reserve
265


287

Nuclear decommissioning trust liability
397


339

Deferred income taxes
21


20

Derivative instruments
307


284

Out-of-market contracts, net
213


230

Non-current liabilities held-for-sale
13


11

Other non-current liabilities
1,116


1,176

Non-current liabilities - discontinued operations


3,184

Total non-current liabilities
17,990


21,488

Total Liabilities
21,695


26,190

Redeemable noncontrolling interest in subsidiaries
85


46

Commitments and Contingencies





Stockholders’ Equity



Common stock
4


4

Additional paid-in capital
8,369


8,358

Retained deficit
(4,713
)

(3,787
)
Less treasury stock, at cost — 101,580,045 and 102,140,814 shares, respectively
(2,386
)

(2,399
)
Accumulated other comprehensive loss
(91
)

(135
)
Noncontrolling interest
2,507


2,405

Total Stockholders’ Equity
3,690


4,446

Total Liabilities and Stockholders’ Equity
$
25,470


$
30,682

See accompanying notes to condensed consolidated financial statements.

12



NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
Nine months ended September 30,
(In millions)
2017
 
2016
Cash Flows from Operating Activities
 
 
 
Net (loss)/income
$
(682
)

$
164

(Loss)/Income from discontinued operations, net of income tax
(802
)

256

Income/(loss) from continuing operations
120


(92
)
Adjustments to reconcile net (loss)/income to net cash provided by operating activities:



Distributions and equity in earnings of unconsolidated affiliates
24


44

Depreciation and amortization
789


826

Provision for bad debts
57


36

Amortization of nuclear fuel
37


39

Amortization of financing costs and debt discount/premiums
44


42

Adjustment for debt extinguishment
3


119

Amortization of intangibles and out-of-market contracts
79


131

Amortization of unearned equity compensation
27


23

Impairment losses
77


211

Changes in deferred income taxes and liability for uncertain tax benefits
26


29

Changes in nuclear decommissioning trust liability
20


24

Changes in derivative instruments
25


30

Changes in collateral posted in support of risk management activities
(103
)

261

Proceeds from sale of emission allowances
21


11

(Gain)/loss on sale of assets
(22
)

70

Changes in other working capital
(380
)

(130
)
Cash provided by continuing operations
844


1,674

Cash (used)/provided by discontinued operations
(38
)

67

Net Cash Provided by Operating Activities
806


1,741

Cash Flows from Investing Activities
 

 
Acquisitions of businesses, net of cash acquired
(36
)

(18
)
Capital expenditures
(760
)

(659
)
Decrease in notes receivable
11


2

Purchases of emission allowances
(47
)

(32
)
Proceeds from sale of emission allowances
105


47

Investments in nuclear decommissioning trust fund securities
(402
)

(378
)
Proceeds from the sale of nuclear decommissioning trust fund securities
382


354

Proceeds from renewable energy grants and state rebates
8


11

Proceeds from sale of assets, net of cash disposed of
36


84

Investments in unconsolidated affiliates
(31
)

(23
)
Other
22


31

Cash used by continuing operations
(712
)

(581
)
Cash (used)/provided by discontinued operations
(53
)

326

Net Cash Used by Investing Activities
(765
)

(255
)
Cash Flows from Financing Activities
 

 
Payment of dividends to common and preferred stockholders
(28
)

(66
)
Payment for preferred shares


(226
)
Net receipts from settlement of acquired derivatives that include financing elements
2


6

Proceeds from issuance of long-term debt
1,134


5,237

Payments for short and long-term debt
(712
)

(5,353
)
Receivable from affiliate
(125
)


Payments for debt extinguishment costs


(98
)
Contributions from, net of distributions to, noncontrolling interest in subsidiaries
65


(127
)
Proceeds from issuance of stock


1

Payment of debt issuance costs
(43
)

(70
)
Other - contingent consideration
(10
)

(10
)
Cash provided/(used) by continuing operations
283


(706
)
Cash (used)/provided by discontinued operations
(224
)

119

Net Cash provided/(used) by Financing Activities
59


(587
)
Effect of exchange rate changes on cash and cash equivalents
(10
)

(6
)
Change in Cash from discontinued operations
(315
)

512

Net Increase in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash
405


381

Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period
1,386


1,322

Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period
$
1,791


$
1,703

See accompanying notes to condensed consolidated financial statements.

13



NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1Basis of Presentation
NRG Energy, Inc., or NRG or the Company, is a leading integrated power company built on the strength of a diverse competitive electric generation portfolio and leading retail electricity platform. NRG is continuously focused on excellence in operating performance of its existing assets and optimal hedging of generation assets and retail load operations, as well as serving the energy needs of end-use residential, commercial and industrial customers in competitive markets through multiple brands and channels. The Company owns and operates approximately 30,000 MW of generation; engages in the trading of wholesale energy, capacity and related products; transacts in and trades fuel and transportation services; and directly sells energy, services, and innovative, sustainable products and services to retail customers under the names “NRG”, "Reliant" and other retail brand names owned by NRG.
The accompanying unaudited interim condensed consolidated financial statements have been prepared in accordance with the SEC's regulations for interim financial information and with the instructions to Form 10-Q. Accordingly, they do not include all of the information and notes required by generally accepted accounting principles for complete financial statements. The following notes should be read in conjunction with the accounting policies and other disclosures as set forth in the notes to the consolidated financial statements in the Company's 2016 Form 10-K. Interim results are not necessarily indicative of results for a full year.
In the opinion of management, the accompanying unaudited interim condensed consolidated financial statements contain all material adjustments consisting of normal and recurring accruals necessary to present fairly the Company's consolidated financial position as of September 30, 2017, and the results of operations, comprehensive income/(loss) and cash flows for the three and nine months ended September 30, 2017 and 2016.
GenOn Chapter 11 Cases
On June 14, 2017, or the Petition Date, GenOn, along with GenOn Americas Generation and certain of their directly and indirectly-owned subsidiaries, or collectively the GenOn Entities, filed voluntary petitions for relief under Chapter 11, or the Chapter 11 Cases, of the U.S. Bankruptcy Code, or the Bankruptcy Code, in the U.S. Bankruptcy Court for the Southern District of Texas, Houston Division, or the Bankruptcy Court. GenOn Mid-Atlantic, as well as its consolidated subsidiaries, REMA and certain other subsidiaries, did not file for relief under Chapter 11.

As a result of the bankruptcy filings and beginning on June 14, 2017, GenOn and its subsidiaries were deconsolidated from NRG’s consolidated financial statements. NRG recorded its investment in GenOn under the cost method with an estimated fair value of zero. NRG determined that this disposal of GenOn and its subsidiaries is a discontinued operation; and, accordingly, the financial information for all historical periods have been recast to reflect GenOn as a discontinued operation. In connection with the disposal, NRG recorded a loss on deconsolidation of $208 million during the quarter ended June 30, 2017. See Note 3, Discontinued Operations, Dispositions and Acquisitions, for more information.

Prior to the GenOn Entities' filing the Chapter 11 Cases, on June 12, 2017, NRG entered into a restructuring support and lock-up agreement, or the Restructuring Support Agreement, with the GenOn Entities and certain holders of the GenOn and GenOn Americas Generation Senior Notes, that provides for a restructuring and recapitalization of the GenOn Entities through a prearranged plan of reorganization. The RSA was amended on October 2, 2017 to remove the requirement to conduct a rights offering in connection with the exit financing. There is no assurance that the GenOn Entities' plan will be approved by the requisite stakeholders, confirmed by the Bankruptcy Court, or successfully implemented thereafter. The principal terms of the Restructuring Support Agreement are described further in Note 3, Discontinued Operations, Dispositions and Acquisitions.

As announced on October 31, 2017, NRG and GenOn engaged in arms-length discussions to settle certain items related to the pre-petition Restructuring Support Agreement, including key topics such as: (i) timeline and transition; (ii) cooperation and co-development matters; (iii) post-employment and retiree health and welfare benefits and pension benefits; (iv) tax matters; and (v) intercompany balances. The agreements reached on these topics are expected to be incorporated into definitive documents for GenOn’s emergence from Chapter 11.


14



Forms of definitive documents were filed with the Bankruptcy Court by the GenOn Entities; however, such definitive documents are subject to ongoing review, revision, and further negotiation by the parties to the Restructuring Support Agreement, including NRG, who have various consent rights over the final form of the plan supplement documents, and may be amended, modified, supplemented, and revised in accordance with those ongoing negotiations.

Transformation Plan
On July 12, 2017, NRG announced its Transformation Plan designed to significantly strengthen earnings and cost competitiveness, lower risk and volatility, and create significant shareholder value. The three-part, three-year plan is comprised of the following targets:
Operations and cost excellence — Cost savings and margin enhancement of $1,065 million recurring, which consists of $590 million of annual cost savings, a $215 million net margin enhancement program, $50 million annual reduction in maintenance capital expenditures, and $210 million in permanent selling, general and administrative expense reduction associated with asset sales.
Portfolio optimization — Targeting up to $4.0 billion of asset sale net cash proceeds, including divestitures of 6 GWs of conventional generation and businesses (excluding GenOn) and the expected monetization of 100% of its interest in NRG Yield, Inc. and its renewables platform.

Capital structure and allocation enhancements — A prioritized capital allocation strategy that targets a reduction in consolidated debt from approximately $19.5 billion ($18 billion net debt) to approximately $6.5 billion ($6 billion net debt). Following the completion of the contemplated asset sales, the Company expects $4.8-$6.3 billion in excess cash to be available for allocation through 2020, after achieving its targeted 3.0x net debt / Adjusted EBITDA corporate credit ratio.

The Company expects to fully implement the Transformation Plan by the end of 2020 with significant completion by the end of 2018. The Company expects to realize (i) $370 million of non-recurring working capital improvements through 2020 and (ii) approximately $290 million, one-time costs to achieve.

Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.
Reclassifications
Certain prior year amounts have been reclassified for comparative purposes. The reclassifications did not affect results from operations, net assets or cash flows.
Note 2Summary of Significant Accounting Policies
Other Balance Sheet Information
The following table presents the allowance for doubtful accounts included in accounts receivable, net; accumulated depreciation included in property, plant and equipment, net; accumulated amortization included in intangible assets, net and accumulated amortization included in out-of-market contracts, net:
 
September 30, 2017
 
December 31, 2016
 
(In millions)
Accounts receivable allowance for doubtful accounts
$
61

 
$
29

Property, plant and equipment accumulated depreciation
6,437

 
5,711

Intangible assets accumulated amortization
1,750

 
1,687

Out-of-market contracts accumulated amortization
352

 
457


15



Restricted Cash
The following table provides a reconciliation of cash and cash equivalents, restricted cash and funds deposited by counterparties reported within the consolidated balance sheet that sum to the total of the same such amounts shown in the statement of cash flows.
 
September 30, 2017
 
December 31, 2016
 
September 30, 2016
 
December 31, 2015
           
(In millions)
Cash and cash equivalents
$
1,223

 
$
938

 
$
1,217

 
$
853

Funds deposited by counterparties
31

 
2

 
6

 
55

Restricted cash
537

 
446

 
480

 
414

Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows
$
1,791

 
$
1,386

 
$
1,703

 
$
1,322

Funds deposited by counterparties consist of cash held by the Company as a result of collateral posting obligations from its counterparties. Some amounts are segregated into separate accounts that are not contractually restricted but, based on the Company's intention, are not available for the payment of general corporate obligations. Depending on market fluctuations and the settlement of the underlying contracts, the Company will refund this collateral to the hedge counterparties pursuant to the terms and conditions of the underlying trades. Since collateral requirements fluctuate daily and the Company cannot predict if any collateral will be held for more than twelve months, the funds deposited by counterparties are classified as a current asset on the Company's balance sheet, with an offsetting liability for this cash collateral received within current liabilities. As of December 31, 2016, $79 million of the cash collateral received was from GenOn, previously a consolidated subsidiary, and is included in cash collateral received in current liabilities as a result of deconsolidating GenOn, with the offset included in cash and cash equivalents.
Restricted cash consists primarily of funds held to satisfy the requirements of certain debt agreements and funds held within the Company's projects that are restricted in their use.
Noncontrolling Interest
The following table reflects the changes in NRG's noncontrolling interest balance:
 
(In millions)
Balance as of December 31, 2016
$
2,405

Contributions from noncontrolling interest
116

Non-cash adjustments to noncontrolling interest
98

Sale of assets to NRG Yield, Inc.
24

Comprehensive loss attributable to noncontrolling interest
(8
)
Dividends paid to NRG Yield, Inc. public shareholders
(80
)
Distributions to noncontrolling interest
(48
)
Balance as of September 30, 2017
$
2,507


Redeemable Noncontrolling Interest
The following table reflects the changes in the Company's redeemable noncontrolling interest balance:
 
(In millions)
Balance as of December 31, 2016
$
46

Contributions from redeemable noncontrolling interest
73

Non-cash adjustments to noncontrolling interest
21

Comprehensive loss attributable to redeemable noncontrolling interest
(53
)
Distributions to redeemable noncontrolling interest
(2
)
Balance as of September 30, 2017
$
85



16



Recent Accounting Developments - Guidance Adopted in 2017
ASU 2016-18 — In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230), Restricted Cash, or ASU No. 2016-18. The amendments of ASU No. 2016-18 require an entity to include amounts generally described as restricted cash and restricted cash equivalents, including funds deposited by counterparties with cash and cash equivalents when reconciling the beginning of period and end of period total amounts on the statement of cash flows. The amendments of ASU No. 2016-18 are effective for annual reporting periods beginning after December 15, 2017, and interim periods within those annual periods. Early adoption is permitted and the adoption of ASU No. 2016-18 will be applied retrospectively. The Company adopted the guidance in ASU No. 2016-18 during the second quarter of 2017. In connection with the adoption of the standard, the Company has applied the guidance retrospectively which resulted in a decrease in cash flows from operations of $49 million and an increase in cash flows from investing of $66 million on the statement of cash flows for the nine months ended September 30, 2016.
ASU 2016-16 — In October 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740), Intra-Entity Transfers of Assets Other Than Inventory, or ASU No. 2016-16.  Current GAAP prohibits the recognition of current and deferred income taxes for an intra-entity asset transfer until the asset has been sold to an outside party which has resulted in diversity in practice and increased complexity within financial reporting.  The amendments of ASU No. 2016-16 would require an entity to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs.  The Company adopted the guidance in ASU No. 2016-16 effective January 1, 2017. In connection with the adoption of the standard, the Company recorded a reduction to non-current assets of $267 million with a corresponding reduction to cumulative retained deficit. 
ASU 2016-15 — In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments, or ASU No. 2016-15. The amendments of ASU No. 2016-15 were issued to address eight specific cash flow issues for which stakeholders have indicated to the FASB that a diversity in practice existed in how entities were presenting and classifying these items in the statement of cash flows. The issues addressed by ASU No. 2016-15 include but are not limited to the classification of debt prepayment and debt extinguishment costs, payments made for contingent consideration for a business combination, proceeds from the settlement of insurance proceeds, distributions received from equity method investees and separately identifiable cash flows and the application of the predominance principle. The Company adopted the guidance in ASU No. 2016-15 effective January 1, 2017. In connection with the adoption of the standard, the Company has applied the guidance retrospectively which resulted in an increase in cash flows from operations of $98 million and a decrease in cash flows from financing of $98 million on the statement of cash flows for the nine months ended September 30, 2016.
ASU 2016-09 — In March 2016, the FASB issued ASU No. 2016-09, Compensation - Stock Compensation (Topic 718), or ASU No. 2016-09. The amendments focused on simplification specifically with regard to share-based payment transactions, including income tax consequences, classification of awards as equity or liabilities and classification on the statement of cash flows. The Company adopted the guidance in ASU No. 2016-09 effective January 1, 2017 with no material adjustments recorded to the consolidated balance sheet.
Recent Accounting Developments - Guidance Not Yet Adopted
ASU 2017-12 — In August 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815), Targeted Improvements to Accounting for Hedging Activities, or ASU No. 2017-12. The amendments of ASU No. 2017-12 were issued to simplify the application of hedge accounting guidance and more closely align financial reporting for hedging relationships with economic results of an entity's risk management activities. The issues addressed by ASU No. 2017-12 include but are not limited to alignment of risk management activities and financial reporting, risk component hedging, accounting for the hedged item in fair value hedges of interest rate risk, recognition and presentation of the effects of hedging instruments, amounts excluded from the assessment of hedge effectiveness, and other simplifications of hedge accounting guidance. The amendments of ASU No. 2017-12 are effective for fiscal years beginning after December 15, 2018, and interim periods therein.  Early adoption is permitted in any interim period and the effect of the adoption should be reflected as of the beginning of the fiscal year of adoption. The Company does not expect the adoption of ASU No. 2017-12 will have a material impact on its consolidated results of operations, cash flows, and statement of financial position.

17



ASU 2017-07 — In March 2017, the FASB issued ASU No. 2017-07, Compensation - Retirement Benefits (Topic 715), Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, or ASU No. 2017-07.   Current GAAP does not indicate where the amount of net benefit cost should be presented in an entity’s income statement and does not require entities to disclose the amount of net benefit cost that is included in the income statement.  The amendments of ASU No. 2017-07 require an entity to report the service cost component of net benefit costs in the same line item as other compensation costs arising from services rendered by the related employees during the applicable service period.  The other components of net benefit cost are required to be presented separately from the service cost component and outside the subtotal of income from operations. Further, ASU No. 2017-07 prescribes that only the service cost component of net benefit costs is eligible for capitalization. The amendments of ASU No. 2017-07 are effective for fiscal years beginning after December 15, 2017, including interim periods therein.  Early adoption is permitted and must be applied on a retrospective basis, except for the amendments regarding the capitalization of the service cost component, which must be applied prospectively. The Company is currently assessing the impact that the adoption of ASU No. 2017-07 will have on its results of operations, cash flows, and statement of financial position.
ASU 2016-02 — In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), or Topic 842, with the objective to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and to improve financial reporting by expanding the related disclosures. The guidance in Topic 842 provides that a lessee that may have previously accounted for a lease as an operating lease under current GAAP should recognize the assets and liabilities that arise from a lease on the balance sheet. In addition, Topic 842 expands the required quantitative and qualitative disclosures with regards to lease arrangements. The Company expects to adopt the standard effective January 1, 2019 utilizing the required modified retrospective approach for the earliest period presented. The Company expects to elect certain of the practical expedients permitted, including the expedient that permits the Company to retain its existing lease assessment and classification. The Company is currently working through an adoption plan which includes the evaluation of lease contracts compared to the new standard. While the Company is currently evaluating the impact the new guidance will have on its financial position and results of operations, the Company expects to recognize lease liabilities and right of use assets. The extent of the increase to assets and liabilities associated with these amounts remains to be determined pending the Company’s review of its existing lease contracts and service contracts which may contain embedded leases. While this review is still in process, NRG believes the adoption of Topic 842 will have a material impact on its financial statements.
ASU 2014-09 — In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), or Topic 606, which was further amended through various updates issued by the FASB thereafter. The amendments of Topic 606 completed the joint effort between the FASB and the IASB, to develop a common revenue standard for GAAP and IFRS, and to improve financial reporting. The guidance under Topic 606 provides that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for the goods or services provided and establishes a five step model to be applied by an entity in evaluating its contracts with customers. The Company expects to adopt the standard effective January 1, 2018 and apply the guidance retrospectively to contracts at the date of adoption. The Company will recognize the cumulative effect of applying Topic 606 at the date of initial application, as prescribed under the modified retrospective transition method. The Company also expects to elect the practical expedient available under Topic 606 for measuring progress toward complete satisfaction of a performance obligation and for disclosure requirements of remaining performance obligations. The practical expedient allows an entity to recognize revenue in the amount to which the entity has the right to invoice such that the entity has a right to the consideration in an amount that corresponds directly with the value to the customer for performance completed to date by the entity. The Company continues to assess the new standard with a focus on identifying the performance obligations included within its revenue arrangements with customers and evaluating the Company’s methods of estimating the amount and timing of variable consideration. While the impact remains subject to continued review, the Company does not believe the adoption of Topic 606 will have a material impact on its financial statements.

18



Note 3Discontinued Operations, Dispositions and Acquisitions
Discontinued Operations
As described in Note 1, Basis of Presentation, on the Petition Date, the GenOn Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. As a result of the bankruptcy filings, NRG concluded that it no longer controls GenOn as it is subject to the control of the Bankruptcy Court; and, accordingly, NRG no longer consolidates GenOn for financial reporting purposes.
By eliminating a large portion of its operations in the PJM market with the deconsolidation of GenOn, NRG concluded that GenOn meets the criteria for discontinued operations, as this represents a strategic shift in the markets in which NRG operates. As such, all prior period results for GenOn have been reclassified as discontinued operations while NRG will record all ongoing results of GenOn as a cost method investment, which was valued at zero at the date of deconsolidation.
Summarized results of discontinued operations were as follows:
 
Three months ended September 30, 2017 (a)
 
Three months ended September 30, 2016
 
Nine months ended September 30, 2017 (a)
 
Nine months ended September 30, 2016
(In millions)
 
 
 
Operating revenues
$

 
$
532

 
$
646

 
$
1,509

Operating costs and expenses

 
(468
)
 
(700
)
 
(1,409
)
Gain on sale of assets

 
262

 

 
294

Other expenses

 
(43
)
 
(98
)
 
(127
)
(Loss)/Income from operations of discontinued components, before tax

 
283

 
(152
)
 
267

Income tax expense

 
21

 
9

 
20

(Loss)/Incomes from operations of discontinued components

 
262

 
(161
)
 
247

Interest income - affiliate

 
3

 
6

 
9

(Loss)/Income from operations of discontinued components, net of tax

 
265

 
(155
)
 
256

Pre-tax loss on deconsolidation

 

 
(208
)
 

Settlement consideration and services credit

 

 
(289
)
 

Pension and post-retirement liability assumption(b)
(25
)
 

 
(144
)
 

Other
(2
)
 

 
(6
)
 

Loss on disposal of discontinued components, net of tax
(27
)
 

 
(647
)
 

(Loss)/Income from discontinued operations, net of tax
$
(27
)
 
$
265

 
$
(802
)
 
$
256

(a) As of June 14, 2017, NRG no longer consolidates GenOn for financial reporting purposes.
(b) See Note 1, Basis of Presentation, for further discussion regarding the October 30, 2017 proposed changes to the Restructuring Support Agreement. As part of this, NRG recorded the liability for GenOn’s post-employment and retiree health and welfare benefits, in an amount up to $25 million with a corresponding loss on discontinued operations during the third quarter of 2017.

19



The following table summarizes the major classes of assets and liabilities classified as discontinued operations as of December 31, 2016. As of June 14, 2017, NRG no longer consolidates GenOn for financial reporting purposes.
(In millions)
 
December 31, 2016
Cash and cash equivalents
 
$
1,034

Other current assets
 
885

Current assets - discontinued operations
 
1,919

Property, plant and equipment, net
 
2,543

Other non-current assets
 
418

Non-current assets - discontinued operations
 
2,961

Current portion of long term debt and capital leases
 
704

Other current liabilities
 
506

Current liabilities - discontinued operations
 
1,210

Long-term debt and capital leases
 
2,050

Out-of-market contracts
 
811

Other non-current liabilities
 
323

Non-current liabilities - discontinued operations
 
$
3,184

Restructuring Support Agreement
As described in Note 1, Basis of Presentation, NRG, GenOn and certain holders representing greater than 93% in aggregate principal amount of GenOn’s Senior Notes and certain holders representing greater than 93% in aggregate principal amount of GenOn Americas Generation’s Senior Notes entered into a Restructuring Support Agreement that provides for a restructuring and recapitalization of the GenOn Entities through a prearranged plan of reorganization. Completion of the agreed upon terms is contingent upon certain milestones in the Restructuring Support Agreement. Certain principal terms of the Restructuring Support Agreement are detailed below:
1)
Full releases from GenOn and GenOn Americas Generation in favor of NRG, including either a full release or indemnification in favor of NRG for any claims relating to GenOn Mid-Atlantic or REMA and the dismissal of all litigation against NRG.
2)
NRG will provide settlement cash consideration to GenOn of $261.3 million, which will be paid in cash less any amounts owed to NRG under the intercompany secured revolving credit facility. As of September 30, 2017, GenOn owed NRG approximately $125 million under the intercompany secured revolving credit facility. See Note 14, Related Party Transactions, for further discussion of the intercompany secured revolving credit facility.
3)
NRG will consent to the cancellation of its interests in the equity of GenOn. The equity interests in the reorganized GenOn will be issued to the holders of the GenOn Senior Notes.
4)
NRG will retain the pension liability, including payment of approximately $13 million of 2017 pension contributions, for GenOn employees for service provided prior to the completion of the reorganization, which was paid in September 2017. GenOn’s pension liability as of September 30, 2017 was approximately $106 million.
5)
The shared services agreement between NRG and GenOn will be amended such that (i) NRG will provide shared services to GenOn at an annualized rate of $84 million during the pendency of the Chapter 11 Cases, (ii) if the settlement is approved by the bankruptcy court, NRG will provide shared services to GenOn at no charge for two months, and (iii) NRG will then provide an option for up to two, one-month extensions for shared services at an annualized rate of $84 million. See Note 14, Related Party Transactions, for further discussion of the shared services agreement.
6)
NRG will provide a credit of $28 million to GenOn to apply against amounts owed under the shared services agreement upon emergence from bankruptcy. Any unused amount can be paid in cash at GenOn’s request. The credit was intended to reimburse GenOn for its payment of financing costs.
7)
NRG agreed to provide GenOn with a letter of credit facility during the pendency of the Chapter 11 Cases, which could be utilized for required letters of credit in lieu of the intercompany secured revolving credit facility. GenOn can no longer utilize the intercompany secured revolving credit facility and, on July 27, 2017, the letter of credit facility was terminated, as GenOn had obtained a separate letter of credit facility with a third party financial institution. See Note 14, Related Party Transactions, for further discussion of the intercompany secured revolver credit facility and the letter of credit facility obtained in July 2017.
8)
NRG and GenOn have agreed to cooperate in good faith to maximize the value of certain development projects.

20



In addition to the Restructuring Support Agreement, additional support and other agreements are being negotiated, including a transition services agreement. See Note 1, Basis of Presentation, for further discussion regarding the October 30, 2017 proposed changes to the Restructuring Support Agreement.
Settlement Consideration    
NRG has determined that the payment of the settlement consideration is probable and has recorded a liability for the amount due of $261.3 million in accrued expenses and other current liabilities - affiliate with a corresponding loss from discontinued operations. NRG expects to pay this amount net of amounts due from GenOn under the intercompany secured revolving credit facility, which is further described in Note 14, Related Party Transactions.
Pension Liability
NRG will retain the pension liability, including payment of approximately $13 million of 2017 pension contributions, which was paid in September 2017, for the GenOn employees for service provided prior to emergence from bankruptcy. NRG determined that the retention of this liability is probable and has recorded the estimated accumulated pension benefit obligation as of September 30, 2017 of $106 million in other non-current liabilities with a corresponding loss from discontinued operations. NRG's obligation for this liability will be revalued through and at GenOn's emergence from bankruptcy.
Services Agreement
NRG will continue to provide shared services to GenOn under the Services Agreement at an annualized rate of $84 million during the pendency of the Chapter 11 Cases as well as for two months post-emergence at no charge. NRG then will provide an option for up to two, one-month extensions for shared services at an annualized rate of $84 million. Beginning on June 14, 2017, NRG records operating income for the amounts earned for shared services of approximately $5 million per month. NRG has also agreed to provide GenOn with a credit of $28 million against amounts owed under the Services Agreement. Any unused amount can be paid in cash at GenOn’s request. As a result, NRG has concluded that the liability for this credit is probable and has recorded a payable to GenOn for $28 million in accrued expenses and other current liabilities - affiliate with a corresponding loss from discontinued operations. See Note 1, Basis of Presentation, for further discussion regarding the October 30, 2017 proposed changes to the Restructuring Support Agreement and Services Agreement.
Commercial Operations
For pre-disposal periods, NRG provided GenOn with services as described in Note 14, Related Party Transactions. Under intercompany agreements, NRG Power Marketing LLC has entered into physical and financial intercompany commodity and hedging transactions with GenOn and certain of its subsidiaries. Subject to applicable collateral thresholds, these arrangements may provide for the bilateral exchange of credit support based upon market exposure and potential market movements. The terms and conditions of the agreements are generally consistent with industry practices and other third party arrangements. For current and pre-disposal periods, revenue and expense associated with these transactions is recorded in continuing operations.
GenOn Debt
As of June 14, 2017, the GenOn Senior Notes and GenOn Americas Generation Senior Notes, which totaled approximately $2.5 billion, were deconsolidated from NRG's consolidated financial statements. The filing of the Chapter 11 Cases constitutes an event of default under the following debt instruments of GenOn:
1)
The intercompany secured revolving credit facility with NRG;
2)
The indenture governing the GenOn 7.875% Senior Notes due 2017 (as amended or supplemented from time to time);
3)
The indenture governing the GenOn 9.500% Notes due 2018 (as amended or supplemented from time to time);
4)
The indenture governing the GenOn 9.875% Notes due 2020 (as amended or supplemented from time to time);
5)
The indenture governing the GenOn Americas Generation 8.50% Senior Notes due 2021 (as amended or supplemented from time to time); and
6)
The indenture governing the GenOn Americas Generation 9.125% Senior Notes due 2031 (as amended or supplemented from time to time).
Transfer of Assets Under Common Control
On November 1, 2017, NRG completed the sale of a 38 MW solar portfolio primarily comprised of assets from SPP funds, in addition to other projects developed by NRG, to NRG Yield, Inc. for cash consideration of $71 million, plus $3 million in working capital adjustments.
On August 1, 2017, NRG closed on the sale of its remaining 25% interest in NRG Wind TE Holdco, a portfolio of 12 wind projects, to NRG Yield, Inc. for total cash consideration of $44 million, including working capital adjustment of $3 million. The transaction also includes potential additional payments to NRG dependent upon actual energy prices for merchant periods beginning in 2027.

21



On March 27, 2017, the Company sold to NRG Yield, Inc.: (i) a 16% interest in the Agua Caliente solar project, representing ownership of approximately 46 net MW of capacity and (ii) NRG's interests in seven utility-scale solar projects located in Utah representing 265 net MW of capacity, which have reached commercial operations. NRG Yield, Inc. paid cash consideration of $130 million, plus $1 million in working capital adjustments, and assumed non-recourse debt of approximately $328 million.
On September 1, 2016, the Company completed the sale of its remaining 51.05% interest in the CVSR project to NRG Yield, Inc. for total cash consideration of $78.5 million, plus an immaterial working capital adjustment. In addition, NRG Yield, Inc. assumed non-recourse project level debt of $496 million.
Acquisitions
SunEdison Utility-Scale Solar and Wind Acquisition
On November 2, 2016, the Company acquired equity interests in a tax equity portfolio from SunEdison, located in Utah, comprised of 530 MW of mechanically-complete solar assets, of which NRG’s net interest based on cash to be distributed is 265 MW, for upfront cash consideration of $111 million. In connection with the acquisition, the Company assumed non-recourse debt of $222 million. The Company also borrowed additional amounts of $65 million during the fourth quarter of 2016, which effectively reduced the Company's use of liquidity related to the acquisition. The Company does not have a controlling interest in the tax equity portfolio and, accordingly, its interest is recorded as an equity method investment. The purchase price was preliminarily allocated to the equity method investment balance of approximately $328 million, current assets of $5 million and the assumed non-recourse debt of $222 million. The assets reached commercial operations during the fourth quarter of 2016 and have 20-year PPAs with PacificCorp.
The Company acquired a 110 MW portfolio of construction-ready and 71 MW of development solar assets in Hawaii from SunEdison for upfront cash consideration of $2 million on October 3, 2016 and a 154 MW construction-ready solar project in Texas for upfront cash consideration of $11 million on November 9, 2016.
In addition to the total $124 million in upfront cash consideration paid for the above acquisitions, the Company expects to make an estimated $59 million in additional payments contingent upon future development milestones, of which $15 million was paid as of September 30, 2017.
SunEdison Solar Distributed Generation Acquisition
On October 3, 2016, the Company acquired a 29 MW portfolio of mechanically-complete and construction-ready distributed generation solar assets from SunEdison for cash consideration of approximately $67 million excluding post-closing adjustments which reduced the purchase price by $5 million. Subsequent to the acquisition, the Company sold the majority of these assets into a tax-equity financed portfolio within the DGPV Holdco partnership between NRG and NRG Yield, Inc., and expects to sell the remaining assets into a similar portfolio in 2017. The purchase price was allocated to $47 million in construction in progress and $15 million in intangible assets.
Dispositions
Disposition of Majority Interest in EVgo
On June 17, 2016, the Company completed the sale of a majority interest in its EVgo business to Vision Ridge Partners for total consideration of approximately $39 million, including $17 million in cash received, which is net of $2.5 million in working capital adjustments, $15 million contributed as capital to the EVgo business and $7 million of future contributions by Vision Ridge Partners, all of which were determined based on forecasted cash requirements to operate the business in future periods. In addition, the Company has future earnout potential of up to $70 million based on future profitability targets. NRG will retain its original financial obligation of $102.5 million under its agreement with the CPUC whereby EVgo will build at least 200 public fast charging Freedom Station sites and perform the associated work to prepare 10,000 commercial and multi-family parking spaces for electric vehicle charging in California. As part of the sale, NRG has contracted with EVgo to continue to build the remaining required Freedom Stations and commercial and multi-family parking spaces for electric vehicle charging required under this obligation and will be directly reimbursed by NRG for the costs. As a result of the sale, the Company recorded a loss on sale of $83 million during the second quarter of 2016, which reflects the loss on the sale of the equity interest of $27 million and the accrual of NRG's remaining obligation under its agreement with the CPUC of $56 million. On February 22, 2017, the Company and CPUC entered into a second amendment to the agreement which extended the operating period commitment for the Freedom Stations to December 5, 2020. At September 30, 2017, the Company's remaining 35% interest in EVgo of $2 million was accounted for as an equity-method investment.

