false--12-31Q2201900010138715000000P5Y0.010.015000000000.060.04125P10Y23000000P6MP1YP1YP1YP1Y 0001013871 srt:ConsolidationEliminationsMember 2018-04-01 2018-06-30



 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
x☒ Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
   
  For the Quarterly Period Ended:
June 30, 20182019
   
o☐ Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Commission File Number: 001-15891
NRG Energy, Inc.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)
 
41-1724239
(I.R.S. Employer
Identification No.)
          
804 Carnegie Center
,PrincetonNew Jersey
08540
(Address of principal executive offices) 
08540
(Zip Code)
(609) (609) 524-4500
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each ClassTrading Symbol(s)Name of Exchange on Which Registered
Common Stock, par value $0.01NRGNew 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.
Yesx☒Noo☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yesx☒Noo☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer x
Accelerated Filer		☒
Accelerated filero
☐
Non-accelerated filero
☐
Smaller reporting companyo
☐
Emerging growth companyo☐
    (Do not check if a smaller reporting company)   
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  o☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yeso☐Nox☒
As of June 30, 2018,August 7, 2019, there were 303,429,305252,987,889 shares of common stock outstanding, par value $0.01 per share.
 




TABLE OF CONTENTS
Index
CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION
3
GLOSSARY OF TERMS
5
PART I — FINANCIAL INFORMATION
109
ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES
109
ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
6761
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
10597
ITEM 4 — CONTROLS AND PROCEDURES
10799
PART II — OTHER INFORMATION
108100
ITEM 1 — LEGAL PROCEEDINGS
108100
ITEM 1A — RISK FACTORS
108100
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
108100
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES
108100
ITEM 4 — MINE SAFETY DISCLOSURES
108100
ITEM 5 — OTHER INFORMATION
108100
ITEM 6 — EXHIBITS
109101
SIGNATURES
110102







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 Item 1A — Risk Factors Related to NRG Energy, Inc., in Part I, Item 1A of the Company's Annual Report on Form 10-K for the year ended December 31, 2017,2018 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;
The potential adverse effects of the GenOn Entities' filings under Chapter 11 of the Bankruptcy Code and restructuring transactions on NRG's operations, management and employees and the risks associated with operating NRG's business during the restructuring process;
Risks and uncertainties associated with the GenOn Entities' Chapter 11 Cases including the ability to achieve anticipated benefits therefrom;
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, (including wind and solar conditions), catastrophic weather-related or other damage to facilities, unscheduled generation outages, maintenance or repairs, unanticipated changes to fuel supply costs or availability due to higher demand, shortages, transportation problems or other developments, environmental incidents, or electric transmission or gas pipeline system constraints and the possibility that NRG may not have adequate insurance to cover losses as a result of such hazards;
The effectiveness of NRG's risk management policies and procedures and the ability of NRG's counterparties to satisfy their financial commitments;
Counterparties' collateral demands and other factors affecting NRG's liquidity position and financial condition;
NRG's ability to operate its businesses efficiently and generate earnings and cash flows from its asset-based businesses in relation to its debt and other obligations;
NRG's ability to enter into contracts to sell power and procure fuel on acceptable terms and prices;
The liquidity and competitiveness of wholesale markets for energy commodities;
Government regulation, including 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 going forward;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 sell assets to NRG Yield, Inc. and to close drop-down transactions;


NRG's ability to achieve its strategy of regularly returning capital to stockholders;
NRG's ability to obtain and maintain retail market share;
NRG's ability to successfully evaluate investments and achieve intended financial results in new business and growth initiatives;
NRG's ability to successfully integrate, realize cost savings and manage any acquired businesses; and
NRG's ability to develop and maintain successful partnering relationships.relationships as needed.


Forward-looking statements speak only as of the date they were made and NRG Energy, Inc. undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors that could cause NRG's actual results to differ materially from those contemplated in any forward-looking statements included in this Quarterly Report on Form 10-Q should not be construed as exhaustive.



GLOSSARY OF TERMS
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:
20172018 Form 10-K NRG’s Annual Report on Form 10-K for the year ended December 31, 20172018
2023 Term Loan Facility The Company's $1.9$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
Adjusted EBITDAACE Adjusted earnings beforeAffordable Clean Energy
Agua CalienteAgua Caliente Solar Project, a 290 MW photovoltaic power station located in Yuma County, Arizona in which NRG owns 35% interest taxes, depreciation and amortization
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
BACTBest Available Control Technology
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
BRABase 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
CAIRClean Air Interstate Rule
CAISO California Independent System Operator
CASPRCarlsbad Competitive Auctions with Sponsored ResourcesCarlsbad Energy Center, a 528 MW natural gas-fired project located in Carlsbad, CA
CDD Cooling Degree Day
CDWR California Department of Water Resources
CECCalifornia Energy Commission
CenterPointCenterPoint Energy Houston Electric, LLC
CFTC U.S. Commodity Futures Trading Commission
Chapter 11 CasesVoluntary cases commenced by the GenOn Entities under the Bankruptcy Code in the Bankruptcy Court
C&I Commercial industrial and governmental/institutional
CESClean Energy Standard
Cleco Cleco EnergyCorporate Holdings LLC
COD
CO2
 Commercial Operation DateCarbon Dioxide
ComEd Commonwealth Edison
Company NRG Energy, Inc.
CPUCCottonwood California Public Utilities CommissionCottonwood Generating Station, a 1,153 MW natural gas-fueled plant which NRG is leasing through May 2025
CSAPRCPP Cross-State Air Pollution Rule
CVSRCalifornia Valley Solar RanchClean Power Plan
CWA Clean Water Act
D.C. Circuit U.S. Court of Appeals for the District of Columbia Circuit
DGPV Holdco 1NRG DGPV Holdco 1 LLC
DGPV Holdco 2NRG DGPV Holdco 2 LLC
DGPV Holdco 3NRG DGPV Holdco 3 LLC
Distributed Solar Solar power projects that primarily sell power to customers for usage on site, or are interconnected to sell power into a local distribution grid


DNREC Delaware Department of Natural Resources and Environmental Control
DSIDry Sorbent Injection
Economic gross margin Sum of energy revenue, capacity revenue, retail revenue and other revenue, less cost of fuels and other cost of sales
El Segundo Energy CenterEGU NRG West Holdings LLC, the subsidiary of Natural Gas Repowering LLC, which owns the El Segundo Energy Center projectElectric Generating Unit
EME Edison Mission Energy
Energy Plus HoldingsEnergy Plus Holdings LLC
EPA U.S. Environmental Protection Agency
EPCEngineering, Procurement and Construction
EPSAThe Electric Power Supply Association
ERCOT Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas
ESPElectrostatic Precipitator
ESPP NRG Energy, Inc. Amended and Restated Employee Stock Purchase Plan
ESPS Existing Source Performance Standards
Exchange Act The Securities Exchange Act of 1934, as amended

FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
FGD Flue gas desulfurization
Fresh Start
Reporting requirements as defined by ASC-852, Reorganizations
FTRs Financial Transmission Rights
GAAP AccountingGenerally accepted accounting principles generally accepted in the U.S.
GenConn GenConn Energy LLC
GenOn GenOn Energy, Inc.
GenOn Americas GenerationGenOn Americas Generation, LLC
GenOn Americas Generation Senior NotesGenOn Americas Generation's $395 million outstanding unsecured senior notes consisting of $208 million of 8.5% senior notes due 2021 and $187 million of 9.125% senior notes due 2031
GenOn Entities GenOn and certain of its wholly owned subsidiaries, including GenOn Americas Generation.Generation, that filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court on June 14, 2017
GenOn Mid-AtlanticGenOn Mid-Atlantic, LLC and, except where the context indicates otherwise, its subsidiaries, which include the coal generation units at two generating facilities under operating leases
GenOn Senior NotesGenOn's $1.8 billion outstanding unsecured senior notes consisting of $691 million of 7.875% senior notes due 2017, $649 million of 9.5% senior notes due 2018, and $489 million of 9.875% senior notes due 2020
GenOn SettlementA settlement agreement and any other documents necessary to effectuate the settlement among NRG, GenOn, and certain holders of senior unsecured notes of GenOn Americas Generation and GenOn, and certain of GenOn's direct and indirect subsidiaries
GHG Greenhouse Gas
GIP Global Infrastructure Partners
GWGigawatt
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 and isgeneration. Heat rates are generally expressed as BTU per net kWh
HLBVHLW Hypothetical Liquidation at Book Value


High-level radioactive waste
IASBICE International Accounting Standards Board
IFRSInternational Financial Reporting Standards
IPAIllinois Power Agency
IPPNYIndependent Power Producers of New YorkIntercontinental Exchange
ISO Independent System Operator, also referred to as RTOs
ISO-NE ISO New England Inc.
ITCIvanpah Investment Tax CreditIvanpah 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
Marsh LandingNRG Marsh Landing, LLC (formerly known as GenOn Marsh Landing, LLC)
Mass Market Residential and small commercial customers
MATS Mercury and Air Toxics Standards promulgated by the EPA
MDth Thousand Dekatherms
Midwest Generation Midwest Generation, LLC
MISO Midcontinent Independent System Operator, Inc.
MMBtu Million British Thermal Units
MOPRMinimum Offer Price Rule
MW Megawatts
MWeMegawatt equivalent
MWh Saleable megawatt hour net of internal/parasitic load megawatt-hour
MWtMegawatts Thermal Equivalent
NAAQS National Ambient Air Quality Standards
NEPGANew England Power Generators Association
NEPOOL New England Power Pool
NERC North American Electric Reliability Corporation
NJBPUNew Jersey Board of Public Utilities
Net Exposure Counterparty credit exposure to NRG, net of collateral
Net GenerationNodal The net amount of electricity produced, expressed in kWhs or MWhs, thatNodal Exchange is the total amount of electricity generated (gross) minus the amount of electricity used during generationa derivatives exchange
NOL Net Operating Loss
NOVNotice of Violation
NOx
 Nitrogen Oxides
NPDES National Pollutant Discharge Elimination System
NPNS Normal Purchase Normal Sale
NRC U.S. Nuclear Regulatory Commission
NRG NRG Energy, Inc.

NRG YieldReporting segment including the projects owned by NRG Yield, Inc.
NRG Yield 2019 Convertible Notes$345 million aggregate principal amount of 3.50% Convertible Senior Notes due 2019 issued by NRG Yield, Inc.
NRG Yield 2020 Convertible Notes$287.5 million aggregate principal amount of 3.25% Convertible Notes due 2020 issued by NRG Yield, Inc.
NRG Yield, Inc. NRG Yield, Inc., which changed it's name to Clearway Energy, Inc. following the owner of 54.8% of the economic interestssale by NRG of NRG Yield LLC with a controlling interest, and issuer of publicly held shares of Class A and Class C common stock
NSRNew Source Reviewthe 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, unitsUnits 1 & 2
NYAGNuclear Waste Policy Act StateU.S. Nuclear Waste Policy Act of 1982
NY DECNew York OfficeDepartment of Attorney GeneralEnvironmental 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)
ORDCOperating Reserve Demand Curve
PA PUCPennsylvania Public Utility Commission
Peaking Units expected to satisfy demand requirements during the periods of greatest or peak load on thea system
PERPetra Nova Peak Energy RentPetra 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
Petition DatePG&E June 14, 2017
PipelineProjects that range from identified lead to shortlisted with an offtake,PG&E Corporation (NYSE: PCG) and represents a lower level of execution certainty.its primary operating subsidiary, Pacific Gas and Electric Company
PJM PJM Interconnection, LLC
PM2.5Particulate Matter that has a diameter of less than 2.5 micrometers
PPA Power Purchase Agreement
PSDPrevention of Significant Deterioration
PTCProduction Tax Credit
PUCT Public Utility Commission of Texas
PUHCARCE Public Utility Holding Company ActResidential Customer Equivalent is a unit of 2005measure 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 EnergyReliant Energy Retail Services, LLC
REMA NRG REMA LLC, which leases a 100% interest in the Shawville generating facility and 16.7% and 16.5% interestsinterest in the Keystone and Conemaugh generating facilities, respectively
Restructuring Support AgreementRenewables Restructuring SupportConsists of the following projects in which NRG has an ownership interest: Agua Caliente, Ivanpah, and Lock-Up Agreement, dated as of June 12, 2017solar generating stations located at various NFL Stadiums
Renewables PlatformThe renewable operating and as amended on October 2, 2017,development platform sold by and among GenOn Energy,NRG to GIP with NRG's interest in NRG Yield, Inc., GenOn Americas Generation, LLC, and subsidiaries signatory thereto, NRG Energy, Inc. and the noteholders signatory thereto
Retail Reporting segment that includes NRG's residential and small commercial businesses which go to market as Reliant, NRG and other brands owned by NRG, as well as Business Solutions
Revolving Credit FacilityThe Company’s $2.5 billion revolving credit facility, a component of the Senior Credit Facility. The revolving credit facility consists of $289 million of Tranche A Revolving Credit Facility, due 2018, and $2.2 billion of Tranche B Revolving Credit Facility, due 2021
RFORequest for Offer
RGGI Regional Greenhouse Gas Initiative
RMRReliability Must-Run
ROFORight of First Offer
ROFO AgreementSecond Amended and Restated Right of First Offer Agreement by and between NRG Energy, Inc. and NRG Yield, Inc.
RPMReliability Pricing Model
RPV HoldcoNRG RPV Holdco 1 LLC
RTO Regional Transmission Organization
RTRRenewable Technology Resource
SCESouthern California Edison
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 December 31, 2017, NRG’s $4.8June 30, 2019, NRG's $3.8 billion outstanding unsecured senior notes consisting of $992 million of 6.25% senior notes due 2022, $733 million of 6.25% senior notes due 2024, $1.0 billion of the 7.25% senior notes due 2026, $1.25$1.23 billion of the 6.625% senior notes due 2027, and $870$821 million of 5.75% senior notes due 2028.2028 and $733 million of the 5.250% senior notes due 2029
Services AgreementSNF 
NRG provided GenOn with various management, personnel and other services, which include human resources, regulatory and public affairs, accounting, tax, legal, information systems, treasury, risk management, commercial operations, and asset management, as set forth in the services agreement with GenOn

SIFMASecurities Industry and Financial Markets AssociationSpent Nuclear Fuel
SO2
 Sulfur Dioxide
South Central PortfolioNRG'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
STPSouth Texas Project — nuclear generating facility located near Bay City, Texas in which NRG owns a 44% interest
STPNOCSouth Texas Project Nuclear Operating Company


South CentralNRG's South Central business, which owns and operates a 3,555-MW portfolio of generation assets consisting of 225-MW Bayou Cove, 430-MW Big Cajun-I, 1,461-MW Big Cajun-II, 1,263-MW Cottonwood and 176-MW Sterlington, and serves a customer base of cooperatives, municipalities and regional utilities under load contracts.
S&PStandard & Poor's
TCPATelephone Consumer Protection Act
TSA Transportation Services Agreement
TWCC Texas Westmoreland Coal Co.
UPMC Thermal ProjectUniversity 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
WECCWestern Electricity Coordinating Council
WSTWashington-St. Tammany Electric Cooperative, Inc.
Yield OperatingNRG Yield Operating LLC



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,Three months ended June 30,
Six months ended June 30,
(In millions, except for per share amounts)2018
2017
2018
20172019
2018
2019
2018
Operating Revenues







 
 
 
Total operating revenues$2,922

$2,701

$5,343

$5,083
$2,465

$2,461

$4,630

$4,526
Operating Costs and Expenses













Cost of operations2,051

1,841

3,609

3,704
1,845

1,889

3,496

3,274
Depreciation and amortization227

260

462

517
85

112

170

232
Impairment losses74

63

74

63
1

74

1

74
Selling, general and administrative211

221

402

481
211

200

405

376
Reorganization costs23

—

43

—
2

23

15

43
Development costs16

18

29

35
2

3

4

8
Total operating costs and expenses2,602

2,403

4,619

4,800
2,146

2,301

4,091

4,007
Other income - affiliate—

39

—

87
Gain on sale of assets14

2

16

4
1

14

2

16
Operating Income334

339

740

374
320

174

541

535
Other Income/(Expense)













Equity in earnings/(losses) of unconsolidated affiliates18

(3)
16

2
—

5

(21)
6
Other income/(expense), net(20)
14

(23)
26
20

(23)
32

(23)
Loss on debt extinguishment, net(1)
—

(3)
(2)(47)
(1)
(47)
(3)
Interest expense(202)
(247)
(369)
(471)(105)
(123)
(219)
(239)
Total other expense(205)
(236)
(379)
(445)(132)
(142)
(255)
(259)
Income/(Loss) from Continuing Operations Before Income Taxes129

103

361

(71)
Income tax expense/(benefit)8

4

7

(1)
Income/(Loss) from Continuing Operations121

99

354

(70)
Loss from discontinued operations, net of income tax(25)
(741)
(25)
(775)
Net Income/(Loss)96

(642)
329

(845)
Less: Net income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interests24

(16)
(22)
(55)
Net Income/(Loss) Attributable to NRG Energy, Inc.$72

$(626)
$351

$(790)
Earnings/(Loss) per Share Attributable to NRG Energy, Inc. Common Stockholders






Income from Continuing Operations Before Income Taxes188

32

286

276
Income tax (benefit)/expense(1)
5

3

11
Income from Continuing Operations189

27

283

265
Income from discontinued operations, net of income tax13

69

401

64
Net Income202

96

684

329
Less: Net income/(loss) attributable to noncontrolling interest and redeemable interests1

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 — basic310

316

314

316
265

310

272

314
Income/(loss) from continuing operations per weighted average common share — basic$0.31

$0.36

$1.20

$(0.05)
Income/(loss) from discontinued operations per weighted average common share — basic$(0.08)
$(2.34)
$(0.08)
$(2.45)
Earnings/(Loss) per Weighted Average Common Share — Basic$0.23

$(1.98)
$1.12

$(2.50)
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 — diluted314

316

318

316
267

314

274

318
Income/(loss) from continuing operations per weighted average common share — diluted$0.31

$0.36

$1.18

$(0.05)
Income/(loss) from discontinued operations per weighted average common share — diluted$(0.08)
$(2.34)
$(0.08)
$(2.45)
Earnings/(Loss) per Weighted Average Common Share — Diluted$0.23

$(1.98)
$1.10

$(2.50)
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
$0.03

$0.03

$0.06

$0.06
See accompanying notes to condensed consolidated financial statements.





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

Three months ended June 30,
Six months ended June 30,

2018
2017
2018
2017

(In millions)
Net income/(loss)$96

$(642)
$329

$(845)
Other comprehensive income/(loss), net of tax






Unrealized gain/(loss) on derivatives, net of income tax expense of $0, $0, $0, and $15

(5)
19

(1)
Foreign currency translation adjustments, net of income tax expense of $0, $0, $0, and $0(4)
1

(6)
8
Available-for-sale securities, net of income tax expense of $0, $0, $0, and $01

1

1

1
Defined benefit plans, net of income tax expense of $0, $0, $0, and $0(1)
27

(2)
27
Other comprehensive income1

24

12

35
Comprehensive income/(loss)97

(618)
341

(810)
Less: Comprehensive loss attributable to noncontrolling interest and redeemable noncontrolling interest26

(17)
(12)
(56)
Comprehensive income/(loss) attributable to NRG Energy, Inc.71

(601)
353

(754)
Comprehensive income/(loss) available for common stockholders$71

$(601)
$353

$(754)

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 securities1
 1
 1
 1
Defined benefit plans(3) (1) (6) (2)
Other comprehensive (loss)/income(3) 1
 (5) 12
Comprehensive Income199
 97
 679
 341
Less: Comprehensive income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interest1
 26
 1
 (12)
Comprehensive Income Attributable to NRG Energy, Inc.$198
 $71
 $678
 $353
See accompanying notes to condensed consolidated financial statements.



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 counterparties31
 33
Restricted cash11
 17
Accounts receivable, net1,049
 1,024
Inventory370
 412
Derivative instruments850
 764
Cash collateral paid in support of energy risk management activities163
 287
Prepayments and other current assets277
 302
Current assets - held-for-sale—
 1
Current assets - discontinued operations—
 197
Total current assets3,045
 3,600
Property, plant and equipment, net2,610
 3,048
Other Assets   
Equity investments in affiliates383
 412
Operating lease right-of-use assets, net499
 —
Goodwill573
 573
Intangible assets, net561
 591
Nuclear decommissioning trust fund748
 663
Derivative instruments426
 317
Deferred income taxes55
 46
Other non-current assets271
 289
Non-current assets - held-for-sale—
 77
Non-current assets - discontinued operations—
 1,012
Total other assets3,516
 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 liabilities74
 —
Accounts payable723
 863
Derivative instruments778
 673
Cash collateral received in support of energy risk management activities31
 33
Accrued expenses and other current liabilities601
 680
Current liabilities - held-for-sale—
 5
Current liabilities - discontinued operations—
 72
Total current liabilities2,294
 2,398
Other Liabilities   
Long-term debt and capital leases5,794
 6,449
Non-current operating lease liabilities513
 —
Nuclear decommissioning reserve290
 282
Nuclear decommissioning trust liability448
 371
Derivative instruments374
 304
Deferred income taxes71
 65
Other non-current liabilities1,016
 1,274
Non-current liabilities - held-for-sale—
 65
Non-current liabilities - discontinued operations—
 635
Total other liabilities8,506
 9,445
Total Liabilities10,800
 11,843
Redeemable noncontrolling interest in subsidiaries19
 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, respectively4
 4
Additional paid-in-capital8,488
 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

June 30, 2018
December 31, 2017
(In millions, except shares)(Unaudited)  
ASSETS

 
Current Assets 

Cash and cash equivalents$980

$991
Funds deposited by counterparties71

37
Restricted cash286

508
Accounts receivable, net1,371

1,079
Inventory485

532
Derivative instruments851

626
Cash collateral paid in support of energy risk management activities224

171
Accounts receivable - affiliate57

95
Current assets - held for sale100

115
Prepayments and other current assets328

261
Total current assets4,753

4,415
Property, plant and equipment, net12,774

13,908
Other Assets 
 
Equity investments in affiliates1,055

1,038
Notes receivable, less current portion15

2
Goodwill539

539
Intangible assets, net1,860

1,746
Nuclear decommissioning trust fund694

692
Derivative instruments426

172
Deferred income taxes126

134
Non-current assets held-for-sale50

43
Other non-current assets655

629
Total other assets5,420

4,995
Total Assets$22,947

$23,318
LIABILITIES AND STOCKHOLDERS’ EQUITY 
 
Current Liabilities 
 
Current portion of long-term debt and capital leases$952

$688
Accounts payable975

881
Accounts payable - affiliate29

33
Derivative instruments709

555
Cash collateral received in support of energy risk management activities72

37
Current liabilities held-for-sale74

72
Accrued expenses and other current liabilities719

890
Accrued expenses and other current liabilities - affiliate133

161
Total current liabilities3,663

3,317
Other Liabilities 
 
Long-term debt and capital leases14,821

15,716
Nuclear decommissioning reserve274

269
Nuclear decommissioning trust liability410

415
Deferred income taxes17

21
Derivative instruments285

197
Out-of-market contracts, net195

207
Non-current liabilities held-for-sale12

8
Other non-current liabilities1,130

1,122
Total non-current liabilities17,144

17,955
Total Liabilities20,807

21,272
Redeemable noncontrolling interest in subsidiaries69

78
Commitments and Contingencies




Stockholders’ Equity


Common stock4

4
Additional paid-in capital8,481

8,376
Accumulated deficit(5,920)
(6,268)
Less treasury stock, at cost — 116,267,484 and 101,580,045 shares, at June 30, 2018 and December 31, 2017, respectively(2,871)
(2,386)
Accumulated other comprehensive loss(60)
(72)
Noncontrolling interest2,437

2,314
Total Stockholders’ Equity2,071

1,968
Total Liabilities and Stockholders’ Equity$22,947

$23,318

See accompanying notes to condensed consolidated financial statements.



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


Six months ended June 30,Six months ended June 30,
(In millions)2018
20172019 2018
Cash Flows from Operating Activities


   
Net income/(loss)$329

$(845)
Loss from discontinued operations, net of income tax(25)
(775)
Income/(loss) from continuing operations354

(70)
Adjustments to reconcile net income to net cash provided/(used) by operating activities:


Distributions and equity in earnings of unconsolidated affiliates27

26
Net Income$684
 $329
Income from discontinued operations, net of income tax401
 64
Income from continuing operations283
 265
Adjustments to reconcile net income to cash provided by operating activities:   
Distributions and equity earnings of unconsolidated affiliates22
 12
Depreciation, amortization and accretion485

517
184
 252
Provision for bad debts31

18
52
 30
Amortization of nuclear fuel24

24
27
 24
Amortization of financing costs and debt discount/premiums27

29
13
 13
Adjustment for debt extinguishment3

—
Loss on debt extinguishment, net47
 3
Amortization of intangibles and out-of-market contracts48

51
14
 20
Amortization of unearned equity compensation26

16
10
 15
Loss/(gain) on sale and disposal of assets1
 (16)
Impairment losses89

63
1
 88
Changes in derivative instruments(22) (145)
Changes in deferred income taxes and liability for uncertain tax benefits4

8
(5) (2)
Changes in collateral deposits in support of energy risk management activities125
 (9)
Changes in nuclear decommissioning trust liability41

2
17
 41
Changes in derivative instruments(211)
7
Changes in collateral deposits in support of energy risk management activities(18)
(189)
Gain on sale of emission allowances(11)
11
Gain on sale of assets(16)
(22)
Loss on deconsolidation of business22

—
Loss on deconsolidation of Ivanpah project—
 22
Changes in other working capital(401)
(379)(388) (349)
Cash provided by continuing operations524

112
381
 264
Cash used by discontinued operations—

(38)
Cash provided by discontinued operations8
 249
Net Cash Provided by Operating Activities524

74
389
 513
Cash Flows from Investing Activities 
    
Acquisitions of businesses, net of cash acquired(284)
(16)
Payments for acquisitions of businesses(21) (211)
Capital expenditures(691)
(542)(107) (282)
Decrease in notes receivable4

8
Purchases of emission allowances(22)
(30)
Proceeds from sale of emission allowances34

59
Net proceeds from sale of emission allowances(1) 3
Investments in nuclear decommissioning trust fund securities(346)
(279)(209) (346)
Proceeds from the sale of nuclear decommissioning trust fund securities303

277
191
 303
Proceeds from renewable energy grants and state rebates—

8
Proceeds from sale of assets, net of cash disposed of18

35
Deconsolidation of business(160)
—
Changes in investments in unconsolidated affiliates(2)
(30)
Other—

18
Cash used by continuing operations(1,146)
(492)
Proceeds from sale of assets, net of cash disposed and sale of discontinued operations, net of fees1,289
 146
Deconsolidation of Ivanpah project—
 (160)
Net distributions from investments in unconsolidated affiliates7
 (15)
Contributions to discontinued operations(44) (16)
Cash provided/(used) by continuing operations1,105
 (578)
Cash used by discontinued operations—

(53)(2) (584)
Net Cash Used by Investing Activities(1,146)
(545)
Net Cash Provided/(Used) by Investing Activities1,103
 (1,162)
Cash Flows from Financing Activities 

   
Payment of dividends to common and preferred stockholders(19)
(19)
Payment for treasury stock(500)
—
Net receipts from settlement of acquired derivatives that include financing elements—

2
Proceeds from issuance of long-term debt1,605

946
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 stock2
 11
Proceeds from issuance of short and long-term debt1,833
 994
Payment of debt issuance costs(33) (19)
Payments for short and long-term debt(848)
(530)(2,485) (348)
Increase in notes receivable from affiliate—

(125)
Net contributions from noncontrolling interests in subsidiaries222

14
Payment of debt issuance costs(37)
(36)
Other - contingent consideration—

(10)
Cash provided by continuing operations423

242
Cash used by discontinued operations—

(224)
Net Cash Provided by Financing Activities423

18
Effect of exchange rate changes on cash and cash equivalents—

(8)
Cash (used)/provided by continuing operations(1,763) 105
Cash provided by discontinued operations43
 345
Net Cash (Used)/Provided by Financing Activities(1,720) 450
Change in Cash from discontinued operations—

(315)49
 10
Net Decrease in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash(199)
(146)(277) (209)
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period1,536

1,386
613
 1,086
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period$1,337

$1,240
$336
 $877
See accompanying notes to condensed consolidated financial statements.


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)






















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.


NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1 — Nature of Business and Basis of Presentation
General
NRG Energy, Inc., or NRG or the Company, is a customer-driven integrated poweran energy company built on a portfolio of leadingdynamic retail electricity brands andwith 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 continuously focused on servingperfecting the energy needs of end-use residential, commercial and industrial customers in competitiveintegrated model by balancing retail load with generation supply within its deregulated markets, through multiple brands and channels.while evolving to a customer-driven business. The Company:
directlyCompany sells energy, services, and innovative, sustainable products and services directly to retail customers under the names “NRG”"NRG", “Reliant”"Reliant" and other retail brand names owned by NRG;
owns and operatesNRG, supported by approximately 30,00023,000 MW of generation;
engages in the tradinggeneration as of wholesale energy, capacity and related products; and
transacts in and trades fuel and transportation services.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 20172018 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, 2018,2019, and the results of operations, comprehensive income/(loss)income, cash flows and cash flowsstatements 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 2017.
GenOn Chapter 11 Cases
On June 14, 2017, GenOn, along with GenOn Americas GenerationDispositions, the Company concluded that the sale of its South Central Portfolio to Cleco, excluding the Cottonwood facility, met held-for-sale criteria and certain of their directly and indirectly-owned subsidiaries, or collectivelyshould be presented as discontinued operations, as the GenOn Entities, filed voluntary petitions for relief under Chapter 11, or the Chapter 11 Cases, of the U.S. Bankruptcy Code,sale, which closed on February 4, 2019, represented a strategic shift in the U.S. Bankruptcy Court for the Southern District of Texas, Houston Division, or the Bankruptcy Court. GenOn Mid-Atlantic, as well as its consolidated subsidiaries, REMA and certain other subsidiaries, did not file for relief under Chapter 11.
As a result of the bankruptcy filings and beginning on June 14, 2017, GenOn and its subsidiaries were deconsolidated from NRG’s consolidated financial statements.business in which NRG determined that this disposal of GenOn and its subsidiaries is a discontinued operation and, accordingly, theoperates. The financial information for all historical periods has been recast to reflect GenOnthe 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 discontinued operation.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. The reclassifications did not affect results from operations, net assets or cash flows.




Note 2 — Summary 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 tax13
 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 depreciation1,684
 1,811
Intangible assets accumulated amortization1,182
 1,149
Out-of-market contracts accumulated amortization—
 37
 June 30, 2018 December 31, 2017
 (In millions)
Accounts receivable allowance for doubtful accounts$28
 $28
Property, plant and equipment accumulated depreciation4,534
 4,465
Intangible assets accumulated amortization1,443
 1,818
Out-of-market contracts accumulated amortization370
 358

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 sheetsheets that sum to the total of the same such amounts shown in the statementstatements of cash flows.
 June 30, 2019 December 31, 2018
 (In millions)
Cash and cash equivalents$294
 $563
Funds deposited by counterparties31
 33
Restricted cash11
 17
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows$336
 $613
 June 30, 2018 December 31, 2017 June 30, 2017 December 31, 2016
 (In millions)
Cash and cash equivalents$980
 $991
 $752
 $938
Funds deposited by counterparties71
 37
 19
 2
Restricted cash286
 508
 469
 446
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows$1,337
 $1,536
 $1,240
 $1,386

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.
Noncontrolling Interest
The following table reflects the changes in NRG's noncontrolling interest balance:
 (In millions)
Balance as of December 31, 2017$2,314
Dividends paid to NRG Yield, Inc. public shareholders(61)
Distributions to noncontrolling interest(34)
Comprehensive income attributable to noncontrolling interest12
Non-cash adjustments to noncontrolling interest8
Contributions from noncontrolling interest295
Sale of assets to NRG Yield, Inc.(8)
Deconsolidation of Ivanpah(a)
(89)
Balance as of June 30, 2018$2,437
(a) See Note 9, Variable Interest Entities, or VIEs for further information regarding the deconsolidation of Ivanpah effective April 2018.



Redeemable Noncontrolling InterestRecent 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 following table reflectsguidance 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 changes inassets and liabilities that arise from a lease on the Company's redeemable noncontrolling interest balance:
 (In millions)
Balance as of December 31, 2017$78
Distributions to redeemable noncontrolling interest(2)
Contributions from redeemable noncontrolling interest26
Non-cash adjustments to redeemable noncontrolling interest(9)
Comprehensive loss attributable to redeemable noncontrolling interest(24)
Balance as of June 30, 2018$69
Revenue Recognition
Revenue from Contractsbalance sheet. In addition, Topic 842 expands the required quantitative and qualitative disclosures with Customers
On January 1, 2018, theregards to lease arrangements. The Company adopted the guidance in ASC 606 usingstandard and its subsequent corresponding updates effective January 1, 2019 under the modified retrospective method applied to contracts which were not completed as of the adoption date. The Company recognized the cumulative effect of initiallyapproach by applying the new standard as a credit to the opening balance of accumulated deficit, resulting in a decrease of approximately $16 million. The adjustment primarily related to costs incurred to obtain a contract with customers and customer incentives. Following the adoptionprovisions of the new standard,leases guidance at the Company’s revenue recognitioneffective date without adjusting the comparative periods presented. The Company assessed its leasing arrangements, evaluated the impact of its contractsapplying 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 customers remains materially consistenta 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 its historical practice. The comparative information has not been restated and continuesearly adoption permitted for any eliminated or modified disclosures. Certain disclosures in ASU No. 2018-13 are required to be reported underapplied on a retrospective basis and others on a prospective basis. As the accounting standardsamendment contemplates changes in effect for those periods. Thedisclosures only, it will have no material impact on the Company's policies with respect to its various revenue streamsresults of operations, cash flows, or statement of financial position.

Note 3 — Revenue Recognition
Performance Obligations
As of June 30, 2019, estimated future fixed fee performance obligations are detailed below. In general, the Company applies the invoicing practical expedient to recognize revenue$315 million for the revenue streams detailed below, except in circumstances whereremaining six months of fiscal year 2019, and $512 million, $542 million, $284 million and $29 million for the invoiced amount does not represent the value transferred to the customer.
Retail Revenues
Gross revenues for energy salesentirety of fiscal years 2020, 2021, 2022 and services to retail customers are recognized as the Company transfers the promised goods and services to the customer. For the majority of its electricity contracts, the Company’s performance obligation with the customer is satisfied over time and performance obligations for its electricity products are recognized as the customer takes possession of the product. The Company also allocates the contract consideration to distinct performance obligation in a contract for which the timing of the revenue recognized is different. Additionally, customer discounts and incentives reduce the contract consideration and are recognized over the term of the contract.
Energy sales and services that have been delivered but not billed by period end are estimated. Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter reading provided by the independent system operators or electric distribution companies. Volume estimates are based on daily forecasted volumes and estimated customer usage by class. Unbilled revenues are calculated by multiplying these volume estimates by the applicable rate by customer class. Estimated amounts are adjusted when actual usage is known and billed.
As contracts for retail electricity can be for multi-year periods, the Company has performance obligations under these contracts that have not yet been satisfied.2023, respectively. These performance obligations have transaction prices that are both fixed and variable, and that vary based on the contract duration, customer type, inception date and other contract-specific factors. For the fixed price contracts, the amount of any unsatisfied performance obligations will vary based on customer usage, which will depend on factors such as weather and customer activity and therefore it is not practicable to estimate such amounts.
Energy Revenue
Both physical and financial transactions are entered into to optimize the financial performance of the Company's generating facilities. Electric energy revenue is recognized upon transmission to the customer over time, using the output method for measuring progress of satisfaction of performance obligations. Physical transactions, or the sale of generated electricity to meet supply and demand, are recorded on a gross basis in the Company's consolidated statements of operations. The Company applies the invoicing practical expedient, where applicable, in recognizing energy revenue. Under the practical expedient, revenue is recognized based on the invoiced amount which is equal to the value to the customer of NRG’s performance obligation completed to date. Financial transactions, or the buying and selling of energy for trading purposes, are recorded net within operating revenues in the consolidated statements of operations in accordance with ASC 815.


Capacity Revenue
Capacity revenues consist of revenues billed to a third party at either the market or a negotiated contract price for making installed generation capacity available in order to satisfy system integrity and reliability requirements. Capacity revenues are recognized over time, using the output method for measuring progress of satisfaction of performance obligations. The Company applies the invoicing practical expedient, where applicable, in recognizing capacity revenue. Under the practical expedient, revenue is recognized based on the invoiced amount which is equal to the value to the customer of NRG’s performance obligation completed to date.
Capacity revenue contracts mainly consist of:
Capacity auctions — The Company's largest sources of capacity revenues are capacity auctions in PJM, ISO-NE, and NYISO. Both ISO-NE and PJM operate a pay-for-performance model where capacity payments are modified based on real-time performance, where NRG's actual revenues will be the combination of revenues based on the cleared auction MWs plus the net of any over- and under-performance of NRG's fleet. In addition, MISO has an annual auction, known as the Planning Resource Auction, or PRA. The Gulf Coast assets situated in the MISO market may participate in this auction. Estimated revenues for cleared auction MWs in the variousPJM, ISO-NE, NYISO and MISO capacity auctions and are $578 million, $519 million, $410 million, $388 million and $168 millionsubject to penalties for fiscal years 2018, 2019, 2020, 2021 and 2022, respectively.
Resource adequacy and bilateral contracts — In California, there is a resource adequacy requirement that is primarily satisfied through bilateral contracts. Such bilateral contracts are typically short-term resource adequacy contracts. When bilateral contracting does not satisfy the resource adequacy need, such shortfalls can be addressed through procurement tools administered by the CAISO, including the capacity procurement mechanism or reliability must-run contracts. Demand payments from the current long-term contracts are tied to summer peak demand and provide a mechanism for recovering a portion of the costs associated with new or changed environmental laws or regulations. In Texas, capacity and contracted revenues are through bilateral contracts with load serving entities.
Long-term PPAs — Energy, capacity and where applicable, renewable attributes, from the majority of renewable energy assets and certain conventional energy plants is sold through long-term PPAs and tolling agreements to a single counterparty, which is often a utility or commercial customer. Many of these PPAs are accounted for as leases.
Renewable Energy Credits
As stated above, renewable energy credits are usually sold through long-term PPAs. Revenue from the sale of self-generated RECs is recognized when related energy is generated and simultaneously delivered even in cases where there is a certification lag as it has been deemed to be perfunctory.
In a bundled contract to sell energy, capacity and/or self-generated RECs, all performance obligations are deemed to be delivered at the same time and hence, timing of recognition of revenue for all performance obligations is the same and occurs over time. In such cases, it is often unnecessary to allocate transaction price to multiple performance obligations.
Sale of Emission Allowances
The Company records its inventory of emission allowances as part of intangible assets. From time to time, management may authorize the transfer of emission allowances in excess of usage from the Company's emission bank to intangible assets held-for-sale for trading purposes. The Company records the sale of emission allowances on a net basis within operating revenue in the Company's consolidated statements of operations.

non performance.
 

