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

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☒

Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the Quarterly Period Ended:

September 30, 2019

☐

Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Commission File Number: 001-15891

NRG Energy, Inc.

(Exact name of registrant as specified in its charter)

Delaware

41-1724239

(State or other jurisdiction
of incorporation or organization)

(I.R.S. Employer
Identification No.)

804 Carnegie Center,

Princeton

New Jersey

08540

(Address of principal executive offices)

(Zip Code)

(609) 524-4500

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:


Title of Each Class	Trading Symbol(s)	Name of Exchange on Which Registered
Common Stock, par value $0.01	NRG	New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer

☒

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ☐ No ☒

As of October 31, 2019, there were 251,594,290 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			9
ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES			9
ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			62
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			98
ITEM 4 — CONTROLS AND PROCEDURES			100
PART II — OTHER INFORMATION			101
ITEM 1 — LEGAL PROCEEDINGS			101
ITEM 1A — RISK FACTORS			101
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			101
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES			101
ITEM 4 — MINE SAFETY DISCLOSURES			101
ITEM 5 — OTHER INFORMATION			101
ITEM 6 — EXHIBITS			102
SIGNATURES			103

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q of NRG Energy, Inc., or NRG or the Company, includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. The words "believes," "projects," "anticipates," "plans," "expects," "intends," "estimates" and similar expressions are intended to identify forward-looking statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause NRG's actual results, performance and achievements, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. These factors, risks and uncertainties include the factors described under Risk Factors Related to NRG Energy, Inc., in Part I, Item 1A of the Company's Annual Report on Form 10-K for the year ended December 31, 2018 and the following:

•NRG's ability to achieve the expected benefits of its Transformation Plan;

•NRG's ability to obtain and maintain retail market share;

•NRG's ability to engage in successful sales and divestitures as well as mergers and acquisitions activity;

•General economic conditions, changes in the wholesale power markets and fluctuations in the cost of fuel;

•Volatile power supply costs and demand for power;

•Changes in law, including judicial decisions;

•Hazards customary to the power production industry and power generation operations, such as fuel and electricity price volatility, unusual weather conditions, catastrophic weather-related or other damage to facilities, unscheduled generation outages, maintenance or repairs, unanticipated changes to fuel supply costs or availability due to higher demand, shortages, transportation problems or other developments, environmental incidents, or electric transmission or gas pipeline system constraints and the possibility that NRG may not have adequate insurance to cover losses as a result of such hazards;

•The effectiveness of NRG's risk management policies and procedures and the ability of NRG's counterparties to satisfy their financial commitments;

•Counterparties' collateral demands and other factors affecting NRG's liquidity position and financial condition;

•NRG's ability to operate its businesses efficiently and generate earnings and cash flows from its asset-based businesses in relation to its debt and other obligations;

•NRG's ability to enter into contracts to sell power and procure fuel on acceptable terms and prices;

•The liquidity and competitiveness of wholesale markets for energy commodities;

•Government regulation, including changes in market rules, rates, tariffs and environmental laws;

•Price mitigation strategies and other market structures employed by ISOs or RTOs that result in a failure to adequately and fairly compensate NRG's generation units;

•NRG's ability to mitigate forced outage risk for units subject to capacity performance requirements in PJM, performance incentives in ISO-NE, and scarcity pricing in ERCOT;

•NRG's ability to borrow funds and access capital markets, as well as NRG's substantial indebtedness and the possibility that NRG may incur additional indebtedness in the future;

•Operating and financial restrictions placed on NRG and its subsidiaries that are contained in the indentures governing NRG's outstanding notes, in NRG's Senior Credit Facility, and in debt and other agreements of certain of NRG subsidiaries and project affiliates generally;

•Cyber terrorism and inadequate cybersecurity, or the occurrence of a catastrophic loss and the possibility that NRG may not have adequate insurance to cover losses resulting from such hazards or the inability of NRG's insurers to provide coverage;

•NRG's ability to develop and build new power generation facilities;

•NRG's ability to develop and innovate new products, as retail and wholesale markets continue to change and evolve;

•NRG's ability to implement its strategy of finding ways to meet the challenges of climate change, clean air and protecting natural resources, while taking advantage of business opportunities;

•NRG's ability to increase cash from operations through operational and commercial initiatives, corporate efficiencies, asset strategy, and a range of other programs throughout NRG to reduce costs or generate revenues;

•NRG's ability to successfully evaluate investments and achieve intended financial results in new business and growth initiatives;

•NRG's ability to successfully integrate, realize cost savings and manage any acquired businesses; and

•NRG's ability to develop and maintain successful partnering relationships as needed.