22



Rockford Disposition
On May 12, 2016, the Company entered into an agreement with RA Generation, LLC to sell 100% of its interests in the Rockford I and Rockford II generating stations, or Rockford, for cash consideration of $55 million, subject to adjustments for working capital and the results of the PJM 2019/2020 base residual auction. Rockford is a 450 MW natural gas facility located in Rockford, Illinois. The transaction triggered an indicator of impairment as the sales price was less than the carrying amount of the assets, and, as a result the assets were considered to be impaired. The Company measured the impairment loss as the difference between the carrying amount of the assets and the agreed-upon sales price. The Company recorded an impairment loss of $17 million during the quarter ended June 30, 2016 to reduce the carrying amount of the assets held for sale to the fair market value. At June 30, 2016, the Company had $2 million of current assets and $54 million of non-current assets classified as held for sale for Rockford on its balance sheet. On July 12, 2016, the Company completed the sale of Rockford for cash proceeds of $56 million, including $1 million in adjustments for the PJM base residual auction results. For further discussion on this impairment, refer to Note 7, Impairments, to this Form 10-Q.
Note 4Fair Value of Financial Instruments
This footnote should be read in conjunction with the complete description under Note 4, Fair Value of Financial Instruments, to the Company's 2016 Form 10-K.
For cash and cash equivalents, funds deposited by counterparties, accounts and other receivables, accounts payable, restricted cash, and cash collateral paid and received in support of energy risk management activities, the carrying amount approximates fair value because of the short-term maturity of those instruments and are classified as Level 1 within the fair value hierarchy.
The estimated carrying amounts and fair values of NRG's recorded financial instruments not carried at fair market value are as follows:
 
As of September 30, 2017
 
As of December 31, 2016
 
Carrying Amount
 
Fair Value
 
Carrying Amount
 
Fair Value
 
(In millions)
Assets:
 
 
 
 
 
 
 
Notes receivable (a)
$
22

 
$
21

 
$
34

 
$
34

Liabilities:
 
 
 
 
 
 
 
Long-term debt, including current portion (b)
17,097

 
17,423

 
16,655

 
16,620

(a) Includes the current portion of notes receivable which is recorded in prepayments and other current assets on the Company's consolidated balance sheets.
(b) Excludes deferred financing costs, which are recorded as a reduction to long-term debt on the Company's consolidated balance sheets.
The fair value of the Company's publicly-traded long-term debt is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. The fair value of debt securities, non-publicly traded long-term debt and certain notes receivable of the Company are based on expected future cash flows discounted at market interest rates, or current interest rates for similar instruments with equivalent credit quality and are classified as Level 3 within the fair value hierarchy. The following table presents the level within the fair value hierarchy for long-term debt, including current portion as of September 30, 2017 and December 31, 2016:
 
As of September 30, 2017
 
As of December 31, 2016
 
Level 2
 
Level 3
 
Level 2
 
Level 3
 
(In millions)
Long-term debt, including current portion
$
9,571

 
$
7,852

 
$
9,205

 
$
7,415



23



Recurring Fair Value Measurements
Debt securities, equity securities, and trust fund investments, which are comprised of various U.S. debt and equity securities, and derivative assets and liabilities, are carried at fair market value.
The following tables present assets and liabilities measured and recorded at fair value on the Company's condensed consolidated balance sheets on a recurring basis and their level within the fair value hierarchy:
 
As of September 30, 2017
 
Fair Value
(In millions)
Level 1
 
Level 2
 
Level 3
 
Total
Investment in available-for-sale securities (classified within other
    non-current assets):
 
 
 
 
 
 
 
Debt securities
$

 
$

 
$
19

 
$
19

Available-for-sale securities
5

 

 

 
5

Nuclear trust fund investments:
 
 
 
 
 
 
 
Cash and cash equivalents
31

 

 

 
31

U.S. government and federal agency obligations
43

 
1

 

 
44

Federal agency mortgage-backed securities

 
74

 

 
74

Commercial mortgage-backed securities

 
11

 

 
11

Corporate debt securities

 
108

 

 
108

Equity securities
333

 

 
65

 
398

Foreign government fixed income securities

 
4

 

 
4

Other trust fund investments:
 
 
 
 
 
 
 
U.S. government and federal agency obligations
1

 

 

 
1

Derivative assets:
 
 
 
 
 
 
 
Commodity contracts
132

 
409

 
98

 
639

Interest rate contracts

 
42

 

 
42

Total assets
$
545

 
$
649

 
$
182

 
$
1,376

Derivative liabilities:
 
 
 
 
 
 
 
Commodity contracts
201

 
404

 
146

 
751

Interest rate contracts

 
78

 

 
78

Total liabilities
$
201

 
$
482

 
$
146

 
$
829

.

24



 
As of December 31, 2016
 
Fair Value
(In millions)
Level 1
 
Level 2
 
Level 3
 
Total
Investment in available-for-sale securities (classified within other
non-current assets):
 
 
 
 
 
 
 
Debt securities
$

 
$

 
$
17

 
$
17

Available-for-sale securities
10

 

 

 
10

Nuclear trust fund investments:
 
 
 
 
 
 
 
Cash and cash equivalents
25

 

 

 
25

U.S. government and federal agency obligations
72

 
1

 

 
73

Federal agency mortgage-backed securities

 
62

 

 
62

Commercial mortgage-backed securities

 
17

 

 
17

Corporate debt securities

 
84

 

 
84

Equity securities
292

 

 
54

 
346

Foreign government fixed income securities

 
3

 

 
3

Other trust fund investments:
 
 
 
 
 
 
 
U.S. government and federal agency obligations
1

 

 

 
1

Derivative assets:
 
 
 
 
 
 
 
Commodity contracts
560

 
549

 
90

 
1,199

Interest rate contracts

 
49

 

 
49

Total assets
$
960

 
$
765

 
$
161

 
$
1,886

Derivative liabilities:
 
 
 
 
 
 
 
Commodity contracts
494

 
636

 
158

 
1,288

Interest rate contracts

 
88

 

 
88

Total liabilities
$
494

 
$
724

 
$
158

 
$
1,376


There were no transfers during the three and nine months ended September 30, 2017 and 2016 between Levels 1 and 2. The following tables reconcile, for the three and nine months ended September 30, 2017 and 2016, the beginning and ending balances for financial instruments that are recognized at fair value in the condensed consolidated financial statements, at least annually, using significant unobservable inputs:
 
Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
 
Three months ended September 30, 2017
 
Nine months ended September 30, 2017
(In millions)
Debt Securities
 
Trust Fund Investments
 
Derivatives(a)
 
Total
 
Debt Securities
 
Trust Fund Investments
 
Derivatives(a)
 
Total
Beginning balance
$
18

 
$
61

 
$
(11
)
 
$
68

 
$
17

 
$
54

 
$
(68
)
 
$
3

Total gains/(losses) — realized/unrealized:
 
 
 
 
 
 


 
 
 
 
 
 
 


Included in earnings
1

 

 
(28
)
 
(27
)
 
2

 

 
18

 
20

Included in nuclear decommissioning obligation

 
3

 

 
3

 

 
10

 

 
10

Purchases

 
1

 
(9
)
 
(8
)
 

 
1

 

 
1

Transfers into Level 3 (b)

 

 
(6
)
 
(6
)
 

 

 
(11
)
 
(11
)
Transfers out of Level 3 (b)

 

 
6

 
6

 

 

 
13

 
13

Ending balance as of September 30, 2017
$
19

 
$
65

 
$
(48
)
 
$
36

 
$
19

 
$
65

 
$
(48
)
 
$
36

Losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of September 30, 2017
$

 
$

 
$
(13
)
 
$
(13
)
 
$

 
$

 
$
(6
)
 
$
(6
)
(a)
Consists of derivative assets and liabilities, net.
(b)
Transfers into/out of Level 3 are related to the availability of external broker quotes and are valued as of the end of the reporting period. All transfers in/out are with Level 2.

25



 
Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
 
Three months ended September 30, 2016
 
Nine months ended September 30, 2016
(In millions)
Debt Securities
 
Trust Fund Investments
 
Derivatives(a)
 
Total
 
Debt Securities
 
Trust Fund Investments
 
Derivatives(a)
 
Total
Beginning balance
$
16

 
$
51

 
$
18

 
$
85

 
$
17

 
$
54

 
$
(22
)
 
$
49

Total (losses)/gains — realized/unrealized:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Included in earnings

 

 
(5
)
 
(5
)
 

 

 
4

 
4

Included in OCI
1

 

 

 
1

 

 

 

 

Included in nuclear decommissioning obligations

 
3

 

 
3

 

 
(1
)
 

 
(1
)
Purchases

 

 
(25
)
 
(25
)
 

 
1

 
2

 
3

Transfers into Level 3 (b)

 

 
(13
)
 
(13
)
 

 

 
(6
)
 
(6
)
Transfers out of Level 3 (b)

 

 
3

 
3

 

 

 

 

Ending balance as of September 30, 2016
$
17

 
$
54

 
$
(22
)
 
$
49

 
$
17

 
$
54

 
$
(22
)
 
$
49

Losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of September 30, 2016
$

 
$

 
$
(4
)
 
$
(4
)
 
$

 
$

 
$
(11
)
 
$
(11
)
(a)
Consists of derivative assets and liabilities, net.
(b)
Transfers into/out of Level 3 are related to the availability of external broker quotes and are valued as of the end of the reporting period. All transfers in/out are with Level 2.

Derivative Fair Value Measurements
A portion of NRG's contracts are exchange-traded contracts with readily available quoted market prices. A majority of NRG's contracts are non-exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter and on-line exchanges. The remainder of the assets and liabilities represent contracts for which external sources or observable market quotes are not available for the whole term or for certain delivery months or the contracts are retail and load following power contracts. These contracts are valued using various valuation techniques including but not limited to internal models that apply fundamental analysis of the market and corroboration with similar markets. As of September 30, 2017, contracts valued with prices provided by models and other valuation techniques make up 14% of the total derivative assets and 18% of the total derivative liabilities.
NRG's significant positions classified as Level 3 include physical and financial power executed in illiquid markets as well as financial transmission rights, or FTRs. The significant unobservable inputs used in developing fair value include illiquid power location pricing which is derived as a basis to liquid locations. The basis spread is based on observable market data when available or derived from historic prices and forward market prices from similar observable markets when not available. For FTRs, NRG uses the most recent auction prices to derive the fair value.











26



The following tables quantify the significant unobservable inputs used in developing the fair value of the Company's Level 3 positions as of September 30, 2017 and December 31, 2016:
 
Significant Unobservable Inputs
 
September 30, 2017
 
Fair Value
 
 
 
Input/Range
 
Assets
 
Liabilities
 
Valuation Technique
 
Significant Unobservable Input
 
Low
 
High
 
Weighted Average
 
(In millions)
 
 
 
 
 
 
 
 
 
 
Power Contracts
$
47

 
$
101

 
Discounted Cash Flow
 
Forward Market Price (per MWh)
 
$
10

 
$
88

 
$
24

FTRs
51

 
45

 
Discounted Cash Flow
 
Auction Prices (per MWh)
 
(31
)
 
36

 

 
$
98

 
$
146

 
 
 
 
 
 
 
 
 
 
 
Significant Unobservable Inputs
 
December 31, 2016
 
Fair Value
 
 
 
Input/Range
 
Assets
 
Liabilities
 
Valuation Technique
 
Significant Unobservable Input
 
Low
 
High
 
Weighted Average
 
(In millions)
 
 
 
 
 
 
 
 
 
 
Power Contracts
$
39

 
$
108

 
Discounted Cash Flow
 
Forward Market Price (per MWh)
 
$
11

 
$
104

 
$
31

FTRs
51

 
50

 
Discounted Cash Flow
 
Auction Prices (per MWh)
 
(22
)
 
17

 

 
$
90

 
$
158

 
 
 
 
 
 
 
 
 
 
The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable inputs as of September 30, 2017 and December 31, 2016:
Significant Unobservable Input
 
Position
 
Change In Input
 
Impact on Fair Value Measurement
Forward Market Price Power
 
Buy
 
Increase/(Decrease)
 
Higher/(Lower)
Forward Market Price Power
 
Sell
 
Increase/(Decrease)
 
Lower/(Higher)
FTR Prices
 
Buy
 
Increase/(Decrease)
 
Higher/(Lower)
FTR Prices
 
Sell
 
Increase/(Decrease)
 
Lower/(Higher)
The fair value of each contract is discounted using a risk-free interest rate. In addition, the Company applies a credit reserve to reflect credit risk, which is calculated based on published default probabilities. As of September 30, 2017, the credit reserve resulted in a $1 million increase in fair value in operating revenue and cost of operations. As of December 31, 2016, the credit reserve resulted in a $10 million decrease in fair value in operating revenue and cost of operations.
Concentration of Credit Risk
In addition to the credit risk discussion as disclosed in Note 2, Summary of Significant Accounting Policies, to the Company's 2016 Form 10-K, the following is a discussion of the concentration of credit risk for the Company's contractual obligations. Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. NRG is exposed to counterparty credit risk through various activities including wholesale sales, fuel purchases and retail supply arrangements, and retail customer credit risk through its retail load activities.

27



Counterparty Credit Risk
The Company's counterparty credit risk policies are disclosed in its 2016 Form 10-K. As of September 30, 2017, the Company's counterparty credit exposure, excluding credit risk exposure under certain long term agreements, was $134 million with net exposure of $129 million. NRG held collateral (cash and letters of credit) against those positions of $14 million. Approximately 74% of the Company's exposure before collateral is expected to roll off by the end of 2018. Counterparty credit exposure is valued through observable market quotes and discounted at a risk free interest rate. The following tables highlight net counterparty credit exposure by industry sector and by counterparty credit quality. Net counterparty credit exposure is defined as the aggregate net asset position for NRG with counterparties where netting is permitted under the enabling agreement and includes all cash flow, mark-to-market and NPNS, and non-derivative transactions. The exposure is shown net of collateral held, and includes amounts net of receivables or payables.
 
Net Exposure (a) (b)
Category by Industry Sector
(% of Total)
Utilities, energy merchants, marketers and other
91
%
Financial institutions
9

Total as of September 30, 2017
100
%
 
Net Exposure (a) (b)
Category by Counterparty Credit Quality
(% of Total)
Investment grade
79
%
Non-Investment grade/Non-Rated
21

Total as of September 30, 2017
100
%
(a)
Counterparty credit exposure excludes uranium and coal transportation contracts because of the unavailability of market prices.
(b)
The figures in the tables above exclude potential counterparty credit exposure related to RTOs, ISOs, registered commodity exchanges and certain long term contracts.
NRG has counterparty credit risk exposure to certain counterparties, each of which represent more than 10% of total net exposure discussed above. The aggregate of such counterparties' exposure was $50 million as of September 30, 2017. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration. Given the credit quality, diversification and term of the exposure in the portfolio, NRG does not anticipate a material impact on the Company's financial position or results of operations from nonperformance by any of NRG's counterparties.
RTOs and ISOs
The Company participates in the organized markets of CAISO, ERCOT, ISO-NE, MISO, NYISO and PJM, known as RTOs or ISOs. Trading in these markets is approved by FERC, or in the case of ERCOT, approved by the PUCT and includes credit policies that, under certain circumstances, require that losses arising from the default of one member on spot market transactions be shared by the remaining participants. As a result, the counterparty credit risk to these markets is limited to NRG’s share of overall market and are excluded from the above exposures.
Exchange Traded Transactions
The Company enters into commodity transactions on registered exchanges, notably ICE and NYMEX. These clearinghouses act as the counterparty and transactions are subject to extensive collateral and margining requirements. As a result, these commodity transactions have limited counterparty credit risk.

Long Term Contracts
Counterparty credit exposure described above excludes credit risk exposure under certain long term agreements, including California tolling agreements, Gulf Coast load obligations, and wind and solar PPAs. As external sources or observable market quotes are not available to estimate such exposure, the Company estimates its credit exposure for these contracts based on various techniques including, but not limited to, internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. Based on these valuation techniques, as of September 30, 2017, aggregate credit risk exposure managed by NRG to these counterparties was approximately $4.3 billion, including $2.8 billion related to assets of NRG Yield, Inc., for the next five years. This amount excludes potential credit exposures for projects with long-term PPAs that have not reached commercial operations. The majority of these power contracts are with utilities or public power entities with strong credit quality and public utility commission or other regulatory support. However, such regulated utility counterparties can be impacted by changes in government regulations or treatment by regulatory agencies which NRG is unable to predict.


28



Retail Customer Credit Risk
NRG is exposed to retail credit risk through the Company's retail electricity providers, which serve commercial, industrial and governmental/institutional customers and the Mass market. Retail credit risk results when a customer fails to pay for products or services rendered. The losses may result from both nonpayment of customer accounts receivable and the loss of in-the-money forward value. NRG manages retail credit risk through the use of established credit policies that include monitoring of the portfolio, and the use of credit mitigation measures such as deposits or prepayment arrangements.
As of September 30, 2017, the Company believes its retail customer credit exposure was diversified across many customers and various industries, as well as government entities.
Note 5Nuclear Decommissioning Trust Fund
This footnote should be read in conjunction with the complete description under Note 6, Nuclear Decommissioning Trust Fund, to the Company's 2016 Form 10-K.
NRG's Nuclear Decommissioning Trust Fund assets are comprised of securities classified as available-for-sale and recorded at fair value based on actively quoted market prices. NRG accounts for the Nuclear Decommissioning Trust Fund in accordance with ASC 980, Regulated Operations, because the Company's nuclear decommissioning activities are subject to approval by the PUCT with regulated rates that are designed to recover all decommissioning costs and that can be charged to and collected from the ratepayers per PUCT mandate. Since the Company is in compliance with PUCT rules and regulations regarding decommissioning trusts and the cost of decommissioning is the responsibility of the Texas ratepayers, not NRG, all realized and unrealized gains or losses (including other-than-temporary impairments) related to the Nuclear Decommissioning Trust Fund are recorded to nuclear decommissioning trust liability and are not included in net income or accumulated OCI, consistent with regulatory treatment.
The following table summarizes the aggregate fair values and unrealized gains and losses (including other-than-temporary impairments) for the securities held in the trust funds, as well as information about the contractual maturities of those securities.
 
As of September 30, 2017
 
As of December 31, 2016
(In millions, except otherwise noted)
Fair Value
 
Unrealized Gains
 
Unrealized Losses
 
Weighted-average Maturities (In years)
 
Fair Value
 
Unrealized Gains
 
Unrealized Losses
 
Weighted-average Maturities (In years)
Cash and cash equivalents
$
31

 
$

 
$

 

 
$
25

 
$

 
$

 

U.S. government and federal agency obligations
44

 
2

 

 
10

 
73

 
1

 

 
11

Federal agency mortgage-backed securities
74

 
1

 
1

 
24

 
62

 
1

 
1

 
25

Commercial mortgage-backed securities
11

 

 

 
23

 
17

 

 
1

 
26

Corporate debt securities
108

 
2

 
1

 
11

 
84

 
1

 
2

 
11

Equity securities
398

 
260

 

 

 
346

 
214

 

 

Foreign government fixed income securities
4

 

 

 
9

 
3

 

 

 
9

Total
$
670

 
$
265

 
$
2

 
 
 
$
610

 
$
217

 
$
4

 
 
The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and losses from these sales. The cost of securities sold is determined on the specific identification method.
 
Nine months ended September 30,
 
2017
 
2016
 
(In millions)
Realized gains
$
8

 
$
7

Realized losses
6

 
3

Proceeds from sale of securities
382


354


29



Note 6Accounting for Derivative Instruments and Hedging Activities
This footnote should be read in conjunction with the complete description under Note 5, Accounting for Derivative Instruments and Hedging Activities, to the Company's 2016 Form 10-K.
Energy-Related Commodities
As of September 30, 2017, NRG had energy-related derivative instruments extending through 2031. The Company marks these derivatives to market through the statement of operations.
Interest Rate Swaps
NRG is exposed to changes in interest rates through the Company's issuance of variable rate debt. In order to manage the Company's interest rate risk, NRG enters into interest rate swap agreements. As of September 30, 2017, the Company had interest rate derivative instruments on recourse debt extending through 2021, which are not designated as cash flow hedges. The Company had interest rate swaps on non-recourse debt extending through 2041, most of which are designated as cash flow hedges.
Volumetric Underlying Derivative Transactions
The following table summarizes the net notional volume buy/(sell) of NRG's open derivative transactions broken out by category, excluding those derivatives that qualified for the NPNS exception, as of September 30, 2017 and December 31, 2016. Option contracts are reflected using delta volume. Delta volume equals the notional volume of an option adjusted for the probability that the option will be in-the-money at its expiration date.
 
 
Total Volume
 
 
September 30, 2017
 
December 31, 2016
Category
Units
(In millions)
Emissions
Short Ton
(1
)
 

Coal
Short Ton
15

 
35

Natural Gas
MMBtu
(62
)
 
(53
)
Oil
Barrel

 
1

Power
MWh
19

 
7

Capacity
MW/Day
(1
)
 
(1
)
Interest
Dollars
$
3,806

 
$
3,429

Equity
Shares
1

 
1

The decrease in the coal position was primarily the result of the settlement of hedge positions, and the increase in the power position was primarily the result of additional retail hedge positions.

Fair Value of Derivative Instruments
The following table summarizes the fair value within the derivative instrument valuation on the balance sheets:
 
Fair Value
 
Derivative Assets
 
Derivative Liabilities
 
September 30, 2017
 
December 31, 2016
 
September 30, 2017
 
December 31, 2016
 
(In millions)
Derivatives designated as cash flow hedges:

 
 
 


 
Interest rate contracts current
$

 
$

 
$
8


$
28

Interest rate contracts long-term
10

 
12

 
15


41

Total derivatives designated as cash flow hedges
10

 
12

 
23


69

Derivatives not designated as cash flow hedges:

 
 
 
 

 
Interest rate contracts current
5

 

 
19


7

Interest rate contracts long-term
27

 
37

 
36


12

Commodity contracts current
470

 
1,067

 
495


1,057

Commodity contracts long-term
169

 
132

 
256


231

Total derivatives not designated as cash flow hedges
671

 
1,236

 
806


1,307

Total derivatives
$
681


$
1,248

 
$
829


$
1,376




30



The Company has elected to present derivative assets and liabilities on the balance sheet on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. In addition, collateral received or paid on the Company's derivative assets or liabilities are recorded on a separate line item on the balance sheet. The following table summarizes the offsetting of derivatives by counterparty master agreement level and collateral received or paid:
 
 
Gross Amounts Not Offset in the Statement of Financial Position
 
 
Gross Amounts of Recognized Assets / Liabilities
 
Derivative Instruments
 
Cash Collateral (Held) / Posted
 
Net Amount
As of September 30, 2017
 
(In millions)
Commodity contracts:
 
 
 
 
 
 
 
 
Derivative assets
 
$
639

 
$
(546
)
 
$
(5
)
 
$
88

Derivative liabilities
 
(751
)
 
546

 
83

 
(122
)
Total commodity contracts
 
(112
)
 

 
78

 
(34
)
Interest rate contracts:
 
 
 
 
 
 
 
 
Derivative assets
 
42

 
(2
)
 

 
40

Derivative liabilities
 
(78
)
 
2

 

 
(76
)
Total interest rate contracts
 
(36
)
 

 

 
(36
)
Total derivative instruments
 
$
(148
)
 
$

 
$
78

 
$
(70
)
 
 
Gross Amounts Not Offset in the Statement of Financial Position
 
 
Gross Amounts of Recognized Assets / Liabilities
 
Derivative Instruments
 
Cash Collateral (Held) / Posted
 
Net Amount
As of December 31, 2016
 
(In millions)
Commodity contracts:
 
 
 
 
 
 
 

Derivative assets
 
$
1,199

 
$
(1,021
)
 
$
(13
)
 
$
165

Derivative liabilities
 
(1,288
)
 
1,021

 
13

 
(254
)
Total commodity contracts
 
(89
)
 

 

 
(89
)
Interest rate contracts:
 
 
 
 
 
 
 

Derivative assets
 
49

 
(4
)
 

 
45

Derivative liabilities
 
(88
)
 
4

 

 
(84
)
Total interest rate contracts
 
(39
)
 

 

 
(39
)
Total derivative instruments
 
$
(128
)
 
$

 
$


$
(128
)
Accumulated Other Comprehensive Loss
The following table summarizes the effects of ASC 815 on the Company's accumulated OCI balance attributable to cash flow hedge derivatives, net of tax:
 
Interest Rate Contracts
 
Three months ended September 30,
 
Nine months ended September 30,
 
2017
 
2016
 
2017
 
2016
 
(In millions)
Accumulated OCI beginning balance
$
(67
)
 
$
(165
)
 
$
(66
)
 
$
(101
)
Reclassified from accumulated OCI to income:
 
 
 
 
 
 
 
Due to realization of previously deferred amounts
4

 
2

 
10

 
12

Mark-to-market of cash flow hedge accounting contracts
4

 
32

 
(3
)
 
(42
)
Accumulated OCI ending balance, net of $15, and $28 tax
$
(59
)
 
$
(131
)

$
(59
)

$
(131
)
Losses expected to be realized from OCI during the next 12 months, net of $4 tax
$
14

 

 
$
14

 


Amounts reclassified from accumulated OCI into income and amounts recognized in income from the ineffective portion of cash flow hedges are recorded to interest expense for interest rate contracts. There was no ineffectiveness for the three and nine months ended September 30, 2017 and 2016.

31



Accounting guidelines require a high degree of correlation between the derivative and the hedged item throughout the period in order to qualify as a cash flow hedge. As of December 31, 2016, the Company's regression analysis for Viento Funding II interest rate swaps, while positively correlated, did not meet the required threshold for cash flow hedge accounting. As a result, the Company de-designated the Viento Funding II cash flow hedges as of December 31, 2016, and will prospectively mark these derivatives to market through the income statement.
The Company's regression analysis for Marsh Landing, Walnut Creek, and Avra Valley interest rate swaps, while positively correlated, no longer contain match terms for cash flow hedge accounting. As a result, the Company voluntarily de-designated the Marsh Landing, Walnut Creek, and Avra Valley cash flow hedges as of April 28, 2017, and will prospectively mark these derivatives to market through the income statement.
Impact of Derivative Instruments on the Statements of Operations
Unrealized gains and losses associated with changes in the fair value of derivative instruments not accounted for as cash flow hedges and ineffectiveness of hedge derivatives are reflected in current period consolidated results of operations.
The following table summarizes the pre-tax effects of economic hedges that have not been designated as cash flow hedges, ineffectiveness on cash flow hedges and trading activity on the Company's statement of operations. The effect of energy commodity contracts is included within operating revenues and cost of operations and the effect of interest rate contracts is included in interest expense.
 
Three months ended September 30,
 
Nine months ended September 30,
 
2017
 
2016
 
2017
 
2016
Unrealized mark-to-market results
(In millions)
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges
$
(6
)
 
$
(30
)
 
$
19

 
$
(75
)
Reversal of acquired gain positions related to economic hedges
(2
)
 
(7
)
 
(1
)
 
(11
)
Net unrealized (losses)/gains on open positions related to economic hedges
(16
)
 
(50
)
 
(1
)
 
27

Total unrealized mark-to-market (losses)/gains for economic hedging activities
(24
)
 
(87
)
 
17

 
(59
)
Reversal of previously recognized unrealized (gains)/losses on settled positions related to trading activity
(5
)
 
3

 
(24
)
 
13

Net unrealized (losses)/gains on open positions related to trading activity

 
(8
)
 
17

 
14

Total unrealized mark-to-market (losses)/gains for trading activity
(5
)
 
(5
)
 
(7
)
 
27

Total unrealized (losses)/gains
$
(29
)
 
$
(92
)
 
$
10

 
$
(32
)
 
Three months ended September 30,
 
Nine months ended September 30,
 
2017
 
2016
 
2017
 
2016
 
(In millions)
Unrealized gains/(losses) included in operating revenues
$
21

 
$
57

 
$
178

 
$
(333
)
Unrealized (losses)/gains included in cost of operations
(50
)
 
(149
)
 
(168
)
 
301

Total impact to statement of operations — energy commodities
$
(29
)
 
$
(92
)
 
$
10

 
$
(32
)
Total impact to statement of operations — interest rate contracts
$
11

 
$
9

 
$
(8
)
 
$
(9
)
The reversals of acquired gain or loss positions were valued based upon the forward prices on the acquisition date. The roll-off amounts were offset by realized gains or losses at the settled prices and are reflected in operating revenue or cost of operations during the same period.
For the nine months ended September 30, 2017, the $1 million unrealized loss from open economic hedge positions was primarily the result of a decrease in value of forward purchases of coal, natural gas, and ERCOT power due to decreases in coal, natural gas, and ERCOT electricity prices, which was largely offset by an increase in value of forward sales of PJM power and New York capacity due to decreases in PJM electricity and New York capacity prices.
For the nine months ended September 30, 2016, the $27 million unrealized gain from open economic hedge positions was primarily the result of an increase in value of forward purchases of natural gas due to increases in natural gas prices.

32



Credit Risk Related Contingent Features
Certain of the Company's hedging agreements contain provisions that require the Company to post additional collateral if the counterparty determines that there has been deterioration in credit quality, generally termed “adequate assurance” under the agreements, or requires the Company to post additional collateral if there were a one notch downgrade in the Company's credit rating. The collateral required for contracts with adequate assurance clauses that are in a net liability position as of September 30, 2017, was $27 million. The collateral required for contracts with credit rating contingent features as of September 30, 2017, was $34 million. The Company is also a party to certain marginable agreements where NRG has a net liability position, but the counterparty has not called for the collateral due, which was approximately $17 million as of September 30, 2017.
See Note 4, Fair Value of Financial Instruments, to this Form 10-Q for discussion regarding concentration of credit risk.
Note 7Impairments

2017 Impairment Losses
    
Bacliff Project — On June 16, 2017, NRG Texas Power LLC provided notice to BTEC New Albany, LLC that it was exercising its right to terminate the Amended and Restated Membership Interest Purchase Agreement, or MIPA, due to the Bacliff Project, a new peaking facility at the former P.H. Robinson Electric Generating Station, not achieving commercial completion by the contractual expiration date of May 31, 2017. As a result of the MIPA termination, the Company recorded an impairment loss of $41 million to reduce the carrying amount of the related construction in progress to $0 during the second quarter of 2017. On July 14, 2017, the Company gave notice to BTEC New Albany, LLC that it owes NRG Texas Power LLC approximately $48 million under the terminated MIPA, consisting of $38 million in purchaser incurred costs and $10 million in liquidated damages.
Other Impairments — During the second quarter of 2017, the Company recorded impairment losses of approximately $22 million in connection with the Company's Renewables business. During the third quarter of 2017, the Company recorded an additional $14 million in impairment losses, in connection with the Company's Renewable business.
2016 Impairment Losses
Rockford — On May 12, 2016, the Company entered into an agreement with RA Generation, LLC to sell 100% of its interests in the Rockford generating stations for cash consideration of $55 million. The transaction triggered an indicator of impairment as the sale price was less than the carrying amount of the assets, and, as a result, the assets were considered to be impaired. The Company measured the impairment loss as the difference between the carrying amount of the assets and the agreed-upon sale price. The Company recorded an impairment loss of $17 million during the quarter ended June 30, 2016, to reduce the carrying amount of the assets held for sale to the fair market value.
Other Impairments — During the second quarter of 2016, the Company recorded impairment losses for intangible assets of $8 million in connection with the Company's strategic change in its residential solar business as well as $10 million of deferred marketing expenses. In addition, the Company also recorded an impairment loss of $17 million to record certain previously purchased solar panels at fair market value. During the third quarter of 2016, the Company recorded an additional $9 million in impairment losses related to investments and $8 million in other impairments.
Petra Nova Parish Holdings During the first quarter of 2016, management changed its plans with respect to its future capital commitments driven in part by the continued decline in oil prices. As a result, the Company reviewed its 50% interest in Petra Nova Parish Holdings for impairment utilizing the other-than-temporary impairment model. In determining fair value, the Company utilized an income approach and considered project specific assumptions for the future project cash flows. The carrying amount of the Company's equity method investment exceeded the fair value of the investment and the Company concluded that the decline is considered to be other than temporary. As a result, the Company measured the impairment loss as the difference between the carrying amount and the fair value of the investment and recorded an impairment loss of $140 million.

  

33




Note 8Debt and Capital Leases
This footnote should be read in conjunction with the complete description under Note 12, Debt and Capital Leases, to the Company's 2016 Form 10-K. Long-term debt and capital leases consisted of the following:
(In millions, except rates)
September 30, 2017
 
December 31, 2016
 
September 30, 2017 interest rate % (a)
 
 
 
Recourse debt:
 
 
 
 
 
Senior notes, due 2018
$
398

 
$
398

 
7.625
Senior notes, due 2021
207

 
207

 
7.875
Senior notes, due 2022
992

 
992

 
6.250
Senior notes, due 2023
869

 
869

 
6.625
Senior notes, due 2024
733

 
733

 
6.250
Senior notes, due 2026
1,000

 
1,000

 
7.250
Senior notes, due 2027
1,250

 
1,250

 
6.625
Term loan facility, due 2023
1,876

 
1,891

 
L+2.25
Tax-exempt bonds
465

 
455

 
4.125 - 6.00
Subtotal NRG recourse debt
7,790

 
7,795

 

Non-recourse debt:
 
 
 
 
 
NRG Yield Operating LLC Senior Notes, due 2024
500

 
500

 
5.375
NRG Yield Operating LLC Senior Notes, due 2026
350

 
350

 
5.000
NRG Yield, Inc. Convertible Senior Notes, due 2019
345

 
345

 
3.500
NRG Yield, Inc. Convertible Senior Notes, due 2020
288

 
288

 
3.250
El Segundo Energy Center, due 2023
400

 
443

 
L+1.75 - L+2.375
Marsh Landing, due 2017 and 2023
334

 
370

 
L+1.750 - L+1.875
Alta Wind I - V lease financing arrangements, due 2034 and 2035
940

 
965

 
5.696 - 7.015
Walnut Creek, term loans due 2023
279

 
310

 
L+1.625
Utah Portfolio, due 2022
284

 
287

 
L+2.625
Tapestry, due 2021
165

 
172

 
L+1.625
CVSR, due 2037
746

 
771

 
2.339 - 3.775
CVSR HoldCo, due 2037
194

 
199

 
4.680
Alpine, due 2022
138

 
145

 
L+1.750
Energy Center Minneapolis, due 2017 and 2025
82

 
96

 
5.95 - 7.25
Energy Center Minneapolis, due 2031
125

 
125

 
3.55
Viento, due 2023
169

 
178

 
L+3.00
NRG Yield - other
562

 
540

 
various
Subtotal NRG Yield debt (non-recourse to NRG)
5,901

 
6,084

 
 
Ivanpah, due 2033 and 2038
1,097

 
1,113

 
2.285 - 4.256
Carlsbad Energy Project
407

 

 
4.120
Agua Caliente, due 2037
833

 
849

 
2.395 - 3.633
Agua Caliente Borrower 1, due 2038
89

 

 
5.430
Cedro Hill, due 2025
153

 
163

 
L+1.75
Midwest Generation, due 2019
173

 
231

 
4.390
NRG Other
689

 
468

 
various
Subtotal other NRG non-recourse debt
3,441

 
2,824

 
 
Subtotal all non-recourse debt
9,342

 
8,908

 
 
Subtotal long-term debt (including current maturities)
17,132


16,703

 
 
Capital leases
6

 
6

 
various
Subtotal long-term debt and capital leases (including current maturities)
17,138


16,709

 
 
Less current maturities
(1,247
)

(516
)
 
 
Less debt issuance costs
(198
)
 
(188
)
 
 
Discounts
(35
)
 
(48
)
 
 
Total long-term debt and capital leases
$
15,658


$
15,957

 
 
(a) As of September 30, 2017, L+ equals 3 month LIBOR plus x%, with the exception of the Utah Portfolio term loans.