Disaggregated Revenues     
The following table representstables 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, 2018
   Generation        
(In millions)Retail Gulf Coast East/West Subtotal Renewables NRG Yield Eliminations Total
Energy revenue(a)(b)
$—
 $508
 $144
 $652
 $79
 $192
 $(250) $673
Capacity revenue(a)(b)
—
 68
 160
 228
 —
 87
 (2) 313
Retail revenue

 

 

 

 

 

 

 
Mass customers1,380
 —
 —
 —
 —
 —
 (1) 1,379
Business solutions customers437
 —
 —
 —
 —
 —
 —
 437
Total retail revenue1,817
 —
 —
 —
 —
 —
 (1) 1,816
Mark-to-market for economic hedging activities(c)
—
 289
 (15) 274
 5
 —
 (264) 15
Contract amortization—
 4
 —
 4
 —
 (18) —
 (14)
Other revenue(a)(b)
—
 42
 18
 60
 29
 46
 (16) 119
Total operating revenue1,817
 911
 307
 1,218
 113
 307
 (533) 2,922
Less: Lease revenue6
 —
 1
 1
 96
 267
 —
 370
Less: Derivative revenue—
 898
 (1) 897
 5
 —
 (264) 638
Less: Contract amortization—
 4
 —
 4
 —
 (18) —
 (14)
Total revenue from contracts with customers$1,811
 $9
 $307
 $316
 $12
 $58
 $(269) $1,928
(a) The following amounts of energy and capacity revenue relate to leases and are accounted for under ASC 840:
 Retail Gulf Coast East/West Subtotal Renewables NRG Yield Eliminations Total
Energy revenue$—
 $—
 $—
 $—
 $90
 $182
 $—
 $272
Capacity revenue—
 —
 —
 —
 —
 85
 —
 85
Other revenue6
 —
 1
 1
 6
 —
 —
 13
(b) The following amounts of energy and capacity revenue relate to derivative instruments and are accounted for under ASC 815.
 Retail Gulf Coast East/West Subtotal Renewables NRG Yield Eliminations Total
Energy revenue$—
 $610
 $(30) $580
 $—
 $—
 $—
 $580
Capacity revenue—
 —
 39
 39
 —
 —
 —
 39
Other revenue—
 (1) 5
 4
 —
 —
 —
 4
(c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815.

 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 customers1,401
 —
 —
 —
 (1) 1,400
Business Solutions customers345
 —
 —
 —
 —
 345
Total retail revenue1,746
 —
 —
 —
 (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 revenue1,748
 973
 394
 1,367
 (650) 2,465
Less: Lease revenue3
 —
 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

Six months ended June 30, 2018Three months ended June 30, 2018
  Generation          Generation    
(In millions)Retail Gulf Coast East/West Subtotal Renewables NRG Yield Eliminations TotalRetail Texas East/West/Other Subtotal Corporate/Eliminations Total
Energy revenue(b)(c)
$—
 $879
 $362
 $1,241
 $156
 $306
 $(411) $1,292
$—
 $402
 $259
 $661
 $(251) $410
Capacity revenue(b)(c)
—
 135
 300
 435
 —
 169
 (3) 601
—
 —
 165
 165
 —
 165
Retail revenue                          
Mass customers2,551
 —
 —
 —
 —
 —
 (2) 2,549
1,377
 —
 —
 —
 (1) 1,376
Business solutions customers753
 —
 —
 —
 —
 —
 —
 753
Business Solutions customers437
 —
 —
 —
 —
 437
Total retail revenue3,304
 —
 —
 —
 —
 —
 (2) 3,302
1,814
 —
 —
 —
 (1) 1,813
Mark-to-market for economic hedging activities(c)(b)
(6) (275) (25) (300) (5) —
 220
 (91)—
 296
 (22) 274
 (264) 10
Contract amortization—
 7
 —
 7
 —
 (35) —
 (28)
Other revenue(a)(b)
—
 128
 34
 162
 48
 92
 (35) 267
Other revenues(c)
—
 10
 57
 67
 (4) 63
Total operating revenue3,298
 874
 671
 1,545
 199
 532
 (231) 5,343
1,814
 708
 459
 1,167
 (520) 2,461
Less: Lease revenue12
 —
 2
 2
 160
 448
 —
 622
3
 —
 2
 2
 —
 5
Less: Derivative revenue(6) 710
 79
 789
 (5) —
 220
 998
Less: Contract amortization—
 7
 —
 7
 —
 (35) —
 (28)
Less: Realized and unrealized ASC 815 revenue(a)
—
 865
 48
 913
 (511) 402
Total revenue from contracts with customers$3,292
 $157
 $590
 $747
 $44
 $119
 $(451) $3,751
$1,811
 $(157) $409
 $252
 $(9) $2,054
(a) The following amounts of energy and capacity revenue relate to leases and are accounted for under ASC 840:
(a) Generation includes higher revenues due to the Company's large internal transfer of power based on average annualized market prices, which are offset by higher(a) Generation includes higher revenues due to the Company's large internal transfer of power based on average annualized market prices, which are offset by higher
cost of operations within Retail cost of operations within Retail
(b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815(b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815
(c) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 which are included in the amounts above:(c) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 which are included in the amounts above:
Retail Gulf Coast East/West Subtotal Renewables NRG Yield Eliminations TotalRetail Texas East/West/Other Subtotal Corporate/Eliminations Total
Energy revenue$—
 $—
 $—
 $—
 $151
 $284
 $—
 $435
$—
 $569
 $26
 $595
 $(247) $348
Capacity revenue—
 —
 —
 —
 —
 164
 —
 164
—
 —
 39
 39
 —
 39
Other revenue12
 —
 2
 2
 9
 —
 —
 23
—
 —
 5
 5
 —
 5
(b) The following amounts of energy and capacity revenue relate to derivative instruments and are accounted for under ASC 815.
Retail Gulf Coast East/West Subtotal Renewables NRG Yield Eliminations Total
Energy revenue$—
 $981
 $31
 $1,012
 $—
 $—
 $—
 $1,012
Capacity revenue—
 —
 65
 65
 —
 —
 —
 65
Other revenue—
 4
 8
 12
 —
 —
 —
 12
(c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815.
Contract Amortization
Assets and liabilities recognized from power sales agreements assumed at Fresh Start and through acquisitions related to the sale of electric capacity and energy in future periods for which the fair value has been determined to be significantly less (more) than market are amortized to revenue over the term of each underlying contract based on actual generation and/or contracted volumes.
Lease Revenue
 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 customers2,722
 —
 —
 —
 (2) 2,720
Business Solutions customers631
 —
 —
 —
 —
 631
Total retail revenue3,353
 —
 —
 —
 (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 revenue3,355
 1,373
 817
 2,190
 (915) 4,630
Less: Lease revenue6
 —
 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
Certain of the Company’s revenues are obtained through PPAs or other contractual agreements. Many of these agreements are accounted for as operating leases under ASC 840 Leases. Certain of these leases have no minimum lease payments and all of the rent is recorded as contingent rent on an actual basis when the electricity is delivered. Judgment is required by management in determining the economic life of each generating facility, in evaluating whether certain lease provisions constitute minimum payments or represent contingent rent and other factors in determining whether a contract contains a lease and whether the lease is an operating lease or capital lease.

 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 customers2,553
 —
 —
 —
 (2) 2,551
Business Solutions customers747
 —
 —
 —
 —
 747
Total retail revenue3,300
 —
 —
 —
 (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 revenue3,294
 457
 981
 1,438
 (206) 4,526
Less: Lease revenue7
 —
 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, 2018June 30, 2019 December 31, 2018
Deferred customer acquisition costs $102
$123
 $111
   
Accounts receivable, net - Contracts with customers 1,187
1,015
 999
Accounts receivable, net - Leases 152
Accounts receivable, net - Derivative instruments 32
43
 20
Accounts receivable, net - Affiliate4
 5
Total accounts receivable, net $1,371
$1,062
 $1,024
   
Unbilled revenues (included within Accounts receivable, net - Contracts with customers) 445
$403
 $392
Deferred revenues 73
Deferred revenues(a)
89
 67
The Company’s customer acquisition costs consist of broker fees, commission payments and other costs that represent incremental costs of obtaining the contract(a) Deferred revenues from contracts with customers for which the Company expectssix 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 recover. The Company amortizes these amounts over the estimated life of the customer contract. As a practical expedient, the Company expenses the incremental costs of obtaining a contract if the amortization period of the asset would have been one year or less.
When the Company receives consideration from the customer that is in excess of the amount due, such consideration is reclassified to deferred revenue which represents a contract liability. Generally,balance at the Company will recognizebeginning of each period was $13 million and $16 million, respectively. The revenue from contract liabilities in the next period as the Company satisfies its performance obligations.
Recent Accounting Developments - Guidance Adopted in 2018
ASU 2017-07 — In March 2017, the FASB issued ASU No. 2017-07, Compensation - Retirement Benefits (Topic 715), Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, or ASU No. 2017-07.   Current GAAP does not indicate where the amount of net benefit cost should be presented in an entity’s income statement and does not require entities to disclose the amount of net benefit cost that is included in the income statement. The amendments of ASU No. 2017-07 require an entity to report the service cost component of net benefit costs in the same line item as other compensation costs arising from services rendered by the related employeesrecognized during the applicable service period. The other componentsthree months ended June 30, 2019 and 2018, relating to the deferred revenue balance at the beginning of net benefit cost are required to be presented separately from the service cost component and outside the subtotal of income from operations. Further, ASU No. 2017-07 prescribes that only the service cost component of net benefit costs is eligible for capitalization. The Company adopted the amendments of ASU No. 2017-07 effective January 1, 2018. In connection with the adoption of the standard, the Company has applied the guidance retrospectively which resulted in an increase in cost of operations of $4each period was $19 million and $8$16 million, with a corresponding increaserespectively. The change in other income, net on the statement of operations fordeferred revenue balances during the three and six months ended June 30, 2017, respectively.
ASU 2016-01 - In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition2019 and Measurement of Financial Assets and Financial Liabilities, or ASU No. 2016-01. The amendments of ASU No. 2016-01 eliminate available-for-sale classification of equity investments and require that equity investments (except those accounted for under the equity method of accounting, or those that result in consolidation of the investee) be generally measured at fair value with changes in fair value recognized in net income. Further, the amendments require that financial assets and financial liabilities be presented separately in the notes2018 was primarily due to the financial statements, grouped by measurement categorytiming difference of when consideration was received and form of financial asset. The guidance in ASU No. 2016-01 is effective for financial statements issued for fiscal years beginning after December 15, 2017, and interim periods within those annual periods. The Company adoptedwhen the amendments of ASU No. 2016-01 effective January 1, 2018. In connection with the adoption of the standard, the Company has applied the guidance on a modified retrospective basis, which resulted in no material adjustments recorded to the consolidated results of operations, cash flows, and statement of financial position.performance obligation was transferred.


Recent Accounting Developments - Guidance Not Yet Adopted
ASU 2016-02 — In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), or Topic 842, with the objective to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and to improve financial reporting by expanding the related disclosures. The guidance in Topic 842 provides that a lessee that may have previously accounted for a lease as an operating lease under current GAAP should recognize the assets and liabilities that arise from a lease on the balance sheet. In addition, Topic 842 expands the required quantitative and qualitative disclosures with regards to lease arrangements. The Company will adopt the standard effective January 1, 2019, and expects to elect certain of the practical expedients permitted, including the expedient that permits the Company to retain its existing lease assessment and classification. The Company is currently working through an adoption plan which includes the evaluation of lease contracts compared to the new standard. While the Company is currently evaluating the impact the new guidance will have on its financial position and results of operations, the Company expects to recognize lease liabilities and right of use assets. The extent of the increase to assets and liabilities associated with these amounts remains to be determined pending the Company’s review of its existing lease contracts and service contracts which may contain embedded leases. While this review is still in process, NRG believes the adoption of Topic 842 will have a material impact on its financial statements. The Company is also monitoring recent changes to Topic 842 and the related impact on the implementation process.

Note 34 — Acquisitions, Discontinued Operations and Dispositions
This footnote should be read in conjunction with the complete description under Note 3, Discontinued Operations, Acquisitions and Dispositions, to the Company's 2017 Form 10-K.
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 approximately $219$213 million in cash, inclusive of approximately $54 million in payments for estimated working capital, which is subject to further adjustment.cash. The acquisition increased NRG's retail portfolio by approximately 395,000 RCEs or 300,000 customers. The purchase price was provisionally allocated as follows: $2
 (In millions)
Net current and non-current working capital$46
Other intangible assets133
Goodwill34
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 tax1
 —
 28
 —
Gain from discontinued operations, including disposal, net of tax$1
 $16
 $36
 $32


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 $8consideration, 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.

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 Fees27
 —
 27
 —
Gain on disposal of discontinued operations, net of tax10
 —
 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 restrictedNRG Yield, Inc. Prior to Discontinued Operations
On June 19, 2018, the Company completed the UPMC Thermal Project and received cash $46consideration 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 accounts receivable,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, to derivative assets, $169 million to customer relationshipsexcluding working capital adjustments, and contracts, $26 million to current and non-current assets, $25 million to accounts payable, $31 million to derivative liabilities, and $18 million to current and non-current liabilities.assumed non-recourse debt of $183 million.
Discontinued OperationsGenOn
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 has concluded that it no longer controlscontrolled GenOn as it iswas subject to the control of the Bankruptcy Court; and, accordingly, NRG no longer consolidatesdeconsolidated GenOn for financial reporting purposes.purposes as of June 14, 2017.

By eliminating a large portion of its operations in the PJM market with the deconsolidation of GenOn, NRG has concluded that GenOn meetsmet the criteria for discontinued operations, as this representsrepresented a strategic shift in the marketsbusiness in which NRG operates. As such, all prior period results for GenOn have beenwere 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)
Other2
 (27) 2
 (27)
Gain/(loss) from discontinued operations, net of tax$2
 $(25) $2
 $(25)
 Three months ended June 30, 2018 Period from April 1, 2017 through June 14, 2017 Six months ended June 30, 2018 Period from January 1, 2017 through June 14, 2017
(In millions)   
Operating revenues$—
 $265
 $—
 $646
Operating costs and expenses—
 (327) —
 (700)
Other expenses—
 (54) —
 (98)
Loss from operations of discontinued components, before tax—
 (116) —
 (152)
Income tax expense—
 8
 —
 9
Loss from operations of discontinued components—
 (124) —
 (161)
Interest income - affiliate2
 3
 3
 6
Loss from operations of discontinued components, net of tax2
 (121) 3
 (155)
Pre-tax loss on deconsolidation—
 (208) —
 (208)
Settlement consideration and services credit—
 (289) —
 (289)
Pension and post-retirement liability assumption1
 (119) 1
 (119)
Advisory and consulting fees(1) (4) (2) (4)
Other(27) —
 (27) —
Loss on disposal of discontinued components, net of tax(27) (620) (28) (620)
Loss from discontinued operations, net of tax$(25) $(741) $(25) $(775)
        

GenOn Settlement
Effective July 16, 2018, NRG and GenOn consummated the GenOn Settlement which accelerated certain terms contemplated by the plan of reorganization, as further described below. As a result,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, and (iv) certain other balances due$4 million reduction of the settlement payment related to NRG totaling $6 million. As of June 30, 2018, the Company had reserved for all amounts deemed to be uncollectible.
In order to facilitate the consummation of the GenOn Settlement, among other items, NRG assignedassigning to GenOn approximately $8 million of historical claims against REMA in exchange for $4.2 million, which was credited as a reduction of the settlement payment. GenOn also indemnifiedand (v) certain other balances due to NRG for any potential claims by REMA up to the amount of $10 million, and posted a letter of credit in that amount in favor of NRG as security for the indemnification. Other than those obligations which survive or are independent of the releases described herein, the GenOn Settlement provides NRG releases from GenOn and each of its debtor and non-debtor subsidiaries, excluding REMA.totaling $2 million.
Restructuring Support Agreement
Prior to the filing of GenOn's bankruptcy case, NRG, GenOn and certain holders representing greater than 93% in aggregate principal amount of GenOn’s Senior Notes and certain holders representing greater than 93% in aggregate principal amount of GenOn Americas Generation’s Senior Notes entered into a Restructuring Support Agreement that provided for a restructuring and recapitalization of the GenOn Entities through a prearranged plan of reorganization. In December 2017, the Bankruptcy Court approved the plan of reorganization, pursuant to an order of confirmation. Consummation of the plan of reorganization has not yet occurred and remains subject to the satisfaction or waiver of certain conditions precedent. Certain principal terms of the plan of reorganization are detailed below:
1)The dismissal of certain prepetition litigation and full releases from GenOn and each of its debtor and non-debtor subsidiaries in favor of NRG, excluding REMA.
2)
NRG provided settlement cash consideration to GenOn of $261.3 million, paid in cash less amounts owed to NRG under the intercompany secured revolving credit facility. As of June 30, 2018, GenOn owed NRG approximately $151 million under the intercompany secured revolving credit facility, plus interest and fees accrued thereon. See Note 14, Related Party Transactions for further discussion of the intercompany secured revolving credit facility. The net liability for these amounts, along with the services credit described below, is recorded in accrued expenses and other current liabilities - affiliate as of June 30, 2018 and December 31, 2017.


3)NRG will retain the pension liability, including payment of approximately $13 million of 2017 pension contributions, for GenOn employees for service provided prior to the completion of the reorganization, which was paid in September 2017. GenOn’s pension liability as of June 30, 2018, was approximately $90 million. NRG will also retain the liability for GenOn’s post-employment and retiree health and welfare benefits, in an amount up to $25 million. These liabilities are recorded within other non-current liabilities as of June 30, 2018 and December 31, 2017.
4)
The shared services agreement between NRG and GenOn was terminated and replaced as of the plan confirmation date with a transition services agreement. Under the transition services agreement, NRG provided the shared services and other separation services at an annualized rate of $84 million, subject to certain credits and adjustments. See Note 14, Related Party Transactions, for further discussion of the Services Agreement.
5)NRG provided a credit of $28 million to GenOn to apply against amounts owed under the transition services agreement. The unused credit of approximately $18 million was paid in cash to GenOn. The credit was intended to reimburse GenOn for its payment of financing costs.
6)NRG and GenOn also agreed to cooperate in good faith to maximize the value of certain development projects. Pursuant to this, GenOn made a one-time payment in the amount of $15 million to NRG in December 2017 as compensation for a purchase option with respect to the Canal 3 project. During the second quarter of 2018, NRG sold Canal 3 to Stonepeak Kestrel Holdings II LLC, or Stonepeak Kestrel, in conjunction with GenOn's sale of Canal Units 1 and 2 to Stonepeak Kestrel Holdings LLC. NRG reimbursed GenOn for $13.5 million of the one-time payment upon the closing of the sale of Canal 3.
GenMA Settlement
The Bankruptcy Court order confirming the plan of reorganization also approved the settlement terms agreed to among the GenOn Entities, NRG, the Consenting Holders, GenOn Mid-Atlantic, and certain of GenOn Mid-Atlantic’sMid-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 and effective 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$37.5 million in letters of credit as new qualifying credit support to GenOn Mid-Atlantic; and
NRG paid approximately $6 million as reimbursement of professional fees incurred by certain of GenOn Mid-Atlantic'sMid- 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 approximately $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 iswas 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.
In addition, theThe Company completed other asset sales for $7 million of cash proceeds inof $18 million and $16 million during the first half of 2018.six months ended June 30, 2019 and 2018, respectively.
Transfers of Assets Under Common Control
On June 19, 2018, the Company completed the sale of the substantially completed assets of the UPMC Thermal Project to NRG Yield, Inc. for cash consideration of $84 million, subject to working capital adjustments.
On March 30, 2018, as part of the Transformation Plan, 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 approximately $42 million, excluding working capital adjustments, and assumed non-recourse debt of approximately $183 million. Concurrently, an initial contribution of approximately $19 million was received from the third-party investor in the underlying tax equity partnership, which is included in noncontrolling interest.
On March 27, 2017, the Company sold to NRG Yield, Inc.: (i) a 16% interest in the Agua Caliente solar project, representing ownership of approximately 46 net MW of capacity and (ii) NRG's interests in seven utility-scale solar projects located in Utah representing 265 net MW of capacity, which have reached commercial operations. NRG Yield, Inc. paid cash consideration of $130 million, plus $1 million in working capital adjustments, and assumed non-recourse debt of approximately $328 million.


Note 45 — Fair Value of Financial Instruments
This footnote should be read in conjunction with the complete description under Note 4, Fair Value of Financial Instruments, to the Company's 2017 Form 10-K.
For cash and cash equivalents, funds deposited by counterparties, accounts and other receivables, accounts payable, restricted cash, and cash collateral paid and received in support of energy risk management activities, the carrying amount approximatesamounts approximate fair valuevalues because of the short-term maturity of those instruments and are classified as Level 1 within the fair value hierarchy.

The estimated carrying amounts and fair values of NRG's recorded financial instruments not carried at fair market value are as follows:
 As of 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
 As of June 30, 2018 As of December 31, 2017
 Carrying Amount Fair Value Carrying Amount Fair Value
 (In millions)
Assets:       
Notes receivable (a)
$21
 $18
 $16
 $15
Liabilities:       
Long-term debt, including current portion (b)
15,969
 16,163
 16,603
 16,894

(a) Includes the current portion of notes receivable which is recorded in prepayments and other current assets on the Company's consolidated balance sheets.
(b) Excludes deferred financing costs, which are recorded as a reduction to long-term debt on the Company's consolidated balance sheets.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, 20182019 and December 31, 2017:2018:
 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

 As of June 30, 2018 As of December 31, 2017
 Level 2 Level 3 Level 2 Level 3
 (In millions)
Long-term debt, including current portion$9,586
 $6,577
 $8,934
 $7,960




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 equivalents25
 25
 —
 —
U.S. government and federal agency obligations57
 57
 —
 —
Federal agency mortgage-backed securities92
 —
 92
 —
Commercial mortgage-backed securities29
 —
 29
 —
Corporate debt securities102
 —
 102
 —
Equity securities366
 366
 —
 —
Foreign government fixed income securities4
 —
 4
 —
Other trust fund investments:       
U.S. government and federal agency obligations1
 1
 —
 —
Derivative assets:       
Commodity contracts1,276
 131
 770
 375
Measured using net asset value practical expedient:       
Equity securities — nuclear trust fund investments73
 

 

 

       Equity securities9
      
Total assets$2,072
 $580
 $1,016
 $394
Derivative liabilities:       
Commodity contracts$1,152
 $245
 $629
 $278
Total liabilities$1,152
 $245
 $629
 $278

 As of June 30, 2018
 Fair Value
(In millions)Total Level 1 Level 2 Level 3
Investments in securities (classified within other non-current assets)$22
 $3
 $—
 $19
Nuclear trust fund investments:       
Cash and cash equivalents25
 25
 —
 —
U.S. government and federal agency obligations42
 42
 —
 —
Federal agency mortgage-backed securities97
 —
 97
 —
Commercial mortgage-backed securities16
 —
 16
 —
Corporate debt securities101
 —
 101
 —
Equity securities342
 342
 —
 —
Foreign government fixed income securities6
 —
 6
 —
Other trust fund investments:       
U.S. government and federal agency obligations1
 1
 —
 —
Derivative assets:       
Commodity contracts1,169
 188
 481
 500
Interest rate contracts108
 —
 108
 —
Measured using net asset value practical expedient:       
Equity securities — nuclear trust fund investments65
 

 

 

Total assets$1,994
 $601
 $809
 $519
Derivative liabilities:       
Commodity contracts971
 236
 388
 347
Interest rate contracts23
 —
 23
 —
Total liabilities$994
 $236
 $411
 $347


 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 equivalents19
 19
 —
 —
U.S. government and federal agency obligations46
 46
 —
 —
Federal agency mortgage-backed securities100
 —
 100
 —
Commercial mortgage-backed securities22
 —
 22
 —
Corporate debt securities96
 —
 96
 —
Equity securities312
 312
 —
 —
Foreign government fixed income securities4
 —
 4
 —
Other trust fund investments:       
U.S. government and federal agency obligations1
 1
 —
 —
Derivative assets:       
Commodity contracts1,042
 137
 796
 109
Interest rate contracts39
 —
 39
 —
Measured using net asset value practical expedient:       
Equity securities — nuclear trust fund investments64
      
       Equity securities8
      
Total assets$1,792
 $517
 $1,075
 $128
Derivative liabilities:       
Commodity contracts$977
 $224
 $664
 $89
Total liabilities$977
 $224
 $664
 $89

 As of December 31, 2017
 Fair Value
(In millions)Total Level 1 Level 2 Level 3
Investments in securities (classified within other non-current assets)$22
 $3
 $—
 $19
Nuclear trust fund investments:       
Cash and cash equivalents47
 45
 2
 —
U.S. government and federal agency obligations43
 42
 1
 —
Federal agency mortgage-backed securities82
 —
 82
 —
Commercial mortgage-backed securities14
 —
 14
 —
Corporate debt securities99
 —
 99
 —
Equity securities334
 334
 —
 —
Foreign government fixed income securities5
 —
 5
 —
Other trust fund investments:       
U.S. government and federal agency obligations1
 1
 —
 —
Derivative assets:       
Commodity contracts745
 191
 509
 45
Interest rate contracts53
 —
 53
 —
Measured using net asset value practical expedient:       
Equity securities — nuclear trust fund investments68
      
Total assets$1,513
 $616
 $765
 $64
Derivative liabilities:       
Commodity contracts693
 257
 359
 77
Interest rate contracts59
 —
 59
 —
Total liabilities$752
 $257
 $418
 $77




There were no transfers during the three and six months ended June 30, 20182019 and 20172018 between Levels 1 and 2. The following tables reconcile, for the three and six months ended June 30, 20182019 and 2017,2018, 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, 2018 Six months ended June 30, 2018
(In millions)Debt Securities 
Derivatives(a)
 Total Debt Securities 
Derivatives(a)
 Total
Beginning balance$19
 $(22) $(3) $19
 $(32) $(13)
Contracts acquired in Xoom acquisition—
 12
 12
 —
 12
 12
Total losses — realized/unrealized:    

     

Included in earnings—
 (21) (21) —
 (19) (19)
Purchases—
 (4) (4) —
 (3) (3)
Transfers into Level 3 (b)
—
 193
 193
 —
 197
 197
Transfers out of Level 3 (b)
—
 (5) (5) —
 (2) (2)
Ending balance as of June 30, 2018$19
 $153
 $172
 $19
 $153
 $172
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—
 20
 20
 —
 17
 17
 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 earnings1
 (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.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 2.2

 Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
 Three months ended June 30, 2017 Six months ended June 30, 2017
(In millions)Debt Securities 
Derivatives(a)
 Total Debt Securities 
Derivatives(a)
 Total
Beginning balance$18
 $(56) $(38) $17
 $(68) $(51)
Total gains — realized/unrealized:           
Included in earnings—
 40
 40
 1
 46
 47
Included in nuclear decommissioning obligation—
 —
 —
 —
 —
 —
Purchases—
 5
 5
 —
 9
 9
Transfers into Level 3 (b)
—
 3
 3
 —
 (5) (5)
Transfers out of Level 3 (b)
—
 (3) (3) —
 7
 7
Ending balance as of June 30, 2017$18
 $(11) $7
 $18
 $(11) $7
Gains 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, 2017—
 22
 22
 —
 7
 7
 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.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 2.2






Derivative Fair Value Measurements
A portion of NRG's contracts are exchange-traded contracts with readily available quoted market prices. A majority of NRG's contracts are non-exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter and on-line exchanges. The remainder of the assets and liabilities represent contracts for which external sources or observable market quotes are not available for the whole term or for certain delivery months or the contracts are retail and load following power contracts.available. These contracts are valued usingbased on various valuation techniques including, but not limited to, internal models that applybased on a fundamental analysis of the market and corroborationextrapolation of the observable market data with similar markets.characteristics. As of June 30, 20182019, contracts valued with prices provided by models and other valuation techniques make up 39%29% of the total derivative assets and 35%24% of the total derivative liabilities.
NRG's significant positions classified as Level 3 include physical and financial power executed in illiquid markets as well as financial transmission rights, or FTRs. The significant unobservable inputs used in developing fair value include illiquid power location pricing which is derived as a basis to liquid locations. The basis spread is based on observable market data when available or derived from historic prices and forward market prices from similar observable markets when not available. For FTRs, NRG uses the most recent auction prices to derive the fair value.

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, 20182019 and December 31, 2017:2018:
Significant Unobservable Inputs
June 30, 2018June 30, 2019
Fair Value Input/RangeFair Value Input/Range
Assets Liabilities Valuation Technique Significant Unobservable Input Low High Weighted AverageAssets Liabilities Valuation Technique Significant Unobservable Input Low High Weighted Average
(In millions)      (In millions)      
Power Contracts$481
 $330
 Discounted Cash Flow Forward Market Price (per MWh) $6
 $198
 $35
$347
 $261
 Discounted Cash Flow Forward Market Price (per MWh) $4
 $142
 $25
FTRs19
 17
 Discounted Cash Flow Auction Prices (per MWh) (48) 47
 —
28
 17
 Discounted Cash Flow Auction Prices (per MWh) (134) 52
 0
$500
 $347
      $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
FTRs20
 14
 Discounted Cash Flow Auction Prices (per MWh) (90) 34
 0
 $109
 $89
          

 Significant Unobservable Inputs
 December 31, 2017
 Fair Value   Input/Range
 Assets Liabilities Valuation Technique Significant Unobservable Input Low High Weighted Average
 (In millions)          
Power Contracts$34
 $65
 Discounted Cash Flow Forward Market Price (per MWh) $10
 $142
 $33
FTRs11
 12
 Discounted Cash Flow Auction Prices (per MWh) (28) 46
 —
 $45
 $77
          
The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable inputs as of June 30, 20182019 and December 31, 2017:2018:
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, 2018,2019 the credit reserve resulted in a $4$2 million decrease in fair value which is composedcost of a $1 million loss in OCI and a $3 million loss in interest expense.operations. As of December 31, 2017,2018, the credit reserve resulteddid not result in noa 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 20172018 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.

Counterparty Credit Risk
The Company's counterparty credit risk policies are disclosed in its 20172018 Form 10-K. As of June 30, 20182019, the Company's counterparty credit exposure, excluding credit risk exposure underfrom RTOs, ISOs, registered commodity exchanges and certain long termlong-term agreements, was $289$273 million with net exposure of $112 million. and NRG held collateral (cash and letters of credit) against those positions of $246$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 77%60% of the Company's exposure before collateral is expected to roll off by the end of 2019.2020. 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 other7684%
Financial institutions2416

Total as of June 30, 20182019100%
 
Net Exposure (a) (b)
Category by Counterparty Credit Quality(% of Total)
Investment grade7653%
Non-InvestmentNon-investment grade/Non-Ratednon-rated2447

Total as of June 30, 20182019100%
(a)Counterparty credit exposure excludes uranium and coal transportation contracts because of the unavailability of market prices.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.long-term contracts
NRGThe Company currently has counterparty credit risk$33 million in exposure to certain counterparties, eachone wholesale counterparty in excess of which represent more than 10% of total net exposure discussed above. The aggregate of such counterparties' exposure was $49 millionabove as of June 30, 2018.2019. 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 the Company'sits 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 NYMEX.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 TermLong-Term Contracts
Counterparty credit exposure described above excludes credit risk exposure under certain long term agreements, including California tolling agreements, Gulf Coast load obligations, and wind andlong-term contracts, primarily solar PPAs. As external sources or observable market quotes are not available to estimate such exposure, the Company estimates its credit exposure forvalues 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, 2018,2019, aggregate credit risk exposure managed by NRG to these counterparties was approximately $4.1 billion,$524 million for the next five years, including $2.5 billion relatedexposure to assetsPG&E as described below.

NRG, through its unconsolidated affiliates Ivanpah and Agua Caliente, has exposure to PG&E of NRG Yield, Inc.,approximately $337 million for the next five years. This amount excludes potential credit exposuresAs 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 projects with long-term PPAs that have not reached commercial operations. The majority of these power contracts are with utilitiesUsing the Equity Method and Variable Interest Entities, or public power entities with strong credit quality and public utility commission or other regulatory support. However, such regulated utility counterparties can be impacted by changes in government regulations or treatment by regulatory agencies which NRG is unable to predict.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, 20182019, 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 56 — Nuclear Decommissioning Trust Fund
This footnote should be read in conjunction with the complete description under Note 6, Nuclear Decommissioning Trust Fund, to the Company's 2017 Form 10-K.
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 (including other-than-temporary impairments) for the securities held in the trust funds, as well as information about the contractual maturities of those securities.
 As of 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 obligations57
 4
 —
 12
 46
 1
 —
 12
Federal agency mortgage-backed securities92
 2
 —
 24
 100
 1
 2
 23
Commercial mortgage-backed securities29
 1
 1
 23
 22
 —
 1
 22
Corporate debt securities102
 5
 —
 11
 96
 1
 2
 11
Equity securities439
 291
 —
 —
 376
 231
 1
 —
Foreign government fixed income securities4
 —
 —
 8
 4
 —
 —
 9
Total$748
 $303
 $1
   $663
 $234
 $6
  
 As of June 30, 2018 As of December 31, 2017
(In millions, except otherwise noted)Fair Value Unrealized Gains Unrealized Losses Weighted-average Maturities (In years) Fair Value Unrealized Gains Unrealized Losses Weighted-average Maturities (In years)
Cash and cash equivalents$25
 $—
 $—
 —
 $47
 $—
 $—
 —
U.S. government and federal agency obligations42
 1
 —
 14
 43
 1
 —
 11
Federal agency mortgage-backed securities97
 —
 3
 23
 82
 1
 1
 23
Commercial mortgage-backed securities16
 —
 1
 22
 14
 —
 —
 20
Corporate debt securities101
 1
 2
 10
 99
 2
 1
 11
Equity securities407
 272
 —
 —
 402
 272
 —
 —
Foreign government fixed income securities6
 —
 —
 8
 5
 —
 —
 9
Total$694
 $274
 $6
   $692
 $276
 $2
  



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 securities191

303

 Six months ended June 30,
 2018 2017
 (In millions)
Realized gains$7
 $3
Realized losses6
 3
Proceeds from sale of securities$303

$277



Note 67 — Accounting for Derivative Instruments and Hedging Activities
This footnote should be read in conjunction with the complete description under Note 5, Accounting for Derivative Instruments and Hedging Activities, to the Company's 2017 Form 10-K.
Energy-Related Commodities
As of June 30, 20182019, NRG had energy-related derivative instruments extending through 2031.2034. 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 iswas 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 entersentered into interest rate swap agreements. As of June 30, 20182019, NRG had no interest rate derivative instruments on recourse debt extending through 2021, which are not designated as cash flow hedges. The Company had interest rate swaps on non-recourse debt extending through 2041, a portionresult of which are designated as cash flow hedges.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, 20182019 and December 31, 20172018. 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
CategoryUnits(In millions)
EmissionsShort Ton1
 (2)
Renewable Energy CertificatesCertificates1
 1
CoalShort Ton7
 13
Natural GasMMBtu(238) (330)
OilBarrels—
 1
PowerMWh21
 1
CapacityMW/Day(1) (1)
InterestDollars$—
 $1,000
  Total Volume
  June 30, 2018 December 31, 2017
CategoryUnits(In millions)
EmissionsShort Ton2
 1
CoalShort Ton12
 21
Natural GasMMBtu(551) (17)
PowerMWh16
 14
CapacityMW/Day(1) (1)
InterestDollars$4,016
 $3,876
EquityShares—
 1
The increasedecrease 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.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 current850
 747
 778

673
Commodity contracts long-term426
 295
 374

304
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges$1,276
 $1,081
 $1,152

$977
 Fair Value
 Derivative Assets Derivative Liabilities
 June 30, 2018 December 31, 2017 June 30, 2018 December 31, 2017
 (In millions)
Derivatives Designated as Cash Flow or Fair Value Hedges:
   

 
Interest rate contracts current$3
 $1
 $2

$5
Interest rate contracts long-term23
 11
 5

11
Total Derivatives Designated as Cash Flow or Fair Value Hedges26
 12
 7

16
Derivatives Not Designated as Cash Flow or Fair Value Hedges:
    
 
Interest rate contracts current16
 9
 5

15
Interest rate contracts long-term66
 32
 11

28
Commodity contracts current832
 616
 702

535
Commodity contracts long-term337
 129
 269

158
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges1,251
 786
 987

736
Total Derivatives$1,277

$798
 $994

$752



The Company has elected to present derivative assets and liabilities on the balance sheet on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. In addition, collateral received or paid on the Company's derivative assets or liabilities are recorded on a separate line item on the balance sheet. The following table summarizes the offsetting of derivatives by counterparty master agreement level and collateral received or paid:
 Gross Amounts Not Offset in the Statement of Financial Position Gross Amounts Not Offset in the June 30, 2019 Balance Sheet
 Gross Amounts of Recognized Assets / Liabilities Derivative Instruments Cash Collateral (Held) / Posted Net Amount Gross Amounts of Recognized Assets / Liabilities Derivative Instruments Cash Collateral (Held) / Posted Net Amount
As of June 30, 2018 (In millions)
 (In millions)
Commodity contracts:                
Derivative assets $1,169
 $(817) $(50) $302
 $1,276
 $(1,029) $(10) $237
Derivative liabilities (971) 817
 98
 (56) (1,152) 1,029
 58
 (65)
Total commodity contracts 198
 —
 48
 246
 $124
 $—
 $48
 $172
Interest rate contracts:        
Derivative assets 108
 (3) —
 105
Derivative liabilities (23) 3
 —
 (20)
Total interest rate contracts 85
 —
 —
 85
Total derivative instruments $283
 $—
 $48
 $331
  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
  Gross Amounts Not Offset in the Statement of Financial Position
  Gross Amounts of Recognized Assets / Liabilities Derivative Instruments Cash Collateral (Held) / Posted Net Amount
As of December 31, 2017 (In millions)
Commodity contracts:       
Derivative assets $745
 $(578) $(11) $156
Derivative liabilities (693) 578
 73
 (42)
Total commodity contracts 52
 —
 62
 114
Interest rate contracts:       
Derivative assets 53
 (3) —
 50
Derivative liabilities (59) 3
 —
 (56)
Total interest rate contracts (6) —
 —
 (6)
Total derivative instruments $46
 $—
 $62

$108

Accumulated Other Comprehensive Loss
The following table summarizes the effects of ASC 815 on the Company's accumulated OCIOCL 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 amounts3
 7
Mark-to-market of cash flow hedge accounting contracts5
 24
Accumulated OCL ending balance, net of $5 tax$(23)
$(23)
 Interest Rate Contracts
 Three months ended June 30, Six months ended June 30,
 2018 2017 2018 2017
 (In millions)
Accumulated OCI beginning balance$(31) $(61) $(54) $(66)
Reclassified from accumulated OCI to income:       
Due to realization of previously deferred amounts3
 3
 7
 6
Mark-to-market of cash flow hedge accounting contracts5
 (9) 24
 (7)
Accumulated OCI ending balance, net of $5, and $16 tax$(23) $(67)
$(23)
$(67)
Losses expected to be realized from OCI during the next 12 months, net of $1 tax$8
 

 $8
 


Amounts reclassified from accumulated OCIOCL into income are recorded to interest expense for interest rate contracts.
The Company's regression analysis for Marsh Landing, Walnut Creek, and Avra Valley interest rate swaps, while positively correlated, no longer contain match terms for cash flow hedge accounting. As a result, the Company voluntarily de-designated the Marsh Landing, Walnut Creek, and Avra Valley cash flow hedges as of April 28, 2017, and will prospectively mark these derivatives to market through the income statement.