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

GLOSSARY OF TERMS

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:


2018 Form 10-K						NRG’s Annual Report on Form 10-K for the year ended December 31, 2018
2023 Term Loan Facility						The Company's $1.7 billion (as of December 31, 2018) term loan facility due 2023, a component of the Senior Credit Facility, which was repaid during the second quarter of 2019
ACE						Affordable Clean Energy
Agua Caliente						Agua Caliente Solar Project, a 290 MW photovoltaic power station located in Yuma County, Arizona in which NRG owns 35% interest
ARO						Asset Retirement Obligation
ASC						The FASB Accounting Standards Codification, which the FASB established as the source of authoritative GAAP
ASU						Accounting Standards Updates - updates to the ASC
Average realized prices						Volume-weighted average power prices, net of average fuel costs and reflecting the impact of settled hedges
Bankruptcy Code						Chapter 11 of Title 11 the U.S. Bankruptcy Code
Bankruptcy Court						United States Bankruptcy Court for the Southern District of Texas, Houston Division
BETM						Boston Energy Trading and Marketing LLC
BRA						Base Residual Auction
BTU						British Thermal Unit
Business Solutions						NRG's business solutions group, which includes demand response, commodity sales, energy efficiency and energy management services
CAA						Clean Air Act
CAISO						California Independent System Operator
Carlsbad						Carlsbad Energy Center, a 528 MW natural gas-fired project located in Carlsbad, CA
CDD						Cooling Degree Day
CDWR						California Department of Water Resources
CFTC						U.S. Commodity Futures Trading Commission
C&I						Commercial industrial and governmental/institutional
CES						Clean Energy Standard
Cleco						Cleco Corporate Holdings LLC
CO₂						Carbon Dioxide
ComEd						Commonwealth Edison
Company						NRG Energy, Inc.
Cottonwood						Cottonwood Generating Station, a 1,153 MW natural gas-fueled plant which NRG is leasing through May 2025
CPP						Clean Power Plan
CWA						Clean Water Act
D.C. Circuit						U.S. Court of Appeals for the District of Columbia Circuit
Distributed Solar						Solar power projects that primarily sell power to customers for usage on site, or are interconnected to sell power into a local distribution grid
DNREC						Delaware Department of Natural Resources and Environmental Control
Economic gross margin						Sum of energy revenue, capacity revenue, retail revenue and other revenue, less cost of fuels and other cost of sales
EGU						Electric Generating Unit
EME						Edison Mission Energy
EPA						U.S. Environmental Protection Agency
ERCOT						Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas
ESPP						NRG Energy, Inc. Amended and Restated Employee Stock Purchase Plan
ESPS						Existing Source Performance Standards
Exchange Act						The Securities Exchange Act of 1934, as amended
FASB						Financial Accounting Standards Board


FERC						Federal Energy Regulatory Commission
FGD						Flue gas desulfurization
FTRs						Financial Transmission Rights
GAAP						Generally accepted accounting principles in the U.S.
GenConn						GenConn Energy LLC
GenOn						GenOn Energy, Inc.
GenOn Entities						GenOn and certain of its wholly owned subsidiaries, including GenOn Americas Generation, that filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court on June 14, 2017
GHG						Greenhouse Gas
GIP						Global Infrastructure Partners