34



Recourse Debt
2023 Term Loan Facility
On January 24, 2017, NRG repriced the 2023 Term Loan Facility, reducing the interest rate margin by 50 basis points to LIBOR plus 2.25%. The LIBOR floor remains 0.75%.
Revolving Credit Facility
On June 12, 2017, NRG repaid $125 million on the Revolving Credit Facility. As of September 30, 2017, no cash borrowings were outstanding on the revolver.
Senior Notes
2017 Senior Note Redemptions
On October 16, 2017, the Company redeemed $398 million of its 7.625% Senior Notes due 2018 and $206 million of its 7.875% Senior Notes due 2021 for $630 million, which included $14 million in accrued interest.
2016 Senior Note Repurchases
During the nine months ended September 30, 2016, the Company repurchased $2.6 billion in aggregate principal of its Senior Notes in the open market for $2.7 billion, which included accrued interest of $67 million. In connection with the repurchases, a $94 million loss on debt extinguishment was recorded, which included the write-off of previously deferred financing costs of $15 million.
Issuance of 2026 Senior Notes
On May 23, 2016, NRG issued $1.0 billion in aggregate principal amount at par of 7.25% senior notes due 2026, or the 2026 Senior Notes. The 2026 Senior Notes are senior unsecured obligations of NRG and are guaranteed by certain of its subsidiaries. Interest is paid semi-annually beginning on November 15, 2016, until the maturity date of May 15, 2026.
Issuance of 2027 Senior Notes
On August 2, 2016, NRG issued $1.25 billion in aggregate principal amount at par of 6.625% senior notes due 2027, or the 2027 Senior Notes. The 2027 Senior Notes are senior unsecured obligations of NRG and are guaranteed by certain of its subsidiaries. Interest is paid semi-annually beginning on January 15, 2017, until the maturity date of January 15, 2027. The proceeds from the issuance of the 2027 Senior Notes were utilized to retire the Company's 8.250% senior notes due 2020 and reduce the balance of the Company's 7.875% senior notes due 2021.
Non-recourse Debt
NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility
NRG Yield LLC and its direct wholly owned subsidiary, NRG Yield Operating LLC, entered into a senior secured revolving credit facility, which can be used for cash and for the issuance of letters of credit. At September 30, 2017, there was $68 million of letters of credit issued under the revolving credit facility and no borrowing outstanding on the revolver.
Project Financings
Agua Caliente Project Financing
On February 17, 2017, Agua Caliente Borrower 1 LLC and Agua Caliente Borrower 2 LLC, or Agua Caliente Holdco, the indirect owners of 51% of the Agua Caliente solar facility, issued $130 million of senior secured notes under the Agua Caliente Holdco Financing Agreement, or 2038 Agua Caliente Holdco Notes, that bear interest at 5.43% and mature on December 31, 2038. As described in Note 3, Discontinued Operations, Dispositions and Acquisitions, on March 27, 2017, NRG Yield, Inc. acquired Agua Caliente Borrower 2 LLC from NRG. The debt is joint and several with respect to Agua Caliente Borrower 1 LLC and Agua Caliente Borrower 2 LLC and is secured by the equity interests of each borrower in the Agua Caliente solar facility.

35



Carlsbad Project Financing
On May 26, 2017, Carlsbad Energy Holdings, LLC entered into a note payable agreement with financial institutions for the issuance of up to $407 million of senior secured notes that bear interest at a rate of 4.12%, and mature on October 31, 2038. As of September 30, 2017, all $407 million of these notes were outstanding.
Also on May 26, 2017, Carlsbad Energy Holdings, LLC entered into a credit agreement, or the Carlsbad Financing Agreement, with the issuing banks, for a $194 million construction loan, that will convert to a term loan upon completion of the project. The Carlsbad Financing Agreement also includes a letter of credit facility with an aggregate principle amount not to exceed $83 million, and a working capital loan facility with an aggregate principle amount not to exceed $4 million.
Note 9Variable Interest Entities, or VIEs
Entities that are not Consolidated
NRG has interests in entities that are considered VIEs under ASC 810, Consolidation, but NRG is not considered the primary beneficiary.  NRG accounts for its interests in these entities under the equity method of accounting.
GenConn Energy LLC Through its consolidated subsidiary, NRG Yield Operating LLC, the Company owns a 50% interest in GCE Holding LLC, the owner of GenConn, which owns and operates two 190 MW peaking generation facilities in Connecticut at NRG's Devon and Middletown sites. NRG's maximum exposure to loss is limited to its equity investment, which was $102 million as of September 30, 2017.
Entities that are Consolidated
The Company has a controlling financial interest in certain entities which have been identified as VIEs under ASC 810. These arrangements are primarily related to tax equity arrangements entered into with third-parties in order to finance the cost of solar energy systems under operating leases and wind facilities eligible for certain tax credits as further described in Note 2, Summary of Significant Accounting Policies to the Company's 2016 Form 10-K. For one of the tax equity arrangements, the Company has a deficit restoration obligation equal to $100 million as of September 30, 2017, which would be required to be funded if the arrangement were to be dissolved.
The summarized financial information for the Company's consolidated VIEs consisted of the following:
(In millions)
September 30, 2017
 
December 31, 2016
Current assets
$
74

 
$
87

Net property, plant and equipment
1,466

 
1,534

Other long-term assets
1,026

 
954

Total assets
2,566

 
2,575

Current liabilities
69

 
59

Long-term debt
420

 
442

Other long-term liabilities
187

 
183

Total liabilities
676

 
684

Noncontrolling interests
578

 
529

Net assets less noncontrolling interests
$
1,312

 
$
1,362


36




Note 10Changes in Capital Structure
As of September 30, 2017 and December 31, 2016, the Company had 500,000,000 shares of common stock authorized. The following table reflects the changes in NRG's common stock issued and outstanding:
 
Issued
 
Treasury
 
Outstanding
Balance as of December 31, 2016
417,583,825

 
(102,140,814
)
 
315,443,011

Shares issued under LTIPs
634,738

 

 
634,738

Shares issued under ESPP

 
560,769

 
560,769

Balance as of September 30, 2017
418,218,563

 
(101,580,045
)
 
316,638,518

Preferred Stock
On May 24, 2016, NRG entered an agreement with Credit Suisse Group to repurchase 100% of the outstanding shares of its $344.5 million 2.822% preferred stock. On June 13, 2016, the Company completed the repurchase from Credit Suisse of 100% of the outstanding shares at a price of $226 million. The transaction resulted in a gain on redemption of $78 million, measured as the difference between the fair value of the cash consideration paid upon redemption of $226 million and the carrying value of the preferred stock at the time of the redemption of $304 million. This amount is reflected in net income/(loss) available to NRG common stockholders in the calculation of earnings per share.
Amended and Restated Employee Stock Purchase Plan
On April 27, 2017, NRG stockholders approved an increase of 3,000,000 shares available for issuance under the ESPP. As of September 30, 2017, there were 3,107,050 shares of treasury stock available for issuance under the ESPP.
Amended and Restated Long-term Incentive Plan
On April 27, 2017, NRG stockholders approved an increase of 3,000,000 shares available for issuance under the NRG Energy, Inc. Amended and Restated Long-term Incentive Plan.
NRG Common Stock Dividends
The following table lists the dividends paid during the nine months ended September 30, 2017:
 
Third Quarter 2017
 
Second Quarter 2017

First Quarter 2017
Dividends per Common Share
$
0.03

 
$
0.03


$
0.03

On October 18, 2017, NRG declared a quarterly dividend on the Company's common stock of $0.03 per share, payable November 15, 2017, to stockholders of record as of November 1, 2017, representing $0.12 per share on an annualized basis.
The Company's common stock dividends are subject to available capital, market conditions, and compliance with associated laws, regulations and other contractual obligations.

37



Note 11Earnings/(Loss) Per Share
Basic earnings/(loss) per common share is computed by dividing net income/(loss) less accumulated preferred stock dividends by the weighted average number of common shares outstanding. Shares issued and treasury shares repurchased during the year are weighted for the portion of the year that they were outstanding. Diluted earnings/(loss) per share is computed in a manner consistent with that of basic income/(loss) per share while giving effect to all potentially dilutive common shares that were outstanding during the period. During the second quarter of 2016, the Company repurchased 100% of the outstanding shares of its 2.822% preferred stock. The reconciliation of NRG's basic and diluted earnings/(loss) per share is shown in the following table:
 
Three months ended September 30,
 
Nine months ended September 30,
(In millions, except per share data)
2017
 
2016
 
2017
 
2016
Basic and diluted income/(loss) per share attributable to NRG Energy, Inc. common stockholders
Net income/(loss) attributable to NRG Energy, Inc.
$
171

 
$
402

 
$
(619
)
 
$
213

Dividends for preferred shares

 

 

 
5

Gain on redemption of 2.822% redeemable perpetual preferred stock

 

 

 
(78
)
Income/(loss) available for common stockholders
$
171


$
402


$
(619
)

$
286

Weighted average number of common shares outstanding - basic
317

 
316


317

 
315

Income/(loss) per weighted average common share — basic
$
0.54

 
$
1.27

 
$
(1.95
)
 
$
0.91

Diluted income/(loss) per share attributable to NRG Energy, Inc. common stockholders
 
 
 
 
Weighted average number of common shares outstanding - diluted
317

 
316

 
317

 
315

Incremental shares attributable to the issuance of equity compensation (treasury stock method)
5

 
1

 

 
1

Total dilutive shares
322

 
317

 
317

 
316

Income/(loss) per weighted average common share — diluted
$
0.53

 
$
1.27

 
$
(1.95
)
 
$
0.91

The following table summarizes NRG’s outstanding equity instruments that are anti-dilutive and were not included in the computation of the Company’s diluted earnings/(loss) per share:
 
Three months ended September 30,
 
Nine months ended September 30,
(In millions of shares)
2017
 
2016
 
2017
 
2016
Equity compensation plans
1

 
2

 
6

 
3

Total
1

 
2

 
6

 
3


38



Note 12Segment Reporting
The Company's segment structure reflects how management currently makes financial decisions and allocates resources. The Company's businesses are segregated as follows: Generation, which includes generation, international and BETM; Retail, which includes Mass customers and Business Solutions, which includes C&I customers and other distributed and reliability products; Renewables, which includes solar and wind assets, excluding those in NRG Yield; NRG Yield; and corporate activities. The financial information for the three and nine months ended September 30, 2016 has been recast to reflect the current segment structure.
On September 1, 2016, NRG Yield acquired the remaining 51.05% interest in CVSR Holdco LLC, which indirectly owns the CVSR solar facility, from the Company. On March 27, 2017, NRG Yield acquired from NRG a 16% interest in the Agua Caliente solar project, and NRG's interests in seven utility-scale solar projects located in Utah. On August 1, 2017, NRG Yield acquired the remaining 25% interest in NRG Wind TE Holdco from the Company. All three acquisitions were treated as a transfer of entities under common control and accordingly, all historical periods have been recast to reflect the acquisition as if they had occurred at the beginning of the financial statement period.
On June 14, 2017, as described in Note 3, Discontinued Operations, Dispositions and Acquisitions, NRG deconsolidated GenOn for financial reporting purposes. The financial information for all historical periods have been recast to reflect the deconsolidation of GenOn and to present discontinued operations within the corporate segment.
NRG’s chief operating decision maker, its chief executive officer, evaluates the performance of its segments based on operational measures including adjusted earnings before interest, taxes, depreciation and amortization, or Adjusted EBITDA, free cash flow and capital for allocation, as well as net income/(loss).
 
Generation(a)
 
Retail (a)
 
Renewables(a)
 
NRG Yield
 
Corporate(a)
 
Eliminations
 
Total
Three months ended September 30, 2017
(In millions)
Operating revenues(a)
$
1,224

 
$
1,937

 
$
144

 
$
265

 
$
2

 
$
(523
)
 
$
3,049

Depreciation and amortization
96

 
29

 
51

 
88

 
8

 

 
272

Impairment losses
1

 

 
13

 

 

 

 
14

Equity in (losses)/earnings of unconsolidated affiliates
12

 

 
(3
)
 
28

 

 
(10
)
 
27

Loss on debt extinguishment, net

 

 

 

 
(1
)
 

 
(1
)
Income/(loss) from continuing operations before income taxes
258

 
69

 
(7
)
 
49

 
(161
)
 
(12
)
 
196

Income/(loss) from continuing operations
258

 
69

 
(4
)
 
41

 
(162
)
 
(12
)
 
190

Loss from discontinued operations, net of tax

 

 

 

 
(27
)
 

 
(27
)
Net Income/(loss)
258

 
69


(4
)
 
41

 
(189
)
 
(12
)
 
163

Net Income/(loss) attributable to NRG Energy, Inc.
$
258


$
69

 
$
9

 
$
35


$
(220
)
 
$
20

 
$
171

Total assets as of September 30, 2017
$
8,585

 
$
2,445

 
$
5,357

 
$
8,442

 
$
11,090

 
$
(10,449
)
 
$
25,470

(a) Operating revenues include inter-segment sales and net derivative gains and losses of:
$
491

 
$
(8
)
 
$
19

 
$

 
$
21

 
$

 
$
523

 
Generation(a)
 
Retail(a)
 
Renewables(a)
 
NRG Yield
 
Corporate(a)
 
Eliminations
 
Total
Three months ended September 30, 2016
(In millions)
Operating revenues(a)
$
1,536

 
$
2,012

 
$
139

 
$
272

 
$
24

 
$
(562
)
 
$
3,421

Depreciation and amortization
134

 
26

 
48

 
75

 
15

 

 
298

Impairment losses
9

 

 

 

 

 

 
9

Equity in earnings/(losses) of unconsolidated affiliates
6

 

 
(10
)
 
16

 
5

 
(1
)
 
16

Gain on sale of assets


 

 

 

 
4

 

 
4

Loss on debt extinguishment, net

 

 

 

 
(50
)
 

 
(50
)
Income/(loss) from continuing operations before income taxes
370

 
(78
)
 
(1
)
 
63

 
(202
)
 
4

 
156

Income/(loss) from continuing operations
372

 
(78
)
 
2

 
50

 
(222
)
 
4

 
128

Income from discontinued operations, net of tax

 

 

 

 
265

 

 
265

Net Income/(Loss)
372

 
(78
)
 
2

 
50

 
43

 
4

 
393

Net Income/(Loss) attributable to NRG Energy, Inc.
$
372

 
$
(78
)
 
$
(9
)
 
$
55

 
$
19

 
$
43

 
$
402

(a) Operating revenues include inter-segment sales and net derivative gains and losses of:
$
506

 
$
(2
)
 
$
8

 
$

 
$
50

$
52

$

 
$
562


39




 
Generation(a)
 
Retail (a)
 
Renewables(a)
 
NRG Yield
 
Corporate(a)
 
Eliminations
 
Total
Nine months ended September 30, 2017
(In millions)
Operating revenues(a)
$
3,072

 
$
4,875

 
$
364

 
$
767

 
$
13

 
$
(959
)
 
$
8,132

Depreciation and amortization
287

 
87

 
150

 
241

 
24

 

 
789

Impairment losses
42

 

 
35

 

 

 

 
77

Equity in (losses)/earnings of unconsolidated affiliates
(16
)
 

 
(6
)
 
63

 
7

 
(19
)
 
29

Gain on sale of assets
4

 

 

 

 

 

 
4

Loss on debt extinguishment, net

 

 
(3
)
 

 

 

 
(3
)
Income/(loss) from continuing operations before income taxes
202

 
371

 
(97
)
 
100

 
(430
)
 
(21
)
 
125

Income/(loss) from continuing operations
200

 
380

 
(84
)
 
85

 
(440
)
 
(21
)
 
120

Loss from discontinued operations, net of tax

 

 

 

 
(802
)
 

 
(802
)
Net Income/(Loss)
200

 
380

 
(84
)
 
85

 
(1,242
)
 
(21
)
 
(682
)
Net Income/(Loss) attributable to NRG Energy, Inc.
$
200

 
$
380

 
$
(18
)
 
$
87

 
$
(1,306
)
 
$
38

 
$
(619
)
(a) Operating revenues include inter-segment sales and net derivative gains and losses of:
$
897

 
$
3

 
$
23

 
$

 
$
36

 
$

 
$
959

 
Generation(a)
 
Retail(a)
 
Renewables(a)
 
NRG Yield(a)
 
Corporate(a)
 
Eliminations
 
Total
Nine months ended September 30, 2016
(In millions)
Operating revenues(a)
$
3,173

 
$
4,918

 
$
336

 
$
789

 
$
54

 
$
(942
)
 
$
8,328

Depreciation and amortization
331

 
83

 
143

 
224

 
45

 

 
826

Impairment losses
26

 

 
27

 

 
12

 

 
65

Equity in earnings/(losses) of unconsolidated affiliates
1

 

 
(16
)
 
34

 
11

 
(17
)
 
13

Loss on sale of assets

 

 

 

 
(79
)
 

 
(79
)
Impairment loss on investment
(142
)
 

 
1

 

 
(6
)
 

 
(147
)
Loss on debt extinguishment, net

 

 

 

 
(119
)
 

 
(119
)
(Loss)/income from continuing operations before income taxes
(51
)
 
735

 
(121
)
 
141

 
(706
)
 
(15
)
 
(17
)
(Loss)/income from continuing operations
(49
)
 
734

 
(107
)
 
116

 
(771
)
 
(15
)
 
(92
)
Income from discontinued operations, net of tax

 

 

 

 
256

 

 
256

Net (Loss)/Income
(49
)
 
734

 
(107
)
 
116

 
(515
)
 
(15
)
 
164

Net (Loss)/Income attributable to NRG Energy, Inc.
$
(49
)
 
$
734

 
$
(103
)
 
$
113

 
$
(547
)
 
$
65

 
$
213

(a) Operating revenues include inter-segment sales and net derivative gains and losses of:
$
836

 
$
3

 
$
16

 
$
6

 
$
81

 
$

 
$
942






40



Note 13Income Taxes
Effective Tax Rate
The income tax provision consisted of the following:
 
Three months ended September 30,
 
Nine months ended September 30,
(In millions except otherwise noted)
2017
 
2016
 
2017
 
2016
Income/(Loss) before income taxes
$
196

 
$
156

 
$
125

 
$
(17
)
Income tax expense from continuing operations
6

 
28

 
5

 
75

Effective tax rate
3.1
%
 
17.9
%

4.0
%

(441.2
)%
For the three months and nine months ended September 30, 2017, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the tax benefit for the change in valuation allowance and the generation of PTCs and ITCs from various wind and solar facilities, respectively, partially offset by the inclusion of consolidated partnerships and current state tax expense.
For the three months ended September 30, 2016, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the tax benefit for the change in valuation allowance, partially offset by amortization of indefinite lived assets, inclusion of consolidated partnerships and state tax expense.
For the nine months ended September 30, 2016, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the amortization of indefinite lived assets, the inclusion of consolidated partnerships, state tax expense and the expense for the change in valuation allowance.
Uncertain Tax Benefits
As of September 30, 2017, NRG has recorded a non-current tax liability of $40 million for uncertain tax benefits from positions taken on various state income tax returns, including accrued interest. For the nine months ended September 30, 2017, NRG accrued an immaterial amount of interest relating to the uncertain tax benefits. As of September 30, 2017, NRG had cumulative interest and penalties related to these uncertain tax benefits of $4 million. The Company recognizes interest and penalties related to uncertain tax benefits in income tax expense.
NRG is subject to examination by taxing authorities for income tax returns filed in the U.S. federal jurisdiction and various state and foreign jurisdictions including operations located in Australia. The Company is not subject to U.S. federal income tax examinations for years prior to 2015. With few exceptions, state and local income tax examinations are no longer open for years before 2010. The Company's primary foreign operations are also no longer subject to examination by local jurisdictions for years prior to 2010.

41



Note 14Related Party Transactions
Services Agreement with GenOn
The Company provides GenOn with various management, personnel and other services, which include human resources, regulatory and public affairs, accounting, tax, legal, information systems, treasury, risk management, commercial operations, and asset management, as set forth in the services agreement with GenOn, or the Services Agreement. The initial term of the Services Agreement was through December 31, 2013, with an automatic renewal absent a request for termination. The fee charged was determined based on a fixed amount as described in the Services Agreement and was calculated based on historical GenOn expenses prior to the NRG Merger. The annual fees under the Services Agreement were approximately $193 million and management has concluded that this method of charging overhead costs is reasonable. As described in Note 3, Discontinued Operations, Dispositions and Acquisitions, in connection with the Restructuring Support Agreement, NRG agreed to provide shared services to GenOn under the Services Agreement for an adjusted annualized fee of $84 million through the pendency of the Chapter 11 Cases. Beginning on June 14, 2017, NRG records operating income for the amounts earned for shared services of approximately $5 million per month. Subsequent to the GenOn Entities' emergence from bankruptcy, NRG will provide shared services for two months at no charge; after which GenOn has an additional two, one-month options to provide services at an annualized fee of $84 million. NRG charges these fees on a monthly basis, less amounts incurred directly by GenOn. For the three and nine months ended September 30, 2017, NRG recorded other income - affiliate related to these services of $14 million and $104 million, respectively. For the three and nine months ended September 30, 2016, NRG recorded other income - affiliate related to these services of $48 million and $144 million, respectively.
In addition, as described in Note 3, Discontinued Operations, Dispositions and Acquisitions, under the Restructuring Support Agreement, NRG has agreed to provide GenOn with a $28 million credit against amounts owed to NRG prior to the Petition Date under the current Services Agreement. The credit was intended to reimburse GenOn for its payment of financing costs. In addition, the Restructuring Support Agreement provides that to the extent GenOn has paid for services during the bankruptcy proceedings and the aforementioned credit has not been applied in full, NRG shall, upon request by GenOn, reimburse such payments in cash up to the amount of any unused portion of the credit.
See Note 1, Basis of Presentation, for further discussion regarding the October 30, 2017 proposed changes to the Restructuring Support Agreement and Services Agreement, based on which NRG recorded a reserve of $15 million against affiliate receivable balances as of September 30, 2017.
Credit Agreement with GenOn
NRG and GenOn are party to a secured intercompany revolving credit agreement.  The intercompany revolving credit agreement provided for a $500 million revolving credit facility, all of which was available for revolving loans and letters of credit. At September 30, 2017 and December 31, 2016, $103 million and $272 million, respectively, of letters of credit were issued and outstanding under the NRG credit agreement for GenOn. Additionally, as of September 30, 2017, there were $125 million of loans outstanding under the intercompany secured revolving credit facility. As of December 31, 2016, no loans were outstanding under this intercompany secured revolving credit facility. In addition, the intercompany secured revolving credit facility contains customary covenants and events of default. As of September 30, 2017, GenOn was in default under the secured intercompany revolving credit agreement due to the filing of the Chapter 11 Cases.
As a result of the Chapter 11 Cases, no additional revolving loans or letters of credit are available to GenOn. In addition, NRG agreed to provide GenOn with a letter of credit facility during the pendency of the Chapter 11 Cases, which could be utilized for required letters of credit in lieu of the intercompany secured revolving credit facility. The letter of credit facility provided availability of up to $330 million less amounts borrowed and letters of credit provided are required to be cash collateralized at 103% of the letter of credit amount. On July 27, 2017, this letter of credit facility was terminated as GenOn has obtained a separate letter of credit facility with a third party financial institution. Effective with completion of the reorganization, GenOn must repay NRG for all revolving loans outstanding, with such amount to be netted against the settlement payment owed from NRG to GenOn. Accordingly, the affiliate receivable is recorded net within accrued expenses and other current liabilities - affiliate on the consolidated balance sheet as of September 30, 2017. Interest continues to accrue during the pendency of the Chapter 11 Cases and borrowings remain secured obligations.


42



Commercial Operations Agreement
NRG Power Marketing LLC has entered into physical and financial intercompany commodity and hedging transactions with GenOn and certain of its subsidiaries. Subject to applicable collateral thresholds, these arrangements may provide for the bilateral exchange of credit support based upon market exposure and potential market movements. The terms and conditions of the agreements are generally consistent with industry practices and other third party arrangements. As of September 30, 2017, derivative assets and liabilities associated with these transactions are recorded within NRG's derivative instruments balances on the consolidated balance sheet, with related revenues and costs within operating revenues and cost of operations, respectively.

Note 15Commitments and Contingencies
This footnote should be read in conjunction with the complete description under Note 22, Commitments and Contingencies, to the Company's 2016 Form 10-K.
Commitments
First Lien Structure — NRG has granted first liens to certain counterparties on a substantial portion of the Company's assets, excluding assets acquired in the EME (including Midwest Generation) acquisitions, assets held by NRG Yield, Inc. and NRG's assets that have project-level financing, to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or MWh equivalents. The Company's lien counterparties may have a claim on NRG's assets to the extent market prices exceed the hedged price. As of September 30, 2017, hedges under the first liens were out-of-the-money for NRG on a counterparty aggregate basis.
Lignite Contract with Texas Westmoreland Coal Co. — The Company has a contract with TWCC for reclamation activities associated with closure of the Jewett mine.  NRG is responsible for reclamation costs and has recorded an adequate ARO liability. The Railroad Commission of Texas has imposed a bond obligation of $95.5 million on TWCC for the reclamation of the mine. Pursuant to the contract with TWCC, NRG supports this obligation through surety bonds. Additionally, NRG is obligated to provide additional performance assurance if required by the Railroad Commission of Texas.
Contingencies
The Company's material legal proceedings are described below. The Company believes that it has valid defenses to these legal proceedings and intends to defend them vigorously. NRG records reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. As applicable, the Company has established an adequate reserve for the matters discussed below. In addition, legal costs are expensed as incurred. Management has assessed each of the following matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought, and the probability of success. Unless specified below, the Company is unable to predict the outcome of these legal proceedings or reasonably estimate the scope or amount of any associated costs and potential liabilities. As additional information becomes available, management adjusts its assessment and estimates of such contingencies accordingly. Because litigation is subject to inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate resolution of the Company's liabilities and contingencies could be at amounts that are different from its currently recorded reserves and that such difference could be material.
In addition to the legal proceedings noted below, NRG and its subsidiaries are party to other litigation or legal proceedings arising in the ordinary course of business. In management's opinion, the disposition of these ordinary course matters will not materially adversely affect NRG's consolidated financial position, results of operations, or cash flows.
Midwest Generation Asbestos Liabilities — The Company, through its subsidiary, Midwest Generation, may be subject to potential asbestos liabilities as a result of its acquisition of EME. The Company is currently analyzing the scope of potential liability as it may relate to Midwest Generation. The Company believes that it has established an adequate reserve for these cases.
Energy Plus Holdings On August 7, 2012, Energy Plus Holdings received a subpoena from the NYAG which generally sought information and business records related to Energy Plus Holdings' sales, marketing and business practices. Energy Plus Holdings provided documents and information to the NYAG. On June 22, 2015, the NYAG issued another subpoena seeking additional information. Energy Plus Holdings provided responsive documents to this second subpoena. On August 28, 2017, the parties entered into an Assurance of Discontinuance resolving this matter.


43



Midwest Generation New Source Review Litigation — In August 2009, the EPA and the Illinois Attorney General, or the Government Plaintiffs, filed a complaint, or the Governments’ Complaint, in the U.S. District Court for the Northern District of Illinois alleging violations of CAA PSD requirements by Midwest Generation arising from maintenance, repair or replacement projects at six Illinois coal-fired electric generating stations performed by Midwest Generation or ComEd, a prior owner of the stations, including alleged failures to obtain PSD construction permits and to comply with BACT requirements. The Government Plaintiffs also alleged violations of opacity and PM standards at the Midwest Generation plants. Finally, the Government Plaintiffs alleged that Midwest Generation violated certain operating permit requirements under Title V of the CAA allegedly arising from such claimed PSD, opacity and PM emission violations. In addition to seeking penalties of up to $37,500 per violation, per day, the complaint seeks an injunction ordering Midwest Generation to install controls sufficient to meet BACT emission rates at the units subject to the complaint and other remedies, which could go well beyond the requirements of the CPS. Several environmental groups intervened as plaintiffs in this litigation and filed a complaint, or the Intervenors’ Complaint, which alleged opacity, PM and related Title V violations. Midwest Generation filed a motion to dismiss nine of the ten PSD counts in the Governments’ Complaint, and to dismiss the tenth PSD count to the extent the Governments’ Complaint sought civil penalties for that count. The trial court granted the motion in March 2010.
In June 2010, the Government Plaintiffs and Intervenors each filed an amended complaint. The Governments’ Amended Complaint again alleged that Midwest Generation violated PSD (based upon the same projects as alleged in their original complaint, but adding allegations that the Company was liable as the “successor” to ComEd), Title V and opacity and PM standards. It named EME and ComEd as additional defendants and alleged PSD violations (again, premised on the same projects) against them. The Intervenors’ Amended Complaint named only Midwest Generation as a defendant and alleged Title V and opacity/PM violations, as well as one of the ten PSD violations alleged in the Governments’ Amended Complaint. Midwest Generation again moved to dismiss all but one of the Government Plaintiffs’ PSD claims and the related Title V claims. Midwest Generation also filed a motion to dismiss the PSD claim in the Intervenors’ Amended Complaint and the related Title V claims. In March 2011, the trial court granted Midwest Generation’s partial motion to dismiss the Government Plaintiffs’ PSD claims. The trial court denied Midwest Generation’s motion to dismiss the PSD claim asserted in the Intervenors’ Amended Complaint, but noted that the plaintiffs would be required to convince the court that the statute of limitations should be equitably tolled. The trial court did not address other counts in the amended complaints that allege violations of opacity and PM emission limitations under the Illinois State Implementation Plan and related Title V claims. The trial court also granted the motions to dismiss the PSD claims asserted against EME and ComEd.
Following the trial court ruling, the Government Plaintiffs appealed the trial court’s dismissals of their PSD claims, including the dismissal of nine of the ten PSD claims against Midwest Generation and of the PSD claims against the other defendants. Those PSD claim dismissals were affirmed by the U.S. Court of Appeals for the Seventh Circuit in July 2013. In addition, in 2012, all but one of the environmental groups that had intervened in the case dismissed their claims without prejudice. As a result, only one environmental group remains a plaintiff intervenor in the case. The Company does not expect the resolution of this matter to have a material impact on the Company’s consolidated financial position, results of operations or cash flows.
Telephone Consumer Protection Act Purported Class Actions Three purported class action lawsuits have been filed against NRG Residential Solar Solutions, LLC — one in California and two in New Jersey.  The plaintiffs generally allege misrepresentation by the call agents and violations of the TCPA, claiming that the defendants engaged in a telemarketing campaign placing unsolicited calls to individuals on the “Do Not Call List.” The plaintiffs seek statutory damages of up to $1,500 per plaintiff, actual damages and equitable relief. On June 22, 2017, plaintiffs in the California case filed a motion for leave to file a second amended complaint to substitute new plaintiffs. Defendants’ filed an opposition to this motion on June 26, 2017. The court granted plaintiffs' motion to substitute new plaintiffs and on August 1, 2017, Defendants filed an answer to the second amended complaint. On August 31, 2017, the court in the California case agreed that the litigation should be stayed pending the New Jersey settlement. On July 12, 2017, the parties in the New Jersey action reached an agreement in principle to resolve the class allegations which was confirmed by a term sheet signed by the parties on July 28, 2017. On September 27, 2017, plaintiffs in the New Jersey case filed their motion for preliminary approval of the class settlement.


44



California Department of Water Resources and San Diego Gas & Electric Company v. Sunrise Power Company LLC — On January 29, 2016, CDWR and SDG&E filed a lawsuit against Sunrise Power Company, along with NRG and Chevron Power Corporation.  In June 2001, CDWR and Sunrise entered into a 10-year PPA under which Sunrise would construct and operate a generating facility and provide power to CDWR.  At the time the PPA was entered into, Sunrise had a transportation services agreement, or TSA, to purchase natural gas from Kern River through April 30, 2018.  In August 2003, CDWR entered into an agreement with Sunrise and Kern River in which CDWR accepted assignment of the TSA through the term of the PPA.  After the PPA expired, Kern River demanded that any reassignment be to a party which met certain creditworthiness standards which Sunrise did not.  As such, the plaintiffs brought this lawsuit against the defendants alleging breach of contract, breach of covenant of good faith and fair dealing and improper distributions.  Plaintiffs generally claim damages of $1.2 million per month for the remaining 70 months of the TSA. On April 20, 2016, the defendants filed demurrers in response to the plaintiffs' complaint. The demurrers were granted on June 14, 2016; however, the plaintiffs were allowed to file amended complaints on July 1, 2016. On July 27, 2016, defendants filed demurrers to the amended complaints. On November 18, 2016, the court sustained the demurrers and allowed plaintiffs another opportunity to file a second amended lawsuit which they did on January 13, 2017. On April 21, 2017, the court issued an order sustaining the demurrers without leave to amend. On July 14, 2017, CDWR filed a notice of appeal.