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 consolidated results of operations.

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 energy commodity contractshedges is included within operating revenues and cost of operations and the effect of interest rate contractshedges is included in interest expense.
 Three months ended June 30, Six months ended June 30,
 2018 2017 2018 2017
Unrealized mark-to-market results(In millions)
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges$(3) $22
 $(1) $25
Reversal of acquired (gain)/loss positions related to economic hedges(1) 1
 (1) 1
Net unrealized (losses)/gains on open positions related to economic hedges(67) 36
 127
 15
Total unrealized mark-to-market (losses)/gains for economic hedging activities(71) 59
 125
 41
Reversal of previously recognized unrealized gains on settled positions related to trading activity(3) (4) (6) (19)
Net unrealized gains on open positions related to trading activity8
 16
 19
 17
Total unrealized mark-to-market gains/(losses) for trading activity5
 12
 13
 (2)
Total unrealized (losses)/gains$(66) $71
 $138
 $39
 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 hedges1
 (1) (1) (1)
Net unrealized gains/(losses) on open positions related to economic hedges9
 (73) 12
 132
Total unrealized mark-to-market gains/(losses) for economic hedging activities21
 (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 activity13
 8
 26
 19
Total unrealized mark-to-market gains for trading activity12
 5
 19
 13
Total unrealized gains/(losses)$33
 $(71) $60
 $143
Three months ended June 30, Six months ended June 30,Three months ended June 30, Six months ended June 30,
2018 2017 2018 20172019 2018 2019 2018
(In millions)(In millions)
Unrealized gains/(losses) included in operating revenues$20
 $53
 $(78) $157
$253
 $15
 $280
 $(73)
Unrealized (losses)/gains included in cost of operations(86) 18
 216
 (118)(220) (86) (220) 216
Total impact to statement of operations — energy commodities$(66) $71
 $138
 $39
$33
 $(71) $60
 $143
Total impact to statement of operations — interest rate contracts$13
 $(24) $61
 $(19)$(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 $127$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.
For the six months ended June 30, 2017, the $15 million unrealized gain from open economic hedge positions was primarily the result of an increase in value of forward sales of PJM electricity and New York capacity due to decreases in PJM electricity and New York capacity prices, which was offset by a decrease in value of forward purchases of natural gas and coal due to decreases in natural gas and coal 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, 2018,2019 was $31$19 million. The collateral required for contracts with credit rating contingent features that are in a net liability position as of June 30, 2018,2019 was $3$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 approximately $4$3 million as of June 30, 20182019.
See Note 45, Fair Value of Financial Instruments, to this Form 10-Q for discussion regarding concentration of credit risk.


Note 8 — Leases
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 cost33
 56
Short-term lease cost1
 1
Variable lease cost2
 3
Sublease income(5) (9)
Total lease cost$31
 $51

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 leases53
Right-of-use assets obtained in exchange for new operating lease liabilities214
Lease Term and Discount Rate:
Weighted-average remaining lease termIn Years
Finance leases2.5
Operating leases8.1
Weighted-average discount rate%
Finance leases6.50
Operating leases5.73


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
202095
202185
202285
202386
Thereafter371
Total undiscounted lease payments$772
Less: present value adjustment(185)
Total discounted lease payments$587

Note 79 —Impairments
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 is expected to close in the third quarter ofclosed 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 NYPSCNYSPSC, which challenged the legality of the Dunkirk contract.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 have shownconcluded that itextensive electric system upgrades would be necessary for the station to return to service. This would cause the Company to incur a material increase in costs. In addition, the interconnection upgrades that the NYISO has identified may not be ready until December 2023, which represents a significantcost and delay the project schedule. This causedschedule, which would render the project impractical. Consequently, the Company to recordrecorded an impairment loss of $46$46 million, during the second quarter of 2018, reducing the carrying amount of the related assets to $0.$0.
2017 Impairment Losses
Bacliff Project


Note 10— On June 16, 2017, NRG Texas Power LLC provided notice to BTEC New Albany, LLC that it was exercising its right to terminate the Amended and Restated Membership Interest Purchase Agreement, or MIPA, due to the Bacliff Project, a new peaking facility at the former P.H. Robinson Electric Generating Station, not achieving commercial completion by the contractual expiration date of May 31, 2017. As a result of the MIPA termination, the Company recorded an impairment loss of $41 million to reduce the carrying amount of the related construction in progress to $0 during the second quarter of 2017. Subsequent to the MIPA termination, BTEC filed claims against NRG Texas Power LLC with respect to the termination of the MIPA and NRG filed counterclaims against BTEC as further described in Note 15, Commitments and Contingencies. On June 7, 2018, the parties resolved all claims and counterclaims in the lawsuit.
Other Impairments — During the second quarter of 2017, the Company recorded impairment losses of approximately $22 million in connection with the Company's Renewables business.



Note 8 — Debt and Capital Leases
This footnote should be read in conjunction with the complete description under Note 12, Debt and Capital Leases, to the Company's 2017 Form 10-K. Long-term debt and capital leases consisted of the following:
(In millions, except rates)June 30, 2018 December 31, 2017 
June 30, 2018 interest rate % (a)
   
Recourse debt:     
Senior Notes, due 2022$977
 $992
 6.250
Senior Notes, due 2024733
 733
 6.250
Senior Notes, due 20261,000
 1,000
 7.250
Senior Notes, due 20271,250
 1,250
 6.625
Senior Notes, due 2028841
 870
 5.750
Convertible Senior Notes, due 2048575
 —
 2.750
Revolving loan facility, due 2018 and 202126
 —
 L+1.75
Term loan facility, due 20231,862
 1,872
 L+1.75
Tax-exempt bonds465
 465
 4.125 - 6.00
Subtotal recourse debt7,729
 7,182
 
Non-recourse debt:     
NRG Yield, Inc. Convertible Senior Notes, due 2019345
 345
 3.500
NRG Yield, Inc. Convertible Senior Notes, due 2020288
 288
 3.250
NRG Yield Operating LLC Senior Notes, due 2024500
 500
 5.375
NRG Yield Operating LLC Senior Notes, due 2026350
 350
 5.000
NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility, due 2023(b)
—
 55
 L+1.75
El Segundo Energy Center, due 2023369
 400
 L+1.75 - L+2.375
Marsh Landing, due 2023305
 318
 L+2.125
Alta Wind I - V lease financing arrangements, due 2034 and 2035901
 926
 5.696 - 7.015
Walnut Creek, term loans due 2023254
 267
 L+1.625
Utah Portfolio, due 2022273
 278
 various
Tapestry, due 2021155
 162
 L+1.625
CVSR, due 2037731
 746
 2.339 - 3.775
CVSR HoldCo, due 2037188
 194
 4.680
Alpine, due 2022133
 135
 L+1.750
Energy Center Minneapolis, due 2031, 2033, 2035 and 2037328
 208
 various
Viento, due 2023154
 163
 L+3.00
Buckthorn Solar, due 2018 and 2025132
 169
 L+1.750
NRG Yield - other564
 579
 various
Subtotal NRG Yield debt (non-recourse to NRG) (c)
5,970
 6,083
  
Ivanpah, due 2033 and 2038 (e)
—
 1,073
 2.285 - 4.256
Carlsbad Energy Project (c)
513
 427
 L+1.625 - 4.120
Agua Caliente, due 2037812
 818
 2.395 - 3.633
Agua Caliente Borrower 1, due 203886
 89
 5.430
Cedro Hill, due 2025 (c)
144
 151
 L+1.75
Midwest Generation, due 2019108
 152
 4.390
NRG Other Renewables (c)
623
 478
 various
NRG Other107
 180
 various
Subtotal other NRG non-recourse debt2,393
 3,368
  
Subtotal all non-recourse debt8,363
 9,451
  
Subtotal long-term debt (including current maturities)16,092

16,633
  
Capital leases3
 5
 various
Subtotal long-term debt and capital leases (including current maturities)16,095

16,638
  
Less current maturities(d)
(952)
(688)  
Less debt issuance costs(199) (204)  
Discounts(123) (30)  
Total long-term debt and capital leases$14,821

$15,716
  

(In millions, except rates)June 30, 2019 December 31, 2018 Interest rate %
   
Recourse debt:     
Senior Notes, due 2024$—
 $733
 6.250
Senior Notes, due 20261,000
 1,000
 7.250
Senior Notes, due 20271,230
 1,230
 6.625
Senior Notes, due 2028821
 821
 5.750
Senior Notes, due 2029733
 —
 5.250
Convertible Senior Notes, due 2048575
 575
 2.750
Senior Secured First Lien Notes, due 2024600
 —
 3.750
Senior Secured First Lien Notes, due 2029500
 —
 4.450
Term Loan Facility (a) 
—
 1,698
 L+1.75
Tax-exempt bonds466
 466
 4.125 - 6.00
Subtotal recourse debt5,925
 6,523
 
Non-recourse debt:     
Agua Caliente Borrower 1, due 203883
 86
 5.430
Midwest Generation—
 48
 4.390
Other34
 34
 various
Subtotal all non-recourse debt117
 168
  
Subtotal long-term debt (including current maturities)6,042

6,691
  
Capital leases1
 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 June 30,December 31, 2018, L+ equals 3-monththe interest rate was 1-month LIBOR plus x%, except for Carlsbad, the Buckthorn Solar and Utah Solar Portfolio where L+ equals 1 month LIBOR plus x% and Viento where L+ equals 6-month LIBOR plus x%.1.75%
(b) Applicable rate is determined by the Borrower Leverage Ratio, as defined in the credit agreement.
(c) Debt associated with the asset sales announced in February 2018.
(d) The NRG Yield, Inc. Convertible Senior Notes, due 2019, become due in February 2019 and are recorded in current maturities as of June 30, 2018.
(e) The Company deconsolidated Ivanpah during the second quarter of 2018.


Recourse Debt
2023 Term Loan Facility
On March 21, 2018, NRG repriced the 2023 Term Loan Facility, reducing the interest rate margin by 50 basis points to LIBOR plus 1.75% and reducing the LIBOR floor to 0.00%.

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 2048 Convertible2024 and 2029 Senior Secured First Lien Notes
During the second quarter of 2018,On May 28, 2019, NRG issued $575 million in$1.1 billion of aggregate principal amount of 2.75% Convertible Senior Notessenior secured first lien notes, consisting of $600 million 3.75% senior secured first lien notes due 2048,2024 and $500 million 4.45% senior secured first lien notes due 2029, or the Convertible Notes.Senior Secured First Lien Notes, at a discount. The Convertible Notes are convertible, under certain circumstances, into the Company's common stock, cash or a combination thereof (at NRG's option) at an initial conversion price of $47.74 per common share, which is equivalent to an initial conversion rate of approximately 20.9479 shares of common stock per $1,000 principal amount of Convertible Notes. Interest on the Convertible Notes is payable semi-annually in arrears on June 1 and December 1 of each year, commencing on December 1, 2018. The Convertible Notes mature on June 1, 2048, unless earlier repurchased, redeemed or converted in accordance with their terms. The ConvertibleSenior Secured First Lien Notes are guaranteed on a first-priority basis by certain NRG subsidiaries. Prior to the closeeach of business on the business day immediately preceding December 1, 2024, the ConvertibleNRG’s current and future subsidiaries that guarantee indebtedness under its credit agreement. The Senior Secured First Lien Notes will be convertible only uponsecured by a first priority security interest in the occurrencesame collateral that is pledged for the benefit of certain eventsthe lenders under NRG’s credit agreement, which consists of a substantial portion of the property and during certain periods,assets owned by NRG and thereafter during specified periods as follows:
•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 1, 202415, 2019, until the closematurity dates of business on the second scheduled trading day immediately before June 1, 2025;15, 2024 and
•from December 1, 2047 until the close of business on the second scheduled trading day immediately before the maturity date.
June 15, 2029. The Convertible Notes are accounted for in accordance with ASC 470-20, Debt with Conversion and Other Options. Under ASC 470-20, issuers of convertible debt instruments that may be settled in cash upon conversion, including partial cash settlement, are required to separately account for the liability (debt) and equity (conversion option) components. The carrying amount of the liability component at issuance date of $472 million was calculated by estimating the fair value of similar liabilities without a conversion feature. The residual principal amount of the notes of $103 million was allocated to the equity component with offset to debt discount. The debt discount will be amortized to interest expense using the effective interest method over seven years which is determined to be the expected life of the Convertible Notes.
The Company incurred approximately $12 million in transaction costs in connection withproceeds from the issuance of the notes. These costsSenior Secured First Lien Notes, together with cash on hand, were allocatedused to repay the liability and equity components in proportion toCompany's 2023 Term Loan Facility.
2024 Senior Notes Redemption
During the allocation of proceeds. Transaction costs of $9.5 million, allocated to the liability component, were recognized as deferred financing costs and are amortized over the seven years. Transaction costs of $2 million, allocated to the equity component, were recognized as a reduction of additional paid-in capital.
Senior Note Repurchases
In connection with the Transformation Plan, the Company has committed to reduce its debt balance by an additional $640 million to achieve a target net debt to adjusted EBITDA credit ratio of 3.0/1. The following open market senior note repurchases were completed to assist in achieving this target.
In connection with the repurchases during the sixthree months ended June 30, 2018,2019, the Company redeemed $733 million of its 6.25% Senior Notes due 2024 and recorded a $1 million loss on debt extinguishment was recorded,of $29 million, which included the write-off of previously deferred financingdebt issuance costs of $1$5 million.

Principal Repurchased
Cash Paid (a)                         

Average Early Redemption Percentage
In millions, except rates




5.750% senior notes due 2028$29

$30

99.24%
6.250% senior notes due 202214

15

103.25%
Total at June 30, 2018$43

$45


6.250% senior notes due 20226

6

103.25%
5.750% senior notes due 202820
 21
 99.13%
6.625% senior notes due 202720
 21
 103.06%
Total at August 2, 2018$89
 $93
  
(a) Includes payment for accrued interest of $1 million.


Non-recourse Debt
NRG Yield LLC and NRG Yield Operating LLC RevolvingSenior Credit Facility
NRG Yield LLC and its direct wholly owned subsidiary, NRG Yield Operating LLC, are parties to a senior secured revolving credit facility, which can be used for cash and for the issuance of letters of credit. On April 30, 2018, NRG Yield LLC and NRG Yield Operating LLC refinanced the revolving credit facility, which extended the maturity of the facility to April 28, 2023 and decreased the overall cost of borrowing from L+ 2.50% to L+1.75%. At June 30, 2018, there was $67 million of letters of credit issued under the revolving credit facility and no outstanding borrowings on the revolver.
Project Financings
Thermal FinancingTerm Loan Facility Repayment
On June 19, 2018, NRG Energy Center Minneapolis, a subsidiary of NRG Yield LLC, entered into an amended and restated Thermal note purchase and private shelf agreement whereas it authorizedMay 28, 2019, the Company repaid its $1.7 billion 2023 Term Loan Facility using the proceeds from the issuance of the Series E Notes, Series F Notes, Series G Notes, and Series HSenior Secured First Lien Notes, as further describedwell 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 table below: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.
 Amount Interest Rate
In millions, except rates   
Energy Center Minneapolis Series E Notes, due 2033$70
 4.80%
Energy Center Minneapolis Series F Notes, due 203310
 4.60%
Energy Center Minneapolis Series G Notes, due 203583
 5.90%
Energy Center Minneapolis Series H Notes, due 203740
 4.83%
Total proceeds$203
  
Repayment of Energy Center Minneapolis Series C Notes, due 2025(83) 5.95%
Net borrowings$120
  
The Series G Notes were used to refinance the Series C Notes due 2025. The amended and restated Thermal note purchase and private shelf agreement also established a private shelf facility for the future issuance of notes in the amount of $40 million.
Rosamond FinancingRevolving Credit Facility Modification
On June 4, 2018, Rosamond Solar Portfolio, LLC entered into a financingMay 28, 2019, the Company amended its existing credit agreement with financial institutionsto, among other things, (i) provide for a $118$184 million construction loan, which will convertincrease 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 term loan upon completionrelease of project constructionthe 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 $175 million investment tax credit, or ITC, bridge loan, both of which havesustainability-linked pricing metric that permits an interest rate of LIBOR plus 1.75%, as well as a letter of credit facility with availability of upadjustment tied to $33 million. The ITC bridge loan is expectedNRG meeting targets related to be repaid with proceeds from a tax equity arrangement by April 30, 2019. The term loan matures on April 30, 2034. As of June 30, 2018, $83 millionenvironmental sustainability and $5 million had been borrowed under(vi) make certain other changes to the construction loan and the ITC bridge loan, respectively.existing covenants.

Non-Recourse Debt
Agua Caliente Project FinancingBorrower 1
On February 17, 2017,January 22, 2019, the lenders of the Agua Caliente Borrower 1 LLC anddebt 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, or Agua Caliente Holdco, the indirect ownersa subsidiary of 51% of the Agua Caliente solar facility, issued $130 million of senior secured notes under the Agua Caliente Holdco Financing Agreement, or 2038 Agua Caliente Holdco Notes, that bear interest at 5.43% and mature on December 31, 2038. As described in Note 3, Acquisitions, Discontinued Operations and DispositionsClearway Energy Inc., on March 27, 2017, NRG Yield, Inc. acquired Agua Caliente Borrower 2 LLC from NRG. The debtwhich is joint and several to the parties. The Company is working with respectthe lenders to Agua Caliente Borrower 1 LLC and Agua Caliente Borrower 2 LLC and is secured by the equity interestsdetermine a path forward.
Cottonwood - Letters of each borrower in the Agua Caliente solar facility.
Carlsbad Project FinancingCredit
On May 26, 2017, Carlsbad Energy Holdings, LLCJanuary 4, 2019, the Company entered into a note payable agreement with financial institutions for the issuance of up to $407an $80 million of senior secured notes that bear interest at a rate of 4.12%, and mature on October 31, 2038, and a credit agreement for a $194 million construction loan, that will convert to a term loan upon completion of the project as well as a letterissue letters of credit, which is currently supporting the Cottonwood facility with an aggregate principal amount not to exceed $83 million, and a working capital loanlease. Annual fees of 1.33% on the facility with an aggregate principal amount not to exceed $4 million.are paid quarterly in advance. As of June 30, 2018, $5132019, the full $80 million was outstanding under bothissued.
Note 11 — Investments Accounted for Using the noteEquity Method and the construction loan.


Note 9 — Variable Interest Entities, or VIEs
Entities that are not Consolidated
NRG has interests in entities that are considered VIEs under ASC 810, Consolidation, but NRG is not considered the primary beneficiary.  NRG accounts for its interests in these entities underthe 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.
Utility-Scale Solar Portfolio—Through its consolidated subsidiary, NRG Yield, Inc.,PG&E Bankruptcy - The Agua Caliente project and two of the Company has equity interests in Four Brothers Solar, LLC, Granite Mountain Holdings, LLC, and Iron Springs Holdings, LLC, whichthree Ivanpah units are accounted for as equity method investments as the Company does not have a controlling financial interest. The assets have 20-yearparty to PPAs with PacifiCorp.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

exposure to loss is limited to its equity investment, which was $338$206 million for Agua Caliente and $16 million for Ivanpah as of June 30, 2018.2019. See Note 10, Debt and Capital Leases for further discussion on Agua Caliente.
GenConn Energy LLC— ThroughVariable Interest Entities
NRG accounts for its consolidated subsidiary,interests in certain entities that are considered VIEs under ASC 810, Consolidation, for which NRG Yield, Inc.,is not the Company owns a 50% interest in GCE Holding LLC,primary beneficiary, under the owner of GenConn, which owns and operates two190-MW peaking generation facilities in Connecticut at NRG's Devon and Middletown sites. NRG's maximum exposure to loss is limited to its equity investment, which was $100 million as of June 30, 2018.method.
Ivanpah Master Holdings LLC — Through its consolidated subsidiary, NRG Solar Ivanpah LLC, the CompanyNRG owns a 54.6%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 392393 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 in connection with several recent events, including the planned sale of NRG's renewables platform. Ensuing negotiations culminated inand entered into a settlement during the second quarter of 2018 between the parties which2018. 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, Consolidations.810. As a result, NRG determined that it is not the primary beneficiary and deconsolidated Ivanpah. NRG recognized a loss of $22$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. NRG's maximum exposure to loss is limited to its equity investment, which was $57 million as of June 30, 2018.
Entities that are Consolidated
The Company has a controlling financial interest in certain entities whichthat have been identified as VIEs under ASC 810. These arrangements are primarily related to tax equity arrangements entered into with third-parties in order to finance the cost of solar energy systems under operating leases and wind facilities eligible for certain tax credits as further described in Note 2, Summary of Significant Accounting Policies to the Company's 20172018 Form 10-K. For one of the tax equity arrangements, the Company has a deficit restoration obligation equal to $83 million as of June 30, 2018, which would be required to be funded if the arrangement were to be dissolved.
The summarized financial information for the Company's consolidated VIEs consisted of the following:
(In millions)June 30, 2019 December 31, 2018
Current assets$3
 $3
Net property, plant and equipment74
 76
Other long-term assets29
 28
Total assets106
 107
Current liabilities1
 2
Long-term debt28
 29
Other long-term liabilities8
 7
Total liabilities37
 38
Redeemable noncontrolling interest19
 19
Net assets less noncontrolling interests$50
 $50

(In millions)June 30, 2018 December 31, 2017
Current assets$191
 $118
Net property, plant and equipment2,709
 2,337
Other long-term assets660
 658
Total assets3,560
 3,113
Current liabilities119
 96
Long-term debt814
 661
Other long-term liabilities211
 209
Total liabilities1,144
 966
Redeemable noncontrolling interest69
 78
Noncontrolling interest660
 507
Net assets less noncontrolling interest$1,687
 $1,562



Note 1012 — Changes in Capital Structure
As of June 30, 20182019 and December 31, 20172018, 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, 2018420,288,886
 (136,638,847) 283,650,039
Shares issued under LTIPs1,541,588
 —
 1,541,588
Shares repurchased—
 (26,621,029) (26,621,029)
Balance as of June 30, 2019421,830,474
 (163,259,876) 258,570,598
Shares issued under LTIPs subsequent to June 30, 20193,827
 —
 3,827
Shares repurchased subsequent to June 30, 2019—
 (5,586,536) (5,586,536)
Balance as of August 7, 2019421,834,301
 (168,846,412) 252,987,889
 Issued Treasury Outstanding
Balance as of December 31, 2017418,323,134
 (101,580,045) 316,743,089
Shares issued under LTIPs1,373,655
 —
 1,373,655
Shares issued under ESPP—
 175,862
 175,862
Shares repurchased—
 (14,863,301) (14,863,301)
Balance as of June 30, 2018419,696,789
 (116,267,484) 303,429,305
Employee Stock Purchase Plan
In January 2018, 175,862 shares of common stock were issued to employee accounts from treasury stock for the offering period of July 1, 2017, to December 31, 2017. In January 2018, NRG suspended the ESPP.
Share Repurchases
InDuring 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 the Company to repurchase $1 billionan additional $250 million of its common stock, with the first $500 million program beginning as soon as permitted. The following repurchases have been made during the six months ended June 30, 2018.
 Total number of shares purchased 
Average price paid per share (a)
 
Amounts paid for shares purchased  (in millions) (a)
Board Authorized Share Repurchases     
First Quarter 20183,114,748
 
 $93
Second Quarter 2018 (b)
11,748,553
 
 407
Total Board Authorized Share Repurchases as of June 30, 201814,863,301
   $500
July 2018860,880
 
 —
Total Board Authorized Share Repurchases as of August 2, 201815,724,181
 $31.80
 $500
(a) The average price paid per share and amounts paid for shares purchased exclude the commissions of $0.01 per share paid in connection with the share repurchase.
(b) The share repurchases forto be executed in the second quarter include 9,969,023half of the shares repurchased through the ASR Agreement, as described below.
Accelerated Share Repurchase2019.
On May 24, 2018,February 28, 2019, the Company executed an accelerated share repurchase agreement, or ASR Agreement, with a financial institution to repurchase a total of $354$400 million of outstanding common stock based on a volume weighted average price. The Company received initial shares of 9,969,023,9,086,903, which were recorded in treasury stock at fair value based on the closing price on March 12, 2019, of $343$390 million, with the remaining $11$10 million recorded in additional paid in capital, representing the value of the forward contract to purchase additional shares. In July 2018,April 2019, the financial institution delivered the remaining shares pursuant to the ASR Agreementagreement and the Company received an351,768 additional 860,880 shares. The average price paid for all of the shares delivered under the ASR Agreement was $32.69$42.38 per share. Upon receipt of the additional shares in April 2019, the Company transferred the $11$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 program6,153,415
 $250
2019 program:   
Shares repurchased under February 28, 2019 Accelerated Share Repurchase Agreement 
9,438,671
 400
Other repurchases11,028,943
 404
Total Share Repurchases during the six months ended June 30, 201926,621,029
 $1,054
Repurchases made subsequent to June 30, 2019 to complete the 2019 program5,586,536
 $196
Total Share Repurchases during the period ended August 7, 201932,207,565
 $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.


NRG Common Stock Dividends
The following table listsA quarterly dividend of $0.03 per share was paid on the dividends paidCompany's common stock during the sixthree months ended June 30, 2018:
 Second Quarter 2018
First Quarter 2018
Dividends per Common Share$0.03

$0.03
2019. On July 18, 2018,19, 2019, NRG declared a quarterly dividend on the Company's common stock of $0.03 per share, payable August 15, 2018,2019, to stockholders of record as of August 1, 2018,2019, 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 1113 — Earnings/(Loss)Earnings Per Share
Basic earnings/(loss)earnings per common share is computed by dividing net income/(loss) less accumulated preferred stock dividendsincome by the weighted average number of common shares outstanding. Shares issued and treasury shares repurchased during the year are weighted for the portion of the year that they were outstanding. Diluted earnings/(loss)earnings per share is computed in a manner consistent with that of basic income/(loss)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 lossincome per share is shown in the following table:
 Three months ended June 30, Six months ended June 30,
In millions, except per share data2018 2017 2018 2017
Basic income/(loss) per share attributable to NRG Energy, Inc. common stockholders
Net income/(loss) attributable to NRG Energy, Inc.$72
 $(626) $351
 $(790)
Weighted average number of common shares outstanding - basic310
 316

314
 316
Earnings/(loss) per weighted average common share — basic$0.23
 $(1.98) $1.12
 $(2.50)
Diluted income/(loss) per share attributable to NRG Energy, Inc. common stockholders    
Weighted average number of common shares outstanding - diluted310
 316
 314
 316
Incremental shares attributable to the issuance of equity compensation (treasury stock method)4
 —
 4
 —
Total dilutive shares314
 316
 318
 316
Earnings/(loss) per weighted average common share — diluted$0.23
 $(1.98) $1.10
 $(2.50)
 Three months ended June 30, Six months ended June 30,
In millions, except per share data2019 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 - basic265
 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 - basic265
 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 - dilutive267
 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 lossincome per share:
 Three months ended June 30, Six months ended June 30,
In millions of shares2019 2018 2019 2018
Equity compensation plans—
 —
 —
 1

 Three months ended June 30, Six months ended June 30,
In millions of shares2018 2017 2018 2017
Equity compensation plans—
 6
 1
 6
Total—
 6
 1
 6

Note 14 — Segment Reporting

Note 12 — Segment Reporting
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 follows: Generation, which includes generation, international and BETM;well as renewables. Retail which includes Mass customers and Business Solutions, which includes C&I customers and other distributed and reliability products; Renewables, which includes solar and wind assets, excluding those in NRG Yield; NRG Yield; and corporate activities.
During 2017, NRG Yield acquired several projects totaling 555 MW from NRG. On Marchproducts. Intersegment sales are accounted for at market.The financial information for the six months ended June 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. These acquisitions were treated as a transfer of entities under common control and accordingly, all historical periods havehas been recast to reflect the acquisitions as if they had occurred at the beginning of the financial statement period.current segment structure.
On June 14, 2017,February 4, 2019, as described in Note 3, 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 GenOn NRG Yield, Inc., its Renewables Platform and Carlsbadfor financial reporting purposes. The financial information for all historical periods havethe six months ended June 30, 2018, has been recast to reflect the presentation of GenOnthese 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.
 
Retail(a)
 
Generation(a)
 
Renewables(a)
 NRG Yield 
Corporate(a)
 Eliminations Total
Three months ended June 30, 2018(In millions)
Operating revenues(a)
$1,817
 $1,218
 $113
 $307
 $7
 $(540) $2,922
Depreciation and amortization31
 66
 40
 82
 8
 —
 227
Impairment losses—
 74
 —
 —
 —
 —
 74
Reorganization costs1
 3
 3
 —
 16
 —
 23
Equity in earnings/(losses) of unconsolidated affiliates—
 —
 5
 29
 —
 (16) 18
(Loss)/income from continuing operations before income taxes(84) 273
 (17) 103
 (134) (12) 129
(Loss)/income from continuing operations(84) 272
 (12) 96
 (139) (12) 121
Loss from discontinued operations, net of tax—
 —
 —
 —
 (25) —
 (25)
Net (Loss)/Income(84) 272
 (12) 96
 (164) (12) 96
(Loss)/Income attributable to NRG Energy, Inc.$(88) $272
 $(35) $73

$(244) $94
 $72
Total assets as of June 30, 2018$7,217
 $4,306
 $4,117
 $8,448
 $9,675
 $(10,816) $22,947
 
Three months ended June 30, 2019(a)
 Retail Generation Corporate Eliminations Total
 (In millions)
Operating revenues(b)
$1,748
 $1,367
 $—
 $(650) $2,465
Depreciation and amortization32
 45
 8
 —
 85
Impairment losses1
 —
 —
 —
 1
Reorganization costs2
 —
 —
 —
 2
Gain on sale of assets—
 —
 1
 —
 1
Loss on debt extinguishment, net—
 —
 (47) —
 (47)
(Loss)/income from continuing operations before income taxes(280) 618
 (151) 1
 188
(Loss)/income from continuing operations(280) 618
 (150) 1
 189
Income from discontinued operations, net of tax—
 —
 13
 —
 13
Net (loss)/income(280) 618
 (137) 1
 202
Net (loss)/income attributable to NRG Energy, Inc.$(281) $618
 $(137) $1
 $201
(a) Operating revenues include inter-segment sales and net derivative gains and losses of:$2
 $546
 $9
 $—
 $(17) $—
 $540
 
Retail(a)
 
Generation(a)
 
Renewables(a)
 NRG Yield 
Corporate(a)
 Eliminations Total
Three months ended June 30, 2017(In millions)
Operating revenues(a)
$1,603
 $882
 $119
 $288
 $3
 $(194) $2,701
Depreciation and amortization29
 95
 49
 79
 8
 —
 260
Impairment losses—
 41
 22
 —
 —
 —
 63
Equity in (losses)/earnings of unconsolidated affiliates—
 (15) (2) 16
 3
 (5) (3)
Income/(loss) from continuing operations before income taxes330
 (89) (51) 52
 (134) (5) 103
Income/(loss) from continuing operations341
 (90) (46) 44
 (145) (5) 99
Loss from discontinued operations, net of tax—
 —
 —
 —
 (741) —
 (741)
Net Income/(Loss)341
 (90) (46) 44
 (886) (5) (642)
Net Income/(Loss) attributable to NRG Energy, Inc.$341
 $(90) $(21) $38
 $(919) $25
 $(626)
(a) Operating revenues include inter-segment sales and net derivative gains and losses of:$1
 $171
 $3
 $—
 $19
 $—
 $194

(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) $2,461
Depreciation and amortization30
 74
 9
 (1) 112
Reorganization costs1
 3
 19
 —
 23
Equity in earnings of unconsolidated affiliates—
 5
 2
 (2) 5
(Loss)/income from continuing operations before income taxes(84) 252
 (137) 1
 32
(Loss)/income from continuing operations(84) 252
 (142) 1
 27
Income from discontinued operations, net of tax—
 —
 69
 —
 69
Net (loss)/income(84) 252
 (73) 1
 96
Net (loss)/income attributable to NRG Energy, Inc.$(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




 
Retail(a)
 
Generation(a)
 
Renewables(a)
 NRG Yield 
Corporate(a)
 Eliminations Total
Six months ended June 30, 2018(In millions)
Operating revenues(a)
$3,298
 $1,545
 $199
 $532
 $9
 $(240) $5,343
Depreciation and amortization59
 133
 90
 163
 17
 —
 462
Impairment losses—
 74
 —
 —
 —
 —
 74
Reorganization costs4
 7
 3
 —
 29
 —
 43
Equity in earnings/(losses) of unconsolidated affiliates—
 2
 5
 33
 (1) (23) 16
Income/(Loss) from continuing operations before income taxes861
 (264) (56) 102
 (260) (22) 361
Income/(Loss) from continuing operations861
 (265) (45) 96
 (271) (22) 354
Income from discontinued operations, net of tax—
 —
 —
 —
 (25) —
 (25)
Net Income/(Loss)861
 (265) (45) 96
 (296) (22) 329
Net Income/(Loss) attributable to NRG Energy, Inc.$851
 $(265) $(33) $94
 $(392) $96
 $351
 
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 amortization63
 91
 16
 —
 170
Impairment losses1
 —
 —
 —
 1
Reorganization costs3
 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) Operating revenues include inter-segment sales and net derivative gains and losses of:$3
 $239
 $17
 $—
 $(19) $—
 $240
(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
 
Retail (a)
 
Generation(a)
 
Renewables(a)
 NRG Yield 
Corporate(a)
 Eliminations Total
Six months ended June 30, 2017             
Operating revenues(a)
$2,938
 $1,848
 $213
 $509
 $11
 $(436) $5,083
Depreciation and amortization57
 192
 96
 156
 16
 —
 517
Impairment losses—
 41
 22
 —
 —
 —
 63
Equity in (losses)/earnings of unconsolidated affiliates—
 (28) (3) 35
 7
 (9) 2
Income/(loss) from continuing operations before income taxes303
 (52) (87) 49
 (275) (9) (71)
Income/(loss) from continuing operations311
 (54) (77) 42
 (283) (9) (70)
Loss from discontinued operations, net of tax—
 —
 —
 —
 (775) —
 (775)
Net Income/(loss)311
 (54) (77) 42
 (1,058) (9) (845)
Net Income/(loss) attributable to NRG Energy, Inc.$311
 $(54) $(24) $50
 $(1,091) $18
 $(790)
 
Six months ended June 30, 2018 (a)
 Retail Generation Corporate Eliminations Total
          
Operating revenues(b)
$3,294
 $1,438
 $—
 $(206) $4,526
Depreciation and amortization56
 160
 18
 (2) 232
Impairment losses—
 74
 —
 —
 74
Reorganization costs5
 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 taxes860
 (319) (264) (1) 276
Income/(loss) from continuing operations860
 (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) Operating revenues include inter-segment sales and net derivative gains and losses of:$11
 $406
 $4
 $—
 $15
 $—
 $436
(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 1315 — Income 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 rates2018 2017 2018 2017
Income/(Loss) before income taxes$129
 $103
 $361
 $(71)
Income tax expense/(benefit) from continuing operations8
 4
 7
 (1)
Effective tax rate6.2% 3.9%
1.9%
1.4%
 Three months ended June 30, Six months ended June 30,
In millions, except rates2019 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%

For the three and six months ended June 30, 2019 and 2018,, NRG's overall effective tax rate was differentlower than the statutory rate of 21%, primarily due to the tax benefit for the change in valuation allowance, and the generation of PTCs from various wind facilities partially offset by the inclusion of consolidated partnerships and the current state tax expense.
For the three months ended June 30, 2017, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the tax benefit for the change in valuation allowance and the generation of PTCs and ITCs from various wind and solar facilities, respectively, partially offset by the inclusion of consolidated partnerships and current state tax expense.
For the six months ended June 30, 2017, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the tax expense for the change in valuation allowance and current state tax expense, partially offset by the generation of PTCs and ITCs from various wind and solar facilities, respectively.
Uncertain Tax Benefits
As of June 30, 2018,2019, NRG has recorded a non-current tax liability of $39$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, 2018,2019, NRG accrued an immaterial amount of interest relating to the uncertain tax benefits. As of June 30, 2018,2019, NRG had cumulative interest and penalties related to these uncertain tax benefits of $5 million.$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 1416 — Related Party Transactions
Services AgreementThe 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
Ivanpah7
 5
 18
 5
Midway-Sunset1
 —
 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 Transition Services Agreementmaintenance 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 GenOnGenConn 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.
The CompanyIvanpah — 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 with— NRG provided various management, personnel and other services which include human resources, regulatory and public affairs, accounting, tax, legal, information systems, treasury, risk management, commercial operations, and asset management, as set forth in the services agreement with GenOn, or the Services Agreement. The initial term of the Services Agreement was through December 31, 2013, with an automatic renewal absent a request for termination. The fee charged was determined based on a fixed amount as described in the Services Agreement and was calculated based on historical GenOn expenses prior to the NRG Merger. The annual fees under the Services Agreement were approximately $193 million and management has concluded that this method of charging overhead costs is reasonable. As described in Note 3, Acquisitions, Discontinued Operations and Dispositions, in connection with the Restructuring Support Agreement, NRG agreed to provide shared services to GenOn under the Services Agreement for an adjusted annualized fee of $84 million.
In December 2017,transition services agreement in conjunction with the confirmation of the GenOn Entities' plan of reorganization, the Services Agreement was terminated and replaced by the transition services agreement. Under the transition services agreement, NRG provided the shared services and other separation services at an annualized rate of $84 million, subject to certain credits and adjustments.reorganization. GenOn provided notice to NRG of its intent to terminate the transition services agreement effective August 15, 2018 and in connection with the settlement agreement described in Note 3, Acquisitions, Discontinued Operations and Dispositions, all amounts owed and payable to NRG were settled against the $28 million credit provided for in the Restructuring Support Agreement. NRG may provide additional separation services that are necessary for or reasonably related to the operation of GenOn's business after such date, subject to NRG's prior written consent, not to be unreasonably withheld. For the three and six months ended June 30, 2018, NRG recorded approximately $21 million and $42 million, respectively, under the transition services agreement against selling, general and administrative expenses post-Chapter 11 Filing. For the three and six months ended June 30, 2017, NRG recorded other income - affiliate related to these services of $39 million and $87 million, respectively.settled.
Credit Agreement with GenOn
NRG and GenOn are party to a secured intercompany revolving credit agreement.  The intercompany revolving credit agreement provided for a $500 million revolving credit facility, all of which was available for revolving loans and letters of credit. At June 30, 2018 and December 31, 2017, $45 million and $92 million, respectively, of letters of credit were issued and outstanding under the NRG credit agreement for GenOn. Additionally, as of June 30, 2018 and December 31, 2017, there were $151 million and $125 million, respectively, of loans outstanding under the intercompany secured revolving credit facility. In addition, the intercompany secured revolving credit facility contains customary covenants and events of default. As of June 30, 2018, GenOn was in default under the secured intercompany revolving credit agreement due to the filing of the Chapter 11 Cases.
As a result of the Chapter 11 Cases, no additional revolving loans or letters of credit are available to GenOn. As the Restructuring Support Agreement provided that the borrowings be repaid to NRG at or prior to emergence, NRG recorded its affiliate receivable for the amount outstanding net within accrued expenses and other current liabilities - affiliate on the consolidated balance sheet as of June 30, 2018. Interest continued to accrue during the pendency of the Chapter 11 Cases until July 2018, when all borrowings and related interest were settled against amounts owed by the Company to GenOn as further discussed in

Note 3 , Acquisitions, Discontinued Operations and Dispositions, in connection with the settlement between NRG and GenOn.
Commercial Operations Agreement
NRG Power Marketing LLC has entered into physical and financial intercompany commodity and hedging transactions with GenOn and certain of its subsidiaries. Subject to applicable collateral thresholds, these arrangements may provide for the bilateral exchange of credit support based upon market exposure and potential market movements. The terms and conditions of the agreements are generally consistent with industry practices and other third party arrangements. As of June 30, 2018, derivative assets and liabilities associated with these transactions are recorded within NRG's derivative instruments balances on the consolidated balance sheet, with related revenues and costs within operating revenues and cost of operations, respectively. Additionally, as of June 30, 2018 and December 31, 2017, the Company had $24 million and $32 million, respectively, of cash collateral posted in support of energy risk management activities by GenOn.