GWh						Gigawatt Hour
HAP						Hazardous Air Pollutant
HDD						Heating Degree Day
Heat Rate						A measure of thermal efficiency computed by dividing the total BTU content of the fuel burned by the resulting kWhs generated. Heat rates can be expressed as either gross or net heat rates, depending upon whether the electricity output measured is gross or net generation. Heat rates are generally expressed as BTU per net kWh
HLW						High-level radioactive waste
ICE						Intercontinental Exchange
ISO						Independent System Operator, also referred to as RTOs
ISO-NE						ISO New England Inc.
Ivanpah						Ivanpah Solar Electric Generation Station, a 393 MW solar thermal power plant located in California's Mojave Desert in which NRG owns 54.5% interest
kWh						Kilowatt-hour
LaGen						Louisiana Generating, LLC
LIBOR						London Inter-Bank Offered Rate
LTIPs						Collectively, the NRG LTIP and the NRG GenOn LTIP
Mass Market						Residential and small commercial customers
MATS						Mercury and Air Toxics Standards promulgated by the EPA
MDth						Thousand Dekatherms
Midwest Generation						Midwest Generation, LLC
MISO						Midcontinent Independent System Operator, Inc.
MMBtu						Million British Thermal Units
MW						Megawatts
MWe						Megawatt equivalent
MWh						Saleable megawatt hour net of internal/parasitic load megawatt-hour
NAAQS						National Ambient Air Quality Standards
NEPOOL						New England Power Pool
NERC						North American Electric Reliability Corporation
NJBPU						New Jersey Board of Public Utilities
Net Exposure						Counterparty credit exposure to NRG, net of collateral
Nodal						Nodal Exchange is a derivatives exchange
NOL						Net Operating Loss
NOx						Nitrogen Oxides
NPDES						National Pollutant Discharge Elimination System
NPNS						Normal Purchase Normal Sale
NRC						U.S. Nuclear Regulatory Commission
NRG						NRG Energy, Inc.


NRG Yield, Inc.						NRG Yield, Inc., which changed it's name to Clearway Energy, Inc. following the sale by NRG of NRG Yield and the Renewables Platform to GIP


Nuclear Decommissioning Trust Fund						NRG's nuclear decommissioning trust fund assets, which are for the Company's portion of the decommissioning of the STP, Units 1 & 2
Nuclear Waste Policy Act						U.S. Nuclear Waste Policy Act of 1982
NY DEC						New York Department of Environmental Conservation
NYISO						New York Independent System Operator
NYMEX						New York Mercantile Exchange
NYSPSC						New York State Public Service Commission
OCI/OCL						Other Comprehensive Income/(Loss)
ORDC						Operating Reserve Demand Curve
PA PUC						Pennsylvania Public Utility Commission
Peaking						Units expected to satisfy demand requirements during the periods of greatest or peak load on a system
Petra Nova						Petra Nova Parish Holdings, LLC which is 50% owned by NRG and which owns and operates a 240 MWe carbon capture system and a 78 MW cogeneration facility, and owns an equity interest in an oilfield
PG&E						PG&E Corporation (NYSE: PCG) and its primary operating subsidiary, Pacific Gas and Electric Company
PJM						PJM Interconnection, LLC
PM2.5						Particulate Matter that has a diameter of less than 2.5 micrometers
PPA						Power Purchase Agreement
PUCT						Public Utility Commission of Texas
RCE						Residential Customer Equivalent is a unit of measure used by the energy industry to denote the typical annual commodity consumption by a single-family residential customer. 1 RCE represents 1,000 therms of natural gas or 10,000 kWh of electricity
RCRA						Resource Conservation and Recovery Act of 1976
Reliant Energy						Reliant Energy Retail Services, LLC
REMA						NRG REMA LLC, which leases a 100% interest in the Shawville generating facility and 16.7% and 16.5% interest in the Keystone and Conemaugh generating facilities, respectively
Renewables						Consists of the following projects in which NRG has an ownership interest: Agua Caliente, Ivanpah, and solar generating stations located at various NFL Stadiums
Renewables Platform						The renewable operating and development platform sold by NRG to GIP with NRG's interest in NRG Yield, Inc.
Retail						Reporting segment that includes NRG's residential and small commercial businesses which go to market as Reliant, NRG and other brands owned by NRG, as well as Business Solutions
RGGI						Regional Greenhouse Gas Initiative
RTO						Regional Transmission Organization
SDG&E						San Diego Gas & Electric
SEC						U.S. Securities and Exchange Commission
Securities Act						The Securities Act of 1933, as amended
Senior Credit Facility						NRG's senior secured credit facility, comprised of the Revolving Credit Facility and the 2023 Term Loan Facility. The 2023 Term Loan Facility was repaid in the second quarter of 2019
Senior Notes						As of September 30, 2019, NRG's $3.8 billion outstanding unsecured senior notes consisting of $1.0 billion of the 7.25% senior notes due 2026, $1.23 billion of the 6.625% senior notes due 2027, $821 million of 5.75% senior notes due 2028 and $733 million of the 5.250% senior notes due 2029