Braun v. NRG Yield, Inc. — On April 19, 2016, plaintiffs filed a putative class action lawsuit against NRG Yield, Inc., the current and former members of its board of directors individually, and other parties in California Superior Court in Kern County, CA.  Plaintiffs allege various violations of the Securities Act due to the defendants’ alleged failure to disclose material facts related to low wind production prior to the NRG Yield, Inc.'s June 22, 2015 Class C common stock offering.  Plaintiffs seek compensatory damages, rescission, attorney’s fees and costs. The Defendants filed demurrers and a motion challenging jurisdiction on October 18, 2016. On October 26, 2017, the court approved the parties' stipulation which provides the plaintiffs' opposition is due on December 6, 2017 and defendants' reply is due on February 8, 2018.

Ahmed v. NRG Energy, Inc. and the NRG Yield Board of Directors — On September 15, 2016, plaintiffs filed a putative class action lawsuit against NRG Energy, Inc., the directors of NRG Yield, Inc., and other parties in the Delaware Chancery Court. The complaint alleges that the defendants breached their respective fiduciary duties with regard to the recapitalization of NRG Yield, Inc. common stock in 2015. The plaintiffs generally seek economic damages, attorney’s fees and injunctive relief. The defendants filed a motion to dismiss the lawsuit on December 21, 2016. Plaintiffs filed their objection to the motion to dismiss on February 15, 2017. The defendants' reply was filed on March 24, 2017. The court heard oral argument on defendants' motion to dismiss on June 20, 2017. On September 7, 2017, the court requested additional briefing which the parties provided on September 21, 2017.

Griffoul v. NRG Residential Solar Solutions — On February 28, 2017, plaintiffs, consisting of New Jersey residential solar customers, filed a purported class action lawsuit in New Jersey state court.  Plaintiffs allege violations of the New Jersey Consumer Fraud Action and Truth-in-Consumer Contracts, Warranty and Notice Act with regard to certain provisions of their residential solar contracts.  The plaintiffs seek damages and injunctive relief as to the proper allocation of the solar renewable energy credits. On June 6, 2017, the defendants filed a motion to compel arbitration or dismiss the lawsuit. Plaintiffs filed their opposition on June 29, 2017. On July 14, 2017, the court denied NRG's motion to compel arbitration or dismiss the case. On July 25, 2017, NRG filed a motion for reconsideration of the appeal, which the court denied. On August 22, 2017, NRG filed a notice of appeal. NRG’s appellate brief was filed on October 25, 2017. Plaintiffs’ opposition is due on November 16, 2017.
Rice v. NRG — On April 14, 2017, plaintiffs filed a purported class action lawsuit in the U.S. District Court for the Western District of Pennsylvania against NRG, First Energy Corporation and Matt Canastrale Contracting, Inc.  Plaintiffs generally claim personal injury, trespass, nuisance and property damage related to the disposal of coal ash from GenOn's Elrama Power Plant and First Energy’s Mitchell and Hatfield Power Plants. Plaintiffs generally seek monetary damages, medical monitoring and remediation of their property. Plaintiffs filed an amended complaint on August 14, 2017. On October 20, 2017, NRG filed its answer and affirmative defenses.

Washington-St. Tammany and Claiborne Electric Cooperative v. LaGen — On June 28, 2017, plaintiffs Washington-St. Tammany Electric Cooperative, Inc. and Claiborne Electric Cooperative, Inc. filed a lawsuit against Louisiana Generating, L.L.C., or LaGen, in the United States District Court for the Middle District of Louisiana. The plaintiffs claim breach of contract against LaGen for allegedly improperly charging the plaintiffs for costs related to the installation and maintenance of certain pollution control technology. Plaintiffs seek damages for the alleged improper charges and a declaration as to which charges are proper under the contract. On September 14, 2017, the court issued a scheduling order setting this case for trial on October 21, 2019. LaGen filed a motion for a more definite statement on September 18, 2017.


45



GenOn Chapter 11 Cases — On the Petition Date, the GenOn Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. Under the Restructuring Support Agreement to which the GenOn Entities, NRG and certain of GenOn's and GenOn Americas Generation's senior unsecured noteholders are parties, each of them has agreed to support Bankruptcy Court approval of the plan of reorganization. GenOn has a customary "fiduciary out" under the Restructuring Support Agreement. Moreover, the Bankruptcy Court may not approve the plan of reorganization. If the plan of reorganization is not approved, NRG may not be entitled to the benefits of the Settlement Agreement provided under the Restructuring Support Agreement and it will remain subject to any claims of GenOn and the noteholders, including claims relating to or arising out of any shared services and any other relationships or transactions between the companies. See Note 3, Discontinued Operations, Dispositions and Acquisitions, for additional information related to the Chapter 11 Cases.
GenOn Noteholders' Lawsuit On December 13, 2016, certain indenture trustees for an ad hoc group of holders, or the Noteholders, of the GenOn Energy, Inc. 7.875% Senior Notes due 2017, 9.500% Notes due 2018, and 9.875% Notes due 2020, and the GenOn Americas Generation, LLC 8.50% Senior Notes due 2021 and 9.125% Senior Notes due 2031, along with certain of the Noteholders, filed a complaint in the Superior Court of the State of Delaware against NRG and GenOn alleging certain claims related to the Services Agreement between NRG and GenOn. Plaintiffs generally seek return of all monies paid under the Services Agreement and any other damages that the court deems appropriate. On February 3, 2017, the court entered an order approving a Standstill Agreement whereby the parties agreed to suspend all deadlines in the case until March 1, 2017.  The Standstill Agreement terminated on March 1, 2017. On April 30, 2017, the Noteholders filed an amended complaint that asserts (i) additional fraudulent transfer claims in relation to GenOn’s sale of the Marsh Landing project to NRG Yield LLC, (ii) alleged breaches of fiduciary duty by certain current and former officers and directors of GenOn in relation to the Services Agreement and the alleged usurpation of corporate opportunities concerning the Mandalay and Canal projects and (iii) claims against NRG for allegedly aiding and abetting such claimed breaches of fiduciary duties. In addition to NRG and GenOn, the amended complaint names NRG Yield LLC and certain current and former officers and directors of GenOn as defendants. The plaintiffs, among other things, generally seek return of all monies paid under the services agreement and any other damages that the court deems appropriate. Pursuant to the terms of the Restructuring Support Agreement, this matter should ultimately be resolved if the GenOn Entities' plan of reorganization is approved by the Bankruptcy Court.

Morgantown v. GenOn Mid-Atlantic — On June 8, 2017, Morgantown and Dickerson Owner Lessors filed a lawsuit against GenOn Mid-Atlantic, LLC, NRG North America LLC, GenOn Americas Generation, LLC, NRG Americas, Inc., GenOn Energy Holdings, Inc., GenOn Energy, Inc., and NRG Energy, Inc. in New York State Supreme Court. The plaintiffs allege that they were overcharged by defendants for certain services outlined in a Services Agreement and that defendants caused a Qualified Credit Support portion of a Participation Agreement, or QCS Agreement, to be violated by causing the transfer of certain money outside the allowable confines set forth in the QCS Agreement. In addition, plaintiffs claim that the transfers were unfairly executed and done so in an effort to defraud plaintiffs and hinder their ability to continue to do business. As such, plaintiffs seek, among other things, the return of certain transferred funds and service charges paid and to bar defendants from executing additional transfers on plaintiffs’ behalf. A claims estimation ruling on this matter by the Bankruptcy Court could occur as early as November 7, 2017.

BTEC v. NRG Texas Power — On July 18, 2017, BTEC New Albany LLC, or BTEC, filed a lawsuit against NRG Texas Power LLC, or NRG Texas Power, in the Harris County District Court in Texas.  On January 15, 2013, the parties entered into a Membership  Interest and Purchase Agreement, or MIPA, whereby BTEC agreed to dismantle, transport and rebuild an electric power generation facility at the former P.H. Robinson Electric Generating Station in Bacliff, Texas.  The MIPA required BTEC to meet a Guaranteed Commercial Completion Date of May 31, 2016.  But even a year later, BTEC had not satisfied all of the contractually-required acceptance criteria.  As a result and given that the MIPA expiration date passed on May 31, 2017, NRG elected to terminate the contract in June 2017. BTEC claims that NRG Texas Power breached the MIPA by improperly terminating it, and seeks a declaratory judgment as to the rights and obligations of the parties.  In addition, BTEC seeks damages, interest and attorney’s fees. On August 14, 2017, NRG Texas Power served its answer to the lawsuit. On September 7, 2017, NRG Texas Power filed a counterclaim seeking damages in excess of $48 million.


46



GenOn Related Contingencies

Actions Pursued by MC Asset Recovery With Mirant Corporation's emergence from bankruptcy protection in 2006, certain actions filed by GenOn Energy Holdings and some of its subsidiaries against third parties were transferred to MC Asset Recovery, a wholly owned subsidiary of GenOn Energy Holdings.  MC Asset Recovery is governed by a manager who is independent of NRG and GenOn.  MC Asset Recovery is a disregarded entity for income tax purposes. Under the remaining action transferred to MC Asset Recovery, MC Asset Recovery seeks to recover damages from Commerzbank AG and various other banks, or the Commerzbank Defendants, for alleged fraudulent transfers that occurred prior to Mirant's bankruptcy proceedings.  In December 2010, the U.S. District Court for the Northern District of Texas dismissed MC Asset Recovery's complaint against the Commerzbank Defendants.  In January 2011, MC Asset Recovery appealed the District Court's dismissal of its complaint against the Commerzbank Defendants to the U.S. Court of Appeals for the Fifth Circuit, or the Fifth Circuit.  In March 2012, the Fifth Circuit reversed the District Court's dismissal and reinstated MC Asset Recovery's amended complaint against the Commerzbank Defendants.  On December 10, 2015, the District Court granted summary judgment in favor of the Commerzbank Defendants. On December 29, 2015, MC Asset Recovery filed a notice to appeal this judgment with the Fifth Circuit. On June 1, 2017, the Fifth Circuit affirmed the District Court's judgment. On June 12, 2017, MC Asset Recovery petitioned the Fifth Circuit for rehearing. The petition for rehearing was denied and a court order and judgment affirming the District Court's judgments was entered on July 17, 2017. On January 17, 2018, the bankruptcy court will hear a Motion for a Final Decree in the Mirant bankruptcy.
Natural Gas Litigation GenOn is party to several lawsuits, certain of which are class action lawsuits, in state and federal courts in Kansas, Missouri, Nevada and Wisconsin. These lawsuits were filed in the aftermath of the California energy crisis in 2000 and 2001 and the resulting FERC investigations and relate to alleged conduct to increase natural gas prices in violation of state antitrust law and similar laws. The lawsuits seek treble or punitive damages, restitution and/or expenses. The lawsuits also name as parties a number of energy companies unaffiliated with NRG. In July 2011, the U.S. District Court for the District of Nevada, which was handling four of the five cases, granted the defendants' motion for summary judgment and dismissed all claims against GenOn in those cases. The plaintiffs appealed to the U.S. Court of Appeals for the Ninth Circuit, or the Ninth Circuit, which reversed the decision of the District Court. GenOn along with the other defendants in the lawsuit filed a petition for a writ of certiorari to the U.S. Supreme Court challenging the Ninth Circuit's decision and the U.S. Supreme Court granted the petition. On April 21, 2015, the U.S. Supreme Court affirmed the Ninth Circuit’s holding that plaintiffs’ state antitrust law claims are not field-preempted by the federal Natural Gas Act and the Supremacy Clause of the U.S. Constitution.  The U.S. Supreme Court left open whether the claims were preempted on the basis of conflict preemption. The U.S. Supreme Court directed that the case be remanded to the U.S. District Court for the District of Nevada for further proceedings. On March 7, 2016, class plaintiffs filed their motions for class certification. Defendants filed their briefs in opposition to class plaintiffs' motions for class certification on June 24, 2016. On March 30, 2017, the court denied the plaintiffs' motions for class certification. On April 13, 2017, the plaintiffs petitioned the Ninth Circuit for interlocutory review of the court’s order denying class certification. On June 13, 2017, the Ninth Circuit granted plaintiffs' petition for interlocutory review.
In May 2016 in one of the Kansas cases, the U.S. District Court for the District of Nevada granted the defendants' motion for summary judgment. Subsequently in December 2016, the plaintiffs filed a notice of appeal with the Ninth Circuit. The appeal has been fully briefed by the parties. GenOn has agreed to indemnify CenterPoint against certain losses relating to these lawsuits.
In September 2012, the State of Nevada Supreme Court, which was handling the remaining case, affirmed dismissal by the Eighth Judicial District Court for Clark County, Nevada of all plaintiffs' claims against GenOn. In February 2013, the plaintiffs in the Nevada case filed a petition for a writ of certiorari to the U.S. Supreme Court. In June 2013, the U.S. Supreme Court denied the petition for a writ of certiorari, thereby ending one of the five lawsuits.
Potomac River Environmental Investigation In March 2013, NRG Potomac River LLC, a subsidiary of GenOn, received notice that the District of Columbia Department of Environment (now renamed the Department of Energy and Environment, or DOEE) was investigating potential discharges to the Potomac River originating from the Potomac River Generating facility site, a site where the generation facility is no longer in operation. In connection with that investigation, DOEE served a civil subpoena on NRG Potomac River LLC requesting information related to the site and potential discharges occurring from the site.  NRG Potomac River LLC provided various responsive materials.  In January 2016, DOEE advised NRG Potomac River LLC that DOEE believed various environmental violations had occurred as a result of discharges DOEE believes occurred to the Potomac River from the Potomac River Generating facility site and as a result of associated failures to accurately or sufficiently report such discharges.  DOEE has indicated it believes that penalties are appropriate in light of the violations.  NRG Potomac River LLC is currently reviewing the information provided by DOEE.

47



Note 16Regulatory Matters
This footnote should be read in conjunction with the complete description under Note 23, Regulatory Matters, to the Company's 2016 Form 10-K.
NRG operates in a highly regulated industry and is subject to regulation by various federal and state agencies. As such, NRG is affected by regulatory developments at both the federal and state levels and in the regions in which NRG operates. In addition, NRG is subject to the market rules, procedures, and protocols of the various ISO and RTO markets in which NRG participates. These power markets are subject to ongoing legislative and regulatory changes that may impact NRG's wholesale and retail businesses.
In addition to the regulatory proceedings noted below, NRG and its subsidiaries are parties to other regulatory proceedings arising in the ordinary course of business or have other regulatory exposure. In management's opinion, the disposition of these ordinary course matters will not materially adversely affect NRG's consolidated financial position, results of operations, or cash flows.
National
Zero-Emission Credits for Nuclear Plants in Illinois — In 2016, Illinois enacted a Zero Emission Credit, or ZEC, program for selected nuclear units in Illinois. In total, the program directs over $2.5 billion over ten years to nuclear plants in Illinois that would otherwise retire. Pursuant to the legislation, the Illinois Power Agency, or IPA, conducts a competitive solicitation to procure ZECs, although both the Governor of Illinois and Exelon have already announced that the ZECs will be awarded to two Exelon-owned nuclear power plants in Illinois.  These ZECs are out-of-market subsidies that threaten to artificially suppress market prices and interfere with the wholesale power market. On February 14, 2017, NRG, along with other companies, filed a complaint in the U.S. District Court for the Northern District of Illinois alleging that the state program is preempted by federal law and in violation of the dormant commerce clause. Another plaintiff group filed a similar complaint on the same day. Subsequently, on March 31, 2017, NRG, along with other companies, filed a motion for preliminary injunction. On April 10, 2017, Exelon, as an intervenor defendant, and State defendants filed motions to dismiss. On July 14, 2017, Defendants' motions to dismiss were granted. On July 17, 2017, NRG, along with other companies, filed a notice of appeal to the U.S. Court of Appeals for the Seventh Circuit. On July 18, 2017, the Court of Appeals issued an order setting an expedited briefing schedule for the matter. Briefing is underway.

Zero-Emission Credits for Nuclear Plants in New York — On August 1, 2016, the NYSPSC issued its Clean Energy Standard, or CES, which provided for ZECs which would provide more than $7.6 billion over 12 years in out-of-market subsidy payments to certain selected nuclear generating units in the state. These ZECs are out-of-market subsidies that threaten to artificially suppress market prices and interfere with the wholesale power market. On October 19, 2016, NRG, along with other companies, filed a complaint in the U.S. District Court for the Southern District of New York, challenging the validity of the NYSPSC action and the ZEC program. On March 29, 2017, the U.S. District Court heard oral arguments on a motion to dismiss filed by defendants. On July 25, 2017, the defendants' motions to dismiss were granted. On August 24, 2017, NRG, along with other companies, filed a notice of appeal to the U.S. Court of Appeals for the Second Circuit. On September 9, 2017, the Court of Appeals issued a briefing schedule. Briefing is underway.

Department of Energy's Proposed Grid Resiliency Pricing Rule — On September 29, 2017, the Department of Energy issued a proposed rulemaking titled the "Grid Resiliency Pricing Rule." The rulemaking directs FERC to take action to reform the ISO/RTO markets to value certain reliability and resiliency attributes of electric generation resources. On October 2, 2017, FERC issued a notice inviting comments. On October 4, 2017, FERC staff issued a series of questions requesting commenters to address. On October 23, 2017, NRG filed comments encouraging FERC to act expeditiously to modernize energy and capacity markets in a manner compatible with robust competitive markets.


48



Note 17Environmental Matters
This footnote should be read in conjunction with the complete description under Note 24, Environmental Matters, to the Company's 2016 Form 10-K.
NRG is subject to a wide range of environmental laws in the development, construction, ownership and operation of projects. These laws generally require that governmental permits and approvals be obtained before construction and during operation of power plants. NRG is also subject to laws regarding the protection of wildlife, including migratory birds, eagles and threatened and endangered species. The electric generation industry has been facing requirements regarding GHGs, combustion byproducts, water discharge and use, and threatened and endangered species that have been put in place in recent years. However, under the current U.S. presidential administration, some of these rules are being reconsidered and reviewed. In general, future laws are expected to require the addition of emissions controls or other environmental controls or to impose certain restrictions on the operations of the Company's facilities, which could have a material effect on the Company's consolidated financial position, results of operations, or cash flows. Federal and state environmental laws generally have become more stringent over time, although this trend could slow or pause in the near term with respect to federal laws under the current U.S. presidential administration.
The EPA finalized CSAPR in 2011, which was intended to replace CAIR in January 2012, to address certain states' obligations to reduce emissions so that downwind states can achieve federal air quality standards. In December 2011, the D.C. Circuit stayed the implementation of CSAPR and then vacated CSAPR in August 2012 but kept CAIR in place until the EPA could replace it. In April 2014, the U.S. Supreme Court reversed and remanded the D.C. Circuit's decision. In October 2014, the D.C. Circuit lifted the stay of CSAPR. In response, the EPA in November 2014 amended the CSAPR compliance dates. Accordingly, CSAPR replaced CAIR on January 1, 2015. On July 28, 2015, the D.C. Circuit held that the EPA had exceeded its authority by requiring certain reductions that were not necessary for downwind states to achieve federal standards. Although the D.C. Circuit kept the rule in place, the court ordered the EPA to revise the Phase 2 (or 2017) (i) SO2 budgets for four states including Texas and (ii) ozone-season NOx budgets for 11 states including Maryland, New Jersey, New York, Ohio, Pennsylvania and Texas. On October 26, 2016, the EPA finalized the CSAPR Update Rule, which reduces future NOx allocations and discounts the current banked allowances to account for the more stringent 2008 Ozone NAAQS and to address the D.C. Circuit's July 2015 decision. This rule has been challenged in the D.C. Circuit. The Company believes its investment in pollution controls and cleaner technologies leave the fleet well-positioned for compliance.
In February 2012, the EPA promulgated standards (the MATS rule) to control emissions of HAPs from coal and oil-fired electric generating units. The rule established limits for mercury, non-mercury metals, certain organics and acid gases, which had to be met beginning in April 2015 (with some units getting a 1-year extension). In June 2015, the U.S. Supreme Court issued a decision in the case of Michigan v. EPA, and held that the EPA unreasonably refused to consider costs when it determined that it was "appropriate and necessary" to regulate HAPs emitted by electric generating units. The U.S. Supreme Court did not vacate the MATS rule but rather remanded it to the D.C. Circuit for further proceedings. In December 2015, the D.C. Circuit remanded the MATS rule to the EPA without vacatur. On April 25, 2016, the EPA released a supplemental finding that the benefits of this regulation outweigh the costs to address the U.S. Supreme Court's ruling that the EPA had not properly considered costs. This finding has been challenged in the D.C. Circuit. On April 18, 2017, the EPA asked the D.C. Circuit to postpone oral argument that had been scheduled for May 18, 2017 because the EPA is closely reviewing the supplemental finding to determine whether it should reconsider all or part of the rule. On April 27, 2017, the D.C. Circuit granted EPA's request to postpone the oral argument and hold the case in abeyance. While NRG cannot predict the final outcome of this rulemaking, NRG believes that because it has already invested in pollution controls and cleaner technologies, the fleet is well-positioned to comply with the MATS rule.
Water
In August 2014, the EPA finalized the regulation regarding the use of water for once through cooling at existing facilities to address impingement and entrainment concerns. NRG anticipates that more stringent requirements will be incorporated into some of its water discharge permits over the next several years as NPDES permits are renewed.
Effluent Limitations Guidelines — In November 2015, the EPA revised the Effluent Limitations Guidelines for Steam Electric Generating Facilities, which would have imposed more stringent requirements (as individual permits were renewed) for wastewater streams from flue gas desulfurization, or FGD, fly ash, bottom ash, and flue gas mercury control.  In April 2017, the EPA granted two petitions to reconsider the rule and also administratively stayed some of the deadlines. On September 18, 2017, the EPA promulgated a final rule that (i) postpones the compliance dates to preserve the status quo for FGD wastewater and bottom ash transport water by two years to November 2020 until the EPA completes its next rulemaking and (ii) withdrew the April 2017 administrative stay. The legal challenges have been suspended while the EPA reconsiders and likely modifies the rule. Accordingly, the Company has largely eliminated its estimate of the environmental capital expenditures that would have been required to comply with permits incorporating the revised guidelines. The Company will revisit these estimates after the rule is revised.  

49



Byproducts, Wastes, Hazardous Materials and Contamination
In April 2015, the EPA finalized the rule regulating byproducts of coal combustion (e.g., ash and gypsum) as solid wastes under the RCRA. On September 13, 2017, the EPA granted the petition for reconsideration that the Utility Solid Waste Activities Group filed in May 2017. The Company has evaluated the impact of the new rule on the Company's consolidated financial position, results of operations, or cash flows and has accrued its environmental and asset retirement obligations under the rule based on current estimates as of September 30, 2017.
East Region
Burton Island Old Ash Landfill — In January 2006, NRG's Indian River Power LLC was notified that it may be a potentially responsible party with respect to Burton Island Old Ash Landfill, a historic captive landfill located at the Indian River facility. On October 1, 2007, NRG signed an agreement with DNREC to investigate the site through the Voluntary Clean-up Program, or the VCP. On February 4, 2008, DNREC issued findings that no further action was required in relation to surface water and that a previously planned shoreline stabilization project would satisfactorily address shoreline erosion. The landfill itself required a Remedial Investigation and Feasibility Study to determine the type and scope of any additional required work. DNREC approved the Feasibility Study in December 2012. In January 2013, DNREC proposed a remediation plan based on the Feasibility Study. The remediation plan was approved in October 2013. In December 2015, DNREC approved the Company's remediation design and the Company's Long Term Stewardship Plan. In the second quarter of 2017, the Company completed the remediation requirements in the remediation plan. The cost of completing the work required by the remediation plan was within amounts budgeted in early 2016. The estimated cost to comply with the Long-Term Stewardship Plan was added to the liability in December 2016.
In addition to the VCP, on May 29, 2008, DNREC requested that NRG's Indian River Power LLC participate in the development and performance of a Natural Resource Damage Assessment at the Burton Island Old Ash Landfill. NRG is working with DNREC and other trustees to close out the assessment process.

50



Note 18Condensed Consolidating Financial Information
As of September 30, 2017, the Company had outstanding $5.4 billion of Senior Notes due from 2018 to 2027, as shown in Note 8, Debt and Capital Leases. These Senior Notes are guaranteed by certain of NRG's current and future 100% owned domestic subsidiaries, or guarantor subsidiaries. These guarantees are both joint and several. The non-guarantor subsidiaries include all of NRG's foreign subsidiaries and certain domestic subsidiaries, and NRG Yield, Inc. and its subsidiaries.
Unless otherwise noted below, each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of September 30, 2017:
Ace Energy, Inc.
New Genco GP, LLC
NRG Norwalk Harbor Operations Inc.
Allied Home Warranty GP LLC
Norwalk Power LLC
NRG Operating Services, Inc.
Allied Warranty LLC
NRG Advisory Services LLC
NRG Oswego Harbor Power Operations Inc.
Arthur Kill Power LLC
NRG Affiliate Services Inc.
NRG PacGen Inc.
Astoria Gas Turbine Power LLC
NRG Arthur Kill Operations Inc.
NRG Portable Power LLC
Bayou Cove Peaking Power, LLC
NRG Astoria Gas Turbine Operations Inc.
NRG Power Marketing LLC
BidURenergy, Inc.
NRG Bayou Cove LLC
NRG Reliability Solutions LLC
Cabrillo Power I LLC
NRG Business Services LLC
NRG Renter's Protection LLC
Cabrillo Power II LLC
NRG Cabrillo Power Operations Inc.
NRG Retail LLC
Carbon Management Solutions LLC
NRG California Peaker Operations LLC
NRG Retail Northeast LLC
Cirro Group, Inc.
NRG Cedar Bayou Development Company, LLC
NRG Rockford Acquisition LLC
Cirro Energy Services, Inc.
NRG Connected Home LLC
NRG Saguaro Operations Inc.
Conemaugh Power LLC
NRG Connecticut Affiliate Services Inc.
NRG Security LLC
Connecticut Jet Power LLC
NRG Construction LLC
NRG Services Corporation
Cottonwood Development LLC
NRG Curtailment Solutions, Inc
NRG SimplySmart Solutions LLC
Cottonwood Energy Company LP
NRG Development Company Inc.
NRG South Central Affiliate Services Inc.
Cottonwood Generating Partners I LLC
NRG Devon Operations Inc.
NRG South Central Generating LLC
Cottonwood Generating Partners II LLC
NRG Dispatch Services LLC
NRG South Central Operations Inc.
Cottonwood Generating Partners III LLC
NRG Distributed Energy Resources Holdings LLC
NRG South Texas LP
Cottonwood Technology Partners LP
NRG Distributed Generation PR LLC
NRG SPV #1 LLC
Devon Power LLC
NRG Dunkirk Operations Inc.
NRG Texas C&I Supply LLC
Dunkirk Power LLC
NRG El Segundo Operations Inc.
NRG Texas Gregory LLC
Eastern Sierra Energy Company LLC
NRG Energy Efficiency-L LLC
NRG Texas Holding Inc.
El Segundo Power, LLC
NRG Energy Labor Services LLC
NRG Texas LLC
El Segundo Power II LLC
NRG ECOKAP Holdings LLC
NRG Texas Power LLC
Energy Alternatives Wholesale, LLC
NRG Energy Services Group LLC
NRG Warranty Services LLC
Energy Choice Solutions LLC
NRG Energy Services International Inc.
NRG West Coast LLC
Energy Plus Holdings LLC
NRG Energy Services LLC
NRG Western Affiliate Services Inc.
Energy Plus Natural Gas LLC
NRG Generation Holdings, Inc.
O'Brien Cogeneration, Inc. II
Energy Protection Insurance Company
NRG Greenco LLC
ONSITE Energy, Inc.
Everything Energy LLC
NRG Home & Business Solutions LLC
Oswego Harbor Power LLC
Forward Home Security, LLC
NRG Home Services LLC
Reliant Energy Northeast LLC
GCP Funding Company, LLC
NRG Home Solutions LLC
Reliant Energy Power Supply, LLC
Green Mountain Energy Company
NRG Home Solutions Product LLC
Reliant Energy Retail Holdings, LLC
Gregory Partners, LLC
NRG Homer City Services LLC
Reliant Energy Retail Services, LLC
Gregory Power Partners LLC
NRG Huntley Operations Inc.
RERH Holdings, LLC
Huntley Power LLC
NRG HQ DG LLC
Saguaro Power LLC
Independence Energy Alliance LLC
NRG Identity Protect LLC
Somerset Operations Inc.
Independence Energy Group LLC
NRG Ilion Limited Partnership
Somerset Power LLC
Independence Energy Natural Gas LLC
NRG Ilion LP LLC
Texas Genco GP, LLC
Indian River Operations Inc.
NRG International LLC
Texas Genco Holdings, Inc.
Indian River Power LLC
NRG Maintenance Services LLC
Texas Genco LP, LLC
Keystone Power LLC
NRG Mextrans Inc.
Texas Genco Services, LP
Langford Wind Power, LLC
NRG MidAtlantic Affiliate Services Inc.
US Retailers LLC
Louisiana Generating LLC
NRG Middletown Operations Inc.
Vienna Operations Inc.
Meriden Gas Turbines LLC
NRG Montville Operations Inc.
Vienna Power LLC
Middletown Power LLC
NRG New Roads Holdings LLC
WCP (Generation) Holdings LLC
Montville Power LLC
NRG North Central Operations Inc.
West Coast Power LLC
NEO Corporation
NRG Northeast Affiliate Services Inc.
 
 
 
 
 
 
 
 
 
 

51



NRG conducts much of its business through and derives much of its income from its subsidiaries. Therefore, the Company's ability to make required payments with respect to its indebtedness and other obligations depends on the financial results and condition of its subsidiaries and NRG's ability to receive funds from its subsidiaries. There are no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to NRG. However, there may be restrictions for certain non-guarantor subsidiaries.
The following condensed consolidating financial information presents the financial information of NRG Energy, Inc., the guarantor subsidiaries and the non-guarantor subsidiaries in accordance with Rule 3-10 under the SEC Regulation S-X. The financial information may not necessarily be indicative of results of operations or financial position had the guarantor subsidiaries or non-guarantor subsidiaries operated as independent entities.
In this presentation, NRG Energy, Inc. consists of parent company operations. Guarantor subsidiaries and non-guarantor subsidiaries of NRG are reported on an equity basis. For companies acquired, the fair values of the assets and liabilities acquired have been presented on a push-down accounting basis.

52



NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the three months ended September 30, 2017
(Unaudited)
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 
Consolidated
 
(In millions)
Operating Revenues
 
 
 
 
 
 
 
 
 
Total operating revenues
$
2,160

 
$
1,021

 
$

 
$
(132
)
 
$
3,049

Operating Costs and Expenses
 
 
 
 
 
 
 
 
 
Cost of operations
1,588

 
682

 
15

 
(129
)
 
2,156

Depreciation and amortization
104

 
160

 
8

 

 
272

Impairment losses

 
14

 

 

 
14

Selling, general and administrative
97

 
29

 
88

 
(1
)
 
213

Reorganization

 

 
18

 

 
18

Development activity expenses

 
9

 
5

 

 
14

Total operating costs and expenses
1,789

 
894

 
134

 
(130
)
 
2,687

     Other income - affiliate

 

 
14

 

 
14

Operating Income/(Loss)
371

 
127

 
(120
)
 
(2
)
 
376

Other Income/(Expense)
 
 
 
 
 
 
 
 
 
Equity in losses of consolidated subsidiaries
(41
)
 
(9
)
 
(134
)
 
184

 

Equity in (losses)/earnings of unconsolidated affiliates

 
(606
)
 
666

 
(33
)
 
27

Other income
7

 
3

 
5

 

 
15

Loss on debt extinguishment

 
(1
)
 

 

 
(1
)
Interest expense
(4
)
 
(103
)
 
(114
)
 

 
(221
)
Total other (expense)/income
(38
)
 
(716
)
 
423

 
151

 
(180
)
Income/(Loss) from Continuing Operations Before Income Taxes
333

 
(589
)
 
303

 
149

 
196

Income tax expense/(benefit)
113

 
(209
)
 
102

 

 
6

Income/(Loss) from Continuing Operations
220

 
(380
)
 
201

 
149

 
190

Loss from Discontinued Operations, net of income tax

 
(27
)
 

 

 
(27
)
Net Income/(Loss)
220

 
(407
)
 
201

 
149

 
163

Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interests

 
(3
)
 
30

 
(35
)
 
(8
)
Net Income/(Loss) Attributable to
NRG Energy, Inc.
$
220

 
$
(404
)
 
$
171

 
$
184

 
$
171

(a)
All significant intercompany transactions have been eliminated in consolidation.









53




NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the nine months ended September 30, 2017
(Unaudited)
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 
Consolidated
 
(In millions)
Operating Revenues
 
 
 
 
 
 
 
 
 
Total operating revenues
$
5,517


$
2,872


$


$
(257
)

$
8,132

Operating Costs and Expenses
 
 
 
 
 
 
 
 
 
Cost of operations
4,156

 
1,904

 
46

 
(254
)
 
5,852

Depreciation and amortization
307

 
458

 
24

 

 
789

Impairment losses
42

 
35

 

 

 
77

Selling, general and administrative
281

 
115

 
304

 
(3
)
 
697

Reorganization

 

 
18

 

 
18

Development activity expenses

 
34

 
15

 

 
49

Total operating costs and expenses
4,786

 
2,546

 
407

 
(257
)
 
7,482

     Other income - affiliate

 

 
104

 

 
104

Gain on sale of assets
4

 

 

 

 
4

Operating Income/(Loss)
735

 
326

 
(303
)
 

 
758

Other Income/(Expense)
 
 
 
 
 
 
 
 
 
Equity in losses of consolidated subsidiaries
(61
)
 
(66
)
 
(182
)
 
309

 

Equity in earnings/(losses) of unconsolidated affiliates

 
101

 
(3
)
 
(69
)
 
29

Other income
8

 
15

 
10

 

 
33

Loss on debt extinguishment

 
(3
)
 

 

 
(3
)
Interest expense
(11
)
 
(328
)
 
(353
)
 

 
(692
)
Total other expense
(64
)
 
(281
)
 
(528
)
 
240

 
(633
)
Income/(Loss) from Continuing Operations Before Income Taxes
671

 
45

 
(831
)
 
240

 
125

Income tax expense/(benefit)
244

 
28

 
(267
)
 

 
5

Income/(Loss) from Continuing Operations
427

 
17

 
(564
)
 
240

 
120

Loss from Discontinued Operations, net of income tax

 
(802
)
 

 

 
(802
)
Net Income/(Loss)
427

 
(785
)
 
(564
)
 
240

 
(682
)
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interests

 
(49
)
 
55

 
(69
)
 
(63
)
Net Income/(Loss) Attributable to
NRG Energy, Inc.
$
427

 
$
(736
)
 
$
(619
)
 
$
309

 
$
(619
)
(a)
All significant intercompany transactions have been eliminated in consolidation.


