Annual Statements Open main menu

NRG ENERGY, INC. - Quarter Report: 2019 June (Form 10-Q)


 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
 
Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
 
 
 
 
 
 
 
For the Quarterly Period Ended:
June 30, 2019
 
 
 
 
 
 
 
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)
(Address of principal executive offices)
Delaware
 
 
 
41-1724239
(State or other jurisdiction
of incorporation or organization)
 
(I.R.S. Employer
Identification No.)
          804 Carnegie Center
,
Princeton
New Jersey
08540
(Address of principal executive offices)
 
(Zip Code)
(609524-4500
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Trading Symbol(s)
Name of Exchange on Which Registered
Common Stock, par value $0.01
NRG
New York Stock Exchange
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       No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files).
Yes       No
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
Accelerated filer
Non-accelerated filer
Smaller reporting company
Emerging growth 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.    
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes       No
As of August 7, 2019, there were 252,987,889 shares of common stock outstanding, par value $0.01 per share.
 

1


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 the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the 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 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, 2018 and the following:
NRG's ability to achieve the expected benefits of its Transformation Plan;
NRG's ability to obtain and maintain retail market share;
NRG's ability to engage in successful sales and divestitures as well as 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;
Changes in law, including judicial decisions;
Hazards customary to the power production industry and power generation operations, such as fuel and electricity price volatility, unusual weather 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 changes in market rules, rates, tariffs and environmental laws;
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 in the future;
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;
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 as needed.


3


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 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:
2018 Form 10-K
 
NRG’s Annual Report on Form 10-K for the year ended December 31, 2018
2023 Term Loan Facility
 
The Company's $1.7 billion (as of December 31, 2018) term loan facility due 2023, a component of the Senior Credit Facility, which was repaid during the second quarter of 2019
ACE
 
Affordable Clean Energy
Agua Caliente
 
Agua Caliente Solar Project, a 290 MW photovoltaic power station located in Yuma County, Arizona in which NRG owns 35% interest
ARO
 
Asset Retirement Obligation
ASC
 
The FASB Accounting Standards Codification, which the FASB established as the source of authoritative GAAP
ASU
 
Accounting Standards Updates - updates to the ASC
Average realized prices
 
Volume-weighted average power prices, net of average fuel costs and reflecting the impact of settled hedges
Bankruptcy Code
 
Chapter 11 of Title 11 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
BRA
 
Base Residual Auction
BTU
 
British Thermal Unit
Business Solutions
 
NRG's business solutions group, which includes demand response, commodity sales, energy efficiency and energy management services
CAA
 
Clean Air Act
CAISO
 
California Independent System Operator
Carlsbad
 
Carlsbad Energy Center, a 528 MW natural gas-fired project located in Carlsbad, CA
CDD
 
Cooling Degree Day
CDWR
 
California Department of Water Resources
CFTC
 
U.S. Commodity Futures Trading Commission
C&I
 
Commercial industrial and governmental/institutional
CES
 
Clean Energy Standard
Cleco
 
Cleco Corporate Holdings LLC
CO2
 
Carbon Dioxide
ComEd
 
Commonwealth Edison
Company
 
NRG Energy, Inc.
Cottonwood
 
Cottonwood Generating Station, a 1,153 MW natural gas-fueled plant which NRG is leasing through May 2025
CPP
 
Clean Power Plan
CWA
 
Clean Water Act
D.C. Circuit
 
U.S. Court of Appeals for the District of Columbia Circuit
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
DNREC
 
Delaware Department of Natural Resources and Environmental Control
Economic gross margin
 
Sum of energy revenue, capacity revenue, retail revenue and other revenue, less cost of fuels and other cost of sales
EGU
 
Electric Generating Unit
EME
 
Edison Mission Energy
EPA
 
U.S. Environmental Protection Agency
ERCOT
 
Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas
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

5


FASB
 
Financial Accounting Standards Board
FERC
 
Federal Energy Regulatory Commission
FGD
 
Flue gas desulfurization
FTRs
 
Financial Transmission Rights
GAAP
 
Generally accepted accounting principles in the U.S.
GenConn
 
GenConn Energy LLC
GenOn
 
GenOn Energy, Inc.
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
GHG
 
Greenhouse Gas
GIP
 
Global Infrastructure Partners
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 upon whether the electricity output measured is gross or net generation. Heat rates are generally expressed as BTU per net kWh
HLW
 
High-level radioactive waste
ICE
 
Intercontinental Exchange
ISO
 
Independent System Operator, also referred to as RTOs
ISO-NE
 
ISO New England Inc.
Ivanpah
 
Ivanpah Solar Electric Generation Station, a 393 MW solar thermal power plant located in California's Mojave Desert in which NRG owns 54.5% interest
kWh
 
Kilowatt-hour
LaGen
 
Louisiana Generating, LLC
LIBOR
 
London Inter-Bank Offered Rate
LTIPs
 
Collectively, the NRG LTIP and the NRG GenOn LTIP
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.
MMBtu
 
Million British Thermal Units
MW
 
Megawatts
MWe
 
Megawatt equivalent
MWh
 
Saleable megawatt hour net of internal/parasitic load megawatt-hour
NAAQS
 
National Ambient Air Quality Standards
NEPOOL
 
New England Power Pool
NERC
 
North American Electric Reliability Corporation
NJBPU
 
New Jersey Board of Public Utilities
Net Exposure
 
Counterparty credit exposure to NRG, net of collateral
Nodal
 
Nodal Exchange is a derivatives exchange
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.

6


NRG Yield, Inc.
 
NRG Yield, Inc., which changed it's name to Clearway Energy, Inc. following the sale by NRG of NRG Yield and the Renewables Platform to GIP
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
Nuclear Waste Policy Act
 
U.S. Nuclear Waste Policy Act of 1982
NY DEC
 
New York Department of Environmental Conservation
NYISO
 
New York Independent System Operator
NYMEX
 
New York Mercantile Exchange
NYSPSC
 
New York State Public Service Commission
OCI/OCL
 
Other Comprehensive Income/(Loss)
ORDC
 
Operating Reserve Demand Curve
PA PUC
 
Pennsylvania Public Utility Commission
Peaking
 
Units expected to satisfy demand requirements during the periods of greatest or peak load on a system
Petra Nova
 
Petra Nova Parish Holdings, LLC which is 50% owned by NRG and which owns and operates a 240 MWe carbon capture system and a 78 MW cogeneration facility, and owns an equity interest in an oilfield
PG&E
 
PG&E Corporation (NYSE: PCG) and its primary operating subsidiary, Pacific Gas and Electric Company
PJM
 
PJM Interconnection, LLC
PM2.5
 
Particulate Matter that has a diameter of less than 2.5 micrometers
PPA
 
Power Purchase Agreement
PUCT
 
Public Utility Commission of Texas
RCE
 
Residential Customer Equivalent is a unit of measure used by the energy industry to denote the typical annual commodity consumption by a single-family residential customer. 1 RCE represents 1,000 therms of natural gas or 10,000 kWh of electricity
RCRA
 
Resource Conservation and Recovery Act of 1976
Reliant Energy
 
Reliant Energy Retail Services, LLC
REMA
 
NRG REMA LLC, which leases a 100% interest in the Shawville generating facility and 16.7% and 16.5% interest in the Keystone and Conemaugh generating facilities, respectively
Renewables
 
Consists of the following projects in which NRG has an ownership interest: Agua Caliente, Ivanpah, and solar generating stations located at various NFL Stadiums
Renewables Platform
 
The renewable operating and development platform sold by NRG to GIP with NRG's interest in NRG Yield, Inc.
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
RGGI
 
Regional Greenhouse Gas Initiative
RTO
 
Regional Transmission Organization
SDG&E
 
San Diego Gas & Electric
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, comprised of the Revolving Credit Facility and the 2023 Term Loan Facility. The 2023 Term Loan Facility was repaid in the second quarter of 2019
Senior Notes
 
As of June 30, 2019, NRG's $3.8 billion outstanding unsecured senior notes consisting of $1.0 billion of the 7.25% senior notes due 2026, $1.23 billion of the 6.625% senior notes due 2027, $821 million of 5.75% senior notes due 2028 and $733 million of the 5.250% senior notes due 2029
SNF
 
Spent Nuclear Fuel
SO2
 
Sulfur Dioxide
South Central Portfolio
 
NRG's South Central Portfolio, which owned and operated a portfolio of generation assets consisting of Bayou Cove, Big Cajun-I, Big Cajun-II, Cottonwood and Sterlington, was sold on February 4, 2019. NRG is leasing back the Cottonwood facility through May 2025
STP
 
South Texas Project — nuclear generating facility located near Bay City, Texas in which NRG owns a 44% interest
STPNOC
 
South Texas Project Nuclear Operating Company

7


TSA
 
Transportation Services Agreement
TWCC
 
Texas Westmoreland Coal Co.
UPMC Thermal Project
 
University of Pittsburgh Medical Center thermal generating project that provides power, steam, chilled water and backup power located in Pittsburgh, PA.
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
VCP
 
Voluntary Clean-Up Program
VIE
 
Variable Interest Entity

8


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 June 30,

Six months ended June 30,
(In millions, except for per share amounts)
2019

2018

2019

2018
Operating Revenues

 

 

 

Total operating revenues
$
2,465


$
2,461


$
4,630


$
4,526

Operating Costs and Expenses







Cost of operations
1,845


1,889


3,496


3,274

Depreciation and amortization
85


112


170


232

Impairment losses
1


74


1


74

Selling, general and administrative
211


200


405


376

Reorganization costs
2


23


15


43

Development costs
2


3


4


8

Total operating costs and expenses
2,146


2,301


4,091


4,007

Gain on sale of assets
1


14


2


16

Operating Income
320


174


541


535

Other Income/(Expense)







Equity in earnings/(losses) of unconsolidated affiliates


5


(21
)

6

Other income/(expense), net
20


(23
)

32


(23
)
Loss on debt extinguishment, net
(47
)

(1
)

(47
)

(3
)
Interest expense
(105
)

(123
)

(219
)

(239
)
Total other expense
(132
)

(142
)

(255
)

(259
)
Income from Continuing Operations Before Income Taxes
188


32


286


276

Income tax (benefit)/expense
(1
)

5


3


11

Income from Continuing Operations
189


27


283


265

Income from discontinued operations, net of income tax
13


69


401


64

Net Income
202


96


684


329

Less: Net income/(loss) attributable to noncontrolling interest and redeemable interests
1


24


1


(22
)
Net Income Attributable to NRG Energy, Inc.
$
201


$
72


$
683


$
351

Earnings per Share Attributable to NRG Energy, Inc.







Weighted average number of common shares outstanding — basic
265


310


272


314

Income from continuing operations per weighted average common share — basic
$
0.71


$
0.01


$
1.04


$
0.92

Income from discontinued operations per weighted average common share — basic
$
0.05


$
0.22


$
1.47


$
0.20

Earnings per Weighted Average Common Share — Basic
$
0.76


$
0.23


$
2.51


$
1.12

Weighted average number of common shares outstanding — diluted
267


314


274


318

Income from continuing operations per weighted average common share — diluted
$
0.70


$
0.01


$
1.03


$
0.90

Income from discontinued operations per weighted average common share — diluted
$
0.05


$
0.22


$
1.46


$
0.20

Earnings per Weighted Average Common Share — Diluted
$
0.75


$
0.23


$
2.49


$
1.10

Dividends Per Common Share
$
0.03


$
0.03


$
0.06


$
0.06

See accompanying notes to condensed consolidated financial statements.

9



NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

Three months ended June 30,

Six months ended June 30,

2019

2018

2019

2018
 
(In millions)
Net Income
$
202

 
$
96

 
$
684

 
$
329

Other Comprehensive (Loss)/Income
 
 
 
 
 
 
 
Unrealized gain on derivatives

 
5

 

 
19

Foreign currency translation adjustments
(1
)
 
(4
)
 

 
(6
)
Available-for-sale securities
1

 
1

 
1

 
1

Defined benefit plans
(3
)
 
(1
)
 
(6
)
 
(2
)
Other comprehensive (loss)/income
(3
)
 
1

 
(5
)
 
12

Comprehensive Income
199

 
97

 
679

 
341

Less: Comprehensive income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interest
1

 
26

 
1

 
(12
)
Comprehensive Income Attributable to NRG Energy, Inc.
$
198

 
$
71

 
$
678

 
$
353

See accompanying notes to condensed consolidated financial statements.

10


NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
 
June 30, 2019
 
December 31, 2018
(In millions, except share data)
(Unaudited)
 
 
ASSETS
 
 
 
Current Assets
 
 
 
Cash and cash equivalents
$
294

 
$
563

Funds deposited by counterparties
31

 
33

Restricted cash
11

 
17

Accounts receivable, net
1,049

 
1,024

Inventory
370

 
412

Derivative instruments
850

 
764

Cash collateral paid in support of energy risk management activities
163

 
287

Prepayments and other current assets
277

 
302

Current assets - held-for-sale

 
1

Current assets - discontinued operations

 
197

Total current assets
3,045

 
3,600

Property, plant and equipment, net
2,610

 
3,048

Other Assets
 
 
 
Equity investments in affiliates
383

 
412

Operating lease right-of-use assets, net
499

 

Goodwill
573

 
573

Intangible assets, net
561

 
591

Nuclear decommissioning trust fund
748

 
663

Derivative instruments
426

 
317

Deferred income taxes
55

 
46

Other non-current assets
271

 
289

Non-current assets - held-for-sale

 
77

Non-current assets - discontinued operations

 
1,012

Total other assets
3,516

 
3,980

Total Assets
$
9,171

 
$
10,628

LIABILITIES AND STOCKHOLDERS' EQUITY
 
 
 
Current Liabilities
 
 
 
Current portion of long-term debt and capital leases
$
87

 
$
72

Current portion of operating lease liabilities
74

 

Accounts payable
723

 
863

Derivative instruments
778

 
673

Cash collateral received in support of energy risk management activities
31

 
33

Accrued expenses and other current liabilities
601

 
680

Current liabilities - held-for-sale

 
5

Current liabilities - discontinued operations

 
72

Total current liabilities
2,294

 
2,398

Other Liabilities
 
 
 
Long-term debt and capital leases
5,794

 
6,449

Non-current operating lease liabilities
513

 

Nuclear decommissioning reserve
290

 
282

Nuclear decommissioning trust liability
448

 
371

Derivative instruments
374

 
304

Deferred income taxes
71

 
65

Other non-current liabilities
1,016

 
1,274

Non-current liabilities - held-for-sale

 
65

Non-current liabilities - discontinued operations

 
635

Total other liabilities
8,506

 
9,445

Total Liabilities
10,800

 
11,843

Redeemable noncontrolling interest in subsidiaries
19

 
19

Commitments and Contingencies


 


Stockholders' Equity
 
 
 
Common stock; $0.01 par value; 500,000,000 shares authorized; 421,830,474 and 420,288,886 shares issued and 258,570,598 and 283,650,039 shares outstanding at June 30, 2019 and December 31, 2018, respectively
4

 
4

Additional paid-in-capital
8,488

 
8,510

Accumulated deficit
(5,355
)
 
(6,022
)
Less treasury stock, at cost - 163,259,876 and 136,638,847 shares at June 30, 2019 and December 31, 2018, respectively
(4,686
)
 
(3,632
)
Accumulated other comprehensive loss
(99
)
 
(94
)
Total Stockholders' Equity
(1,648
)
 
(1,234
)
Total Liabilities and Stockholders' Equity
$
9,171

 
$
10,628


See accompanying notes to condensed consolidated financial statements.

11


NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)


Six months ended June 30,
(In millions)
2019
 
2018
Cash Flows from Operating Activities
 
 
 
Net Income
$
684

 
$
329

Income from discontinued operations, net of income tax
401

 
64

Income from continuing operations
283

 
265

Adjustments to reconcile net income to cash provided by operating activities:
 
 
 
Distributions and equity earnings of unconsolidated affiliates
22

 
12

Depreciation, amortization and accretion
184

 
252

Provision for bad debts
52

 
30

Amortization of nuclear fuel
27

 
24

Amortization of financing costs and debt discount/premiums
13

 
13

Loss on debt extinguishment, net
47

 
3

Amortization of intangibles and out-of-market contracts
14

 
20

Amortization of unearned equity compensation
10

 
15

Loss/(gain) on sale and disposal of assets
1

 
(16
)
Impairment losses
1

 
88

Changes in derivative instruments
(22
)
 
(145
)
Changes in deferred income taxes and liability for uncertain tax benefits
(5
)
 
(2
)
Changes in collateral deposits in support of energy risk management activities
125

 
(9
)
Changes in nuclear decommissioning trust liability
17

 
41

Loss on deconsolidation of Ivanpah project

 
22

Changes in other working capital
(388
)
 
(349
)
Cash provided by continuing operations
381

 
264

Cash provided by discontinued operations
8

 
249

Net Cash Provided by Operating Activities
389

 
513

Cash Flows from Investing Activities
 
 
 
Payments for acquisitions of businesses
(21
)
 
(211
)
Capital expenditures
(107
)
 
(282
)
Net proceeds from sale of emission allowances
(1
)
 
3

Investments in nuclear decommissioning trust fund securities
(209
)
 
(346
)
Proceeds from the sale of nuclear decommissioning trust fund securities
191

 
303

Proceeds from sale of assets, net of cash disposed and sale of discontinued operations, net of fees
1,289

 
146

Deconsolidation of Ivanpah project

 
(160
)
Net distributions from investments in unconsolidated affiliates
7

 
(15
)
Contributions to discontinued operations
(44
)
 
(16
)
Cash provided/(used) by continuing operations
1,105

 
(578
)
Cash used by discontinued operations
(2
)
 
(584
)
Net Cash Provided/(Used) by Investing Activities
1,103

 
(1,162
)
Cash Flows from Financing Activities
 
 
 
Payments of dividends to common stockholders
(16
)
 
(19
)
Payments for treasury stock
(1,039
)
 
(500
)
Payments for debt extinguishment costs
(24
)
 

Distributions to noncontrolling interests from subsidiaries
(1
)
 
(14
)
Proceeds from issuance of common stock
2

 
11

Proceeds from issuance of short and long-term debt
1,833

 
994

Payment of debt issuance costs
(33
)
 
(19
)
Payments for short and long-term debt
(2,485
)
 
(348
)
Cash (used)/provided by continuing operations
(1,763
)
 
105

Cash provided by discontinued operations
43

 
345

Net Cash (Used)/Provided by Financing Activities
(1,720
)
 
450

Change in Cash from discontinued operations
49

 
10

Net Decrease in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash
(277
)
 
(209
)
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period
613

 
1,086

Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period
$
336

 
$
877

See accompanying notes to condensed consolidated financial statements.

12



NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(Unaudited)
 
Common
Stock
 
Additional
Paid-In
Capital
 
Accumulated Deficit
 
Treasury
Stock
 
Accumulated
Other
Comprehensive
Loss
 
Total
Stock-holders'
Equity
 
(In millions)
Balance at December 31, 2018
$
4

 
$
8,510

 
$
(6,022
)
 
$
(3,632
)
 
$
(94
)
 
$
(1,234
)
Net income
 
 
 
 
482

 
 
 
 
 
482

Other comprehensive loss
 
 
 
 
 
 
 
 
(2
)
 
(2
)
Share repurchases
 
 
(10
)
 
 
 
(739
)
 
 
 
(749
)
Equity-based compensation
 
 
(32
)
 


 
 
 
 
 
(32
)
Issuance of common stock
 
 
5

 
 
 
 
 
 
 
5

Common stock dividends
 
 
 
 
(8
)
 
 
 
 
 
(8
)
Balance at March 31, 2019
$
4

 
$
8,473

 
$
(5,548
)
 
$
(4,371
)
 
$
(96
)
 
$
(1,538
)
Net income
 
 
 
 
201

 
 
 
 
 
201

Other comprehensive loss
 
 
 
 
 
 
 
 
(3
)
 
(3
)
Share repurchases
 
 
10

 
 
 
(315
)
 
 
 
(305
)
Equity-based compensation
 
 
5

 
 
 
 
 
 
 
5

Common stock dividends
 
 
 
 
(8
)
 
 
 
 
 
(8
)
Balance at June 30, 2019
$
4

 
$
8,488

 
$
(5,355
)
 
$
(4,686
)
 
$
(99
)

$
(1,648
)






















13


NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Continued)
(Unaudited)

 
Common
Stock
 
Additional
Paid-In
Capital
 
Accumulated Deficit
 
Treasury
Stock
 
Accumulated
Other
Comprehensive
Loss
 
Noncon- trolling
Interest
 
Total
Stock-holders'
Equity
 
(In millions)
Balance at December 31, 2017
$
4

 
$
8,376

 
$
(6,268
)
 
$
(2,386
)
 
$
(72
)
 
$
2,314

 
$
1,968

Net income/(loss)
 
 
 
 
279

 
 
 
 
 
(30
)
 
249

Other comprehensive income
 
 
 
 
 
 
 
 
11

 
 
 
11

Sale of assets to NRG Yield, Inc.
 
 
8

 
 
 
 
 
 
 
4

 
12

ESPP share purchases
 
 
(2
)
 
 
 
5

 
 
 
 
 
3

Share repurchases
 
 
 
 
 
 
(93
)
 
 
 
 
 
(93
)
Equity-based compensation
 
 
(10
)
 
 
 
 
 
 
 
 
 
(10
)
Issuance of common stock
 
 
7

 
 
 
 
 
 
 
 
 
7

Common stock dividends
 
 
 
 
(10
)
 
 
 
 
 
 
 
(10
)
Distributions to noncontrolling interests
 
 
 
 
 
 
 
 
 
 
(19
)
 
(19
)
Dividends paid to NRG Yield, Inc.
 
 
 
 
 
 
 
 
 
 
(30
)
 
(30
)
Contributions from noncontrolling interests
 
 
 
 
 
 
 
 
 
 
153

 
153

Adoption of new accounting standards
 
 
 
 
17

 
 
 
 
 
 
 
17

Balance at March 31, 2018
$
4

 
$
8,379

 
$
(5,982
)
 
$
(2,474
)
 
$
(61
)
 
$
2,392

 
$
2,258

Net income
 
 
 
 
72

 
 
 
 
 
32

 
104

Other comprehensive income
 
 
 
 
 
 
 
 
1

 
 
 
1

Sale of assets to NRG Yield, Inc.
 
 
 
 
 
 
 
 
 
 
(2
)
 
(2
)
ESPP share purchases
 
 
 
 
 
 
(1
)
 
 
 
 
 
(1
)
Share repurchases
 
 
(11
)
 
 
 
(396
)
 
 
 
 
 
(407
)
Equity-based compensation
 
 
8

 
 
 
 
 
 
 
 
 
8

Issuance of common stock
 
 
4

 
 
 
 
 
 
 
 
 
4

Common stock dividends
 
 
 
 
(9
)
 
 
 
 
 
 
 
(9
)
Distributions to noncontrolling interests
 
 
 
 
 
 
 
 
 
 
(15
)
 
(15
)
Dividends paid to NRG Yield, Inc.
 
 
 
 
 
 
 
 
 
 
(31
)
 
(31
)
Contributions from noncontrolling interests
 
 
 
 
 
 
 
 
 
 
150

 
150

Adoption of new accounting standards
 
 
 
 
(1
)
 
 
 
 
 
 
 
(1
)
Deconsolidation of Business
 
 
 
 
 
 
 
 
 
 
(89
)
 
(89
)
Equity component of convertible senior notes
 
 
101

 
 
 
 
 
 
 
 
 
101

Balance at June 30, 2018
$
4

 
$
8,481

 
$
(5,920
)
 
$
(2,871
)
 
$
(60
)
 
$
2,437

 
$
2,071


See accompanying notes to condensed consolidated financial statements.


14


NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1Nature of Business and Basis of Presentation
General
NRG Energy, Inc., or NRG or the Company, is an energy company built on dynamic retail brands with diverse generation assets. NRG brings the power of energy to consumers by producing, selling and delivering electricity and related products and services in major competitive power markets in the U.S. in a manner that delivers value to all of NRG's stakeholders. NRG is perfecting the integrated model by balancing retail load with generation supply within its deregulated markets, while evolving to a customer-driven business. The Company sells energy, services, and innovative, sustainable products and services directly to retail customers under the names "NRG", "Reliant" and other brand names owned by NRG, supported by approximately 23,000 MW of generation as of June 30, 2019.
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 2018 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 June 30, 2019, and the results of operations, comprehensive income, cash flows and statements of stockholders' equity for the three and six months ended June 30, 2019 and 2018.
Discontinued Operations
During the fourth quarter of 2018, as described in Note 4, Acquisitions, Discontinued Operations and Dispositions, the Company concluded that the sale of its South Central Portfolio to Cleco, excluding the Cottonwood facility, met held-for-sale criteria and should be presented as discontinued operations, as the sale, which closed on February 4, 2019, represented a strategic shift in the business in which NRG operates. The financial information for all historical periods has been recast to reflect the presentation of these entities as discontinued operations.
On August 31, 2018, as described in Note 4, Acquisitions, Discontinued Operations and Dispositions, NRG deconsolidated NRG Yield, Inc. and its Renewables Platform for financial reporting purposes. The financial information for all historical periods has been recast to reflect the presentation of these entities, as well as the Carlsbad project, as discontinued operations. As a result of the sale of NRG Yield, the Company no longer controls the Agua Caliente project. Due to this change in control, the Company also deconsolidated the Agua Caliente project from its financial results and began accounting for the project as an equity method investment.
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.


15


Note 2Summary of Significant Accounting Policies
Net Income attributable to NRG Energy, Inc.
The following table reflects the net income attributable to NRG Energy, Inc. after removing the net income/(loss) attributable to the noncontrolling interest and redeemable noncontrolling interest:
 
Three months ended June 30,
 
Six months ended June 30,
 
2019
 
2018
 
2019
 
2018
 
(In millions)
Income from continuing operations, net of income tax
$
188

 
$
27

 
$
282

 
$
272

Income from discontinued operations, net of income tax
13

 
45

 
401

 
79

Net income attributable to NRG Energy, Inc.
$
201

 
$
72

 
$
683

 
$
351


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:
 
June 30, 2019
 
December 31, 2018
 
(In millions)
Accounts receivable allowance for doubtful accounts
$
28

 
$
32

Property, plant and equipment accumulated depreciation
1,684

 
1,811

Intangible assets accumulated amortization
1,182

 
1,149

Out-of-market contracts accumulated amortization

 
37


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 sheets that sum to the total of the same such amounts shown in the statements of cash flows.
 
June 30, 2019
 
December 31, 2018
 
(In millions)
Cash and cash equivalents
$
294

 
$
563

Funds deposited by counterparties
31

 
33

Restricted cash
11

 
17

Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows
$
336

 
$
613


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.
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.




16



Recent Accounting Developments - Guidance Adopted in 2019
ASU 2016-02 - In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), or Topic 842, which was further amended through various updates issued by the FASB thereafter, 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 adopted the standard and its subsequent corresponding updates effective January 1, 2019 under the modified retrospective approach by applying the provisions of the new leases guidance at the effective date without adjusting the comparative periods presented. The Company assessed its leasing arrangements, evaluated the impact of applying practical expedients and accounting policy elections, and implemented lease accounting software to meet the reporting requirements of the standard. The Company established operating lease liabilities of $404 million and right-of-use assets of $321 million upon adoption, before considering deferred taxes. The adoption of Topic 842 did not have a material impact on the statements of operations or cash flows. See Note 8, Leases, for further discussion.