Note 1517 — Commitments and Contingencies
This footnote should be read in conjunction with the complete description under Note 22, Commitments and Contingencies, to the Company's 2017 Form 10-K.
Commitments
First Lien Structure
NRG has granted first liens to certain counterparties on a substantial portion of the Company's assets, excluding assets acquired in the GenOn and EME (including Midwest Generation) acquisitions, assets held by NRG Yield, Inc. and 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, 2018,2019, 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 reservesaccruals 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 reserveaccrual for the applicable legal matters, including regulatory and environmental matters as further discussed below.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 reservesaccruals and that such difference could be material.
In addition to the legal proceedings noted below, NRG and its subsidiaries are party to other litigation or legal proceedings arising in the ordinary course of business. In management's opinion, the disposition of these ordinary course matters will not materially adversely affect NRG's consolidated financial position, results of operations, or cash flows.

Midwest Generation Asbestos Liabilities— The Company, through certain of its subsidiary, Midwestsubsidiaries, has settled the indemnification claims brought by Commonwealth Edison Company and Exelon Generation may be subject to potential asbestos liabilitiesCompany LLC (collectively, "ComEd") as a result of itsthe Company's acquisition of EME. ThePursuant to a settlement agreement dated as of May 29, 2019, the Company is currently analyzing the scope of potential liability as it may relatepaid $26 million to Midwest Generation. The Company believesComEd, which was previously accrued. In addition, ComEd released all claims that it has established an adequate reserve for these cases. On March 27, 2018, ComEd filed a Motion to Compel Payments of Claims seeking $61 million related to asbestos liabilities. On April 25, 2018, NRG filed an Omnibus Objection to All Remaining Claims of ComEd and Exelon.
Midwest Generation New Source Review Litigation— In 2009, the EPA and the Illinois Attorney General,were or the Government Plaintiffs, filed a complaintcould have been asserted in its claims in the U.S. District Court for the Northern District of Illinois alleging violations of CAA PSD requirementsEME bankruptcy case and opacity and PM regulations. Several environmental groups intervened as plaintiffs in this litigation.  Midwest Generation moved to dismiss ninecertain of the ten PSD counts. The trial court granted the motionCompany's subsidiaries released all permissive and compulsory counter claims they could have asserted in 2010.  Following the trial court ruling, the Government Plaintiffs appealed the trial court’s dismissals of their PSD claims.  Those PSD claim dismissals were affirmed by the U.S. Court of Appeals for the Seventh Circuit in 2013.   On May 10, 2018, the district court approved the Consent Decree settling this litigation and dismissed the case.  Pursuantresponse to the Consent Decree, Midwest Generation has paid $500,000 to each of the State of Illinois and the Federal Government and has agreed to make and maintain certain operational improvements. ComEd claims.


Telephone Consumer Protection Act Purported Class Actions —Three purported class action lawsuits have been filed against NRG Residential Solar Solutions, LLC — one in California and two in New Jersey.  The plaintiffs generally allege misrepresentation by the call agents and violations of the TCPA, claiming that the defendants engaged in a telemarketing campaign placing unsolicited calls to individuals on the “Do Not Call List.” The plaintiffs seek statutory damages of up to $1,500 per plaintiff, actual damages and equitable relief. On June 22, 2017, plaintiffs in the California case filed a motion for leave to file a second amended complaint to substitute new plaintiffs. Defendants filed an opposition to this motion on June 26, 2017. The court granted plaintiffs' motion to substitute new plaintiffs and on August 1, 2017, defendants filed an answer to the second amended complaint. On August 31, 2017, the court in the California case agreed that the litigation should be stayed pending final court approval of the New Jersey settlement. On July 12, 2017, the parties in one of the New Jersey actions reached an agreement in principle to resolve the class allegations which was confirmed by a term sheet signed by the parties on July 28, 2017. On September 27, 2017, plaintiffs in one of the New Jersey cases filed their motion for preliminary approval of the class settlement which was approved by the court on November 17, 2017. On May 14, 2018, the court entered a final order approving the class action settlement and dismissing the lawsuit, thereby ending the New Jersey lawsuits. On July 2, 2018, the court in the California case entered an order dismissing the lawsuit.
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.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, CDWRplaintiffs filed a notice of appeal. On January 10, 2018, CDWRplaintiffs filed itstheir opening appellate brief. Defendants filed their opposition brief on April 10, 2018. On May 30, 2018, CDWRplaintiffs filed their reply brief.
Braun v. NRG Yield, Inc. — On April 19, 2016, plaintiffs filed a putative class action lawsuit against NRG Yield, Inc., the current and former members of its board of directors individually, and other parties in California Superior Court in Kern County, CA.  Plaintiffs allege various violations of the Securities Act due to the defendants’ alleged failure to disclose material facts related to low wind production prior to the NRG Yield, Inc.'s June 22, 2015 Class C common stock offering.  Plaintiffs seek compensatory damages, rescission, attorney’s fees and costs. The Defendants filed demurrers and a motion challenging jurisdiction on October 18, 2016. On July 30, 2018, the plaintiffs filed an opposition to the defendants’ motion to quash service of the summons and an opposition to the defendants’ demurrer.
Griffoul v. NRG Residential Solar Solutions — On February 28, 2017, plaintiffs, consisting of New Jersey residential solar customers, filed a purported class action lawsuit in New Jersey state court.  Plaintiffs allege violations of the New Jersey Consumer Fraud Action and Truth-in-Consumer Contracts, Warranty and Notice Act with regard to certain provisions of their residential solar contracts.  The plaintiffs seek damages and injunctive relief as to the proper allocation of the solar renewable energy credits. On June 6, 2017, the defendants filed a motion to compel arbitration or dismiss the lawsuit. Plaintiffs filed their opposition on June 29, 2017. On July 14, 2017,case is now waiting for the court denied NRG's motionof appeal to compel arbitration or dismiss the case. On July 25, 2017, NRG filed a motion for reconsideration of the appeal, which was denied. On August 22, 2017, NRG filed a notice of appeal. Afterschedule oral argument on April 24, 2018, the Appellate Division reversed the lower court on May 4, 2018, and ordered that the plaintiff must arbitrate their claims against NRG. On May 23, 2018, the plaintiff filed a petition for certification with the Supreme Court of New Jersey seeking to overturn the Appellate Division ruling. The petition and objection are fully briefed.argument.
Rice v. NRG — On April 14, 2017, plaintiffs filed a purported class action lawsuit in the U.S. District Court for the Western District of Pennsylvania against NRG, First Energy Corporation and Matt Canastrale Contracting, Inc.  Plaintiffs generally claim personal injury, trespass, nuisance and property damage related to the disposal of coal ash from GenOn's Elrama Power Plant and First Energy’s Mitchell and Hatfield Power Plants. Plaintiffs generally seek monetary damages, medical monitoring and remediation of their property. Plaintiffs filed an amended complaint on August 14, 2017. On October 20, 2017, NRG filed its answers and affirmative defenses. On July 6, 2018, NRG filed a motion for summary judgment. Plaintiffs filed their opposition to the motion for summary judgment on July 29, 2018.


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.
GenOn Chapter 11 Cases — On February 4, 2019, NRG sold the Petition Date,South Central Portfolio, including the GenOn Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. Under the Restructuring Support Agreement to which the GenOn Entities, NRG and certain of GenOn's and GenOn Americas Generation's senior unsecured noteholders are parties, each of them supported the Bankruptcy Court's approval of the plan of reorganization. GenOn has a customary "fiduciary out" under the Restructuring Support Agreement. If the plan of reorganization is not consummated, NRG may not be entitled to the benefits of the Settlement Agreement provided under the Restructuring Support Agreement and it will remainentities subject to any claims of GenOn and the noteholders, including claims relating to or arising out of any shared services and any other relationships or transactions between the companies. See Note 3, Acquisitions, Discontinued Operations and Dispositions, for additional information related to the Chapter 11 Cases.
GenOn Noteholders' Lawsuit —On December 13, 2016, certain indenture trustees for an ad hoc group of holders, or the Noteholders, of the GenOn Energy, Inc. 7.875% Senior Notes due 2017, 9.500% Notes due 2018, and 9.875% Notes due 2020, and the GenOn Americas Generation, LLC 8.50% Senior Notes due 2021 and 9.125% Senior Notes due 2031, along with certain of the Noteholders, filed a complaint in the Superior Court of the State of Delaware againstthis litigation. However, NRG and GenOn alleging certain claims related to the Services Agreement between NRG and GenOn. Plaintiffs generally seek return of all monies paid under the Services Agreement and any other damages that the court deems appropriate. On February 3, 2017, the court entered an order approving a Standstill Agreement whereby the parties agreed to suspend all deadlines in the case until March 1, 2017.  The Standstill Agreement terminated on March 1, 2017. On April 30, 2017, the Noteholders filed an amended complaint that asserts (i) additional fraudulent transfer claims in relation to GenOn’s sale of the Marsh Landing project to NRG Yield LLC, (ii) alleged breaches of fiduciary duty by certain current and former officers and directors of GenOn in relation to the Services Agreement and the alleged usurpation of corporate opportunities concerning the Mandalay and Canal projects and (iii) claims against NRG for allegedly aiding and abetting such claimed breaches of fiduciary duties. In addition to NRG and GenOn, the amended complaint names NRG Yield LLC and certain current and former officers and directors of GenOn as defendants. The plaintiffs, among other things, generally seek return of all monies paid under the services agreement and any other damages that the court deems appropriate. On July 13, 2018, NRG and GenOn executed a term sheet that resolves and releases the GenOn Noteholder litigation.
Morgantown v. GenOn Mid-Atlantic — On June 8, 2017, Morgantown and Dickerson Owner Lessors filed a lawsuit against GenOn Mid-Atlantic, LLC, NRG North America LLC, GenOn Americas Generation, LLC, NRG Americas, Inc., GenOn Energy Holdings, Inc., GenOn Energy, Inc., and NRG Energy, Inc. in New York State Supreme Court. The plaintiffs allege that they were overcharged by defendants for certain services outlined in a Services Agreement and that defendants caused a Qualified Credit Support portion of a Participation Agreement, or QCS Agreement, to be violated by causing the transfer of certain money outside the allowable confines set forth in the QCS Agreement. In addition, plaintiffs claim that the transfers were unfairly executed and done so in an effort to defraud plaintiffs and hinder their ability to continue to do business. As such, plaintiffs seek, among other things, the return of certain transferred funds and service charges paid and to bar defendants from executing additional transfers on plaintiffs’ behalf. On November 7, 2017, the Bankruptcy Court issued an order estimating the claims to be valued at $0. On December 14, 2017, a settlement agreement was executed between GenOn and NRG. On April 27, 2018, the parties executed a mutual release which in conjunction with the settlement agreement resolved this lawsuit.
BTEC v. NRG Texas Power — On July 18, 2017, BTEC New Albany LLC, or BTEC, filed a lawsuit against NRG Texas Power LLC, or NRG Texas Power, in the Harris County District Court in Texas.  On January 15, 2013, the parties entered into a Membership Interest and Purchase Agreement, or MIPA, whereby BTEC agreed to dismantle, transport and rebuild an electric power generation facility at the former P.H. Robinson Electric Generating Station in Bacliff, Texas.  The MIPA required BTEC to meet a Guaranteed Commercial Completion Date of May 31, 2016.  Because BTEC had not satisfied all of the contractually-required acceptance criteria by the MIPA expiration date, NRG elected to terminate the contract in June 2017. BTEC claimed that NRG Texas Power breached the MIPA by improperly terminating it, and sought a declaratory judgment as to the rights and obligations of the parties as well as damages, interest and attorney’s fees. On September 7, 2017, NRG Texas Power filed a counterclaim seeking damages in excess of $48 million. On June 7, 2018, the parties resolved all claims and counterclaims in the lawsuit and a dismissal order was subsequently entered by the court on July 12, 2018.



GenOn Related Contingencies
Actions Pursued by MC Asset Recovery—With Mirant Corporation's emergence from bankruptcy protection in 2006, certain actions filed by GenOn Energy Holdings and some of its subsidiaries against third parties were transferred to MC Asset Recovery, a wholly owned subsidiary of GenOn Energy Holdings.  MC Asset Recovery is governed by a manager who is independent of NRG and GenOn.  MC Asset Recovery is a disregarded entity for income tax purposes. Under the remaining action transferred to MC Asset Recovery, MC Asset Recovery sought to recover damages from Commerzbank AG and various other banks, or the Commerzbank Defendants, for alleged fraudulent transfers that occurred prior to Mirant's bankruptcy proceedings.  In December 2010, the U.S. District Court for the Northern District of Texas dismissed MC Asset Recovery's complaint against the Commerzbank Defendants.  In January 2011, MC Asset Recovery appealed the District Court's dismissal of its complaint against the Commerzbank Defendants to the U.S. Court of Appeals for the Fifth Circuit, or the Fifth Circuit.  In March 2012, the Fifth Circuit reversed the District Court's dismissal and reinstated MC Asset Recovery's amended complaint against the Commerzbank Defendants.  On December 10, 2015, the District Court granted summary judgment in favor of the Commerzbank Defendants. On December 29, 2015, MC Asset Recovery filed a notice to appeal this judgment with the Fifth Circuit. On June 1, 2017, the Fifth Circuit affirmed the District Court's judgment. On June 12, 2017, MC Asset Recovery petitioned the Fifth Circuit for rehearing. The petition for rehearing was denied and a court order and judgment affirming the District Court's judgments was entered on July 17, 2017. On October 17, 2018, the bankruptcy court is scheduled to hear a Motion for a Final Decree to close the Mirant bankruptcy case.
Natural Gas Litigation—GenOn has been a party to several lawsuits, certain of which are class action lawsuits, in state and federal courts, of which four remain pending involving plaintiffs in Kansas, Missouri and Wisconsin. These lawsuits were filed in the aftermath of the California energy crisis in 2000 and 2001 and the resulting FERC investigations and relate to alleged conduct to increase natural gas prices in violation of state antitrust law and similar laws. The lawsuits seek treble or punitive damages, restitution and/or expenses. The lawsuits also name as parties a number of energy companies unaffiliated with NRG. In July 2011, the U.S. District Court for the District of Nevada, which was handling four of the five cases, granted the defendants' motion for summary judgment and dismissed all claims against GenOn in those cases. The plaintiffs appealed to the U.S. Court of Appeals for the Ninth Circuit, or the Ninth Circuit, which reversed the decision of the District Court. GenOn along with the other defendants in the lawsuit filed a petition for a writ of certiorari to the U.S. Supreme Court challenging the Ninth Circuit's decision and the U.S. Supreme Court granted the petition. On April 21, 2015, the U.S. Supreme Court affirmed the Ninth Circuit’s holding that plaintiffs’ state antitrust law claims are not field-preempted by the federal Natural Gas Act and the Supremacy Clause of the U.S. Constitution.  The U.S. Supreme Court left open whether the claims were preempted on the basis of conflict preemption. The U.S. Supreme Court directed that the case be remanded to the U.S. District Court for the District of Nevada for further proceedings.
On March 7, 2016, class plaintiffs filed their motions for class certification. On March 30, 2017, the court denied the plaintiffs' motions for class certification, which the plaintiffs appealed to. The plaintiffs petitioned the Ninth Circuit for interlocutory review. On July 12, 2018, the Ninth Circuit heard oral arguments and the case is under submission pending a decision.
On February 26, 2018, GenOn filed objections to the proofs of claim filed in the Chapter 11 Cases by all of the plaintiffs in each of the four cases. GenOn filed that same day a motion asking the Bankruptcy Court to estimate all of the proofs of claim at zero dollars, to which the plaintiffs objected. The Bankruptcy Court denied the plaintiffs' objection, ruling that it had the authority to consider GenOn's objections to the proofs of claim and to estimate the claims, but has certified its decision for review by either the Fifth Circuit Court of Appeals or the District Court.
In June 2018, GenOn reached a settlement with plaintiffs in three of the four remaining suits, which leaves only the one purported class action involving plaintiffs in Wisconsin. CenterPoint Energy Services is a defendant in that case, and GenOn has agreed to indemnify CenterPoint againstthe purchaser for certain losses relatingsuffered 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 lawsuit. The Nevada District Judge granted summary judgment in favor of CenterPoint in that lawsuit andappropriate relief. Midwest Generation has been working with the plaintiffs appealed that decision to the Ninth Circuit. The appeal was argued on February 16, 2018, and the case is under submission pending a decision.


Mirant Chapter 11 Proceedings — In July 2003, and various dates thereafter, the Mirant Debtors filed voluntary petitions in the U.S. Bankruptcy Court for the Northern District of Texas, Fort Worth Division, for relief under Chapter 11 of the Bankruptcy Code. GenOn Energy Holdings and most of the other Mirant Debtors emerged from bankruptcy on January 3, 2006, when the plan of reorganization that was approved in conjunction with Mirant Corporation's emergence from bankruptcy protection, or the Mirant Plan, became effective. The remaining Mirant Debtors emerged from bankruptcy on various dates in 2007. Approximately 461,000 of the shares of GenOn Energy Holdings common stock to be distributed under the Mirant Plan have not yet been distributed and have been reserved for distribution with respect to claims disputed by the Mirant Debtors that have not been resolved. Upon the Mirant/RRI Merger, those reserved shares converted into a reserve for approximately 1.3 million shares of GenOn common stock. Upon the NRG Merger, those reserved shares converted into a reserve for approximately 159,000 shares of NRG common stock. Under the terms of the Mirant Plan, upon the resolution of such a disputed claim, the claimant will receive the same pro rata distributions of common stock, cash, or both as previously allowed claims, regardless of the price at which the common stock is trading at the time the claim is resolved. If the aggregate amount of any such payouts results in the number of reserved shares being insufficient, additional shares of common stock may be issuedIllinois EPA to address the shortfall. The bankruptcy court is scheduled to hear a Motion for a Final Decree in the Mirant bankruptcy on October 17, 2018.groundwater issues since 2010.
Potomac River Environmental Investigation—In March 2013, NRG Potomac River LLC, a subsidiary of GenOn, received notice that the District of Columbia Department of Environment (now renamed the Department of Energy and Environment, or DOEE) was investigating potential discharges to the Potomac River originating from the Potomac River Generating facility site, a site where the generation facility is no longer in operation. In connection with that investigation, DOEE served a civil subpoena on NRG Potomac River LLC requesting information related to the site and potential discharges occurring from the site.  NRG Potomac River LLC provided various responsive materials.  In January 2016, DOEE advised NRG Potomac River LLC that DOEE believed various environmental violations had occurred as a result of discharges DOEE believes occurred to the Potomac River from the Potomac River Generating facility site and as a result of associated failures to accurately or sufficiently report such discharges.  DOEE has indicated it believes that penalties are appropriate in light of the violations.  NRG Potomac River LLC is currently reviewing the information provided by DOEE.
Natixis v. GenOn Mid-Atlantic—On February 16, 2018, Natixis Funding Corp. and Natixis, New York Branch filed a complaint in the Supreme Court of the State of New York against GenOn Mid-Atlantic, the owner lessors under GenOn Mid-Atlantic’s operating leases of the Dickerson and Morgantown coal generation units, and the lease indenture trustee under those leases.  The plaintiffs’ allegations against GenOn Mid-Atlantic relate to a payment agreement between GenOn Mid-Atlantic and Natixis Funding Corp. to procure credit support for the payment of certain lease payments owed pursuant to the GenOn Mid-Atlantic operating leases for Morgantown and Dickerson.  The plaintiffs seek approximately $34 million in damages arising from GenOn Mid-Atlantic’s purported breach of certain warranties in the payment agreement. On April 2, 2018, GenOn Mid-Atlantic removed the allegations against it to the U.S. District Court for the Southern District of New York. On April 11, 2018, the U.S. District Court for the Southern District of New York entered a briefing schedule on a forthcoming motion to remand by Natixis Funding Corp. and a forthcoming motion to transfer by GenOn Mid-Atlantic. On April 26, 2018, Natixis Funding Corp. filed its motion to remand. On May 31, 2018, GenOn Mid-Atlantic opposed the motion to remand and filed a cross-motion to transfer. The parties completed briefing on the motions to remand and transfer on July 9, 2018, and the U.S. District Court for the Southern District of New York held an oral argument on July 18, 2018 and continued the motions to a subsequent conference scheduled for September 26, 2018.
Note 1618 — Regulatory Matters
This footnote should be read in conjunction with the complete description under Note 23, Regulatory Matters, to the Company's 2017 Form 10-K. Environmental regulatory matters are discussed within Note 17, 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.


National
Department of Energy Consideration of 202(c) and Defense Production Act —On March 29, 2018, FirstEnergy Solutions requested that the Department of Energy provide price supports for its coal and nuclear units by having the DOE issue an emergency must-run order under Section 202(c) of the Federal Power Act. A number of parties have filed comments with the DOE, including PJM, challenging the assertion that the FirstEnergy Solutions’ units are necessary for grid reliability. The DOE has not yet formally responded. On June 1, 2018, the White House announced that President Trump has directed Secretary of Energy Rick Perry to "prepare immediate steps to stop the loss" of coal and nuclear resources. No formal timeline for action on either proposal has been set by the Administration.
Zero-Emission Credits for Nuclear Plants in Illinois — In 2016, Illinois enacted a Zero Emission Credit, or ZEC, program for selected nuclear units in Illinois. In total, the program directs over $2.5 billion over ten years to two Exelon-owned nuclear power plants in Illinois.  These ZECs are out-of-market subsidies that threaten to artificially suppress market prices and interfere with the wholesale power market. On February 14, 2017, NRG, along with other companies, filed a complaint in the U.S. District Court for the Northern District of Illinois alleging that the state program is preempted by federal law and in violation of the dormant commerce clause. On July 14, 2017, Defendants' motions to dismiss were granted. On July 17, 2017, NRG, along with other companies, filed a notice of appeal to the U.S. Court of Appeals for the Seventh Circuit. Briefing is complete. On May 29, 2018, the United States filed an amicus brief at the invitation of the Seventh Circuit arguing that the ZEC program is not preempted.
Zero-Emission Credits for Nuclear Plants in New York South Central— On August 1,4, 2016, NRG received a document hold notice from FERC regarding conduct in the NYSPSC issued its Clean Energy Standard, or CES, which provided for ZECs which would provide more than $7.6 billion over 12 years in out-of-market subsidy paymentsMISO and PJM markets. It required NRG to certain selected nuclearretain communications related to multiple generating units in the state. These ZECs are out-of-market subsidiesSouth 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

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 threatenit 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 artificially suppress market prices and interferethe preliminary findings. The Company understands that FERC is concerned that the Company was inaccurate in its communications with the wholesale power market. On October 19, 2016, NRG, alongMarket Monitor regarding the costs and risks associated with other companies, filed a complaintoperating certain units in the U.S. District Court forforward timeframe. NRG withdrew the Southern District of New York, challenging the validity of the NYSPSC action and the ZEC program. On July 25, 2017, Defendants' motions to dismiss were granted. On August 24, 2017, NRG, along with other plaintiff companies, filed a notice of appealbids prior to the U.S. Court of Appeals for the Second Circuit. Briefing is complete. On May 29, 2018, the United States filed an amicus brief at the invitation of the Seventh Circuit arguing that the ZEC program is not preempted.
Department of Energy's Proposed Grid Resiliency Pricing Rule and Subsequent FERC Proceeding — On September 29, 2017, the Department of Energy issued a proposed rulemaking titled the "Grid Resiliency Pricing Rule." The rulemaking directs FERC to take action to reform the ISO/RTO markets to value certain reliability and resiliency attributes of electric generation resources. On October 2, 2017, FERC issued a notice inviting comments. On October 4, 2017, FERC staff issued a series of questions requesting commenters to address. On October 23, 2017, NRG filed comments encouraging FERC to act expeditiously to modernize energy and capacity markets in a manner compatible with robust competitive markets. On January 8, 2018, FERC terminated the proposed rulemaking and opened a new proceeding asking each ISO/RTO to address specific questions focused on grid resilience. On March 9, 2018, the ISOs/RTOs filed comments to the questions posed by FERC. The Company responded on May 9, 2018 and is currently awaiting a decision from FERC.
East/West
Montgomery County Station Power Tax—On December 20, 2013, NRG received a letter from Montgomery County, Maryland requesting payment of an energy tax for the consumption of station power at the Dickerson Facility over the previous three years.  Montgomery County seeks payment2016 auction in the amountnormal course of $22 million, which includes tax, interest and penalties.  NRG disputed the applicability of the tax. On December 11, 2015, the Maryland Tax Court reversed Montgomery County's assessment. Montgomery County filed an appeal, and on February 2, 2017, the Montgomery County Circuit Court affirmed theour commercial business decision of the tax court. On February 17, 2017, Montgomery County filed an appeal to the Court of Special Appeals of Maryland. On April 24, 2018, the Court of Special Appeals of Maryland affirmed the lower court's decision and on May 29, 2018, Montgomery County petitioned the Court of Appeals of Maryland to issue a writ of certiorari to review that decision. NRG filed an answer opposing the petition on June 18, 2018. The petition is currently pending before the Court of Appeals of Maryland.making.
Puente Power Project
Note 19— On October 5, 2017, the California Energy Commission, or CEC, the agency responsible for permitting the Puente Power Project, issued a statement on behalf of the committee of two Commissioners overseeing the permitting process stating their intention to issue a proposed decision that would deny a permit for the Puente Power Project. On October 16, 2017, NRG filed a motion to suspend the permitting proceeding for at least six months, which was granted on November 3, 2017. On May 31, 2018, the CEC extended the suspension period at NRG's request to July 1, 2019. The supplemental extension period should allow sufficient time to determine whether alternate procurement efforts undertaken by SCE supersede the need for the Puente Power Project.


Note 17 — Environmental Matters
This footnote should be read in conjunction with the complete description under Note 24, Environmental Matters, to the Company's 2017 Form 10-K.
NRG is subject to a wide range of environmental laws in the development, construction, ownership and operation of projects. These laws generally require that governmental permits and approvals be obtained before construction and during operation of power plants. NRG is also subject to laws regarding the protection of wildlife, including migratory birds, eagles and threatened and endangered species. The electric generation industry has been facing requirements regarding GHGs, combustion byproducts, water discharge and use, and threatened and endangered species that have been put in place in recent years. However, under the current U.S. presidential administration, some of these rules are being reconsidered and reviewed. In general, future laws are expected to require the addition of emissions controls or other environmental controls or to impose certain restrictions on the operations of the Company's facilities, which could have a material effect on the Company's consolidated financial position, results of operations, or cash flows. Federal and state environmental laws generally have become more stringent over time, although this trend could slow or pause in the near term with respect to federal laws under the current U.S. presidential administration.
The EPA finalized CSAPR in 2011, which was intended to replace CAIR in January 2012, to address certain states' obligations to reduce emissions so that downwind states can achieve federal air quality standards. In December 2011, the D.C. Circuit stayed the implementation of CSAPR and then vacated CSAPR in August 2012 but kept CAIR in place until the EPA could replace it. In April 2014, the U.S. Supreme Court reversed and remanded the D.C. Circuit's decision. In October 2014, the D.C. Circuit lifted the stay of CSAPR. In response, the EPA in November 2014 amended the CSAPR compliance dates. Accordingly, CSAPR replaced CAIR on January 1, 2015. Air
On July 28, 2015,8, 2019, EPA promulgated the D.C. Circuit heldACE rule, which rescinded the CPP, which sought to broadly regulate CO2 emissions from the power sector. The ACE rule requires states that the EPA had exceeded its authority by requiring certain reductions that were not necessary for downwind stateshave coal-fired EGUs to achieve federal standards. Although the D.C. Circuit kept the rule in place, the court ordered the EPAdevelop plans to revise the Phase 2 (or 2017) (i) SO2 budgets for four states including Texas and (ii) ozone-season NOx budgets for 11 states including Maryland, New Jersey, New York, Ohio, Pennsylvania and Texas. On October 26, 2016, the EPA finalized the CSAPR Update Rule, which reduces future NOx allocations and discounts the current banked allowances to account for the more stringent 2008 Ozone NAAQS and to address the D.C. Circuit's July 2015 decision. This rule has been challenged in the D.C. Circuit. The Company believes its investment in pollution controls and cleaner technologies leave the fleet well-positioned for compliance.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 (with some units getting a 1-year extension).2015. In June 2015, the U.S. Supreme Court issued a decision in the case of Michigan v. EPA, and held thatDecember 2018, the EPA unreasonably refused to consider costs when it determinedproposed a finding that itregulating HAPs was not "appropriate and necessary" to regulate HAPs emitted by electric generating units. The U.S. Supreme Court did not vacatebecause the costs far exceed the benefits. Nonetheless, the EPA proposed keeping the substantive requirements of the MATS rule but rather remanded it to the D.C. Circuit for further proceedings. In December 2015, the D.C. Circuit remanded the MATS rule to the EPA without vacatur. On April 25, 2016, the EPA released a supplemental finding that the benefits of this regulation outweigh the costs to address the U.S. Supreme Court's ruling that the EPA had not properly considered costs. This finding has been challenged in the D.C. Circuit. On April 18, 2017, the EPA asked the D.C. Circuit to postpone oral argument that had been scheduled for May 18, 2017 because the EPA is closely reviewing the supplemental finding to determine whether it should reconsider all or part of the rule. On April 27, 2017, the D.C. Circuit granted EPA's request to postpone the oral argument and hold the case in abeyance. While NRG cannot predict the final outcome of this rulemaking, NRG believes that because it has already invested in pollution controls and cleaner technologies, the fleet is well-positioned to comply with the MATS rule.
Water
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, or FGD, fly ash, bottom ash, and flue gas mercury control.  In April 2017, the EPA granted two petitions to reconsider the rule and also administratively stayed some of the deadlines. On September 18, 2017, the EPA promulgated a final rule that, (i)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 and (ii) withdrewrulemaking. On April 12, 2019, the April 2017 administrative stay. The legal challenges have been suspended whileUnited States Court of Appeals for the EPA reconsiders and likely modifiesFifth Circuit released its opinion remanding portions of the rule.rule to the EPA. Accordingly, the Company has largely eliminated its estimate of the environmental capital expenditures that would have been required to comply with permits incorporating the revised guidelines. The Company will revisit these estimates after the rule is revised.


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.
East/West
New Source Review — The EPA and various states have been investigating compliance of electric generating facilities with the pre-construction permitting requirementsCompany will determine estimates of the CAA known as “new source review,” or NSR. In 2007, Midwest Generation received an NOV fromcost of compliance after the EPA alleging that past work at Crawford, Fisk, Joliet, Powerton, Waukegan and Will County generating stations violated NSR and other regulations. These alleged violations are the subject of litigation described in Note 15, Commitments and Contingencies. Additionally, in April 2013, the Connecticut Department of Energy and Environmental Protection issued four NOVs alleging that past work at oil-fired combustion turbines at the Torrington Terminal, Franklin, Branford and Middletown generating stations violated regulations regarding NSR.rule is revised.