SNF						Spent Nuclear Fuel
SO₂						Sulfur Dioxide


South Central Portfolio						NRG's South Central Portfolio, which owned and operated a portfolio of generation assets consisting of Bayou Cove, Big Cajun-I, Big Cajun-II, Cottonwood and Sterlington, was sold on February 4, 2019. NRG is leasing back the Cottonwood facility through May 2025
STP						South Texas Project — nuclear generating facility located near Bay City, Texas in which NRG owns a 44% interest
STPNOC						South Texas Project Nuclear Operating Company

TSA						Transportation Services Agreement


TWCC						Texas Westmoreland Coal Co.
UPMC Thermal Project						University of Pittsburgh Medical Center thermal generating project that provides power, steam, chilled water and backup power located in Pittsburgh, PA.
U.S.						United States of America
U.S. DOE						U.S. Department of Energy
Utility Scale Solar						Solar power projects, typically 20 MW or greater in size (on an alternating current basis), that are interconnected into the transmission or distribution grid to sell power at a wholesale level
VaR						Value at Risk
VCP						Voluntary Clean-Up Program
VIE						Variable Interest Entity

PART I — FINANCIAL INFORMATION

ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three months ended September 30,						Nine months ended September 30,
(In millions, except for per share amounts)	2019		2018		2019		2018
Operating Revenues
Total operating revenues	$	2,996	$	2,960	$	7,626	$	7,486
Operating Costs and Expenses
Cost of operations	2,153		2,238		5,649		5,512
Depreciation and amortization	91		99		261		331
Impairment losses	—		—		1		74
Selling, general and administrative	210		211		615		587
Reorganization costs	1		27		16		70
Development costs	1		1		5		9
Total operating costs and expenses	2,456		2,576		6,547		6,583

Gain on sale of assets	—		14		2		30
Operating Income	540		398		1,081		933
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates	29		20		8		26
Impairment losses on investments	(107)		(1)		(107)		(16)
Other income, net	17		19		49		12
Loss on debt extinguishment, net	—		(19)		(47)		(22)
Interest expense	(99)		(122)		(318)		(361)
Total other expense	(160)		(103)		(415)		(361)
Income from Continuing Operations Before Income Taxes	380		295		666		572
Income tax expense	6		8		9		19
Income from Continuing Operations	374		287		657		553
(Loss)/income from discontinued operations, net of income tax	(2)		(336)		399		(272)
Net Income/(Loss)	372		(49)		1,056		281
Less: Net income attributable to noncontrolling interest and redeemable interests	—		23		1		1
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	372	$	(72)	$	1,055	$	280
Earnings per Share Attributable to NRG Energy, Inc.
Weighted average number of common shares outstanding — basic	254		299		266		309
Income from continuing operations per weighted average common share — basic	$	1.47	$	0.88	$	2.47	$	1.79
(Loss)/income from discontinued operations per weighted average common share — basic	$	(0.01)	$	(1.12)	$	1.50	$	(0.88)
Earnings/(Loss) per Weighted Average Common Share — Basic	$	1.46	$	(0.24)	$	3.97	$	0.91
Weighted average number of common shares outstanding — diluted	256		299		268		313
Income from continuing operations per weighted average common share — diluted	$	1.46	$	0.88	$	2.45	$	1.76
(Loss)/income from discontinued operations per weighted average common share — diluted	$	(0.01)	$	(1.12)	$	1.49	$	(0.87)
Earnings/(Loss) per Weighted Average Common Share — Diluted	$	1.45	$	(0.24)	$	3.94	$	0.89