Recent Accounting Developments - Guidance Not Yet Adopted
ASU 2018-17 - In October 2018, the FASB issued ASU No. 2018-17, Consolidations (Topic 810): Targeted Improvements to Related Party Guidance for Variable Interest Entities, in response to stakeholders’ observations that Topic 810, Consolidations, could be improved thereby improving general purpose financial reporting. Specifically, ASC 2018-17 requires application of the variable interest entity (VIE) guidance to private companies under common control and consideration of indirect interest held through related parties under common control for determining whether fees paid to decision makers and service providers are variable interests. The amendments are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. All entities are required to apply the amendments retrospectively with a cumulative-effect adjustment to retained earnings at the beginning of the earliest period presented. The Company is evaluating the impact of adopting this guidance on the consolidated financial statements and disclosures.

ASU 2018-13 - In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework - Changes to the Disclosure Requirement for Fair value Measurement), or ASU No. 2018-13. The guidance in ASU No. 2018-13 eliminates such disclosures as the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy. The amendments in ASU No. 2018-13 add new disclosure requirements for Level 3 measurements. ASU No. 2018-13 is effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years, with early adoption permitted for any eliminated or modified disclosures. Certain disclosures in ASU No. 2018-13 are required to be applied on a retrospective basis and others on a prospective basis. As the amendment contemplates changes in disclosures only, it will have no material impact on the Company's results of operations, cash flows, or statement of financial position.

Note 3Revenue Recognition
Performance Obligations
As of June 30, 2019, estimated future fixed fee performance obligations are $315 million for the remaining six months of fiscal year 2019, and $512 million, $542 million, $284 million and $29 million for the entirety of fiscal years 2020, 2021, 2022 and 2023, respectively. These performance obligations are for cleared auction MWs in the PJM, ISO-NE, NYISO and MISO capacity auctions and are subject to penalties for non performance.
 

17


Disaggregated Revenues     
The following tables represent the Company’s disaggregation of revenue from contracts with customers for the three and six months ended June 30, 2019 and 2018 along with the reportable segment for each category:
 
Three months ended June 30, 2019
 
 
 
Generation
 
 
 
 
(In millions)
Retail
 
Texas
 
East/West/Other
 
Subtotal
 
Corporate/Eliminations
 
Total
Energy revenue(a)(c)
$

 
$
497

 
$
117

 
$
614

 
$
(365
)
 
$
249

Capacity revenue(c)

 

 
154

 
154

 
1

 
155

Retail revenue
 
 
 
 
 
 
 
 
 
 
 
Mass customers
1,401

 

 

 

 
(1
)
 
1,400

Business Solutions customers
345

 

 

 

 

 
345

Total retail revenue
1,746

 

 

 

 
(1
)
 
1,745

Mark-to-market for economic hedging activities(a)(b)
2

 
460

 
64

 
524

 
(285
)
 
241

Other revenues(c)

 
16

 
59

 
75

 

 
75

Total operating revenue
1,748

 
973

 
394

 
1,367

 
(650
)
 
2,465

Less: Lease revenue
3

 

 
2

 
2

 

 
5

Less: Realized and unrealized ASC 815 revenue(a)
2

 
1,184

 
140

 
1,324

 
(649
)
 
677

Total revenue from contracts with customers
$
1,743

 
$
(211
)
 
$
252

 
$
41

 
$
(1
)
 
$
1,783

(a) Generation includes higher revenues due to the Company's large internal transfer of power based on average annualized market prices, which are offset by higher
       cost of operations within Retail
(b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815
(c) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 which are included in the amounts above:
 
Retail
 
Texas
 
East/West/Other
 
Subtotal
 
Corporate/Eliminations
 
Total
Energy revenue
$

 
$
717

 
$
42

 
$
759

 
$
(365
)
 
$
394

Capacity revenue

 

 
29

 
29

 
1

 
30

Other revenue

 
7

 
5

 
12

 

 
12


18


 
Three months ended June 30, 2018
 
 
 
Generation
 
 
 
 
(In millions)
Retail
 
Texas
 
East/West/Other
 
Subtotal
 
Corporate/Eliminations
 
Total
Energy revenue(a)(c)
$

 
$
402

 
$
259

 
$
661

 
$
(251
)
 
$
410

Capacity revenue(c)

 

 
165

 
165

 

 
165

Retail revenue
 
 
 
 
 
 
 
 
 
 
 
Mass customers
1,377

 

 

 

 
(1
)
 
1,376

Business Solutions customers
437

 

 

 

 

 
437

Total retail revenue
1,814

 

 

 

 
(1
)
 
1,813

Mark-to-market for economic hedging activities(a)(b)

 
296

 
(22
)
 
274

 
(264
)
 
10

Other revenues(c)

 
10

 
57

 
67

 
(4
)
 
63

Total operating revenue
1,814

 
708

 
459

 
1,167

 
(520
)
 
2,461

Less: Lease revenue
3

 

 
2

 
2

 

 
5

Less: Realized and unrealized ASC 815 revenue(a)

 
865

 
48

 
913

 
(511
)
 
402

Total revenue from contracts with customers
$
1,811

 
$
(157
)
 
$
409

 
$
252

 
$
(9
)
 
$
2,054

(a) Generation includes higher revenues due to the Company's large internal transfer of power based on average annualized market prices, which are offset by higher
       cost of operations within Retail
(b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815
(c) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 which are included in the amounts above:
 
Retail
 
Texas
 
East/West/Other
 
Subtotal
 
Corporate/Eliminations
 
Total
Energy revenue
$

 
$
569

 
$
26

 
$
595

 
$
(247
)
 
$
348

Capacity revenue

 

 
39

 
39

 

 
39

Other revenue

 

 
5

 
5

 

 
5


 
Six months ended June 30, 2019
 
 
 
Generation
 
 
 
 
(In millions)
Retail
 
Texas
 
East/West/Other
 
Subtotal
 
Corporate/Eliminations
 
Total
Energy revenue(a)(c)
$

 
$
855

 
$
341

 
$
1,196

 
$
(641
)
 
$
555

Capacity revenue(c)

 

 
309

 
309

 

 
309

Retail revenue
 
 
 
 
 
 
 
 
 
 
 
Mass customers
2,722

 

 

 

 
(2
)
 
2,720

Business Solutions customers
631

 

 

 

 

 
631

Total retail revenue
3,353

 

 

 

 
(2
)
 
3,351

Mark-to-market for economic hedging activities(a)(b)
2

 
473

 
56

 
529

 
(270
)
 
261

Other revenues(c)

 
45

 
111

 
156

 
(2
)
 
154

Total operating revenue
3,355

 
1,373

 
817

 
2,190

 
(915
)
 
4,630

Less: Lease revenue
6

 

 
4

 
4

 

 
10

Less: Realized and unrealized ASC 815 revenue(a)
2

 
1,730

 
237

 
1,967

 
(911
)
 
1,058

Total revenue from contracts with customers
$
3,347

 
$
(357
)
 
$
576

 
$
219

 
$
(4
)
 
$
3,562

(a) Generation includes higher revenues due to the Company's large internal transfer of power based on average annualized market prices, which are offset by higher
       cost of operations within Retail
(b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815
(c) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 which are included in the amounts above:
 
Retail
 
Texas
 
East/West/Other
 
Subtotal
 
Corporate/Eliminations
 
Total
Energy revenue
$

 
$
1,242

 
$
129

 
$
1,371

 
$
(641
)
 
$
730

Capacity revenue

 

 
48

 
48

 

 
48

Other revenue

 
15

 
4

 
19

 

 
19


 

19


 
Six months ended June 30, 2018
 
 
 
Generation
 
 
 
 
(In millions)
Retail
 
Texas
 
East/West/Other
 
Subtotal
 
Corporate/Eliminations
 
Total
Energy revenue(a)(c)
$

 
$
666

 
$
598

 
$
1,264

 
$
(411
)
 
$
853

Capacity revenue(c)

 

 
308

 
308

 
(1
)
 
307

Retail revenue
 
 
 
 
 
 
 
 
 
 
 
Mass customers
2,553

 

 

 

 
(2
)
 
2,551

Business Solutions customers
747

 

 

 

 

 
747

Total retail revenue
3,300

 

 

 

 
(2
)
 
3,298

Mark-to-market for economic hedging activities(a)(b)
(6
)
 
(273
)
 
(27
)
 
(300
)
 
220

 
(86
)
Other revenues(c)

 
64

 
102

 
166

 
(12
)
 
154

Total operating revenue
3,294

 
457

 
981

 
1,438

 
(206
)
 
4,526

Less: Lease revenue
7

 

 
4

 
4

 

 
11

Less: Realized and unrealized ASC 815 revenue(a)
(6
)
 
714

 
132

 
846

 
(184
)
 
656

Total revenue from contracts with customers
$
3,293

 
$
(257
)
 
$
845

 
$
588

 
$
(22
)
 
$
3,859

(a) Generation includes higher revenues due to the Company's large internal transfer of power based on average annualized market prices, which are offset by higher
       cost of operations within Retail
(b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815
(c) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 which are included in the amounts above:
 
Retail
 
Texas
 
East/West/Other
 
Subtotal
 
Corporate/Eliminations
 
Total
Energy revenue
$

 
$
982

 
$
86

 
$
1,068

 
$
(404
)
 
$
664

Capacity revenue

 

 
65

 
65

 

 
65

Other revenue

 
5

 
8

 
13

 

 
13



Contract Balances
The following table reflects the contract assets and liabilities included in the Company’s balance sheet as of June 30, 2019
and December 31, 2018:
(In millions)
June 30, 2019
 
December 31, 2018
Deferred customer acquisition costs
$
123

 
$
111

 
 
 
 
Accounts receivable, net - Contracts with customers
1,015

 
999

Accounts receivable, net - Derivative instruments
43

 
20

Accounts receivable, net - Affiliate
4

 
5

Total accounts receivable, net
$
1,062

 
$
1,024

 
 
 
 
Unbilled revenues (included within Accounts receivable, net - Contracts with customers)
$
403

 
$
392

Deferred revenues(a)
89

 
67

(a) Deferred revenues from contracts with customers for the six month period ended June 30, 2019 and the twelve month period ended December 31, 2018 were approximately $31 million and $19 million, respectively
The revenue recognized during the six months ended June 30, 2019 and 2018, relating to the deferred revenue balance at the beginning of each period was $13 million and $16 million, respectively. The revenue recognized during the three months ended June 30, 2019 and 2018, relating to the deferred revenue balance at the beginning of each period was $19 million and $16 million, respectively. The change in deferred revenue balances during the three and six months ended June 30, 2019 and 2018 was primarily due to the timing difference of when consideration was received and when the performance obligation was transferred.


20


Note 4Acquisitions, Discontinued Operations and Dispositions
Acquisitions
Stream Energy Acquisition - On May 15, 2019, the Company entered into an agreement to acquire Stream Energy's retail electricity and natural gas business operating in 9 states and Washington, D.C. for $300 million in cash and estimated transaction costs and working capital adjustments of approximately $25 million. The acquisition increased NRG's retail portfolio by approximately 600,000 RCEs or 450,000 customers. The acquisition closed on August 1, 2019.
XOOM Energy Acquisition - On June 1, 2018, the Company completed the acquisition of XOOM Energy, LLC, an electricity and natural gas retailer operating in 19 states, Washington, D.C. and Canada for $213 million in cash. The acquisition increased NRG's retail portfolio by approximately 395,000 RCEs or 300,000 customers. The purchase price was allocated as follows:
 
(In millions)
Net current and non-current working capital
$
46

Other intangible assets
133

Goodwill
34

XOOM Purchase Price
$
213


Discontinued Operations
Sale of South Central Portfolio
On February 4, 2019, the Company completed the sale of the South Central Portfolio to Cleco for cash consideration of $1 billion excluding working capital and other adjustments. The Company concluded that the divested business met the criteria for discontinued operations as of December 31, 2018, as the disposition represented a strategic shift in the business in which NRG operates and the criteria for held-for-sale were met. As such, all current and prior period results for the operations of the South Central Portfolio, except for the Cottonwood facility as discussed below, were reclassified as discontinued operations. In connection with the transaction, NRG also entered into a transition services agreement to provide certain corporate services to the divested business.
The South Central Portfolio includes the 1,153 MW Cottonwood natural gas generating facility. Upon the closing of the sale of the South Central Portfolio, NRG entered into an agreement with Cleco to leaseback the Cottonwood facility through May 2025. Due to its continuing involvement with the Cottonwood facility, NRG did not use discontinued operations treatment in accounting for historical and ongoing activity with Cottonwood.
Summarized results of the South Central Portfolio discontinued operations were as follows:    
 
Three months ended
 
Six months ended
(In millions)
June 30, 2019
 
June 30, 2018
 
June 30, 2019
 
June 30, 2018
Operating revenues
$

 
$
107

 
$
31

 
$
209

Operating costs and expenses

 
(91
)
 
(23
)
 
(177
)
Gain from discontinued operations, net of tax

 
16

 
8

 
32

Gain on disposal of discontinued operations, net of tax
1

 

 
28

 

Gain from discontinued operations, including disposal, net of tax
$
1

 
$
16

 
$
36

 
$
32



21


The following table summarizes the major classes of assets and liabilities classified as discontinued operations of the South Central Portfolio:
(In millions)
 
December 31, 2018
Cash and cash equivalents
 
$
89

Accounts receivable - trade, net
 
49

Inventory
 
35

Other current assets
 
5

Current assets - discontinued operations
 
178

Property, plant and equipment, net
 
408

Other non-current assets
 
1

Non-current assets - discontinued operations
 
409

Accounts payable
 
19

Other current liabilities
 
5

Current liabilities - discontinued operations
 
24

Out-of-market contracts, net
 
50

Other non-current liabilities
 
11

Non-current liabilities - discontinued operations
 
$
61


Sale of Ownership in NRG Yield, Inc. and the Renewables Platform
On August 31, 2018, the Company completed the sale of its ownership interests in NRG Yield, Inc. and the Renewables Platform to GIP for total cash consideration of $1.348 billion. The Company concluded that the divested businesses met the criteria for discontinued operations, as the dispositions represent a strategic shift in the markets in which NRG operates. As such, all prior period results for NRG Yield, Inc. and the Renewables Platform were reclassified as discontinued operations. In connection with the transaction, NRG entered into a transition services agreement to provide certain corporate services to the divested businesses. During the six months ended June 30, 2019, the Company recorded an adjustment to reduce the purchase price by $17 million in connection with the completion of the Patriot Wind project. The Company expects to recover a portion of this adjustment in the future. During the six months ended June 30, 2019, the Company reduced the liability related to the indemnification of NRG Yield for any increase in property taxes for certain solar properties by $22 million due to updated estimates.
Carlsbad
On February 6, 2018, NRG entered into an agreement with NRG Yield and GIP to sell 100% of its membership interests in Carlsbad Energy Holdings LLC, which owns the Carlsbad project, for $385 million of cash consideration, excluding working capital adjustments. The primary condition to close the Carlsbad transaction was the completion of the sale of NRG Yield and the Renewables Platform. At the time of the sale of NRG Yield and the Renewables Platform in August 2018, the Company concluded that the Carlsbad project met the criteria for discontinued operations and accordingly, all current and prior period results for Carlsbad were reclassified as discontinued operations. The transaction closed on February 27, 2019. Carlsbad continues to have a ground lease and easement agreement with NRG with an initial term ending in 2039 and two ten year extensions. As a result of the transaction, additional commitments related to the project totaled approximately $23 million as of December 31, 2018 and June 30, 2019.

22


Summarized results of NRG Yield, Inc. and the Renewables Platform and Carlsbad discontinued operations were as follows:    
 
Three months ended
 
Six months ended
(In millions)
June 30, 2019
 
June 30, 2018
 
June 30, 2019
 
June 30, 2018
Operating revenues
$

 
$
368

 
$
19

 
$
628

Operating costs and expenses

 
(223
)
 
(9
)
 
(453
)
Other expenses

 
(65
)
 
(5
)
 
(123
)
Gain from operations of discontinued components, before tax

 
80

 
5

 
52

Income tax expense/(benefit)

 
2

 

 
(5
)
Gain from discontinued operations, net of tax

 
78

 
5

 
57

Gain on disposal of discontinued operations, net of tax
(17
)
 

 
331

 

Other Commitments, Indemnification and Fees
27

 

 
27

 

Gain on disposal of discontinued operations, net of tax
10

 

 
358

 

Gain from discontinued operations, including disposal, net of tax
$
10

 
$
78

 
$
363

 
$
57


The following table summarizes the major classes of assets and liabilities classified as discontinued operations of Carlsbad:
(In millions)
 
December 31, 2018
Restricted cash
 
$
4

Accounts receivable - trade, net
 
10

Other current assets
 
5

Current assets - discontinued operations
 
19

Property, plant and equipment, net
 
590

Intangible assets, net
 
9

Other non-current assets
 
4

Non-current assets - discontinued operations
 
603

Current portion of long-term debt and capital leases
 
20

Accounts payable
 
27

Other current liabilities
 
1

Current liabilities - discontinued operations
 
48

Long-term debt and capital leases
 
572

Other non-current liabilities
 
2

Non-current liabilities - discontinued operations
 
$
574


Sale of Assets to NRG Yield, Inc. Prior to Discontinued Operations
On June 19, 2018, the Company completed the UPMC Thermal Project and received cash consideration from NRG Yield of $84 million, plus an additional $3 million received at final completion in January 2019.
On March 30, 2018, the Company sold to NRG Yield, Inc. 100% of NRG's interests in Buckthorn Renewables, LLC, which owns a 154 MW construction-stage utility-scale solar generation project located in Texas. NRG Yield, Inc. paid cash consideration of $42 million, excluding working capital adjustments, and assumed non-recourse debt of $183 million.
GenOn
On June 14, 2017, 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 controlled GenOn as it was subject to the control of the Bankruptcy Court; and, accordingly, NRG deconsolidated GenOn for financial reporting purposes as of June 14, 2017.

23


By eliminating a large portion of its operations in the PJM market with the deconsolidation of GenOn, NRG concluded that GenOn met the criteria for discontinued operations, as this represented a strategic shift in the business in which NRG operates. As such, all prior period results for GenOn were reclassified as discontinued operations. GenOn's plan of reorganization was confirmed on December 14, 2018.
Summarized results of GenOn discontinued operations were as follows:    
 
Three months ended
 
Six months ended
(In millions)
June 30, 2019
 
June 30, 2018
 
June 30, 2019
 
June 30, 2018
Interest income - affiliate
$

 
$
2

 
$

 
$
3

Pension and post-retirement liability assumption

 
1

 

 
1

Advisory and consulting fees

 
(1
)
 

 
(2
)
Other
2

 
(27
)
 
2

 
(27
)
Gain/(loss) from discontinued operations, net of tax
$
2

 
$
(25
)
 
$
2

 
$
(25
)

GenOn Settlement
Effective July 16, 2018, NRG and GenOn consummated the GenOn Settlement whereby the Company paid GenOn approximately $125 million, which included (i) the settlement consideration of $261 million, (ii) the transition services credit of $28 million and (iii) the return of $15 million of collateral posted to NRG; offset by the (i) $151 million in borrowings under the intercompany secured revolving credit facility, (ii) related accrued interest and fees of $12 million, (iii) remaining payments due under the transition services agreement of $10 million, (iv) $4 million reduction of the settlement payment related to NRG assigning to GenOn approximately $8 million of historical claims against REMA and (v) certain other balances due to NRG totaling $2 million.
GenMA Settlement
The Bankruptcy Court approved settlement terms agreed to among the GenOn Entities, NRG, the Consenting Holders, GenOn Mid-Atlantic, and certain of GenOn Mid-Atlantic's stakeholders, or the GenMA Settlement, and directed the settlement parties to cooperate in good faith to negotiate definitive documentation consistent with the GenMA Settlement term sheet in order to pursue consummation of the GenMA Settlement. The definitive documentation effectuating the GenMA Settlement was finalized as of April 27, 2018. Certain terms of the compromise with respect to NRG and GenOn Mid-Atlantic are as follows:
Settlement of all pending litigation and objections to the Plan (including with respect to releases and feasibility);
NRG provided $37.5 million in letters of credit as new qualifying credit support to GenOn Mid-Atlantic; and
NRG paid $6 million as reimbursement of professional fees incurred by certain of GenOn Mid- Atlantic's stakeholders in connection with the GenMA Settlement.
Dispositions
On June 29, 2018, the Company completed the sale of Canal 3 to Stonepeak Kestrel for cash proceeds of $16 million and recorded a gain of $17 million. Prior to the sale, Canal 3 entered into a financing arrangement and received cash proceeds of $167 million, of which $151 million was distributed to the Company. The related debt was non-recourse to NRG and was transferred to Stonepeak Kestrel in connection with the sale of Canal 3. The Company entered into a project management agreement in 2018 to manage construction of Canal 3, and substantial completion was reached in June 2019.
The Company completed other asset sales for cash proceeds of $18 million and $16 million during the six months ended June 30, 2019 and 2018, respectively.

Note 5Fair Value of Financial Instruments
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 amounts approximate fair values because of the short-term maturity of those instruments and are classified as Level 1 within the fair value hierarchy.

24


The estimated carrying amounts and fair values of NRG's recorded financial instruments not carried at fair market value are as follows:
 
As of June 30, 2019
 
As of December 31, 2018
 
Carrying Amount
 
Fair Value
 
Carrying Amount
 
Fair Value
 
(In millions)
Assets:
 
 
 
 
 
 
 
Notes receivable 
$
12

 
$
8

 
$
17

 
$
14

Liabilities:
 
 
 
 
 
 
 
Long-term debt, including current portion (a)
5,951

 
6,422

 
6,591

 
6,697


(a) 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 June 30, 2019 and December 31, 2018:
 
As of June 30, 2019
 
As of December 31, 2018
 
Level 2
 
Level 3
 
Level 2
 
Level 3
 
(In millions)
Long-term debt, including current portion
$
6,305

 
$
117

 
$
6,528

 
$
169



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 June 30, 2019
(In millions)
Total
 
Level 1
 
Level 2
 
Level 3
Investments in securities (classified within other current and non-current assets)
$
38

 
$

 
$
19

 
$
19

Nuclear trust fund investments:
 
 
 
 
 
 
 
Cash and cash equivalents
25

 
25

 

 

U.S. government and federal agency obligations
57

 
57

 

 

Federal agency mortgage-backed securities
92

 

 
92

 

Commercial mortgage-backed securities
29

 

 
29

 

Corporate debt securities
102

 

 
102

 

Equity securities
366

 
366

 

 

Foreign government fixed income securities
4

 

 
4

 

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

 
1

 

 

Derivative assets:
 
 
 
 
 
 
 
Commodity contracts
1,276

 
131

 
770

 
375

Measured using net asset value practical expedient:
 
 
 
 
 
 
 
Equity securities — nuclear trust fund investments
73

 


 


 


       Equity securities
9

 
 
 
 
 
 
Total assets
$
2,072

 
$
580

 
$
1,016

 
$
394

Derivative liabilities:
 
 
 
 
 
 
 
Commodity contracts
$
1,152

 
$
245

 
$
629

 
$
278

Total liabilities
$
1,152

 
$
245

 
$
629

 
$
278




25


 
As of December 31, 2018
(In millions)
Total
 
Level 1
 
Level 2
 
Level 3
Investments in securities (classified within other current and non-current assets)
$
39

 
$
2

 
$
18

 
$
19

Nuclear trust fund investments:
 
 
 
 
 
 
 
Cash and cash equivalents
19

 
19

 

 

U.S. government and federal agency obligations
46

 
46

 

 

Federal agency mortgage-backed securities
100

 

 
100

 

Commercial mortgage-backed securities
22

 

 
22

 

Corporate debt securities
96

 

 
96

 

Equity securities
312

 
312

 

 

Foreign government fixed income securities
4

 

 
4

 

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

 
1

 

 

Derivative assets:
 
 
 
 
 
 
 
Commodity contracts
1,042

 
137

 
796

 
109

Interest rate contracts
39

 

 
39

 

Measured using net asset value practical expedient:
 
 
 
 
 
 
 
Equity securities — nuclear trust fund investments
64

 
 
 
 
 
 
       Equity securities
8

 
 
 
 
 
 
Total assets
$
1,792

 
$
517

 
$
1,075

 
$
128

Derivative liabilities:
 
 
 
 
 
 
 
Commodity contracts
$
977

 
$
224

 
$
664

 
$
89

Total liabilities
$
977

 
$
224

 
$
664

 
$
89



There were no transfers during the three and six months ended June 30, 2019 and 2018 between Levels 1 and 2. The following tables reconcile, for the three and six months ended June 30, 2019 and 2018, 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 June 30, 2019
 
Six months ended June 30, 2019
(In millions)
Debt Securities
 
Derivatives(a)
 
Total
 
Debt Securities
 
Derivatives(a)
 
Total
Beginning balance
$
18

 
$
(2
)
 
$
16

 
$
19

 
$
20

 
$
39

Contracts added from acquisitions

 
(1
)
 
(1
)
 

 
(1
)
 
(1
)
Total gains/(losses) — realized/unrealized included in earnings
1

 
(17
)
 
(16
)
 
1

 
(27
)
 
(26
)
Cash received

 

 

 
(1
)
 

 
(1
)
Purchases

 
(10
)
 
(10
)
 

 
(12
)
 
(12
)
Transfers into Level 3(b)

 
113

 
113

 

 
130

 
130

Transfers out of Level 3(b)

 
14

 
14

 

 
(13
)
 
(13
)
Ending balance as of June 30, 2019
$
19

 
$
97

 
$
116

 
$
19

 
$
97

 
$
116

Gains/(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 June 30, 2019
$
1

 
$
(19
)
 
$
(18
)
 
$
1

 
$
(31
)
 
$
(30
)
(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

26


 
Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
 
Three months ended June 30, 2018
 
Six months ended June 30, 2018
(In millions)
Debt Securities
 
Derivatives(a)
 
Total
 
Debt Securities
 
Derivatives(a)
 
Total
Beginning balance
$
19

 
$
5

 
$
24

 
$
19

 
$
(15
)
 
$
4

Contracts added in XOOM acquisition

 
12

 
12

 

 
12

 
12

Total (losses) — realized/unrealized
included in earnings

 
(27
)
 
(27
)
 

 
(16
)
 
(16
)
Purchases

 
(4
)
 
(4
)
 

 
(3
)
 
(3
)
Transfers into Level 3(b)

 
193

 
193

 

 
197

 
197

Transfers out of Level 3(b)

 
(5
)
 
(5
)
 

 
(1
)
 
(1
)
Ending balance as of June 30, 2018
$
19

 
$
174

 
$
193

 
$
19

 
$
174

 
$
193

(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 June 30, 2018
$

 
$
(27
)
 
$
(27
)
 
$

 
$
(15
)
 
$
(15
)

(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. These contracts are valued based on various valuation techniques including, but not limited to, internal models based on a fundamental analysis of the market and extrapolation of the observable market data with similar characteristics. As of June 30, 2019, contracts valued with prices provided by models and other valuation techniques make up 29% of derivative assets and 24% of 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.