 

Note 1820 — Condensed Consolidating Financial Information
As of June 30, 20182019, the Company had outstanding $5.4$4.4 billion of Senior Notes due from 20222024 to 2048 and outstanding $1.1 billion of Senior Secured First Lien Notes due from 2024 to 2029, as shown in Note 810, 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, and NRG Yield, Inc. and its 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, 20182019:
Ace Energy, Inc.New Genco GP,NRG Business Services LLCNRG Northeast Affiliate ServicesPacGen Inc.
Allied Home Warranty GP LLCNorwalkNRG Cabrillo Power LLCOperations Inc.NRG Norwalk Harbor Operations Inc.Portable Power LLC
Allied Warranty LLCNRG Advisory ServicesCalifornia Peaker Operations LLCNRG Operating Services, Inc.Power Marketing LLC
Arthur Kill Power LLCNRG Affiliate Services Inc.Cedar Bayou Development Company, LLCNRG Oswego Harbor Power Operations Inc.Reliability Solutions LLC
Astoria Gas Turbine Power LLCNRG Arthur Kill Operations Inc.NRG PacGen Inc.
Bayou Cove Peaking Power,Connected Home LLCNRG Astoria Gas Turbine Operations Inc.NRG Portable PowerRenter's Protection LLC
BidURenergy, Inc.NRG Bayou Cove LLCConnecticut Affiliate Services Inc.NRG Power MarketingRetail LLC
Cabrillo Power I LLCNRG Business ServicesConstruction LLCNRG Reliability SolutionsRetail Northeast LLC
Cabrillo Power II LLCNRG Cabrillo Power Operations Inc.Curtailment Solutions, IncNRG Renter's ProtectionRockford Acquisition LLC
Carbon Management Solutions LLCNRG California Peaker Operations LLCDevelopment Company Inc.NRG Retail LLCSaguaro Operations Inc.
Cirro Group, Inc.NRG Cedar Bayou Development Company, LLCDevon Operations Inc.NRG Retail NortheastSecurity LLC
Cirro Energy Services, Inc.NRG Connected HomeDispatch Services LLCNRG Rockford Acquisition LLC
Conemaugh Power LLCNRG Connecticut Affiliate Services Inc.NRG Saguaro Operations Inc.
Connecticut Jet Power LLCNRG Construction LLCNRG Security LLC
Cottonwood Development LLCNRG Curtailment Solutions, IncNRG Services Corporation
Cottonwood Energy Company LPNRG Development Company Inc.NRG SimplySmart Solutions LLC
Cottonwood Generating Partners I LLCNRG Devon Operations Inc.NRG South Central Affiliate Services Inc.
Cottonwood Generating Partners II LLCNRG Dispatch Services LLCNRG South Central Generating LLC
Cottonwood Generating Partners IIIConnecticut Jet Power LLCNRG Distributed Energy Resources Holdings LLCNRG South Central Operations Inc.SimplySmart Solutions LLC
Cottonwood Technology Partners LPDevon Power LLCNRG Distributed Generation PR LLCNRG South Texas LPCentral Affiliate Services Inc.
DevonDunkirk Power LLCNRG Dunkirk Operations Inc.NRG Texas C&I Supply LLCSouth Central Operations Inc.
DunkirkEastern Sierra Energy Company LLCNRG ECOKAP Holdings LLCNRG South Texas LP
El Segundo Power, LLCNRG El Segundo Operations Inc.NRG Texas GregoryC&I Supply LLC
Eastern Sierra Energy Company LLCNRG Energy Efficiency-L LLCNRG Texas Holding Inc.
El Segundo Power II LLCNRG Energy Labor Services LLCNRG Texas LLC
El Segundo Power II LLCNRG ECOKAP Holdings LLCNRG Texas PowerGregory LLC
Energy Alternatives Wholesale, LLCNRG Energy Services Group LLCNRG Warranty Services LLCTexas Holding Inc.
Energy Choice Solutions LLCNRG Energy Services International Inc.NRG West CoastTexas LLC
Energy Plus Holdings LLCNRG Energy Services LLCNRG Western Affiliate Services Inc.Texas Power LLC
Energy Plus Natural Gas LLCNRG Generation Holdings, Inc.O'Brien Cogeneration, Inc. IINRG Warranty Services LLC
Energy Protection Insurance CompanyNRG Greenco LLCONSITE Energy, Inc.NRG West Coast LLC
Everything Energy LLCNRG Home & Business Solutions LLCOswego Harbor Power LLCNRG Western Affiliate Services Inc.
Forward Home Security, LLCNRG Home Services LLCReliant Energy Northeast LLCO'Brien Cogeneration, Inc. II
GCP Funding Company, LLCNRG Home Solutions LLCReliantONSITE Energy, Power Supply, LLCInc.
Green Mountain Energy CompanyNRG Home Solutions Product LLCReliant Energy Retail Holdings,Oswego Harbor Power LLC
Gregory Partners, LLCNRG Homer City Services LLCReliant Energy Retail Services,Northeast LLC
Gregory Power Partners LLCNRG Huntley Operations Inc.RERH Holdings,Reliant Energy Power Supply, LLC
Huntley Power LLCNRG HQ DG LLCSaguaro PowerReliant Energy Retail Holdings, LLC
Independence Energy Alliance LLCNRG Identity Protect LLCSomerset Operations Inc.Reliant Energy Retail Services, LLC
Independence Energy Group LLCNRG Ilion Limited PartnershipSomerset PowerRERH Holdings, LLC
Independence Energy Natural Gas LLCNRG Ilion LP LLCTexas Genco GP,Saguaro Power LLC
Indian River Operations Inc.NRG International LLCTexas Genco Holdings,Somerset Operations Inc.
Indian River Power LLCNRG Maintenance Services LLCTexas Genco LP, LLC
KeystoneSomerset Power LLCNRG Mextrans Inc.Texas Genco Services, LP
Louisiana Generating LLCNRG MidAtlantic Affiliate Services Inc.US Retailers LLC
Meriden Gas Turbines LLCNRG Mextrans Inc.Texas Genco GP, LLC
Middletown Power LLCNRG MidAtlantic Affiliate Services Inc.Texas Genco Holdings, Inc.
Montville Power LLCNRG Middletown Operations Inc.Texas Genco LP, LLC
NEO CorporationNRG Montville Operations Inc.Texas Genco Services, LP
New Genco GP, LLCNRG North Central Operations Inc.US Retailers LLC
Norwalk Power LLCNRG Northeast Affiliate Services Inc.Vienna Operations Inc.
Middletown PowerNRG Advisory Services LLCNRG MontvilleNorwalk Harbor Operations Inc.Vienna Power LLC
Montville Power LLCNRG Affiliate Services Inc.NRG New Roads Holdings LLCOperating Services, Inc.WCP (Generation) Holdings LLC
NEO CorporationNRG Arthur Kill Operations Inc.NRG North CentralOswego Harbor Power Operations Inc.West Coast Power LLC
NRG Astoria Gas Turbine Operations Inc.



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 underof Regulation S-X of the SEC Regulation S-X.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.



NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the three months ended June 30, 20182019
(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 operations1,590
 252
 10
 (7) 1,845
Depreciation and amortization51
 26
 8
 —
 85
Impairment losses1
 —
 —
 —
 1
Selling, general and administrative112
 12
 87
 —
 211
Reorganization costs—
 —
 2
 —
 2
Development costs—
 1
 1
 —
 2
Total operating costs and expenses1,754
 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 subsidiaries2
 —
 430
 (432) —
Other income, net4
 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 Taxes389
 45
 186
 (432) 188
Income tax expense/(benefit)—
 1
 (2) —
 (1)
Income from Continuing Operations389
 44
 188
 (432) 189
Income from discontinued operations, net of income tax—
 —
 13
 —
 13
Net Income389
 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
 Guarantor Subsidiaries Non-Guarantor Subsidiaries 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 Consolidated
 (In millions)
Operating Revenues         
Total operating revenues$2,276
 $659
 $—
 $(13) $2,922
Operating Costs and Expenses         
Cost of operations1,778
 282
 (4) (5) 2,051
Depreciation and amortization76
 143
 8
 —
 227
Impairment losses—
 74
 —
 —
 74
Selling, general and administrative110
 34
 77
 (10) 211
Reorganization costs1
 —
 22
 —
 23
Development costs—
 13
 3
 —
 16
Total operating costs and expenses1,965
 546
 106
 (15) 2,602
Gain on sale of assets—
 14
 —
 —
 14
Operating Income/(Loss)311
 127
 (106) 2
 334
Other Income/(Expense)         
Equity in earnings of consolidated subsidiaries7
 —
 355
 (362) —
Equity in earnings of unconsolidated affiliates—
 18
 —
 —
 18
Other income/(expense), net4
 (26) 2
 —
 (20)
Loss on debt extinguishment, net—
 —
 (1) —
 (1)
Interest expense(4) (92) (106) —
 (202)
Total other income/(expense)7
 (100) 250
 (362) (205)
Income Before Income Taxes318
 27
 144
 (360) 129
Income tax expense/(benefit)108
 (68) (32) —
 8
Income from Continuing Operations210
 95
 176
 (360) 121
Loss from discontinued operations, net of income tax—
 —
 (25) —
 (25)
Net Income210
 95
 151
 (360) 96
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interests—
 (57) 79
 2
 24
Net Income Attributable to
NRG Energy, Inc.
$210
 $152
 $72
 $(362) $72

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




NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the six months ended June 30, 20182019
(Unaudited)
Guarantor Subsidiaries Non-Guarantor Subsidiaries 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 ConsolidatedGuarantor Subsidiaries Non-Guarantor Subsidiaries 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 Consolidated
(In millions)(In millions)
Operating Revenues                  
Total operating revenues$4,120
 $1,249
 $—
 $(26) $5,343
$3,909
 $727
 $—
 $(6) $4,630
Operating Costs and Expenses                 
Cost of operations3,004
 613
 9
 (17) 3,609
2,948
 535
 19
 (6) 3,496
Depreciation and amortization149
 297
 16
 —
 462
105
 49
 16
 —
 170
Impairment losses—
 74
 —
 —
 74
1
 —
 —
 —
 1
Selling, general and administrative213
 60
 139
 (10) 402
234
 28
 143
 —
 405
Reorganization costs3
 —
 40
 —
 43
—
 —
 15
 —
 15
Development costs—
 23
 7
 (1) 29
—
 1
 3
 —
 4
Total operating costs and expenses3,369
 1,067
 211
 (28) 4,619
3,288
 613
 196
 (6) 4,091
Gain on sale of assets3
 13
 —
 —
 16
1
 1
 —
 —
 2
Operating Income/(Loss)754
 195
 (211) 2
 740
622
 115
 (196) —
 541
Other Income/(Expense)                 
Equity in earnings of consolidated subsidiaries9
 —
 685
 (694) —
12
 —
 729
 (741) —
Equity in earnings/(losses) of unconsolidated affiliates—
 17
 (1) —
 16
Other income/(expense), net8
 (36) 5
 —
 (23)
Equity in losses of unconsolidated affiliates—
 (21) —
 —
 (21)
Other income, net8
 9
 15
 —
 32
Loss on debt extinguishment, net—
 —
 (3) —
 (3)—
 —
 (47) —
 (47)
Interest expense(7) (164) (198) —
 (369)(7) (9) (203) —
 (219)
Total other income/(expense)10
 (183) 488
 (694) (379)13
 (21) 494
 (741) (255)
Income Before Income Taxes764
 12
 277
 (692) 361
Income tax expense/(benefit)221
 (20) (194) —
 7
Income from Continuing Operations Before Income Taxes635
 94
 298
 (741) 286
Income tax expense—
 1
 2
 —
 3
Income from Continuing Operations543
 32
 471
 (692) 354
635
 93
 296
 (741) 283
Loss from discontinued operations, net of income tax—
 —
 (25) —
 (25)
Income from discontinued operations, net of income tax9
 5
 387
 —
 401
Net Income543
 32
 446
 (692) 329
644
 98
 683
 (741) 684
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interests—
 (119) 95
 2
 (22)
Less: Net income attributable to noncontrolling interest and redeemable interests—
 1
 —
 —
 1
Net Income Attributable to
NRG Energy, Inc.
$543
 $151
 $351
 $(694) $351
$644
 $97
 $683
 $(741) $683
(a)All significant intercompany transactions have been eliminated in consolidation.consolidation





NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME
For the three months ended June 30, 20182019
(Unaudited)
Guarantor Subsidiaries Non-Guarantor Subsidiaries 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 ConsolidatedGuarantor Subsidiaries Non-Guarantor Subsidiaries 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 Consolidated
(In millions)(In millions)
Net Income$210
 $95
 $151
 $(360) $96
$389
 $44
 $201
 $(432) $202
Other Comprehensive Income, net of tax         
Unrealized gain on derivatives, net—
 4
 6
 (5) 5
Other Comprehensive Loss         
Foreign currency translation adjustments, net(4) (4) (5) 9
 (4)(1) (1) (1) 2
 (1)
Available-for-sale securities, net

—
 —
 1
 —
 1
—
 —
 1
 —
 1
Defined benefit plans, net—
 —
 (1) —
 (1)—
 —
 (3) —
 (3)
Other comprehensive (loss)/income(4) —
 1
 4
 1
Other comprehensive loss(1) (1) (3) 2
 (3)
Comprehensive Income206
 95
 152
 (356) 97
388
 43
 198
 (430) 199
Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest—
 (57) 81
 2
 26
Less: Comprehensive income attributable to noncontrolling redeemable interest—
 1
 —
 —
 1
Comprehensive Income Attributable to NRG Energy, Inc.$206
 $152
 $71
 $(358) $71
$388
 $42
 $198
 $(430) $198
(a)All significant intercompany transactions have been eliminated in consolidation.consolidation




NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME
For the six months ended June 30, 20182019
(Unaudited)
Guarantor Subsidiaries Non-Guarantor Subsidiaries 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 ConsolidatedGuarantor Subsidiaries Non-Guarantor Subsidiaries 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 Consolidated
(In millions)(In millions)
Net Income$543
 $32
 $446
 $(692) $329
$644
 $98
 $683
 $(741) $684
Other Comprehensive (Loss)/Income, net of tax         
Unrealized gain on derivatives, net—
 20
 21
 (22) 19
Foreign currency translation adjustments, net(6) (6) (8) 14
 (6)
Other Comprehensive Loss        
Available-for-sale securities, net—
 —
 1
 —
 1
—
 —
 1
 —
 1
Defined benefit plans, net—
 —
 (2) —
 (2)—
 —
 (6) —
 (6)
Other comprehensive (loss)/income(6) 14
 12
 (8) 12
Other comprehensive loss—
 —
 (5) —
 (5)
Comprehensive Income537
 46
 458
 (700) 341
644
 98
 678
 (741) 679
Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest—
 (119) 105
 2
 (12)
Less: Comprehensive income attributable to noncontrolling redeemable interest—
 1
 —
 —
 1
Comprehensive Income Attributable to NRG Energy, Inc.$537
 $165
 $353
 $(702) $353
$644
 $97
 $678
 $(741) $678
(a)All significant intercompany transactions have been eliminated in consolidation.consolidation





NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
June 30, 20182019
(Unaudited)
Guarantor Subsidiaries Non-Guarantor Subsidiaries 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 ConsolidatedGuarantor Subsidiaries Non-Guarantor Subsidiaries 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 Consolidated
ASSETS(In millions)(In millions)
Current Assets                  
Cash and cash equivalents$71
 $395
 $514
 $—
 $980
$—
 $27
 $267
 $—
 $294
Funds deposited by counterparties71
 —
 —
 —
 71
31
 —
 —
 —
 31
Restricted cash9
 277
 —
 —
 286
8
 2
 1
 —
 11
Accounts receivable, net1,094
 274
 3
 —
 1,371
1,383
 133
 277
 (744) 1,049
Inventory309
 176
 —
 —
 485
254
 116
 —
 —
 370
Derivative instruments837
 36
 15
 (37) 851
867
 54
 —
 (71) 850
Cash collateral paid in support of energy risk management activities209
 15
 —
 —
 224
148
 15
 —
 —
 163
Accounts receivable - affiliate1,189
 123
 141
 (1,396) 57
Current assets - held for sale—
 100
 —
 —
 100
Prepayments and other current assets173
 122
 35
 (2) 328
190
 11
 76
 —
 277
Total current assets3,962
 1,518
 708

(1,435) 4,753
2,881
 358
 621

(815) 3,045
Property, plant and equipment, net2,402
 10,164
 231
 (23) 12,774
1,494
 965
 151
 —
 2,610
Other Assets                 
Investment in subsidiaries486
 —
 8,111
 (8,597) —
436
 —
 4,191
 (4,627) —
Equity investments in affiliates—
 1,055
 —
 —
 1,055
—
 383
 —
 —
 383
Notes receivable, less current portion—
 15
 —
 —
 15
Operating lease right-of-use assets, net91
 279
 129
 —
 499
Goodwill360
 179
 —
 —
 539
359
 214
 —
 —
 573
Intangible assets, net415
 1,448
 —
 (3) 1,860
402
 159
 —
 —
 561
Nuclear decommissioning trust fund694
 —
 —
 —
 694
748
 —
 —
 —
 748
Derivative instruments329
 61
 38
 (2) 426
420
 22
 —
 (16) 426
Deferred income tax156
 34
 (64) —
 126
—
 56
 (1) —
 55
Non-current assets held-for-sale—
 50
 —
 —
 50
Other non-current assets81
 454
 120
 —
 655
148
 30
 96
 (3) 271
Total other assets2,521
 3,296
 8,205
 (8,602) 5,420
2,604
 1,143
 4,415
 (4,646) 3,516
Total Assets$8,885
 $14,978
 $9,144
 $(10,060) $22,947
$6,979
 $2,466
 $5,187
 $(5,461) $9,171
LIABILITIES AND STOCKHOLDERS’ EQUITY                  
Current Liabilities                  
Current portion of long-term debt and capital leases$—
 $862
 $92
 $(2) $952
$—
 $87
 $—
 $—
 $87
Current portion of operating lease liabilities22
 31
 21
 —
 74
Accounts payable699
 230
 46
 —
 975
937
 107
 423
 (744) 723
Accounts payable — affiliate1,901
 (207) (269) (1,396) 29
Derivative instruments695
 51
 —
 (37) 709
817
 32
 —
 (71) 778
Cash collateral received in support of energy risk management activities72
 —
 —
 —
 72
31
 —
 —
 —
 31
Current liabilities held-for-sale—
 74
 —
 —
 74
Accrued expenses and other current liabilities270
 123
 326
 —
 719
258
 42
 301
 —
 601
Accrued expenses and other current liabilities-affiliate—
 —
 133
 —
 133
Total current liabilities3,637
 1,133
 328
 (1,435) 3,663
2,065
 299
 745
 (815) 2,294
Other Liabilities                 
Long-term debt and capital leases245
 7,428
 7,148
 —
 14,821
245
 89
 5,463
 (3) 5,794
Non-current operating lease liabilities73
 313
 127
 —
 513
Nuclear decommissioning reserve274
 —
 —
 —
 274
290
 —
 —
 —
 290
Nuclear decommissioning trust liability410
 —
 —
 —
 410
448
 —
 —
 —
 448
Derivative instruments388
 2
 —
 (16) 374
Deferred income taxes112
 64
 (159) —
 17
(10) 68
 13
 —
 71
Derivative instruments237
 50
 —
 (2) 285
Out-of-market contracts, net58
 137
 —
 —
 195
Non-current liabilities held-for-sale—
 12
 —
 —
 12
Other non-current liabilities410
 311
 409
 —
 1,130
399
 148
 469
 —
 1,016
Total non-current liabilities1,746
 8,002
 7,398
 (2) 17,144
Total liabilities5,383
 9,135
 7,726
 (1,437) 20,807
Total other liabilities1,833
 620
 6,072
 (19) 8,506
Total Liabilities3,898
 919
 6,817
 (834) 10,800
Redeemable noncontrolling interest in subsidiaries—
 69
 —
 —
 69
—
 19
 —
 —
 19
Stockholders’ Equity3,502
 5,774
 1,418
 (8,623) 2,071
3,081
 1,528
 (1,630) (4,627) (1,648)
Total Liabilities and Stockholders’ Equity$8,885
 $14,978
 $9,144
 $(10,060) $22,947
$6,979
 $2,466
 $5,187
 $(5,461) $9,171
(a)All significant intercompany transactions have been eliminated in consolidation.consolidation



NRG ENERGY, INC. AND SUBSIDIARIES CONDENSED
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the six months ended June 30, 20182019
(Unaudited)
 Guarantor Subsidiaries Non-Guarantor Subsidiaries 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 Consolidated
 (In millions)
Cash Flows from Operating Activities         
Net income$543
 $32
 $446
 $(692) $329
Loss from discontinued operations—
 —
 (25) —
 (25)
Net income from continuing operations543
 32
 471
 (692) 354
Adjustments to reconcile net income to net cash provided/(used) by operating activities:        
Distributions from unconsolidated affiliates—
 50
 —
 (7) 43
Equity in (earnings)/losses of unconsolidated affiliates—
 (17) 1
 —
 (16)
Depreciation, amortization and accretion162
 307
 16
 —
 485
Provision for bad debts31
 —
 —
 —
 31
Amortization of nuclear fuel24
 —
 —
 —
 24
Amortization of financing costs and debt discount/premiums—
 18
 9
 —
 27
Adjustment for debt extinguishment—
 —
 3
 —
 3
Amortization of intangibles and out-of-market contracts9
 39
 —
 —
 48
Amortization of unearned equity compensation—
 —
 26
 —
 26
Impairment losses—
 89
 —
 —
 89
Changes in deferred income taxes and liability for uncertain tax benefits221
 (41) (176) —
 4
Changes in nuclear decommissioning trust liability41
 —
 —
 —
 41
Changes in derivative instruments(154) (43) 8
 (22) (211)
Changes in collateral deposits in support of energy risk management activities(4) (14) —
 —
 (18)
Gain on sale of emission allowances(11) —
 —
 —
 (11)
Gain on sale of assets(3) (13) —
 —
 (16)
Loss on deconsolidation of business—
 22
 —
 —
 22
Changes in other working capital(298) 41
 (865) 721
 (401)
Net Cash Provided/(Used) by Operating Activities561
 470
 (507) —
 524
Cash Flows from Investing Activities         
Dividends from NRG Yield, Inc.—
 —
 52
 (52) —
Acquisition of Drop Down Assets, net of cash acquired—
 (126) —
 126
 —
Acquisition of business, net of cash acquired(2) (282) —
 —
 (284)
Capital expenditures(105) (556) (30) —
 (691)
Decrease in notes receivable—
 4
 —
 —
 4
Purchases of emission allowances(22) —
 —
 —
 (22)
Proceeds from sale of emission allowances34
 —
 —
 —
 34
Investments in nuclear decommissioning trust fund securities(346) —
 —
 —
 (346)
Proceeds from the sale of nuclear decommissioning trust fund securities303
 —
 —
 —
 303
Proceeds from sale of assets, net of cash disposed of10
 8
 —
 —
 18
Deconsolidation of business—
 (160) —
 —
 (160)
Change in investments in unconsolidated affiliates—
 (2) —
 —
 (2)
Net Cash (Used)/Provided by Investing Activities(128) (1,114) 22
 74
 (1,146)
Cash Flows from Financing Activities

  
  
    
Dividends from NRG Yield, Inc.—
 (52) —
 52
 —
Payment (for)/from intercompany loans(323) 108
 215
 —
 —
Acquisition of Drop Down Assets, net of cash acquired—
 —
 126
 (126) —
Payment of dividends to common and preferred stockholders—
 —
 (19) —
 (19)
Payment for treasury stock—
 —
 (500) —
 (500)
Proceeds from issuance of long-term debt—
 774
 831
 —
 1,605
Payments for short and long-term debt—
 (564) (284) —
 (848)
Contributions from, net of distributions to noncontrolling interests in subsidiaries—
 222
 —
 —
 222
Payment of debt issuance costs—
 (24) (13) —
 (37)
Net Cash (Used)/Provided by Financing Activities(323) 464
 356
 (74) 423
Net Increase/(Decrease) in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash110
 (180) (129) —
 (199)
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period41
 852
 643
 —
 1,536
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period$151

$672

$514

$—
 $1,337
 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 operations9
 5
 387
 —
 401
Income from continuing operations635
 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 accretion115
 53
 16
 —
 184
Provision for bad debts42
 4
 6
 —
 52
Amortization of nuclear fuel27
 —
 —
 —
 27
Amortization of financing costs and debt discount/premiums—
 —
 13
 —
 13
Loss on debt extinguishment, net—
 —
 47
 —
 47
Amortization of intangibles13
 1
 —
 —
 14
Amortization of unearned equity compensation—
 —
 10
 —
 10
(Loss)/gain on sale and disposal of assets(3) 1
 3
 —
 1
Impairment losses1
 —
 —
 —
 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 activities128
 (3) —
 —
 125
Changes in nuclear decommissioning trust liability17
 —
 —
 —
 17
Changes in other working capital(343) (64) 19
 —
 (388)
Cash provided/(used) by continuing operations592
 72
 (283) —
 381
Cash provided/(used) by discontinued operations17
 (9) —
 —
 8
Net Cash Provided/(Used) by Operating Activities609
 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 securities191
 —
 —
 —
 191
Proceeds from sale of assets, net of cash disposed and sale of discontinued operations, net of fees1
 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 loans206
 (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 operations17
 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 Period95
 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.consolidation



NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the three months ended June 30, 20172018
(Unaudited)
Guarantor Subsidiaries Non-Guarantor Subsidiaries 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 ConsolidatedGuarantor Subsidiaries Non-Guarantor Subsidiaries 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 Consolidated
(In millions)(In millions)
Operating Revenues                  
Total operating revenues$2,060
 $664
 $—
 $(23) $2,701
$2,172
 $291
 $—
 $(2) $2,461
Operating Costs and Expenses                  
Cost of operations1,530
 312
 20
 (21) 1,841
1,702
 195
 (5) (3) 1,889
Depreciation and amortization99
 153
 8
 —
 260
63
 40
 9
 —
 112
Impairment losses42
 21
 —
 —
 63
—
 74
 —
 —
 74
Selling, general and administrative96
 29
 97
 (1) 221
108
 16
 76
 —
 200
Reorganization costs1
 —
 22
 —
 23
Development costs—
 13
 5
 —
 18
—
 1
 3
 (1) 3
Total operating costs and expenses1,767
 528
 130
 (22) 2,403
1,874
 326
 105
 (4) 2,301
Other income - affiliate—
 —
 39
 —
 39
Gain on sale of assets2
 —
 —
 —
 2
—
 14
 —
 —
 14
Operating Income/(Loss)295
 136
 (91) (1) 339
298
 (21) (105) 2
 174
Other Income/(Expense)     
    
 
 

 
 
Equity in earnings/(losses) of consolidated subsidiaries8
 —
 (149) 141
 —
Equity in losses of unconsolidated affiliates—
 (2) (1) —
 (3)
Other income, net—
 41
 7
 (34) 14
Equity in earnings of consolidated subsidiaries7
 —
 353
 (360) —
Equity in earnings of unconsolidated affiliates—
 5
 —
 —
 5
Other income/(loss), net3
 (29) 3
 —
 (23)
Loss on debt extinguishment, net—
 —
 (1) —
 (1)
Interest expense(4) (121) (122) —
 (247)(4) (13) (106) —
 (123)
Total other income/(expense)4
 (82) (265) 107
 (236)6
 (37) 249
 (360) (142)
Income/(Loss) from Continuing Operations Before Income Taxes299
 54
 (356) 106
 103
304
 (58) 144
 (358) 32
Income tax expense/(benefit)113
 267
 (376) —
 4
108
 (71) (32) —
 5
Income/(Loss) from Continuing Operations186
 (213) 20
 106
 99
Loss from discontinued operations, net of income tax—
 (123) (618) —
 (741)
Net Income/(Loss)186
 (336) (598) 106
 (642)
Income from Continuing Operations196
 13
 176
 (358) 27
Income/(loss) from discontinued operations, net of income tax15
 80
 (26) —
 69
Net Income211
 93
 150
 (358) 96
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest—
 (9) 28
 (35) (16)—
 (56) 78
 2
 24
Net Income/(Loss) Attributable to NRG Energy, Inc.$186
 $(327) $(626) $141
 $(626)
Net Income Attributable to NRG Energy, Inc.$211
 $149
 $72
 $(360) $72
(a)All significant intercompany transactions have been eliminated in consolidation.consolidation




NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the six months ended June 30, 20172018
(Unaudited)
Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc.
(Note Issuer)		 
Eliminations(a)
 ConsolidatedGuarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc.
(Note Issuer)		 
Eliminations(a)
 Consolidated
(In millions)(In millions)
Operating Revenues                  
Total operating revenues$3,878
 $1,241
 $—
 $(36) $5,083
$3,916
 $620
 $—
 $(10) $4,526
Operating Costs and Expenses                 
Cost of operations3,050
 651
 39
 (36) 3,704
2,857
 419
 9
 (11) 3,274
Depreciation and amortization198
 303
 16
 —
 517
123
 92
 17
 —
 232
Impairment losses42
 21
 —
 —
 63
—
 74
 —
 —
 74
Selling, general and administrative205
 64
 213
 (1) 481
212
 27
 137
 —
 376
Reorganization costs3
 —
 40
 —
 43
Development costs—
 25
 10
 —
 35
—
 2
 7
 (1) 8
Total operating costs and expenses3,495
 1,064
 278
 (37) 4,800
3,195
 614
 210
 (12) 4,007
Other income - affiliate—
 —
 87
 —
 87
Gain on sale of assets4
 —
 —
 —
 4
3
 13
 —
 —
 16
Operating Income/(Loss)387
 177
 (191) 1
 374
724
 19
 (210) 2
 535
Other Income/(Expense)                 
Equity in earnings/(losses) of consolidated subsidiaries13
 —
 (100) 87
 —
Equity in earnings of consolidated subsidiaries8
 —
 685
 (693) —
Equity in earnings/(losses) of unconsolidated affiliates—
 4
 (2) —
 2
—
 7
 (1) —
 6
Other income, net1
 47
 13
 (35) 26
Other income/(loss), net8
 (36) 5
 —
 (23)
Loss on debt extinguishment, net—
 (2) —
 —
 (2)—
 —
 (3) —
 (3)
Interest expense(7) (225) (239) —
 (471)(7) (34) (198) —
 (239)
Total other income/(expense)7
 (176) (328) 52
 (445)9
 (63) 488
 (693) (259)
Income/(Loss) from Continuing Operations Before Income Taxes394
 1
 (519) 53
 (71)733
 (44) 278
 (691) 276
Income tax expense/(benefit)131
 237
 (369) —
 (1)221
 (16) (194) —
 11
Income/(Loss) from Continuing Operations263
 (236) (150) 53
 (70)512
 (28) 472
 (691) 265
Loss from discontinued operations, net of income tax—
 (160) (615) —
 (775)
Net Income/(Loss)263
 (396) (765) 53
 (845)
Income/(loss) from discontinued operations, net of income tax30
 60
 (26) —
 64
Net Income542
 32
 446
 (691) 329
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest—
 (46) 25
 (34) (55)—
 (119) 95
 2
 (22)
Net Income/(Loss) Attributable to NRG Energy, Inc.$263
 $(350) $(790) $87
 $(790)
Net Income Attributable to NRG Energy, Inc.$542
 $151
 $351
 $(693) $351
(a)All significant intercompany transactions have been eliminated in consolidation.consolidation





NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)INCOME
For the three months ended June 30, 20172018
(Unaudited)
 Guarantor Subsidiaries Non-Guarantor Subsidiaries 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 Consolidated
 (In millions)
Net Income/(Loss)$186
 $(336) $(598) $106
 $(642)
Other Comprehensive Income, net of tax         
Unrealized loss on derivatives, net—
 (6) (4) 5
 (5)
Foreign currency translation adjustments, net—
 1
 —
 —
 1
Available-for-sale securities, net—
 —
 1
 —
 1
Defined benefit plans, net—
 28
 28
 (29) 27
Other comprehensive income—
 23
 25
 (24) 24
Comprehensive Income/(Loss)186
 (313) (573) 82
 (618)
Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest—
 (10) 28
 (35) (17)
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.$186
 $(303) $(601) $117
 $(601)
 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 Income207
 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.consolidation



NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)INCOME
For the six months ended June 30, 20172018
(Unaudited)
 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc.
(Note Issuer)		 
Eliminations(a)
 Consolidated
 (In millions)
Net Income/(Loss)$263
 $(396) $(765) $53
 $(845)
Other Comprehensive Income, net of tax         
Unrealized loss on derivatives, net—
 (1) —
 —
 (1)
Foreign currency translation adjustments, net5
 5
 7
 (9) 8
Available-for-sale securities, net—
 —
 1
 —
 1
Defined benefit plans, net—
 29
 27
 (29) 27
Other comprehensive income5
 33
 35
 (38) 35
Comprehensive Income/(Loss)268
 (363) (730) 15
 (810)
Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest—
 (47) 25
 (34) (56)
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.$268
 $(316) $(755) $49
 $(754)
 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 Income536
 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.consolidation





NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 20172018
Guarantor Subsidiaries Non-Guarantor Subsidiaries 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 ConsolidatedGuarantor Subsidiaries Non-Guarantor Subsidiaries 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 Consolidated
ASSETS(In millions)(In millions)
Current Assets                  
Cash and cash equivalents$—
 $348
 $643
 $—
 $991
$55
 $28
 $480
 $—
 $563
Funds deposited by counterparties37
 —
 —
 —
 37
33
 —
 —
 —
 33
Restricted cash4
 504
 —
 —
 508
7
 10
 —
 —
 17
Accounts receivable, net912
 163
 4
 —
 1,079
1,354
 115
 309
 (754) 1,024
Inventory338
 194
 —
 —
 532
278
 134
 —
 —
 412
Derivative instruments646
 29
 9
 (58) 626
779
 50
 16
 (81) 764
Cash collateral paid in support of energy risk management activities170
 1
 —
 —
 171
275
 12
 —
 —
 287
Accounts receivable - affiliate685
 133
 (129) (594) 95
Current assets held-for-sale8
 107
 —
 —
 115
Prepayments and other current assets122
 112
 27
 —
 261
180
 32
 90
 —
 302
Current assets - held-for-sale—
 1
 —
 —
 1
Current assets - discontinued operations177
 20
 —
 —
 197
Total current assets2,922
 1,591
 554
 (652) 4,415
3,138
 402
 895
 (835) 3,600
Property, plant and equipment, net2,507
 11,188
 238
 (25) 13,908
1,938
 957
 153
 —
 3,048
Other Assets                 
Investment in subsidiaries266
 —
 7,581
 (7,847) —
446
 —
 4,707
 (5,153) —
Equity investments in affiliates—
 1,036
 2
 —
 1,038
—
 412
 —
 —
 412
Note receivable, less current portion—
 2
 38
 (38) 2
Goodwill360
 179
 —
 —
 539
359
 214
 —
 —
 573
Intangible assets, net454
 1,295
 —
 (3) 1,746
422
 169
 —
 —
 591
Nuclear decommissioning trust fund692
 —
 —
 —
 692
663
 —
 —
 —
 663
Derivative instruments126
 15
 31
 —
 172
296
 4
 22
 (5) 317
Deferred income taxes377
 (7) (236) —
 134
6
 (143) 183
 —
 46
Non-current assets held for sale—
 43
 —
 —
 43
Other non-current assets50
 459
 120
 —
 629
133
 71
 97
 (12) 289
Non-current assets - held for sale—
 77
 —
 —
 77
Non-current assets - discontinued operations405
 607
 —
 —
 1,012
Total other assets2,325
 3,022
 7,536
 (7,888) 4,995
2,730
 1,411
 5,009
 (5,170) 3,980
Total Assets$7,754
 $15,801
 $8,328
 $(8,565) $23,318
$7,806
 $2,770
 $6,057
 $(6,005) $10,628
LIABILITIES AND STOCKHOLDERS’ EQUITY                  
Current Liabilities                  
Current portion of long-term debt and capital leases$—
 $667
 $59
 $(38) $688
$—
 $55
 $17
 $—
 $72
Accounts payable610
 216
 55
 —
 881
1,368
 (185) 434
 (754) 863
Accounts payable — affiliate742
 (297) 181
 (593) 33
Derivative instruments556
 57
 —
 (58) 555
713
 41
 —
 (81) 673
Cash collateral received in support of energy risk management activities37
 —
 —
 —
 37
33
 —
 —
 —
 33
Current liabilities held-for-sale—
 72
 —
 —
 72
Accrued expenses and other current liabilities303
 162
 425
 —
 890
291
 36
 353
 —
 680
Accrued expenses and other current liabilities - affiliate—
 —
 161
 —
 161
Current liabilities - held-for-sale—
 5
 —
 —
 5
Current liabilities - discontinued operations24
 48
 —
 —
 72
Total current liabilities2,248
 877
 881
 (689) 3,317
2,429
 —
 804
 (835) 2,398
Other Liabilities                 
Long-term debt and capital leases244
 8,733
 6,739
 —
 15,716
244
 192
 6,025
 (12) 6,449
Nuclear decommissioning reserve269
 —
 —
 —
 269
282
 —
 —
 —
 282
Nuclear decommissioning trust liability415
 —
 —
 —
 415
371
 —
 —
 —
 371
Derivative instruments306
 3
 —
 (5) 304
Deferred income taxes112
 64
 (155) —
 21
112
 61
 (108) —
 65
Derivative instruments136
 61
 —
 —
 197
Out-of-market contracts, net66
 141
 —
 —
 207
Non-current liabilities held-for-sale—
 8
 —
 —
 8
Other non-current liabilities410
 321
 391
 —
 1,122
402
 320
 552
 —
 1,274
Total non-current liabilities1,652
 9,328
 6,975
 —
 17,955
Non-current liabilities - held-for-sale—
 65
 —
 —
 65
Non-current liabilities - discontinued operations58
 577
 —
 —
 635
Total other liabilities1,775
 1,218
 6,469
 (17) 9,445
Total Liabilities3,900
 10,205
 7,856
 (689) 21,272
4,204
 1,218
 7,273
 (852) 11,843
Redeemable noncontrolling interest in subsidiaries—
 78
 —
 —
 78
—
 19
 —
 —
 19
Stockholders’ Equity3,854
 5,518
 472
 (7,876) 1,968
3,602
 1,533
 (1,216) (5,153) (1,234)
Total Liabilities and Stockholders’ Equity$7,754
 $15,801
 $8,328

$(8,565) $23,318
$7,806
 $2,770
 $6,057

$(6,005) $10,628
(a)All significant intercompany transactions have been eliminated in consolidation.consolidation



NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the six months ended June 30, 20172018
(Unaudited)
 Guarantor Subsidiaries Non-Guarantor Subsidiaries 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 Consolidated
 (In millions)
Cash Flows from Operating Activities         
Net income/(loss)$263
 $(396) $(765) $53
 $(845)
Loss from discontinued operations—
 (160) (615) —
 (775)
Net income/(loss) from continuing operations263
 (236) (150) 53
 (70)
Adjustments to reconcile net income/(loss) to net cash provided/(used) by operating activities:         
Distributions from unconsolidated affiliates—
 32
 —
 (4) 28
Equity in (earnings)/losses of unconsolidated affiliates—
 (4) 2
 —
 (2)
Depreciation, amortization and accretion198
 303
 16
 —
 517
Provision for bad debts17
 1
 —
 —
 18
Amortization of nuclear fuel24
 —
 —
 —
 24
Amortization of financing costs and debt discount/premiums—
 20
 9
 —
 29
Amortization of intangibles and out-of-market contracts12
 39
 —
 —
 51
Amortization of unearned equity compensation—
 —
 16
 —
 16
Impairment losses42
 21
 —
 —
 63
Changes in deferred income taxes and liability for uncertain tax benefits131
 237
 (360) —
 8
Changes in nuclear decommissioning trust liability2
 —
 —
 —
 2
Changes in derivative instruments12
 (12) 7
 —
 7
Changes in collateral deposits in support of energy risk management activities(203) 11
 3
 —
 (189)
Proceeds from sale of emission allowances11
 —
 —
 —
 11
Gain on sale of assets(22) —
 —
 —
 (22)
Changes in other working capital(329) (539) 538
 (49) (379)
Net cash provided/(used) by continuing operations158
 (127)
81

—
 112
Cash used by discontinued operations—
 (38) —
 —
 (38)
Net Cash Provided/(Used) by Operating Activities158
 (165) 81
 —
 74
Cash Flows from Investing Activities         
Dividends from NRG Yield, Inc.—
 —
 45
 (45) —
Intercompany dividends—
 —
 129
 (129) —
Acquisition of Drop Down Assets, net of cash acquired—
 (131) —
 131
 —
Acquisition of businesses, net of cash acquired—
 (16) —
 —
 (16)
Capital expenditures(90) (436) (16) —
 (542)
Decrease in notes receivable8
 —
 —
 —
 8
Purchases of emission allowances(30) —
 —
 —
 (30)
Proceeds from sale of emission allowances59
 —
 —
 —
 59
Investments in nuclear decommissioning trust fund securities(279) —
 —
 —
 (279)
Proceeds from the sale of nuclear decommissioning trust fund securities277
 —
 —
 —
 277
Proceeds from renewable energy grants and state rebates—
 8
 —
 —
 8
Proceeds from sale of assets, net of cash disposed of35
 —
 —
 —
 35
Change in investments in unconsolidated affiliates—
 (30) —
 —
 (30)
Other18
 —
 —
 —
 18
Net cash (used)/provided by continuing operations(2) (605) 158

(43) (492)
Cash used by discontinued operations—
 (53) —
 —
 (53)
Net Cash (Used)/Provided by Investing Activities(2) (658) 158
 (43) (545)
Cash Flows from Financing Activities         
Dividends from NRG Yield, Inc.—
 (45) —
 45
 —
Payments (for)/from intercompany loans—
 (129) —
 129
 —
Acquisition of Drop Down Assets, net of cash acquired—
 —
 131
 (131) —
Intercompany dividends(122) 369
 (247) —
 —
Payment of dividends to common and preferred stockholders—
 —
 (19) —
 (19)
Net receipts from settlement of acquired derivatives that include financing elements—
 2
 —
 —
 2
Proceeds from issuance of long-term debt—
 741
 205
 —
 946
Payments for short and long-term debt—
 (316) (214) —
 (530)
Increase in notes receivable from affiliate—
 (125) —
 —
 (125)
Distributions to, net of contributions from, noncontrolling interests in subsidiaries—
 14
 —
 —
 14
Payments of debt issuance costs—
 (32) (4) —
 (36)
Other - contingent consideration—
 (10) —
 —
 (10)
Net cash (used)/provided by continuing operations(122) 469
 (148) 43
 242
Cash used by discontinued operations—
 (224) —
 —
 (224)
Net Cash (Used)/Provided by Financing Activities(122) 245
 (148) 43
 18
Effect of exchange rate changes on cash and cash equivalents—
 (8) —
 —
 (8)
Change in cash from discontinued operations—
 (315) —
 —
 (315)
Net Increase/(Decrease) in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash34
 (271) 91
 —
 (146)
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period13
 1,050
 323
 —
 1,386
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period$47
 $779
 $414
 $—
 $1,240
 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 operations30
 60
 (26) —
 64
Income/(loss) from continuing operations512
 (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 accretion136
 99
 17
 —
 252
Provision for bad debts30
 —
 —
 —
 30
Amortization of nuclear fuel24
 —
 —
 —
 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 contracts16
 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 benefits221
 (47) (176) —
 (2)
Changes in collateral deposits in support of energy risk management activities(5) (4) —
 —
 (9)
Changes in nuclear decommissioning trust liability41
 —
 —
 —
 41
Loss on deconsolidation of Ivanpah project—
 22
 —
 —
 22
Changes in other working capital152
 (56) (445) —
 (349)
Cash provided/(used) by continuing operations962
 96

(794)
—
 264
Cash provided by discontinued operations50
 199
 —
 —
 249
Net Cash Provided/(Used) by Operating Activities1,012
 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 allowances3
 —
 —
 —
 3
Investments in nuclear decommissioning trust fund securities(346) —
 —
 —
 (346)
Proceeds from the sale of nuclear decommissioning trust fund securities303
 —
 —
 —
 303
Proceeds from sale of assets, net of cash disposed of11
 —
 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 operations2
 (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 operations52
 (42) —
 —
 10
Net Increase/(Decrease) in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash60
 (163) (106) —
 (209)
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period41
 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.consolidation



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, 20182019 and 20172018. Also refer to NRG's 20172018 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




Executive Summary
Introduction and Overview
NRG Energy, Inc., or NRG or the Company, is a customer-driven integrated poweran energy company built on a portfolio of leadingdynamic retail electricity brands andwith 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 continuously focused on servingperfecting the energy needs of end-use residential, commercial and industrial customers in competitiveintegrated model by balancing retail load with generation supply within its deregulated markets, through multiple brands and channels.while evolving to a customer-driven business. The Company:
directlyCompany sells energy, services, and innovative, sustainable products and services directly to retail customers under the names “NRG”, “Reliant”"NRG" and "Reliant" and other retail brand names owned by NRG;
owns and operatesNRG supported by approximately 30,00023,000 MW of generation;
engages in the tradinggeneration as of wholesale energy, capacity and related products; and
transacts in and trades fuel and transportation services.
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, 2018,2019, by operating segment:
 
Global Generation Portfolio(a)
 
Global Generation Portfolio(a)
 (In MW) (In MW)
 Generation         Generation    
Generation Type 
Gulf Coast(f)(i)
 
East/West(b)
 
Renewables(c)(g)(j)(k)
 
NRG Yield(d)(j)
 
Other(e)(j)
 Total Global 
Texas(b)
 
East/West(c)(d)
 
Other (e)
 Total Global
Natural gas(f)
 7,464
 4,878
 —
 1,888
 —
 14,230
 4,759
 4,994
 —
 9,753
Coal 5,114
 3,871
 —
 —
 —
 8,985
 4,174
 3,745
 —
 7,919
Oil —
 3,641
 —
 190
 —
 3,831
 —
 3,600
 —
 3,600
Nuclear 1,136
 —
 —
 —
 —
 1,136
 1,126
 —
 —
 1,126
Wind(g)
 —
 —
 739
 2,200
 —
 2,939
Utility Scale Solar —
 —
 342
 921
 —
 1,263
 —
 321
 —
 321
Distributed Solar —
 —
 189
 52
 114
 355
Total generation capacity(h)
 13,714
 12,390
 1,270
 5,251
 114
 32,739
Capacity attributable to noncontrolling interest(h)
 —
 —
 (580) (2,358) —
 (2,938)
Total net generation capacity 13,714
 12,390
 690
 2,893
 114
 29,801
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.units
(b)Includes International and BETM.
(b) Does not include Cottonwood, which is included in East/West
(c)Includes Distributed Solar capacity fromInternational and the remaining Renewables generation assets held by DGPV Holdco 1, DGPV Holdco 2, and DGPV Holdco 3.
(d)Does not include NRG Yield, Inc.'s thermal converted (MWt) capacity, which is part of the NRG Yield operating segment.
(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. Also includes capacity from operating portfolios of residential solar assets held by RPV Holdco.
(f)Natural gas generation does not include 371 MW related to Greens Bayou 5 which was retired in January 2018.
(g)During the first quarter of 2018, NRG sold 10 MW to third parties related to the Minnesota wind assets.
(h)NRG Yield's total generation capacity includes 6 MW for noncontrolling interest for Spring Canyon II and III. NRG Yield's total generation capacity net of this noncontrolling interest was 5,247 MW.
(i)Includes the South Central business, which owns and operates a 3,555 MW portfolio of generation assets in Gulf Coast, and which the Company expects to sell as announced on February 6, 2018. NRG will lease back the 1,263 MW Cottonwood facility.
(j)Includes net MW for NRG Yield, Inc. of 2,893 MW and the Renewables operating and development platform of 467 MW, which the Company expects to sell as announced on February 6, 2018.systems
(k) Does not include net MW for Ivanpah of 196 MW due to deconsolidation in the second quarter of 2018.



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 fully integratedinnovative solutions to the end-use energy consumer. This strategy is intended to enable the Company to createoptimize the integrated model to generate predictable cash flow, significantly strengthen earnings and maintain growth at reasonable margins while de-risking the Company in termscost competitiveness, and lower risk and volatility. Sustainability is an integral piece of NRG's strategy and ties directly to business success, reduced risks and mitigated exposure to cyclical commodity price risk. At the same time, the Company's relentless commitment to safety for its employees, customers and partners continues unabated.


brand value.
To effectuate the Company’s strategy, NRG is focused on: (i) excellence in operating performance of its existing assets including repowering its power generation assets at premium sites and optimal hedging of generation assets and retail load operations; (ii) 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; (iii)(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 focused on achieving the regular return of and on stockholder capital within the dictates of prudent balance sheet management, including reducing consolidated debt and pursuing selective acquisitions, joint ventures, divestitures and investments.management.


Transformation Plan
NRG is well underway in the process of executing its Transformation Plan, which is designed to significantly strengthen earnings and cost competitiveness, lower risk and volatility, and create significant shareholder value.Plan. The Company expects to fully implement the Transformation Plan by the end of 2020, with a significant completion byportion of the end ofplan 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 — Cost- Recurring cost savings and margin enhancement of $1,065 million, recurring, 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.

Portfolio optimization — Targeting up to $3.2 billion The Company realized annual cost savings of asset sale cash proceeds, including divestitures of 6 GW of conventional generation$532 million and businesses (excluding GenOn) and the expected monetization of 100% of its interest in NRG Yield, Inc. and its renewables platform.
In 2017, NRG executed asset sales of 322 MW for aggregate cash of $150 million, which includes sales to NRG Yield, Inc. and the sale of Minnesota wind projects to third parties.
On February 6, 2018, NRG announced agreements to sell (i) NRG's full ownership interest in NRG Yield, Inc. and NRG's renewables platform, a 3,440 MW portfolio, for cash of $1.375 billion, subject to certain adjustments; and (ii) NRG's South Central business, a 3,555 MW portfolio of generation assets, for cash of $1.0 billion, subject to certain adjustments. The transactions are subject to certain closing conditions and are expected to close in the second half of 2018.
On February 6, 2018, the Company entered into an agreement with NRG Yield, Inc. to sell 100% of the membership interests in Carlsbad Energy Holdings LLC, which owns the Carlsbad project, a 527-MW natural gas-fired project in Carlsbad, CA, pursuant to the ROFO Agreement. The purchase price for the transaction is $365 million in cash consideration, subject to customary working capital and other adjustments.
On March 30, 2018, the Company completed the sale of 100% of its ownership interest in Buckthorn Solar to NRG Yield, Inc. for cash consideration of approximately $42 million.
During the first half of 2018, the Company completed the sale of various other assets for approximately $7 million.
On June 19, 2018, the Company completed the sale of the substantially completed assets of the UPMC Thermal Project to NRG Yield, Inc. for cash consideration of $84 million, subject to working capital adjustments.
On August 1, 2018, the Company completed the sale of 100% of its ownership interests in BETM to a third party for $70 million, subject to working capital adjustments. The sale also resulted in the release and return of approximately $119$32 million of letters of credit, $30margin enhancements during the year ended December 31, 2018, and expects to realize $590 million of parent guarantees,cost savings and $4$135 million of net cash collateral to NRG.margin enhancements in 2019.


Capital structure and allocation enhancements — A prioritized capital allocation strategy that targets a reduction in consolidated debt to achieve its targeted 3.0x net debt / Adjusted EBITDA credit ratio.
Expected reduction in non-recourse debt related to the sale of NRG's ownership in NRG Yield, Inc. and the NRG renewables platform and the sales of Carlsbad Energy Center and Buckthorn Solar.
Year to date open market repurchases of $93 million, representing principal reduction of Senior Notes of $89 million.

Working Capital and Costs to Achieve —The Company expects to realize (i) $370 million of non-recurring working capital improvements through 2020 and (ii) approximately $290 million one-time costscost to achieve.
Since the inception of the Transformation Plan, By December 31, 2018, NRG hashad realized $298$333 million of non-recurring working capital improvements and $113$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 20172018 Form 10-K in Item 1, Business — Regulatory Matters. These matters have been updated below and in Note 16, 18, Regulatory Matters, to the Condensed Consolidated Financial Statements of this Form 10-Q as found in Item 1.10-Q.
As owners of power plants and 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 thermal, or distributed generation assets are located. In addition, NRG is subject to the market rules, procedures and protocols of the various ISO and RTO markets in which it participates. Likewise, certain NRG entities participating in the retail markets are subject to rules and regulations established by the states in which NRG entities are licensed to sell at retail. NRG must also comply with the mandatory reliability requirements imposed by NERC and the regional reliability entities in the regions where NRG operates.
NRG's operations within the ERCOT footprint are not subject to rate regulation by FERC, as they are deemed to operate solely within the ERCOT market and not in interstate commerce. These operations are subject to regulation by the PUCT, as well as to regulation by the NRC with respect to NRG's ownership interest in STP.
Federal Energy Regulation
Department of Energy's Proposed Grid Resiliency Pricing Rule and Subsequent FERC ProceedingPG&E Corporation Bankruptcy Filing —On September 29, 2017, the Department of Energy issued a proposed rulemaking titled the "Grid Resiliency Pricing Rule." The rulemaking directs FERC to take action to reform the ISO/RTO markets to value certain reliability and resiliency attributes of electric generation resources. On October 2, 2017, FERC issued a notice inviting comments. On October 4, 2017, FERC staff issued a series of questions requesting commenters to address. On October 23, 2017, NRG filed comments encouraging FERC to act expeditiously to modernize energy and capacity markets in a manner compatible with robust competitive markets. On January 8, 2018,18, 2019, NextEra Energy, Inc., filed a petition for declaratory order requesting that FERC terminatedassert 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 proposed rulemakingbankruptcy courts have concurrent jurisdiction to review and opened a new proceeding asking each ISO/RTOaddress 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 specific questions focusedthe disposition of wholesale power contracts. On June 26, 2019, PG&E appealed the FERC order that was issued on grid resilience. On March 9, 2018,January 25, 2019. The issue of jurisdiction over wholesale power contracts remains in litigation.





(a) adjusted EBITDA as defined per the ISOs/RTOs filed comments to the questions posed by FERC. The Company responded on May 9, 2018 and is currently awaiting a decision from FERC.Senior Credit Facility

State Energy Regulation
State Out-Of-Market Subsidy Proposals — On April 12, 2018, the New Jersey State Legislature passed a bill to provide out-of-market subsidies to the state’s nuclear plants. The bill has not yet been signed by the New Jersey Governor. In addition, Certain other states in the areas of the country in which NRG operates, including Ohio and Pennsylvania, have considered but have not enacted proposals to provide out-of-market subsidy payments to potentially uneconomic nuclear and fossil generating units. NRG has opposed 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/rule and tariff changes that occur in the ISO regions. For further discussion on regulatory developments see Note 16, 18, Regulatory Matters, to the Condensed Consolidated Financial Statements.
Gulf Coast
MISO
Revisions to MISO Capacity Construct — On February 28, 2018, FERC issued two orders on MISO’s capacity market design, which together, re-affirm MISO’s existing capacity market structure. FERC also held that, even though there was a period of time between where MISO’s capacity market structure may not have just and reasonable, FERC exercised its remedial authority not to rerun past auctions. On March 30, 2018, the Company filed a motion for rehearing with FERC. The eventual outcome of this proceeding will affect capacity prices in MISO and the incentive for generators in MISO to sell capacity into neighboring markets.


East/West
PJM
2021/2022 PJM Auction Results — On May 23, 2018, PJM announced the results of its 2021/2022 base residual auction. NRG, excluding GenOn, cleared approximately 4,740 MW of Capacity Performance product. NRG’s expected capacity revenues, excluding GenOn, from the base residual auction for the 2021/2022 delivery year are approximately $328 million.
The table below provides a detailed description of NRG’s 2021/2022 base residual auction results from May 23, 2018:
 Capacity Performance Product
Zone
Cleared Capacity (MW)(a)
 Price ($/MW-day)
COMED3,995 $195.55
DPL552 $165.73
MAAC121 $140.00
PEPCO72 $140.00
Total4,740  
(a)Does not include capacity sold by NRG Curtailment Specialists.
Capacity Market Reforms Filing—On April 9, 2018, PJM filed with FERC twois considering various proposals to reform the PJM capacity market, reform proposals in one filing attempting to address market impacts created by out-of-market subsidies.PJM proposed a capacity re-pricing proposal as its preferred optionincluding whether to accommodate state subsidies in the wholesale market. In the alternative, PJM proposes extending its MOPRmarket or to existingmitigate 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 FERC issued an order rejecting both ofOrder with respect to the PJM proposals. Instead, FERC found the existing PJM tariff unjust and unreasonable, and initiated a new proceeding to develop a just and reasonable outcome. Among other things,August 2019 BRA. On July 25, 2019, FERC directed PJM not to adoptrun 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 minimum price rule that would apply to all subsidized resources, including nuclear and renewable resources. Additionally, FERC directed PJM to consider whether to allow state regulators to remove equal amounts of subsidized generation and load from the capacity market. FERC established a briefing schedule and committed to issuing a final order in early 2019critical factor for implementation for next year’s BRA.setting future prices.
PJM Seasonal Capacity ProceedingPJM's Operational Reserve Demand Curve Filing — On November 17, 2016,March 29, 2019, PJM proposed energy and reserve market reforms to allow winter-enhance price formation in reserve markets, which includes modifying its Operating Reserve Demand Curve and summer-peaking capacity resources to “aggregate” their seasonal capacity into an annual capacity product eligible to participatealigning market-based reserve products in Day-Ahead and Real-Time markets. The matter is pending at FERC. If the proposal were approved as Capacity Performance resources. NRG filed, comments specifically supporting PJM’s proposal to modify the aggregation rules to allow seasonal capacity resources to aggregate across LDAsenergy and to allow aggregations through RPM auctions, but opposing the move to seasonal capacity. On January 23, 2017, PJM amended its proposal to address questions from FERC. On March 21, 2017, FERC issued a decision accepting PJM's seasonal capacity aggregation filing pursuant to FERC staff's delegated authority, since FERC did not have a quorum at the time.reserve market prices could increase.
Independent Market Monitor Market Seller Offer Cap Complaint — On February 23, 2018, FERC re-affirmed21, 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 prior order. On February 23, 2018, FERC accepted PJM's filing and dismissedanswer arguing that as a threshold matter the requests for clarification. The outcome of this proceedingIndependent Market Monitor is not authorized to file a complaint against PJM. If the request is granted, default market offer caps could have a material impact on future PJM capacity prices.
Complaints Related to Extension of Base Capacity — In 2015, FERC approved changes to PJM’s capacity market, which included moving from the Base Capacity product to the higher performance Capacity Performance product over the course of a five year transition. Under this transition, as of the May 2017 BRA, the Base Capacity product will no longer be available.  Several parties have filed complaints at FERC seeking to maintain the RPM Base Capacity product for at least one more delivery year or until such time as PJM develops a model for seasonal resources to participate. On February 23, 2018, FERC issued an Order scheduling a technical conference and established a refund effective date of December 23, 2016 and January 5, 2017 for the complaints. Multiple parties filed for rehearing. FERC held a technical conference on April 24, 2018 and received post-technical conference comments on July 13, 2018. The outcome of this proceeding could have a material impact on future PJM capacity prices.lower.
New England
ISO-NE Retention of Mystic Units — ISO-NE recently announced that it had denied delist bids submitted by two ofis 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 three Mystic generating units attached to the DistriGas LNG terminal outside of Boston, citing local reliability concerns. Subsequently, ISO-NE announced its intent to retain the Mystic units in future auctions through an out-of-market payment, citing “fuel security” concerns. On May 1, 2018, ISO-NE filed with FERC to allow it to retain the Mystic units. On July 2, 2018, FERC issued an order denying ISO-NE's requeststation, which utilizes liquefied natural gas for a waiver and initiated a new proceeding to examine whether ISO-NE's capacity market rules were just and reasonable.fuel security. Among other things, FERC found that ISO-NE should file a short-term fuel security agreement as part of its tariff and then redesign its capacity market tospecifically will allow unitsresources retained for fuel security to set priceenter a zero bid in the capacity market. Additional briefing is due 90 days after issuance of the order.


Competitive Auctions with Sponsored Resources Proposal (CASPR) —Forward Capacity Auction, and also ordered ISO-NE to provide a long-term market-based solution for fuel security. On January 8, 2018, ISO-NE2, 2019, multiple parties filed the CASPR proposal which attempts to accommodate state sponsored resources while maintaining competitive market pricing. On January 29, 2018, NRG protested certain aspects of the proposal and also supported ISO-NE’s beginning attempts to address state sponsored resources entering the capacity market. On March 9, 2018, FERC accepted ISO-NE's proposal. On April 9, 2018, NRG joined another generator in filing a request for rehearing. The motions for rehearing isare pending at FERC. The outcome of this proceeding will potentiallymatter may affect future capacity market prices.
Renewable Technology Resource (RTR) Exemption
ISO-NE Inventoried Energy Compensation Proposal—In 2014, 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, approved a package of revisions that included a renewables exemption called the RTR Exemption. After FERC denied rehearing, the case was appealedNRG filed comments to the D.C. Circuit. After a voluntary remand motion, the Court remanded the case back to FERC. In 2016,ISO-NE's response on June 27, 2019. On August 6, 2019, FERC issued an order reaffirming its decision. In 2017, a groupnotice stating that due to lack of generators, including NRG, filed a petition for review withquorum, ISO-NE's proposal became effective by operation of law. ISO-NE's proposal will affect future capacity market prices and the D.C. Circuit. On July 31, 2018, the Court upheld FERC's decision.
Northern Pass Siting Application — On February 1, 2018, the New Hampshire Site Evaluation Committee denied the application for Northern Pass Transmission to cross the state with a 160-mile transmission line from Quebec into southern New Hampshire.  The Northern Pass transmission line project had previously been awarded a contract by the State of Massachusetts, which is now in doubt. The addition of 1,000 MW of additional Canadian hydropower associated with Northern Pass would have affected energy and capacity prices. On February 28, 2018, Northern Pass Transmission filed a motion for rehearing. On March 13, 2018, the New Hampshire Site Evaluation Committee suspended the request for rehearing pending a written decision on the project's full application.compensation fuel secure units receive.
New York
Independent Power Producers of New York (IPPNY) Complaint — On January 9, 2017, EPSA requested FERC to promptly direct the NYISO to file tariff provisions to address pending market concerns related to out-of-market payments to existing generation in the NYISO. This request was prompted by the ZEC program initiated by the NYSPSC. This request follows IPPNY’s complaint at FERC against the NYISO on May 10, 2013, as amended on March 25, 2014. On April 5, 2018, EPSA filed a motion for renewed request for expedited action on the MOPR. The generators asked FERC to direct the NYISO to require that capacity from existing generation resources that would have exited the market but for out-of-market payments be mitigated. Failure to implement buyer-side mitigation measures could result in uneconomic entry, which artificially decreases capacity prices below competitive market levels.
New YorkState Public Service Commission Retail Energy Market Proceedings — On February 23, 2016, the NYSPSC issued what it refersan order referred to as its “Retail Reset” order, orthe Retail Reset Order, in Docket 12-M-0476 et al.Order. Among other things, the Retail Reset Order placed a price cap on energy supply offers and required many retail providers to seek affirmative consent from certain retailimposed burdensome new regulations on customers. Various parties have challenged the NYPSC’sNYSPSC's authority to regulate prices charged by competitive supplierssuppliers. 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 New York state court. Ontwo phases of gradually increasing magnitude. The first phase became effective on March 29, 2018,1, 2019 and the New York State Court of Appeals grantedsecond phase will become effective on March 1, 2020. To date, the ORDC reforms have produced a motion by the Retail Energy Supply Association and National Energy Marketers Association for leave to appeal an earlier adverse Appellate Division ruling. In conjunction with the court challenges, the NYPSC noticed both an evidentiary and a collaborative track to address the functioning of the competitive retail markets. An administrative hearing on the evidentiary track concluded on December 12, 2017 after 10 days of testimony and is nownoticeable improvement in the post-hearing brief phase. The outcome of the evidentiary and collaborative processes, combined with the outcome of the appeal of the Reset Order, could affect the viability of the New York retail energy market.scarcity pricing.
CAISO
Puente Power Project — On October 5, 2017, the California Energy Commission, or CEC, the agency responsible for permitting the Puente Power Project, issued a statement on behalf of the committee of two Commissioners overseeing the permitting process stating their intention to issue a proposed decision that would deny a permit for the Puente Power Project. On October 16, 2017, NRG filed a motion to suspend the permitting proceeding for at least six months, which was granted on November 3, 2017. On May 31, 2018, the CEC extended the suspension period at NRG's request to July 1, 2019. The supplemental extension period should allow sufficient time to determine whether alternate procurement efforts undertaken by SCE supersede the need for the Puente Power Project.



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 20172018 Form 10-K in Item 1, Business - Environmental Matters and Item 1A, Risk Factors. These matters have been updated in Item 1 — Note 17, 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

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.
WaterDomestic Site Remediation Matters
Clean WaterUnder 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.renewed, the Company anticipates the cost of complying with these restrictions 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, or FGD, fly ash, bottom ash, and flue gas mercury control. In April 2017, the EPA granted two petitions to reconsider the rule and also administratively stayed some of the deadlines. On September 18, 2017, the EPA promulgated a final rule that, (i)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 rulemakingrulemaking. 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 (ii) withdrewcoal ash leachate and remanded portions of the April 2017 administrative stay.rule to the EPA. The legal challenges have been suspended while the EPA reconsiders and likely modifies the rule. Accordingly, the Company has largely eliminated its estimate of the environmental capital expenditures that would have been required to comply with permits incorporating the revised guidelines. The Company will revisit these estimates after the rule is revised.EPA revises the rule.
Regional Environmental Developments
Texas Regional Haze 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 October 17, 2017,July 30, 2019, Illinois enacted legislation that will require the EPA promulgated a final rule creating a Texas-only SO2 cap-and-trade programstate to address regional haze. The program is scheduled to begin on January 1, 2019. Several of the Company's units in Texas will be affected by this rule. The rule has been challenged by several environmental groups in the Fifth Circuit of the U.S. Court of Appeals, which litigation has been stayed pending resolution of administrative petitions for reconsideration.promulgate regulations regarding coal ash.




Significant Events
The following significant events have occurred during 2018,2019, 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 Transformation Planbegan 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.

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 describeda 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 Company has continuedTexas fleet by increasing spending by $21 million, including the return of its 385 MW Gregory natural gas plant in Corpus Christi, Texas to execute on its Transformation Plan.service in June 2019.
XOOMStream Energy Acquisition
On June 1, 2018,May 15, 2019, the Company completed the acquisition of XOOM Energy, LLC,entered into an agreement to acquire Stream Energy's retail electricity and natural gas retailerbusiness operating in 199 states and Washington, D.C. and Canada for approximately $219$300 million in cash inclusiveand estimated transaction costs and working capital adjustments of approximately $54 million in payments for estimated working capital, which is subject to further adjustment.$25 million. The acquisition increased NRG's retail portfolio by approximately 300,000 customers in the aggregate by June 30, 2018.
Ivanpah Deconsolidation
During the second quarter of 2018, the Company, recognized a loss of $22 million600,000 RCEs or 450,000 customers. The acquisition closed on the deconsolidation and subsequent recognition of its 54.6% interest in Ivanpah as an equity method investment, as discussed in more detail in Note 9, Variable Interest Entities, or VIEs.
Financing Activities
On March 21, 2018, the Company repriced the 2023 Term Loan Facility, reducing the interest rate margin by 50 basis points to LIBOR plus 1.75% and reducing the LIBOR floor to 0.00%. As a result of the repricing, the Company expects approximately $47 million in interest savings over the remaining life of the loan.
On May 24, 2018, the Company issued $575 million in aggregate principal amount at par of 2.75% convertible senior notes due 2048, as discussed in more detail in Note 8, Debt and Capital Leases.
On June 19, 2018, the Company entered into an amended and restated Thermal note purchase and private shelf agreement whereas it authorized the issuance of the Series E Notes, Series F Notes, Series G Notes, and Series H Notes, as discussed in more detail in Note 8, Debt and Capital Leases.
During the six months ended June 30, 2018, the Company repurchased $43 million in aggregate principal of its Senior Notes in the open market for $45 million, including accrued interest as discussed in more detail in Note 8, Debt and Capital Leases. In July 2018, the Company repurchased an additional $46 million in aggregate principal of its Senior Notes in the open market for $48 million including accrued interest.
On August 1, 2018, the Company announced that it gave the required notice under the indenture governing its 6.25% Senior Notes due 2022, or the 2022 Notes, to redeem for cash $486 million aggregate principal amount of its 2022 Notes, or the Partial Redemption, on August 31, 2018, or the Redemption Date. The redemption price for the 2022 Notes will be 103.125% of the principal amount of the 2022 Notes, plus accrued and unpaid interest to the Redemption Date. The Partial Redemption, combined with recently completed open market repurchases of approximately $89 million of the Company's outstanding indebtedness, will result in the retirement of outstanding indebtedness equal to approximately $575 million which is the aggregate principal amount of the Company's 2.75% convertible senior notes due 2048 issued on May 24, 2018.
Share Repurchases
In February 2018, the Company's board of directors authorized the Company to repurchase $1 billion of its common stock, with the first $500 million program beginning as soon as permitted. In March 2018, the Company repurchased 3,114,748 shares of NRG common stock for approximately $93 million. During the second quarter of 2018, the Company repurchased 11,748,553 shares of NRG common stock for approximately $407 million, including shares repurchased under the ASR Agreement. In July 2018, the Company received an additional 860,880 shares in connection with the settlement of the ASR Agreement, completing the $500 million of share repurchases. The average cost per share for the total $500 million of shares repurchased was $31.80.


2019.
Trends Affecting Results of Operations and Future Business Performance
The Company’s trends are described in the Company’s 20172018 Form 10-K in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations - Trends Affecting Results of Operations and Future Business Performance, and below.Environment.

ERCOT Pricing — ERCOT forward prices for July and August 2018 are significantly higher than where previous summers have settled.  These elevated pricing levels mean that deviations from expected demand and/or generation availability may have a material impact on the Company’s actual results.
Changes in Accounting Standards
See Note 2, Summary of Significant Accounting Policies, to the Condensed Consolidated Financial Statements of this Form 10-Q, for a discussion of recent accounting developments.





Consolidated Results of Operations
The following table provides selected financial information for the Company:
Three months ended June 30, Six months ended June 30,Three months ended June 30,
Six months ended June 30,
(In millions except otherwise noted)2018 2017 Change 2018 2017 Change
(In millions, except as otherwise noted)2019
2018
Change
2019
2018
Change
Operating Revenues           











Energy revenue (a)
$673
 $656
 $17
 $1,292
 $1,243
 $49
$249

$410

$(161)
$555

$853

$(298)
Capacity revenue (a)
313
 297
 16
 601
 559
 42
155

165

(10)
309

307

2
Retail revenue1,816
 1,605
 211
 3,302
 2,946
 356
1,745

1,813

(68)
3,351

3,298

53
Mark-to-market for economic hedging activities15

41
 (26) (91) 159
 (250)241

10

231

261

(86)
347
Contract amortization(14) (14) —
 (28) (29) 1
Other revenues (b)
119
 116
 3
 267
 205
 62
75

63

12

154

154

—
Total operating revenues2,922
 2,701
 221
 5,343
 5,083
 260
2,465

2,461

4

4,630

4,526

104
Operating Costs and Expenses           










Cost of sales (c)
1,515
 1,422
 (93) 2,908
 2,683
 (225)
Cost of Sales (c)
1,273

1,453

180

2,614

2,775

161
Mark-to-market for economic hedging activities86
 (18) (104) (216) 118
 334
220

86

(134)
220

(216)
(436)
Contract and emissions credit amortization (c)
7
 8
 1
 13
 16
 3
6

7

1

11

13

2
Operations and maintenance360
 340
 (20) 730
 712
 (18)284

282

(2)
531

573

42
Other cost of operations83
 89
 6
 174
 175
 1
62

61

(1)
120

129

9
Total cost of operations2,051
 1,841
 (210) 3,609
 3,704
 (95)1,845
 1,889
 44
 3,496
 3,274
 (222)
Depreciation and amortization227
 260
 33
 462
 517
 55
85
 112
 27
 170
 232
 62
Impairment losses74
 63
 (11) 74
 63
 (11)1
 74
 73
 1
 74
 73
Selling, general and administrative211
 221
 10
 402
 481
 79
211
 200
 (11) 405
 376
 (29)
Reorganization costs23
 —
 (23) 43
 —
 (43)2
 23
 21
 15
 43
 28
Development costs16
 18
 2
 29
 35
 6
2
 3
 1
 4
 8
 4
Total operating costs and expenses2,602
 2,403
 (199) 4,619

4,800
 181
2,146
 2,301
 155
 4,091

4,007
 (84)
Other income - affiliate—
 39
 (39) —
 87
 (87)
Gain on sale of assets14
 2
 12
 16
 4
 12
1
 14
 (13) 2
 16
 (14)
Operating Income334
 339
 (5) 740
 374
 366
320
 174
 146
 541
 535
 6
Other Income/(Expense)                      
Equity in earnings/(losses) of unconsolidated affiliates18
 (3) 21
 16
 2
 14
—
 5
 (5) (21) 6
 (27)
Other (losses)/income, net(20) 14
 (34) (23) 26
 (49)
Other income/(expense), net20
 (23) 43
 32
 (23) 55
Loss on debt extinguishment, net(1) —
 (1) (3) (2) (1)(47) (1) (46) (47) (3) (44)
Interest expense(202) (247) 45
 (369) (471) 102
(105) (123) 18
 (219) (239) 20
Total other expense(205) (236) 31
 (379) (445) 66
(132) (142) 10
 (255) (259) 4
Income/(Loss) from Continuing Operations before Income Taxes129
 103
 26
 361
 (71) 432
Income tax expense/(benefit)8
 4
 4
 7
 (1) 8
Income/(Loss) from Continuing Operations121
 99
 22
 354
 (70) 424
Loss from discontinued operations, net of income tax(25) (741) 716
 (25) (775) 750
Net Income/(Loss)96
 (642) 738
 329
 (845) 1,174
Less: Net income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interest24
 (16) 40
 (22) (55) 33
Net Income/(Loss) Attributable to NRG Energy, Inc.$72
 $(626) $698
 $351
 $(790) $1,141
Income from Continuing Operations Before Income Taxes188
 32
 156
 286
 276
 10
Income tax (benefit)/expense(1) 5
 6
 3
 11
 8
Income from Continuing Operations189
 27
 162
 283
 265
 18
Income from discontinued operations, net of income tax13
 69
 (56) 401
 64
 337
Net Income202
 96
 106
 684
 329
 355
Less: Net income/(loss) attributable to noncontrolling interest and redeemable interests1
 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)$2.80
 $3.18
 (12)% $2.90
 $3.25
 (11)%$2.64
 $2.80
 (6)% $2.89
 $2.90
 — %
(a) Includes realized gains and losses from financially settled transactions.transactions
(b) Includes unrealized trading gains and losses.losses
(c) Includes amortization of SO2 and NOx credits and excludes amortization of RGGI credits.     credits     



Management’s discussion of the results of operations for the three months ended June 30, 20182019 and 20172018
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, 20182019 and 2017.2018. The average on-peak power prices for ERCOT - Houston and COMED (PJM) decreasedwere lower primarily due to the change in congestion pattern for the three months ended June 30, 2018, as compared to the same period in 2017.driven by mild weather.
Average on Peak Power Price ($/MWh)Average on Peak Power Price ($/MWh)
Three months ended June 30,Three months ended June 30,
Region2018 2017 Change %2019 2018 Change %
Gulf Coast (a)
     
Texas     
ERCOT - Houston (b)(a)
$34.82
 $46.03
 (24)%$31.88
 $34.82
 (8)%
ERCOT - North(b)(a)
34.89
 27.80
 26 %30.13
 34.89
 (14)%
MISO - Louisiana Hub(c)(b)
44.20
 42.77
 3 %33.40
 44.20
 (24)%
East/West          
NY J/NYC(c)(b)
36.41
 39.35
 (7)%29.52
 36.41
 (19)%
NEPOOL(c)(b)
36.28
 33.57
 8 %27.15
 36.28
 (25)%
COMED (PJM)(c)(b)
31.88
 33.40
 (5)%26.78
 31.88
 (16)%
PJM West Hub(c)(b)
39.73
 32.79
 21 %28.54
 39.73
 (28)%
CAISO - NP15(c)
27.37
 28.29
 (3)%
CAISO - SP15(c)
27.75
 30.72
 (10)%
CAISO - SP15(b)
23.30
 27.75
 (16)%
(a) Gulf Coast region also transacts in PJM - West Hub.
(b) Average on peak power prices based on real time settlement prices as published by the respective ISOs.ISOs
(c)(b) Average on peak power prices based on day ahead settlement prices as published by the respective ISOs.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, 20182019 and 2017, which reflects the impact of settled hedges.2018:
 Average Realized Power Price ($/MWh)
 Three months ended June 30,
Region2018 2017 Change %
Gulf Coast$36.33
 $34.68
 5 %
East/West (a)
35.63
 36.67
 (3)%
 Average Realized Power Price ($/MWh)
 Three months ended June 30,
Region2019 2018 Change %
Texas$43.59
 $36.96
 18 %
East/West/Other (a)(b)
34.60
 43.39
 (20)%
(a) doesDoes not include BETM energy revenue of $15 million and $14$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 2017, respectively.August 2018, respectively


Though theThe average on peakrealized power prices have remained relatively flat, average realized prices by region for the Company have generally fluctuated at different rates year-over-yearfor 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 Company's multi-year hedging program.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.