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

(Unaudited)


	Three months ended September 30,						Nine months ended September 30,
	2019		2018		2019		2018
	(In millions)
Net Income/(Loss)	$	372	$	(49)	$	1,056	$	281
Other Comprehensive (Loss)/Income
Unrealized gain on derivatives	—		5		—		24
Foreign currency translation adjustments	(4)		(2)		(4)		(8)
Available-for-sale securities	(14)		—		(13)		1
Defined benefit plans	(41)		(1)		(47)		(3)
Other comprehensive (loss)/income	(59)		2		(64)		14
Comprehensive Income/(Loss)	313		(47)		992		295
Less: Comprehensive income attributable to noncontrolling interest and redeemable noncontrolling interest	—		26		1		15
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.	$	313	$	(73)	$	991	$	280

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS


	September 30, 2019		December 31, 2018
(In millions, except share data)	(Unaudited)
ASSETS
Current Assets
Cash and cash equivalents	$	243	$	563
Funds deposited by counterparties	30		33
Restricted cash	4		17
Accounts receivable, net	1,376		1,024
Inventory	364		412
Derivative instruments	735		764
Cash collateral paid in support of energy risk management activities	164		287

Prepayments and other current assets	271		302
Current assets - held-for-sale	—		1
Current assets - discontinued operations	—		197
Total current assets	3,187		3,600
Property, plant and equipment, net	2,615		3,048
Other Assets
Equity investments in affiliates	405		412

Operating lease right-of-use assets, net	482		—
Goodwill	591		573
Intangible assets, net	828		591
Nuclear decommissioning trust fund	756		663
Derivative instruments	358		317
Deferred income taxes	53		46
Other non-current assets	252		289
Non-current assets - held-for-sale	—		77
Non-current assets - discontinued operations	—		1,012
Total other assets	3,725		3,980
Total Assets	$	9,527	$	10,628

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Current portion of long-term debt and finance leases	$	302	$	72
Current portion of operating lease liabilities	73		—
Accounts payable	866		863

Derivative instruments	668		673
Cash collateral received in support of energy risk management activities	30		33
Accrued expenses and other current liabilities	625		680

Current liabilities - held-for-sale	—		5
Current liabilities - discontinued operations	—		72
Total current liabilities	2,564		2,398
Other Liabilities
Long-term debt and finance leases	5,798		6,449
Non-current operating lease liabilities	500		—
Nuclear decommissioning reserve	294		282
Nuclear decommissioning trust liability	453		371

Derivative instruments	364		304
Deferred income taxes	70		65

Other non-current liabilities	1,036		1,274
Non-current liabilities - held-for-sale	—		65
Non-current liabilities - discontinued operations	—		635
Total other liabilities	8,515		9,445
Total Liabilities	11,079		11,843
Redeemable noncontrolling interest in subsidiaries	19		19
Commitments and Contingencies
Stockholders' Equity
Common stock; $0.01 par value; 500,000,000 shares authorized;421,859,844 and 420,288,886 shares issued and 251,985,517 and 283,650,039 shares outstanding at September 30, 2019 and December 31, 2018, respectively	4		4
Additional paid-in-capital	8,494		8,510
Accumulated deficit	(4,991)		(6,022)
Less treasury stock, at cost - 169,874,327 and 136,638,847 shares at September 30, 2019 and December 31, 2018, respectively	(4,920)		(3,632)
Accumulated other comprehensive loss	(158)		(94)

Total Stockholders' Equity	(1,571)		(1,234)
Total Liabilities and Stockholders' Equity	$	9,527	$	10,628