54



NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)
For the three months ended September 30, 2017
(Unaudited)
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 
Consolidated
 
(In millions)
Net Income/(Loss)
$
220

 
$
(407
)
 
$
201

 
$
149

 
$
163

Other Comprehensive Income/(Loss), net of tax
 
 
 
 
 
 
 
 
 
Unrealized gain on derivatives, net

 
7

 
7

 
(7
)
 
7

Foreign currency translation adjustments, net
2

 
2

 
2

 
(4
)
 
2

Available-for-sale securities, net

 

 
1

 

 
1

Defined benefit plans, net

 

 
(2
)
 
1

 
(1
)
Other comprehensive income
2

 
9

 
8

 
(10
)
 
9

Comprehensive Income/(Loss)
222

 
(398
)
 
209

 
139

 
172

Less: Comprehensive income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interest

 

 
30

 
(35
)
 
(5
)
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.
$
222

 
$
(398
)
 
$
179

 
$
174

 
$
177

(a)
All significant intercompany transactions have been eliminated in consolidation.






















55



NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)
For the nine months ended September 30, 2017
(Unaudited)
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 
Consolidated
 
(In millions)
Net Income/(Loss)
$
427

 
$
(785
)
 
$
(564
)
 
$
240

 
$
(682
)
Other Comprehensive Income/(Loss), net of tax
 
 
 
 
 
 
 
 
 
Unrealized gain on derivatives, net

 
6

 
7

 
(7
)
 
6

Foreign currency translation adjustments, net
7

 
7

 
9

 
(13
)
 
10

Available-for-sale securities, net

 

 
2

 

 
2

Defined benefit plans, net

 
29

 
25

 
(28
)
 
26

Other comprehensive income
7

 
42

 
43

 
(48
)
 
44

Comprehensive Income/(Loss)
434

 
(743
)
 
(521
)
 
192

 
(638
)
Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest

 
(47
)
 
55

 
(69
)
 
(61
)
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.
$
434

 
$
(696
)
 
$
(576
)
 
$
261

 
$
(577
)
(a)
All significant intercompany transactions have been eliminated in consolidation.



56





NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
September 30, 2017
(Unaudited)
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 
Consolidated
ASSETS
(In millions)
Current Assets
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
(20
)
 
$
350

 
$
893

 
$

 
$
1,223

Funds deposited by counterparties
29

 
2

 

 

 
31

Restricted cash
14

 
523

 

 

 
537

Accounts receivable - trade, net
876

 
395

 
3

 

 
1,274

Accounts receivable - affiliate
222

 
191

 
(22
)
 
(337
)
 
54

Inventory
406

 
224

 

 

 
630

Derivative instruments
438

 
106

 
5

 
(74
)
 
475

Cash collateral posted in support of energy risk management activities
190

 
13

 

 

 
203

Prepayments and other current assets
108

 
147

 
45

 

 
300

Current assets - held for sale

 
33

 

 

 
33

Total current assets
2,263

 
1,984

 
924


(411
)
 
4,760

Net property, plant and equipment
3,980

 
11,142

 
236

 
(26
)
 
15,332

Other Assets
 
 
 
 
 
 
 
 
 
Investment in subsidiaries
1,098

 
1,004

 
9,409

 
(11,511
)
 

Equity investments in affiliates

 
1,135

 
3

 

 
1,138

Notes receivable, less current portion

 
5

 

 

 
5

Goodwill
359

 
303

 

 

 
662

Intangible assets, net
520

 
1,321

 

 
(3
)
 
1,838

Nuclear decommissioning trust fund
670

 

 

 

 
670

Derivative instruments
187

 
38

 
27

 
(46
)
 
206

Deferred income tax
(5
)
 
(148
)
 
358

 

 
205

Non-current assets held-for-sale

 
10

 

 

 
10

Other non-current assets
63

 
520

 
61

 

 
644

Total other assets
2,892

 
4,188

 
9,858

 
(11,560
)
 
5,378

Total Assets
$
9,135

 
$
17,314

 
$
11,018

 
$
(11,997
)
 
$
25,470

LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
 
 
 
 
 
 
Current Liabilities
 
 
 
 
 
 
 
 
 
Current portion of long-term debt and capital leases
$

 
$
623

 
$
624

 
$

 
$
1,247

Accounts payable
599

 
285

 
31

 

 
915

Accounts payable — affiliate
528

 
(340
)
 
146

 
(338
)
 
(4
)
Derivative instruments
418

 
178

 

 
(74
)
 
522

Cash collateral received in support of energy risk management activities
29

 
2

 

 

 
31

Accrued expenses and other current liabilities
301

 
57

 
472

 

 
830

Accrued expenses and other current liabilities-affiliate

 
164

 

 

 
164

Total current liabilities
1,875

 
969

 
1,273

 
(412
)
 
3,705

Other Liabilities
 
 
 
 
 
 
 
 
 
Long-term debt and capital leases
244

 
8,644

 
6,770

 

 
15,658

Nuclear decommissioning reserve
265

 

 

 

 
265

Nuclear decommissioning trust liability
397

 

 

 

 
397

Deferred income taxes
428

 

 
(407
)
 

 
21

Derivative instruments
194

 
159

 

 
(46
)
 
307

Out-of-market contracts, net
69

 
144

 

 

 
213

Non-current liabilities held-for-sale

 
13

 

 

 
13

Other non-current liabilities
377

 
315

 
424

 

 
1,116

Total non-current liabilities
1,974

 
9,275

 
6,787

 
(46
)
 
17,990

Total liabilities
3,849

 
10,244

 
8,060

 
(458
)
 
21,695

Redeemable noncontrolling interest in subsidiaries

 
85

 

 

 
85

Stockholders’ Equity
5,286

 
6,985

 
2,958

 
(11,539
)
 
3,690

Total Liabilities and Stockholders’ Equity
$
9,135

 
$
17,314

 
$
11,018

 
$
(11,997
)
 
$
25,470

(a)
All significant intercompany transactions have been eliminated in consolidation.

57



NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the nine months ended September 30, 2017 (Unaudited)
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 
Consolidated
 
(In millions)
Cash Flows from Operating Activities
 
 
 
 
 
 
 
 
 
Net income/(loss)
$
427

 
$
(785
)
 
$
(564
)
 
$
240

 
$
(682
)
Loss from discontinued operations

 
(802
)
 

 

 
(802
)
Net income/(loss) from continuing operations
427

 
17

 
(564
)
 
240

 
120

Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
 
 
 
 
 
 
 
 

Distributions from unconsolidated affiliates

 
60

 

 
(7
)
 
53

Equity in losses/(earnings) of unconsolidated affiliates

 
(101
)
 
3

 
69

 
(29
)
Depreciation and amortization
307

 
458

 
24

 

 
789

Provision for bad debts
40

 
2

 
15

 

 
57

Amortization of nuclear fuel
37

 

 

 

 
37

Amortization of financing costs and debt discount/premiums

 
31

 
13

 

 
44

Adjustment for debt extinguishment

 
3

 

 

 
3

Amortization of intangibles and out-of-market contracts
20

 
59

 

 

 
79

Amortization of unearned equity compensation

 

 
27

 

 
27

Impairment losses
42

 
35

 

 

 
77

Changes in deferred income taxes and liability for uncertain tax benefits
244

 
28

 
(246
)
 

 
26

Changes in nuclear decommissioning trust liability
20

 

 



 
20

Changes in derivative instruments
(11
)
 
32

 
12

 
(8
)
 
25

Changes in collateral deposits supporting energy risk management activities
(126
)
 
23

 

 

 
(103
)
Proceeds from sale of emission allowances
21

 

 

 

 
21

Gain on sale of assets
(22
)
 

 

 

 
(22
)
Cash (used)/provided by changes in other working capital
(958
)
 
(523
)
 
1,395

 
(294
)
 
(380
)
Cash provided by continuing operations
41

 
124

 
679

 

 
844

Cash used by discontinued operations

 
(38
)
 

 

 
(38
)
Net Cash Provided by Operating Activities
41

 
86

 
679

 

 
806

Cash Flows from Investing Activities
 
 
 
 
 
 
 
 
 

Dividends from NRG Yield, Inc.

 

 
69

 
(69
)
 

Acquisition of Drop Down Assets, net of cash acquired

 
(176
)
 

 
176

 

Intercompany dividends

 

 
129

 
(129
)
 

Acquisition of business, net of cash acquired

 
(36
)
 

 

 
(36
)
Capital expenditures
(135
)
 
(606
)
 
(19
)
 

 
(760
)
Decrease in notes receivable

 
11

 

 

 
11

Purchases of emission allowances
(47
)
 

 

 

 
(47
)
Proceeds from sale of emission allowances
105

 

 

 

 
105

Investments in nuclear decommissioning trust fund securities
(402
)
 

 

 

 
(402
)
Proceeds from sales of nuclear decommissioning trust fund securities
382

 

 

 

 
382

Proceeds from renewable energy grants and state rebates
8

 



 

 
8

Proceeds from sale of assets, net of cash disposed of
36

 

 

 

 
36

Investments in unconsolidated affiliates

 
(31
)
 

 

 
(31
)
Other
22

 

 

 

 
22

Cash (used)/provided by continuing operations
(31
)
 
(838
)
 
179

 
(22
)
 
(712
)
Cash used by discontinued operations

 
(53
)
 

 

 
(53
)
Net Cash (Used)/Provided by Investing Activities
(31
)
 
(891
)
 
179

 
(22
)
 
(765
)
Cash Flows from Financing Activities


 
 

 
 

 
 
 
 
Dividends from NRG Yield, Inc.

 
(69
)
 

 
69

 

Payments from/(for) intercompany loans
9

 
417

 
(426
)
 

 

Acquisition of Drop Down Assets, net of cash acquired

 

 
176

 
(176
)
 

Intercompany dividends

 
(129
)
 

 
129

 

Payment of dividends to common and preferred stockholders

 

 
(28
)
 

 
(28
)
Net receipts from settlement of acquired derivatives that include financing elements

 
2

 

 

 
2

Proceeds from issuance of long-term debt

 
920

 
214

 

 
1,134

Payments for short and long-term debt

 
(493
)
 
(219
)
 

 
(712
)
Receivable from affiliate

 
(125
)
 

 

 
(125
)
Contributions from, net of distributions to, noncontrolling interest in subsidiaries

 
65

 

 

 
65

Payment of debt issuance costs

 
(38
)
 
(5
)
 

 
(43
)
Other - contingent consideration

 
(10
)
 

 

 
(10
)
Cash provided/(used) by continuing operations
9

 
540

 
(288
)
 
22

 
283

Cash used by discontinued operations

 
(224
)
 

 

 
(224
)
Net Cash Provided/(Used) by Financing Activities
9

 
316

 
(288
)
 
22

 
59

Change in cash from discontinued operations

 
(315
)
 

 

 
(315
)
Effect of exchange rate changes on cash and cash equivalents

 
(10
)
 

 

 
(10
)
Net Increase/(Decrease) in Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties
19

 
(184
)
 
570

 

 
405

Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at Beginning of Period
4

 
1,059

 
323

 

 
1,386

Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at End of Period
$
23


$
875


$
893


$

 
$
1,791

(a) All significant intercompany transactions have been eliminated in consolidation.

58



NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the three months ended September 30, 2016
(Unaudited)
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 
Consolidated
 
(In millions)
Operating Revenues
 
 
 
 
 
 
 
 
 
Total operating revenues
$
2,424

 
$
1,090

 
$

 
$
(93
)
 
$
3,421

Operating Costs and Expenses
 
 
 
 
 
 
 
 
 
Cost of operations
1,719

 
804

 
10

 
(93
)
 
2,440

Depreciation and amortization
147

 
144

 
7

 

 
298

Impairment losses
8

 
1

 

 

 
9

Selling, general and administrative
115

 
50

 
112

 

 
277

Development activity expenses

 
10

 
11

 

 
21

Total operating costs and expenses
1,989

 
1,009

 
140

 
(93
)
 
3,045

     Other income - affiliate

 

 
48

 

 
48

Gain on sale of assets

 

 
4

 

 
4

Operating Income/(Loss)
435

 
81

 
(88
)
 

 
428

Other Income/(Expense)
 
 
 
 
 

 
 
 
 
Equity in (losses)/earnings of consolidated subsidiaries
(114
)
 
(10
)
 
562

 
(438
)
 

Equity in earnings/(losses) of unconsolidated affiliates
2

 
75

 
(12
)
 
(49
)
 
16

Loss on investment

 
(8
)
 

 

 
(8
)
Other income/(loss), net
1

 
6

 

 

 
7

Loss on debt extinguishment

 

 
(50
)
 

 
(50
)
Interest expense
(4
)
 
(104
)
 
(129
)
 

 
(237
)
Total other expense
(115
)
 
(41
)
 
371

 
(487
)
 
(272
)
Income from Continuing Operations Before Income Taxes
320

 
40

 
283

 
(487
)
 
156

Income tax expense/(benefit)
134

 
45

 
(151
)
 

 
28

Income from Continuing Operations
186

 
(5
)
 
434

 
(487
)
 
128

Income from Discontinued Operations, net of income tax

 
263

 
2

 

 
265

Net Income
186

 
258

 
436

 
(487
)
 
393

Less: Net income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interest

 
6

 
34

 
(49
)
 
(9
)
Net Income Attributable to NRG Energy, Inc.
$
186

 
$
252

 
$
402

 
$
(438
)
 
$
402

(a)
All significant intercompany transactions have been eliminated in consolidation.

59



NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the nine months ended September 30, 2016
(Unaudited)
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 
Consolidated
 
(In millions)
Operating Revenues
 
 
 
 
 
 
 
 
 
Total operating revenues
$
6,079

 
$
2,400

 
$

 
$
(151
)
 
$
8,328

Operating Costs and Expenses
 
 
 
 
 
 
 
 
 
Cost of operations
4,278

 
1,558

 
29

 
(154
)
 
5,711

Depreciation and amortization
372

 
435

 
19

 

 
826

Impairment losses
8

 
57

 

 

 
65

Selling, general and administrative
306

 
144

 
351

 

 
801

Development activity expenses

 
42

 
23

 

 
65

Total operating costs and expenses
4,964

 
2,236

 
422

 
(154
)
 
7,468

     Other income - affiliate

 

 
144

 

 
144

Loss on sale of assets

 

 
(79
)
 

 
(79
)
Operating Income/(Loss)
1,115

 
164

 
(357
)
 
3

 
925

Other Income/(Expense)
 
 
 
 
 

 
 
 
 
Equity in (losses)/earnings of consolidated subsidiaries
(195
)
 
(80
)
 
904

 
(629
)
 

Equity in earnings/(losses) of unconsolidated affiliates
5

 
114

 
(2
)
 
(104
)
 
13

Impairment loss on investment

 
(147
)
 

 

 
(147
)
Other income, net
3

 
25

 
2

 
(1
)
 
29

Loss on debt extinguishment

 
(4
)
 
(115
)
 

 
(119
)
Interest expense
(11
)
 
(312
)
 
(395
)
 


 
(718
)
Total other (expense)/income
(198
)
 
(404
)
 
394

 
(734
)
 
(942
)
Income/(Loss) Before Income Taxes
917

 
(240
)
 
37

 
(731
)
 
(17
)
Income tax expense/(benefit)
362

 
(49
)
 
(238
)
 

 
75

Income/(Loss) from Continuing Operations
555

 
(191
)
 
275

 
(731
)
 
(92
)
Income from Discontinued Operations, net of income tax

 
248

 
8

 

 
256

Net Income
555

 
57

 
283

 
(731
)
 
164

Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest

 
(17
)
 
70

 
(102
)
 
(49
)
Net Income Attributable to NRG Energy, Inc.
$
555

 
$
74

 
$
213

 
$
(629
)
 
$
213

(a)
All significant intercompany transactions have been eliminated in consolidation.


60



NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)
For the three months ended September 30, 2016
(Unaudited)
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 
Consolidated
 
(In millions)
Net Income
$
186

 
$
258

 
$
436

 
$
(487
)
 
$
393

Other Comprehensive Income/(Loss), net of tax
 
 
 
 
 
 
 
 
 
Unrealized income on derivatives, net

 
40

 
26

 
(39
)
 
27

Foreign currency translation adjustments, net
2

 
2

 
4

 
(5
)
 
3

Defined benefit plans, net
54

 

 
(43
)
 
20

 
31

Other comprehensive loss
56

 
42

 
(13
)
 
(24
)
 
61

Comprehensive Income
242

 
300

 
423

 
(511
)
 
454

Less: Comprehensive income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interest

 
13

 
34

 
(49
)
 
(2
)
Comprehensive Income Attributable to NRG Energy, Inc.
$
242

 
$
287

 
$
389

 
$
(462
)
 
$
456

(a)
All significant intercompany transactions have been eliminated in consolidation.








61



NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)
For the nine months ended September 30, 2016
(Unaudited)
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 
Consolidated
 
(In millions)
Net Income
$
555

 
$
57

 
$
283

 
$
(731
)
 
$
164

Other Comprehensive Income/(Loss), net of tax
 
 
 
 
 
 
 
 

Unrealized (loss)/gain on derivatives, net

 
(15
)
 
46

 
(39
)
 
(8
)
Foreign currency translation adjustments, net
4

 
4

 
6

 
(8
)
 
6

Available-for-sale securities, net

 

 
1

 

 
1

Defined benefit plans, net
55

 

 
(43
)
 
20

 
32

Other comprehensive income/(loss)
59

 
(11
)
 
10

 
(27
)
 
31

Comprehensive Income
614

 
46

 
293

 
(758
)
 
195

Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest

 
(38
)
 
70

 
(102
)
 
(70
)
Comprehensive Income Attributable to NRG Energy, Inc.
614

 
84

 
223

 
(656
)
 
265

Dividends for preferred shares

 

 
5

 

 
5

Gain on redemption of preferred shares

 

 
(78
)
 

 
(78
)
Comprehensive Income Available for Common Stockholders
$
614

 
$
84

 
$
296

 
$
(656
)
 
$
338

(a)
All significant intercompany transactions have been eliminated in consolidation.
















62



NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2016
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations (a)
 
Consolidated
ASSETS
(In millions)
Current Assets
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
(9
)
 
$
624

 
$
323

 
$

 
$
938

Funds deposited by counterparties
2

 

 

 

 
2

Restricted cash
11

 
435

 

 

 
446

Accounts receivable - trade, net
734

 
321

 
3

 

 
1,058

Accounts receivable - affiliate
307

 
(254
)
 
200

 
(139
)
 
114

Inventory
482

 
239

 

 

 
721

Derivative instruments
962

 
196

 
1

 
(92
)
 
1,067

Cash collateral posted in support of energy risk management activities
116

 
34

 

 

 
150

Current assets held-for-sale

 
9

 

 

 
9

Prepayments and other current assets
76

 
152

 
62

 

 
290

Current assets - discontinued operations

 
1,919

 

 

 
1,919

Total current assets
2,681

 
3,675

 
589

 
(231
)
 
6,714

Net Property, Plant and Equipment
4,219

 
10,926

 
251

 
(27
)
 
15,369

Other Assets
 
 
 
 
 
 
 
 
 
Investment in subsidiaries
1,090

 
1,054

 
10,128

 
(12,272
)
 

Equity investments in affiliates
(13
)
 
1,128

 
5

 

 
1,120

Notes receivable, less current portion

 
16

 

 

 
16

Goodwill
359

 
303

 

 

 
662

Intangible assets, net
592

 
1,384

 

 
(3
)
 
1,973

Nuclear decommissioning trust fund
610

 

 

 

 
610

Derivative instruments
144

 
44

 
36

 
(43
)
 
181

Deferred income taxes
3

 

 
222

 

 
225

Non-current assets held for sale

 
10

 

 

 
10

Other non-current assets
67

 
446

 
328

 

 
841

Non-current assets - discontinued operations

 
2,961

 

 

 
2,961

Total other assets
2,852

 
7,346

 
10,719

 
(12,318
)
 
8,599

Total Assets
$
9,752

 
$
21,947

 
$
11,559

 
$
(12,576
)
 
$
30,682

LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
 
 
 
 
 
 
Current Liabilities
 
 
 
 
 
 
 
 
 
Current portion of long-term debt and capital leases
$

 
$
498

 
$
18

 
$

 
$
516

Accounts payable
501

 
247

 
34

 

 
782

Accounts payable — affiliate
744

 
(452
)
 
(122
)
 
(139
)
 
31

Derivative instruments
947

 
237

 

 
(92
)
 
1,092

Cash collateral received in support of energy risk management activities
81

 

 

 

 
81

Accrued expenses and other current liabilities
316

 
209

 
465

 

 
990

Current liabilities - discontinued operations

 
1,210

 

 

 
1,210

Total current liabilities
2,589

 
1,949

 
395

 
(231
)
 
4,702

Other Liabilities
 
 
 
 
 
 
 
 
 
Long-term debt and capital leases
244

 
8,252

 
7,461

 

 
15,957

Nuclear decommissioning reserve
287

 

 

 

 
287

Nuclear decommissioning trust liability
339

 

 

 

 
339

Deferred income taxes
186

 
125

 
(291
)
 

 
20

Derivative instruments
157

 
170

 

 
(43
)
 
284

Out-of-market contracts, net
80

 
150

 

 

 
230

Non-current liabilities held-for-sale

 
11

 

 

 
11

Other non-current liabilities
396

 
456

 
324

 

 
1,176

Non-current liabilities - discontinued operations

 
3,184

 

 

 
3,184

Total non-current liabilities
1,689

 
12,348

 
7,494

 
(43
)
 
21,488

Total Liabilities
4,278

 
14,297

 
7,889

 
(274
)
 
26,190

Redeemable noncontrolling interest in subsidiaries

 
46

 

 

 
46

Stockholders’ Equity
5,474

 
7,604

 
3,670

 
(12,302
)
 
4,446

Total Liabilities and Stockholders’ Equity
$
9,752

 
$
21,947

 
$
11,559


$
(12,576
)
 
$
30,682

(a)
All significant intercompany transactions have been eliminated in consolidation.

63



NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the nine months ended September 30, 2016 (Unaudited)
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 
Consolidated
 
(In millions)
Cash Flows from Operating Activities
 
 
 
 
 
 
 
 
 
Net Income
$
555

 
$
57

 
$
283

 
$
(731
)
 
$
164

Less: Income from discontinued operations

 
248

 
8

 

 
256

Net income/(loss) from continuing operations
555

 
(191
)
 
275

 
(731
)
 
(92
)
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
 
 
 
 
 
 
 
 
 
Distributions from unconsolidated affiliates

 
65

 

 
(8
)
 
57

Equity in (earnings)/losses of unconsolidated affiliates
(5
)
 
(20
)
 
2

 
10

 
(13
)
Depreciation and amortization
372

 
435

 
19

 

 
826

Provision for bad debts
31

 
5

 

 

 
36

Amortization of nuclear fuel
39

 

 

 

 
39

Amortization of financing costs and debt discount/premiums

 
25

 
17

 

 
42

Adjustment for debt extinguishment

 
102

 
17

 

 
119

Amortization of intangibles and out-of-market contracts
32

 
99

 

 

 
131

Amortization of unearned equity compensation

 

 
23

 

 
23

Impairment losses
8

 
203

 

 

 
211

Changes in deferred income taxes and liability for uncertain tax benefits
(134
)
 
(90
)
 
253

 

 
29

Changes in nuclear decommissioning trust liability
24

 

 

 

 
24

Changes in derivative instruments
(173
)
 
206

 
(3
)
 

 
30

Changes in collateral posted supporting energy risk management activities
268

 
(7
)
 

 

 
261

Proceeds from sale of emission allowances
11

 

 

 

 
11

Loss on sale of assets

 

 
70

 

 
70

Cash (used)/provided by changes in other working capital
(827
)
 
168

 
(200
)
 
729

 
(130
)
Net cash provided by continuing operations
201

 
1,000


473



 
1,674

Cash provided by discontinued operations

 
67

 

 

 
67

Net Cash Provided by Operating Activities
201

 
1,067

 
473

 

 
1,741

Cash Flows from Investing Activities
 
 
 
 
 
 
 
 
 
Dividends from NRG Yield, Inc.

 

 
59

 
(59
)
 

Acquisition of September 2016 Drop Down assets, net of cash acquired

 
(77
)
 

 
77

 

Intercompany dividends

 

 
12

 
(12
)
 

Acquisition of businesses, net of cash acquired

 
(18
)
 

 

 
(18
)
Capital expenditures
(145
)
 
(474
)
 
(40
)
 

 
(659
)
Increase in notes receivable

 
2

 

 

 
2

Purchases of emission allowances
(32
)
 

 

 

 
(32
)
Proceeds from sale of emission allowances
47

 

 

 

 
47

Investments in nuclear decommissioning trust fund securities
(378
)
 

 

 

 
(378
)
Proceeds from sales of nuclear decommissioning trust fund securities
354

 

 

 

 
354

Proceeds from renewable energy grants and state rebates

 
11

 

 

 
11

Proceeds from sale of assets, net of cash disposed of

 
67

 
17

 

 
84

Investments in unconsolidated affiliates
2

 
(25
)
 

 

 
(23
)
Other
27

 
(4
)
 
8

 

 
31

Net cash (used)/provided by continuing operations
(125
)
 
(518
)
 
56


6

 
(581
)
Cash provided by discontinued operations

 
326

 

 

 
326

Net Cash (Used)/Provided by Investing Activities
(125
)
 
(192
)
 
56

 
6

 
(255
)
Cash Flows from Financing Activities
 
 
 
 
 
 
 
 
 
Dividends from NRG Yield, Inc.

 
(59
)
 

 
59

 

Payments (for)/from intercompany loans
(2
)
 
(134
)
 
136

 

 

Acquisition of September 2016 Drop Down assets, net of cash acquired

 

 
77

 
(77
)
 

Intercompany dividends
(52
)
 
40

 

 
12

 

Payment of dividends to common and preferred stockholders

 

 
(66
)
 

 
(66
)
Payment for preferred shares

 

 
(226
)
 

 
(226
)
Net receipts for settlement of acquired derivatives that include financing elements

 
6

 

 

 
6

Proceeds from issuance of long-term debt

 
1,097

 
4,140

 

 
5,237

Payments for short and long-term debt
(2
)
 
(811
)
 
(4,540
)
 

 
(5,353
)
Payments for debt extinguishment costs

 
(98
)
 

 

 
(98
)
Distributions from, net of contributions to, noncontrolling interest in subsidiaries

 
(127
)
 

 

 
(127
)
Proceeds from issuance of common stock

 

 
1

 

 
1

Payment of debt issuance costs

 
(17
)
 
(53
)
 

 
(70
)
Other
(3
)
 
(7
)
 

 

 
(10
)
Net cash used by continuing operations
(59
)
 
(110
)
 
(531
)
 
(6
)
 
(706
)
Cash provided by discontinued operations

 
119

 

 

 
119

Net Cash (Used)/Provided by Financing Activities
(59
)
 
9

 
(531
)
 
(6
)
 
(587
)
Change in cash from discontinued operations

 
512

 

 

 
512

Effect of exchange rate changes on cash and cash equivalents

 
(6
)
 

 

 
(6
)
Net Increase/(Decrease) in Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties
17

 
366

 
(2
)
 

 
381

Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at Beginning of Period

 
629

 
693

 

 
1,322

Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at End of Period
$
17

 
$
995

 
$
691

 
$

 
$
1,703

(a)
All significant intercompany transactions have been eliminated in consolidation.

64



ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
As you read this discussion and analysis, refer to NRG's Condensed Consolidated Statements of Operations to this Form 10-Q, which present the results of operations for the three and nine months ended September 30, 2017 and 2016. Also refer to NRG's 2016 Form 10-K, which includes detailed discussions of various items impacting the Company's business, results of operations and financial condition, including: Introduction and Overview section; NRG's Business Strategy section; Business section, including how regulation, weather, and other factors affect NRG's business; and Critical Accounting Policies and Estimates section.
The discussion and analysis below has been organized as follows:
Executive summary, including introduction and overview, business strategy, and changes to the business environment during the period, including environmental and regulatory matters;
Results of operations;
Financial condition, addressing liquidity position, sources and uses of liquidity, capital resources and requirements, commitments, and off-balance sheet arrangements; and
Known trends that may affect NRG's results of operations and financial condition in the future.

65



Executive Summary
Introduction and Overview
NRG Energy, Inc., or NRG or the Company, is a leading integrated power company built on the strength of a diverse competitive electric generation portfolio and leading retail electricity platform. NRG is continuously focused on excellence in operating performance of its existing assets and optimal hedging of generation assets and retail load operations, as well as serving the energy needs of end-use residential, commercial and industrial customers in competitive markets through multiple brands and channels. The Company owns and operates approximately 30,000 MW of generation; engages in the trading of wholesale energy, capacity and related products; transacts in and trades fuel and transportation services; and directly sells energy, services, and innovative, sustainable products and services to retail customers under the names “NRG”, "Reliant" and other retail brand names owned by NRG. NRG was incorporated as a Delaware corporation on May 29, 1992.
The following table summarizes NRG's global generation portfolio as of September 30, 2017, by operating segment:

 
 
Global Generation Portfolio(a)(b)
 
 
(In MW)
 
 
Generation
 
 
 
 
 
 
 
 
Generation Type
 
Gulf Coast
 
East/West (c)
 
Renewables(d) 
 
NRG Yield(e) 
 
Other(f) 
 
Total Global
Natural gas(g)
 
7,464

 
4,939

 

 
1,878

 

 
14,281

Coal
 
5,114

 
3,869

 

 

 

 
8,983

Oil
 

 
3,642

 

 
190

 

 
3,832

Nuclear
 
1,136

 

 

 

 

 
1,136

Wind
 

 

 
743

 
2,206

 

 
2,949

Utility Scale Solar
 

 

 
742

 
921

 

 
1,663

Distributed Solar
 

 

 
175

 
14

 
114

 
303

Total generation capacity(g)
 
13,714

 
12,450

 
1,660

 
5,209

 
114

 
33,147

Capacity attributable to noncontrolling interest(h)
 

 

 
(684
)
 
(2,342
)
 

 
(3,026
)
Total net generation capacity
 
13,714

 
12,450

 
976

 
2,867

 
114

 
30,121

(a) All Utility Scale Solar and Distributed Solar facilities are described in MW on an alternating current basis. MW figures provided represent nominal summer net MW capacity of power generated as adjusted for the Company's owned or leased interest excluding capacity from inactive/mothballed units.
(b)
GenOn, which represented 16,423 MW of global generation at December 31, 2016, was deconsolidated from NRG on June 14, 2017.
(c) Includes International and BETM.
(d) Includes Distributed Solar capacity from assets held by DGPV Holdco 1 and DGPV Holdco 2.
(e) Does not include NRG Yield, Inc.'s thermal converted (MWt) capacity, which is part of the NRG Yield operating segment.
(f) The Distributed Solar figure within "Other" includes the aggregate production capacity of installed and activated residential solar energy systems. Also includes capacity from operating portfolios of residential solar assets held by RPV Holdco.
(g) Natural gas generation does not include 51 MW related to the Miramar and El Cajon sites which were part of the San Diego Combustion Turbines and retired on January 1, 2017, and 106 MW related to Encina Unit 1 which was deactivated on March 31, 2017.
(h)
NRG Yield's total generation capacity includes 6 MWs for noncontrolling interest for Spring Canyon II and III. NRG Yield's total generation capacity net of this noncontrolling interest was 5,203 MWs.

GenOn
On June 14, 2017, GenOn, GenOn Americas Generation and certain of their directly and indirectly-owned subsidiaries, all of which are subsidiaries of NRG, filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas, Houston Division. As a result of the bankruptcy filings and beginning on June 14, 2017, GenOn and its subsidiaries, representing approximately 15,000 MW, were deconsolidated from NRG’s consolidated financial statements.


66



Transformation Plan
On July 12, 2017, NRG announced its Transformation Plan designed to significantly strengthen earnings and cost competitiveness, lower risk and volatility, and create significant shareholder value. The three-part, three-year plan is comprised of the following targets:
Operations and cost excellence — Cost savings and margin enhancement of $1,065 million recurring, which consists of $590 million of annual cost savings, a $215 million net margin enhancement program, $50 million annual reduction in maintenance capital expenditures, and $210 million in permanent selling, general and administrative expense reduction associated with asset sales.

Portfolio optimization — Targeting up to $4.0 billion of asset sale net cash proceeds, including divestitures of 6 GWs of conventional generation and businesses (excluding GenOn) and the expected monetization of 100% of its interest in NRG Yield, Inc. and its renewables platform.

Capital structure and allocation enhancements — A prioritized capital allocation strategy that targets a reduction in consolidated debt from approximately $19.5 billion ($18 billion net debt) to approximately $6.5 billion ($6 billion net debt). Following the completion of the contemplated asset sales, the Company expects $4.8-$6.3 billion in excess cash to be available for allocation through 2020, after achieving its targeted 3.0x net debt / Adjusted EBITDA corporate credit ratio.

The Company expects to fully implement the Transformation Plan by the end of 2020 with significant completion by the end of 2018. The Company expects to realize (i) $370 million of non-recurring working capital improvements through 2020 and (ii) approximately $290 million, one-time costs to achieve.