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, 20182019 and 2017:2018:
 Three months ended June 30, 2018
   Generation        
(In millions)Retail Gulf Coast 
East/West(a)
 Subtotal Renewables NRG Yield Corporate/Eliminations Total
Energy revenue$—

$508

$144

$652

$79

$192

$(250)
$673
Capacity revenue—

68

160

228

—

87

(2)
313
Retail revenue1,817

—

—

—

—

—

(1)
1,816
Mark-to-market for economic hedging activities—

289

(15)
274

5

—

(264)
15
Contract amortization—

4

—

4

—

(18)
—

(14)
Other revenue (b)
—

42

18

60

29

46

(16)
119
Operating revenue1,817

911

307

1,218

113

307

(533)
2,922
Cost of fuel(4)
(260)
(70)
(330)
—

(9)
(25)
(368)
Other cost of sales(c)
(1,315)
(81)
(21)
(102)
(2)
(8)
280

(1,147)
Mark-to-market for economic hedging activities(346)
(4)
—

(4)
—

—

264

(86)
Contract and emission credit amortization—

(7)
—

(7)
—

—

—

(7)
Gross margin$152

$559

$216

$775

$111

$290

$(14)
$1,314
Less: Mark-to-market for economic hedging activities, net(346)
285

(15)
270

5

—

—

(71)
Less: Contract and emission credit amortization, net—

(3)
—

(3)
—

(18)
—

(21)
Economic gross margin$498

$277

$231

$508

$106

$308

$(14)
$1,406
Business Metrics               
MWh sold (thousands)(d)(e)
  13,982
 3,616
   1,211
 2,308
    
MWh generated (thousands) (f)
  12,959
 2,903
   1,211
 2,675
    
(a) Includes International, BETM and Generation eliminations
(b) Renewables other revenue includes $13 million of intercompany revenue to NRG Yield.
(c) Includes purchased energy, capacity and emissions credits
(d) MWh sold excludes generation at facilities in East/West and NRG Yield that generate revenue under capacity agreements.
(e) Does not include thermal MWh of 9 thousand or MWt of 462 thousand for thermal sold by NRG Yield.
(f) Does not include thermal MWh of 28 thousand or MWt of 462 thousand for thermal generated by NRG Yield.



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 revenue1,746

—

—

—

(1)
1,745
Mark-to-market for economic hedging activities2

460

64

524

(285)
241
Other revenue—

16

59

75

—

75
Operating revenue1,748

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, 2017Three months ended June 30, 2018
  Generation        

Generation



(In millions)Retail Gulf Coast 
East/West(a)
 Subtotal Renewables NRG Yield Corporate/Eliminations Total
($ In millions)Retail
Texas
East/West/Other(a)(b)

Subtotal
Corporate/Eliminations
Total
Energy revenue$—

$484

$184

$668

$105

$177

$(294)
$656
$—

$402

$259

$661

$(251)
$410
Capacity revenue—

68

144

212

—

85

—

297
—

—

165

165

—

165
Retail revenue1,605

—

—

—

—

—

—

1,605
1,814

—

—

—

(1)
1,813
Mark-to-market for economic hedging activities(2)
(90)
13

(77)
(3)
—

123

41
—

296

(22)
274

(264)
10
Contract amortization—

3

—

3

—

(17)
—

(14)
Other revenue (b)
—

55

21

76

17

43

(20)
116
Other revenue—

10

57

67

(4)
63
Operating revenue1,603

520

362

882

119

288

(191)
2,701
1,814

708

459

1,167

(520)
2,461
Cost of fuel(2)
(284)
(82)
(366)
(1)
(7)
5

(371)(3)
(188)
(115)
(303)
—

(306)
Other cost of sales(c)
(1,211)
(79)
(52)
(131)
(2)
(7)
300

(1,051)(1,315)
(35)
(50)
(85)
254

(1,146)
Mark-to-market for economic hedging activities158

(15)
(2)
(17)
—

—

(123)
18
(346)
(3)
(1)
(4)
264

(86)
Contract and emission credit amortization—

(7)
(1)
(8)
—

—




(8)—

(7)
—

(7)
—

(7)
Gross margin$548

$135

$225

$360

$116

$274

$(9)
$1,289
$150

$475

$293

$768

$(2)
$916
Less: Mark-to-market for economic hedging activities, net156

(105)
11

(94)
(3)
—

—

59
(346)
293

(23)
270

—

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

(4)
(1)
(5)
—

(17)
—

(22)—

(7)
—

(7)
—

(7)
Economic gross margin$392

$244

$215

$459

$119

$291

$(9)
$1,252
$496

$189

$316

$505

$(2)
$999
Business Metrics                          
MWh sold (thousands)(d)(e)
  13,958
 4,598
   1,059
 2,112
    
MWh generated (thousands) (f)
  13,101
 3,079
   1,059
 2,425
    
(a) Includes International, BETM and Generation eliminations.
(b) Renewables other revenue includes $7 million of intercompany revenue to NRG Yield.
MWh sold (thousands)  10,876
 5,969
      
MWh generated (thousands)  9,848
 5,255
      
(a) Includes International, Renewables, and Generation eliminations(a) Includes International, Renewables, and Generation eliminations
(b) Includes BETM which was sold as of July 31, 2018(b) Includes BETM which was sold as of July 31, 2018
(c) Includes purchased energy, capacity and emissions credits
(d) MWh sold excludes generation at facilities in the East, West and NRG Yield that generate revenue under capacity agreements.
(e) Does not include thermal MWh of 9 thousand or MWt of 418 thousand for thermal sold by NRG Yield.
(f) Does not include thermal MWh of 20 thousand or MWt of 418 thousand for thermal generated by NRG Yield.

The table below represents the weather metrics for the three months ended June 30, 20182019 and 2017:2018:
Three months ended June 30,Three months ended June 30,
Weather MetricsGulf Coast East/WestTexas 
East/West/Other(b)
2018   
2019   
CDDs (a)
1,067
 265
934
 458
HDDs (a)
108
 425
70
 283
2017   
2018   
CDDs921
 281
1,101
 521
HDDs41
 380
91
 325
10-year average      
CDDs970
 259
1,009
 487
HDDs67
 429
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.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



Retail gross marginGross Margin and economic gross marginEconomic Gross Margin
The following is a discussion of gross margin and economic gross margin for Retail.
Three months ended June 30,Three months ended June 30,
(In millions except otherwise noted)2018 2017
(In millions, except as otherwise noted)2019 2018
Retail revenue$1,689
 $1,515
$1,650
 $1,687
Supply management revenue42
 52
50
 42
Capacity revenue86
 38
46
 85
Customer mark-to-market—
 (2)2
 —
Operating revenue (a)
1,817
 1,603
1,748
 1,814
Cost of sales (b)
(1,319) (1,213)(1,288) (1,318)
Mark-to-market for economic hedging activities(346) 158
(486) (346)
Gross Margin$152
 $548
$(26) $150
Less: Mark-to-market for economic hedging activities, net(346) 156
(484) (346)
Economic Gross Margin$498
 $392
$458
 $496
      
Business Metrics      
Mass electricity sales volume — GWh - Gulf Coast9,802
 9,234
Mass electricity sales volume — GWh - Texas9,130
 9,793
Mass electricity sales volume — GWh - All other regions1,592
 1,357
1,913
 1,600
C&I electricity sales volume — GWh - All regions5,403
 5,308
5,008
 5,403
Natural gas sales volumes (MDth)1,244
 438
3,054
 1,244
Average Retail Mass customer count (in thousands)
2,973
 2,859
3,306
 2,966
Ending Retail Mass customer count (in thousands) (c)
3,173
 2,887
3,277
 3,149
(a)Includes intercompany sales of $1$2 million and $1$4 million in 20182019 and 2017,2018, respectively, representing sales from Retail to the Gulf Coast region.Texas region
(b)Includes intercompany purchases of $374 million and $251 million in 2019 and $293 million in 2018, and 2017, respectively.
(c)The acquisitionrespectively, inclusive of XOOM Energy, LLC increased NRG's retail portfolio by approximately 300,000 customers in the aggregate by June 30, 2018.internal transfer of large average annualized market price transactions

Retail gross margin decreased $396$176 million and economic gross margin increased $106decreased $38 million for the three months ended June 30, 20182019, compared to the same period in 20172018, due to:
  (In millions)
Higher gross margin due to higher revenue of $63 million or approximately $3.25 per MWh, driven by customer product, term and mix, offset by higher supply costs of $25 million or approximately $1.25 per MWh, driven by an increase in power prices $38
Higher gross margin from the Business Solutions unit reflecting the early settlement of capacity obligations for 2018 34
Higher gross margin due to an increase in load of 790,000 MWh driven by warmer weather conditions in 2018 as compared to 2017 27
Higher gross margin due to higher volumes driven by higher average customer counts primarily driven by the XOOM acquisition in June 2018 7
Increase in economic gross margin $106
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges (502)
Decrease in gross margin $(396)
  (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)





Generation gross marginGross Margin and economic gross marginEconomic Gross Margin
Generation gross margin increased $415$224 million and economic gross margin increased $49decreased $12 million, both of which include intercompany sales, during the three months ended June 30, 2018,2019, compared to the same period in 2017.2018.


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


Gulf CoastTexas Region
 (In millions)
Higher gross margin due to a 5% increase in average realized prices in South Central and a 6% increase in average realized prices in Texas$45
Higher capacity margins due to an increase in load demand in the South Central business10
Lower energy margin due to a 14% increase in supply cost on load contracts(9)
Lower capacity revenue due to the cancellation of the Greens Bayou RMR agreement in 2017(6)
Lower gross margin from commercial optimization activities(5)
Other(2)
Increase in economic gross margin$33
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges391
Increase in gross margin$424
 (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 201826
Higher gross margin from commercial optimization activities7
Higher gross margin due to margin enhancement initiatives from reduced fuel supply costs7
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 hedges151
Increase in contract and emission credit amortization1
Increase in gross margin$250

East/WestWest/Other
 (In millions)
Higher gross margin due to a 80% increase in New England cleared capacity pricing$16
Higher gross margin due to a 26% increase in PJM cleared capacity pricing which relates to the first full period of capacity performance product pricing15
Lower gross margin due to a 29% decrease in capacity pricing in New York of $15 million and decreases in capacity pricing and volumes due to the Long Beach capacity toll expiration in July 2017 of $4 million(19)
Lower gross margin due to a 6% decrease in generation volumes due to timing of planned and unplanned outages at Midwest Generation, offset by favorable fuel costs(8)
Higher gross margin due to insurance proceeds from outages of $14 million in 2018, compared to business interruption proceeds of $8 million in 20176
Other6
Increase in economic gross margin$16
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges(26)
Increase in contract and emission credit amortization1
Decrease in gross margin$(9)
 (In millions)
Lower gross margin due to the deconsolidations of Ivanpah in April 2018 and Agua Caliente in August 2018$(43)
Lower gross margin primarily due to the sale of BETM, Keystone and Conemaugh in the third quarter of 2018, Guam in the first quarter of 2019 and the retirement of Encina in December 2018(41)
Lower gross margin due to insurance proceeds from outages in 2018(14)
Lower gross margin due to a 22% decrease in realized capacity pricing in New York(10)
Lower gross margin due to an extended forced outage at the Sunrise facility in 2019(7)
Lower gross margin due to a 11% decrease in average realized prices at Cottonwood(7)
Lower gross margin driven by a decrease in economic generation volume due to planned outages in 2019(6)
Higher gross margin due to a 20% increase in PJM capacity prices and a 10% increase in ISO-NE capacity prices16
Higher gross margin from commercial optimization activities6
Other(4)
Decrease in economic gross margin$(110)
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges84
Decrease in gross margin$(26)


Renewables gross margin and economic gross margin
Renewables gross margin decreased $5 million and economic gross margin decreased $13 million for the three months ended June 30, 2018, compared to the same period in 2017. This was driven by the deconsolidation of Ivanpah in May 2018, partially offset by additional distributed solar projects reaching commercial operations in late 2017 and early 2018.
NRG Yield gross margin and economic gross margin
NRG Yield gross margin increased $16 million and economic gross margin increased $17 million for the three months ended June 30, 2018, compared to the same period in 2017. The increase is due to a 9% increase in volume generated by wind projects, primarily the Alta Wind projects and Wildorado from increased wind resources, as well as a 2% increase in solar generation, primarily at CVSR due to higher insolation.


Mark-to-marketMark-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 decreasedincreased by $130$97 million during the three months ended June 30, 20182019, compared to the same period in 20172018.
The breakdown of gains and losses included in operating revenues and operating costs and expenses by region was as follows:
 Three months ended June 30, 2018
   Generation      
 Retail Gulf Coast East/West Renewables 
Eliminations(a)
 Total
 (In millions)
Mark-to-market results in operating revenues           
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges$—
 $(52) $(8) $—
 $28
 $(32)
Net unrealized gains/(losses) on open positions related to economic hedges—
 341
 (7) 5
 (292) 47
Total mark-to-market gains/(losses) in operating revenues$—
 $289
 $(15) $5
 $(264) $15
Mark-to-market results in operating costs and expenses           
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges$62
 $(2) $(3) $—
 $(28) $29
Reversal of acquired gain positions related to economic hedges(1) —
 —
 —
 —
 (1)
Net unrealized (losses)/gains on open positions related to economic hedges(407) (2) 3
 —
 292
 (114)
Total mark-to-market (losses)/gains in operating costs and expenses$(346) $(4) $—
 $—
 $264
 $(86)
 Three months ended June 30, 2019
   Generation    
 Retail Texas East/West/Other 
Eliminations(a)
 Total
 (In millions)
Mark-to-market results in operating revenues         
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges$(1) $(74) $16
 $59
 $—
Net unrealized gains on open positions related to economic hedges3
 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) $11
Reversal of acquired loss positions related to economic hedges1
 —
 —
 —
 1
Net unrealized (losses) on open positions related to economic hedges(556) (17) (3) 344
 (232)
Total mark-to-market (losses) in operating costs and expenses$(486) $(16) $(3) $285
 $(220)
(a)
Represents the elimination of the intercompany activity between Retail and Generation.Generation
 Three months ended June 30, 2017
   Generation      
 Retail Gulf Coast East/West Renewables 
Eliminations(a)
 Total
 (In millions)
Mark-to-market results in operating revenues           
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges$(1) $(7) $(11) $—
 $50
 $31
Net unrealized (losses)/gains on open positions related to economic hedges(1) (83) 24
 (3) 73
 10
Total mark-to-market (losses)/gains in operating revenues$(2) $(90) $13
 $(3) $123
 $41
Mark-to-market results in operating costs and expenses           
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges$45
 $(4) $—
 $—
 $(50) $(9)
Reversal of acquired loss positions related to economic hedges1
 —
 —
 —
 —
 1
Net unrealized gains/(losses)on open positions related to economic hedges112
 (11) (2) —
 (73) 26
Total mark-to-market gains/(losses) in operating costs and expenses$158
 $(15) $(2) $—
 $(123) $18
 Three months ended June 30, 2018
   Generation    
 Retail Texas East/West/Other 
Eliminations(a)
 Total
 (In millions)
Mark-to-market results in operating revenues         
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges$—
 $(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.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.

For the three months ended June 30, 2018, the $15$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.
For the three months ended June 30, 2017, the $41 million gain in operating revenues from economic hedge positions was driven primarily by the reversal of previously recognized unrealized losses on contracts that settled during the period, as well as an increase in value of open positions as a result of decreases in PJM power prices and New York capacity prices, partially offset by a decrease in value of open positions as a result of ERCOT heat rate expansion. The $18 million gain in operating costs and expenses from economic hedge positions was driven primarily by an increase in value of open positions as a result of ERCOT heat rate expansion, partially offset by a decrease in value of open positions as a result of decrease in coal prices and the reversal of previously recognized unrealized gains 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, 20182019 and 2017.2018. 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 withinbased on the Company's Risk Management Policy and are primarily transacted through BETM.Policy.
Three months ended June 30,Three months ended June 30,
(In millions)2018 20172019 2018
Trading gains      
Realized$25
 $14
$15
 $25
Unrealized5
 12
12
 5
Total trading gains$30
 $26
$27
 $30


Operations and Maintenance Expense
 Retail GenerationRenewables NRG Yield Corporate EliminationsTotal
  Gulf Coast 
East/West(a)
    
   (In millions)
Three months ended June 30, 2018$49

$156

$99

$25

$42

$1

$(12)$360
Three months ended June 30, 2017$57

$105

$105

$34

$46

$5

$(12)$340
(a) Includes International, BETM and generation eliminations of $2 million in 2018 and $1 million in 2017.
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 $20$2 million for the three months ended June 30, 2018,2019, compared to the same period in 2017,2018, due to the following:
 (In millions)
2017 proceeds and 2018 payments in settlement of certain legal matters$33
Increase in operations and maintenance due to the gain on sale of the Jewett Mine dragline in 201718
Increased deactivation costs primarily at Dunkirk7
Increase in major maintenance primarily due to outages at W.A. Parish and Big Cajun II6
Decrease in NRG Yield operations and maintenance expense due to lower costs related to forced outages at Walnut Creek in 2018 compared to 2017, as well as lower losses on disposal of assets at Walnut Creek and El Segundo(5)
Decrease in East/West operations and maintenance expense due to major maintenance at Sunrise in 2017(5)
Decrease in Renewables operations and maintenance expense primarily from the deconsolidation of Ivanpah(9)
Decrease in operations and maintenance expense due to cost efficiencies as a result of the Transformation Plan(25)
 $20

 (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 operations14
Increase primarily related to the lease of Cottonwood from February 4, 201910
Increase due to the XOOM acquisition in June 20183
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


Depreciation and amortizationAmortization
Depreciation and amortization decreased by $33$27 million for the three months ended June 30, 2018,2019, compared to the three months ended June 30, 2017,2018, driven primarily by the impairment of property, plant and equipment in prior years as well as the deconsolidationdeconsolidations of Ivanpah in May 2018.
Impairment Losses
For the three months ended June 30,April 2018 and Agua Caliente in August 2018, the Company recorded impairment lossessale of $74 million related to the impairment of the KeystoneCottonwood in February 2019 and Conemaugh generating stations, as well and the impairment of the Dunkirk project, as described in Note 7, Impairments.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, 2018125

58

17

200
 Retail Generation Renewables NRG Yield Corporate Total
   (In millions)
Three months ended June 30, 2018$126

$55

$12

$7

$11

$211
Three months ended June 30, 2017106

52

14

7

42

221
Selling, general and administrative expenses decreasedincreased by $10$11 million for the three months ended June 30, 2018,2019, compared to the same period in 2017,2018, due to the following:
 (In millions)
Decrease in general and administrative expense from cost initiatives for the Transformation Plan$(36)
Prior year fees associated with advisors engaged to assist the Company in its strategic review in 2017(6)
Increase in bad debt expense primarily from increased usage due to weather6
Increase in expense for estimated legal settlements10
Increase in selling and marketing expense associated with costs incurred for margin enhancement initiatives16
 $(10)
 (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 attrition12
Increase in selling expense due to the acquisition of XOOM in June 20183
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, of $23 million, primarily related to employee severance and contract cancellation costs, were incurred as partdecreased 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.
Other Income - Affiliate
Other income - affiliate represents the services fees charged to GenOn for shared services under the Services Agreement through June 14, 2017, the date of deconsolidation.Plan during 2018.
Gain on Sale of Assets
Gain on sale of assets for the three months ended June 30, 2018 consistsconsisted primarily of gains on the sales of Canal 3 and a piece of land, while the gain on the sale of Canal 3, while the gain on sale of assets for the three months ended June 30, 2017, represents2019 consisted primarily of a gain on the sale of land.
Equity in Earnings/(Losses)Loss on Debt Extinguishment
A loss on debt extinguishment of Unconsolidated Affiliates
Equity in earnings of consolidated affiliates increased by $21$47 million forwas recorded during the three months ended June 30, 2018, compared to the three months ended June 30, 2017, which was primarily2019, driven by the equity in earnings recorded in 2018 for Ivanpah after deconsolidation, as well as by prior year losses from Petra Nova Parish Holdings, offset byredemption of the prior period HLBV income allocated to2024 Senior Notes and the Company’s interests inrepayment of the Utah Portfolio.
Other (Losses)/Income, Net
Other losses for the three months ended June 30, 2018, primarily relate to the loss on deconsolidation of Ivanpah of $22 million. Other income for the three months ended June 30, 2017, primarily relates to dividends received from cost method investments as well as income from pension and postretirement investments.

2023 Term Loan Facility.

Interest Expense
NRG's interest expense decreased by $46 million for the three months ended June 30, 2018, compared to the same period in 2017 due to the following:
 (In millions)
Decrease in derivative interest expense from changes in the fair value of interest rate swaps driven by increased interest rates in 2018$(35)
Decrease in interest expense related to repurchases of Senior Notes(9)
Decrease in interest expense related to Ivanpah deconsolidation(6)
Other4
 $(46)
Income Tax Expense
For the three months ended June 30, 2018, NRG recorded an income tax expense of $8 million on pre-tax income of $129 million. For the same period in 2017, NRG recorded an income tax expense of $4 million on pre-tax income of $103 million. The effective tax rate was 6.2% and 3.9% for the three months ended June 30, 2018 and 2017, respectively.
For the three months ended June 30, 2018, NRG's overall effective tax rate was different than the statutory rate of 21% primarily due to the tax benefit for the change in valuation allowance and the generation of PTCs from various wind facilities partially offset by the inclusion of consolidated partnerships and the current state tax expense.
For the three months ended June 30, 2017, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the tax benefit for the change in valuation allowance and the generation of PTCs and ITCs from various wind and solar facilities, respectively, partially offset by the inclusion of consolidated partnerships and current state tax expense.
Net loss attributable to noncontrolling interests and redeemable noncontrolling interests
For the three months ended June 30, 2018 and 2017, net loss attributable to noncontrolling interests and redeemable noncontrolling interests primarily reflects net losses allocated to tax equity investors in tax equity arrangements using the hypothetical liquidation at book value, or HLBV, method, partially offset by NRG Yield, Inc.'s share of net income.


Management’s discussion of the results of operations for the six months ended June 30, 2018 and 2017
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, 2018 and 2017. The average on-peak power prices have generally increased primarily due to increased heat rates for the six months ended June 30, 2018, as compared to the same period in 2017.
 Average on Peak Power Price ($/MWh)
 Six months ended June 30,
Region2018 2017 Change %
Gulf Coast (a)
     
ERCOT - Houston (b)
$33.98
 $36.86
 (8)%
ERCOT - North(b)
33.28
 25.28
 32 %
MISO - Louisiana Hub(c)
45.22
 43.71
 3 %
East/West     
    NY J/NYC(c)
49.19
 37.48
 31 %
    NEPOOL(c)
51.07
 33.69
 52 %
    COMED (PJM)(c)
32.54
 31.89
 2 %
    PJM West Hub(c)
43.58
 32.40
 35 %
CAISO - NP15(c)
30.05
 27.38
 10 %
CAISO - SP15(c)
31.60
 26.87
 18 %
(a) Gulf Coast region also transacts in PJM - West Hub.
(b) Average on peak power prices based on real time settlement prices as published by the respective ISOs.
(c) Average on peak power prices based on day ahead settlement prices as published by the respective ISOs.
The following table summarizes average realized power prices for each region in which NRG operates for the six months ended June 30, 2018 and 2017, which reflects the impact of settled hedges.
 Average Realized Power Price ($/MWh)
 Six months ended June 30,
Region2018 2017 Change %
Gulf Coast$34.85
 $34.25
 2%
East/West (a)
40.69
 40.20
 1%
(a) does not include BETM energy revenue of $32 million and $15 million for 2018 and 2017, respectively.
Though the average on peak power prices have increased on average by 19%, average realized prices by region for the Company have generally fluctuated at different rates year-over-year due to the Company's multi-year hedging program.

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


The below tables present the composition and reconciliation of gross margin and economic gross margin for the six months ended June 30, 2018 and 2017:

Six months ended June 30, 2018


 Generation        
(In millions)Retail Gulf Coast 
East/West(a)
 Subtotal Renewables NRG Yield Corporate/Eliminations Total
Energy revenue$—
 $879
 $362
 $1,241
 $156
 $306
 $(411) $1,292
Capacity revenue—
 135
 300
 435
 —
 169
 (3) 601
Retail revenue3,304
 —
 —
 —
 —
 —
 (2) 3,302
Mark-to-market for economic hedging activities(6) (275) (25) (300) (5) —
 220
 (91)
Contract amortization—
 7
 —
 7
 —
 (35) —
 (28)
Other revenue (b)
—
 128
 34
 162
 48
 92
 (35) 267
Operating revenue3,298
 874
 671
 1,545
 199
 532
 (231) 5,343
Cost of fuel(12) (454) (152) (606) (1) (23) (88) (730)
Other cost of sales(c)
(2,415) (164) (90) (254) (4) (14) 509
 (2,178)
Mark-to-market for economic hedging activities446
 (7) (3) (10) —
 —
 (220) 216
Contract and emission credit amortization—
 (12) (1) (13) —
 —
 —
 (13)
Gross margin$1,317
 $237
 $425
 $662
 $194
 $495
 $(30) $2,638
Less: Mark-to-market for economic hedging activities, net440
 (282) (28) (310) (5) —
 —
 125
Less: Contract and emission credit amortization, net—
 (5) (1) (6) —
 (35) —
 (41)
Economic gross margin$877
 $524
 $454
 $978
 $199
 $530
 $(30) $2,554
Business Metrics               
MWh sold (thousands)(d)(e)
  25,220
 8,110
   2,227
 3,924
    
MWh generated (thousands) (f)
  23,146
 5,463
   2,227
 4,729
    
(a) Includes International, BETM and Generation eliminations.
(b) Renewables other revenue includes $26 million of intercompany revenue to NRG Yield.
(c) Includes purchased energy, capacity and emissions credits.
(d) MWh sold excludes generation at facilities in East/West and NRG Yield that generate revenue under capacity agreements.
(e) Does not include thermal MWh of 18 thousand or MWt of 1,079 thousand for thermal sold by NRG Yield.
(f) Does not include thermal MWh of 47 thousand or MWt of 987 thousand for thermal generated by NRG Yield.


 Six months ended June 30, 2017
   Generation        
(In millions)Retail Gulf Coast 
East/West(a)
 Subtotal Renewables NRG Yield Corporate/Eliminations Total
Energy revenue$—
 $868
 $408
 $1,276
 $174
 $294
 $(501) $1,243
Capacity revenue—
 133
 266
 399
 —
 164
 (4) 559
Retail revenue2,939
 —
 —
 —
 —
 —
 7
 2,946
Mark-to-market for economic hedging activities—
 41
 4
 45
 3
 —
 111
 159
Contract amortization(1) 6
 —
 6
 —
 (34) —
 (29)
Other revenue (b)
—
 102
 20
 122
 36
 85
 (38) 205
Operating revenue2,938
 1,150
 698
 1,848
 213
 509
 (425) 5,083
Cost of fuel(7) (498) (170) (668) (2) (18) 31
 (664)
Other cost of sales(c)
(2,204) (157) (124) (281) (5) (12) 483
 (2,019)
Mark-to-market for economic hedging activities20
 (24) (3) (27) —
 —
 (111) (118)
Contract and emission credit amortization—
 (14) (2) (16) —
 —
 —
 (16)
Gross margin$747
 $457
 $399
 $856
 $206
 $479
 $(22) $2,266
Less: Mark-to-market for economic hedging activities, net20
 17
 1
 18
 3
 —
 —
 41
Less: Contract and emission credit amortization, net(1) (8) (2) (10) —
 (34) —
 (45)
Economic gross margin$728
 $448
 $400
 $848
 $203
 $513
 $(22) $2,270
Business Metrics               
MWh sold (thousands)(d)(e)
  25,340
 9,776
   1,974
 3,789
    
MWh generated (thousands) (f)
  23,790
 6,096
   1,974
 4,244
    
(a) Includes International, BETM and Generation eliminations.
(b) Renewables other revenue includes $14 million of intercompany revenue to NRG Yield.
(c) Includes purchased energy, capacity and emissions credits.
(d) MWh sold excludes generation at facilities in East/West and NRG Yield that generate revenue under capacity agreements.
(e) Does not include thermal MWh of 18 thousand or MWt of 987 thousand for thermal sold by NRG Yield.
(f) Does not include thermal MWh of 36 thousand or MWt of 987 thousand for thermal generated by NRG Yield.
The table below represents the weather metrics for the six months ended June 30, 2018 and 2017:
 Six months ended June 30,
Weather MetricsGulf Coast East/West
2018   
CDDs (a)
1,200
 283
HDDs (a)
1,142
 2,152
2017   
CDDs1,125
 301
HDDs673
 2,008
10-year average   
CDDs1,062
 276
HDDs1,103
 2,206
(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.



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 otherwise noted)2018 2017
Retail revenue$3,135
 $2,813
Supply management revenue75
 84
Capacity revenue94
 42
Customer mark-to-market(6) —
Contract amortization—
 (1)
Other—
 —
Operating revenue (a)
3,298
 2,938
Cost of sales (b)
(2,427) (2,211)
Mark-to-market for economic hedging activities446
 20
Gross Margin$1,317
 $747
Less: Mark-to-market for economic hedging activities, net440
 20
Less: Contract amortization, net—
 (1)
Economic Gross Margin$877
 $728
    
Business Metrics   
Mass electricity sales volume — GWh - Gulf Coast17,745
 16,218
Mass electricity sales volume — GWh - All other regions3,310
 2,998
C&I electricity sales volume — GWh - All regions10,430
 10,141
Natural gas sales volumes (MDth)3,419
 1,700
Average Retail Mass customer count (in thousands) 
2,926
 2,843
Ending Retail Mass customer count (in thousands) (c)
3,173
 2,887
(a)Includes intercompany sales of $2 million and $2 million in 2018 and 2017, respectively, representing sales from Retail to the Gulf Coast region.
(b)Includes intercompany purchases of $415 million and $502 million in 2018 and 2017, respectively.
(c)The acquisition of XOOM Energy, LLC increased NRG's retail portfolio by approximately 300,000 customers in the aggregate by June 30, 2018.
Retail gross margin increased $570 million and economic gross margin increased $149 million for the six months ended June 30, 2018, compared to the same period in 2017, due to:
  (In millions)
Higher gross margin due to higher revenue of $101 million or approximately $3.00 per MWh, driven by customer product, term and mix offset by higher supply costs of $40 million or approximately $1.25 per MWh, driven primarily by an increase in power prices $61
Higher gross margin from the Business Solutions unit reflecting the early settlement of capacity obligations for 2018 34
Higher gross margin due to an increase in load of 1,495,000 MWh driven by more favorable weather conditions in 2018 as compared to 2017 46
Higher gross margin due to higher volumes driven by higher average customer counts primarily driven by the XOOM acquisition in June 2018 8
Increase in economic gross margin $149
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges 420
Increase in contract amortization 1
Increase in gross margin $570



Generation gross margin and economic gross margin
Generation gross margin decreased $194 million and economic gross margin increased $130 million, both of which include intercompany sales, during the six months ended June 30, 2018, compared to the same period in 2017.
The tables below describe the decrease in Generation gross margin and the increase in economic gross margin:
Gulf Coast Region
 (In millions)
Higher gross margin due to a 10% increase in average realized prices in South Central and a 2% increase in average realized prices in Texas$65
Higher gross margin from sales of NOx emission credits35
Higher capacity margins due to an 15% increase in load demand in the South Central business29
Lower energy margin due to a 14% increase in supply cost on load contracts(36)
Lower capacity revenue due to the cancellation of the Greens Bayou RMR agreement in 2017(14)
Other(3)
Increase in economic gross margin$76
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges(299)
Increase in contract and emission credit amortization3
Decrease in gross margin$(220)
East/West
 (In millions)
Higher gross margin due to a 88% increase in New England cleared capacity pricing$34
Higher gross margin due to a 23% increase in PJM cleared capacity pricing which relates to the first full period of capacity performance product pricing29
Higher gross margin from commercial optimization activities15
Higher gross margin by BETM due to higher gains in congestion strategies14
Higher gross margin due to a net overall increase in capacity volumes sold in New York11
Lower gross margin due to a 31% decrease in capacity pricing in New York of $30 million and decreases in capacity pricing and volumes due to the Long Beach capacity toll expiration in July 2017 of $9 million(39)
Lower gross margin due to lower load contracted prices coupled with lower contracted volumes(13)
Lower gross margin due to a 10% decrease in generation volumes due to timing of planned and unplanned outages at Midwest Generation and Arthur Kill, offset by favorable fuel costs(10)
Higher gross margin due to insurance proceeds from outages of $14 million in 2018, compared to business interruption proceeds of $8 million in 20176
Other7
Increase in economic gross margin$54
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges(29)
Increase in contract and emission credit amortization1
Increase in gross margin$26

Renewables gross margin and economic gross margin
Renewables gross margin decreased $12 million and economic gross margin decreased $4 million for the six months ended June 30, 2018, compared to the same period in 2017. This was driven by the deconsolidation of Ivanpah in May 2018, offset in part by additional distributed solar projects reaching commercial operations in late 2017 and early 2018.


NRG Yield gross margin and economic gross margin
NRG Yield gross margin increased $16 million and economic gross margin increased $17 million for the six months ended June 30, 2018, compared to the same period in 2017. The increase is due primarily to a 3% increase in volume generated by wind projects, primarily in connection with higher wind resource at the Alta Wind projects, as well as a 5% increase in solar generation, primarily at CVSR in connection with higher insolation and higher plant availability at Walnut Creek and El Segundo.



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 $84 million during the six months ended June 30, 2018, compared to the same period in 2017.
The breakdown of gains and losses included in operating revenues and operating costs and expenses by region was as follows:
 Six months ended June 30, 2018
   Generation      
 Retail Gulf Coast East/West Renewables 
Eliminations(a)
 Total
 (In millions)
Mark-to-market results in operating revenues           
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges$(1) $(86) $(8) $—
 $31
 $(64)
Net unrealized (losses)/gains on open positions related to economic hedges(5) (189) (17) (5) 189
 (27)
Total mark-to-market (losses)/gains in operating revenues$(6) $(275) $(25) $(5) $220
 $(91)
Mark-to-market results in operating costs and expenses           
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges$104
 $(3) $(7) $—
 $(31) $63
Reversal of acquired gain positions related to economic hedges(1) —
 —
 —
 —
 (1)
Net unrealized gains/(losses) on open positions related to economic hedges343
 (4) 4
 —
 (189) 154
Total mark-to-market gains/(losses) in operating costs and expenses$446
 $(7) $(3) $—
 $(220) $216
(a)Represents the elimination of the intercompany activity between Retail and Generation.
 Six months ended June 30, 2017
   Generation      
 Retail Gulf Coast East/West Renewables 
Eliminations(a)
 Total
 (In millions)
Mark-to-market results in operating revenues           
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges$(1) $(8) $(37) $—
 $89
 $43
Net unrealized gains on open positions related to economic hedges1
 49
 41
 3
 22
 116
Total mark-to-market gains in operating revenues$—
 $41

$4

$3

$111

$159
Mark-to-market results in operating costs and expenses           
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges$76
 $(7) $2
 $—
 $(89) $(18)
Reversal of acquired loss positions related to economic hedges1
 —
 —
 —
 —
 1
Net unrealized losses on open positions related to economic hedges(57) (17) (5) —
 (22) (101)
Total mark-to-market gains/(losses) in operating costs and expenses$20
 $(24)
$(3)
$—

$(111)
$(118)
(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, 2018, the $91 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 an 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.
For the six months ended June 30, 2017, the $159 million gain in operating revenues from economic hedge positions was driven primarily by the increase in value of open positions as a result of decreases in PJM power prices, New York capacity prices, and natural gas prices, as well as the reversal of previously recognized unrealized losses on contracts that settled during the period. The $118 million loss in operating costs and expenses from economic hedge positions was driven primarily by the decrease in value of open positions as a result of decreases in coal and natural gas prices, as well as the reversal of previously recognized unrealized gains 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, 2018 and 2017. The realized and unrealized financial and physical trading results are included in operating revenue within the Generation segment. The Company's trading activities are subject to limits within the Company's Risk Management Policy and are primarily transacted through BETM.
 Six months ended June 30,
(In millions)2018 2017
Trading gains/(losses)   
Realized$40
 $28
Unrealized13
 (2)
Total trading gains$53
 $26

Operations and Maintenance Expense
 Retail GenerationRenewables NRG Yield Corporate EliminationsTotal
  Gulf Coast 
East/West(a)
    
 (In millions)
Six months ended June 30, 2018$96
 $307
 $204
 $53
 $94
 $2
 $(26)$730
Six months ended June 30, 2017$114
 $250
 $200
 $63
 $98
 $9
 $(22)$712
(a) Includes International, BETM and generation eliminations of $3 million in 2018 and $2 million in 2017.
Operations and maintenance expense increased by $18 million for the six months ended June 30, 2018, compared to the same period in 2017, due to the following:
 (In millions)
2017 proceeds and 2018 payments in settlement of certain legal matters$33
Increase in operations and maintenance due to the gain on sale of the Jewett Mine dragline in 201718
Increase in major maintenance primarily due to outages at W.A. Parish and Big Cajun II32
Increased deactivation costs primarily at Dunkirk10
Decrease in operations and maintenance expense due to cost efficiencies as a result of the Transformation
Plan(a)
(60)
Decrease in Renewables operations and maintenance expense primarily from the deconsolidation of Ivanpah(10)
Decrease in NRG Yield operations and maintenance expense due to lower costs related to forced outages at Walnut Creek in 2018 compared to 2017, as well as lower losses on disposal of assets at Walnut Creek and El Segundo(5)
 $18
(a) Approximately $36 million of additional cost savings were achieved in the six months ended June 30, 2017, as compared to the six months ended June 30, 2016, as the savings became permanent through the Transformation Plan.