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Nine months ended September 30,
(In millions)	2019		2018
Cash Flows from Operating Activities
Net Income	$	1,056	$	281
Income/(loss) from discontinued operations, net of income tax	399		(272)
Income from continuing operations	657		553
Adjustments to reconcile net income to cash provided by operating activities:
Distributions and equity earnings of unconsolidated affiliates	(5)		10
Depreciation, amortization and accretion	289		364
Provision for bad debts	87		57
Amortization of nuclear fuel	40		38
Amortization of financing costs and debt discount/premiums	20		21
Loss on debt extinguishment, net	47		22
Amortization of emissions allowances and out-of-market contracts	28		21
Amortization of unearned equity compensation	15		21
Gain on sale and disposal of assets	(20)		(50)

Impairment losses	108		90
Changes in derivative instruments	36		(17)
Changes in deferred income taxes and liability for uncertain tax benefits	(3)		(6)
Changes in collateral deposits in support of energy risk management activities	129		(30)
Changes in nuclear decommissioning trust liability	27		50
GenOn settlement	—		(125)
Loss on deconsolidation of Agua Caliente and Ivanpah projects	—		13
Changes in other working capital	(602)		(361)
Cash provided by continuing operations	853		671
Cash provided by discontinued operations	8		396
Net Cash Provided by Operating Activities	861		1,067
Cash Flows from Investing Activities
Payments for acquisitions of businesses	(348)		(209)
Capital expenditures	(183)		(343)
Net proceeds from notes receivable	2		—
Net proceeds from sale of emission allowances	14		24
Investments in nuclear decommissioning trust fund securities	(295)		(449)
Proceeds from the sale of nuclear decommissioning trust fund securities	271		398
Proceeds from sale of assets, net of cash disposed and sale of discontinued operations, net of fees	1,293		1,555
Deconsolidation of Agua Caliente and Ivanpah projects	—		(268)
Net contributions to investments in unconsolidated affiliates	(94)		(39)
Contributions to discontinued operations	(44)		(23)

Cash provided by continuing operations	616		646
Cash used by discontinued operations	(2)		(705)
Net Cash Provided/(Used) by Investing Activities	614		(59)
Cash Flows from Financing Activities
Payments of dividends to common stockholders	(24)		(28)
Payments for treasury stock	(1,286)		(1,000)

Payments for debt extinguishment costs	(24)		—
Distributions to noncontrolling interests from subsidiaries	(1)		(17)
Proceeds from issuance of common stock	3		15
Proceeds from issuance of short and long-term debt	2,048		995
Payment of debt issuance costs	(34)		(19)
Payments for short and long-term debt	(2,487)		(970)
Receivable from affiliate	—		(26)
Other	—		(4)
Cash used by continuing operations	(1,805)		(1,054)
Cash provided by discontinued operations	43		403
Net Cash Used by Financing Activities	(1,762)		(651)
Effect of exchange rate changes on cash and cash equivalents	—		1
Change in Cash from discontinued operations	49		94
Net (Decrease)/increase in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash	(336)		264
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period	613		1,086
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	$	277	$	1,350

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^(a)					(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^(a)					(8)						(8)

Balance at June 30, 2019	$	4	$	8,488	$	(5,355)	$	(4,686)	$	(99)	$	(1,648)
Net income					372						372
Other comprehensive loss									(59)		(59)
Share repurchases							(234)				(234)
Equity-based compensation			5								5
Issuance of common stock			1								1
Common stock dividends^(a)					(8)						(8)
Balance at September 30, 2019	$	4	$	8,494	$	(4,991)	$	(4,920)	$	(158)	$	(1,571)

(a) Dividends per common share were $0.03 for each of the quarters ended September 30, 2019, June 30, 2019 and March 31, 2019

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^(a)					(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^(a)					(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
Net (loss)/income					(72)						24		(48)
Other comprehensive income									2				2
Sale of assets to NRG Yield, Inc.			1								6		7
Share repurchases			(37)				(463)						(500)
Equity-based compensation			4										4
Issuance of common stock			4										4
Common stock dividends^(a)					(9)								(9)
Distributions to noncontrolling interests											(9)		(9)
Contributions from noncontrolling interests											1		1
Sale of NRG Yield and other business											(2,459)		(2,459)