Regulatory Matters
The Company’s regulatory matters are described in the Company’s 2016 Form 10-K in Item 1, Business — Regulatory Matters. These matters have been updated below and in Note 16, Regulatory Matters, to the Condensed Consolidated Financial Statements of this Form 10-Q as found in Item 1.
As owners of power plants and participants in wholesale and retail energy markets, certain NRG entities are subject to regulation by various federal and state government agencies. These include the CFTC, FERC, NRC, and the PUCT, as well as other public utility commissions in certain states where NRG's generating, thermal, or distributed generation assets are located. In addition, NRG is subject to the market rules, procedures and protocols of the various ISO and RTO markets in which it participates. Likewise, certain NRG entities participating in the retail markets are subject to rules and regulations established by the states in which NRG entities are licensed to sell at retail. NRG must also comply with the mandatory reliability requirements imposed by NERC and the regional reliability entities in the regions where NRG operates.
NRG's operations within the ERCOT footprint are not subject to rate regulation by FERC, as they are deemed to operate solely within the ERCOT market and not in interstate commerce. These operations are subject to regulation by the PUCT, as well as to regulation by the NRC with respect to NRG's ownership interest in STP.

67



East Region
PJM
Minimum Offer Price Rule Exemption Appeal On July 7, 2017, the D.C. Circuit vacated a FERC order from 2013 related to an exemption to the Minimum Offer Price Rule, or MOPR, and remanded the issue back to FERC. On October 23, 2017, PJM re-filed its initial 2012 MOPR. FERC's ruling on PJM's renewed proposal could affect how generators participate in the PJM Base Residual Auction.
2020/2021 PJM Auction Results — On May 23, 2017, PJM announced the results of its 2020/2021 base residual auction. NRG, excluding GenOn, cleared approximately 3,992 MW of Capacity Performance product. NRG’s expected capacity revenues, excluding GenOn, from the base residual auction for the 2020/2021 delivery year are approximately $268 million. For results of the 2019/2020 PJM base residual auction, refer to Item 1 - Business of the 2016 Form 10-K.
The table below provides a detailed description of NRG’s 2020/2021 base residual auction result:
 
Capacity Performance Product
Zone
Cleared Capacity (MW)(a)
 
Price ($/MW-day)
COMED
3,315
 
$188.12
EMAAC
519
 
$187.87
MAAC
158
 
$86.04
Total
3,992
 
 
(a) Includes imports. Does not include capacity sold by NRG Curtailment Specialists.
New England
2020/2021 ISO-NE Auction Results — On February 6, 2017, ISO-NE announced the results of its 2020/2021 forward capacity auction. NRG cleared 2,641 MW at $5.297 KW per month providing expected annual capacity revenues of $167.9 million. The 333 MWs at Canal Unit 3, which previously cleared the tenth forward capacity auction with a seven year price lock at a price of $7.03 KW per month for the 2020/2021 deliverability year, are excluded from these results.

Peak Energy Rent Adjustment Complaint — On September 30, 2016, the New England Power Generators Association, or NEPGA, filed a complaint against ISO-NE asking FERC to find the Peak Energy Rent, or PER, unjust and unreasonable. The PER adjustment reduces capacity payments on days where energy prices exceed a pre-defined level, known as the "PER strike price." On January 9, 2017, FERC granted NEPGA’s complaint requiring a change to the methodology used to calculate the PER strike price. FERC also directed the parties to determine any refunds for PER paid between September 30, 2016 and May 31, 2018. On July 26, 2017, NEPGA filed settlement documents at FERC, which NRG supported. The settlement is pending at FERC. The outcome of this matter will determine the amount of refunds that the NRG fleet may receive as a result of negotiating the PER strike price methodology.
New York
New York Public Service Commission Retail Energy Market Proceedings — On February 23, 2016, the NYSPSC issued what it refers to as its “Retail Reset” order, or Reset Order, in docket 12-M-0476 et al.  Among other things, the Reset Order placed a price cap on energy supply offers and required many retail providers to seek affirmative consent from certain retail customers. Various parties have challenged the NYPSC’s ability to regulate rates charged by competitive suppliers in New York state court.  In conjunction with the court challenges, the NYPSC is scheduled to commence an evidentiary proceeding on the functioning of the competitive retail markets on November 29, 2017.  The outcome of this evidentiary and collaborative process, combined with the outcome of the appeal of the Appellate Division order, could affect the viability of the New York retail energy market.
General
State Out-Of-Market Subsidy Proposals — Certain states including Connecticut, New Jersey, Ohio and Pennsylvania have considered but have not enacted proposals to provide out-of-market subsidy payments to potentially uneconomic nuclear and fossil generating units.  NRG has opposed those efforts to provide out of market subsidies, and intends to continue opposing them in the future.   


68



West Region
CAISO
Puente Power Project — On October 5, 2017, the California Energy Commission, or CEC, the agency responsible for permitting the Puente Power Project, issued a statement on behalf of the committee of two Commissioners overseeing the permitting process stating their intention to issue a proposed decision that would deny a permit for the Puente Power Project. On October 16, 2017, NRG filed a motion to suspend the permitting proceeding for at least six months. A hearing on the motion was held on October 31, 2017, after which the CEC took the matter under submission subject to a written decision to be issued at an unspecified later date. If the CEC Commissioners accept the recommendation, and formally deny a permit for the Puente Power Project, then the project will not move forward.
Nuclear Operations
Decommissioning Trusts — Upon expiration of the operating licenses for the two generating units at STP, recently extended until 2047 and 2048, respectively, the co-owners of STP are required under federal law to decontaminate and decommission the STP facility. Under NRC regulations, a power reactor licensee generally must pre-fund the full amount of its estimated NRC decommissioning obligations unless it is a rate-regulated utility, or a state or municipal entity that sets its own rates, or has the benefit of a state-mandated non-bypassable charge available to periodically fund the decommissioning trust such that the trust, plus allowable earnings, will equal the estimated decommissioning obligations by the time the decommissioning is expected to begin.
Environmental Matters
NRG is subject to a wide range of environmental laws in the development, construction, ownership and operation of projects. These laws generally require that governmental permits and approvals be obtained before construction and maintained during operation of power plants. NRG is also subject to laws regarding the protection of wildlife, including migratory birds, eagles and threatened and endangered species. Requirements regarding GHGs, combustion byproducts, water discharge and use, and threatened and endangered species have been put in place in recent years. However, under the current U.S. presidential administration, some of these rules are being reconsidered and reviewed. Future laws may require the addition of emissions controls or other environmental controls or impose restrictions on the operations of the Company's facilities, which could have a material effect on the Company's operations. Complying with environmental laws involves significant capital and operating expenses. NRG decides to invest capital for environmental controls based on the relative certainty of the requirements, an evaluation of compliance options, and the expected economic returns on capital.  
A number of regulations with the potential to affect the Company and its facilities have been recently promulgated by the EPA but are being reconsidered, including ESPS/NSPS for GHGs, NAAQS revisions and implementation, and effluent guidelines. NRG is evaluating the potential outcomes and any resulting impacts of recently promulgated regulations that the EPA is now reconsidering and cannot fully predict such impacts until administrative reconsiderations and legal challenges are resolved. Federal and state environmental laws generally have become more stringent over time, although this trend could slow or pause in the near term with respect to federal laws under the current U.S. presidential administration. The Company’s environmental matters are described in the Company’s 2016 Form 10-K in Item 1, Business - Environmental Matters and Item 1A, Risk Factors. These matters have been updated in Item 1 — Note 17, Environmental Matters, to the Condensed Consolidated Financial Statements of this Form 10-Q and as follows.
National
Air
The CAA and the resulting regulations (as well as similar state and local requirements) have the potential to affect air emissions, operating practices and pollution control equipment required at power plants. Under the CAA, the EPA sets NAAQS for certain pollutants including SO2, ozone, and PM2.5. Many of the Company's facilities are located in or near areas that are classified by the EPA as not achieving certain NAAQS (non-attainment areas). The relevant NAAQS have historically become more stringent. The Company maintains a comprehensive compliance strategy to address continuing and new requirements. Complying with increasingly stringent NAAQS could require the installation of additional emissions control equipment at some NRG facilities or retiring of units if installing such controls is not economical. Significant changes to air regulatory programs affecting the Company are described below.
Ozone NAAQS — On October 26, 2015, the EPA promulgated a rule that reduces the ozone NAAQS to 0.070 ppm. Challenges to this rule have been stayed at the request of the EPA so that it can evaluate the rule. If the rule is not altered by the EPA and survives legal challenges, this more stringent NAAQS will obligate the states to develop plans to reduce NOx (an ozone precursor), which could affect some of the Company's units.

69



Clean Power Plan — The attention in recent years on GHG emissions has resulted in federal regulations and state legislative and regulatory action. In October 2015, the EPA finalized the Clean Power Plan, or CPP, addressing GHG emissions from existing EGUs. On February 9, 2016, the U.S. Supreme Court stayed the CPP. The D.C. Circuit heard oral argument on the legal challenges to the CPP in September 2016. At the EPA's request, the D.C. Circuit agreed on April 28, 2017 to hold the case in abeyance. On October 16, 2017, the EPA proposed a rule to repeal the CPP. Accordingly, the Company believes the CPP is not likely to survive.
 Byproducts, Wastes, Hazardous Materials and Contamination
In April 2015, the EPA finalized the rule regulating byproducts of coal combustion (e.g., ash and gypsum) as solid wastes under the RCRA. On September 13, 2017, the EPA granted the petition for reconsideration that the Utility Solid Waste Activities Group filed in May 2017. The Company has evaluated the impact of the new rule on the Company's consolidated financial position, results of operations, or cash flows and has accrued its environmental and asset retirement obligations under the rule based on current estimates as of September 30, 2017.
Nuclear Waste — The federal government's program to construct a nuclear waste repository at Yucca Mountain, Nevada was discontinued in 2010. Since 1998, the U.S. DOE has been in default of the federal government's obligations to begin accepting spent nuclear fuel, or SNF, and high-level radioactive waste, or HLW, under the U.S. Nuclear Waste Policy Act of 1982, or the Nuclear Waste Policy Act. Owners of nuclear plants, including the owners of STP, had been required to enter into contracts setting out the obligations of the owners and the U.S. DOE, including the fees to be paid by the owners for the U.S. DOE's services to license a spent fuel repository. Effective May 16, 2014, the U.S. DOE stopped collecting the fees.
On February 5, 2013, STPNOC entered into a settlement agreement with the U.S. DOE for payment of damages relating to the U.S. DOE's failure to accept SNF and HLW under the Nuclear Waste Policy Act through December 31, 2013, which was extended through an addendum dated January 24, 2014, to December 31, 2016. On December 12, 2016, STPNOC received the federal government's offer of another three-year extension of payment for continued failure to accept SNF and HLW. The proposal has been reviewed for adequacy and, with advice of counsel, was accepted. There are no facilities for the reprocessing or permanent disposal of SNF currently in operation in the U.S., nor has the NRC licensed any such facilities. STPNOC currently stores all SNF generated by its nuclear generating facilities in on-site storage pools.  Since STPNOC's SNF storage pools do not have sufficient storage capacity for the life of the units, STPNOC is proceeding to construct dry cask storage capability on-site. STPNOC plans to continue to assert claims against the U.S. DOE for damages relating to the U.S. DOE's failure to accept SNF and HLW.
Under the federal Low-Level Radioactive Waste Policy Act of 1980, as amended, the state of Texas is required to provide, either on its own or jointly with other states in a compact, for the disposal of all low-level radioactive waste generated within the state. STP's warehouse capacity is adequate for on-site storage until a site in Andrews County, Texas becomes fully operational.
Regional Environmental Developments
Gulf Coast Region
Texas Regional Haze — On October 17, 2017, the EPA promulgated a final rule creating a Texas-only SO2 cap-and-trade program to address regional haze. The program is scheduled to begin on January 1, 2019. Several of the Company's units in Texas will be affected by this rule.

East Region
Massachusetts Global Warming Solutions Act Proposed Regulation - In May 2016, the Massachusetts Supreme Judicial Court held that the Massachusetts DEP had not complied with the 2008 Global Warming Solutions Act, which requires establishing limits for sources of GHGs. The Court held that participation in RGGI was not sufficient.  In August 2017, the Massachusetts DEP finalized  a regulation that, if it survives legal challenges, would limit GHG emissions, and may limit operations, from electric generating facilities located in Massachusetts.  The final regulation has been challenged in The Commonwealth of Massachusetts Superior Court of Suffolk County.

 


70



Significant Events
The following significant events have occurred during 2017, as further described within this Management's Discussion and Analysis and the Condensed Consolidated Financial Statements:
NRG Transformation Plan
On July 12, 2017, NRG announced its Transformation Plan. The three-part, three-year plan is comprised of targets in the areas of operational and cost excellence, portfolio optimization, and capital structure and allocation enhancement.
GenOn Chapter 11 Bankruptcy Filing
On the Petition Date, the GenOn Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. As a result of the bankruptcy filings and beginning on the Petition Date, NRG no longer consolidates GenOn for financial reporting purposes, as discussed in more detail in Note 1, Basis of Presentation, Note 3, Discontinued Operations, Dispositions and Acquisitions and Note 14, Related Party Transactions of this Form 10-Q.
Transfers of Assets Under Common Control
On March 27, 2017, NRG completed the sale of the following projects to NRG Yield, Inc.: (i) a 16% interest in the Agua Caliente solar project, and (ii) NRG's interests in seven utility-scale solar projects located in Utah, which have reached commercial operations, for $130 million cash consideration, as discussed in more detail in Note 3, Discontinued Operations, Dispositions and Acquisitions of this Form 10-Q.
On August 1, 2017, NRG closed on the sale of its remaining 25% interest in NRG Wind TE Holdco, a portfolio of 12 wind projects, to NRG Yield, Inc. for total cash consideration of $44 million, including working capital adjustments. The transaction also includes potential additional payments to NRG dependent upon actual energy prices for merchant periods beginning in 2027.
On October 17, 2017, the Company offered NRG Yield, Inc. the opportunity to purchase 100% of its ownership interest in Buckthorn Solar pursuant to the ROFO Agreement.
On November 1, 2017, NRG completed the sale of a 38 MW solar portfolio primarily comprised of assets from SPP funds in addition to other projects developed by NRG, to NRG Yield, Inc. for cash consideration of $71 million, plus $3 million in working capital adjustments.
Financing Activities
On May 26, 2017, Carlsbad Energy Holdings, LLC entered into a note payable agreement with financial institutions for the issuance of up to $407 million of senior secured notes that bear interest at a rate of 4.12%, and mature on October 31, 2038, as discussed in more detail in Note 8, Debt and Capital Leases.
On June 12, 2017, NRG repaid $125 million on the Revolving Credit Facility. As of September 30, 2017, there were no cash borrowings outstanding on the revolver.
On October 16, 2017, NRG redeemed all of its outstanding 7.625% Senior Notes due 2018 and all of its outstanding 7.875% Senior Notes due 2021 for $630 million, which included $14 million in accrued interest.
Operational Matters
Extreme Weather Events
In late August 2017, Hurricane Harvey made landfall on the Texas coast.  During the third quarter of 2017, the Company’s Retail business was impacted by Hurricane Harvey by approximately $20 million.

In addition, during August 2017, NRG's Cottonwood generating station was damaged when the Sabine River Authority opened the floodgates of the Toledo Bend reservoir, which resulted in downstream flooding of the Sabine River. The generating station was returned to service during the fourth quarter of 2017. NRG is continuing to work with insurers on potential property insurance recovery and does not anticipate recovery from business interruption insurance due to the short period of the outage. The Company estimates the impact of the Cottonwood damage and Hurricane Harvey on Gulf Coast Generation to be approximately $20 million.

71



Carlsbad Energy Center Power Purchase Tolling Agreement
As of May 1, 2017, NRG’s subsidiary, Carlsbad Energy Center LLC, achieved the Conditions Precedent, or CP, Satisfaction Date under its power purchase tolling agreement with San Diego Gas & Electric Company for the Carlsbad Energy Center.  The CP Satisfaction Date is the date on which specified conditions precedent under the power purchase tolling agreement have either been satisfied or waived. 
Bacliff Project
On June 16, 2017, the Company provided notice to BTEC New Albany, LLC that NRG Texas Power LLC was exercising its right to terminate the Amended and Restated Membership Interest Purchase Agreement, or MIPA, due to the Bacliff Project, a new peaking facility at the former P.H. Robinson Electric Generating Station, not achieving commercial completion by the contractual expiration date of May 31, 2017. On July 14, 2017, the Company gave notice to BTEC New Albany, LLC that it owes NRG Texas Power LLC approximately $48 million under the terminated MIPA, consisting of $38 million in purchaser incurred costs and $10 million in liquidated damages.
Will County Unit 4
In May 2017, NRG's Will County Unit 4 suffered an equipment failure that is projected to result in an extended outage. At this time, the Company expects to complete repairs and return the unit to service in by early 2018.
Trends Affecting Results of Operations and Future Business Performance
In addition to below, the Company’s trends are described in the Company’s 2016 Form 10-K in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations - Trends Affecting Results of Operations and Future Business Performance.

ERCOT Retirements — A number of announced retirement notices of coal generating facilities in Texas could lower reserve margins in ERCOT. This trend of retirement notices could have an effect on the Company’s results of operations and future business performance, particularly in the ERCOT market.

Changes in Accounting Standards
See Note 2, Summary of Significant Accounting Policies, to the Condensed Consolidated Financial Statements of this Form 10-Q, for a discussion of recent accounting developments.

72



Consolidated Results of Operations
The following table provides selected financial information for the Company:
 
Three months ended September 30,
 
Nine months ended September 30,
(In millions except otherwise noted)
2017
 
2016
 
Change
 
2017
 
2016
 
Change
Operating Revenues
 
 
 
 
 
 
 
 
 
 
 
Energy revenue (a)
$
665

 
$
933

 
$
(268
)
 
$
1,908

 
$
2,478

 
$
(570
)
Capacity revenue (a)
335

 
303

 
32

 
894

 
937

 
(43
)
Retail revenue
1,934


2,015

 
(81
)
 
4,880

 
4,931

 
(51
)
Mark-to-market for economic hedging activities
26


62

 
(36
)
 
185

 
(360
)
 
545

Contract amortization
(12
)
 
(12
)
 

 
(41
)
 
(41
)
 

Other revenues (b)
101

 
120

 
(19
)
 
306

 
383

 
(77
)
Total operating revenues
3,049

 
3,421

 
(372
)
 
8,132

 
8,328

 
(196
)
Operating Costs and Expenses
 
 
 
 
 
 
 
 
 
 
 
Cost of sales (c)
1,679

 
1,847

 
168

 
4,362

 
4,526

 
164

Mark-to-market for economic hedging activities
50

 
149

 
99

 
168

 
(301
)
 
(469
)
Contract and emissions credit amortization (c)
8

 
11

 
3

 
24

 
34

 
10

Operations and maintenance
326

 
354

 
28

 
1,038

 
1,196

 
158

Other cost of operations
93

 
79

 
(14
)
 
260

 
256

 
(4
)
Total cost of operations
2,156

 
2,440

 
284

 
5,852

 
5,711

 
141

Depreciation and amortization
272

 
298

 
26

 
789

 
826

 
37

Impairment losses
14

 
9

 
(5
)
 
77

 
65

 
(12
)
Selling, general and administrative
213

 
277

 
64

 
697

 
801

 
104

Reorganization
18

 

 
(18
)
 
18

 

 
(18
)
Development costs
14

 
21

 
7

 
49

 
65

 
16

Total operating costs and expenses
2,687

 
3,045

 
358

 
7,482


7,468

 
(14
)
   Other income - affiliate
14

 
48

 
(34
)
 
104

 
144

 
(40
)
  Gain/(loss) on sale of assets

 
4

 
(4
)
 
4

 
(79
)
 
83

Operating Income
376

 
428

 
(52
)
 
758

 
925

 
(167
)
Other Income/(Expense)
 
 
 
 
 
 
 
 
 
 
 
Equity in earnings of unconsolidated affiliates
27

 
16

 
11

 
29

 
13

 
16

Impairment loss on investment

 
(8
)
 
8

 

 
(147
)
 
147

Other income, net
15

 
7

 
8

 
33

 
29

 
4

Loss on debt extinguishment, net
(1
)
 
(50
)
 
49

 
(3
)
 
(119
)
 
116

Interest expense
(221
)
 
(237
)
 
16

 
(692
)
 
(718
)
 
26

Total other expense
(180
)
 
(272
)
 
92

 
(633
)
 
(942
)
 
309

Income/(Loss) from Continuing Operations before Income Taxes
196

 
156

 
40

 
125


(17
)
 
142

Income tax expense
6

 
28

 
(22
)
 
5

 
75

 
(70
)
Income/(Loss) from Continuing Operations
190

 
128

 
62

 
120

 
(92
)
 
212

(Loss)/Income from discontinued operations, net of income tax
(27
)
 
265

 
(292
)
 
(802
)
 
256

 
(1,058
)
Net Income/(Loss)
163

 
393

 
(230
)
 
(682
)
 
164

 
(846
)
Less: Net loss attributable to noncontrolling interest and redeemable noncontrolling interest
(8
)
 
(9
)
 
1

 
(63
)
 
(49
)
 
(14
)
Net Income/(Loss) Attributable to NRG Energy, Inc.
$
171

 
$
402

 
$
(231
)
 
$
(619
)
 
$
213

 
$
(832
)
Business Metrics
 
 
 
 


 
 
 
 
 
 
Average natural gas price — Henry Hub ($/MMBtu)
$
3.00

 
$
2.81

 
7
%
 
$
3.17

 
$
2.29

 
38
%
(a) Includes realized gains and losses from financially settled transactions.
(b) Includes unrealized trading gains and losses.
(c) Includes amortization of SO2 and NOx credits and excludes amortization of RGGI credits.    

73



Management’s discussion of the results of operations for the three months ended September 30, 2017 and 2016
Electricity Prices
The following table summarizes average on peak power prices for each of the major markets in which NRG operates for the three months ended September 30, 2017 and 2016. The average on-peak power prices have generally decreased primarily due to the increase in natural gas prices for the three months ended September 30, 2017 as compared to the same period in 2016.
 
Average on Peak Power Price ($/MWh)
 
Three months ended September 30,
Region
2017
 
2016
 
Change %
Gulf Coast (a)
 
 
 
 
 
ERCOT - Houston (b)
$
33.09

 
$
33.12

 
 %
ERCOT - North(b)
29.35

 
30.47

 
(4
)%
MISO - Louisiana Hub(c)
39.56

 
39.83

 
(1
)%
East/West
 
 
 
 

    NY J/NYC(c)
37.42

 
42.50

 
(12
)%
    NEPOOL(c)
31.94

 
42.33

 
(25
)%
    PEPCO (PJM)(c)
38.81

 
42.57

 
(9
)%
    PJM West Hub(c)
35.10

 
38.84

 
(10
)%
CAISO - NP15(c)
46.69

 
38.13

 
22
 %
CAISO - SP15(c)
46.54

 
40.24

 
16
 %
(a) Gulf Coast region also transacts in PJM - West Hub.
(b) Average on peak power prices based on real time settlement prices as published by the respective ISOs.
(c) Average on peak power prices based on day ahead settlement prices as published by the respective ISOs.

The following table summarizes average realized power prices for each region in which NRG operates for the three months ended September 30, 2017 and 2016, which reflects the impact of settled hedges.
 
Average Realized Power Price ($/MWh)
 
Three months ended September 30,
Region
2017
 
2016
 
Change %
Gulf Coast
$
34.69

 
$
39.68

 
(13
)%
East/West
38.19

 
40.44

 
(6
)%
Though the average on peak power prices have decreased on average by 5%, average realized prices by region for the Company have generally fluctuated at a slower rate year-over-year due to the Company's multi-year hedging program.

Gross Margin
The Company calculates gross margin in order to evaluate operating performance as operating revenues less cost of sales, which includes cost of fuel, other costs of sales, contract and emission credit amortization and mark-to-market for economic hedging activities.
Economic Gross Margin
In addition to gross margin, the Company evaluates its operating performance using the measure of economic gross margin, which is not a GAAP measure and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Economic gross margin should be viewed as a supplement to and not a substitute for the Company's presentation of gross margin, which is the most directly comparable GAAP measure. Economic gross margin is not intended to represent gross margin. The Company believes that economic gross margin is useful to investors as it is a key operational measure reviewed by the Company's chief operating decision maker. Economic gross margin is defined as the sum of energy revenue, capacity revenue, retail revenue and other revenue, less cost of fuels and other cost of sales.
Economic gross margin does not include mark-to-market gains or losses on economic hedging activities, contract amortization, emission credit amortization, or other operating costs.

74



The below tables present the composition and reconciliation of gross margin and economic gross margin for the three months ended September 30, 2017 and 2016:
 
Three months ended September 30, 2017
 
Generation
 
 
 
 
 
 
 
 
 
 
(In millions)
Gulf Coast
 
East/West(a)
 
Subtotal
 
Retail
 
Renewables
 
NRG Yield
 
Corporate/Eliminations
 
Total
Energy revenue
$
540

 
$
243

 
$
783

 
$

 
$
119

 
$
146

 
$
(383
)
 
$
665

Capacity revenue
74

 
172

 
246

 

 
1

 
92

 
(4
)
 
335

Retail revenue

 

 

 
1,936

 

 

 
(2
)
 
1,934

Mark-to-market for economic hedging activities
133

 

 
133

 

 
5

 

 
(112
)
 
26

Contract amortization
5

 

 
5

 
1

 
(1
)
 
(18
)
 
1

 
(12
)
Other revenue (b)
41

 
16

 
57

 

 
20

 
44

 
(20
)
 
101

Operating revenue
793

 
431

 
1,224

 
1,937

 
144

 
264

 
(520
)
 
3,049

Cost of fuel
(292
)
 
(123
)
 
(415
)
 
(1
)
 
(1
)
 
(6
)
 
17

 
(406
)
Other cost of sales(c)
(102
)
 
(79
)
 
(181
)
 
(1,457
)
 
(3
)
 
(9
)
 
377

 
(1,273
)
Mark-to-market for economic hedging activities
2

 
10

 
12

 
(174
)
 

 

 
112

 
(50
)
Contract and emission credit amortization
(7
)
 
(1
)
 
(8
)
 

 

 

 

 
(8
)
Gross margin
$
394

 
$
238

 
$
632

 
$
305

 
$
140

 
$
249

 
$
(14
)
 
$
1,312

Less: Mark-to-market for economic hedging activities, net
135


10


145

 
(174
)

5





 
(24
)
Less: Contract and emission credit amortization, net
(2
)

(1
)

(3
)
 
1


(1
)

(18
)

1

 
(20
)
Economic gross margin
$
261

 
$
229


$
490


$
478


$
136


$
267


$
(15
)

$
1,356

Business Metrics
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
MWh sold (thousands)(d)(e)
15,568

 
6,363

 
 
 
 
 
928

 
1,544

 
 
 
 
MWh generated (thousands) (f)
14,185

 
4,106

 
 
 
 
 
928

 
2,261

 
 
 
 
(a) Includes International, BETM and Generation eliminations
(b) Renewables other revenue includes $7 million of intercompany revenue to NRG Yield.
(c) Includes purchased energy, capacity and emissions credits
(d) MWh sold excludes generation at facilities in East/West and NRG Yield that generate revenue under capacity agreements.
(e) Does not include thermal MWh of 9 thousand or MWt of 463 thousand for thermal sold by NRG Yield.
(f) Does not include thermal MWh of 44 thousand or MWt of 463 thousand for thermal generated by NRG Yield.

75



 
Three months ended September 30, 2016
 
Generation
 
 
 
 
 
 
 
 
 
 
(In millions)
Gulf Coast
 
East/West(a)
 
Subtotal
 
Retail
 
Renewables
 
NRG Yield
 
Corporate/Eliminations
 
Total
Energy revenue
$
650

 
$
362

 
$
1,012

 
$

 
$
127

 
$
158


$
(364
)
 
$
933

Capacity revenue
72

 
148

 
220

 

 

 
86

 
(3
)
 
303

Retail revenue

 

 

 
2,009

 

 

 
6

 
2,015

Mark-to-market for economic hedging activities
179

 
57

 
236

 
2

 
1

 

 
(177
)
 
62

Contract amortization
4

 

 
4

 
1

 
(1
)
 
(17
)
 
1

 
(12
)
Other revenue (b)
51

 
13

 
64

 

 
12

 
45

 
(1
)
 
120

Operating revenue
956

 
580

 
1,536

 
2,012

 
139

 
272

 
(538
)
 
3,421

Cost of fuel
(317
)
 
(190
)
 
(507
)
 
(1
)
 
(2
)
 
(7
)
 
18

 
(499
)
Other cost of sales(c)
(114
)
 
(83
)
 
(197
)
 
(1,484
)
 
(1
)
 
(11
)
 
345

 
(1,348
)
Mark-to-market for economic hedging activities
27

 
7

 
34

 
(360
)
 

 

 
177

 
(149
)
Contract and emission credit amortization
(9
)
 

 
(9
)
 
(2
)
 

 

 

 
(11
)
Gross margin
$
543

 
$
314

 
$
857

 
$
165

 
$
136

 
$
254

 
$
2

 
$
1,414

Less: Mark-to-market for economic hedging activities, net
206


64


270

 
(358
)

1





 
(87
)
Less: Contract and emission credit amortization, net
(5
)



(5
)
 
(1
)

(1
)

(17
)

1

 
(23
)
Economic gross margin
$
342

 
$
250

 
$
592

 
$
524

 
$
136

 
$
271

 
$
1

 
$
1,524

Business Metrics
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
MWh sold (thousands)(d)(e)
16,380

 
8,951

 
 
 
 
 
977

 
1,744

 
 
 
 
MWh generated (thousands) (f)
14,927

 
6,426

 
 
 
 
 
977

 
2,372

 
 
 
 
(a) Includes International, BETM and Generation eliminations.
(b) Renewables other revenue includes $5 million of intercompany revenue to NRG Yield.
(c) Includes purchased energy, capacity and emissions credits
(d) MWh sold excludes generation at facilities in the East, West and NRG Yield that generate revenue under capacity agreements.
(e) Does not include thermal MWh of 12 thousand or MWt of 496 thousand for thermal sold by NRG Yield.
(f) Does not include thermal MWh of 125 thousand or MWt of 496 thousand for thermal generated by NRG Yield.
The table below represents the weather metrics for the three months ended September 30, 2017 and 2016:
 
Three months ended September 30,
 
 
 
 
 
 
 
Weather Metrics
Gulf Coast
 
East/West
 
 
 
 
 
 
 
 
2017
 
 
 
 
 
 
 
 
 
 
 
CDDs (a)
1,528

 
770

 
 
 
 
 
 
 
 
HDDs (a)
1

 
34

 
 
 
 
 
 
 
 
2016
 
 
 
 
 
 
 
 
 
 
 
CDDs
1,655

 
806

 
 
 
 
 
 
 
 
HDDs

 
23

 
 
 
 
 
 
 
 
10 year average
 
 
 
 
 
 
 
 
 
 
 
CDDs
1,617

 
705

 
 
 
 
 
 
 
 
HDDs
6

 
40

 
 
 
 
 
 
 
 
(a)
National Oceanic and Atmospheric Administration-Climate Prediction Center - A Cooling Degree Day, or CDD, represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. A Heating Degree Day, or HDD, represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period.


76



Generation gross margin and economic gross margin
Generation gross margin decreased $225 million and economic gross margin decreased $102 million, both of which include intercompany sales, during the three months ended September 30, 2017, compared to the same period in 2016:

The table below describes the decrease in Generation gross margin and economic gross margin:

Gulf Coast Region
 
(In millions)
Lower gross margin due to a 12% decrease in average realized prices primarily in Texas due to lower hedged power prices
$
(76
)
Lower energy margin due to increased supply cost on load contracts
(13
)
Lower capacity margin on contract expirations and lower demand
(9
)
Higher gross margin due to increased generation primarily due to lower unplanned outages
16

Other
1

Decrease in economic gross margin
$
(81
)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges
(71
)
Increase in contract and emission credit amortization
3

Decrease in gross margin
$
(149
)
East/West
 
(In millions)
Lower gross margin due to a 37% decrease in generation driven by lower economic generation due to milder weather conditions and the Will County outage
$
(28
)
Lower gross margin from commercial optimization activities
(8
)
Higher gross margin due to a 38% increase in PJM capacity volumes coupled with a 140% increase in NY/NE realized capacity prices
21

Higher gross margin due to a 12% increase in average realized energy prices due to extreme heat in California and increased pricing during high demand periods in the East
10

Lower gross margin by BETM due to higher gains in 2016 on over the counter strategies, offset in small part by higher gains in 2017 on congestion strategies
(16
)
Decrease in economic gross margin
$
(21
)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges
(54
)
Decrease in contract and emission credit amortization
(1
)
Decrease in gross margin
$
(76
)




77



Retail gross margin and economic gross margin
The following is a discussion of gross margin and economic gross margin for Retail.
 
Three months ended September 30,
(In millions except otherwise noted)
2017
 
2016
Retail revenue
$
1,845

 
$
1,911

Supply management revenue
63

 
53

Capacity revenue
28

 
45

Customer mark-to-market

 
2

Contract amortization
1

 
1

Operating revenue (a)
1,937

 
2,012

Cost of sales (b)
(1,458
)
 
(1,485
)
Mark-to-market for economic hedging activities
(174
)
 
(360
)
Contract amortization

 
(2
)
Gross Margin
$
305

 
$
165

Less: Mark-to-market for economic hedging activities, net
(174
)
 
(358
)
Less: Contract and emission credit amortization, net
1

 
(1
)
Economic Gross Margin
$
478

 
$
524

 
 
 
 
Business Metrics
 
 
 
Mass electricity sales volume - GWh - Gulf Coast
11,935

 
11,996

Mass electricity sales volume - GWh - All other regions
1,724

 
1,986

C&I electricity sales volume — GWh - All regions
5,087

 
5,146

Natural gas sales volumes (MDth)
241

 
172

Average Retail Mass customer count (in thousands) 
2,884

 
2,786

Ending Retail Mass customer count (in thousands)
2,880

 
2,797

(a)
Includes intercompany sales of $2 million and $1 million in 2017 and 2016, respectively, representing sales from Retail to the Gulf Coast region.
(b)
Includes intercompany purchases of $365 million and $340 million in 2017 and 2016, respectively.