Depreciation and amortization
Depreciation and amortization decreased by $55 million for the six months ended June 30, 2018, compared to the same period in 2017, driven primarily by the impairment of property, plant and equipment in prior years as well as the deconsolidation of Ivanpah in May 2018.
Impairment Losses
For the six months ended June 30, 2018, the Company recorded impairment losses of $74 million related to the impairment of the Keystone Conemaugh generating stations, as well as the impairment of the Dunkirk project as described in Note 7, Impairments.
Selling, General and Administrative
Selling, general and administrative expenses are comprised of the following:
 Retail Generation Renewables NRG Yield Corporate Total
   (In millions)
Six months ended June 30, 2018$241
 $106
 $22
 $13
 $20
 $402
Six months ended June 30, 2017225
 111
 27
 12
 106
 481
Selling, general and administrative expenses decreased by $79 million for the six months ended June 30, 2018, compared to the same period in 2017.
 (In millions)
Decrease in general and administrative expense from cost initiatives for the Transformation Plan(a)
$(104)
Prior year fees associated with advisors engaged to assist the Company in its strategic review in 2017(20)
Prior year fees for advisors and other consultants engaged to assist the Company with GenOn's ability to continue as a going concern(11)
Increase in bad debt expense primarily from increased usage due to weather14
Increase in expense for estimated legal settlements10
Increase in selling and marketing expense associated with costs incurred for margin enhancement initiatives32
 $(79)
(a) Approximately $22 million of additional cost savings were achieved in the six months ended June 30, 2017, as compared to the six months ended June 30, 2016, as the savings became permanent through the Transformation Plan.
Reorganization Costs
Reorganization costs of $43 million, primarily related to employee costs, were incurred as part of the Transformation Plan during the six months ended June 30, 2018.
Other Income - Affiliate
Other income - affiliate represents the services fees charged to GenOn for shared services under the Services Agreement through June 14, 2017, the date of deconsolidation.
Gain on Sale of Assets
Gain on sale of assets for the six months ended June 30, 2018, consists primarily of the gain on the sale of Canal 3, while the gain on sale of assets for the six months ended June 30, 2017, represents a gain on the sale of land.
Equity in (Losses)/Earnings of Unconsolidated Affiliates
Equity in earnings of consolidated affiliates increased by $14 million for the six months ended June 30, 2018, compared to the six months ended June 30, 2017, which was primarily driven by the equity in earnings recorded in 2018 for Ivanpah after deconsolidation, as well as by prior year losses from Petra Nova Parish Holdings, offset by the prior period HLBV income allocated to the Company’s interests in the Utah Portfolio.


Other (Losses)/Income, Net
Other losses for the six months ended June 30, 2018, primarily relate to the loss on deconsolidation of Ivanpah of $22 million. Other income for the six months ended June 30, 2017, primarily relates to primarily relates to dividends received from cost method investments as well as income from pension and postretirement investments.
Interest Expense
NRG's interestInterest expense decreased by $102$18 million for the sixthree months ended June 30, 2018,2019, compared to the same period in 20172018, due to the following:
 (In millions)
Decrease in derivative interest expense from changes in the fair value of interest rate swaps driven by increased interest rates in 2018$(75)
Decrease in interest expense related to repurchases of Senior Notes(20)
Decrease in interest expense related to Ivanpah deconsolidation(6)
Other(1)
 $(102)
 (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 $2.4 billion of debt at lower interest rates in 2019 and 2018(21)
Decrease related to the deconsolidations of Ivanpah and Agua Caliente in 2018(9)
Other5
     Decrease in interest expense$(18)
Income Tax (Benefit)/Expense
For the sixthree months ended June 30, 2018, NRG recorded an income tax expense of $7 million on pre-tax income of $361 million. For the same period in 2017, NRG recorded2019, an income tax benefit of $1 million was recorded on a pre-tax lossincome of $71$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 1.9%(0.5)% and 1.4%15.6% for the sixthree months ended June 30, 2019 and 2018, respectively.
For the three months ended June 30, 20182019 and 2017, respectively.
For the six months ended June 30, 2018, NRG's overall effective tax rate was differentrates 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 generationthree 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 PTCs from various wind facilitiesnet income was partially offset by the inclusionnet 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 consolidated partnershipsnet 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.





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,
Region2019 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,
Region2019 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.

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 revenue3,353

—

—

—

(2)
3,351
Mark-to-market for economic hedging activities2

473

56

529

(270)
261
Other revenue—

45

111

156

(2)
154
Operating revenue3,355

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 revenue3,300

—

—

—

(2)
3,298
Mark-to-market for economic hedging activities(6)
(273)
(27)
(300)
220

(86)
Other revenue—

64

102

166

(12)
154
Operating revenue3,294

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 activities446

(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, net440

(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

The table below represents the weather metrics for the six months ended June 30, 2019 and 2018:
 Six months ended June 30,
Weather MetricsTexas 
East/West/Other (b)
2019   
CDDs (a)
1,008
 490
HDDs (a)
1,111
 1,897
2018   
CDDs1,246
 573
HDDs1,059
 1,844
10-year average   
CDDs1,115
 529
HDDs1,031
 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

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 revenue84
 75
Capacity revenue49
 93
Customer mark-to-market2
 (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 - Texas17,119
 17,736
Mass electricity sales volume — GWh - All other regions4,407
 3,319
C&I electricity sales volume — GWh - All regions9,839
 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)


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 current state tax expense.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 201839
Higher gross margin due to commercial optimization activities10
Higher gross margin due to margin enhancement initiatives from reduced fuel supply costs10
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 hedges753
Increase in contract and emission credit amortization1
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 prices46
Higher gross margin due to a 14% increase in weighted average realized prices, primarily at Midwest Generation19
Higher gross margin from commercial optimization activities4
Decrease in economic gross margin$(167)
Increase to mark-to-market for economic hedges primarily due to net unrealized gains/losses on open positions related to economic hedges90
Increase in contract and emission credit amortization1
Decrease in gross margin$(76)


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 hedges3
 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 hedges343
 (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, 2017, NRG's overall effective tax2019, 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 was different than the statutory rate of 35% primarily due to the tax expense for the changecontraction, and decreases in valuation allowance, current state tax expenseERCOT electricity prices, partially offset by the generationreversal of PTCspreviously recognized unrealized gains on contracts that settled during the period. The $220 million loss in operating costs and ITCsexpenses from various windeconomic 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 solar facilities, respectively.decreases in ERCOT electricity prices, partially offset by the reversal of previously recognized unrealized losses on contracts that settled during the period.
Net loss attributable to noncontrolling interests and redeemable noncontrolling interests
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 2017,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
Unrealized19
 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 $42 million for the six months ended June 30, 2019, compared to the same period in 2018, due to the following:
 (In millions)
Decrease due to the reduction in accrual for the Midwest Generation asbestos liability following final settlement(27)
Decrease due to the timing of outages in 2019(23)
Decrease due to the deconsolidations of Ivanpah and Agua Caliente in 2018(20)
Decrease due to 2018 payments in settlement of certain legal matters(10)
Decrease due to cost efficiencies as a result of the Transformation Plan(5)
Increase in investments in Texas plants in preparation for summer operations21
Increase primarily related to the lease of Cottonwood from February 4, 201917
Increase due to the XOOM acquisition in June 20188
Increase associated with costs incurred for margin enhancement initiatives2
Other(5)
    Decrease in operations and maintenance expense$(42)



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, 2018240

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 attrition22
Increase in selling expense due to the acquisition of XOOM in June 201812
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.

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 $2.4 billion of debt at lower interest rates in 2019 and 2018(30)
Increase in derivative interest expense due to the termination of interest rate swaps in 201953
Other5
    Decrease in interest expense$(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.

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 lossof 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.




Liquidity and Capital Resources
Liquidity Position
As of June 30, 20182019 and December 31, 20172018, NRG's total liquidity, excluding collateral received, wasfunds deposited by counterparties, of approximately $2.5$2.1 billion and $3.22.0 billion, respectively, was comprised of the following:
(In millions)June 30, 2018 December 31, 2017
Cash and cash equivalents:   
NRG excluding NRG Yield$850
 $843
NRG Yield and subsidiaries130
 148
Restricted cash - operating43
 71
Restricted cash - reserves (a)
243
 437
Total1,266
 1,499
Total credit facility availability1,222
 1,711
Total liquidity, excluding collateral received$2,488
 $3,210
(In millions)June 30, 2019
December 31, 2018
Cash and cash equivalents$294

$563
Restricted cash - operating9

6
Restricted cash - reserves(a)
2

11
Total305

580
Total credit facility availability1,799

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.expenditures
For the six months ended June 30, 20182019, total liquidity, excluding collateral funds deposited by counterparties, decreasedincreased by $722$127 million. Changes in cash and cash equivalent balances are further discussed hereinafter under the heading CashFlow Discussion. Cash and cash equivalents at June 30, 2018,2019 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, cash proceeds from future sales of assets, including sales to NRG Yield, Inc. and under the Transformation Plan, and financing arrangements, as described in Note 8, 10, Debt and Capital Leases, to this Form 10-Q and Note 12, Debt and Capital Leases, to the Company's 2017 10-K.10-Q. The Company's financing arrangements consist mainly of the Senior Credit Facility,Notes, the Senior Notes, the NRG Yield 2019 Convertible Notes, the NRG Yield 2020 Convertible Notes, the Yield Operating LLC senior unsecured notes, the NRG Yield, Inc. revolving credit facility,Credit Facility, and project-related financings.
Sale of Ownership in NRG Yield, Inc. and Renewables Platform
On February 6, 2018, NRG and Global Infrastructure Partners, or GIP, entered into a purchase and sale agreement for GIP to purchase NRG's ownership in NRG Yield, Inc. and NRG's renewables platform for cash of $1.375 billion, subject to certain adjustments. The purchase and sale agreement includes the sale of all of NRG's ownership in NRG Yield, Inc., NRG's renewable energy development and operations platforms and NRG's renewable energy non-ROFO backlog and pipeline.
In connection with the transaction, the Company entered into a Consent and Indemnity Agreement with NRG Yield, Inc. and GIP setting forth key terms and conditions of NRG Yield, Inc.'s consent to the transaction. As part of the Consent and Indemnity Agreement, NRG has agreed to indemnify GIP and NRG Yield, Inc. and its project companies for any increase in property taxes at the California-based solar projects resulting from the transaction.
The transaction is subject to certain closing conditions, approvalstable below represents the approximate cash proceeds received from sale transactions and consents. Asrelated financings, net of July 31, 2018, all regulatory approvals have been received, however certain significant consents and waivers remain pending, and the Company expects the transaction to close in the second half of 2018. Upon the closing of the transaction, NRG’s interest in the Ivanpah asset will no longer be part of the NRG Yield ROFO assets.


Sale of South Central Business
On February 6, 2018, NRG and Cleco Energy LLC, or Cleco, entered into a purchase and sale agreement for Cleco to purchase NRG's South Central business for cash of $1.0 billion, subject to certain adjustments. The transaction is expected to close in the second half of 2018 and is subject to certain closing conditions, approvals and consents. The South Central business owns and operates a 3,555 MW portfolio of generation assets in the Gulf Coast region. Upon the closing of the transaction, NRG will enter into a sale leaseback agreement for the Cottonwood plant through May 2025.
Sale of BETM
On August 1, 2018, the Company completed the sale of 100% of its ownership interests in BETM to a third party for $70 million, subject to working capital adjustments. The sale also resulted in the release and return of approximately $119 million of letters of credit, $30 million of parent guarantees, and $4 million of net cash collateral to NRG.
Sales of Assets to NRG Yield, Inc.
On June 19, 2018, the Company completed the sale of the substantially completed assets of the UPMC Thermal Project for cash consideration of $84 million, subject to working capital adjustments.
On March 30, 2018, as part of the Transformation Plan, the Company completed the sale of 100% of its ownership interest in Buckthorn Solar to NRG Yield, Inc. for cash consideration of approximately $42 million.
On February 6, 2018, the Company entered into an agreement with NRG Yield, Inc. to sell 100% of the membership interests in Carlsbad Energy Holdings LLC, which owns the Carlsbad project, a 527-MW natural gas fired project in Carlsbad, CA, pursuant to the ROFO Agreement. The purchase price for the transaction is $365 million in cash consideration, subject to customary working capital and other adjustments. The transaction is expected to closeadjustments, completed by the Company during the fourth quartersix 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 2018.
Sale of Canal 3
On June 29, 2018, the Company completed the sale of Canal 3 to Stonepeak Kestrel for cash proceeds of approximately $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 is non-recourse to NRG and was transferred to Stonepeak Kestrel in connection with the sale of Canal 3.
Other Asset Sales
During the first half of 2018, the Company completed the sale of various other assets for approximately $7 million.
2023 Term Loan Facility
On March 21, 2018, NRG repriced the 2023 Term Loan Facility, reducing the interest rate margin by 50 basis points to LIBOR plus 1.75% and reducing the LIBOR floor to 0.00%. As a result of the repricing, the Company expects approximately $47 million in interest savings over the remaining life of the loan.
NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility
On April 30, 2018, NRG Yield LLC and NRG Yield Operating LLC refinanced the revolving credit facility, which extended the maturity of the facility to April 28, 2023, and decreased the overall cost of borrowing from L+ 2.50% to L+1.75%.
2048 Convertible2029 Senior Notes Issuance
On May 24, 2018, the Company14, 2019, NRG issued $575$733 million inof aggregate principal amount at par of 2.75% convertible5.25% senior unsecured notes due 2048.2029. 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.

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 assets acquired in the GenOn and EME (including Midwest Generation) acquisitions, assets held by NRG Yield, Inc. and NRG's assets that have project-level financing.  NRG usesfinancing and the first lien structureassets 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 gas used as a proxy for power.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, 20182019, 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, 20182019:
Equivalent Net Sales Secured by First Lien Structure (a)
2018 2019 2020 2021 2022 2023
In MW264 908 916 765 828 860
As a percentage of total net coal and nuclear capacity (b)
6% 19% 20% 16% 18% 18%
Equivalent Net Sales Secured by First Lien Structure(a)
2019 2020 2021 2022 2023
In MW514 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.region
(b)Net coal and nuclear capacity represents 80% of the Company’s total coal and nuclear assets eligible under the first lien, which excludes coal assets acquired in the EME (includingwith Midwest Generation) acquisition, assets in NRG Yield, Inc.Generation and NRG's assets that have project level financing.financing
Uses of Liquidity
The Company's requirements for liquidity and capital resources, other than for operating its facilities, can generally be categorized by the following: (i) commercial operations activities; (ii) debt service obligations; (iii) capital expenditures, including repowering, and renewable development, and environmental; (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; and (v) collateral for project development.transactions. As of June 30, 20182019, commercial operationsthe Company had total cash collateral outstanding of $234$163 million and $953$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, 20182019, total collateral held fromfunds deposited by counterparties was $76$31 million in cash and $198$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.



Capital Expenditures
The following tables and descriptions summarize the Company's capital expenditures for maintenance, environmental,growth investments, and growth investmentsenvironmental for the six months ended June 30, 2018,2019, and the estimated capital expenditure and growth investmentsexpenditures forecast for the remainder of 2018.2019. 
 Maintenance Environmental 
Growth Investments (b)
 Total
 (In millions)
Retail$12
 $—
 $22
 $34
Generation       
Gulf Coast70
 —
 —
 70
East/West (a)
15
 —
 208
 223
Renewables2
 —
 286
 288
NRG Yield17
 —
 28
 45
Corporate 
6
 —
 25
 31
Total cash capital expenditures for the six months ended June 30, 2018122
 —
 569
 691
     Funding from third party equity partners, cash grants and debt financing, net of fees—
 —
 (618) (618)
     Other investments (c)
—
 —
 286
 286
Total capital expenditures and investments, net of financings122
 —
 237
 359
        
Estimated capital expenditures for the remainder of 201899
 3
 231
 333
     Funding from third party equity partners, cash grants and debt financing, net of fees—
 —
 (73) (73)
     Other investments (c)
—
 —
 10
 10
NRG estimated capital expenditures for the remainder of 2018, net of financings (d)
$99
 $3
 $168
 $270
 Maintenance Environmental 
Growth Investments(c)
 Total
 (In millions)
Retail$9
 $—
 $19
 $28
Generation       
Texas39
 —
 —
 39
East/West/Other(a)
25
 2
 —
 27
Corporate 
3
 —
 10
 13
Total cash capital expenditures for the six months ended June 30, 201976
 2
 29
 107
     Other investments—
 —
 58
 58
Total capital expenditures and investments, net of financings76
 2
 87
 165
        
Estimated capital expenditures for the remainder of 2019(b)
$79
 $1
 $17
 $97
(a) Includes International, Renewables and BETMCottonwood
(b) Total cash capital expenditures include $25Growth investments includes $17 million of cost-to-achieve spendcosts to achieve associated with the Transformation Plan
(c) OtherIncludes other investments, include restricted cash activityacquisitions and acquisitionscosts to achieve
(d) Maintenance capital expenditures includes approximately $66 million for assets to be sold
Growth Investments capital expendituresCapital Expenditures
For the six months ended June 30, 2018,2019, the Company's growth investmentinvestments capital expenditures included $266$27 million for renewablecost to achieve projects $208 million for repowering projectsassociated with the Transformation Plan and $95$2 million for the Company's other growth projects.
Environmental Capital Expenditures
NRG estimates that environmental capital expenditures from 20182019 through 20222023 required to comply with environmental laws will be approximately $76 million, which includes $14 million for Midwest Generation.$36 million.
Common Stock Dividends
The following table listsDividends of $0.06 per share were paid on the dividends paidCompany's common stock during the six months ended June 30, 2018:
 Second Quarter 2018 First Quarter 2018
Dividends per Common Share$0.03
 $0.03
2019. On July 18, 2018,19, 2019, NRG declared a quarterly dividend on the Company's common stock of $0.03 per share, payable August 15, 2018,2019, to stockholders of record as of August 1, 20182019, 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 2018,2019, the Company's board of directors authorized an additional $1.0 billion share repurchase program. Through August 7, 2019, the Company to repurchase $1completed share repurchases of $1.0 billion of its common stock, with the first $500 million program beginning as soon as permitted. In March 2018, the Company repurchased 3,114,748 shares of NRG common stock for approximately $93 million. During the second quarter of 2018, the Company repurchased 11,748,553 shares of NRG common stock for approximately $407 million, including shares repurchased under the ASR Agreement. In July 2018, the Company received an additional 860,880 shares in connection with the settlement2019 share repurchase program, at an average price of the ASR Agreement, completing the $500 million of share repurchases. The average cost$38.38 per share, forof which $804 million was repurchased during the total $500 million of shares repurchased was $31.80.six months ended June 30, 2019.

Senior Note Repurchases
In connection withDuring the Transformation Plan,three months ended June 30, 2019, the Company has committed to reduce its debt balance by an additional $640redeemed $733 million to achieve a target net debt to adjusted EBITDA credit ratio of 3.0/1. The following open market senior note repurchases were completed to assist in achieving this target.
 Principal Repurchased 
Cash Paid (a)                         
 Average Early Redemption Percentage
In millions, except rates     
5.750% senior notes due 2028$29
 $30
 99.24%
6.250% senior notes due 202214
 15
 103.25%
Total at June 30, 2018$43
 $45
  
6.250% senior notes due 2022$6
 $6
 103.25%
5.750% senior notes due 202820
 21
 99.13%
6.625% senior notes due 202720
 21
 103.06%
Total at August 2, 2018$89
 $93
  
(a) Includes payment for accrued interest.
As discussed in more detail in "Significant Events" in this Management's Discussion and Analysis of Financial Condition and Results of Operations, on August 1, 2018, the Company announced that it gave the required notice under the indenture governing its 6.25% Senior Notes due 20222024 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 redeem for cash $486 million aggregate principal amount of its 2022 Notes on August 31, 2018.interest expense.
XOOMStream Energy Acquisition
On June 1, 2018,May 15, 2019, the Company completed the acquisition of XOOM Energy, LLC,entered into an agreement to acquire Stream Energy's retail electricity and natural gas retailerbusiness operating in 199 states and Washington, D.C. and Canada for approximately $219$300 million in cash inclusiveand estimated transaction costs and working capital adjustments of approximately $54 million in payments for estimated working capital, which is subject to further adjustment.$25 million. The acquisition increased NRG's retail portfolio by approximately 300,000 customers600,000 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 aggregateevent 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 June 30, 2018.
Repowerings
Carlsbad — The Company is currently overseeing constructionreducing leverage. During the second quarter of 2019, in connection with the repayment of the Carlsbad project, which when completed will consist of approximately 527 MWs of net generation capacity. On February 6, 2018,2023 Term Loan Facility repayment, as further discussed in Note 10, Debt and Capital Leases, the Company entered into an agreement with NRG Yield, Inc. to sell the Carlsbad project pursuant to the ROFO Agreement. The transaction is expected to close during the fourth quarter of 2018.reduced total outstanding debt by $594 million.
Puente Power Project — On October 5, 2017, the California Energy Commission, or CEC, the agency responsible for permitting the Puente Power Project, issued a statement on behalf of the committee of two Commissioners overseeing the permitting process stating their intention to issue a proposed decision that would deny a permit for the Puente Power Project. On October 16, 2017, NRG filed a motion to suspend the permitting proceeding for at least six months, which was granted on November 3, 2017. On April 20, 2018, NRG filed a motion requesting an additional extension of the suspension period to coincide with the CPUC’s final decision on SCE’s application seeking approval of resources procured through its Moorpark RFO, or until June 30, 2019, whichever is sooner.




Cash Flow Discussion
The following table reflects the changes in cash flows for the comparative six-monthsix month periods:
 Six months ended June 30,  
 2018 2017 Change
 (In millions)
Net cash provided/(used) by operating activities$524
 $74
 $450
Net cash used by investing activities(1,146) (545) (601)
Net cash used by financing activities423
 18
 405
 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 Activities1,103
 (1,162) 2,265
Net Cash (Used)/Provided by Financing Activities(1,720) 450
 (2,170)
Net Cash Provided Byby Operating Activities
Changes to net cash provided by operating activities were driven by:
 (In millions)
Increase in operating income adjusted for non-cash items$262
Changes in cash collateral in support of risk management activities due to changes in commodity prices171
Other changes in working capital(21)
Change in cash from discontinued operations38
 $450
 (In millions)
Change in cash provided by discontinued operations$(241)
Decrease in working capital(39)
Changes in cash collateral in support of risk management activities due to changes in commodity prices134
Increase in operating income adjusted for other non-cash items22
 $(124)

Net Cash Used ByProvided/(Used) by Investing Activities
Changes to net cash usedprovided/(used) by investing activities were driven by:
 (In millions)
Increase in cash paid for acquisitions in 2018 compared to 2017, primarily from the XOOM acquisition$(268)
Increase in capital expenditures for growth investments for solar and repowering projects(149)
Beginning balance of cash removed due to the deconsolidation of Ivanpah in 2018(160)
Decrease in proceeds from the sale of investments in 2017 compared to 2018(17)
Decrease in insurance proceeds for property damage(18)
Decrease in sales of emissions, net of purchases(17)
Change in cash from discontinued operations53
Other(25)
 $(601)
 (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 operations582
Decrease in cash paid for acquisitions primarily due to XOOM acquisition in 2018190
Decrease in capital expenditures175
Cash removed due to deconsolidation of Ivanpah in 2018160
Increase in proceeds received from sales of nuclear decommissioning trust fund securities, net of purchases25
Increase in contributions to discontinued operations(28)
Other18
 $2,265
Net Cash (Used)/Provided Byby Financing Activities
Changes to net cash (used)/provided by financing activities were driven by:
 (In millions)
Repurchases of common stock in 2018, from open market repurchases and the ASR Agreement$(500)
Increase in payments for short and long-term debt(318)
Increase in proceeds from the issuance of long-term debt, primarily for the Convertible Notes659
Change in cash from discontinued operations including long-term deposits in 2017349
Increase in cash contributions, net of distributions from non-controlling interests in 2018, primarily related to tax equity financings208
Other7
 $405
 (In millions)
Increase in payments of short and long-term debt$(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 debt839
Other7
 $(2,170)



NOLs, Deferred Tax Assets and Uncertain Tax Position Implications, under ASC 740
For the six months ended June 30, 2018,2019, the Company had a total domestic pre-tax book income of $361$276 million and an immaterial foreign pre-tax book income.income of $10 million. As of December 31, 2017,2018, the Company had cumulative domestic Federal NOL carryforwards of $2.8$10.7 billion, which will begin expiring in 20262031, and cumulative state NOL carryforwards of $2.2$5.6 billion for financial statement purposes. In addition, NRG also has cumulative foreign NOL carryforwards of $224$213 million, which do not have an expiration date. Contingent upon GenOn's emergence from bankruptcy,In addition to the Company will recognize an estimated $9.7 billion worthless stock deductionabove NOLs, NRG has a $442 million carryforward for interest deductions, as well as $381 million of tax purposes.
credits to be utilized in future years. In addition to these amounts, the Company has $39$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 2018.2019.
The Company has recorded a non-current tax liability of $39$28 million until final resolution with the related taxing authority. The $39$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, 20182019, NRG has several investments in energy and energy-related entities that are accounted for under the equity method of accounting. Several of these investments areNRG’s investment in Ivanpah is a variable interest entitiesentity for which NRG is not the primary beneficiary. See also Note 911, 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 $1.2$1.0 billion as of June 30, 20182019. This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to NRG. See also Note 16, 15, Investments Accounted for by the Equity Method and Variable Interest Entities,, to the Company's 20172018 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 20172018 Form 10-K. See also Note 8,Leases, Note 10, Debt and Capital Leases, and Note 1517, 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, 20182019.



Fair Value of Derivative Instruments
NRG may enter into power purchase and sales contracts, fuel purchase contracts and other energy-related financial instruments to mitigate variability in earnings due to fluctuations in spot market prices and to hedge fuel requirements at generation facilities or retail load obligations. In addition,Historically, in order to mitigate interest rate risk associated with the issuance of the Company's variable rate and fixed rate debt, NRG entersentered 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 20172018 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, 20182019, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at June 30, 20182019.
Derivative Activity Gains(In millions)
Fair Value of Contracts as of December 31, 2017$46
Derivative Activity Gains/(Losses)(In millions)
Fair Value of Contracts as of December 31, 2018$104
Contracts realized or otherwise settled during the period9
(16)
Contracts acquired during the period11
(2)
Changes in fair value217
38
Fair Value of Contracts as of June 30, 2018$283
Fair Value of Contracts as of June 30, 2019$124
Fair Value of Contracts as of June 30, 2018Fair Value of Contracts as of June 30, 2019
MaturityMaturity
Fair value hierarchy (Losses)/Gains1 Year or Less Greater than 1 Year to 3 Years Greater than 3 Years to 5 Years Greater than 5 Years 
Total Fair
Value
1 Year or Less Greater than 1 Year to 3 Years Greater than 3 Years to 5 Years Greater than 5 Years 
Total Fair
Value
(In millions)(In millions)
Level 1$(9) $(30) $(8) $(1) $(48)$(93) $(18) $(3) $—
 $(114)
Level 210
 137
 16
 15
 178
69
 75
 7
 (10) 141
Level 3141
 32
 (6) (14) 153
96
 32
 (5) (26) 97
Total$142
 $139
 $2
 $—
 $283
$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, 2018,2019, NRG's net derivative asset was $283$124 million, an increase to total fair value of $237$20 million as compared to December 31, 2017.2018. This increase was driven by gains in fair value, acquired contracts, and thepartially offset by roll-off of trades that settled during the period.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 $191$94 million in the net value of derivatives as of June 30, 2018.2019. 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 $183$94 million in the net value of derivatives as of June 30, 2018.2019.





Critical Accounting Policies and Estimates
NRG's discussion and analysis of the financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance as well as the use of estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges, and the fair value of certain assets and liabilities. These judgments, in and of themselves, could materially affect the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment may also have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies has not changed.
On an ongoing basis, NRG evaluates these estimates, utilizing historic experience, consultation with experts and other methods the Company considers reasonable. In any event, actual results may differ substantially from the Company's estimates. Any effects on the Company's business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the information that gives rise to the revision becomes known.
The Company identifies its most critical accounting policies as those that are the most pervasive and important to the portrayal of the Company's financial position and results of operations, and that require the most difficult, subjective and/or complex judgments by management regarding estimates about matters that are inherently uncertain. NRG's critical accounting policies include derivative instruments, income taxes and valuation allowance for deferred tax assets, impairment of long lived assets and investments, goodwill and other intangible assets, and contingencies.
The Company performs its annual test of goodwill impairment during the fourth quarter. The Company tests its long-lived assets for impairment whenever indicators of impairment exist. The Company's annual budget is utilized to determine the cash flows associated withsignificant 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 long-lived assets, which incorporates various assumptions, including2018 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 long-term view of natural gas prices and its impact on merchant power prices and fuel costs. The Company's annual budget process is finalized and approved by the Board of Directors in the fourth quarter. It is reasonably possible that the updated long-term cash flows will not support the carrying value of certain assets, and the Company will be required2018 Form 10-K. There have been no material changes to test such assets for impairment. This could also have a negative impact on the fair value of the reporting units that have goodwill balances. This decrease in power prices could also result in an adverse change in the manner that long-lived assets are used, or result in the Company selling an asset before the end of its previously estimated useful life, at a price that is lower than its carrying amount. Accordingly, if these decreases continue, it is possible that the Company's goodwill or long-lived assets will be impaired.critical accounting policies and estimates since the 2018 Form 10-K.





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 20172018 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, 20182019 and 20172018:
(In millions)2018 20172019 2018
VaR as of June 30,$54
 $49
$33
 $54
Three months ended June 30,      
Average$59
 $59
$40
 $59
Maximum68
 66
46
 68
Minimum52
 49
33
 52
Six months ended June 30,      
Average59
 $56
43
 $59
Maximum69
 66
49
 69
Minimum48
 41
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, 20182019, for the entire term of these instruments entered into for both asset management and trading, was $25$11 million, primarily driven by asset-backed transactions.
Interest Rate Risk
NRG iswas exposed to fluctuations in interest rates through its issuance of variable rate debt. Exposures to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, caps, collars and put or call options. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt obligations when taking into account the combination of the variable rate debt and the interest rate derivative instrument. NRG's risk management policies allow the Company to reduce interest rate exposure from variable rate debt obligations.
The Company's project subsidiaries enterCompany has previously entered into interest rate swaps, intended to hedge the risks associated withswaps. As of June 30, 2019, NRG had no interest rates on non-recourse project level debt.rate derivative instruments. See Note 12, 11, Debt and Capital Leases, of the Company's 20172018 Form 10-K for more information on the Company's interest rate swaps.
If allAs of the above swaps had been discontinued on June 30, 2018, the Company would have owed the counterparties $79 million. Based on the credit ratings of the counterparties, NRG believes its exposure to credit risk due to nonperformance by counterparties to its hedge contracts to be insignificant.
NRG has both long and short-term debt instruments that subject the Company to the risk of loss associated with movements in market interest rates. As of June 30, 2018, a 1% change in variable interest rates would result in a $14.3 million change in interest expense on a rolling twelve-month basis.


As of June 30, 20182019, the fair value and related carrying value of the Company's debt was $16.2$6.4 billion and $16.0$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 $981$569 million.

Liquidity Risk
Liquidity risk arises from the general funding needs of NRG's activities and in the management of the Company's assets and liabilities. The Company is currently exposed to additional collateral posting if natural gas prices decline primarily due to the long natural gas equivalent position at various exchanges used to hedge NRG's retail supply load obligations.
Based on a sensitivity analysis for power and gas positions under marginable contracts, a $0.50 per MMBtu change in natural gas prices across the term of the marginable contracts would cause a change in margin collateral posted of approximately $6193 million as of June 30, 20182019, and a 1 MMBtu/MWh change in heat rates for heat rate positions would result in a change in margin collateral posted of approximately $4471 million as of June 30, 20182019. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of June 30, 20182019.
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 45, Fair Value of Financial Instruments, to this Form 10-Q for discussions regarding counterparty credit risk and retail customer credit risk, and Note 67, 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.



ITEM 4 — CONTROLS AND PROCEDURES
Conclusion Regarding the Effectiveness of Disclosure ControlsandProcedures
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, 20182019 that materially affected, or are reasonably likely to materially affect, NRG's internal control over financial reporting.







PART II — OTHER INFORMATION
ITEM 1 — LEGAL PROCEEDINGS
For a discussion of material legal proceedings in which NRG was involved through June 30, 20182019, see Note 1517, Commitments and Contingencies, to this Form 10-Q.
ITEM 1A — RISK FACTORS
Information regarding risk factors appears in Part I, Item 1A, RiskFactors Related to NRG Energy, Inc., in the Company's 20172018 Form 10-K. There have been no material changes in the Company's risk factors since those reported in its 20172018 Form 10‑K.
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
In February 2018, the Company's board of directors authorized the Company to repurchase $1$1.5 billion of its common stock. $1.25 billion common stock withrepurchases were completed in 2018 and the first $500 millionremaining $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 beginning as soon as permitted. The authorization did not specifyto be executed in 2019. Through August 7, 2019, the Company completed the $1.0 billion share repurchase program at an expiration date.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, 2018.2019.
For the three months ended June 30, 2018 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(b)
Month #1        
(April 1, 2018 to April 30, 2018) 1,779,530
 $29.98
 1,779,530
 $853,952,158
Month #2        
(May 1, 2018 to May 31, 2018) 9,969,023
 $32.69
 9,969,023
 $499,950,111
Month #3        
(June 1, 2018 to June 30, 2018) —
 $—
 —
 $499,950,111
Total at June 30, 2018 11,748,553
   11,748,553
  
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

(a) The average price paid per share excludes commissions of $0.01 per share paid in connection with the April share repurchases.
(b) Includes commissions of $0.01 per share paid in connection with the April share repurchases.


ITEM 3 — DEFAULTS UPON SENIOR SECURITIES
See Note 3, Discontinued Operations and Dispositions, to the Condensed Consolidated Financial Statements of the Company's 2017 Form 10-K, for a description of events of default by GenOn and GenOn Americas Generation under the GenOn Senior Notes and the GenOn Americas Generation Senior Notes.None.
ITEM 4 — MINE SAFETY DISCLOSURES
Not applicable.
ITEM 5 — OTHER INFORMATION
None.



ITEM 6 — EXHIBITS
Number Description Method of Filing
4.1 
Indenture, dated May 24, 2018,23, 2016, between NRG Energy, Inc. and Delaware Trust Company (as successor in interest to Law Debenture Trust Company of New York), as trustee.
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
Fifth Supplemental Indenture, dated May 14, 2019, among NRG energy, Inc., the guarantors named therein and Delaware Trust Company, as trustee.
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
Form of 5.250% Senior Notes due 2029.
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
Indenture, dated May 28, 2019, between NRG Energy, Inc. and Delaware Trust Company, as trustee.
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
Supplemental Indenture, dated May 28, 2019, among NRG Energy, Inc., the guarantors named therein and Delaware Trust Company, as trustee.
 Incorporated herein by reference to Exhibit 4.1 to the Registrant's Current Report on Form 8-K filed on May 25, 2018.
4.2
Form of 2.75% Convertible Senior Notes due 2048.
Incorporated herein by reference to Exhibit 4.2 to the Registrant's Current Reportcurrent report on Form 8-K filed on May 25, 2018.30, 2019
4.6
Form of 3.750% Senior Secured First Lien Notes due 2024.
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

Form of 4.450% Senior Secured First Lien Notes due 2029.
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 
ThirdFourth Amendment, Agreement, dated as of May 7, 2018, by and28, 2019, among NRG Energy, Inc., its subsidiaries parties thereto, the lenders from time to time partiesparty thereto and Citicorp North America, Inc., as administrative agent and as collateral agent.agent
 Incorporated herein by reference to Exhibit 10.1 to the Registrant's Current Reportcurrent report on Form 8-K filed on May 7, 2018.
10.2
NRG Energy, Inc. Amended and Restated Executive Change-in-Control and General Severance Plan for Tier IA and Tier IIA Executives (Amended and Restated Effective April 1, 2018).
Filed herewith.30, 2019
31.1 
Rule 13a-14(a)/15d-14(a) certification of Mauricio Gutierrez.
 Filed herewith.
31.2 
Rule 13a-14(a)/15d-14(a) certification of Kirkland B. Andrews.
 Filed herewith.
31.3 
Rule 13a-14(a)/15d-14(a) certification of David Callen.
 Filed herewith.
32 
Section 1350 Certification.
 Furnished herewith.
101 INS Inline XBRL Instance Document. Filed herewith.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.
104Cover 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.





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 2, 20187, 2019
Chief Accounting Officer
(Principal Accounting Officer)
 
 








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