Balance at September 30, 2018	$	4	$	8,453	$	(6,001)	$	(3,334)	$	(58)	$	—	$	(936)

(a) Dividends per common share were $0.03 for each of the quarters ended September 30, 2018, June 30, 2018 and March 31, 2018

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 an energy company built on dynamic retail brands with diverse generation assets. NRG brings the power of energy to consumers by producing, selling and delivering electricity and related products and services in major competitive power markets in the U.S. in a manner that delivers value to all of NRG's stakeholders. NRG is perfecting the integrated model by balancing retail load with generation supply within its deregulated markets, while evolving to a customer-driven business. The Company sells energy, services, and innovative, sustainable products and services directly to retail customers under the names "NRG", "Reliant" and other brand names owned by NRG, supported by approximately 23,000 MW of generation as of September 30, 2019.

The accompanying unaudited interim condensed consolidated financial statements have been prepared in accordance with the SEC's regulations for interim financial information and with the instructions to Form 10-Q. Accordingly, they do not include all of the information and notes required by generally accepted accounting principles for complete financial statements. The following notes should be read in conjunction with the accounting policies and other disclosures as set forth in the notes to the consolidated financial statements in the Company's 2018 Form 10-K. Interim results are not necessarily indicative of results for a full year.

In the opinion of management, the accompanying unaudited interim condensed consolidated financial statements contain all material adjustments consisting of normal and recurring accruals necessary to present fairly the Company's consolidated financial position as of September 30, 2019, and the results of operations, comprehensive income, cash flows and statements of stockholders' equity for the three and nine months ended September 30, 2019 and 2018.

Discontinued Operations

During the fourth quarter of 2018, as described in Note 4, Acquisitions, Discontinued Operations and Dispositions, the Company concluded that the sale of its South Central Portfolio to Cleco, excluding the Cottonwood facility, met held-for-sale criteria and should be presented as discontinued operations, as the sale, which closed on February 4, 2019, represented a strategic shift in the business in which NRG operates. The financial information for all historical periods has been recast to reflect the presentation of these entities as discontinued operations.

On August 31, 2018, as described in Note 4, Acquisitions, Discontinued Operations and Dispositions, NRG deconsolidated NRG Yield, Inc. and its Renewables Platform for financial reporting purposes. The financial information for all historical periods was recast to reflect the presentation of these entities, as well as the Carlsbad project, as discontinued operations in the third quarter of 2018. As a result of the sale of NRG Yield, the Company no longer controls the Agua Caliente project. Due to this change in control, the Company also deconsolidated the Agua Caliente project from its financial results and began accounting for the project as an equity method investment.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.

Reclassifications

Certain prior year amounts have been reclassified for comparative purposes.

Note 2 — Summary of Significant Accounting Policies

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

The following table reflects the net income/(loss) attributable to NRG Energy, Inc. after removing the net income attributable to the noncontrolling interest and redeemable noncontrolling interest:


	Three months ended September 30,						Nine months ended September 30,
	2019		2018		2019		2018
	(In millions)
Income from continuing operations, net of income tax	$	374	$	274	$	656	$	547
(Loss)/income from discontinued operations, net of income tax	(2)		(346)		399		(267)
Net income/(loss) attributable to NRG Energy, Inc.	$	372	$	(72)	$	1,055	$	280

Other Balance Sheet Information

The following table presents the allowance for doubtful accounts included in accounts receivable, net; accumulated depreciation included in property, plant and equipment, net; accumulated amortization included in intangible assets, net and accumulated amortization included in out-of-market contracts, net:


	September 30, 2019		December 31, 2018
	(In millions)
Accounts receivable allowance for doubtful accounts	$	57	$	32
Property, plant and equipment accumulated depreciation	1,759		1,811
Intangible assets accumulated amortization	1,215		1,149
Out-of-market contracts accumulated amortization	—		37