Retail gross margin increased $140 million and economic gross margin decreased $46 million for the three months ended September 30, 2017, compared to the same period in 2016, due to:
 
(In millions)
Lower gross margin due to lower rates to customers driven by customer product, term, and mix of $26 million or approximately $1.25 per MWh and higher supply costs of $10 million or approximately $0.50 per MWh driven primarily by an increase in power prices at the time of procurement
$
(36
)
Lower gross margin of $15 million due to a reduction in load of 477,000 MWh partially offset by $4 million in higher margin due to the lower unfavorable impacts of selling back excess supply due to milder weather conditions in 2017 as compared to 2016
(11
)
Lower gross margin of $9 million due to a reduction in load of 200,000 MWh, and the unfavorable impact of selling back excess supply along with $7 million of customer relief related to the impact of Hurricane Harvey in 2017
(16
)
Higher gross margin due to higher volumes driven by higher average customer usage and mix
17

Decrease in economic gross margin
$
(46
)
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges
184

Increase in contract and emission credit amortization
2

Increase in gross margin
$
140




78



Mark-to-market for Economic Hedging Activities
Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges and ineffectiveness on cash flow hedges. Total net mark-to-market results increased by $63 million during the three months ended September 30, 2017, compared to the same period in 2016.
The breakdown of gains and losses included in operating revenues and operating costs and expenses by region was as follows:
 
Three months ended September 30, 2017
 
Generation
 
 
 
 
 
 
 
 
 
Gulf Coast
 
East/West
 
Retail
 
Renewables
 
Eliminations(a)
 
Total
 
(In millions)
Mark-to-market results in operating revenues
 
 
 
 
 
 
 
 
 
 
 
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges
$
121

 
$
5

 
$

 
$
1

 
$
(68
)
 
$
59

Net unrealized gains/(losses) on open positions related to economic hedges
12

 
(5
)
 

 
4

 
(44
)
 
(33
)
Total mark-to-market gains/(losses) in operating revenues
$
133

 
$

 
$

 
$
5

 
$
(112
)
 
$
26

Mark-to-market results in operating costs and expenses
 
 
 
 
 
 
 
 
 
 
 
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges
$
(5
)
 
$
(1
)
 
$
(127
)
 
$

 
$
68

 
$
(65
)
Reversal of acquired gain positions related to economic hedges

 

 
(2
)
 

 

 
(2
)
Net unrealized gains/(losses) on open positions related to economic hedges
7

 
11

 
(45
)
 

 
44

 
17

Total mark-to-market gains/(losses) in operating costs and expenses
$
2

 
$
10

 
$
(174
)
 
$

 
$
112

 
$
(50
)
(a)
Represents the elimination of the intercompany activity between Retail and Generation.
 
Three months ended September 30, 2016
 
Generation
 
 
 
 
 
 
 
 
 
Gulf Coast
 
East/West
 
Retail
 
Renewables
 
Eliminations(a)
 
Total
 
(In millions)
Mark-to-market results in operating revenues
 
 
 
 
 
 
 
 
 
 
 
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges
$
8

 
$
(1
)
 
$

 
$

 
$
(77
)
 
$
(70
)
Net unrealized gains/(losses) on open positions related to economic hedges
171

 
58

 
2

 
1

 
(100
)
 
132

Total mark-to-market gains/(losses) in operating revenues
$
179

 
$
57

 
$
2

 
$
1

 
$
(177
)
 
$
62

Mark-to-market results in operating costs and expenses
 
 
 
 
 
 
 
 
 
 
 
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges
$
7

 
$
2

 
$
(46
)
 
$

 
$
77

 
$
40

Reversal of acquired gain positions related to economic hedges

 
(5
)
 
(2
)
 

 

 
(7
)
Net unrealized gains/(losses) on open positions related to economic hedges
20

 
10

 
(312
)
 

 
100

 
(182
)
Total mark-to-market gains/(losses) in operating costs and expenses
$
27

 
$
7

 
$
(360
)
 
$

 
$
177

 
$
(149
)
(a)
Represents the elimination of the intercompany activity between Retail and Generation.

Mark-to-market results consist of unrealized gains and losses on contracts that are not yet settled. The settlement of these transactions is reflected in the same revenue or cost caption as the items being hedged.
The reversals of acquired gain or loss positions were valued based upon the forward prices on the acquisition date.

79



For the three months ended September 30, 2017, the $26 million gain in operating revenues from economic hedge positions was driven primarily by the reversal of previously recognized unrealized losses on contracts that settled during the period, partially offset by a decrease in value of open positions as a result of an increase in natural gas prices. The $50 million loss in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period, partially offset by an increase in value of open positions as a result of an increase in coal prices.
For the three months ended September 30, 2016, the $62 million gain in operating revenues from economic hedge positions was driven primarily by an increase in value of open positions as a result of decreases in gas and electricity prices, partially offset by the reversal of previously recognized unrealized gains on contracts that settled during the period. The $149 million loss in operating costs and expenses from economic hedge positions was driven primarily by a decrease in value of open positions as a result of decreases in natural gas and ERCOT electricity prices, partially offset by the reversal of previously recognized unrealized losses on contracts that settled during the period.
In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the three months ended September 30, 2017 and 2016. The realized and unrealized financial and physical trading results are included in operating revenue within the Generation segment. The Company's trading activities are subject to limits within the Company's Risk Management Policy and are primarily transacted through BETM.
 
Three months ended September 30,
(In millions)
2017
 
2016
Trading (losses)/gains
 
 
 
Realized
$
(10
)
 
$
20

Unrealized
(5
)
 
(5
)
Total trading (losses)/gains
$
(15
)
 
$
15



80



Operations and Maintenance Expense
 
Generation
Retail
 
Renewables
 
NRG Yield
 
Corporate
 
Eliminations
Total
 
Gulf Coast
 
East/West(a)
 
 
 
 
 
 
(In millions)
Three months ended September 30, 2017
$
120

 
$
85

 
$
56

 
$
28

 
$
46

 
$
3

 
$
(12
)
$
326

Three months ended September 30, 2016
139

 
97

 
58

 
19

 
41

 
7

 
(7
)
354

(a)
Includes International, BETM and generation eliminations of $2 million in 2017 and $1 million in 2016.

Operations and maintenance expense decreased by $28 million for the three months ended September 30, 2017, compared to the same period in 2016, due to the following:
 
(In millions)
Decrease in operation and maintenance expenses due to a reduction in normal maintenance at various gas and coal facilities in Texas
$
(18
)
Decrease in operation and maintenance expenses primarily due to major maintenance activities and environmental work at Midwest Generation in 2016
(11
)
Other
1

 
$
(28
)
Selling, General and Administrative
Selling, general and administrative expenses are comprised of the following:
 
Generation
 
Retail
 
Renewables
 
NRG Yield
 
Corporate
 
Total
 
(In millions)
Three months ended September 30, 2017
$
42

 
$
112

 
$
14

 
$
4

 
$
41

 
$
213

Three months ended September 30, 2016
64

 
137

 
12

 
4

 
60

 
277

Selling, general and administrative expenses decreased by $64 million for the three months ended September 30, 2017, compared to the same period in 2016. The decrease in year over year expenses is due primarily to a reduction in personnel costs and selling and marketing activities as the Company continues to focus on cost management.
Reorganization
Reorganization expenses of $18 million were incurred during the third quarter of 2017 related to the Transformation Plan announced on July 12, 2017.
Loss on Debt Extinguishment
A loss on debt extinguishment of $50 million was recorded for the three months ended September 30, 2016, primarily driven by the repurchase of NRG Senior Notes at a price above par value, combined with the write-off of unamortized debt issuance costs.

81



Interest Expense
NRG's interest expense decreased by $16 million for the three months ended September 30, 2017, compared to the same period in 2016 due to the following:
 
(In millions)
Decrease due to the repurchase of Senior Notes in 2016 of $25 million, partly offset by Senior Notes issued in 2016 of $7 million
$
(18
)
Decrease due to termination of swaps related to 2016 Capistrano debt refinancing
(16
)
Increase due to the issuance of Carlsbad Energy Project debt during 2017, and Utah Portfolio debt, due 2022, during 2016
8

Increase in derivative interest expense from changes in fair value of interest rate swaps
4

Increase due to the issuance of Yield Operating Senior Notes, due 2026
3

Other
3

 
$
(16
)
Income Tax Expense
For the three months ended September 30, 2017, NRG recorded income tax expense of $6 million on pre-tax income of $196 million. For the same period in 2016, NRG recorded income tax expense of $28 million on pre-tax income of $156 million. The effective tax rate was 3.1% and 17.9% for the three months ended September 30, 2017 and 2016, respectively.
For the three months ended September 30, 2017, NRG's overall effective tax rate was different then the statutory rate of 35% primarily due to the tax benefit for the change in valuation allowance and the generation of PTCs and ITCs from various wind and solar facilities, respectively, partially offset by the inclusion of consolidated partnerships and current state tax expense.
For the three months ended September 30, 2016, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the tax benefit for the change in valuation allowance, partially offset by amortization of indefinite lived assets, inclusion of consolidated partnerships and state tax expense.
(Loss)/Income from Discontinued Operations, Net of Income Tax Expense/(Benefit)
For the three months ended September 30, 2017, NRG recorded loss from discontinued operations, net of income tax expense/(benefit) of $27 million.
For the three months ended September 30, 2016, NRG recorded income from discontinued operations, net of income tax expense/(benefit) of $265 million.



82



Management’s discussion of the results of operations for the nine months ended September 30, 2017, and 2016
Electricity Prices
The following table summarizes average on-peak power prices for each of the major markets in which NRG operates for the nine months ended September 30, 2017, and 2016. Average on-peak power prices increased primarily due to the increase in natural gas prices for the nine months ended September 30, 2017 as compared to the same period in 2016.
 
Average on Peak Power Price ($/MWh)
 
Nine months ended September 30,
Region
2017

2016
 
Change %
Gulf Coast (a)
 
 
 
 
 
ERCOT - Houston (b)
$
35.61

 
$
25.97

 
37
 %
ERCOT - North(b)
26.64

 
24.14

 
10
 %
MISO - Louisiana Hub(c)
42.33

 
33.47

 
26
 %
East/West
 
 
 
 

    NY J/NYC(c)
37.46

 
35.04

 
7
 %
    NEPOOL(c)
33.11

 
33.80

 
(2
)%
    PEPCO (PJM)(c)
35.65

 
38.15

 
(7
)%
    PJM West Hub(c)
33.30

 
33.95

 
(2
)%
CAISO - NP15(c)
33.82

 
29.38

 
15
 %
CAISO - SP15(c)
33.42

 
30.22

 
11
 %
(a) Gulf Coast region also transacts in PJM - West Hub.
(b) Average on peak power prices based on real time settlement prices as published by the respective ISOs.
(c) Average on peak power prices based on day ahead settlement prices as published by the respective ISOs.

The following table summarizes average realized power prices for each region in which NRG operates for the nine months ended September 30, 2017, and 2016, which reflects the impact of settled hedges.
 
Average Realized Power Price ($/MWh)
 
Nine months ended September 30,
Region
2017
 
2016
 
Change %
Gulf Coast
$
34.42

 
$
39.52

 
(13
)%
East/West
40.33

 
42.38

 
(5
)%
Though the average on peak power prices have increased on average by 7%, average realized prices by region for the Company have generally fluctuated at a slower rate year-over-year due to the Company's multi-year hedging program.

Gross Margin
The Company calculates gross margin in order to evaluate operating performance as operating revenues less cost of sales, which includes cost of fuel, other costs of sales, contract and emission credit amortization and mark-to-market for economic hedging activities.
Economic Gross Margin
In addition to gross margin, the Company evaluates its operating performance using the measure of economic gross margin, which is not a GAAP measure and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Economic gross margin should be viewed as a supplement to and not a substitute for the Company's presentation of gross margin, which is the most directly comparable GAAP measure. Economic gross margin is not intended to represent gross margin. The Company believes that economic gross margin is useful to investors as it is a key operational measure reviewed by the Company's chief operating decision maker. Economic gross margin is defined as the sum of energy revenue, capacity revenue, retail revenue and other revenue, less cost of fuels and other cost of sales.
Economic gross margin does not include mark-to-market gains or losses on economic hedging activities, contract amortization, emission credit amortization, or other operating costs.

83



The below tables present the composition and reconciliation of gross margin and economic gross margin for the nine months ended September 30, 2017 and 2016:
 
Nine months ended September 30, 2017
 
Generation
 
 
 
 
 
 
 
 
 
 
(In millions)
Gulf Coast
 
East/West(a)
 
Subtotal
 
Retail
 
Renewables
 
NRG Yield
 
Corporate/Eliminations
 
Total
Energy revenue
$
1,408

 
$
651

 
$
2,059

 
$

 
$
298

 
$
436

 
$
(885
)
 
$
1,908

Capacity revenue
207

 
438

 
645

 

 
1

 
256

 
(8
)
 
894

Retail revenue

 

 

 
4,875

 

 

 
5

 
4,880

Mark-to-market for economic hedging activities
174

 
4

 
178

 

 
8

 

 
(1
)
 
185

Contract amortization
11

 

 
11

 

 
(1
)
 
(52
)
 
1

 
(41
)
Other revenue (b)
143

 
36

 
179

 

 
58

 
127

 
(58
)
 
306

Operating revenue
1,943

 
1,129

 
3,072

 
4,875

 
364

 
767

 
(946
)
 
8,132

Cost of fuel
(790
)
 
(293
)
 
(1,083
)
 
(8
)
 
(3
)
 
(24
)
 
48

 
(1,070
)
Other cost of sales(c)
(259
)
 
(203
)
 
(462
)
 
(3,661
)
 
(8
)
 
(21
)
 
860

 
(3,292
)
Mark-to-market for economic hedging activities
(22
)
 
7

 
(15
)
 
(154
)
 

 


 
1

 
(168
)
Contract and emission credit amortization
(21
)
 
(3
)
 
(24
)
 

 

 
 
 

 
(24
)
Gross margin
$
851

 
$
637

 
$
1,488

 
$
1,052

 
$
353

 
$
722

 
$
(37
)
 
$
3,578

Less: Mark-to-market for economic hedging activities, net
152

 
11

 
163

 
(154
)
 
8

 

 

 
17

Less: Contract and emission credit amortization, net
(10
)
 
(3
)
 
(13
)
 

 
(1
)
 
(52
)
 
1

 
(65
)
Economic gross margin
$
709

 
$
629

 
$
1,338

 
$
1,206

 
$
346

 
$
774

 
$
(38
)
 
$
3,626

Business Metrics
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
MWh sold (thousands)(d)(e)
40,908

 
16,140

 
 
 
 
 
2,940

 
5,295

 
 
 
 
MWh generated (thousands) (f)
37,975

 
10,202

 
 
 
 
 
2,940

 
6,467

 
 
 
 
(a) Includes International, BETM and Generation eliminations.
(b) Renewables other revenue includes $21 million of intercompany revenue to NRG Yield.
(c) Includes purchased energy, capacity and emissions credits.
(d) MWh sold excludes generation at facilities in the East, West and NRG Yield that generate revenue under capacity agreements.
(e) Does not include thermal MWh of 27 thousand or MWt of 1,450 thousand for thermal sold by NRG Yield.
(f) Does not include thermal MWh of 80 thousand or MWt of 1,450 thousand for thermal generated by NRG Yield.

84



 
Nine months ended September 30, 2016
 
Generation
 
 
 
 
 
 
 
 
 
 
(In millions)
Gulf Coast
 
East/West(a)
 
Subtotal
 
Retail
 
Renewables
 
NRG Yield
 
Corporate/Eliminations
 
Total
Energy revenue
$
1,598

 
$
896

 
$
2,494

 
$

 
$
303

 
$
459

 
$
(778
)
 
$
2,478

Capacity revenue
222

 
468

 
690

 

 

 
256

 
(9
)
 
937

Retail revenue

 

 

 
4,918

 

 

 
13

 
4,931

Mark-to-market for economic hedging activities
(270
)
 
(9
)
 
(279
)
 

 

 

 
(81
)
 
(360
)
Contract amortization
11

 

 
11

 

 
(1
)
 
(51
)
 

 
(41
)
Other revenue (b)
182

 
75

 
257

 

 
34

 
125

 
(33
)
 
383

Operating revenue
1,743

 
1,430

 
3,173

 
4,918

 
336

 
789

 
(888
)
 
8,328

Cost of fuel
(718
)
 
(371
)
 
(1,089
)
 
(5
)
 
(3
)
 
(25
)
 
114

 
(1,008
)
Other cost of sales(c)
(309
)
 
(245
)
 
(554
)
 
(3,628
)
 
(9
)
 
(23
)
 
696

 
(3,518
)
Mark-to-market for economic hedging activities
62

 
8

 
70

 
150

 

 

 
81

 
301

Contract and emission credit amortization
(22
)
 
(4
)
 
(26
)
 
(5
)
 

 
(6
)
 
3

 
(34
)
Gross margin
$
756

 
$
818

 
$
1,574

 
$
1,430

 
$
324

 
$
735

 
$
6

 
$
4,069

Less: Mark-to-market for economic hedging activities, net
(208
)
 
(1
)
 
(209
)
 
150

 

 

 

 
(59
)
Less: Contract and emission credit amortization, net
(11
)
 
(4
)
 
(15
)
 
(5
)
 
(1
)
 
(57
)
 
3

 
(75
)
Economic gross margin
$
975

 
$
823

 
$
1,798

 
$
1,285

 
$
325

 
$
792

 
$
3

 
$
4,203

Business Metrics
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
MWh sold (thousands)(d)(e)
40,433

 
21,141

 
 
 
 
 
2,968

 
5,563

 
 
 
 
MWh generated (thousands) (f)
36,427

 
13,732

 
 
 
 
 
2,968

 
6,828

 
 
 
 
(a) Includes International, BETM and Generation eliminations.
(b) Renewables other revenue includes $13 million of intercompany revenue to NRG Yield.
(c) Includes purchased energy, capacity and emissions credits
(d) MWh sold excludes generation at facilities in the East, West and NRG Yield that generate revenue under capacity agreements.
(e) Does not include thermal MWh of 61 thousand or MWt of 1,497 thousand for thermal sold by NRG Yield.
(f) Does not include thermal MWh of 248 thousand or MWt of 1,497 thousand for thermal generated by NRG Yield.

The table below represents the weather metrics for the nine months ended September 30, 2017 and 2016:
 
Nine months ended September 30,
 
 
 
 
 
 
 
 
 
Weather Metrics
Gulf Coast
 
East/West
 
 
 
 
 
 
 
 
 
 
2017
 
 
 
 
 
 
 
 
 
 
 
 
 
CDDs (a)
2,653

 
1,071

 
 
 
 
 
 
 
 
 
 
HDDs (a)
674

 
2,041

 
 
 
 
 
 
 
 
 
 
2016
 
 
 
 
 
 
 
 
 
 
 
 
 
CDDs
2,605

 
1,098

 
 
 
 
 
 
 
 
 
 
HDDs
984

 
2,046

 
 
 
 
 
 
 
 
 
 
10 year average
 
 
 
 
 
 
 
 
 
 
 
 
 
CDDs
2,656

 
976

 
 
 
 
 
 
 
 
 
 
HDDs
1,167

 
2,277

 
 
 
 
 
 
 
 
 
 
(a)
National Oceanic and Atmospheric Administration-Climate Prediction Center - A Cooling Degree Day, or CDD, represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. A Heating Degree Day, or HDD, represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period.


85



Generation gross margin and economic gross margin
Generation gross margin decreased $86 million and economic gross margin decreased $460 million, both of which include intercompany sales, during the nine months ended September 30, 2017, compared to the same period in 2016:

The tables below describe the decrease in Generation gross margin and economic gross margin:

Gulf Coast Region
 
(In millions)
Lower gross margin due to a 12% decrease in average realized prices primarily in Texas due to lower hedged power prices
$
(225
)
Lower energy margin due to increased supply costs on load contracts
(39
)
Lower capacity margin on contract expirations and lower demand
(29
)
Lower gross margin due to a 42% decrease in ISO capacity prices and a 58% decrease in volume
(18
)
Lower gross margin from a 7% decrease in nuclear generation driven by the timing of planned outages
(17
)
Higher gross margin primarily due to 19% higher coal generation mainly in Texas driven by timing of planned outages
59

Other
3

Decrease in economic gross margin
$
(266
)
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges
360

Increase in contract and emission credit amortization
1

Increase in gross margin
$
95


East/West
 
(In millions)
Lower gross margin due to a 14% decrease in generation driven by lower economic generation due to milder weather conditions and the Will County outage
$
(60
)
Lower gross margin by BETM due to higher gains in 2016 on over the counter strategies, offset in small part by higher gains in 2017 on congestion strategies
(45
)
Lower gross margin from commercial optimization activities
(39
)
Lower gross margin due to lower load contracted prices coupled with slightly lower volumes
(26
)
Lower gross margin due to a 16% decrease in capacity pricing in New York of $10 million coupled with decreases in capacity pricing and volumes due to the Long Beach capacity toll expiration and unit retirements in California
(23
)
Other
(1
)
Decrease in economic gross margin
$
(194
)
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges
12

Increase in contract and emission credit amortization
1

Decrease in gross margin
$
(181
)




86



Retail gross margin and economic gross margin
The following is a discussion of gross margin and economic gross margin for Retail.
 
Nine months ended September 30,
(In millions except otherwise noted)
2017
 
2016
Retail revenue
$
4,658

 
$
4,727

Supply management revenue
147

 
117

Capacity revenue
70

 
74

Operating revenue (a)
4,875

 
4,918

Cost of sales (b)
(3,669
)
 
(3,633
)
Mark-to-market for economic hedging activities
(154
)
 
150

Contract amortization

 
(5
)
Gross Margin
$
1,052

 
$
1,430

Less: Mark-to-market for economic hedging activities, net
(154
)
 
150

Less: Contract and emission credit amortization, net

 
(5
)
Economic Gross Margin
$
1,206

 
$
1,285

 
 
 
 
Business Metrics
 
 
 
Mass electricity sales volume - GWh - Gulf Coast
28,153

 
27,382

Mass electricity sales volume - GWh - All other regions
4,722

 
5,264

C&I electricity sales volume — GWh - All regions (c)
15,228

 
14,357

Natural gas sales volumes (MDth)
1,941

 
1,423

Average Retail Mass customer count (in thousands)
2,857

 
2,770

Ending Retail Mass customer count (in thousands)
2,880

 
2,797

(a)
Includes intercompany sales of $4 million and $3 million in 2017 and 2016, respectively, representing sales from Retail to the Gulf Coast region.
(b)
Includes intercompany purchases of $830 million and $655 million in 2017 and 2016.
(c)
Includes volumes for 2017 for one customer that self-supplied their volumes during the first six months of 2016.

Retail gross margin decreased $378 million and economic gross margin decreased $79 million for the nine months ended September 30, 2017, compared to the same period in 2016, due to:
 
(In millions)
Lower gross margin due to lower rates to customers driven by customer product, term, and mix of $95 million or approximately $2 per MWh, partially offset by lower supply costs of $5 million or approximately $0.10 per MWh driven primarily by a decrease in power prices at the time of procurement
$
(90
)
Lower gross margin of $9 million due to a reduction in load of 200,000 MWh, and the unfavorable impact of selling back excess supply along with $7 million of customer relief related to the impact of Hurricane Harvey in 2017
(16
)
Lower gross margin of $13 million due to a reduction in load of 420,000 MWh and $2 million in lower margin due to the unfavorable impacts of selling back excess supply due to milder weather conditions in 2017 as compared to 2016
(15
)
Higher gross margin due to higher volumes driven by higher average customer usage and mix
42

Decrease in economic gross margin
$
(79
)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges
(304
)
Increase in contract and emission credit amortization
5

Decrease in gross margin
$
(378
)


87




Renewables gross margin and economic gross margin
Renewables gross margin increased $29 million and economic gross margin increased $21 million for the nine months ended September 30, 2017, compared to the same period in 2016, primarily driven by new distributed generation solar projects placed in service, increased margin in operations and maintenance agreements and receipt of insurance proceeds offsetting lower volume at the Ivanpah solar plant.
NRG Yield gross margin and economic gross margin
NRG Yield gross margin decreased $13 million and economic gross margin decreased by $19 million during the nine months ended September 30, 2017, compared to the same period in 2016, due to a 4% decrease in volume generated at wind projects, primarily in connection with lower wind resources at the Alta Wind and NRG Wind TE Holdco projects, as well as 5% decrease in solar generation, primarily at CVSR in connection with lower insolation.
Mark-to-market for Economic Hedging Activities
Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges and ineffectiveness on cash flow hedges. Total net mark-to-market results increased by $76 million during the nine months ended September 30, 2017, compared to the same period in 2016.
The breakdown of gains and losses included in operating revenues and operating costs and expenses by region was as follows:
 
Nine months ended September 30, 2017
 
Generation
 
 
 
 
 
 
 
 
 
Gulf Coast
 
East/West
 
Retail
 
Renewables
 
Eliminations(a)
 
Total
 
(In millions)
Mark-to-market results in operating revenues
 
 
 
 
 
 
 
 
 
 
 
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges
$
113

 
$
(32
)
 
$
(1
)
 
$
1

 
$
21

 
$
102

Net unrealized gains/(losses) on open positions related to economic hedges
61

 
36

 
1

 
7

 
(22
)
 
83

Total mark-to-market gains/(losses) in operating revenues
$
174

 
$
4

 
$

 
$
8

 
$
(1
)
 
$
185

Mark-to-market results in operating costs and expenses
 
 
 
 
 
 
 
 
 
 
 
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges
$
(12
)
 
$
1

 
$
(51
)
 
$

 
$
(21
)
 
$
(83
)
Reversal of acquired gain positions related to economic hedges

 

 
(1
)
 

 

 
(1
)
Net unrealized (losses)/gains on open positions related to economic hedges
(10
)
 
6

 
(102
)
 

 
22

 
(84
)
Total mark-to-market (losses)/gains in operating costs and expenses
$
(22
)
 
$
7

 
$
(154
)
 
$

 
$
1

 
$
(168
)
(a)
Represents the elimination of the intercompany activity between Retail and Generation.

88



 
Nine months ended September 30, 2016
 
Generation
 
 
 
 
 
 
 
 
Gulf Coast
 
East/West
 
Retail
 
Renewables
 
Eliminations(a)
 
Total
 
(In millions)
Mark-to-market results in operating revenues
 
 
 
 
 
 
 
 
 
 
 
Reversal of previously recognized unrealized gains on settled positions related to economic hedges
$
(260
)
 
$
(68
)
 
$
(1
)
 
$

 
$

 
$
(329
)
Net unrealized (losses)/gains on open positions related to economic hedges
(10
)
 
59

 
1

 

 
(81
)
 
(31
)
Total mark-to-market losses in operating revenues
$
(270
)
 
$
(9
)
 
$

 
$

 
$
(81
)
 
$
(360
)
Mark-to-market results in operating costs and expenses
 
 
 
 
 
 
 
 
 
 
 
Reversal of previously recognized unrealized losses on settled positions related to economic hedges
$
26

 
$
10

 
$
218

 
$

 
$

 
$
254

Reversal of acquired gain positions related to economic hedges

 
(10
)
 
(1
)
 

 

 
(11
)
Net unrealized gains/(losses) on open positions related to economic hedges
36

 
8

 
(67
)
 

 
81

 
58

Total mark-to-market gains in operating costs and expenses
$
62

 
$
8

 
$
150

 
$

 
$
81

 
$
301

(a)
Represents the elimination of the intercompany activity between Retail and Generation.

Mark-to-market results consist of unrealized gains and losses on contracts that are not yet settled. The settlement of these transactions is reflected in the same revenue or cost caption as the items being hedged.
The reversals of acquired gain or loss positions were valued based upon the forward prices on the acquisition date.
For the nine months ended September 30, 2017, the $185 million gain in operating revenues from economic hedge positions was driven primarily by the reversal of previously recognized unrealized losses on contracts that settled during the period, as well as an increase in value of open positions as a result of decreases in PJM power prices, New York capacity prices, and natural gas prices. The $168 million loss in operating costs and expenses from economic hedge positions was driven primarily by the decrease in value of open positions as a result of decreases in coal, natural gas, and ERCOT power prices, as well as the reversal of previously recognized unrealized gains on contracts that settled during the period.
For the nine months ended September 30, 2016, the $360 million loss in operating revenues from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period. The $301 million gain in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized losses on contracts that settled during the period, as well as the increase in value of open positions as a result of increases in natural gas prices.
In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the nine months ended September 30, 2017, and 2016. The realized and unrealized financial and physical trading results are included in operating revenue within the Generation segment. The Company's trading activities are subject to limits within the Company's Risk Management Policy and are primarily transacted through BETM.
 
Nine months ended September 30,
(In millions)
2017
 
2016
Trading gains/(losses)
 
 
 
Realized
$
18

 
$
67

Unrealized
(7
)
 
27

Total trading gains
$
11

 
$
94



89



Operations and Maintenance Expense
 
Generation
Retail
 
Renewables
 
NRG Yield
 
Corporate
 
Eliminations
Total
 
Gulf Coast
 
East/West(a)
 
 
 
 
 
 
(In millions)
 
Nine months ended September 30, 2017
$
370

 
$
284

 
$
170

 
$
91

 
$
143

 
$
12

 
$
(32
)
$
1,038

Nine months ended September 30, 2016
419

 
374

 
178

 
93

 
134

 
19

 
(21
)
1,196

(a)
Includes International, BETM and generation eliminations of $3 million in 2017 and $4 million in 2016.

Operations and maintenance expense decreased by $158 million for the nine months ended September 30, 2017, compared to the same period in 2016, due to the following:
 
(In millions)
Decrease in operation and maintenance expenses due to major maintenance activities and environmental control work at Midwest Generation in 2016
$
(68
)
Decrease in operation and maintenance expenses due to lower expenses at Big Cajun II in 2017
(26
)
Decrease in operation and maintenance expenses due to the deactivation of the Huntley and Dunkirk facilities in 2016
(16
)
Decrease in operation and maintenance expenses due to a reduction in normal maintenance at various gas and coal facilities in Texas
(15
)
Decrease in Retail operation and maintenance expenses due to reduced headcount
(8
)
Decrease in operations and maintenance expenses related to outage work at Arthur Kill in 2016
(6
)
Decrease in operations and maintenance expenses due to a reduction in headcount related to the sale of the Engine Services business
(4
)
Other
(15
)
 
$
(158
)

Selling, General and Administrative
Selling, general and administrative expenses are comprised of the following:
 
Generation
 
Retail
 
Renewables
 
NRG Yield
 
Corporate
 
Total
 
(In millions)
Nine months ended September 30, 2017
$
155

 
$
337

 
$
43

 
$
16

 
$
146

 
$
697

Nine months ended September 30, 2016
195

 
362

 
43

 
10

 
191

 
801

Selling, general and administrative expenses decreased by $104 million for the nine months ended September 30, 2017, compared to the same period in 2016. The decrease in year over year expenses is due primarily to a reduction in personnel costs and selling and marketing activities as the Company continues to focus on cost management.
Reorganization
Reorganization expenses of $18 million were incurred during the third quarter of 2017 related to the Transformation Plan announced on July 12, 2017.
Loss on Sale of Assets
During the nine months ended September 30, 2016, the Company sold a majority interest in its EVgo business to Vision Ridge Partners, as described in Note 3, Discontinued Operations, Dispositions and Acquisitions, of this Form 10-Q, which resulted in a loss on sale of $79 million .
Impairment Losses on Investments
For the nine months ended September 30, 2016, the Company recorded other-than-temporary impairment losses of $147 million, which is primarily due to its 50% interest in Petra Nova Parish Holdings, as further described in Note 7, Impairments, of this Form 10-Q.

90



Loss on Debt Extinguishment
A loss on debt extinguishment of $119 million was recorded for the nine months ended September 30, 2016, primarily driven by the repurchase of NRG Senior Notes at a price above par value, combined with the write-off of unamortized debt issuance costs.
Interest Expense
NRG's interest expense decreased by $26 million for the nine months ended September 30, 2017, compared to the same period in 2016 due to the following:
 
(In millions)
Decrease due to the repurchase of Senior Notes in 2016 of $127 million, partly offset by Senior Notes issued in 2016 of $78 million
$
(49
)
Decrease due to termination of swaps related to 2016 Capistrano debt refinancing
(16
)
Increase due to the issuance of Utah Portfolio debt, due 2022 and CVSR Holdco Notes, due 2037 during 2016
16

Increase due to the issuance of Carlsbad Energy Project debt and Agua Caliente HoldCo, due 2038 during 2017
10

Increase in derivative interest expense from changes in fair value of interest rate swaps
9

Increase due to the issuance of Yield Operating Senior Notes, due 2026, partially offset by repayment of the Yield Revolving Credit Facility, due 2019 during 2016
8

Other
(4
)
 
$
(26
)
Income Tax Expense
For the nine months ended September 30, 2017, NRG recorded income tax expense of $5 million on a pre-tax income of $125 million. For the same period in 2016, NRG recorded income tax expense of $75 million on a pre-tax loss of $17 million. The effective tax rate was 4.0% and (441.2)% for the nine months ended September 30, 2017 and 2016, respectively.
For the nine months ended September 30, 2017, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the tax benefit for the change in valuation allowance and the generation of PTCs and ITCs from various wind and solar facilities, respectively, partially offset by the inclusion of consolidated partnerships and current state tax expense.
For the nine months ended September 30, 2016, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due the amortization of indefinite lived assets, the inclusion of consolidated partnerships, state tax expense and the expense for the change in valuation allowance.
Net loss attributable to noncontrolling interests and redeemable noncontrolling interests
For the nine months ended September 30, 2017 and 2016, net loss attributable to noncontrolling interests and redeemable noncontrolling interests primarily reflects net losses allocated to tax equity investors in tax equity arrangements using the hypothetical liquidation at book value, or HLBV, method, partially offset by NRG Yield, Inc.'s share of net income.
(Loss)/Income from Discontinued Operations, Net of Income Tax (Benefit)/Expense
For the nine months ended September 30, 2017, NRG recorded loss from discontinued operations, net of income tax (benefit)/expense of $802 million.
    
For the nine months ended September 30, 2016, NRG recorded income from discontinued operations, net of income tax (benefit)/expense of $256 million.