27


The following tables quantify the significant unobservable inputs used in developing the fair value of the Company's Level 3 positions as of June 30, 2019 and December 31, 2018:
 
June 30, 2019
 
Fair Value
 
 
 
Input/Range
 
Assets
 
Liabilities
 
Valuation Technique
 
Significant Unobservable Input
 
Low
 
High
 
Weighted Average
 
(In millions)
 
 
 
 
 
 
 
 
 
 
Power Contracts
$
347

 
$
261

 
Discounted Cash Flow
 
Forward Market Price (per MWh)
 
$
4

 
$
142

 
$
25

FTRs
28

 
17

 
Discounted Cash Flow
 
Auction Prices (per MWh)
 
(134
)
 
52

 
0
 
$
375

 
$
278

 
 
 
 
 
 
 
 
 
 
 
December 31, 2018
 
Fair Value
 
 
 
Input/Range
 
Assets
 
Liabilities
 
Valuation Technique
 
Significant Unobservable Input
 
Low
 
High
 
Weighted Average
 
(In millions)
 
 
 
 
 
 
 
 
 
 
Power Contracts
$
89

 
$
75

 
Discounted Cash Flow
 
Forward Market Price (per MWh)
 
$
1

 
$
214

 
$
31

FTRs
20

 
14

 
Discounted Cash Flow
 
Auction Prices (per MWh)
 
(90
)
 
34

 
0
 
$
109

 
$
89

 
 
 
 
 
 
 
 
 
 

The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable inputs as of June 30, 2019 and December 31, 2018:
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 June 30, 2019 the credit reserve resulted in a $2 million decrease in cost of operations. As of December 31, 2018, the credit reserve did not result in a significant change 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 2018 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.

28


Counterparty Credit Risk
The Company's counterparty credit risk policies are disclosed in its 2018 Form 10-K. As of June 30, 2019, counterparty credit exposure, excluding credit exposure from RTOs, ISOs, registered commodity exchanges and certain long-term agreements, was $273 million and NRG held collateral (cash and letters of credit) against those positions of $93 million, resulting in a net exposure of $226 million. NRG periodically receives collateral from counterparties in excess of their exposure. Collateral amounts shown include such excess while net exposure shown excludes excess collateral received. Approximately 60% of the Company's exposure before collateral is expected to roll off by the end of 2020. 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
84
%
Financial institutions
16

Total as of June 30, 2019
100
%
 
Net Exposure (a) (b)
Category by Counterparty Credit Quality
(% of Total)
Investment grade
53
%
Non-investment grade/non-rated
47

Total as of June 30, 2019
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
The Company currently has $33 million in exposure to one wholesale counterparty in excess of 10% of total net exposure discussed above as of June 30, 2019. 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 its 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 the overall market and are excluded from the above exposures.
Exchange Traded Transactions
The Company enters into commodity transactions on registered exchanges, notably ICE, NYMEX and Nodal. 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 contracts, primarily solar PPAs. As external sources or observable market quotes are not available to estimate such exposure, the Company values 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 June 30, 2019, aggregate credit risk exposure managed by NRG to these counterparties was approximately $524 million for the next five years, including exposure to PG&E as described below.

29


NRG, through its unconsolidated affiliates Ivanpah and Agua Caliente, has exposure to PG&E of approximately $337 million for the next five years. As a result of the bankruptcy filing by PG&E on January 29, 2019, it is uncertain whether and to what extent the bankruptcy may have an effect on these contracts. For further discussion see Note 11, Investments Accounted for Using the Equity Method and Variable Interest Entities, or VIEs.
Retail Customer Credit Risk
The Company is exposed to retail credit risk through the Company's retail electricity providers, which serve C&I customers and the Mass market. Retail credit risk results in losses when a customer fails to pay for services rendered. The losses may result from both nonpayment of customer accounts receivable and the loss of in-the-money forward value. The Company 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 June 30, 2019, the Company's retail customer credit exposure to C&I and Mass customers was diversified across many customers and various industries, as well as government entities.
Note 6Nuclear Decommissioning Trust Fund
NRG's Nuclear Decommissioning Trust Fund assets, which are for the decommissioning of its 44% interest in STP, 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 the 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 for the securities held in the trust funds, as well as information about the contractual maturities of those securities.
 
As of June 30, 2019
 
As of December 31, 2018
(In millions, except maturities)
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
$
25

 
$

 
$

 

 
$
19

 
$

 
$

 

U.S. government and federal agency obligations
57

 
4

 

 
12

 
46

 
1

 

 
12

Federal agency mortgage-backed securities
92

 
2

 

 
24

 
100

 
1

 
2

 
23

Commercial mortgage-backed securities
29

 
1

 
1

 
23

 
22

 

 
1

 
22

Corporate debt securities
102

 
5

 

 
11

 
96

 
1

 
2

 
11

Equity securities
439

 
291

 

 

 
376

 
231

 
1

 

Foreign government fixed income securities
4

 

 

 
8

 
4

 

 

 
9

Total
$
748

 
$
303

 
$
1

 
 
 
$
663

 
$
234

 
$
6

 
 

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.
 
Six months ended June 30,
 
2019
 
2018
 
(In millions)
Realized gains
$
5

 
$
7

Realized losses
(5
)
 
(6
)
Proceeds from sale of securities
191


303



30


Note 7Accounting for Derivative Instruments and Hedging Activities
Energy-Related Commodities
As of June 30, 2019, NRG had energy-related derivative instruments extending through 2034. The Company marks these derivatives to market through the statement of operations. NRG has executed power purchase agreements extending through 2033 that qualified for the NPNS exception and were therefore exempt from fair value accounting treatment.
Interest Rate Swaps
NRG was 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 entered into interest rate swap agreements. As of June 30, 2019, NRG had no interest rate derivative instruments as a result of the early termination of such contracts in connection with the repayment of the 2023 Term Loan Facility during the second quarter of 2019. See Note 10, Debt and Capital Leases, for further discussion.
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 June 30, 2019 and December 31, 2018. 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
 
 
June 30, 2019
 
December 31, 2018
Category
Units
(In millions)
Emissions
Short Ton
1

 
(2
)
Renewable Energy Certificates
Certificates
1

 
1

Coal
Short Ton
7

 
13

Natural Gas
MMBtu
(238
)
 
(330
)
Oil
Barrels

 
1

Power
MWh
21

 
1

Capacity
MW/Day
(1
)
 
(1
)
Interest
Dollars
$

 
$
1,000

The decrease in the natural gas position was primarily the result of additional retail hedge positions and settlement of generation hedges. The increase in the power position was primarily the result of additional retail hedge positions and the settlement of generation hedges. The decrease in the interest position was the result of the early settlement of the interest rate swaps.
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
 
June 30, 2019
 
December 31, 2018
 
June 30, 2019
 
December 31, 2018
 
(In millions)
Derivatives Not Designated as Cash Flow or Fair Value Hedges:

 
 
 
 

 
Interest rate contracts current
$

 
$
17

 
$


$

Interest rate contracts long-term

 
22

 



Commodity contracts current
850

 
747

 
778


673

Commodity contracts long-term
426

 
295

 
374


304

Total Derivatives Not Designated as Cash Flow or Fair Value Hedges
$
1,276

 
$
1,081

 
$
1,152


$
977



31


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 June 30, 2019 Balance Sheet
 
 
Gross Amounts of Recognized Assets / Liabilities
 
Derivative Instruments
 
Cash Collateral (Held) / Posted
 
Net Amount
 
 
(In millions)
Commodity contracts:
 
 
 
 
 
 
 
 
Derivative assets
 
$
1,276

 
$
(1,029
)
 
$
(10
)
 
$
237

Derivative liabilities
 
(1,152
)
 
1,029

 
58

 
(65
)
Total commodity contracts
 
$
124

 
$

 
$
48

 
$
172

 
 
Gross Amounts Not Offset in the December 31, 2018 Balance Sheet
 
 
Gross Amounts of Recognized Assets / Liabilities
 
Derivative Instruments
 
Cash Collateral (Held) / Posted
 
Net Amount
 
 
(In millions)
Commodity contracts:
 
 
 
 
 
 
 

Derivative assets
 
$
1,042

 
$
(778
)
 
$
(31
)
 
$
233

Derivative liabilities
 
(977
)
 
778

 
114

 
(85
)
Total commodity contracts
 
65

 

 
83

 
148

Interest rate contracts:
 
 
 
 
 
 
 

Derivative assets
 
39

 

 

 
39

Total interest rate contracts
 
39

 

 

 
39

Total derivative instruments
 
$
104

 
$

 
$
83


$
187


Accumulated Other Comprehensive Loss
The following table summarizes the effects on the Company's accumulated OCL balance attributable to cash flow hedge derivatives, net of tax:
 
Interest Rate Contracts
 
Three months ended June 30, 2018
 
Six months ended June 30, 2018
 
(In millions)
Accumulated OCL beginning balance
$
(31
)
 
$
(54
)
Reclassified from accumulated OCL to income:
 
 
 
Due to realization of previously deferred amounts
3

 
7

Mark-to-market of cash flow hedge accounting contracts
5

 
24

Accumulated OCL ending balance, net of $5 tax
$
(23
)

$
(23
)

Amounts reclassified from accumulated OCL into income are recorded in discontinued operations.
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 are reflected in current period results of operations.

32


The following table summarizes the pre-tax effects of economic hedges that have not been designated as cash flow hedges and trading activity on the Company's statement of operations. The effect of commodity hedges is included within operating revenues and cost of operations and the effect of interest rate hedges is included in interest expense.
 
Three months ended June 30,
 
Six months ended June 30,
 
2019
 
2018
 
2019
 
2018
Unrealized mark-to-market results
(In millions)
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges
$
11

 
$
(2
)
 
$
30

 
$
(1
)
Reversal of acquired loss/(gain) positions related to economic hedges
1

 
(1
)
 
(1
)
 
(1
)
Net unrealized gains/(losses) on open positions related to economic hedges
9

 
(73
)
 
12

 
132

Total unrealized mark-to-market gains/(losses) for economic hedging activities
21

 
(76
)
 
41

 
130

Reversal of previously recognized unrealized gains on settled positions related to trading activity
(1
)
 
(3
)
 
(7
)
 
(6
)
Net unrealized gains on open positions related to trading activity
13

 
8

 
26

 
19

Total unrealized mark-to-market gains for trading activity
12

 
5

 
19

 
13

Total unrealized gains/(losses)
$
33

 
$
(71
)
 
$
60

 
$
143

 
Three months ended June 30,
 
Six months ended June 30,
 
2019
 
2018
 
2019
 
2018
 
(In millions)
Unrealized gains/(losses) included in operating revenues
$
253

 
$
15

 
$
280

 
$
(73
)
Unrealized (losses)/gains included in cost of operations
(220
)
 
(86
)
 
(220
)
 
216

Total impact to statement of operations — energy commodities
$
33

 
$
(71
)
 
$
60

 
$
143

Total impact to statement of operations — interest rate contracts
$
(29
)
 
$
3

 
$
(38
)
 
$
15

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 six months ended June 30, 2019, the $12 million unrealized gain from open economic hedge positions was primarily the result of an increase in value of forward power positions due to decreases in power prices.
For the six months ended June 30, 2018, the $132 million unrealized gain from open economic hedge positions was primarily the result of an increase in value of forward purchases of ERCOT heat rate and ERCOT electricity contracts due to ERCOT heat rate expansion and increases in ERCOT power prices.
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 require 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 June 30, 2019 was $19 million. The collateral required for contracts with credit rating contingent features that are in a net liability position as of June 30, 2019 was $13 million. The Company is also a party to certain marginable agreements under which it has a net liability position, but the counterparty has not called for the collateral due, which was $3 million as of June 30, 2019.
See Note 5, Fair Value of Financial Instruments, for discussion regarding concentration of credit risk.


33


Note 8Leases
The Company leases generating facilities, land, office and equipment, railcars, and storefront space at retail stores. Operating leases with an initial term greater than twelve months are recognized as right-of-use assets and lease liabilities in the consolidated balance sheets. The Company recognizes lease expense for all operating leases on a straight-line basis over the lease term. In the future, should another systematic basis become more representative of the pattern in which the lessee expects to consume the remaining economic benefit of the right-of-use asset, the Company will use that basis for lease expense.
The Company considers a contract to be or to contain a lease when both of the following conditions apply: 1) an asset is either explicitly or implicitly identified in the contract and 2) the contract conveys to the Company the right to control the use of the identified asset for a period of time. The Company has the right to control the use of the identified asset when the Company has both the right to obtain substantially all the economic benefits from the use of the identified asset and the right to direct how and for what purpose the identified asset is used throughout the period of use.
Lease payments are typically fixed and payable on a monthly, quarterly, semi-annual or annual basis. Lease payments under certain agreements may escalate over the lease term either by a fixed percentage or a fixed dollar amount. Certain leases may provide for variable lease payments in the form of payments based on usage, a percentage of sales from the location under lease, or index-based (e.g., the U.S. Consumer Price Index) adjustments to lease payments. The Company has no leases which contain residual value guarantees provided by the Company as a lessee.
The Company’s leases may grant the Company an option to renew a lease for an additional term(s) or to terminate the lease after a certain period. As part of its transition from the guidance contained in Topic 840 to the updated guidance in Topic 842, the Company elected not to use the practical expedient of using hindsight to determine the lease term and in assessing impairment of the right-of-use assets.
As permitted by Topic 842, the Company made an accounting policy election for all asset classes not to recognize right-of-use assets and lease liabilities in the consolidated balance sheets for its short-term leases, which are leases that have a lease term of twelve months or less. For the initial measurement of lease liabilities, the Company uses as the discount rate either the rate implicit in the lease, if known, or its incremental borrowing rate, which is the rate of interest that the Company would have to pay to borrow, on a collateralized basis, over a similar term an amount equal to the payments for the lease.
In transition to Topic 842, the Company elected to apply the effective date transition method as of the January 1, 2019 adoption date. In accordance with this method, the Company’s reporting for comparative periods prior to January 1, 2019 presented in the financial statements continues to be in conformity with the guidance in Topic 840. The Company elected the following practical expedients, which allow entities to:
1.not reassess whether any contracts that existed prior to the January 1, 2019 implementation date are or contain leases;
2.
not reassess the lease classification for any leases that commenced prior to the January 1, 2019 implementation date, meaning that all commenced capital leases under Topic 840 will be classified as finance leases under Topic 842 and all commenced operating leases under Topic 840 will be classified as operating leases under Topic 842;
3.
not reassess initial direct costs for any leases;
4.
not reassess whether existing land easements, which were not previously accounted as leases under Topic 840, are or contain leases; and
5.
not separate lease and non-lease components for all asset classes, except office space leases and generation facilities leases.

As described in Note 4, Acquisitions, Discontinued Operations and Dispositions, upon the close of the South Central Portfolio sale, the Company entered into an agreement to leaseback the Cottonwood facility through May 2025. The lease was accounted for in accordance with ASC 842-40, Sale and Leaseback Transactions, as an operating lease and accordingly, a right-of-use asset and lease liability were established on the lease commencement date and will be amortized through the end of the lease.
Lease Cost:
(In millions)
Three months ended June 30, 2019
 
Six months ended June 30, 2019
Operating lease cost
33

 
56

Short-term lease cost
1

 
1

Variable lease cost
2

 
3

Sublease income
(5
)
 
(9
)
Total lease cost
$
31

 
$
51


34


Other information:
(In millions)
Six months ended June 30, 2019
Cash paid for amounts included in the measurement of lease liabilities:
$
53

   Operating cash flows from operating leases
53

Right-of-use assets obtained in exchange for new operating lease liabilities
214

Lease Term and Discount Rate:
Weighted-average remaining lease term
In Years
Finance leases
2.5
Operating leases
8.1
 
 
Weighted-average discount rate
%
Finance leases
6.50
Operating leases
5.73


As of June 30, 2019, annual payments based on the maturities of NRG's leases are expected to be as follows:
 
(In millions)
Remainder of 2019
$
50

2020
95

2021
85

2022
85

2023
86

Thereafter
371

Total undiscounted lease payments
$
772

Less: present value adjustment
(185
)
Total discounted lease payments
$
587


Note 9Impairments
2018 Impairment Losses
Keystone and Conemaugh — On June 29, 2018, the Company entered into an agreement to sell its approximately 3.7% interests in the Keystone and Conemaugh generating stations. NRG recorded impairment losses of $14 million for Keystone and $14 million for Conemaugh to adjust the carrying amount of the assets to fair value based on the contractual sale price. The transaction closed on September 5, 2018.
Dunkirk — During the second quarter of 2018, NRG ceased its development of the project to add gas capability at the Dunkirk generating station. The project was put on hold in 2015 pending the resolution of a lawsuit filed by Entergy Corporation against the NYSPSC, which challenged the legality of its contract with Dunkirk. The lawsuit was later dropped and development continued, but the delay imposed a new requirement on Dunkirk to enter into the NYISO interconnection study process. The NYISO studies concluded that extensive electric system upgrades would be necessary for the station to return to service. This would cause the Company to incur a material increase in cost and delay the project schedule, which would render the project impractical. Consequently, the Company recorded an impairment loss of $46 million during the second quarter of 2018, reducing the carrying amount of the related assets to $0.




35


Note 10Debt and Capital Leases
Long-term debt and capital leases consisted of the following:
(In millions, except rates)
June 30, 2019
 
December 31, 2018
 
Interest rate %
 
 
 
Recourse debt:
 
 
 
 
 
Senior Notes, due 2024
$

 
$
733

 
6.250
Senior Notes, due 2026
1,000

 
1,000

 
7.250
Senior Notes, due 2027
1,230

 
1,230

 
6.625
Senior Notes, due 2028
821

 
821

 
5.750
Senior Notes, due 2029
733

 

 
5.250
Convertible Senior Notes, due 2048
575

 
575

 
2.750
Senior Secured First Lien Notes, due 2024
600

 

 
3.750
Senior Secured First Lien Notes, due 2029
500

 

 
4.450
Term Loan Facility (a) 

 
1,698

 
L+1.75
Tax-exempt bonds
466

 
466

 
4.125 - 6.00
Subtotal recourse debt
5,925

 
6,523

 

Non-recourse debt:
 
 
 
 
 
Agua Caliente Borrower 1, due 2038
83

 
86

 
5.430
Midwest Generation

 
48

 
4.390
Other
34

 
34

 
various
Subtotal all non-recourse debt
117

 
168

 
 
Subtotal long-term debt (including current maturities)
6,042


6,691

 
 
Capital leases
1

 
1

 
various
Subtotal long-term debt and capital leases (including current maturities)
6,043


6,692

 
 
Less current maturities
(87
)

(72
)
 
 
Less debt issuance costs
(71
)
 
(70
)
 
 
Discounts
(91
)
 
(101
)
 
 
Total long-term debt and capital leases
$
5,794


$
6,449

 
 
(a) As of December 31, 2018, the interest rate was 1-month LIBOR plus 1.75%

Recourse Debt
Senior Notes
Issuance of 2029 Senior Notes
On May 14, 2019, NRG issued $733 million of aggregate principal amount at par of 5.25% senior unsecured notes due 2029, or the 2029 Senior Notes. The 2029 Senior Notes are senior unsecured obligations of NRG and are guaranteed by certain of its subsidiaries. Interest will be paid semi-annually beginning on December 15, 2019, until the maturity date of June 15, 2029. The proceeds from the issuance of the 2029 Senior Notes were utilized to redeem the Company's remaining 6.25% Senior Notes due 2024.
Issuance of 2024 and 2029 Senior Secured First Lien Notes
On May 28, 2019, NRG issued $1.1 billion of aggregate principal amount of senior secured first lien notes, consisting of $600 million 3.75% senior secured first lien notes due 2024 and $500 million 4.45% senior secured first lien notes due 2029, or the Senior Secured First Lien Notes, at a discount. The Senior Secured First Lien Notes are guaranteed on a first-priority basis by each of NRG’s current and future subsidiaries that guarantee indebtedness under its credit agreement. The Senior Secured First Lien Notes will be secured by a first priority security interest in the same collateral that is pledged for the benefit of the lenders under NRG’s credit agreement, which consists of a substantial portion of the property and assets owned by NRG and the guarantors. The collateral securing the Senior Secured First Lien Notes will be released if the Company obtains an investment grade rating from two out of the three rating agencies, subject to an obligation to reinstate the collateral if such rating agencies withdraw the Company's investment grade rating or downgrade its rating below investment grade. Interest will be paid semi-annually beginning on December 15, 2019, until the maturity dates of June 15, 2024 and June 15, 2029. The proceeds from the issuance of the Senior Secured First Lien Notes, together with cash on hand, were used to repay the Company's 2023 Term Loan Facility.
2024 Senior Notes Redemption
During the three months ended June 30, 2019, the Company redeemed $733 million of its 6.25% Senior Notes due 2024 and recorded a loss on debt extinguishment of $29 million, which included the write-off of previously deferred debt issuance costs of $5 million.

36



Senior Credit Facility
2023 Term Loan Facility Repayment
On May 28, 2019, the Company repaid its $1.7 billion 2023 Term Loan Facility using the proceeds from the issuance of the Senior Secured First Lien Notes, as well as cash on hand, resulting in a decrease of $594 million to long-term debt outstanding. The Company recorded a loss on debt extinguishment of $17 million, which included the write-off of previously deferred debt issuance costs of $13 million. As a result of the repayment of the outstanding 2023 Term Loan Facility, the Company terminated the related interest rate swap agreements, which were in-the-money, and received $25 million that was recorded as a reduction to interest expense.
Revolving Credit Facility Modification
On May 28, 2019, the Company amended its existing credit agreement to, among other things, (i) provide for a $184 million increase in revolving commitments, resulting in aggregate revolving commitments under the amended credit agreement equal to $2.6 billion, (ii) extend the maturity date of the revolving loans and commitments under the amended credit agreement to May 28, 2024, (iii) provide for a release of the collateral securing the amended credit agreement if NRG obtains an investment grade rating from two out of the three rating agencies, subject to an obligation to reinstate the collateral if such rating agencies withdraw NRG’s investment grade rating or downgrade NRG’s rating below investment grade, (iv) reduce the applicable margins for borrowings under (a) ABR Revolving Loans from 1.25% to 0.75% and (b) Eurodollar Revolving Loans from 2.25% to 1.75%, (v) add a sustainability-linked pricing metric that permits an interest rate adjustment tied to NRG meeting targets related to environmental sustainability and (vi) make certain other changes to the existing covenants.

Non-Recourse Debt
Agua Caliente Borrower 1
On January 22, 2019, the lenders of the Agua Caliente Borrower 1 debt notified Agua Caliente Borrower 1, a subsidiary of the Company, of certain defaults under the financing agreement as it relates to the bankruptcy filing made by PG&E on January 29, 2019. PG&E is the offtaker of the underlying contracts, which are material to the project. The financing was entered into along with Agua Caliente Borrower 2, LLC, a subsidiary of Clearway Energy Inc., which is joint and several to the parties. The Company is working with the lenders to determine a path forward.
Cottonwood - Letters of Credit
On January 4, 2019, the Company entered into an $80 million credit agreement to issue letters of credit, which is currently supporting the Cottonwood facility lease. Annual fees of 1.33% on the facility are paid quarterly in advance. As of June 30, 2019, the full $80 million was issued.
Note 11Investments Accounted for Using the Equity Method and Variable Interest Entities, or VIEs
Entities that are not Consolidated
NRG accounts for the Company's significant investments using the equity method of accounting. NRG's carrying value of equity investments can be impacted by a number of elements including impairments, unrealized gains and losses on derivatives and movements in foreign currency exchange rates.
PG&E Bankruptcy - The Agua Caliente project and two of the three Ivanpah units are party to PPAs with PG&E. Both projects have project financing with the U.S. DOE. On January 29, 2019, PG&E Corp. and subsidiary utility PG&E filed for Chapter 11 bankruptcy protection. As part of their filing, PG&E asked the Bankruptcy Court to confirm exclusive jurisdiction over their "rights to reject" PPAs or other contracts regulated by FERC. As a result of the bankruptcy filing, the Agua Caliente and Ivanpah projects have issued notices of events of default under their respective loan agreements.
Under the current schedule set by the bankruptcy court, PG&E has the exclusive opportunity to propose a restructuring plan until September 26, 2019, although the ad hoc committee of senior unsecured noteholders filed a motion on June 25, 2019 to terminate PG&E's exclusivity period and to allow it to propose a plan that would include the assumption of all renewable contracts entered into by PG&E. The bankruptcy court has not yet ruled on that motion.
The Company's subsidiaries are working with their partners on the projects and the loan counterparties. The Company believes that the Agua Caliente and Ivanpah PPAs with PG&E will not be rejected in the bankruptcy proceedings. NRG's maximum

37


exposure to loss is limited to its equity investment, which was $206 million for Agua Caliente and $16 million for Ivanpah as of June 30, 2019. See Note 10, Debt and Capital Leases for further discussion on Agua Caliente.
Variable Interest Entities
NRG accounts for its interests in certain entities that are considered VIEs under ASC 810, Consolidation, for which NRG is not the primary beneficiary, under the equity method.
Through its consolidated subsidiary, NRG Solar Ivanpah LLC, NRG owns a 54.5% interest in Ivanpah Master Holdings LLC, or Ivanpah, the owner of three solar electric generating projects located in the Mojave Desert with a total capacity of 393 MW. NRG considers this investment a VIE under ASC 810 and NRG is not considered the primary beneficiary. The Company accounts for its interest under the equity method of accounting.
The Ivanpah solar electric generating projects were funded in large part by loans guaranteed by the U.S. DOE and equity from the projects' partners. During the first quarter of 2018, all interested parties sought a restructuring of Ivanpah's debt in order to avoid a potential event of default with respect to the loans and entered into a settlement during the second quarter of 2018. The settlement resulted in certain transactions, including the release of reserves totaling $95 million to fund equity distributions to the partners, which reduced the equity at risk, and the prepayment of certain of the debt balance outstanding, and the amendment of certain of Ivanpah's governing documents. The equity distributions and prepayment of debt were funded by the agreed upon release of reserve funds. These events were considered to be a reconsideration event in accordance with ASC 810. As a result, NRG determined that it is not the primary beneficiary and deconsolidated Ivanpah. NRG recognized a loss of $22 million on the deconsolidation and subsequent recognition of Ivanpah as an equity method investment during the six months ended June 30, 2018. The deconsolidation of Ivanpah reduced the Company's assets by approximately $1.3 billion, which was primarily property, plant and equipment, and reduced the Company's liabilities by $1.2 billion, which was primarily long-term debt.
Entities that are Consolidated
The Company has a controlling financial interest in certain entities that 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 eligible for certain tax credits as further described in Note 2, Summary of Significant Accounting Policies to the Company's 2018 Form 10-K.
The summarized financial information for the Company's consolidated VIEs consisted of the following:
(In millions)
June 30, 2019
 
December 31, 2018
Current assets
$
3

 
$
3

Net property, plant and equipment
74

 
76

Other long-term assets
29

 
28

Total assets
106

 
107

Current liabilities
1

 
2

Long-term debt
28

 
29

Other long-term liabilities
8

 
7

Total liabilities
37

 
38

Redeemable noncontrolling interest
19

 
19

Net assets less noncontrolling interests
$
50

 
$
50



38


Note 12Changes in Capital Structure
As of June 30, 2019 and December 31, 2018, 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, 2018
420,288,886

 
(136,638,847
)
 
283,650,039

Shares issued under LTIPs
1,541,588

 

 
1,541,588

Shares repurchased

 
(26,621,029
)
 
(26,621,029
)
Balance as of June 30, 2019
421,830,474

 
(163,259,876
)
 
258,570,598

Shares issued under LTIPs subsequent to June 30, 2019
3,827

 

 
3,827

Shares repurchased subsequent to June 30, 2019

 
(5,586,536
)
 
(5,586,536
)
Balance as of August 7, 2019
421,834,301

 
(168,846,412
)
 
252,987,889


Share Repurchases
During January and February, the Company completed $250 million of share repurchases in connection with 2018 share repurchase program, at an average price of $40.61 per share. Through August 7, 2019, the Company completed additional share repurchases of $1.0 billion at an average price of $38.38 per share under the 2019 $1.0 billion program that was authorized in February 2019 by the Company's board of directors. In August 2019, the Company announced that the board of directors authorized an additional $250 million of share repurchases to be executed in the second half of 2019.
On February 28, 2019, the Company executed an accelerated share repurchase agreement, or ASR Agreement, with a financial institution to repurchase a total of $400 million of outstanding common stock based on a volume weighted average price. The Company received initial shares of 9,086,903, which were recorded in treasury stock at fair value based on the closing price on March 12, 2019, of $390 million, with the remaining $10 million recorded in additional paid in capital, representing the value of the forward contract to purchase additional shares. In April 2019, the financial institution delivered the remaining shares pursuant to the ASR agreement and the Company received 351,768 additional shares. The average price paid for all the shares delivered under the ASR Agreement was $42.38 per share. Upon receipt of the additional shares in April 2019, the Company transferred the $10 million from additional paid in capital to treasury stock.
The following repurchases have been made during the six months ended June 30, 2019 and through August 7, 2019 under the 2018 and 2019 share repurchase programs:
 
Total number of shares purchased
 
Amounts paid for shares purchased  (in millions)
Board Authorized Share Repurchases
 
 
 
2018 program:
 
 
 
 Repurchases made during January-February to complete the 2018 program
6,153,415

 
$
250

2019 program:
 
 
 
Shares repurchased under February 28, 2019 Accelerated Share Repurchase Agreement 
9,438,671

 
400

Other repurchases
11,028,943

 
404

Total Share Repurchases during the six months ended June 30, 2019
26,621,029

 
$
1,054

Repurchases made subsequent to June 30, 2019 to complete the 2019 program
5,586,536

 
$
196

Total Share Repurchases during the period ended August 7, 2019
32,207,565

 
$
1,250


Employee Stock Purchase Plan
In March 2019, the Company reopened participation in the ESPP, which allows eligible employees to elect to withhold between 1% and 10% of their eligible compensation to purchase shares of NRG common stock at the lesser of 95% of its market value on the offering date or 95% of the fair market value on the exercise date. An offering date will occur each April 1 and October 1. An exercise date will occur each September 30 and March 31.