91



Liquidity and Capital Resources
Liquidity Position
As of September 30, 2017 and December 31, 2016, NRG's liquidity, excluding collateral received, was approximately $3.4 billion and $2.4 billion, respectively, comprised of the following:
(In millions)
September 30, 2017
 
December 31, 2016
Cash and cash equivalents:
 
 
 
NRG excluding NRG Yield
$
1,044

 
$
621

NRG Yield and subsidiaries
179

 
317

Restricted cash - operating
124

 
56

Restricted cash - reserves (a)
413

 
390

Total
1,760

 
1,384

Total credit facility availability
1,604


989

Total liquidity, excluding collateral received
$
3,364

 
$
2,373

(a) Includes reserves primarily for debt service, performance obligations, and capital expenditures.
For the nine months ended September 30, 2017, total liquidity, excluding collateral funds deposited by counterparties, increased by $1 billion. Changes in cash and cash equivalents balances are further discussed hereinafter under the heading Cash Flow Discussion. Cash and cash equivalents at September 30, 2017 were predominantly held in money market funds invested in treasury securities, treasury repurchase agreements or government agency debt.
Management believes that the Company's liquidity position and cash flows from operations will be adequate to finance operating and maintenance capital expenditures, to fund dividends to NRG's common stockholders, and to fund other liquidity commitments. Management continues to regularly monitor the Company's ability to finance the needs of its operating, financing and investing activity within the dictates of prudent balance sheet management.
On July 12, 2017, NRG announced its Transformation Plan, which is described further in Management's Discussion and Analysis of Financial Condition and Results of Operations - Executive Summary.
Credit Ratings
The following table summarizes the Company's credit ratings as of September 30, 2017:
 
S&P
 
Moody's
NRG Energy, Inc. 
BB- Stable
 
Ba3 Stable
7.625% Senior Notes, due 2018
BB-
 
B1
7.875% Senior Notes, due 2021
BB-
 
B1
6.25% Senior Notes, due 2022
BB-
 
B1
6.625% Senior Notes, due 2023
BB-
 
B1
6.25% Senior Notes, due 2024
BB-
 
B1
7.25% Senior Notes, due 2026
BB-
 
B1
6.625% Senior Notes, due 2027
BB-
 
B1
Term Loan Facility, due 2023
BB+
 
Baa3
NRG Yield, Inc.
BB
 
Ba2
5.375% NRG Yield Operating LLC Senior Notes, due 2024
BB
 
Ba2
5.00% NRG Yield Operating LLC Senior Notes, due 2026
BB
 
Ba2
On October 6, 2017, Moody's upgraded the NRG rating outlook to positive from stable and affirmed NRG's Ba3 Corporate Family Rating.

92



Sources of Liquidity
The principal sources of liquidity for NRG's future operating and capital expenditures are expected to be derived from new and existing financing arrangements, existing cash on hand, cash flows from operations and cash proceeds from future sales of assets, including sales to NRG Yield, Inc. As described in Note 8, Debt and Capital Leases, to this Form 10-Q and Note 12, Debt and Capital Leases, to the Company's 2016 Form 10-K, the Company's financing arrangements consist mainly of the Senior Credit Facility, the Senior Notes, the NRG Yield 2019 Convertible Notes, the NRG Yield 2020 Convertible Notes, the NRG Yield Operating LLC senior unsecured notes, the NRG Yield, Inc. revolving credit facility, and project-related financings.
Carlsbad Project Financing
On May 26, 2017, Carlsbad Energy Holdings, LLC entered into a note payable agreement with financial institutions for the issuance of up to $407 million of senior secured notes that bear interest at a rate of 4.12%, and mature on October 31, 2038. As of September 30, 2017, all $407 million of these notes were outstanding.
Also on May 26, 2017, Carlsbad Energy Holdings, LLC entered into a credit agreement, or the Carlsbad Financing Agreement, with the issuing banks, for a $194 million construction loan, that will convert to a term loan upon completion of the project. The Carlsbad Financing Agreement also includes a letters of credit facility not to exceed aggregate amount of $83 million, and a working capital loan facility with an aggregate principle amount not to exceed $4 million.
ROFO Agreement Expansion and Offer
On February 24, 2017, the Company amended and restated the ROFO Agreement to expand the ROFO assets pipeline with the addition of 234 net MW of utility-scale solar projects. These assets include Buckthorn Solar, a 154 net MW facility located in Texas, and the Hawaii Solar projects, which have a combined capacity of 80 net MW.
On October 17, 2017, the Company offered NRG Yield, Inc. the opportunity to purchase 100% of its ownership interest in Buckthorn Solar pursuant to the ROFO Agreement.
Sale of Assets to NRG Yield, Inc.
On November 1, 2017, NRG completed the sale of a 38 MW solar portfolio primarily comprised of assets from SPP funds, in addition to other projects developed by NRG, to NRG Yield, Inc. for cash consideration of $71 million, plus $3 million in working capital adjustments.
On August 1, 2017, NRG closed on its sale of the remaining 25% interest in NRG Wind TE Holdco, a portfolio of 12 wind projects, to NRG Yield, Inc. for total cash consideration of $44 million. The transaction also includes potential additional payments to NRG dependent on actual energy prices for merchant periods beginning in 2027.
On May 23, 2017, NRG offered NRG Yield, Inc. the opportunity to form a new distributed solar investment partnership enabling up to $50 million in investment by NRG Yield, Inc. In addition, on July 31, 2017, NRG offered NRG Yield, Inc. equity interests in a 38 MW portfolio of distributed and small utility-scale solar assets primarily comprised of assets from NRG's Solar Power Partners, or SPP, funds in addition to other projects developed since the acquisition of SPP. These equity interests are not part of the ROFO Agreement. Both the distributed solar investment partnership and the distributed and small utility-scale solar acquisitions are subject to negotiation and approval by NRG Yield, Inc.'s independent directors. As of September 30, 2017, NRG Yield, Inc has invested $41 million in distributed solar investment partnerships with NRG.
On March 27, 2017, the Company sold (i) a 16% interest in the Agua Caliente solar project, representing ownership of approximately 46 net MW of capacity and (ii) NRG's interests in seven utility-scale solar projects located in Utah representing 265 net MW of capacity which have reached commercial operations to NRG Yield, Inc. NRG Yield Inc. paid cash consideration of $130 million, plus $1 million in working capital adjustments, and assumed non-recourse project debt of approximately $328 million.
2023 Term Loan Facility
On January 24, 2017, NRG repriced the 2023 Term Loan Facility, reducing the interest rate margin by 50 basis points to LIBOR plus 2.25%, the LIBOR floor remains 0.75%. As a result of the repricing, the Company expects interest savings of approximately $9 million in 2017 and approximately $60 million in interest savings over the life of the loan.

93



First Lien Structure
NRG has granted first liens to certain counterparties on a substantial portion of the Company's assets, excluding assets acquired through EME (including Midwest Generation), assets held by NRG Yield, Inc., and NRG's assets that have project-level financing.  NRG uses the first lien structure to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or gas used as a proxy for power.  To the extent that the underlying hedge positions for a counterparty are out-of-the-money to NRG, the counterparty would have claim under the first lien program.  The first lien program limits the volume that can be hedged, not the value of underlying out-of-the-money positions.  The first lien program does not require NRG to post collateral above any threshold amount of exposure as the lien counterparty’s exposure to NRG is positively correlated to the value of the specified generation assets.  Within the first lien structure, the Company can hedge up to 80% of its coal and nuclear capacity, and 10% of its other assets, with these counterparties for the first 60 months and then declining thereafter.  These volumetric limits, exclude Midwest Generation's coal capacity. The first lien structure is not subject to unwind or termination upon a ratings downgrade of a counterparty and has no stated maturity date.
The Company's first lien counterparties may have a claim on its assets to the extent market prices exceed the hedged prices. As of September 30, 2017, all hedges under the first liens were out-of-the-money on a counterparty aggregate basis.
The following table summarizes the amount of MW hedged against the Company's coal and nuclear assets and as a percentage relative to the Company's coal and nuclear capacity under the first lien structure as of September 30, 2017:
Equivalent Net Sales Secured by First Lien Structure (a)
2017
 
2018
 
2019
 
2020
 
2021
In MW
1,458

 
1,093

 

 

 

As a percentage of total net coal and nuclear capacity (b)
27
%
 
20
%
 
%
 
%
 
%
(a)
Equivalent net sales include natural gas swaps converted using a weighted average heat rate by region.
(b)
Net coal and nuclear capacity represents 80% of the Company’s total coal and nuclear assets eligible under the first lien which excludes coal assets acquired in the EME (Midwest Generation) acquisition, assets in NRG Yield, Inc. and NRG's assets that have project level financing.
Uses of Liquidity
The Company's requirements for liquidity and capital resources, other than for operating its facilities, can generally be categorized by the following: (i) commercial operations activities; (ii) debt service obligations; (iii) capital expenditures, including repowering and renewable development, and environmental; and (iv) allocations in connection with acquisition opportunities, debt repayments, return of capital and dividend payments to stockholders.
Senior Note Redemptions
On October 16, 2017, the Company redeemed $398 million of its 7.625% Senior Notes due 2018 and $206 million of its 7.875% Senior Notes due 2021 for $630 million, which included $14 million in accrued interest. As a result of the senior note redemptions a $12 million loss on debt extinguishment will be recorded in the fourth quarter of 2017. In addition, the Company expects to save approximately $47 million in annualized interest.
Restructuring Support Agreement
As described in Note 3, Discontinued Operations, Dispositions and Acquisitions, NRG, the GenOn Entities and certain holders of the GenOn and GenOn Americas Generation Senior Notes entered into a Restructuring Support Agreement, that provides for a restructuring and recapitalization of GenOn through a prearranged plan of reorganization. Certain principal terms of the Restructuring Support Agreement include that NRG will provide settlement consideration to GenOn of $261.3 million, which will be paid in cash less any amounts owed to NRG under the intercompany secured revolving credit facility. As of June 30, 2017, GenOn owed NRG approximately $125 million under the intercompany secured revolving credit facility. NRG agreed to provide GenOn with a letter of credit facility during the pendency of the Chapter 11 Cases, to be utilized for required letters of credit in lieu of the intercompany secured revolving credit facility. GenOn can no longer utilize the intercompany secured revolving credit facility and, on July 27, 2017, the letter of credit facility was terminated, as GenOn has obtained a separate letter of credit facility with a third party financial institution. In addition, NRG will retain the pension liability, including payment of approximately $13 million of 2017 pension contributions, for GenOn employees for service provided prior to the completion of the reorganization, which was paid in September 2017. GenOn’s pension liability as of September 30, 2017 was approximately $106 million. See Note 1, Basis of Presentation, for further discussion regarding the October 30, 2017 proposed changes to the Restructuring Support Agreement, which includes the retention of the liability for GenOn’s post-employment and retiree health and welfare benefits, in an amount up to $25 million, recorded as a liability as of September 30, 2017.

94



Revolving Credit Facility
As of September 30, 2017, there were no cash borrowings outstanding on the revolver.
Commercial Operations
NRG's commercial operations activities require a significant amount of liquidity and capital resources. These liquidity requirements are primarily driven by: (i) margin and collateral posted with counterparties; (ii) margin and collateral required to participate in physical markets and commodity exchanges; (iii) timing of disbursements and receipts (i.e. buying fuel before receiving energy revenues); (iv) initial collateral for large structured transactions; and (v) collateral for project development. As of September 30, 2017, commercial operations had total cash collateral outstanding of $274 million, and $606 million outstanding in letters of credit to third parties primarily to support its commercial activities for both wholesale and retail transactions. As of September 30, 2017, total collateral held from counterparties was $31 million in cash and $17 million in letters of credit.
Future liquidity requirements may change based on the Company's hedging activities and structures, fuel purchases, and future market conditions, including forward prices for energy and fuel and market volatility. In addition, liquidity requirements are dependent on NRG's credit ratings and general perception of its creditworthiness.

95



Capital Expenditures
The following tables and descriptions summarize the Company's capital expenditures for maintenance, environmental, and growth investments for the nine months ended September 30, 2017, and the currently estimated capital expenditure and growth investments forecast for the remainder of 2017
 
Maintenance
 
Environmental
 
Growth Investments
 
Total
 
(In millions)
Generation
 
 
 
 
 
 
 
Gulf Coast
$
73

 
$
1

 
$
3

 
$
77

East/West
17

 
24

 
240

 
281

Retail
22

 

 
33

 
55

Renewables
3

 

 
309

 
312

NRG Yield
21

 

 
2

 
23

Corporate 
11

 

 
1

 
12

Total cash capital expenditures for the nine months ended September 30, 2017
147

 
25

 
588

 
760

     Funding from third party equity partners, cash grants and debt financing, net of fees

 

 
(815
)
 
(815
)
     Other investments (a)

 

 
95

 
95

Total capital expenditures and investments, net of financings
147

 
25

 
(132
)
 
40

 
 
 
 
 
 
 
 
Estimated capital expenditures for the remainder of 2017
76

 
10

 
430

 
516

     Funding from third party equity partners, cash grants and debt financing, net of fees

 

 
(211
)
 
(211
)
NRG estimated capital expenditures for the remainder of 2017, net of financings
$
76

 
$
10

 
$
219

 
$
305

(a)
Other investments include restricted cash activity.

Environmental capital expenditures — For the nine months ended September 30, 2017, the Company's environmental capital expenditures included DSI/ESP upgrades at the Powerton facility and the Joliet gas conversion to satisfy CPS.
Growth Investments capital expenditures — For the nine months ended September 30, 2017, the Company's growth investment capital expenditures included $245 million for solar projects, $241 million for repowering projects, $65 million for wind projects and $37 million for the Company's other growth projects.
Environmental Capital Expenditures
NRG estimates that environmental capital expenditures from 2017 through 2021 required to comply with environmental laws will be approximately $60 million, which includes $16 million for Midwest Generation. The increase from last quarter is driven primarily by the addition of the anticipated costs of adding NOx control equipment at certain of the Company's units in Connecticut.
Dividends
The following table lists the dividends paid during the nine months ended September 30, 2017:
 
Third Quarter 2017
 
Second Quarter 2017
 
First Quarter 2017
Dividends per Common Share
$
0.030

 
$
0.030

 
$
0.030

On October 18, 2017, NRG declared a quarterly dividend on the Company's common stock of $0.03 per share, payable November 15, 2017, to stockholders of record as of November 1, 2017 representing $0.12 on an annualized basis.
The Company's common stock dividends are subject to available capital, market conditions, and compliance with associated laws, regulations and other contractual obligations. The Company expects that, based on current circumstances, comparable cash dividends will continue to be paid in the foreseeable future.

96



Fuel Repowerings
The table below lists the Company's currently projected repowering and conversion projects. With respect to facilities that are currently operating, the timing of the projects listed below could adversely impact the Company's operating revenues, gross margin and other operating costs during the period prior to the targeted COD.
Facility
Net Generation Capacity (MW) (b)
 
Project Type
 
Fuel Type
 
Targeted COD
Repowerings
 
 
 
 
 
 
 
Carlsbad Peakers (formerly Encina) Units 1, 2, 3, 4, 5 and GT
527

 
Growth
 
Natural Gas
 
Q4 2018
Puente (formerly Mandalay) Units 1 and 2(a)
262

 
Growth
 
Natural Gas
 
Q2 2020
Total Fuel Repowerings
789

 
 
 
 
 
 
(a) See Regulatory Matters in the Management's Discussion and Analysis to this Form 10-Q for recent developments in the permitting process that may impact the viability of the Puente project.
(b On June 16, 2017, NRG Texas Power LLC provided notice to BTEC New Albany, LLC that it was exercising its right to terminate the Amended and Restated Membership Interest Purchase Agreement, or MIPA, due to the Bacliff Project, a new peaking facility at the former P.H. Robinson Electric Generating Station, not achieving commercial completion by the contractual expiration date of May 31, 2017. On July 14, 2017, the Company gave notice to BTEC New Albany, LLC that it owes NRG Texas Power LLC approximately $48 million under the terminated MIPA, consisting of $38 million in purchaser incurred costs and $10 million in liquidated damages.





97



Cash Flow Discussion
The following table reflects the changes in cash flows for the comparative nine month periods:
 
Nine months ended September 30,
 
 
 
2017
 
2016
 
Change
 
(In millions)
Net cash used by operating activities
$
806

 
$
1,741

 
$
(935
)
Net cash used by investing activities
(765
)
 
(255
)
 
(510
)
Net cash provided by financing activities
59

 
(587
)
 
646

Net Cash Used By Operating Activities
Changes to net cash used by operating activities were driven by:
 
(In millions)
Changes in cash collateral in support of risk management activities due to changes in commodity prices
$
(364
)
Decrease in operating income adjusted for non-cash items
(216
)
Decrease in other assets and liabilities
(127
)
Cash used by discontinued operations
(105
)
Decrease in accounts payable due to lower expenses and the timing of payments in 2017 compared to 2016.
(68
)
Increase in inventory due to lower generation in 2017, combined with earlier inventory purchases in the fourth quarter of 2015 for anticipated 2016 generation requirements
(64
)
Other
(35
)
Decrease in accounts receivable due to the timing of cash receipts in 2017 compared to 2016
44

 
$
(935
)
Net Cash Used By Investing Activities
Changes to net cash used by investing activities were driven by:
 
(In millions)
Cash used by discontinued operations
$
(379
)
Decrease in maintenance and environmental capital expenditures, offset by an increase in growth capital expenditures
(101
)
Proceeds from sale of assets in 2016 compared to 2017
(48
)
Increase in cash paid for acquisitions in 2017 compared to 2016
(18
)
Other
(7
)
Net increase in emissions allowances activity
43

 
$
(510
)
Net Cash Provided By Financing Activities
Changes to net cash provided by financing activities were driven by:
 
(In millions)
Increase in borrowings, primarily related to Agua Caliente Borrower 1 & 2, 2038 Senior Notes and the Carlsbad Project Financing as well as reduced payments due to repurchases of Senior Notes in 2016
$
538

Increase due to purchase of preferred stock in 2016
226

Increase in cash contributions, net of distributions from non-controlling interest in 2017
192

Decrease in debt extinguishment cost
98

Decrease in payment of dividends, primarily related to reduction of NRG dividend rate in the first quarter of 2016
38

Decrease in deferred debt issuance cost
27

Decrease in financing element related to acquired derivatives
(5
)
Payment for affiliate receivable
(125
)
Cash used by discontinued operations
(343
)
 
$
646


98



NOLs, Deferred Tax Assets and Uncertain Tax Position Implications, under ASC 740
For the nine months ended September 30, 2017, the Company had total domestic pre-tax book income of $112 million and foreign pre-tax book income of $13 million. As of December 31, 2016, the Company had cumulative domestic Federal NOL carryforwards of $3.4 billion, of which $1.2 billion is from GenOn Energy, Inc. and subsidiaries which will begin expiring in 2026 and cumulative state NOL carryforwards of $4.9 billion for financial statement purposes. In addition, NRG has cumulative foreign NOL carryforwards of $196 million, which do not have an expiration date. Contingent upon GenOn's emergence from bankruptcy, the Company will recognize an estimated $7.8 billion worthless stock deduction for tax purposes. The NOL balances of $1.2 billion will remain with the GenOn group of companies upon emergence from bankruptcy.
In addition to these amounts, the Company has $36 million of tax effected uncertain tax benefits. As a result of the Company's tax position, and based on current forecasts, NRG anticipates income tax payments, primarily to state and local jurisdictions, of up to $25 million in 2017.
The Company has recorded a non-current tax liability of $40 million until final resolution with the related taxing authority. The $40 million non-current tax liability for uncertain tax benefits is from positions taken on various state income tax returns, including accrued interest.
NRG is subject to examination by taxing authorities for income tax returns filed in the U.S. federal jurisdiction and various state and foreign jurisdictions including operations located in Australia. The Company is not subject to U.S. federal income tax examinations for years prior to 2015. With few exceptions, state and local income tax examinations are no longer open for years prior to 2010. The Company's primary foreign operations are also no longer subject to examination by local jurisdictions for years prior to 2010.
Off-Balance Sheet Arrangements
Obligations under Certain Guarantee Contracts
NRG and certain of its subsidiaries enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include financial and performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications.
Retained or Contingent Interests
NRG does not have any material retained or contingent interests in assets transferred to an unconsolidated entity.
Obligations Arising Out of a Variable Interest in an Unconsolidated Entity
Variable interest in equity investments — As of September 30, 2017, NRG has several investments with an ownership interest percentage of 50% or less in energy and energy-related entities that are accounted for under the equity method of accounting. Several of these investments are variable interest entities for which NRG is not the primary beneficiary. See also Note 9, Variable Interest Entities, or VIEs, to this Form 10-Q.
NRG's pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $616 million as of September 30, 2017. This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to NRG. See also Note 16, Investments Accounted for by the Equity Method and Variable Interest Entities, to the Company's 2016 Form 10-K.
Contractual Obligations and Commercial Commitments
NRG has a variety of contractual obligations and other commercial commitments that represent prospective cash requirements in addition to the Company's capital expenditure programs, as disclosed in the Company's 2016 Form 10-K. See also Note 8, Debt and Capital Leases, and Note 15, Commitments and Contingencies, to this Form 10-Q for a discussion of new commitments and contingencies that also include contractual obligations and commercial commitments that occurred during the three and nine months ended September 30, 2017.

99



Fair Value of Derivative Instruments
NRG may enter into power purchase and sales contracts, fuel purchase contracts and other energy-related financial instruments to mitigate variability in earnings due to fluctuations in spot market prices and to hedge fuel requirements at generation facilities or retail load obligations. In addition, in order to mitigate interest rate risk associated with the issuance of the Company's variable rate and fixed rate debt, NRG enters into interest rate swap agreements. The following disclosures about fair value of derivative instruments provide an update to, and should be read in conjunction with, Fair Value of Derivative Instruments in Item 7 — Management's Discussion and Analysis of Financial Condition and Results of Operations, of the Company's 2016 Form 10‑K.
The tables below disclose the activities that include both exchange and non-exchange traded contracts accounted for at fair value in accordance with ASC 820, Fair Value Measurements and Disclosures, or ASC 820. Specifically, these tables disaggregate realized and unrealized changes in fair value; disaggregate estimated fair values at September 30, 2017, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at September 30, 2017.
Derivative Activity (Losses)/Gains
(In millions)
Fair Value of Contracts as of December 31, 2016
$
(128
)
Contracts realized or otherwise settled during the period
21

Changes in fair value
(41
)
Fair Value of Contracts as of September 30, 2017
$
(148
)
 
Fair Value of Contracts as of September 30, 2017
 
Maturity
Fair value hierarchy (Losses)/Gains
1 Year or Less
 
Greater than 1 Year to 3 Years
 
Greater than 3 Years to 5 Years
 
Greater than 5 Years
 
Total Fair
Value
 
(In millions)
Level 1
$
(34
)
 
$
(30
)
 
$
(5
)
 
$

 
$
(69
)
Level 2
11

 
(28
)
 
(14
)
 

 
(31
)
Level 3
(24
)
 
(11
)
 
(5
)
 
(8
)
 
(48
)
Total
$
(47
)
 
$
(69
)
 
$
(24
)
 
$
(8
)
 
$
(148
)
The Company has elected to present derivative assets and liabilities on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. Also, collateral received or paid on the Company's derivative assets or liabilities are recorded on a separate line item on the balance sheet. Consequently, the magnitude of the changes in individual current and non-current derivative assets or liabilities is higher than the underlying credit and market risk of the Company's portfolio. As discussed in Item 3 - Quantitative and Qualitative Disclosures About Market Risk, Commodity Price Risk, to this Form 10-Q, NRG measures the sensitivity of the Company's portfolio to potential changes in market prices using VaR, a statistical model which attempts to predict risk of loss based on market price and volatility. NRG's risk management policy places a limit on one-day holding period VaR, which limits the Company's net open position. As the Company's trade-by-trade derivative accounting results in a gross-up of the Company's derivative assets and liabilities, the net derivative asset and liability position is a better indicator of NRG's hedging activity. As of September 30, 2017, NRG's net derivative liability was $148 million, a decrease to total fair value of $20 million as compared to December 31, 2016. This decrease was driven by losses in fair value, largely offset by the roll-off of trades that settled during the period.
Based on a sensitivity analysis using simplified assumptions, the impact of a $0.50 per MMBtu increase in natural gas prices across the term of the derivative contracts would result in an increase of approximately $39 million in the net value of derivatives as of September 30, 2017. The impact of a $0.50 per MMBtu decrease in natural gas prices across the term of derivative contracts would result in a decrease of approximately $62 million in the net value of derivatives as of September 30, 2017.


100



Critical Accounting Policies and Estimates
NRG's discussion and analysis of the financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance as well as the use of estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges, and the fair value of certain assets and liabilities. These judgments, in and of themselves, could materially affect the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment may also have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies has not changed.
On an ongoing basis, NRG evaluates these estimates, utilizing historic experience, consultation with experts and other methods the Company considers reasonable. In any event, actual results may differ substantially from the Company's estimates. Any effects on the Company's business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the information that gives rise to the revision becomes known.
The Company identifies its most critical accounting policies as those that are the most pervasive and important to the portrayal of the Company's financial position and results of operations, and that require the most difficult, subjective and/or complex judgments by management regarding estimates about matters that are inherently uncertain. NRG's critical accounting policies include derivative instruments, income taxes and valuation allowance for deferred tax assets, impairment of long lived assets and investments, goodwill and other intangible assets, and contingencies.
The Company performs its annual test of goodwill impairment during the fourth quarter.  The Company tests its long-lived assets for impairment whenever indicators of impairment exist. The Company’s annual budget is utilized to determine the cash flows associated with the Company’s long-lived assets, which incorporates various assumptions, including the Company’s long-term view of natural gas prices and its impact on merchant power prices and fuel costs. The Company’s annual budget process is finalized and approved by the Board of Directors in the fourth quarter. It is reasonably possible that the updated long term cash flows will not support the carrying value of certain assets, and the Company will be required to test such assets for impairment. This could also have a negative impact on the fair value of the reporting units that have goodwill balances.  This decrease in power prices could also result in an adverse change in the manner that long-lived assets are used, or result in the Company selling an asset before the end of its previously estimated useful life, at a price that is lower than its carrying amount. During the preparation of the budget, the Company noted that management’s view of long term merchant power prices has decreased, and accordingly, it is reasonably possible that certain of the Company's goodwill and/or long-lived assets will be significantly impaired during the fourth quarter of 2017.



101



ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
NRG is exposed to several market risks in the Company's normal business activities. Market risk is the potential loss that may result from market changes associated with the Company's merchant power generation or with an existing or forecasted financial or commodity transaction. The types of market risks the Company is exposed to are commodity price risk, interest rate risk, liquidity risk, credit risk and currency exchange risk. The following disclosures about market risk provide an update to, and should be read in conjunction with, Item 7A — Quantitative and Qualitative Disclosures About Market Risk, of the Company's 2016 Form 10-K.
Commodity Price Risk
Commodity price risks result from exposures to changes in spot prices, forward prices, volatilities and correlations between various commodities, such as natural gas, electricity, coal, oil and emissions credits. NRG manages the commodity price risk of the Company's merchant generation operations and load serving obligations by entering into various derivative or non-derivative instruments to hedge the variability in future cash flows from forecasted sales and purchases of electricity and fuel. NRG measures the risk of the Company's portfolio using several analytical methods, including sensitivity tests, scenario tests, stress tests, position reports and VaR. NRG uses a Monte Carlo simulation based VaR model to estimate the potential loss in the fair value of its energy assets and liabilities, which includes generation assets, load obligations and bilateral physical and financial transactions.
The following table summarizes average, maximum and minimum VaR for NRG's commodity portfolio, including generation assets, load obligations and bilateral physical and financial transactions, calculated using the VaR model for the three and nine months ended September 30, 2017 and 2016:
(In millions)
2017
 
2016
VaR as of September 30,
$
40

 
$
40

Three months ended September 30,
 
 
 
Average
$
30

 
$
59

Maximum
40

 
72

Minimum
25

 
40

Nine months ended September 30,
 
 
 
Average
$
27

 
$
58

Maximum
40

 
72

Minimum
20

 
40

In order to provide additional information for comparative purposes to NRG's peers, the Company also uses VaR to estimate the potential loss of derivative financial instruments that are subject to mark-to-market accounting. These derivative instruments include transactions that were entered into for both asset management and trading purposes. The VaR for the derivative financial instruments calculated using the diversified VaR model as of September 30, 2017, for the entire term of these instruments entered into for both asset management and trading was $17 million, primarily driven by asset-backed transactions.
Interest Rate Risk
NRG is exposed to fluctuations in interest rates through its issuance of variable rate debt. Exposures to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, caps, collars and put or call options. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt obligations when taking into account the combination of the variable rate debt and the interest rate derivative instrument. NRG's risk management policies allow the Company to reduce interest rate exposure from variable rate debt obligations.
The Company's project subsidiaries enter into interest rate swaps, intended to hedge the risks associated with interest rates on non-recourse project level debt. See Note 12, Debt and Capital Leases, of the Company's 2016 Form 10-K for more information on the Company's interest rate swaps.
If all of the above swaps had been discontinued on September 30, 2017, the Company would have owed the counterparties $43 million. Based on the credit ratings of the counterparties, NRG believes its exposure to credit risk due to nonperformance by counterparties to its hedge contracts to be insignificant.
NRG has both long and short-term debt instruments that subject the Company to the risk of loss associated with movements in market interest rates. As of September 30, 2017, a 1% change in variable interest rates would result in a $13.8 million change in interest expense on a rolling twelve month basis.

102



As of September 30, 2017, the fair value and related carrying value of the Company's debt was $17.4 billion and $17.1 billion, respectively. NRG estimates that a 1% decrease in market interest rates would have increased the fair value of the Company's long-term debt by $984 million.
Liquidity Risk
Liquidity risk arises from the general funding needs of NRG's activities and in the management of the Company's assets and liabilities. The Company is currently exposed to additional collateral posting if natural gas prices decline primarily due to the long natural gas equivalent position at various exchanges used to hedge NRG's retail supply load obligations.
Based on a sensitivity analysis for power and gas positions under marginable contracts, a $0.50 per MMBtu change in natural gas prices across the term of the marginable contracts would cause a change in margin collateral posted of approximately $164 million as of September 30, 2017, and a 1 MMBtu/MWh change in heat rates for heat rate positions would result in a change in margin collateral posted of approximately $149 million as of September 30, 2017. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of September 30, 2017.
Credit Risk
Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. NRG is exposed to counterparty credit risk through various activities including wholesale sales, fuel purchases and retail supply arrangements, and retail customer credit risk through its retail load activities. See Note 4, Fair Value of Financial Instruments, to this Form 10-Q for discussions regarding counterparty credit risk and retail customer credit risk, and Note 6, Accounting for Derivative Instruments and Hedging Activities, to this Form 10-Q for discussion regarding credit risk contingent features.
Currency Exchange Risk
NRG's foreign earnings and investments may be subject to foreign currency exchange risk, which NRG generally does not hedge. As these earnings and investments are not material to NRG's consolidated results, the Company's foreign currency exposure is limited.

103



ITEM 4 — CONTROLS AND PROCEDURES
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
Under the supervision and with the participation of NRG's management, including its principal executive officer, principal financial officer and principal accounting officer, NRG conducted an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures, as such term is defined in Rules 13a-15(e) or 15d-15(e) of the Exchange Act. Based on this evaluation, the Company's principal executive officer, principal financial officer and principal accounting officer concluded that the disclosure controls and procedures were effective as of the end of the period covered by this Quarterly Report on Form 10-Q.
Changes in Internal Control over Financial Reporting
There were no changes in NRG’s internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred in the third quarter of 2017 that materially affected, or are reasonably likely to materially affect, NRG’s internal control over financial reporting.



104



PART II — OTHER INFORMATION
ITEM 1 — LEGAL PROCEEDINGS
For a discussion of material legal proceedings in which NRG was involved through September 30, 2017, see Note 15, Commitments and Contingencies, to this Form 10-Q.
ITEM 1A — RISK FACTORS
Information regarding risk factors appears in Part I, Item 1A, Risk Factors Related to NRG Energy, Inc., in the Company's 2016 Form 10-K, and Part II, Item 1A of the Company's Form 10-Q for the quarter ended June 30, 2017. There have been no material changes in the Company's risk factors since those reported in its 2016 Form 10‑K and its Form 10-Q for the quarter ended June 30, 2017.
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None.
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES
See Note 3, Discontinued Operations, Dispositions and Acquisitions, to the Condensed Consolidated Financial Statements of this Form 10-Q, for a description of events of default by GenOn and GenOn Americas Generation under the GenOn Senior Notes and the GenOn Americas Generation Senior Notes.
ITEM 4 — MINE SAFETY DISCLOSURES
Not applicable.
ITEM 5 — OTHER INFORMATION
None.

105



ITEM 6 — EXHIBITS
Number
 
Description
 
Method of Filing
10.1
 
 
Incorporated herein by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on October 6, 2017.
10.2
 
 
Incorporated herein by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed on October 6, 2017.
10.3
 
 
Incorporated herein by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on November 1, 2017.
31.1
 
 
Filed herewith.
31.2
 
 
Filed herewith.
31.3
 
 
Filed herewith.
32
 
 
Furnished herewith.
101 INS
 
XBRL Instance Document.
 
Filed herewith.
101 SCH
 
XBRL Taxonomy Extension Schema.
 
Filed herewith.
101 CAL
 
XBRL Taxonomy Extension Calculation Linkbase.
 
Filed herewith.
101 DEF
 
XBRL Taxonomy Extension Definition Linkbase.
 
Filed herewith.
101 LAB
 
XBRL Taxonomy Extension Label Linkbase.
 
Filed herewith.
101 PRE
 
XBRL Taxonomy Extension Presentation Linkbase.
 
Filed herewith.


106



SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
NRG ENERGY, INC.
(Registrant) 
 
 
 
 
 
/s/ MAURICIO GUTIERREZ 
 
 
Mauricio Gutierrez
 
 
Chief Executive Officer
(Principal Executive Officer) 
 
 
 
 
 
 
/s/ KIRKLAND B. ANDREWS  
 
 
Kirkland B. Andrews 
 
 
Chief Financial Officer
(Principal Financial Officer) 
 
 
 
 
 
 
/s/ DAVID CALLEN
 
 
David Callen
 
Date: November 2, 2017
Chief Accounting Officer
(Principal Accounting Officer) 
 
 




107