39


NRG Common Stock Dividends
A quarterly dividend of $0.03 per share was paid on the Company's common stock during the three months ended June 30, 2019. On July 19, 2019, NRG declared a quarterly dividend on the Company's common stock of $0.03 per share, payable August 15, 2019, to stockholders of record as of August 1, 2019, 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.

Note 13Earnings Per Share
Basic earnings per common share is computed by dividing net income 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 per share is computed in a manner consistent with that of basic income per share while giving effect to all potentially dilutive common shares that were outstanding during the period. The outstanding non-qualified stock options, non-vested restricted stock units, market stock units, and relative performance stock units are not considered outstanding for purposes of computing basic income per share. However, these instruments are included in the denominator for purposes of computing diluted income per share under the treasury stock method. The 2048 Convertible Senior Notes are convertible, under certain circumstances, into the Company’s common stock, cash or combination thereof (at NRG's option). There is no dilutive effect for the 2048 Convertible Senior Notes due to the Company’s expectation to settle the liability in cash.

The reconciliation of NRG's basic and diluted income per share is shown in the following table:
 
Three months ended June 30,
 
Six months ended June 30,
In millions, except per share data
2019
 
2018
 
2019
 
2018
Basic income per share attributable to NRG Energy, Inc;
 
 
 
 
Net income attributable to NRG Energy, Inc. common stockholders
$
201

 
$
72

 
$
683

 
$
351

Weighted average number of common shares outstanding - basic
265

 
310


272

 
314

Income per weighted average common share — basic
$
0.76

 
$
0.23

 
$
2.51

 
$
1.12

 
 
 
 
 
 
 
 
Diluted income per share attributable to NRG Energy, Inc;
 
 
 
 
Net income attributable to NRG Energy, Inc. available to common shareholders
$
201

 
$
72

 
$
683

 
351

Weighted average number of common shares outstanding - basic
265

 
310

 
272

 
314

Incremental shares attributable to the issuance of equity compensation (treasury stock method)
2

 
4

 
2

 
4

Weighted average number of common shares outstanding - dilutive
267

 
314

 
274

 
318

Income per weighted average common share — diluted
$
0.75

 
$
0.23

 
$
2.49

 
$
1.10


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 income per share:
 
Three months ended June 30,
 
Six months ended June 30,
In millions of shares
2019
 
2018
 
2019
 
2018
Equity compensation plans

 

 

 
1


Note 14Segment Reporting

40


The Company's segment structure reflects how management currently makes financial decisions and allocates resources. The Company's businesses are segregated into the Retail, Generation and corporate segments. Generation includes all power plant activities, domestic and international, as well as renewables. Retail includes Mass customers and Business Solutions, which includes C&I customers and other distributed and reliability products. Intersegment sales are accounted for at market.The financial information for the six months ended June 30, 2018 has been recast to reflect the current segment structure.
On February 4, 2019, as described in Note 4, Acquisitions, Discontinued Operations and Dispositions, the Company completed the sale of and deconsolidated the South Central Portfolio. On August 31, 2018, as described in Note 4, Acquisitions, Discontinued Operations and Dispositions, NRG deconsolidated NRG Yield, Inc., its Renewables Platform and Carlsbad for financial reporting purposes. The financial information for the six months ended June 30, 2018, has been recast to reflect the presentation of these entities as 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) and net income/(loss) attributable to NRG Energy, Inc.
 
Three months ended June 30, 2019(a)
 
Retail
 
Generation
 
Corporate
 
Eliminations
 
Total
 
(In millions)
Operating revenues(b)
$
1,748

 
$
1,367

 
$

 
$
(650
)
 
$
2,465

Depreciation and amortization
32

 
45

 
8

 

 
85

Impairment losses
1

 

 

 

 
1

Reorganization costs
2

 

 

 

 
2

Gain on sale of assets

 

 
1

 

 
1

Loss on debt extinguishment, net

 

 
(47
)
 

 
(47
)
(Loss)/income from continuing operations before income taxes
(280
)
 
618

 
(151
)
 
1

 
188

(Loss)/income from continuing operations
(280
)
 
618

 
(150
)
 
1

 
189

Income from discontinued operations, net of tax

 

 
13

 

 
13

Net (loss)/income
(280
)
 
618

 
(137
)
 
1

 
202

Net (loss)/income attributable to NRG Energy, Inc.
$
(281
)
 
$
618

 
$
(137
)
 
$
1

 
$
201

 
(a) Includes intersegment revenues and costs associated with the internal transfer of power, which is based on average annualized market prices and results in higher revenues in Generation and higher cost of operations in Retail that are eliminated in consolidation
(b) Operating revenues include intersegment sales and net derivative gains and losses of:
$
2

 
$
627

 
$
21

 
$

 
$
650

 
Three months ended June 30, 2018(a)
 
Retail
 
Generation
 
Corporate
 
Eliminations
 
Total
 
(In millions)
Operating revenues(b)
$
1,814

 
$
1,167

 
$

 
$
(520
)
 
$
2,461

Depreciation and amortization
30

 
74

 
9

 
(1
)
 
112

Reorganization costs
1

 
3

 
19

 

 
23

Equity in earnings of unconsolidated affiliates

 
5

 
2

 
(2
)
 
5

(Loss)/income from continuing operations before income taxes
(84
)
 
252

 
(137
)
 
1

 
32

(Loss)/income from continuing operations
(84
)
 
252

 
(142
)
 
1

 
27

Income from discontinued operations, net of tax

 

 
69

 

 
69

Net (loss)/income
(84
)
 
252

 
(73
)
 
1

 
96

Net (loss)/income attributable to NRG Energy, Inc.
$
(84
)
 
$
250

 
$
(97
)
 
$
3

 
$
72

 
(a) Includes intersegment revenues and costs associated with our internal transfer of power, which is based on average annualized market prices and results in higher revenues in Generation and higher cost of operations in Retail that are eliminated in consolidation
(b) Operating revenues include intersegment sales and net derivative gains and losses of:
$
4

 
$
514

 
$
2

 
$

 
$
520





41


 
Six months ended June 30, 2019 (a)
 
Retail
 
Generation
 
Corporate
 
Eliminations
 
Total
 
(In millions)
Operating revenues(b)
$
3,355

 
$
2,190

 
$

 
$
(915
)
 
$
4,630

Depreciation and amortization
63

 
91

 
16

 

 
170

Impairment losses
1

 

 

 

 
1

Reorganization costs
3

 
1

 
11



 
15

Gain on sale of assets

 
1

 
1

 

 
2

Equity in losses of unconsolidated affiliates

 
(21
)
 

 

 
(21
)
Loss on debt extinguishment, net

 

 
(47
)
 

 
(47
)
(Loss)/income from continuing operations before income taxes
(169
)
 
731

 
(275
)
 
(1
)
 
286

(Loss)/income from continuing operations
(170
)
 
731

 
(277
)
 
(1
)
 
283

Income from discontinued operations, net of tax

 

 
401

 

 
401

Net (loss)/income
(170
)
 
731

 
124

 
(1
)
 
684

Net (loss)/income attributable to NRG Energy, Inc. common stockholders
$
(171
)
 
$
731

 
$
124

 
$
(1
)
 
$
683

(a) Includes intersegment revenues and costs associated with our internal transfer of power, which is based on average annualized market prices and results in higher revenues in Generation and higher cost of operations in Retail that are eliminated in consolidation
(b) Operating revenues include inter-segment sales and net derivative gains and losses of:
$
5

 
$
862

 
$
48

 
$

 
$
915

 
Six months ended June 30, 2018 (a)
 
Retail
 
Generation
 
Corporate
 
Eliminations
 
Total
 
 
 
 
 
 
 
 
 
 
Operating revenues(b)
$
3,294

 
$
1,438

 
$

 
$
(206
)
 
$
4,526

Depreciation and amortization
56

 
160

 
18

 
(2
)
 
232

Impairment losses

 
74

 

 

 
74

Reorganization costs
5

 
6

 
32

 

 
43

Gain on sale of assets

 
2

 
14

 

 
16

Equity in earnings of unconsolidated affiliates

 
7

 
1

 
(2
)
 
6

Income/(loss) from continuing operations before income taxes
860

 
(319
)
 
(264
)
 
(1
)
 
276

Income/(loss) from continuing operations
860

 
(319
)
 
(275
)
 
(1
)
 
265

Income from discontinued operations, net of tax

 

 
64

 

 
64

Net income/(loss)
860

 
(319
)
 
(211
)
 
(1
)
 
329

Net income/(loss) attributable to NRG Energy, Inc. common stockholders
$
859

 
$
(313
)
 
$
(196
)
 
$
1

 
$
351

(a) Includes intersegment revenues and costs associated with our internal transfer of power, which is based on average annualized market prices and results in higher revenues in Generation and higher cost of operations in Retail that are eliminated in consolidation
(b) Operating revenues include inter-segment sales and net derivative gains and losses of:
$
6

 
$
205

 
$
(5
)
 
$

 
$
206

Note 15Income Taxes
Effective Income Tax Rate
The income tax provision consisted of the following:
 
Three months ended June 30,
 
Six months ended June 30,
In millions, except rates
2019
 
2018
 
2019
 
2018
Income from continuing operations before income taxes
$
188

 
$
32

 
$
286

 
$
276

Income tax (benefit)/expense from continuing operations
(1
)
 
5

 
3

 
11

Effective income tax rate
(0.5
)%
 
15.6
%

1.0
%

4.0
%

42


For the three and six months ended June 30, 2019 and 2018, NRG's overall effective tax rate was lower than the statutory rate of 21%, primarily due to the tax benefit for the change in valuation allowance, partially offset by current state tax expense.
Uncertain Tax Benefits
As of June 30, 2019, NRG has recorded a non-current tax liability of $28 million for uncertain tax benefits from positions taken on various state income tax returns, including accrued interest. For the six months ended June 30, 2019, NRG accrued an immaterial amount of interest relating to the uncertain tax benefits. As of June 30, 2019, 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 no longer 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.
Note 16Related Party Transactions
The following table summarizes NRG's material related party transactions with third party affiliates:
 
Three months ended June 30,
 
Six months ended June 30,
 
2019
 
2018
 
2019
 
2018
 
(In millions)
 
 
Revenues from Related Parties Included in Operating Revenues
 
 
 
 
 
 
 
Gladstone
$
1

 
$
1

 
$
1

 
$
1

GenConn

 
1

 

 
3

Ivanpah
7

 
5

 
18

 
5

Midway-Sunset
1

 

 
2

 

Revenues from Related Parties recorded against selling, general and administrative expenses
 
 
 
 
 
 
 
GenOn

 
21

 

 
42

Total
$
9

 
$
28

 
$
21

 
$
51


Gladstone — NRG provides services to Gladstone, an equity method investment, under an operations and maintenance agreement. Fees for services under this contract primarily include recovery of NRG's costs of operating the plant, as approved in the annual budget, as well as a base monthly fee.
GenConn — NRG provides services to GenConn under operations and maintenance agreements with GenConn Devon and GenConn Middletown that began in June 2010 and June 2011, respectively. NRG no longer has an ownership interest in GenConn as a result of the sale of its ownership interests in NRG Yield, Inc. and its Renewables Platform.
Ivanpah — NRG provides services to Ivanpah, an equity method investment, under an operations and maintenance agreement and a project management agreement with each project company. Fees for the services under these contracts primarily include recovery of NRG's costs of operating the plant and providing administrative services, plus a profit margin. Ivanpah became a related party to NRG upon deconsolidation in the second quarter of 2018.
Midway-Sunset — NRG provides services to Midway-Sunset, an equity method investment, under an operations and maintenance agreement. Fees for the services under this contract primarily include recovery of NRG's costs of operating the plant, as approved in the annual budget, as well as a base monthly fee and an annual incentive bonus.
GenOn — NRG provided various management, personnel and other services to GenOn under the transition services agreement in conjunction with the confirmation of the GenOn Entities' plan of reorganization. GenOn provided notice to NRG of its intent to terminate the transition services agreement effective August 15, 2018 and all amounts owed and payable to NRG were settled.


43


Note 17Commitments and Contingencies
Commitments
First Lien Structure
NRG has granted first liens to certain counterparties on a substantial portion of the Company's assets, excluding NRG's assets that have project-level financing and the assets of certain non-guarantor subsidiaries, 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 June 30, 2019, all hedges under the first lien were in-the-money for NRG on a counterparty aggregate basis.
Jewett Mine Lignite Contract
The Company's Limestone facility historically blended lignite obtained from the Jewett mine, which was operated by Texas Westmoreland Coal Co, or TWCC, and coal sourced from the Powder River Basin in Wyoming. On August 18, 2016, NRG gave notice to TWCC terminating the active mining of lignite under the contract, effective on December 31, 2016. Under the contract, TWCC remained responsible for reclamation activities. NRG is responsible for reclamation costs and has recorded an adequate ARO liability. The Railroad Commission of Texas has imposed a bond obligation of approximately $99 million for the reclamation of the mine. Pursuant to the contract, NRG supports this obligation through surety bonds. Additionally, under the terms of the contract, NRG is obligated to provide additional performance assurance if required by the Railroad Commission of Texas.
On October 9, 2018, TWCC and certain of its affiliates filed for protection under Chapter 11 of the U.S. Bankruptcy Code before the United States Bankruptcy Court for the Southern District of Texas. TWCC obtained authorization from the bankruptcy court to continue to perform its obligations under its contract with the Company and to maintain surety bonds programs throughout its operations. In addition, NRG has not received any indication from the Railroad Commission of Texas of an intent to draw on the surety bonds. TWCC and its debtor affiliates filed a plan of reorganization that the Bankruptcy Court confirmed on March 2, 2019. Pursuant to the plan, TWCC and its assets, including the Jewett mine and related agreements with NRG, were purchased by Westmoreland Mining LLC, an entity owned by Westmoreland Mining Holdings LLC, a new entity that is ultimately owned and controlled by certain holders of the pre-bankruptcy funded indebtedness of TWCC and certain of its affiliates.
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 accruals 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 accrual for the applicable legal matters, including regulatory and environmental matters as further discussed in Note 18, Regulatory Matters, and Note 19, Environmental Matters. 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 accruals 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.

44


Midwest Generation Asbestos Liabilities — The Company, through certain of its subsidiaries, has settled the indemnification claims brought by Commonwealth Edison Company and Exelon Generation Company LLC (collectively, "ComEd") as a result of the Company's acquisition of EME. Pursuant to a settlement agreement dated as of May 29, 2019, the Company paid $26 million to ComEd, which was previously accrued. In addition, ComEd released all claims that were or could have been asserted in its claims in the EME bankruptcy case and certain of the Company's subsidiaries released all permissive and compulsory counter claims they could have asserted in response to the ComEd claims.
California Department of Water Resources and San Diego Gas & Electric Company v. Sunrise Power Company LLC - On January 29, 2016, CDWR and SDG&E (plaintiffs) filed a lawsuit against Sunrise Power Company, along with NRG and Chevron Power Corporation (defendants). 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 objections in response to the plaintiffs' complaint. The objections 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 objections to the amended complaints. On November 18, 2016, the court sustained the objections 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 objections without leave to amend. On July 14, 2017, plaintiffs filed a notice of appeal. On January 10, 2018, plaintiffs filed their opening appellate brief. Defendants filed their opposition brief on April 10, 2018. On May 30, 2018, plaintiffs filed their reply brief. The case is now waiting for the court of appeal to schedule oral argument.
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 its answer and affirmative defenses on November 17, 2017. On February 4, 2019, NRG sold the South Central Portfolio, including the entities subject to this litigation. However, NRG has agreed to indemnify the purchaser for certain losses suffered in connection therewith.
Sierra club et al. v. Midwest Generation LLC - In 2012, several environmental groups filed a complaint against Midwest Generation with the Illinois Pollution Control Board ("IPCB") alleging violations of environmental law resulting in groundwater contamination. In June 2019, the IPCB found that Midwest Generation violated the law because it had improperly handled coal ash at four facilities in Illinois and caused or allowed coal ash constituents to impact groundwater. The IPCB will hold hearings to determine the appropriate relief. Midwest Generation has been working with the Illinois EPA to address the groundwater issues since 2010.

Note 18Regulatory Matters
Environmental regulatory matters are discussed within Note 19, Environmental Matters, to this Form 10-Q.
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.
South Central — On August 4, 2016, NRG received a document hold notice from FERC regarding conduct in the MISO and PJM markets. It required NRG to retain communications related to multiple generating units in the South Central region. Since sending the notice, FERC has been investigating potential violations of MISO rules involving bidding for the Big Cajun 2 facility, as well as other aspects of NRG’s operations in MISO. FERC has the authority to require disgorgement of profits and to impose

45


penalties and NRG retains any liability following the sale of the South Central Portfolio. We expect a preliminary finding from FERC in 2019.
ISO-NE — On February 5, 2019, FERC has informed the Company that it has made a preliminary finding that the Company violated FERC's market behavior rules in connection with offers made into the ISO-NE Forward Capacity Auction in 2016. On April 26, 2019, NRG responded to the preliminary findings. The Company understands that FERC is concerned that the Company was inaccurate in its communications with the Market Monitor regarding the costs and risks associated with operating certain units in the forward timeframe. NRG withdrew the bids prior to the 2016 auction in the normal course of our commercial business decision making.

Note 19Environmental 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 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.
Air
On July 8, 2019, EPA promulgated the ACE rule, which rescinded the CPP, which sought to broadly regulate CO2 emissions from the power sector. The ACE rule requires states that have coal-fired EGUs to develop plans to seek heat rate improvements from coal-fired EGUs.
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. In December 2018, the EPA proposed a finding that regulating HAPs was not "appropriate and necessary" because the costs far exceed the benefits. Nonetheless, the EPA proposed keeping the substantive requirements of the MATS rule. 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
Once Through Cooling Regulation — 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. The Company anticipates the cost of complying with these requirements to be immaterial.
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, fly ash, bottom ash, and flue gas mercury control. On September 18, 2017, the EPA promulgated a final rule that, among other things, 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. On April 12, 2019, the United States Court of Appeals for the Fifth Circuit released its opinion remanding portions of the rule to the EPA. Accordingly, the Company has 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.
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. In 2017, the EPA agreed to reconsider the rule. On July 30, 2018, the EPA promulgated a rule that amends the existing ash rule by extending some of the deadlines and providing more flexibility for compliance. On August 21, 2018, the D.C. Circuit found, among other things, that the EPA had not adequately regulated unlined ponds and legacy ponds. Accordingly, we anticipate that the EPA will promulgate new regulations to address these issues (including compliance deadlines) as it reconsiders other aspects of the existing rule. The EPA has stated that it intends to further revise the rule. The Company will determine estimates of the cost of compliance after the rule is revised.

46


 
Note 20Condensed Consolidating Financial Information
As of June 30, 2019, the Company had outstanding $4.4 billion of Senior Notes due from 2024 to 2048 and outstanding $1.1 billion of Senior Secured First Lien Notes due from 2024 to 2029, as shown in Note 10, Debt and Capital Leases. These Senior Notes and Senior Secured First Lien 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.
Unless otherwise noted below, each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes and the Senior Secured First Lien Notes as of June 30, 2019:
Ace Energy, Inc.
NRG Business Services LLC
NRG PacGen Inc.
Allied Home Warranty GP LLC
NRG Cabrillo Power Operations Inc.
NRG Portable Power LLC
Allied Warranty LLC
NRG California Peaker Operations LLC
NRG Power Marketing LLC
Arthur Kill Power LLC
NRG Cedar Bayou Development Company, LLC
NRG Reliability Solutions LLC
Astoria Gas Turbine Power LLC
NRG Connected Home LLC
NRG Renter's Protection LLC
BidURenergy, Inc.
NRG Connecticut Affiliate Services Inc.
NRG Retail LLC
Cabrillo Power I LLC
NRG Construction LLC
NRG Retail Northeast LLC
Cabrillo Power II LLC
NRG Curtailment Solutions, Inc
NRG Rockford Acquisition LLC
Carbon Management Solutions LLC
NRG Development Company Inc.
NRG Saguaro Operations Inc.
Cirro Group, Inc.
NRG Devon Operations Inc.
NRG Security LLC
Cirro Energy Services, Inc.
NRG Dispatch Services LLC
NRG Services Corporation
Connecticut Jet Power LLC
NRG Distributed Energy Resources Holdings LLC
NRG SimplySmart Solutions LLC
Devon Power LLC
NRG Distributed Generation PR LLC
NRG South Central Affiliate Services Inc.
Dunkirk Power LLC
NRG Dunkirk Operations Inc.
NRG South Central Operations Inc.
Eastern Sierra Energy Company LLC
NRG ECOKAP Holdings LLC
NRG South Texas LP
El Segundo Power, LLC
NRG El Segundo Operations Inc.
NRG Texas C&I Supply LLC
El Segundo Power II LLC
NRG Energy Labor Services LLC
NRG Texas Gregory LLC
Energy Alternatives Wholesale, LLC
NRG Energy Services Group LLC
NRG Texas Holding Inc.
Energy Choice Solutions LLC
NRG Energy Services International Inc.
NRG Texas LLC
Energy Plus Holdings LLC
NRG Energy Services LLC
NRG Texas Power LLC
Energy Plus Natural Gas LLC
NRG Generation Holdings, Inc.
NRG Warranty Services LLC
Energy Protection Insurance Company
NRG Greenco LLC
NRG West Coast LLC
Everything Energy LLC
NRG Home & Business Solutions LLC
NRG Western Affiliate Services Inc.
Forward Home Security, LLC
NRG Home Services LLC
O'Brien Cogeneration, Inc. II
GCP Funding Company, LLC
NRG Home Solutions LLC
ONSITE Energy, Inc.
Green Mountain Energy Company
NRG Home Solutions Product LLC
Oswego Harbor Power LLC
Gregory Partners, LLC
NRG Homer City Services LLC
Reliant Energy Northeast LLC
Gregory Power Partners LLC
NRG Huntley Operations Inc.
Reliant Energy Power Supply, LLC
Huntley Power LLC
NRG HQ DG LLC
Reliant Energy Retail Holdings, LLC
Independence Energy Alliance LLC
NRG Identity Protect LLC
Reliant Energy Retail Services, LLC
Independence Energy Group LLC
NRG Ilion Limited Partnership
RERH Holdings, LLC
Independence Energy Natural Gas LLC
NRG Ilion LP LLC
Saguaro Power LLC
Indian River Operations Inc.
NRG International LLC
Somerset Operations Inc.
Indian River Power LLC
NRG Maintenance Services LLC
Somerset Power LLC
Meriden Gas Turbines LLC
NRG Mextrans Inc.
Texas Genco GP, LLC
Middletown Power LLC
NRG MidAtlantic Affiliate Services Inc.
Texas Genco Holdings, Inc.
Montville Power LLC
NRG Middletown Operations Inc.
Texas Genco LP, LLC
NEO Corporation
NRG Montville Operations Inc.
Texas Genco Services, LP
New Genco GP, LLC
NRG North Central Operations Inc.
US Retailers LLC
Norwalk Power LLC
NRG Northeast Affiliate Services Inc.
Vienna Operations Inc.
NRG Advisory Services LLC
NRG Norwalk Harbor Operations Inc.
Vienna Power LLC
NRG Affiliate Services Inc.
NRG Operating Services, Inc.
WCP (Generation) Holdings LLC
NRG Arthur Kill Operations Inc.
NRG Oswego Harbor Power Operations Inc.
West Coast Power LLC
NRG Astoria Gas Turbine Operations Inc.
 
 


47


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 of Regulation S-X of the Securities Act. 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.

48


NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the three months ended June 30, 2019
(Unaudited)
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 
Consolidated
 
(In millions)
Operating Revenues
 
 
 
 
 
 
 
 
 
Total operating revenues
$
2,140

 
$
332

 
$

 
$
(7
)
 
$
2,465

Operating Costs and Expenses
 
 
 
 
 
 
 
 
 
Cost of operations
1,590

 
252

 
10

 
(7
)
 
1,845

Depreciation and amortization
51

 
26

 
8

 

 
85

Impairment losses
1

 

 

 

 
1

Selling, general and administrative
112

 
12

 
87

 

 
211

Reorganization costs

 

 
2

 

 
2

Development costs

 
1

 
1

 

 
2

Total operating costs and expenses
1,754

 
291

 
108

 
(7
)
 
2,146

Gain on sale of assets

 
1

 

 

 
1

Operating Income/(Loss)
386

 
42

 
(108
)
 

 
320

Other Income/(Expense)
 
 
 
 
 
 
 
 
 
Equity in earnings of consolidated subsidiaries
2

 

 
430

 
(432
)
 

Other income, net
4

 
8

 
8

 

 
20

Loss on debt extinguishment, net

 

 
(47
)
 

 
(47
)
Interest expense
(3
)
 
(5
)
 
(97
)
 

 
(105
)
Total other income/(expense)
3

 
3

 
294

 
(432
)
 
(132
)
Income from Continuing Operations Before Income Taxes
389

 
45

 
186

 
(432
)
 
188

Income tax expense/(benefit)

 
1

 
(2
)
 

 
(1
)
Income from Continuing Operations
389

 
44

 
188

 
(432
)
 
189

Income from discontinued operations, net of income tax

 

 
13

 

 
13

Net Income
389

 
44

 
201

 
(432
)
 
202

Less: Net income attributable to noncontrolling interest and redeemable interests

 
1

 

 

 
1

Net Income Attributable to NRG Energy, Inc.
$
389

 
$
43

 
$
201

 
$
(432
)
 
$
201


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


49


NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the six months ended June 30, 2019
(Unaudited)
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 
Consolidated
 
(In millions)
Operating Revenues
 
 
 
 
 
 
 
 
 
Total operating revenues
$
3,909

 
$
727

 
$

 
$
(6
)
 
$
4,630

Operating Costs and Expenses
 
 
 
 
 
 
 
 

Cost of operations
2,948

 
535

 
19

 
(6
)
 
3,496

Depreciation and amortization
105

 
49

 
16

 

 
170

Impairment losses
1

 

 

 

 
1

Selling, general and administrative
234

 
28

 
143

 

 
405

Reorganization costs

 

 
15

 

 
15

Development costs

 
1

 
3

 

 
4

Total operating costs and expenses
3,288

 
613

 
196

 
(6
)
 
4,091

Gain on sale of assets
1

 
1

 

 

 
2

Operating Income/(Loss)
622

 
115

 
(196
)
 

 
541

Other Income/(Expense)
 
 
 
 
 
 
 
 

Equity in earnings of consolidated subsidiaries
12

 

 
729

 
(741
)
 

Equity in losses of unconsolidated affiliates

 
(21
)
 

 

 
(21
)
Other income, net
8

 
9

 
15

 

 
32

Loss on debt extinguishment, net

 

 
(47
)
 

 
(47
)
Interest expense
(7
)
 
(9
)
 
(203
)
 

 
(219
)
Total other income/(expense)
13

 
(21
)
 
494

 
(741
)
 
(255
)
Income from Continuing Operations Before Income Taxes
635

 
94

 
298

 
(741
)
 
286

Income tax expense

 
1

 
2

 

 
3

Income from Continuing Operations
635

 
93

 
296

 
(741
)
 
283

Income from discontinued operations, net of income tax
9

 
5

 
387

 

 
401

Net Income
644

 
98

 
683

 
(741
)
 
684

Less: Net income attributable to noncontrolling interest and redeemable interests

 
1

 

 

 
1

Net Income Attributable to NRG Energy, Inc.
$
644

 
$
97

 
$
683

 
$
(741
)
 
$
683

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


50


NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME
For the three months ended June 30, 2019
(Unaudited)
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 
Consolidated
 
(In millions)
Net Income
$
389

 
$
44

 
$
201

 
$
(432
)
 
$
202

Other Comprehensive Loss
 
 
 
 
 
 
 
 
 
Foreign currency translation adjustments, net
(1
)
 
(1
)
 
(1
)
 
2

 
(1
)
Available-for-sale securities, net

 

 
1

 

 
1

Defined benefit plans, net

 

 
(3
)
 

 
(3
)
Other comprehensive loss
(1
)
 
(1
)
 
(3
)
 
2

 
(3
)
Comprehensive Income
388

 
43

 
198

 
(430
)
 
199

Less: Comprehensive income attributable to noncontrolling redeemable interest

 
1

 

 

 
1

Comprehensive Income Attributable to NRG Energy, Inc.
$
388

 
$
42

 
$
198

 
$
(430
)
 
$
198

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


51


NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME
For the six months ended June 30, 2019
(Unaudited)
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 
Consolidated
 
(In millions)
Net Income
$
644

 
$
98

 
$
683

 
$
(741
)
 
$
684

Other Comprehensive Loss
 
 
 
 
 
 
 
 

Available-for-sale securities, net

 

 
1

 

 
1

Defined benefit plans, net

 

 
(6
)
 

 
(6
)
Other comprehensive loss

 

 
(5
)
 

 
(5
)
Comprehensive Income
644

 
98

 
678

 
(741
)
 
679

Less: Comprehensive income attributable to noncontrolling redeemable interest

 
1

 

 

 
1

Comprehensive Income Attributable to NRG Energy, Inc.
$
644

 
$
97

 
$
678

 
$
(741
)
 
$
678

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


52


NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
June 30, 2019
(Unaudited)
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 
Consolidated
ASSETS
(In millions)
Current Assets
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$

 
$
27

 
$
267

 
$

 
$
294

Funds deposited by counterparties
31

 

 

 

 
31

Restricted cash
8

 
2

 
1

 

 
11

Accounts receivable, net
1,383

 
133

 
277

 
(744
)
 
1,049

Inventory
254

 
116

 

 

 
370

Derivative instruments
867

 
54

 

 
(71
)
 
850

Cash collateral paid in support of energy risk management activities
148

 
15

 

 

 
163

Prepayments and other current assets
190

 
11

 
76

 

 
277

Total current assets
2,881

 
358

 
621


(815
)
 
3,045

Property, plant and equipment, net
1,494

 
965

 
151

 

 
2,610

Other Assets
 
 
 
 
 
 
 
 

Investment in subsidiaries
436

 

 
4,191

 
(4,627
)
 

Equity investments in affiliates

 
383

 

 

 
383

Operating lease right-of-use assets, net
91

 
279

 
129

 

 
499

Goodwill
359

 
214

 

 

 
573

Intangible assets, net
402

 
159

 

 

 
561

Nuclear decommissioning trust fund
748

 

 

 

 
748

Derivative instruments
420

 
22

 

 
(16
)
 
426

Deferred income tax

 
56

 
(1
)
 

 
55

Other non-current assets
148

 
30

 
96

 
(3
)
 
271

Total other assets
2,604

 
1,143

 
4,415

 
(4,646
)
 
3,516

Total Assets
$
6,979

 
$
2,466

 
$
5,187

 
$
(5,461
)
 
$
9,171

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

 
$
87

 
$

 
$

 
$
87

Current portion of operating lease liabilities
22

 
31

 
21

 

 
74

Accounts payable
937

 
107

 
423

 
(744
)
 
723

Derivative instruments
817

 
32

 

 
(71
)
 
778

Cash collateral received in support of energy risk management activities
31

 

 

 

 
31

Accrued expenses and other current liabilities
258

 
42

 
301

 

 
601

Total current liabilities
2,065

 
299

 
745

 
(815
)
 
2,294

Other Liabilities
 
 
 
 
 
 
 
 

Long-term debt and capital leases
245

 
89

 
5,463

 
(3
)
 
5,794

Non-current operating lease liabilities
73

 
313

 
127

 

 
513

Nuclear decommissioning reserve
290

 

 

 

 
290

Nuclear decommissioning trust liability
448

 

 

 

 
448

Derivative instruments
388

 
2

 

 
(16
)
 
374

Deferred income taxes
(10
)
 
68

 
13

 

 
71

Other non-current liabilities
399

 
148

 
469

 

 
1,016

Total other liabilities
1,833

 
620

 
6,072

 
(19
)
 
8,506

Total Liabilities
3,898

 
919

 
6,817

 
(834
)
 
10,800

Redeemable noncontrolling interest in subsidiaries

 
19

 

 

 
19

Stockholders’ Equity
3,081

 
1,528

 
(1,630
)
 
(4,627
)
 
(1,648
)
Total Liabilities and Stockholders’ Equity
$
6,979

 
$
2,466

 
$
5,187

 
$
(5,461
)
 
$
9,171

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

53


NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the six months ended June 30, 2019
(Unaudited)
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 
Consolidated
 
(In millions)
Cash Flows from Operating Activities
 
 
 
 
 
 
 
 
 
Net income
$
644

 
$
98

 
$
683

 
$
(741
)
 
$
684

Income from discontinued operations
9

 
5

 
387

 

 
401

Income from continuing operations
635

 
93

 
296

 
(741
)
 
283

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

Distributions and equity in (earnings)/losses of unconsolidated affiliates and consolidated subsidiaries
(12
)
 
22

 
(729
)
 
741

 
22

Depreciation, amortization and accretion
115

 
53

 
16

 

 
184

Provision for bad debts
42

 
4

 
6

 

 
52

Amortization of nuclear fuel
27

 

 

 

 
27

Amortization of financing costs and debt discount/premiums

 

 
13

 

 
13

Loss on debt extinguishment, net

 

 
47

 

 
47

Amortization of intangibles
13

 
1

 

 

 
14

Amortization of unearned equity compensation

 

 
10

 

 
10

(Loss)/gain on sale and disposal of assets
(3
)
 
1

 
3

 

 
1

Impairment losses
1

 

 

 

 
1

Changes in derivative instruments
(28
)
 
(32
)
 
38

 

 
(22
)
Changes in deferred income taxes and liability for uncertain tax benefits

 
(3
)
 
(2
)
 

 
(5
)
Changes in collateral deposits in support of energy risk management activities
128

 
(3
)
 

 

 
125

Changes in nuclear decommissioning trust liability
17

 

 

 

 
17

Changes in other working capital
(343
)
 
(64
)
 
19

 

 
(388
)
Cash provided/(used) by continuing operations
592

 
72

 
(283
)
 

 
381

Cash provided/(used) by discontinued operations
17

 
(9
)
 

 

 
8

Net Cash Provided/(Used) by Operating Activities
609

 
63

 
(283
)
 

 
389

Cash Flows from Investing Activities
 
 
 
 
 
 
 
 


Intercompany dividends

 

 
738

 
(738
)
 

Payments for acquisitions of businesses
(21
)
 

 

 

 
(21
)
Capital expenditures
(77
)
 
(15
)
 
(15
)
 

 
(107
)
Net purchases of emission allowances
(1
)
 

 

 

 
(1
)
Investments in nuclear decommissioning trust fund securities
(209
)
 

 

 

 
(209
)
Proceeds from the sale of nuclear decommissioning trust fund securities
191

 

 

 

 
191

Proceeds from sale of assets, net of cash disposed and sale of discontinued operations, net of fees
1

 
400

 
888

 


 
1,289

Net distributions from investments in unconsolidated affiliates

 
7

 

 

 
7

Contributions to discontinued operations

 
(44
)
 

 

 
(44
)
Cash (used)/provided by continuing operations
(116
)
 
348

 
1,611

 
(738
)
 
1,105

Cash used by discontinued operations

 
(2
)
 

 

 
(2
)
Net Cash (Used)/Provided by Investing Activities
(116
)
 
346

 
1,611

 
(738
)
 
1,103

Cash Flows from Financing Activities


 
 
 
 
 
 
 

Payments from/(for) intercompany loans
206

 
(375
)
 
169

 

 

Intercompany dividends
(738
)
 

 

 
738

 

Payment of dividends to common stockholders

 

 
(16
)
 

 
(16
)
Payments for treasury stock

 

 
(1,039
)
 

 
(1,039
)
Payments for debt extinguishment

 

 
(24
)
 

 
(24
)
Distributions to noncontrolling interests from subsidiaries

 
(1
)
 

 

 
(1
)
Proceeds from issuance of common stock

 

 
2

 

 
2

Proceeds from issuance of long-term debt

 

 
1,833

 

 
1,833

Payment of debt issuance costs

 

 
(33
)
 

 
(33
)
Payments for long-term debt

 
(53
)
 
(2,432
)
 

 
(2,485
)
Cash used by continuing operations
(532
)
 
(429
)
 
(1,540
)
 
738

 
(1,763
)
Cash provided by discontinued operations

 
43

 

 

 
43

Net Cash Used by Financing Activities
(532
)
 
(386
)
 
(1,540
)
 
738

 
(1,720
)
Change in cash from discontinued operations
17

 
32

 

 

 
49

Net Decrease in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash
(56
)
 
(9
)
 
(212
)
 

 
(277
)
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period
95

 
38

 
480

 

 
613

Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period
$
39


$
29


$
268


$

 
$
336

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

54


NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the three months ended June 30, 2018
(Unaudited)
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 
Consolidated
 
(In millions)
Operating Revenues
 
 
 
 
 
 
 
 
 
Total operating revenues
$
2,172

 
$
291

 
$

 
$
(2
)
 
$
2,461

Operating Costs and Expenses
 
 
 
 
 
 
 
 
 
Cost of operations
1,702

 
195

 
(5
)
 
(3
)
 
1,889

Depreciation and amortization
63

 
40

 
9

 

 
112

Impairment losses

 
74

 

 

 
74

Selling, general and administrative
108

 
16

 
76

 

 
200

Reorganization costs
1

 

 
22

 

 
23

Development costs

 
1

 
3

 
(1
)
 
3

Total operating costs and expenses
1,874

 
326

 
105

 
(4
)
 
2,301

Gain on sale of assets

 
14

 

 

 
14

Operating Income/(Loss)
298

 
(21
)
 
(105
)
 
2

 
174

Other Income/(Expense)

 

 


 

 

Equity in earnings of consolidated subsidiaries
7

 

 
353

 
(360
)
 

Equity in earnings of unconsolidated affiliates

 
5

 

 

 
5

Other income/(loss), net
3

 
(29
)
 
3

 

 
(23
)
Loss on debt extinguishment, net

 

 
(1
)
 

 
(1
)
Interest expense
(4
)
 
(13
)
 
(106
)
 

 
(123
)
Total other income/(expense)
6

 
(37
)
 
249

 
(360
)
 
(142
)
Income/(Loss) from Continuing Operations Before Income Taxes
304

 
(58
)
 
144

 
(358
)
 
32

Income tax expense/(benefit)
108

 
(71
)
 
(32
)
 

 
5

Income from Continuing Operations
196

 
13

 
176

 
(358
)
 
27

Income/(loss) from discontinued operations, net of income tax
15

 
80

 
(26
)
 

 
69

Net Income
211

 
93

 
150

 
(358
)
 
96

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

 
(56
)
 
78

 
2

 
24

Net Income Attributable to NRG Energy, Inc.
$
211

 
$
149

 
$
72

 
$
(360
)
 
$
72

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


55


NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the six months ended June 30, 2018
(Unaudited)
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 
Consolidated
 
(In millions)
Operating Revenues
 
 
 
 
 
 
 
 
 
Total operating revenues
$
3,916

 
$
620

 
$

 
$
(10
)
 
$
4,526

Operating Costs and Expenses
 
 
 
 
 
 
 
 

Cost of operations
2,857

 
419

 
9

 
(11
)
 
3,274

Depreciation and amortization
123

 
92

 
17

 

 
232

Impairment losses

 
74

 

 

 
74

Selling, general and administrative
212

 
27

 
137

 

 
376

Reorganization costs
3

 

 
40

 

 
43

Development costs

 
2

 
7

 
(1
)
 
8

Total operating costs and expenses
3,195

 
614

 
210

 
(12
)
 
4,007

Gain on sale of assets
3

 
13

 

 

 
16

Operating Income/(Loss)
724

 
19

 
(210
)
 
2

 
535

Other Income/(Expense)
 
 
 
 
 
 
 
 

Equity in earnings of consolidated subsidiaries
8

 

 
685

 
(693
)
 

Equity in earnings/(losses) of unconsolidated affiliates

 
7

 
(1
)
 

 
6

Other income/(loss), net
8

 
(36
)
 
5

 

 
(23
)
Loss on debt extinguishment, net

 

 
(3
)
 

 
(3
)
Interest expense
(7
)
 
(34
)
 
(198
)
 

 
(239
)
Total other income/(expense)
9

 
(63
)
 
488

 
(693
)
 
(259
)
Income/(Loss) from Continuing Operations Before Income Taxes
733

 
(44
)
 
278

 
(691
)
 
276

Income tax expense/(benefit)
221

 
(16
)
 
(194
)
 

 
11

Income/(Loss) from Continuing Operations
512

 
(28
)
 
472

 
(691
)
 
265

Income/(loss) from discontinued operations, net of income tax
30

 
60

 
(26
)
 

 
64

Net Income
542

 
32

 
446

 
(691
)
 
329

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

 
(119
)
 
95

 
2

 
(22
)
Net Income Attributable to NRG Energy, Inc.
$
542

 
$
151

 
$
351

 
$
(693
)
 
$
351

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


56


NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME
For the three months ended June 30, 2018
(Unaudited)
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 
Consolidated
 
(In millions)
Net Income
$
211

 
$
93

 
$
150

 
$
(358
)
 
$
96

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

 
4

 
6

 
(5
)
 
5

Foreign currency translation adjustments, net
(4
)
 
(4
)
 
(5
)
 
9

 
(4
)
Available-for-sale securities, net

 

 
1

 

 
1

Defined benefit plans, net

 

 
(1
)
 

 
(1
)
Other comprehensive (loss)/income
(4
)
 

 
1

 
4

 
1

Comprehensive Income
207

 
93

 
151

 
(354
)
 
97

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

 
(56
)
 
80

 
2

 
26

Comprehensive Income Attributable to NRG Energy, Inc.
$
207

 
$
149

 
$
71

 
$
(356
)
 
$
71

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

57


NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME
For the six months ended June 30, 2018
(Unaudited)
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 
Consolidated
 
(In millions)
Net Income
$
542

 
$
32

 
$
446

 
$
(691
)
 
$
329

Other Comprehensive (Loss)/Income
 
 
 
 
 
 
 
 

Unrealized gain on derivatives, net

 
20

 
21

 
(22
)
 
19

Foreign currency translation adjustments, net
(6
)
 
(6
)
 
(8
)
 
14

 
(6
)
Available-for-sale securities, net

 

 
1

 

 
1

Defined benefit plans, net

 

 
(2
)
 

 
(2
)
Other comprehensive (loss)/income
(6
)
 
14

 
12

 
(8
)
 
12

Comprehensive Income
536

 
46

 
458

 
(699
)
 
341

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

 
(119
)
 
105

 
2

 
(12
)
Comprehensive Income Attributable to NRG Energy, Inc.
$
536

 
$
165

 
$
353

 
$
(701
)
 
$
353

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


58


NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2018
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 
Consolidated
ASSETS
(In millions)
Current Assets
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
55

 
$
28

 
$
480

 
$

 
$
563

Funds deposited by counterparties
33

 

 

 

 
33

Restricted cash
7

 
10

 

 

 
17

Accounts receivable, net
1,354

 
115

 
309

 
(754
)
 
1,024

Inventory
278

 
134

 

 

 
412

Derivative instruments
779

 
50

 
16

 
(81
)
 
764

Cash collateral paid in support of energy risk management activities
275

 
12

 

 

 
287

Prepayments and other current assets
180

 
32

 
90

 

 
302

Current assets - held-for-sale

 
1

 

 

 
1

Current assets - discontinued operations
177

 
20

 

 

 
197

Total current assets
3,138

 
402

 
895

 
(835
)
 
3,600

Property, plant and equipment, net
1,938

 
957

 
153

 

 
3,048

Other Assets
 
 
 
 
 
 
 
 

Investment in subsidiaries
446

 

 
4,707

 
(5,153
)
 

Equity investments in affiliates

 
412

 

 

 
412

Goodwill
359

 
214

 

 

 
573

Intangible assets, net
422

 
169

 

 

 
591

Nuclear decommissioning trust fund
663

 

 

 

 
663

Derivative instruments
296

 
4

 
22

 
(5
)
 
317

Deferred income taxes
6

 
(143
)
 
183

 

 
46

Other non-current assets
133

 
71

 
97

 
(12
)
 
289

Non-current assets - held for sale

 
77

 

 

 
77

Non-current assets - discontinued operations
405

 
607

 

 

 
1,012

Total other assets
2,730

 
1,411

 
5,009

 
(5,170
)
 
3,980

Total Assets
$
7,806

 
$
2,770

 
$
6,057

 
$
(6,005
)
 
$
10,628

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

 
$
55

 
$
17

 
$

 
$
72

Accounts payable
1,368

 
(185
)
 
434

 
(754
)
 
863

Derivative instruments
713

 
41

 

 
(81
)
 
673

Cash collateral received in support of energy risk management activities
33

 

 

 

 
33

Accrued expenses and other current liabilities
291

 
36

 
353

 

 
680

Current liabilities - held-for-sale

 
5

 

 

 
5

Current liabilities - discontinued operations
24

 
48

 

 

 
72

Total current liabilities
2,429

 

 
804

 
(835
)
 
2,398

Other Liabilities
 
 
 
 
 
 
 
 

Long-term debt and capital leases
244

 
192

 
6,025

 
(12
)
 
6,449

Nuclear decommissioning reserve
282

 

 

 

 
282

Nuclear decommissioning trust liability
371

 

 

 

 
371

Derivative instruments
306

 
3

 

 
(5
)
 
304

Deferred income taxes
112

 
61

 
(108
)
 

 
65

Other non-current liabilities
402

 
320

 
552

 

 
1,274

Non-current liabilities - held-for-sale

 
65

 

 

 
65

Non-current liabilities - discontinued operations
58

 
577

 

 

 
635

Total other liabilities
1,775

 
1,218

 
6,469

 
(17
)
 
9,445

Total Liabilities
4,204

 
1,218

 
7,273

 
(852
)
 
11,843

Redeemable noncontrolling interest in subsidiaries

 
19

 

 

 
19

Stockholders’ Equity
3,602

 
1,533

 
(1,216
)
 
(5,153
)
 
(1,234
)
Total Liabilities and Stockholders’ Equity
$
7,806

 
$
2,770

 
$
6,057


$
(6,005
)
 
$
10,628

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

59


NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the six months ended June 30, 2018
(Unaudited)
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 
Consolidated
 
(In millions)
Cash Flows from Operating Activities
 
 
 
 
 
 
 
 
 
Net income
$
542

 
$
32

 
$
446

 
$
(691
)
 
$
329

Income/(loss) from discontinued operations
30

 
60

 
(26
)
 

 
64

Income/(loss) from continuing operations
512

 
(28
)
 
472

 
(691
)
 
265

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

Distributions and equity in (earnings)/losses of unconsolidated affiliates and consolidated subsidiaries
(8
)
 
11

 
(682
)
 
691

 
12

Depreciation, amortization and accretion
136

 
99

 
17

 

 
252

Provision for bad debts
30

 

 

 

 
30

Amortization of nuclear fuel
24

 

 

 

 
24

Amortization of financing costs and debt discount/premiums

 
1

 
12

 

 
13

Loss on debt extinguishment, net

 

 
3

 

 
3

Amortization of intangibles and out-of-market contracts
16

 
4

 

 

 
20

Amortization of unearned equity compensation

 

 
15

 

 
15

Loss on sale and disposal of assets
(3
)
 
(13
)
 

 

 
(16
)
Impairment losses

 
88

 

 

 
88

Changes in derivative instruments
(154
)
 
19

 
(10
)
 

 
(145
)
Changes in deferred income taxes and liability for uncertain tax benefits
221

 
(47
)
 
(176
)
 

 
(2
)
Changes in collateral deposits in support of energy risk management activities
(5
)
 
(4
)
 

 

 
(9
)
Changes in nuclear decommissioning trust liability
41

 

 

 

 
41

Loss on deconsolidation of Ivanpah project

 
22

 

 

 
22

Changes in other working capital
152

 
(56
)
 
(445
)
 

 
(349
)
Cash provided/(used) by continuing operations
962

 
96


(794
)


 
264

Cash provided by discontinued operations
50

 
199

 

 

 
249

Net Cash Provided/(Used) by Operating Activities
1,012

 
295

 
(794
)
 

 
513

Cash Flows from Investing Activities
 
 
 
 
 
 
 
 
 
Intercompany dividends

 

 
157

 
(157
)
 

Payments for acquisitions of businesses
(2
)
 
(209
)
 

 

 
(211
)
Capital expenditures
(103
)
 
(149
)
 
(30
)
 

 
(282
)
Net proceeds from sale of emission allowances
3

 

 

 

 
3

Investments in nuclear decommissioning trust fund securities
(346
)
 

 

 

 
(346
)
Proceeds from the sale of nuclear decommissioning trust fund securities
303

 

 

 

 
303

Proceeds from sale of assets, net of cash disposed of
11

 

 
135

 

 
146

Deconsolidation of Ivanpah project

 
(160
)
 

 

 
(160
)
Net contributions for investments in unconsolidated affiliates

 
(15
)
 

 

 
(15
)
Contributions to discontinued operations

 
(16
)
 

 

 
(16
)
Cash (used)/provided by continuing operations
(134
)
 
(549
)
 
262


(157
)
 
(578
)
Cash provided/(used) by discontinued operations
2

 
(586
)
 

 

 
(584
)
Net Cash (Used)/Provided by Investing Activities
(132
)
 
(1,135
)
 
262

 
(157
)
 
(1,162
)
Cash Flows from Financing Activities
 
 
 
 
 
 
 
 

Payments (for)/from intercompany loans
(611
)
 
204

 
407

 

 

Intercompany dividends
(157
)
 

 

 
157

 

Payment of dividends to common stockholders

 

 
(19
)
 

 
(19
)
Payments for treasury stock

 

 
(500
)
 

 
(500
)
Distributions to noncontrolling interests from subsidiaries

 
(14
)
 

 

 
(14
)
Proceeds from issuance of common stock

 

 
11

 

 
11

Proceeds from issuance of short and long-term debt

 
163

 
831

 

 
994

Payment of debt issuance costs

 

 
(19
)
 

 
(19
)
Payments for short and long-term debt

 
(63
)
 
(285
)
 

 
(348
)
Cash (used)/provided by continuing operations
(768
)
 
290

 
426

 
157

 
105

Cash provided by discontinued operations

 
345

 

 

 
345

Net Cash (Used)/Provided by Financing Activities
(768
)
 
635

 
426

 
157

 
450

Change in cash from discontinued operations
52

 
(42
)
 

 

 
10

Net Increase/(Decrease) in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash
60

 
(163
)
 
(106
)
 

 
(209
)
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period
41

 
425

 
620

 

 
1,086

Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period
$
101

 
$
262

 
$
514

 
$

 
$
877

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

60


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 six months ended June 30, 2019 and 2018. Also refer to NRG's 2018 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.

As further described in Note 4, Acquisitions, Discontinued Operations and Dispositions, the Company is treating the following businesses as discontinued operations, and has recast prior periods to present in the corporate segment:
South Central Portfolio
NRG Yield, Inc. and its Renewables Platform
Carlsbad
GenOn


61


Executive Summary
Introduction and Overview
NRG Energy, Inc., or NRG or the Company, is an energy company built on dynamic retail brands with diverse generation assets. NRG brings the power of energy to consumers by producing, selling and delivering electricity and related products and services in major competitive power markets in the U.S. in a manner that delivers value to all of NRG's stakeholders. NRG is perfecting the integrated model by balancing retail load with generation supply within its deregulated markets, while evolving to a customer-driven business. The Company sells energy, services, and innovative, sustainable products and services directly to retail customers under the names "NRG" and "Reliant" and other brand names owned by NRG supported by approximately 23,000 MW of generation as of June 30, 2019. NRG was incorporated as a Delaware corporation on May 29, 1992.
The following table summarizes NRG's global generation portfolio as of June 30, 2019, by operating segment:
 
 
Global Generation Portfolio(a)
 
 
(In MW)
 
 
Generation
 
 
 
 
Generation Type
 
Texas(b)
 
East/West(c)(d)
 
Other (e)
 
Total Global
Natural gas
 
4,759

 
4,994

 

 
9,753

Coal
 
4,174

 
3,745

 

 
7,919

Oil
 

 
3,600

 

 
3,600

Nuclear
 
1,126

 

 

 
1,126

Utility Scale Solar
 

 
321

 

 
321

Battery Storage & Distributed Solar
 
2

 

 
60

 
62

Total generation capacity
 
10,061

 
12,660

 
60

 
22,781

(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) Does not include Cottonwood, which is included in East/West
(c)
Includes International and the remaining Renewables generation assets
(d) Includes 1,153 MW for the Cottonwood facility that was sold to Cleco on February 4, 2019, which the company is leasing until 2025
(e)
The Distributed Solar figure within "Other" includes the aggregate production capacity of installed and activated residential solar energy systems

Strategy
NRG's strategy is to maximize stockholder value through the safe production and sale of reliable power to its customers in the markets served by the Company, while positioning the Company to provide innovative solutions to the end-use energy consumer. This strategy is intended to enable the Company to optimize the integrated model to generate predictable cash flow, significantly strengthen earnings and cost competitiveness, and lower risk and volatility. Sustainability is an integral piece of NRG's strategy and ties directly to business success, reduced risks and brand value.
To effectuate the Company’s strategy, NRG is focused on: (i) serving the energy needs of end-use residential, commercial and industrial customers in competitive markets through multiple brands and channels with a variety of retail energy products and services differentiated by innovative features, premium service, sustainability, and loyalty/affinity programs; (ii) deploying innovative and renewable energy solutions for consumers within its retail businesses; (iii) excellence in operating performance of its existing assets including optimal hedging of generation assets and retail load operations; and (iv) engaging in a proactive capital allocation plan within the dictates of prudent balance sheet management.


62


Transformation Plan
NRG is well underway in executing its Transformation Plan. The Company expects to fully implement the Transformation Plan by the end of 2020, with a significant portion of the plan completed in 2018. The three-part, three-year plan is comprised of the following targets, and the Company's achievements towards such targets are as follows:
Operations and cost excellence - Recurring cost savings and margin enhancement of $1,065 million, which consists of $590 million of cumulative 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. The Company realized annual cost savings of $532 million and $32 million of margin enhancements during the year ended December 31, 2018, and expects to realize $590 million of cost savings and $135 million of margin enhancements in 2019.

The Company expects to realize (i) $370 million of non-recurring working capital improvements through 2020 and (ii) approximately $290 million one-time cost to achieve. By December 31, 2018, NRG had realized $333 million of non-recurring working capital improvements and $194 million of one-time costs to achieve. The Company expects to incur approximately $95 million of one-time cost to achieve in 2019.

Portfolio Optimization - Targeted and completed $3.0 billion of asset sale cash proceeds, including $1.4 billion in the first quarter of 2019 from the sales of the South Central portfolio, the Carlsbad project and Guam.
Capital Structure and Allocation - As of December 31, 2018, the Company achieved the planned credit ratio of 3.0x net debt / adjusted EBITDA(a). During the first quarter of 2019, the Company revised its credit metrics target in order to further strengthen its balance sheet by reducing leverage.
Energy Regulatory Matters
The Company’s regulatory matters are described in the Company’s 2018 Form 10-K in Item 1, Business — Regulatory Matters. These matters have been updated below and in Note 18, Regulatory Matters, of this Form 10-Q.
As participants in wholesale and retail energy markets and owners of power plants, 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 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.
Federal Energy Regulation
PG&E Corporation Bankruptcy Filing — On January 18, 2019, NextEra Energy, Inc., filed a petition for declaratory order requesting that FERC assert its jurisdiction over PG&E's wholesale contracts prior to PG&E's formal bankruptcy filing. Exelon Corporation and EDF Renewables filed similar complaints. On January 25, 2019, FERC found that it and the bankruptcy courts have concurrent jurisdiction to review and address the disposition of wholesale power contracts. Separately, the PG&E bankruptcy court ruled on June 7, 2019 that it does not share concurrent jurisdiction with FERC and has unilateral discretion to address the disposition of wholesale power contracts. On June 26, 2019, PG&E appealed the FERC order that was issued on January 25, 2019. The issue of jurisdiction over wholesale power contracts remains in litigation.





(a) adjusted EBITDA as defined per the Senior Credit Facility

63


State Energy Regulation
State Out-Of-Market Subsidy Proposals — NRG has opposed efforts to provide out-of-market subsidies for nuclear generators and intends to continue opposing them in the future. Nuclear subsidy programs have either been implemented, are in the process of being implemented, or have been introduced for discussion in Connecticut, Illinois, New Jersey, New York, Ohio and Pennsylvania. NRG and others were unsuccessful in challenging the legality of the subsidies in Illinois and New York, and the U.S. Supreme Court has declined to review the lower court decisions. 
Illinois Legislature Considers Changes to the Generator Business Model In Illinois, in addition to legislation to provide more subsidies to nuclear power plants in the state, the Legislature is also considering several bills that may affect NRG’s wholesale and retail revenues, including a bill that would replace the PJM capacity market with a state-run capacity market. Illinois ended its regular session on May 31, 2019 without passing these significant energy bills. NRG is opposed to this legislative effort and has supported a competitive clean energy market design that would competitively procure additional zero emission power without sacrificing the consumer benefits of the competitive PJM market design. 
New York State Climate Leadership and Community Protection Act — In June 2019, NY State Legislature passed climate change legislation establishing by 2030, 70 percent of the state's energy will be generated by renewables and by 2040, the state's entire electric system must be zero-emitting. The law includes a provision that the NYSPSC may temporarily suspend or modify the obligations under its program if the Commission finds that the program impedes safe and adequate electric service, likely impairs "existing obligations and agreements," and/or increases consumer late payments or service disconnections. The legislation includes provision for offsets, including carbon capture and sequestration, but electric generation sources are not eligible to participate in the offsets mechanism.

Regional Regulatory Developments
NRG is affected by rule and tariff changes that occur in the ISO regions. For further discussion on regulatory developments see Note 18, Regulatory Matters, to the Condensed Consolidated Financial Statements.
East/West
PJM
Capacity Market Reforms Filing — FERC is considering various proposals to reform the PJM capacity market, including whether to accommodate state subsidies in the wholesale market or to mitigate subsidized resources, along with other changes. As part of this process, FERC established a procedural timetable and delayed the 2019 Base Residual Auction until August 2019. On April 10, 2019, PJM filed a motion seeking clarification of FERC's June 29, 2018 Order with respect to the August 2019 BRA. On July 25, 2019, FERC directed PJM not to run the BRA in August 2019 and wait to hold the auction until new rules are in place. Decisions around harmonizing federal and state policy initiatives are a critical factor for setting future prices.
PJM's Operational Reserve Demand Curve Filing — On March 29, 2019, PJM proposed energy and reserve market reforms to enhance price formation in reserve markets, which includes modifying its Operating Reserve Demand Curve and aligning market-based reserve products in Day-Ahead and Real-Time markets. The matter is pending at FERC. If the proposal were approved as filed, energy and reserve market prices could increase.
Independent Market Monitor Market Seller Offer Cap Complaint — On February 21, 2019, the Independent Market Monitor filed a complaint alleging that the current Market Seller Offer Cap is too high. On April 9, 2019, PJM filed its answer arguing that as a threshold matter the Independent Market Monitor is not authorized to file a complaint against PJM. If the request is granted, default market offer caps could be lower.
New England
ISO-NE Retention of Mystic Units — ISO-NE is currently engaged in extensive litigation at FERC regarding how to ensure system reliability in a gas-constrained system. In particular, FERC has approved ISO-NE's proposal to retain units at the Mystic generating station, which utilizes liquefied natural gas for fuel security. Among other things, FERC specifically will allow resources retained for fuel security to enter a zero bid in the Forward Capacity Auction, and also ordered ISO-NE to provide a long-term market-based solution for fuel security. On January 2, 2019, multiple parties filed for rehearing. The motions for rehearing are pending at FERC. The outcome of this matter may affect future capacity market prices.

64


ISO-NE Inventoried Energy Compensation Proposal — On March 25, 2019, ISO-NE proposed an interim measure to address near-term fuel security concerns. The proposal would provide payment for inventoried energy during winter months. NRG protested, among other things, the payment rate proposed by the ISO for inventoried energy. After ISO-NE supplemented its filings due to a deficiency notice from FERC, NRG filed comments to ISO-NE's response on June 27, 2019. On August 6, 2019, FERC issued a notice stating that due to lack of quorum, ISO-NE's proposal became effective by operation of law. ISO-NE's proposal will affect future capacity market prices and the compensation fuel secure units receive.
New York
New York State Public Service Commission Retail Energy Market Proceedings — On February 23, 2016, the NYSPSC issued an order referred to as the Retail Reset Order. Among other things, the Retail Reset Order placed a price cap on energy supply offers and imposed burdensome new regulations on customers. Various parties have challenged the NYSPSC's authority to regulate prices charged by competitive suppliers. This litigation is ongoing.
Texas
ORDC Reforms — In January 2019, the PUCT directed ERCOT to implement changes to its scarcity pricing structure, known as the ORDC, which is designed to increase the likelihood of scarcity pricing to support existing generation and new investment. The PUCT directed ORDC reforms to be implemented in two phases of gradually increasing magnitude. The first phase became effective on March 1, 2019 and the second phase will become effective on March 1, 2020. To date, the ORDC reforms have produced a noticeable improvement in scarcity pricing.

Environmental Regulatory Matters
NRG is subject to numerous 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. Federal and state environmental laws historically have become more stringent over time. Future laws may require the addition of emissions controls or other environmental controls or impose restrictions on our operations, which could affect the Company's operations. Complying with environmental laws often involves significant capital and operating expenses, as well as occasionally curtailing operations. 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 that may affect the Company are under review by the EPA, including ESPS for GHGs, ash disposal requirements, NAAQS revisions and implementation and effluent limitation guidelines. NRG will evaluate the impact of these regulations as they are revised but cannot fully predict the impact of each until anticipated legal challenges are resolved. The Company’s environmental matters are described in the Company’s 2018 Form 10-K in Item 1, Business - Environmental Matters and Item 1A, Risk Factors. These matters have been updated in Note 19, Environmental Matters, to the Condensed Consolidated Financial Statements of this Form 10-Q and as follows.
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 become more stringent. The Company maintains a comprehensive compliance strategy to address continuing and new requirements. Complying with increasingly stringent air regulations could require the installation of additional emissions control equipment at some NRG facilities or retiring of units if installing such controls is not economic. Significant changes to air regulatory programs affecting the Company are described below.
MATS — In 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. In December 2018, the EPA proposed a finding that regulating HAPs was not "appropriate and necessary" because the costs far exceed the benefits. Nonetheless, the EPA proposed keeping the substantive requirements of the MATS rule. 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.
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 CPP, addressing GHG emissions from existing EGUs. On February 9, 2016, the U.S. Supreme Court stayed the CPP. In July 2019, EPA promulgated the ACE rule, which rescinds the CPP. The ACE

65


rule requires states with coal-fired EGUs to develop plans to seek heat rate improvements from coal-fired EGUs to reduce GHG emissions.
 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. In September 2017, the EPA agreed to reconsider the rule. On July 30, 2018, the EPA promulgated a rule that amends the existing ash rule by extending some of the deadlines and providing more flexibility for compliance. On August 21, 2018, the D.C. Circuit found, among other things, that the EPA had not adequately regulated unlined ponds and legacy ponds. Accordingly, we anticipate that the EPA will promulgate new regulations to address these issues (including compliance deadlines) as it reconsiders other aspects of the existing rule. The EPA has stated that it intends to further revise the rule. The Company will provide estimates of the cost of compliance after the rule is revised.
Domestic Site Remediation Matters
Under certain federal, state and local environmental laws, a current or previous owner or operator of a facility, including an electric generating facility, may be required to investigate and remediate releases or threatened releases of hazardous or toxic substances or petroleum products. NRG may be responsible for property damage, personal injury and investigation and remediation costs incurred by a party in connection with hazardous material releases or threatened releases. These laws impose liability without regard to whether the owner knew of or caused the presence of the hazardous substances, and the courts have interpreted liability under such laws to be strict (without fault) and joint and several. Cleanup obligations can often be triggered during the closure or decommissioning of a facility, in addition to spills during its operations. Further discussions of affected NRG sites can be found in Note 19, Environmental Matters, to the Consolidated Financial Statements.
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 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 was reviewed and 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 in 1985, 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. Texas is currently in a compact with the state of Vermont, and the compact low-level waste facility located in Andrews County in Texas has been operational since 2012.
Water 
The Company is required under the CWA to comply with intake and discharge requirements, requirements for technological controls and operating practices. As with air quality regulations, federal and state water regulations have become more stringent and imposed new requirements.
Once Through Cooling Regulation — In August 2014, EPA finalized the regulation regarding the use of water for once through cooling at existing facilities to address impingement and entrainment concerns. While 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, the Company anticipates the cost of complying with these restrictions to be immaterial.

66


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, fly ash, bottom ash, and flue gas mercury control. On September 18, 2017, the EPA promulgated a final rule that, among other things, 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. On April 12, 2019, the United States Court of Appeals for the Fifth circuit addressed challenges to the rule brought by several environmental groups related to legacy wastewaters and coal ash leachate and remanded portions of the rule to the EPA. The Company has 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 EPA revises the rule.
Regional Environmental Developments
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. In December 2015, DNREC approved the Company's remediation design, the Company's Closure Report and the Company's Long Term Stewardship Plan. The cost of completing the work required by the approved remediation plan is consistent with amounts budgeted in early 2016 and remediation was completed in 2017. The estimated cost to comply with the Long-Term Stewardship Plan was added to the liability in 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.
NY NOx — In February 2019, NY DEC proposed a more stringent NOx regulation that depending on the outcome of the regulatory process, may result in the retirement of some of our combustion turbines in New York.
Ash Regulation in Illinois — On July 30, 2019, Illinois enacted legislation that will require the state to promulgate regulations regarding coal ash.

Significant Events
The following significant events have occurred during 2019, in addition to the Transformation Plan events, as further described within this Management's Discussion and Analysis and the Condensed Consolidated Financial Statements:
Renewable Power Purchase Agreements
During 2019, NRG began execution of its strategy to procure mid to long-term generation through power purchase agreements totaling approximately 1,300 MWs with third-party project developers and other counterparties. The tenor of these agreements is an average of ten years. The Company expects to continue evaluating and executing agreements, such as these, that support the mid to longer-term needs of its business.
Share Repurchases
During January and February, the Company completed $250 million of share repurchases in connection with the 2018 share repurchase program, at an average price of $40.61 per share. In February 2019, the Company's board of directors authorized an additional $1.0 billion share repurchase program. Through August 7, 2019, the Company completed share repurchases of $1.0 billion in connection with the 2019 share repurchase program, at an average price of $38.38 per share, of which $804 million was repurchased during the six months ended June 30, 2019. In August 2019, the Company announced that the board of directors authorized an additional $250 million of share repurchases to be executed in the second half of 2019.
Financing Activities
On May 14, 2019, NRG issued $733 million of aggregate principal amount at par of 5.25% senior unsecured notes due 2029. The proceeds from the issuance of the 2029 Senior Notes were utilized to redeem the remaining Company's 6.25% Senior Notes due 2024.
On May 28, 2019, NRG issued $1.1 billion of aggregate principal amount of senior secured first lien notes, consisting of $600 million 3.75% senior secured first lien notes due 2024 and $500 million 4.45% senior secured first lien notes due 2029, or the Senior Secured First Lien Notes, at a discount. The proceeds from the issuance of the Senior Secured First Lien Notes, as well as cash on hand, were used to repay the Company's $1.7 billion 2023 Term Loan facility, resulting in a decrease of $594 million to long-term debt outstanding.

67


On May 28, 2019, NRG amended its existing credit agreement to, among other things, provide for a $184 million increase in revolving commitments, resulting in aggregate revolving commitments under the amended credit agreement equal to $2.6 billion. See Note 10, Debt and Capital Leases, for further discussion.
As a result of the financing activities discussed above, interest savings are expected to be approximately $15 million in 2019 and annualized interest savings are expected to be approximately $25 million.
Pre-Summer Maintenance and Gregory Natural Gas Plant
The Company expanded pre-summer maintenance of the Texas fleet by increasing spending by $21 million, including the return of its 385 MW Gregory natural gas plant in Corpus Christi, Texas to service in June 2019.
Stream Energy Acquisition
On May 15, 2019, the Company entered into an agreement to acquire Stream Energy's retail electricity and natural gas business operating in 9 states and Washington, D.C. for $300 million in cash and estimated transaction costs and working capital adjustments of approximately $25 million. The acquisition increased NRG's retail portfolio by approximately 600,000 RCEs or 450,000 customers. The acquisition closed on August 1, 2019.
Trends Affecting Results of Operations and Future Business Performance
The Company’s trends are described in the Company’s 2018 Form 10-K in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations - Business Environment.

Changes in Accounting Standards
See Note 2, Summary of Significant Accounting Policies, for a discussion of recent accounting developments.


68


Consolidated Results of Operations
The following table provides selected financial information for the Company:
 
Three months ended June 30,

Six months ended June 30,
(In millions, except as otherwise noted)
2019

2018

Change

2019

2018

Change
Operating Revenues












Energy revenue (a)
$
249


$
410


$
(161
)

$
555


$
853


$
(298
)
Capacity revenue (a)
155


165


(10
)

309


307


2

Retail revenue
1,745


1,813


(68
)

3,351


3,298


53

Mark-to-market for economic hedging activities
241


10


231


261


(86
)

347

Other revenues (b)
75


63


12


154


154



Total operating revenues
2,465


2,461


4


4,630


4,526


104

Operating Costs and Expenses











Cost of Sales (c)
1,273


1,453


180


2,614


2,775


161

Mark-to-market for economic hedging activities
220


86


(134
)

220


(216
)

(436
)
Contract and emissions credit amortization (c)
6


7


1


11


13


2

Operations and maintenance
284


282


(2
)

531


573


42

Other cost of operations
62


61


(1
)

120


129


9

Total cost of operations
1,845

 
1,889

 
44

 
3,496

 
3,274

 
(222
)
Depreciation and amortization
85

 
112

 
27

 
170

 
232

 
62

Impairment losses
1

 
74

 
73

 
1

 
74

 
73

Selling, general and administrative
211

 
200

 
(11
)
 
405

 
376

 
(29
)
Reorganization costs
2

 
23

 
21

 
15

 
43

 
28

Development costs
2

 
3

 
1

 
4

 
8

 
4

Total operating costs and expenses
2,146

 
2,301

 
155

 
4,091


4,007

 
(84
)
Gain on sale of assets
1

 
14

 
(13
)
 
2

 
16

 
(14
)
Operating Income
320

 
174

 
146

 
541

 
535

 
6

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

 
5

 
(5
)
 
(21
)
 
6

 
(27
)
Other income/(expense), net
20

 
(23
)
 
43

 
32

 
(23
)
 
55

Loss on debt extinguishment, net
(47
)
 
(1
)
 
(46
)
 
(47
)
 
(3
)
 
(44
)
Interest expense
(105
)
 
(123
)
 
18

 
(219
)
 
(239
)
 
20

Total other expense
(132
)
 
(142
)
 
10

 
(255
)
 
(259
)
 
4

Income from Continuing Operations Before Income Taxes
188

 
32

 
156

 
286

 
276

 
10

Income tax (benefit)/expense
(1
)
 
5

 
6

 
3

 
11

 
8

Income from Continuing Operations
189

 
27

 
162

 
283

 
265

 
18

Income from discontinued operations, net of income tax
13

 
69

 
(56
)
 
401

 
64

 
337

Net Income
202

 
96

 
106

 
684

 
329

 
355

Less: Net income/(loss) attributable to noncontrolling interest and redeemable interests
1

 
24

 
(23
)
 
1

 
(22
)
 
23

Net Income Attributable to NRG Energy, Inc.
$
201

 
$
72

 
$
129

 
$
683

 
$
351

 
$
332

Business Metrics
 
 
 
 


 
 
 
 
 
 
Average natural gas price — Henry Hub ($/MMBtu)
$
2.64

 
$
2.80

 
(6
)%
 
$
2.89

 
$
2.90

 
 %
(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     

69


Management’s discussion of the results of operations for the three months ended June 30, 2019 and 2018
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 June 30, 2019 and 2018. The average on-peak power prices were lower primarily driven by mild weather.
 
Average on Peak Power Price ($/MWh)
 
Three months ended June 30,
Region
2019
 
2018
 
Change %
Texas
 
 
 
 
 
ERCOT - Houston(a)
$
31.88

 
$
34.82

 
(8
)%
ERCOT - North(a)
30.13

 
34.89

 
(14
)%
MISO - Louisiana Hub(b)
33.40

 
44.20

 
(24
)%
East/West
 
 
 
 
 
    NY J/NYC(b)
29.52

 
36.41

 
(19
)%
    NEPOOL(b)
27.15

 
36.28

 
(25
)%
    COMED (PJM)(b)
26.78

 
31.88

 
(16
)%
    PJM West Hub(b)
28.54

 
39.73

 
(28
)%
CAISO - SP15(b)
23.30

 
27.75

 
(16
)%
(a) Average on peak power prices based on real time settlement prices as published by the respective ISOs
(b) 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, including the impact of settled hedges, for the three months ended June 30, 2019 and 2018:
 
Average Realized Power Price ($/MWh)
 
Three months ended June 30,
Region
2019
 
2018
 
Change %
Texas
$
43.59

 
$
36.96

 
18
 %
East/West/Other (a)(b)
34.60

 
43.39

 
(20
)%
(a) Does not include BETM energy revenue of $16 million for 2018, which was sold in July 2018
(b) Does not include Ivanpah or Agua Caliente energy revenue of $47 million, as they were deconsolidated in April 2018 and August 2018, respectively

The average realized power prices fluctuated at different rates for the three months ended June 30, 2019 as compared to the same period in 2018 due to two factors:
The Company's multi-year hedging program
During the year, the Company transfers power between the Retail and Generation segments based on market prices. Within Texas, the Retail and Generation segments transact a large internal transfer of power based on average annualized market prices that can result in significant fluctuations on a quarterly basis, but annually have a mark-to-market of $0 at the time of execution. The impact of this internal transfer is more prominent in 2019 due to the increased forward power prices in summer 2019.

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.

70


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.
The below tables present the composition and reconciliation of gross margin and economic gross margin for the three months ended June 30, 2019 and 2018:

Three months ended June 30, 2019



Generation




($ In millions)
Retail

Texas

East/West/Other(a)

Subtotal

Corporate/Eliminations

Total
Energy revenue
$


$
497


$
117


$
614


$
(365
)

$
249

Capacity revenue




154


154


1


155

Retail revenue
1,746








(1
)

1,745

Mark-to-market for economic hedging activities
2


460


64


524


(285
)

241

Other revenue


16


59


75




75

Operating revenue
1,748


973


394


1,367


(650
)

2,465

Cost of fuel
(12
)

(203
)

(65
)

(268
)

1


(279
)
Other cost of sales(b)
(1,276
)

(23
)

(59
)

(82
)

364


(994
)
Mark-to-market for economic hedging activities
(486
)

(16
)

(3
)

(19
)

285


(220
)
Contract and emission credit amortization


(6
)



(6
)



(6
)
Gross margin
$
(26
)

$
725


$
267


$
992


$


$
966

Less: Mark-to-market for economic hedging activities, net
(484
)

444


61


505




21

Less: Contract and emission credit amortization, net


(6
)



(6
)



(6
)
Economic gross margin
$
458


$
287


$
206


$
493


$


$
951

Business Metrics







 

 

MWh sold (thousands)



11,401


3,410










MWh generated (thousands)



10,645


2,535










(a) Includes International, Renewables, and Generation eliminations
(b) Includes purchased energy, capacity and emissions credits

Three months ended June 30, 2018



Generation




($ In millions)
Retail

Texas

East/West/Other(a)(b)

Subtotal

Corporate/Eliminations

Total
Energy revenue
$


$
402


$
259


$
661


$
(251
)

$
410

Capacity revenue




165


165




165

Retail revenue
1,814








(1
)

1,813

Mark-to-market for economic hedging activities


296


(22
)

274


(264
)

10

Other revenue


10


57


67


(4
)

63

Operating revenue
1,814


708


459


1,167


(520
)

2,461

Cost of fuel
(3
)

(188
)

(115
)

(303
)



(306
)
Other cost of sales(c)
(1,315
)

(35
)

(50
)

(85
)

254


(1,146
)
Mark-to-market for economic hedging activities
(346
)

(3
)

(1
)

(4
)

264


(86
)
Contract and emission credit amortization


(7
)



(7
)



(7
)
Gross margin
$
150


$
475


$
293


$
768


$
(2
)

$
916

Less: Mark-to-market for economic hedging activities, net
(346
)

293


(23
)

270




(76
)
Less: Contract and emission credit amortization, net


(7
)



(7
)



(7
)
Economic gross margin
$
496


$
189


$
316


$
505


$
(2
)

$
999

Business Metrics
 
 
 
 
 
 
 
 
 
 
 
MWh sold (thousands)
 
 
10,876

 
5,969

 
 
 
 
 
 
MWh generated (thousands)
 
 
9,848

 
5,255

 
 
 
 
 
 
(a) Includes International, Renewables, and Generation eliminations
(b) Includes BETM which was sold as of July 31, 2018
(c) Includes purchased energy, capacity and emissions credits

71




The table below represents the weather metrics for the three months ended June 30, 2019 and 2018:
 
Three months ended June 30,
Weather Metrics
Texas
 
East/West/Other(b)
2019
 
 
 
CDDs (a)
934

 
458

HDDs (a)
70

 
283

2018
 
 
 
CDDs
1,101

 
521

HDDs
91

 
325

10-year average
 
 
 
CDDs
1,009

 
487

HDDs
60

 
310

(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
(b) The East/West/Other weather metrics are comprised of the average of the CDD and HDD regional results for the Northeast, West - California and West - South Central regions

72


Retail Gross Margin and Economic Gross Margin
The following is a discussion of gross margin and economic gross margin for Retail.
 
Three months ended June 30,
(In millions, except as otherwise noted)
2019
 
2018
Retail revenue
$
1,650

 
$
1,687

Supply management revenue
50

 
42

Capacity revenue
46

 
85

Customer mark-to-market
2

 

Operating revenue(a)
1,748

 
1,814

Cost of sales(b)
(1,288
)
 
(1,318
)
Mark-to-market for economic hedging activities
(486
)
 
(346
)
Gross Margin
$
(26
)
 
$
150

Less: Mark-to-market for economic hedging activities, net
(484
)
 
(346
)
Economic Gross Margin
$
458

 
$
496

 
 
 
 
Business Metrics
 
 
 
Mass electricity sales volume — GWh - Texas
9,130

 
9,793

Mass electricity sales volume — GWh - All other regions
1,913

 
1,600

C&I electricity sales volume — GWh - All regions
5,008

 
5,403

Natural gas sales volumes (MDth)
3,054

 
1,244

Average Retail Mass customer count (in thousands) 
3,306

 
2,966

Ending Retail Mass customer count (in thousands)
3,277

 
3,149

(a)
Includes intercompany sales of $2 million and $4 million in 2019 and 2018, respectively, representing sales from Retail to the Texas region
(b)
Includes intercompany purchases of $374 million and $251 million in 2019 and 2018, respectively, inclusive of the internal transfer of large average annualized market price transactions

Retail gross margin decreased $176 million and economic gross margin decreased $38 million for the three months ended June 30, 2019, compared to the same period in 2018, due to:
 
 
(In millions)
Lower gross margin from Business Solutions primarily due to a reduction in the volume of an early settlement of capacity obligations in 2019 as compared to 2018
 
$
(28
)
Lower gross margin due to the unfavorable impact from weather that resulted in a decrease in load of 750,000 MWh in 2019 as compared to 2018
 
(28
)
Higher gross margin primarily driven by higher volumes from XOOM and other customer acquisitions
 
10

Higher gross margin from Mass due to increased revenues of approximately $5.75 per MWh or $62 million primarily driven by margin enhancement initiatives, partially offset by higher supply costs driven by an increase in power prices of approximately $5.00 per MWh or $54 million
 
8

Business Solutions gross margin remained unchanged as lower revenues were offset by lower costs. Lower revenues were driven by lower rates to customers of approximately $5.25 per MWh or $27 million, offset by lower supply costs driven by a decrease in power prices at the time of procurement of approximately $5.25 per MWh or $27 million
 

Decrease in economic gross margin
 
$
(38
)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges
 
(138
)
Decrease in gross margin
 
$
(176
)


73


Generation Gross Margin and Economic Gross Margin
Generation gross margin increased $224 million and economic gross margin decreased $12 million, both of which include intercompany sales, during the three months ended June 30, 2019, compared to the same period in 2018.

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

Texas Region
 
(In millions)
Higher gross margin due to a 18% increase in average realized prices primarily due to the intersegment transactions at annual average power prices
$
58

Higher gross margin driven by planned outages at STP, Cedar Bayou and forced outages at T.H. Wharton and Greens Bayou in 2018
26

Higher gross margin from commercial optimization activities
7

Higher gross margin due to margin enhancement initiatives from reduced fuel supply costs
7

Increase in economic gross margin
$
98

Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges
151

Increase in contract and emission credit amortization
1

Increase in gross margin
$
250


East/West/Other
 
(In millions)
Lower gross margin due to the deconsolidations of Ivanpah in April 2018 and Agua Caliente in August 2018
$
(43
)
Lower gross margin primarily due to the sale of BETM, Keystone and Conemaugh in the third quarter of 2018, Guam in the first quarter of 2019 and the retirement of Encina in December 2018
(41
)
Lower gross margin due to insurance proceeds from outages in 2018
(14
)
Lower gross margin due to a 22% decrease in realized capacity pricing in New York
(10
)
Lower gross margin due to an extended forced outage at the Sunrise facility in 2019
(7
)
Lower gross margin due to a 11% decrease in average realized prices at Cottonwood
(7
)
Lower gross margin driven by a decrease in economic generation volume due to planned outages in 2019
(6
)
Higher gross margin due to a 20% increase in PJM capacity prices and a 10% increase in ISO-NE capacity prices
16

Higher gross margin from commercial optimization activities
6

Other
(4
)
Decrease in economic gross margin
$
(110
)
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges
84

Decrease in gross margin
$
(26
)


74


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. Total net mark-to-market results increased by $97 million during the three months ended June 30, 2019, compared to the same period in 2018.
The breakdown of gains and losses included in operating revenues and operating costs and expenses by region was as follows:
 
Three months ended June 30, 2019
 
 
 
Generation
 
 
 
 
 
Retail
 
Texas
 
East/West/Other
 
Eliminations(a)
 
Total
 
(In millions)
Mark-to-market results in operating revenues
 
 
 
 
 
 
 
 
 
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges
$
(1
)
 
$
(74
)
 
$
16

 
$
59

 
$

Net unrealized gains on open positions related to economic hedges
3

 
534

 
48

 
(344
)
 
241

Total mark-to-market gains in operating revenues
$
2

 
$
460

 
$
64

 
$
(285
)
 
$
241

Mark-to-market results in operating costs and expenses
 
 
 
 
 
 
 
 
 
Reversal of previously recognized unrealized losses on settled positions related to economic hedges
$
69

 
$
1

 
$

 
$
(59
)
 
$
11

Reversal of acquired loss positions related to economic hedges
1

 

 

 

 
1

Net unrealized (losses) on open positions related to economic hedges
(556
)
 
(17
)
 
(3
)
 
344

 
(232
)
Total mark-to-market (losses) in operating costs and expenses
$
(486
)
 
$
(16
)
 
$
(3
)
 
$
285

 
$
(220
)
(a)
Represents the elimination of the intercompany activity between Retail and Generation
 
Three months ended June 30, 2018
 
 
 
Generation
 
 
 
 
 
Retail
 
Texas
 
East/West/Other
 
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
$

 
$
(53
)
 
$
(6
)
 
$
28

 
$
(31
)
Net unrealized gains/(losses) on open positions related to economic hedges

 
349

 
(16
)
 
(292
)
 
41

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

 
$
296

 
$
(22
)
 
$
(264
)
 
$
10

Mark-to-market results in operating costs and expenses
 
 
 
 
 
 
 
 
 
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges
$
62

 
$
(1
)
 
$
(4
)
 
$
(28
)
 
$
29

Reversal of acquired gain positions related to economic hedges
(1
)
 

 

 

 
(1
)
Net unrealized (losses)/gains on open positions related to economic hedges
(407
)
 
(2
)
 
3

 
292

 
(114
)
Total mark-to-market (losses) in operating costs and expenses
$
(346
)
 
$
(3
)
 
$
(1
)
 
$
264

 
$
(86
)
(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.
For the three months ended June 30, 2019, the $241 million gain in operating revenues from economic hedge positions was driven primarily by an increase in the value of open positions as a result of decreases in natural gas prices, ERCOT heat rate contraction, and decreases in ERCOT electricity prices. The $220 million loss in operating costs and expenses from economic hedge positions was driven primarily by a decrease in the value of open positions as a result of decreases in natural gas prices, ERCOT heat rate contraction, and decreases in ERCOT electricity prices, partially offset by the reversal of previously recognized unrealized losses on contracts that settled during the period.

75


For the three months ended June 30, 2018, the $10 million gain in operating revenues from economic hedge positions was driven primarily by an increase in the value of open positions as a result of ERCOT heat rate contraction and decreases in ERCOT electricity prices, partially offset by the reversal of previously recognized unrealized gains on contracts that settled during the period. The $86 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 ERCOT heat rate contraction and decreases in 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 June 30, 2019 and 2018. 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 based on the Company's Risk Management Policy.
 
Three months ended June 30,
(In millions)
2019
 
2018
Trading gains
 
 
 
Realized
$
15

 
$
25

Unrealized
12

 
5

Total trading gains
$
27

 
$
30


Operations and Maintenance Expense

Operations and maintenance expense are comprised of the following:



Generation

Corporate

Eliminations



Retail

Texas

East/West/Other



Total

(In millions)
Three months ended June 30, 2019
$
56


$
114


$
113


$
2


$
(1
)

$
284

Three months ended June 30, 2018
$
49


$
123


$
112


$


$
(2
)

$
282

(a) Includes International, Renewables, and Generation eliminations

Operations and maintenance expenses increased by $2 million for the three months ended June 30, 2019, compared to the same period in 2018, due to the following:
 
(In millions)
Increase as a result of timing of the realization of Transformation Plan savings
$
20

Increase in investments in Texas plants in preparation for summer operations
14

Increase primarily related to the lease of Cottonwood from February 4, 2019
10

Increase due to the XOOM acquisition in June 2018
3

Decrease due to the timing of outages in 2019
(23
)
Decrease due to 2018 payments in settlement of certain legal matters
(10
)
Decrease due to the deconsolidations of Ivanpah and Agua Caliente in 2018
(6
)
Other
(6
)
    Increase in operations and maintenance expense
$
2

 
Other Cost of Operations

Other cost of operations are comprised of the following:



Generation


Retail

Texas

East/West/Other

Total

(In millions)
Three months ended June 30, 2019
$
27


$
16


$
19


$
62

Three months ended June 30, 2018
$
26


$
15


$
20


$
61


76



Depreciation and Amortization
Depreciation and amortization decreased by $27 million for the three months ended June 30, 2019, compared to the three months ended June 30, 2018, driven primarily by the deconsolidations of Ivanpah in April 2018 and Agua Caliente in August 2018, the sale of Cottonwood in February 2019 and prior year impairments.
Selling, General and Administrative
Selling, general and administrative expenses are comprised of the following:

Retail

Generation

Corporate

Total

(In millions)
Three months ended June 30, 2019
$
135


$
71


$
5


$
211

Three months ended June 30, 2018
125


58


17


200

Selling, general and administrative expenses increased by $11 million for the three months ended June 30, 2019, compared to the same period in 2018, due to the following:
 
(In millions)
Increase in selling and marketing expenses associated with costs incurred for margin enhancement initiatives
$
19

Increase in bad debt expense primarily due to higher customer attrition
12

Increase in selling expense due to the acquisition of XOOM in June 2018
3

Decrease due to additional litigation in 2018
(10
)
Decrease in general and administrative expense from cost initiatives as a result of the Transformation Plan
(9
)
Decrease related to fees incurred in the acquisition of businesses
(3
)
Other
(1
)
    Increase in selling, general and administrative expenses
$
11

Reorganization Costs
Reorganization costs, primarily related to employee severance and contract cancellation costs, decreased by $21 million for the three months ended June 30, 2019 compared to the same period in 2018, driven primarily by significant achievement of the operations and cost excellence portion of the Transformation Plan during 2018.
Gain on Sale of Assets
Gain on sale of assets for the three months ended June 30, 2018 consisted primarily of gains on the sales of Canal 3 and a piece of land, while the gain on the sale of assets for the three months ended June 30, 2019 consisted primarily of a gain on the sale of land.
Loss on Debt Extinguishment
A loss on debt extinguishment of $47 million was recorded during the three months ended June 30, 2019, driven by the redemption of the 2024 Senior Notes and the repayment of the 2023 Term Loan Facility.

77


Interest Expense
Interest expense decreased by $18 million for the three months ended June 30, 2019, compared to the same period in 2018, due to the following:
 
(In millions)
Increase in derivative interest expense due to the termination of interest rate swaps
$
32

Decrease related to the termination of in-the-money interest rate swaps
(25
)
Decrease related to the debt reduction of $1.2 billion and refinancing $2.4 billion of debt at lower interest rates in 2019 and 2018
(21
)
Decrease related to the deconsolidations of Ivanpah and Agua Caliente in 2018
(9
)
Other
5

     Decrease in interest expense
$
(18
)
Income Tax (Benefit)/Expense
For the three months ended June 30, 2019, an income tax benefit of $1 million was recorded on pre-tax income of $188 million. For the same period in 2018, income tax expense of $5 million was recorded on pre-tax income of $32 million. The effective tax rate was (0.5)% and 15.6% for the three months ended June 30, 2019 and 2018, respectively.
For the three months ended June 30, 2019 and 2018, NRG's overall effective tax rates were lower than the statutory rate of 21%, primarily due to the tax benefit for the change in valuation allowance, partially offset by current state tax expense.
Income from Discontinued Operations, Net of Income Tax
 
 
Three Months Ended June 30,
(In millions)
 
2019
 
2018
 
Change
South Central Portfolio
 
1

 
16

 
$
(15
)
Yield Renewables Platform & Carlsbad
 
10

 
78

 
(68
)
Genon
 
2

 
(25
)
 
27

Income from discontinued operations, net of tax
 
$
13

 
$
69

 
$
(56
)
For the three months ended June 30, 2019, NRG recorded income from discontinued operations, net of income tax of $13 million, a decrease of $56 million from income of $69 million in the same period in 2018, as further described in Note 4, Acquisitions, Discontinued Operations and Dispositions.
Net Income Attributable to Noncontrolling Interests and Redeemable Noncontrolling Interests
Net income attributable to noncontrolling interests and redeemable noncontrolling interests was $1 million for the three months ended June 30, 2019, compared to $24 million for three months ended June 30, 2018. For the three months ended June 30, 2018, NRG Yield, Inc.'s share of net income was partially offset by the net losses allocated to tax equity investors in tax equity arrangements using the hypothetical liquidation at book value, or HLBV, method and Ivanpah's share of net losses. As a result of the disposition of NRG Yield Inc. and its Renewables Platform, as well as the deconsolidation of Ivanpah, the Company does not anticipate material NCI in the future.





78


Management’s discussion of the results of operations for the six months ended June 30, 2019 and 2018
Electricity Prices
The following table summarizes average on peak power prices for each of the major markets in which NRG operates for the six months ended June 30, 2019 and 2018. The average on-peak power prices have generally decreased primarily due to lower winter demand and heat rate contraction.
 
Average on Peak Power Price ($/MWh)
 
Six months ended June 30,
Region
2019
 
2018
 
Change %
Texas
 
 
 
 
 
ERCOT - Houston (a)
$
30.04

 
$
33.98

 
(12
)%
ERCOT - North(a)
29.08

 
33.28

 
(13
)%
MISO - Louisiana Hub(b)
33.12

 
45.22

 
(27
)%
East/West
 
 
 
 
 
    NY J/NYC(b)
37.34

 
49.19

 
(24
)%
    NEPOOL(b)
37.28

 
51.07

 
(27
)%
    COMED (PJM)(b)
28.44

 
32.54

 
(13
)%
    PJM West Hub(b)
31.17

 
43.58

 
(28
)%
CAISO - SP15(b)
36.86

 
31.60

 
17
 %
(a) Average on peak power prices based on real time settlement prices as published by the respective ISOs
(b) 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, including the impact of settled hedges, for the six months ended June 30, 2019 and 2018:
 
Average Realized Power Price ($/MWh)
 
Six months ended June 30,
Region
2019
 
2018
 
Change %
Texas
$
42.06

 
$
34.44

 
22
 %
East/West/Other (a) (b)
36.45

 
47.43

 
(23
)%
(a) Does not include BETM energy revenue of $32 million for 2018, respectively
(b) Does not include Ivanpah or Agua Caliente energy revenue of $94 million, as they were deconsolidated in April 2018 and August 2018, respectively

The average realized power prices fluctuated at different rates for the six months ended June 30, 2019 as compared to the same period in 2018 due to two factors:
The Company's multi-year hedging program
During the year, the Company transfers power between the Retail and Generation segments based on market prices. Within Texas, the Retail and Generation segments transact a large internal transfer of power based on average annualized market prices that can result in significant fluctuations on a quarterly basis, but annually have a mark-to-market of $0 at the time of execution. The impact of this internal transfer is more prominent in 2019 due to the increased forward power prices in summer 2019.

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.

79


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.
The below tables present the composition and reconciliation of gross margin and economic gross margin for the six months ended June 30, 2019 and 2018:

Six months ended June 30, 2019



Generation




($ In millions)
Retail

Texas

East/West/Other(a)

Subtotal

Corporate/Eliminations

Total
Energy revenue
$


$
855


$
341


$
1,196


$
(641
)

$
555

Capacity revenue




309


309




309

Retail revenue
3,353








(2
)

3,351

Mark-to-market for economic hedging activities
2


473


56


529


(270
)

261

Other revenue


45


111


156


(2
)

154

Operating revenue
3,355


1,373


817


2,190


(915
)

4,630

Cost of fuel
(51
)

(352
)

(165
)

(517
)

3


(565
)
Other cost of sales (b)
(2,472
)

(69
)

(148
)

(217
)

640


(2,049
)
Mark-to-market for economic hedging activities
(494
)

2


2


4


270


(220
)
Contract and emission credit amortization


(11
)



(11
)



(11
)
Gross margin
$
338


$
943


$
506


$
1,449


$
(2
)

$
1,785

Less: Mark-to-market for economic hedging activities, net
(492
)

475


58


533




41

Less: Contract and emission credit amortization, net


(11
)



(11
)



(11
)
Economic gross margin
$
830


$
479


$
448


$
927


$
(2
)

$
1,755

Business Metrics
 
 
 
 
 
 
 
 
 
 
 
MWh sold (thousands)
 
 
20,329

 
9,354

 
 
 
 
 
 
MWh generated (thousands) 
 
 
18,279

 
6,957

 
 
 
 
 
 
(a) Includes International, Renewables, and Generation eliminations
(b) Includes purchased energy, capacity and emissions credits

Six months ended June 30, 2018



Generation




($ In millions)
Retail

Texas

East/West/Other(a)(b)

Subtotal

Corporate/Eliminations

Total
Energy revenue
$


$
666


$
598


$
1,264


$
(411
)

$
853

Capacity revenue




308


308


(1
)

307

Retail revenue
3,300








(2
)

3,298

Mark-to-market for economic hedging activities
(6
)

(273
)

(27
)

(300
)

220


(86
)
Other revenue


64


102


166


(12
)

154

Operating revenue
3,294


457


981


1,438


(206
)

4,526

Cost of fuel
(11
)

(311
)

(239
)

(550
)

(2
)

(563
)
Other cost of sales (b)
(2,417
)

(62
)

(154
)

(216
)

421


(2,212
)
Mark-to-market for economic hedging activities
446


(5
)

(5
)

(10
)

(220
)

216

Contract and emission credit amortization


(12
)

(1
)

(13
)



(13
)
Gross margin
$
1,312


$
67


$
582


$
649


$
(7
)

$
1,954

Less: Mark-to-market for economic hedging activities, net
440


(278
)

(32
)

(310
)



130

Less: Contract and emission credit amortization, net


(12
)

(1
)

(13
)



(13
)
Economic gross margin
$
872


$
357


$
615


$
972


$
(7
)

$
1,837

Business Metrics
 
 
 
 
 
 
 
 
 
 
 
MWh sold (thousands)
 
 
19,340

 
12,607

 
 
 
 
 
 
MWh generated (thousands) 
 
 
17,304

 
9,957

 
 
 
 
 
 
(a) Includes International, Renewables, and Generation eliminations
(b) Includes BETM, which was sold as of July 31, 2018
(c) Includes purchased energy, capacity and emissions credits

80


The table below represents the weather metrics for the six months ended June 30, 2019 and 2018:
 
Six months ended June 30,
Weather Metrics
Texas
 
East/West/Other (b)
2019
 
 
 
CDDs (a)
1,008

 
490

HDDs (a)
1,111

 
1,897

2018
 
 
 
CDDs
1,246

 
573

HDDs
1,059

 
1,844

10-year average
 
 
 
CDDs
1,115

 
529

HDDs
1,031

 
1,850

(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
(b) The East/West/Other weather metrics are comprised of the average of the CDD and HDD regional results for the Northeast, West-California and West- South Central regions

81


Retail Gross Margin and Economic Gross Margin
The following is a discussion of gross margin and economic gross margin for Retail.
 
Six months ended June 30,
(In millions, except as otherwise noted)
2019
 
2018
Retail revenue
$
3,220

 
$
3,132

Supply management revenue
84

 
75

Capacity revenue
49

 
93

Customer mark-to-market
2

 
(6
)
Operating revenue (a)
3,355

 
3,294

Cost of sales (b)
(2,523
)
 
(2,428
)
Mark-to-market for economic hedging activities
(494
)
 
446

Gross Margin
$
338

 
$
1,312

Less: Mark-to-market for economic hedging activities, net
(492
)
 
440

Economic Gross Margin
$
830

 
$
872

 
 
 
 
Business Metrics
 
 
 
Mass electricity sales volume — GWh - Texas
17,119

 
17,736

Mass electricity sales volume — GWh - All other regions
4,407

 
3,319

C&I electricity sales volume — GWh - All regions
9,839

 
10,430

Natural gas sales volumes (MDth)
13,601

 
3,419

Average Retail Mass customer count (in thousands) 
3,317

 
2,922

Ending Retail Mass customer count (in thousands)
3,277

 
3,149

(a)
Includes intercompany sales of $5 million and $6 million in 2019 and 2018, respectively, representing sales from Retail to the Texas region
(b)
Includes intercompany purchases of $676 million and $415 million in 2019 and 2018, respectively, inclusive of the internal transfer of large average annualized market price transactions
Retail gross margin decreased $974 million and economic gross margin decreased $42 million for the six months ended June 30, 2019, compared to the same period in 2018, due to:
 
 
(In millions)
Lower gross margin due to the unfavorable impact from weather that resulted in a decrease in load of 900,000 MWh in 2019 as compared to 2018
 
$
(36
)
Lower gross margin from Business Solutions primarily due to a reduction in the volume of an early settlement of capacity obligations in 2019 as compared to 2018
 
(28
)
Lower gross margin from Mass due to higher supply costs driven by an increase in power prices of approximately $12.25 per MWh or $134 million, partially offset by higher revenue of approximately $10.25 per MWh or $111 million primarily driven by margin enhancement initiatives
 
(23
)
Lower gross margin from Business Solutions due to lower revenue driven by lower rates to customers of approximately $6.25 per MWh or $61 million, partially offset by lower supply costs driven by a decrease in power prices at the time of procurement of approximately $3.50 per MWh or $36 million and lower volumes due to customer usage and mix of $24 million
 
(1
)
Higher gross margin primarily driven by higher volumes from XOOM and other customer acquisitions
 
46

Decrease in economic gross margin
 
$
(42
)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges
 
(932
)
Decrease in gross margin
 
$
(974
)


82


Generation Gross Margin and Economic Gross Margin
Generation gross margin increased $800 million and economic gross margin decreased $45 million, both of which include intercompany sales, during the six months ended June 30, 2019, compared to the same period in 2018.
The tables below describe the increase in Generation gross margin and the decrease in economic gross margin:
Texas Region
 
(In millions)
Higher gross margin due to a 22% increase in weighted average realized prices, due primarily to the inter-segment transactions at annual average power prices
$
89

Higher gross margin driven by planned outage at STP, Cedar Bayou and a forced outage at T.H.Wharton in 2018
39

Higher gross margin due to commercial optimization activities
10

Higher gross margin due to margin enhancement initiatives from reduced fuel supply costs
10

Decreased gross margin from lower sales of NOx emission credits
(22
)
Other
(4
)
Increase in economic gross margin
$
122

Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges
753

Increase in contract and emission credit amortization
1

Increase in gross margin
$
876

East/West/Other
 
(In millions)
Lower gross margin due to Ivanpah and Agua deconsolidations in April 2018 and August 2019, respectively
$
(87
)
Lower gross margin due to the sale of BETM, Keystone and Conemaugh in the third quarter of 2018, Guam in the first quarter of 2019 and the retirement of Encina in December
(75
)
Lower gross margin due to decrease in economic generation volumes, primarily due to dark spread and spark spread contractions in the northeast and planned outages in 2019
(30
)
Lower gross margin driven by a 27% decrease in realized capacity pricing in New York
(18
)
Lower gross margin due to insurance proceeds from outages in 2018
(14
)
Lower gross margin due to an extended forced outage at the Sunrise facility in 2019
(12
)
Higher gross margin due to a 29% increase in PJM capacity prices and a 13% increase in ISO-NE capacity prices
46

Higher gross margin due to a 14% increase in weighted average realized prices, primarily at Midwest Generation
19

Higher gross margin from commercial optimization activities
4

Decrease in economic gross margin
$
(167
)
Increase to mark-to-market for economic hedges primarily due to net unrealized gains/losses on open positions related to economic hedges
90

Increase in contract and emission credit amortization
1

Decrease in gross margin
$
(76
)


83


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. Total net mark-to-market results decreased by $89 million during the six months ended June 30, 2019, compared to the same period in 2018.
The breakdown of gains and losses included in operating revenues and operating costs and expenses by region was as follows:
 
Six months ended June 30, 2019
 
 
 
Generation
 
 
 
 
 
Retail
 
Texas
 
East/West/Other
 
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
$
(1
)
 
$
(153
)
 
$
(6
)
 
$
152

 
$
(8
)
Net unrealized gains on open positions related to economic hedges
3

 
626

 
62

 
(422
)
 
269

Total mark-to-market gains in operating revenues
$
2

 
$
473

 
$
56

 
$
(270
)
 
$
261

Mark-to-market results in operating costs and expenses
 
 
 
 
 
 
 
 
 
Reversal of previously recognized unrealized losses on settled positions related to economic hedges
$
184

 
$
4

 
$
2

 
$
(152
)
 
$
38

Reversal of acquired gain positions related to economic hedges
(1
)
 

 

 

 
(1
)
Net unrealized (losses) on open positions related to economic hedges
(677
)
 
(2
)
 

 
422

 
(257
)
Total mark-to-market (losses)/gains in operating costs and expenses
$
(494
)
 
$
2

 
$
2

 
$
270

 
$
(220
)
(a)
Represents the elimination of the intercompany activity between Retail and Generation
 
Six months ended June 30, 2018
 
 
 
Generation
 
 
 
 
 
Retail
 
Texas
 
East/West/Other
 
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
$
(1
)
 
$
(88
)
 
$
(6
)
 
$
31

 
$
(64
)
Net unrealized (losses) on open positions related to economic hedges
(5
)
 
(185
)
 
(21
)
 
189

 
(22
)
Total mark-to-market (losses) in operating revenues
$
(6
)
 
$
(273
)

$
(27
)

$
220


$
(86
)
Mark-to-market results in operating costs and expenses
 
 
 
 
 
 
 
 
 
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges
$
104

 
$
(2
)
 
$
(8
)
 
$
(31
)
 
$
63

Reversal of acquired gain positions related to economic hedges
(1
)
 

 

 

 
(1
)
Net unrealized gains/(losses) on open positions related to economic hedges
343

 
(3
)
 
3

 
(189
)
 
154

Total mark-to-market gains/(losses) in operating costs and expenses
$
446

 
$
(5
)

$
(5
)

$
(220
)

$
216

(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.
For the six months ended June 30, 2019, the $261 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 natural gas prices, ERCOT heat rate contraction, and decreases in ERCOT electricity prices, partially offset by the reversal of previously recognized unrealized gains on contracts that settled during the period. The $220 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 prices, ERCOT heat rate contraction, and decreases in ERCOT electricity prices, partially offset by the reversal of previously recognized unrealized losses on contracts that settled during the period.

84


For the six months ended June 30, 2018, the $86 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, as well as a decrease in the value of open positions as a result of ERCOT heat rate expansion and increases in ERCOT electricity prices. The $216 million gain in operating costs and expenses from economic hedge positions was driven primarily by the increase in value of open positions as a result of ERCOT heat rate expansion and increases in ERCOT electricity prices, as well as 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 six months ended June 30, 2019 and 2018. 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 based on the Company's Risk Management Policy.
 
Six months ended June 30,
(In millions)
2019
 
2018
Trading gains
 
 
 
Realized
$
31

 
$
40

Unrealized
19

 
13

Total trading gains
$
50

 
$
53

Operations and Maintenance Expense

Operations and maintenance expense are comprised of the following:

Retail

Generation

Corporate

Eliminations

Total


Texas

East/West/Other(a)



(In millions)
Six months ended June 30, 2019
$
110


$
228


$
190


$
4


$
(1
)

$
531

Six months ended June 30, 2018
$
96


$
243


$
236


$
1


$
(3
)

573

(a) Includes International, Renewables, and Generation eliminations
 
Operations and maintenance expense decreased by $42 million for the six months ended June 30, 2019, compared to the same period in 2018, due to the following:
 
(In millions)
Decrease due to the reduction in accrual for the Midwest Generation asbestos liability following final settlement
(27
)
Decrease due to the timing of outages in 2019
(23
)
Decrease due to the deconsolidations of Ivanpah and Agua Caliente in 2018
(20
)
Decrease due to 2018 payments in settlement of certain legal matters
(10
)
Decrease due to cost efficiencies as a result of the Transformation Plan
(5
)
Increase in investments in Texas plants in preparation for summer operations
21

Increase primarily related to the lease of Cottonwood from February 4, 2019
17

Increase due to the XOOM acquisition in June 2018
8

Increase associated with costs incurred for margin enhancement initiatives
2

Other
(5
)
    Decrease in operations and maintenance expense
$
(42
)



85



Other Cost of Operations

Other Cost of operations are comprised of the following:



Generation




Retail

Texas

East/West/Other


Total

(In millions)
Six months ended June 30, 2019
$
53


$
32


$
35



$
120

Six months ended June 30, 2018
$
50


$
36


$
43



$
129


Other cost of operations decreased by $9 million for the six months ended June 30, 2019, compared to the same period in 2018, due to the following:
 
(In millions)
Decrease in other cost of operations due to cost efficiencies as a result of the Transformation Plan
$
(5
)
Decrease in ARO accretion expense due to prior year write-off of S.R. Berton
(4
)
    Decrease in other cost of operations
$
(9
)
Depreciation and Amortization
Depreciation and amortization decreased by $62 million for the six months ended June 30, 2019, compared to the same period in 2018, driven primarily by the deconsolidations of Ivanpah in April 2018 and Agua Caliente in August 2018, the sale of Cottonwood in February 2019 and prior year impairments.
Selling, General and Administrative
Selling, general and administrative expenses comprised of the following:

Retail

Generation

Corporate

Total

(In millions)
Six months ended June 30, 2019
$
277


$
117


$
11


$
405

Six months ended June 30, 2018
240


110


26


376

Selling, general and administrative expenses increased by $29 million for the six months ended June 30, 2019, compared to the same period in 2018, due to the following:
 
(In millions)
Increase in selling and marketing expenses associated with costs incurred for margin enhancement initiatives
$
34

Increase in bad debt expense primarily due to higher customer attrition
22

Increase in selling expense due to the acquisition of XOOM in June 2018
12

Decrease in general and administrative expense from cost efficiencies as a result of the Transformation Plan
(26
)
Decrease due to higher accruals for estimated legal liabilities in 2018
(10
)
Decrease related to fees incurred in the acquisition of businesses
(3
)
    Increase in selling, general and administrative expenses
$
29

Reorganization Costs     
Reorganization costs, primarily related to employee severance and contract cancellation costs, decreased by $28 million for the six months ended June 30, 2019, compared to the same period in 2018, driven primarily by significant achievement of the operations and cost excellence portion of the Transformation Plan during 2018.

86


Gain on Sale of Assets
The gain on sale of assets for the six months ended June 30, 2018 consisted primarily of gains on the sales of Canal 3 and a piece of land, while the gain on the sale of assets for the six months ended June 30, 2019 consisted primarily of a gain on the sale of land.
Equity in (Losses)/Earnings of Unconsolidated Affiliates
Equity in (losses)/earnings of unconsolidated affiliates decreased by $27 million for the six months ended June 30, 2019, compared to the six months ended June 30, 2018, primarily driven by six months of losses for Ivanpah in 2019 as a result of the deconsolidations in 2018.
Other Income/(Expense), Net
Other income for the six months ended June 30, 2019 primarily relates to interest income, dividends received from cost method investments and income from pension and postretirement investments. Other expense for the six months ended June 30, 2018 primarily relates to the loss on the deconsolidation of Ivanpah.
Loss on Debt Extinguishment
A loss on debt extinguishment of $47 million was recorded during the six months ended June 30, 2019, driven by the redemption of the 2024 Senior Notes and the repayment of the 2023 Term Loan Facility.
Interest Expense
Interest expense decreased by $20 million for the six months ended June 30, 2019, compared to the same period in 2018, due to the following:
 
(In millions)
Decrease related to the deconsolidations of Ivanpah and Agua Caliente in 2018
$
(23
)
Decrease related to the termination of in-the-money interest rate swaps
(25
)
Decrease related to the debt reduction of $1.2 billion and refinancing $2.4 billion of debt at lower interest rates in 2019 and 2018
(30
)
Increase in derivative interest expense due to the termination of interest rate swaps in 2019
53

Other
5

    Decrease in interest expense
$
(20
)
Income Tax Expense
For the six months ended June 30, 2019, income tax expense of $3 million was recorded on pre-tax income of $286 million. For the same period in 2018, income tax expense of $11 million was recorded on a pre-tax income of $276 million. The effective tax rate was 1.0% and 4.0% for the six months ended June 30, 2019 and 2018, respectively.
For the six months ended June 30, 2019 and 2018, NRG's overall effective tax rates were lower than the statutory rate of 21%, primarily due to the tax benefit for the change in valuation allowance partially offset by the current state tax expense.

87


Income from Discontinued Operations, Net of Income Tax
 
 
Six Months Ended June 30,
(In millions)
 
2019
 
2018
 
Change
South Central Portfolio
 
36

 
32

 
$
4

Yield Renewables Platform & Carlsbad
 
363

 
57

 
306

GenOn
 
2

 
(25
)
 
27

Income from discontinued operations, net of tax
 
$
401

 
$
64

 
$
337

For the six months ended June 30, 2019, NRG recorded income from discontinued operations, net of income tax of $401 million, an increase of $337 million from income of $64 million in the same period in 2018, as further described in Note 4, Acquisitions, Discontinued Operations and Dispositions.
Net Income/(Loss) Attributable to Noncontrolling Interests and Redeemable Noncontrolling Interests
Net income/(loss) attributable to noncontrolling interests and redeemable noncontrolling interests was net income of $1 million for the six months ended June 30, 2019, compared to a net loss of $22 million for the six months ended June 30, 2018. For the six months ended June 30, 2018, the net loss primarily reflects net losses allocated to tax equity investors in tax equity arrangements using the hypothetical liquidation at book value, or HLBV, method and Ivanpah's share of net losses, partially offset by NRG Yield, Inc.'s share of net income. As a result of the disposition of NRG Yield Inc. and its Renewables Platform, as well as the deconsolidation of Ivanpah, the Company does not anticipate material NCI in the future.


88


Liquidity and Capital Resources
Liquidity Position
As of June 30, 2019 and December 31, 2018, NRG's total liquidity, excluding funds deposited by counterparties, of approximately $2.1 billion and $2.0 billion, respectively, was comprised of the following:
(In millions)
June 30, 2019

December 31, 2018
Cash and cash equivalents
$
294


$
563

Restricted cash - operating
9


6

Restricted cash - reserves(a)
2


11

Total
305


580

Total credit facility availability
1,799


1,397

Total liquidity, excluding funds deposited by counterparties
$
2,104


$
1,977

(a) Includes reserves primarily for debt service, performance obligations, and capital expenditures
For the six months ended June 30, 2019, total liquidity, excluding funds deposited by counterparties, increased by $127 million. Changes in cash and cash equivalent balances are further discussed hereinafter under the heading Cash Flow Discussion. Cash and cash equivalents at June 30, 2019 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.
Sources of Liquidity
The principal sources of liquidity for NRG's future operating and maintenance capital expenditures are expected to be derived from cash on hand, cash flows from operations, and financing arrangements, as described in Note 10, Debt and Capital Leases, to this Form 10-Q. The Company's financing arrangements consist mainly of the Senior Notes, the Senior Credit Facility, and project-related financings.
The table below represents the approximate cash proceeds received from sale transactions and related financings, net of working capital and other adjustments, completed by the Company during the six months ended June 30, 2019:
Sales
 
Cash Proceeds (in millions)
South Central Portfolio
 
$
962

Carlsbad
 
396

Guam
 
8

Other
 
10

Sales transactions during the six months ended June 30, 2019
 
$
1,376

Issuance of 2029 Senior Notes
On May 14, 2019, NRG issued $733 million of aggregate principal amount at par of 5.25% senior unsecured notes due 2029. The proceeds from the issuance of the 2029 Senior Notes were utilized to redeem the Company's remaining 6.25% Senior Notes due 2024.
Issuance of 2024 and 2029 Senior Secured Notes
On May 28, 2019, NRG issued $1.1 billion of aggregate principal amount of senior secured first lien notes, consisting of $600 million 3.75% senior secured first lien notes due 2024 and $500 million 4.45% senior secured first lien notes due 2029, at a discount. The proceeds from the issuance of the Senior Secured First Lien Notes, together with cash on hand, were used to repay the Company's 2023 Term Loan Facility, resulting in a decrease of $594 million to long-term debt outstanding.

89


Revolving Credit Facility Modification
On May 28, 2019, the Company amended its existing credit agreement to, among other things, (i) provide for a $184 million increase in revolving commitments, resulting in aggregate revolving commitments under the amended credit agreement equal to $2.6 billion, (ii) extend the maturity date of the revolving loans and commitments under the amended credit agreement to May 28, 2024, (iii) provide for a release of the collateral securing the amended credit agreement if NRG obtains an investment grade rating from two out of the three rating agencies, subject to an obligation to reinstate the collateral if such rating agencies withdraw NRG’s investment grade rating or downgrade NRG’s rating below investment grade, (iv) reduce the applicable margins for borrowings under (a) ABR Revolving Loans from 1.25% to 0.75% and (b) Eurodollar Revolving Loans from 2.25% to 1.75%, (v) add a sustainability-linked pricing metric that permits an interest rate adjustment tied to NRG meeting targets related to environmental sustainability and (vi) make certain other changes to the existing covenants.
First Lien Structure
NRG has granted first liens to certain counterparties on a substantial portion of the Company's assets, excluding NRG's assets that have project-level financing and the assets of certain non-guarantor subsidiaries, 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. To the extent that the underlying hedge positions for a counterparty are out-of-the-money to NRG, the counterparty would have a 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.  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. Net exposure to a counterparty on all trades must be positively correlated to the price of the relevant commodity for the first lien to be available to that counterparty. 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 June 30, 2019, all hedges under the first liens were in-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 June 30, 2019:
Equivalent Net Sales Secured by First Lien Structure(a)
2019
 
2020
 
2021
 
2022
 
2023
In MW
514
 
865
 
740
 
792
 
846
As a percentage of total net coal and nuclear capacity(b)
11%
 
19%
 
16%
 
17%
 
19%
(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 with Midwest Generation 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, development, and environmental; (iv) allocations in connection with acquisition opportunities, debt repayments, share repurchases, return of capital and dividend payments to stockholders; and (v) costs necessary to execute the Transformation Plan.
Commercial Operations
The Company'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); and (iv) initial collateral for large structured transactions. As of June 30, 2019, the Company had total cash collateral outstanding of $163 million and $682 million outstanding in letters of credit to third parties primarily to support its commercial activities for both wholesale and retail transactions. As of June 30, 2019, total funds deposited by counterparties was $31 million in cash and $100 million of 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 the Company's credit ratings and general perception of its creditworthiness.

90


Capital Expenditures
The following tables and descriptions summarize the Company's capital expenditures for maintenance, growth investments, and environmental for the six months ended June 30, 2019, and the estimated capital expenditures forecast for the remainder of 2019
 
Maintenance
 
Environmental
 
Growth Investments(c)
 
Total
 
(In millions)
Retail
$
9

 
$

 
$
19

 
$
28

Generation
 
 
 
 
 
 
 
Texas
39

 

 

 
39

East/West/Other(a)
25

 
2

 

 
27

Corporate 
3

 

 
10

 
13

Total cash capital expenditures for the six months ended June 30, 2019
76

 
2

 
29

 
107

     Other investments

 

 
58

 
58

Total capital expenditures and investments, net of financings
76

 
2

 
87

 
165

 
 
 
 
 
 
 
 
Estimated capital expenditures for the remainder of 2019(b)
$
79

 
$
1

 
$
17

 
$
97

(a) Includes International, Renewables and Cottonwood
(b) Growth investments includes $17 million of costs to achieve associated with the Transformation Plan
(c) Includes other investments, acquisitions and costs to achieve

Growth Investments Capital Expenditures
For the six months ended June 30, 2019, the Company's growth investments capital expenditures included $27 million for cost to achieve projects associated with the Transformation Plan and $2 million for the Company's other growth projects.
Environmental Capital Expenditures
NRG estimates that environmental capital expenditures from 2019 through 2023 required to comply with environmental laws will be approximately $36 million.
Common Stock Dividends
Dividends of $0.06 per share were paid on the Company's common stock during the six months ended June 30, 2019. On July 19, 2019, NRG declared a quarterly dividend on the Company's common stock of $0.03 per share, payable August 15, 2019, to stockholders of record as of August 1, 2019, 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 and regulations. The Company expects that, based on current circumstances, comparable cash dividends will continue to be paid in the foreseeable future.
Share Repurchases
During January and February, the Company completed $250 million of share repurchases in connection with the 2018 share repurchase program, at an average price of $40.61 per share. In February 2019, the Company's board of directors authorized an additional $1.0 billion share repurchase program. Through August 7, 2019, the Company completed share repurchases of $1.0 billion in connection with the 2019 share repurchase program, at an average price of $38.38 per share, of which $804 million was repurchased during the six months ended June 30, 2019.

91


Senior Note Repurchases
During the three months ended June 30, 2019, the Company redeemed $733 million of its 6.25% Senior Notes due 2024 and recorded a loss on debt extinguishment of $29 million, which included the write-off of previously deferred debt issuance costs of $5 million.
2023 Term Loan Facility Repayment
On May 28, 2019, the Company repaid its $1.7 billion 2023 Term Loan Facility using the proceeds from the issuance of the Senior Secured First Lien Notes, as well as cash on hand. The Company recorded a loss on debt extinguishment of $17 million, which included the write-off of previously deferred debt issuance costs of $13 million. As a result of the repayment of the outstanding 2023 Term Loan Facility, the Company terminated the related interest rate swap agreements, which were in-the-money, and received $25 million that was recorded as a reduction to interest expense.
Stream Energy Acquisition
On May 15, 2019, the Company entered into an agreement to acquire Stream Energy's retail electricity and natural gas business operating in 9 states and Washington, D.C. for $300 million in cash and estimated transaction costs and working capital adjustments of approximately $25 million. The acquisition increased NRG's retail portfolio by approximately 600,000 RCEs or 450,000 customers. The acquisition closed on August 1, 2019.
Petra Nova Debt Repayment
NRG has guaranteed up to $124 million of Petra Nova's $248 million project debt to its lenders for purposes of debt repayment in the event Petra Nova is unable to meet its projected debt coverage covenant as stipulated in its financing agreements. The covenant test and possible repayment, or a portion thereof, are scheduled to occur in the third quarter of 2019. Once such payment is made, NRG's guarantee will terminate.
Balance Sheet Target Ratio
NRG revised its credit metrics target in order to further strengthen its balance sheet by reducing leverage. During the second quarter of 2019, in connection with the repayment of the 2023 Term Loan Facility repayment, as further discussed in Note 10, Debt and Capital Leases, the Company reduced total outstanding debt by $594 million.

Cash Flow Discussion
The following table reflects the changes in cash flows for the comparative six month periods:
 
Six months ended June 30,
 
 
 
2019
 
2018
 
Change
 
(In millions)
Net Cash Provided by Operating Activities
$
389

 
$
513

 
$
(124
)
Net Cash Provided/(Used) by Investing Activities
1,103

 
(1,162
)
 
2,265

Net Cash (Used)/Provided by Financing Activities
(1,720
)
 
450

 
(2,170
)
Net Cash Provided by Operating Activities
Changes to net cash provided by operating activities were driven by:
 
(In millions)
Change in cash provided by discontinued operations
$
(241
)
Decrease in working capital
(39
)
Changes in cash collateral in support of risk management activities due to changes in commodity prices
134

Increase in operating income adjusted for other non-cash items
22

 
$
(124
)

92


Net Cash Provided/(Used) by Investing Activities
Changes to net cash provided/(used) by investing activities were driven by:
 
(In millions)
Increase in proceeds from sale of assets and discontinued operations primarily due to sales of South Central Portfolio and Carlsbad
$
1,143

Decrease in cash used by discontinued operations
582

Decrease in cash paid for acquisitions primarily due to XOOM acquisition in 2018
190

Decrease in capital expenditures
175

Cash removed due to deconsolidation of Ivanpah in 2018
160

Increase in proceeds received from sales of nuclear decommissioning trust fund securities, net of purchases
25

Increase in contributions to discontinued operations
(28
)
Other
18

 
$
2,265

Net Cash (Used)/Provided by Financing Activities
Changes to net cash (used)/provided by financing activities were driven by:
 
(In millions)
Increase in payments of short and long-term debt
$
(2,137
)
Increase in payments for treasury stock
(539
)
Change in cash provided by discontinued operations
(302
)
Increase in payments of debt extinguishment costs and deferred issuance costs
(38
)
Increase in proceeds from issuance of short and long-term debt
839

Other
7

 
$
(2,170
)

93


NOLs, Deferred Tax Assets and Uncertain Tax Position Implications, under ASC 740
For the six months ended June 30, 2019, the Company had domestic pre-tax book income of $276 million and foreign pre-tax book income of $10 million. As of December 31, 2018, the Company had cumulative domestic Federal NOL carryforwards of $10.7 billion, which will begin expiring in 2031, and cumulative state NOL carryforwards of $5.6 billion for financial statement purposes. NRG also has cumulative foreign NOL carryforwards of $213 million, which do not have an expiration date. In addition to the above NOLs, NRG has a $442 million carryforward for interest deductions, as well as $381 million of tax credits to be utilized in future years. In addition to these amounts, the Company has $24 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 $20 million in 2019.
The Company has recorded a non-current tax liability of $28 million until final resolution with the related taxing authority. The $28 million non-current tax liability for uncertain tax benefits is from positions taken on various state income tax returns, including accrued interest.
The Company is no longer 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.
As of June 30, 2019 and December 31, 2018, the Company had a valuation allowance on its domestic net deferred tax assets of $3.7 billion and $3.8 billion, respectively, due to its history of net operating losses. The realization of net deferred tax assets is dependent on the Company's ability to generate sufficient future taxable income during periods prior to the expiration of the tax attributes. Given the Company's current earnings and forecasted future earnings, there is a reasonable possibility that within the next six months there may be sufficient positive evidence to allow for the release of a significant portion of the valuation allowance, which will result in a material increase to net income in the period such conclusion is made. The Company will continue to evaluate the evidence on a quarterly basis.
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 June 30, 2019, NRG has investments in energy and energy-related entities that are accounted for under the equity method of accounting. NRG’s investment in Ivanpah is a variable interest entity for which NRG is not the primary beneficiary. See also Note 11, Investments Accounted for Using the Equity Method and 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 $1.0 billion as of June 30, 2019. This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to NRG. See also Note 15, Investments Accounted for by the Equity Method and Variable Interest Entities, to the Company's 2018 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 2018 Form 10-K. See also Note 8, Leases, Note 10, Debt and Capital Leases, and Note 17, 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 six months ended June 30, 2019.

94


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. Historically, in order to mitigate interest rate risk associated with the issuance of the Company's variable rate and fixed rate debt, NRG entered into interest rate swap agreements. As of June 30, 2019, NRG had no interest rate derivative instruments. 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 2018 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 June 30, 2019, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at June 30, 2019.
Derivative Activity Gains/(Losses)
(In millions)
Fair Value of Contracts as of December 31, 2018
$
104

Contracts realized or otherwise settled during the period
(16
)
Contracts acquired during the period
(2
)
Changes in fair value
38

Fair Value of Contracts as of June 30, 2019
$
124

 
Fair Value of Contracts as of June 30, 2019
 
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
$
(93
)
 
$
(18
)
 
$
(3
)
 
$

 
$
(114
)
Level 2
69

 
75

 
7

 
(10
)
 
141

Level 3
96

 
32

 
(5
)
 
(26
)
 
97

Total
$
72

 
$
89

 
$
(1
)
 
$
(36
)
 
$
124

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 June 30, 2019, NRG's net derivative asset was $124 million, an increase to total fair value of $20 million as compared to December 31, 2018. This increase was driven by gains in fair value, partially offset by roll-off of trades that settled during the period and contracts acquired.
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 a decrease of approximately $94 million in the net value of derivatives as of June 30, 2019. The impact of a $0.50 per MMBtu decrease in natural gas prices across the term of derivative contracts would result in an increase of approximately $94 million in the net value of derivatives as of June 30, 2019.


95


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's significant accounting policies are outlined in Note 2, Summary of Significant Accounting Policies, of this Form 10-Q, and in Note 2, Summary of Significant Accounting Policies, under Part IV, Item 15 the Company's 2018 Form 10-K. The Company's critical accounting estimates are described in Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, in the Company's 2018 Form 10-K. There have been no material changes to the Company's critical accounting policies and estimates since the 2018 Form 10-K.


96


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 2018 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 six months ending June 30, 2019 and 2018:
(In millions)
2019
 
2018
VaR as of June 30,
$
33

 
$
54

Three months ended June 30,
 
 
 
Average
$
40

 
$
59

Maximum
46

 
68

Minimum
33

 
52

Six months ended June 30,
 
 
 
Average
43

 
$
59

Maximum
49

 
69

Minimum
33

 
48

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 June 30, 2019, for the entire term of these instruments entered into for both asset management and trading, was $11 million, primarily driven by asset-backed transactions.
Interest Rate Risk
NRG was 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 has previously entered into interest rate swaps. As of June 30, 2019, NRG had no interest rate derivative instruments. See Note 11, Debt and Capital Leases, of the Company's 2018 Form 10-K for more information on the Company's interest rate swaps.
As of June 30, 2019, the fair value and related carrying value of the Company's debt was $6.4 billion and $6.0 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 $569 million.

97


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 $93 million as of June 30, 2019, and a 1 MMBtu/MWh change in heat rates for heat rate positions would result in a change in margin collateral posted of approximately $71 million as of June 30, 2019. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of June 30, 2019.
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 5, Fair Value of Financial Instruments, to this Form 10-Q for discussions regarding counterparty credit risk and retail customer credit risk, and Note 7, 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.

98


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 quarter ended June 30, 2019 that materially affected, or are reasonably likely to materially affect, NRG's internal control over financial reporting.



99


PART II — OTHER INFORMATION
ITEM 1 — LEGAL PROCEEDINGS
For a discussion of material legal proceedings in which NRG was involved through June 30, 2019, see Note 17, 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 2018 Form 10-K. There have been no material changes in the Company's risk factors since those reported in its 2018 Form 10‑K.
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
In 2018, the Company's board of directors authorized the Company to repurchase $1.5 billion of its common stock. $1.25 billion common stock repurchases were completed in 2018 and the remaining $0.25 billion completed through February 2019. In addition the Company's board of directors authorized in February 2019 an additional $1.0 billion share repurchase program to be executed in 2019. Through August 7, 2019, the Company completed the $1.0 billion share repurchase program at an average price of $38.38 per share. In August 2019, the Company announced that the board of directors authorized an additional $0.25 billion of share repurchases to be executed in the second half of 2019.
The table below sets forth the information with respect to purchases made by or on behalf of NRG or any "affiliated purchaser" (as defined in Rule 10b-18(a)(3) under the Exchange Act), of NRG's common stock during the quarter ended June 30, 2019.
For the three months ended June 30, 2019
 
Total Number of Shares Purchased
 
Average Price Paid per Share(a)
 
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
 
Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs(a)
Month #1
 
 
 
 
 
 
 
 
(April 1, 2019 to April 30, 2019)
 
390,908

 
(b)

 
390,908

 
$
499,773,516

Month #2
 
 
 
 
 
 
 
 
(May 1, 2019 to May 31, 2019) 
 
4,246,164

 
$
35.83

 
4,246,164

 
$
347,547,868

Month #3
 
 
 
 
 
 
 
 
(June 1, 2019 to June 30, 2019)
 
4,375,000

 
$
34.67

 
4,375,000

 
$
195,779,264

Total at June 30, 2019
 
9,012,072

 
 
 
9,012,072

 
 
(a)
Includes commissions paid
(b)
Includes 351,768 additional shares delivered under the ASR agreement upon settlement. The average price paid per share for April purchases excluding the additional shares delivered under the ASR was $41.99


ITEM 3 — DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4 — MINE SAFETY DISCLOSURES
Not applicable.
ITEM 5 — OTHER INFORMATION
None.

100


ITEM 6 — EXHIBITS
Number
 
Description
 
Method of Filing
4.1
 
 
Incorporated herein by reference to Exhibit 4.1 to the Registrant's current report on Form 8-K filed on May 16, 2019
4.2
 
 
Incorporated herein by reference to Exhibit 4.2 to the Registrant's current report on Form 8-K filed on May 16, 2019
4.3
 
 
Incorporated herein by reference to Exhibit 4.3 to the Registrant's current report on Form 8-K filed on May 16, 2019
4.4
 
 
Incorporated herein by reference to Exhibit 4.1 to the Registrant's current report on Form 8-K filed on May 30, 2019
4.5
 
 
Incorporated herein by reference to Exhibit 4.2 to the Registrant's current report on Form 8-K filed on May 30, 2019
4.6
 
 
Incorporated herein by reference to Exhibit 4.3 to the Registrant's current report on Form 8-K filed on May 30, 2019
4.7
 
 
Incorporated herein by reference to Exhibit 4.4 to the Registrant's current report on Form 8-K filed on May 30, 2019
10.1
 
 
Incorporated herein by reference to Exhibit 10.1 to the Registrant's current report on Form 8-K filed on May 30, 2019
31.1
 
 
Filed herewith.
31.2
 
 
Filed herewith.
31.3
 
 
Filed herewith.
32
 
 
Furnished herewith.
101 INS
 
Inline XBRL Instance Document.
 
The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
101 SCH
 
Inline XBRL Taxonomy Extension Schema.
 
Filed herewith.
101 CAL
 
Inline XBRL Taxonomy Extension Calculation Linkbase.
 
Filed herewith.
101 DEF
 
Inline XBRL Taxonomy Extension Definition Linkbase.
 
Filed herewith.
101 LAB
 
Inline XBRL Taxonomy Extension Label Linkbase.
 
Filed herewith.
101 PRE
 
Inline XBRL Taxonomy Extension Presentation Linkbase.
 
Filed herewith.
104
 
Cover Page Interactive Data File (the cover page interactive data file does not appear in Exhibit 104 because it's Inline XBRL tags are embedded within the Inline XBRL document).
 
Filed herewith.


101


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: August 7, 2019
Chief Accounting Officer
(Principal Accounting Officer) 
 
 




102