Restricted Cash

The following table provides a reconciliation of cash and cash equivalents, restricted cash and funds deposited by counterparties reported within the consolidated balance sheets that sum to the total of the same such amounts shown in the statements of cash flows:


	September 30, 2019		December 31, 2018
	(In millions)
Cash and cash equivalents	$	243	$	563
Funds deposited by counterparties	30		33
Restricted cash	4		17
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows	$	277	$	613

Funds deposited by counterparties consist of cash held by the Company as a result of collateral posting obligations from its counterparties. Some amounts are segregated into separate accounts that are not contractually restricted but, based on the Company's intention, are not available for the payment of general corporate obligations. Depending on market fluctuations and the settlement of the underlying contracts, the Company will refund this collateral to the hedge counterparties pursuant to the terms and conditions of the underlying trades. Since collateral requirements fluctuate daily and the Company cannot predict if any collateral will be held for more than twelve months, the funds deposited by counterparties are classified as a current asset on the Company's balance sheet, with an offsetting liability for this cash collateral received within current liabilities.

Restricted cash consists primarily of funds held to satisfy the requirements of certain debt agreements and funds held within the Company's projects that are restricted in their use.

Pension Plan Amendments

During the third quarter of 2019, STPNOC announced that the defined benefit pension plan will be frozen for non-union employees on December 31, 2021. This resulted in the curtailment of benefits, thereby requiring a remeasurement, including an update to the discount rate used to determine benefit obligations. As a result, NRG recognized a gain of $8 million related to the curtailment of benefits and an increase of $32 million to the pension liability was recorded to other comprehensive income. The STP defined benefit plan is further described in Note 13, Benefit Plans and Other Postretirement Benefits, to the Company’s 2018 Form 10-K.

Recent Accounting Developments - Guidance Adopted in 2019

ASU 2016-02 - In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), or Topic 842, which was further amended through various updates issued by the FASB thereafter, with the objective to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and to improve financial reporting by expanding the related disclosures. The guidance in Topic 842 provides that a lessee that may have previously accounted for a lease as an operating lease under current GAAP should recognize the assets and liabilities that arise from a lease on the balance sheet. In addition, Topic 842 expands the required quantitative and qualitative disclosures with regards to lease arrangements. The Company adopted the standard and its subsequent corresponding updates effective January 1, 2019 under the modified retrospective approach by applying the provisions of the new leases guidance at the effective date without adjusting the comparative periods presented. The Company assessed its leasing arrangements, evaluated the impact of applying practical expedients and accounting policy elections, and implemented lease accounting software to meet the reporting requirements of the standard. The Company established operating lease liabilities of $404 million and right-of-use assets of $321 million upon adoption, before considering deferred taxes. The adoption of Topic 842 did not have a material impact on the statements of operations or cash flows. See Note 8, Leases, for further discussion.

Recent Accounting Developments - Guidance Not Yet Adopted

ASU 2018-17 - In October 2018, the FASB issued ASU No. 2018-17, Consolidations (Topic 810): Targeted Improvements to Related Party Guidance for Variable Interest Entities, in response to stakeholders’ observations that Topic 810, Consolidations, could be improved thereby improving general purpose financial reporting. Specifically, ASC 2018-17 requires application of the variable interest entity (VIE) guidance to private companies under common control and consideration of indirect interest held through related parties under common control for determining whether fees paid to decision makers and service providers are variable interests. The amendments are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. All entities are required to apply the amendments retrospectively with a cumulative-effect adjustment to retained earnings at the beginning of the earliest period presented. The Company is evaluating the impact of adopting this guidance on the consolidated financial statements and disclosures.

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

Note 3 — Revenue Recognition

Performance Obligations

As of September 30, 2019, estimated future fixed fee performance obligations are $136 million for the remaining three months of fiscal year 2019, and $532 million, $586 million, $297 million and $29 million for the entirety of fiscal years 2020, 2021, 2022 and 2023, respectively. These performance obligations are for cleared auction MWs in the PJM, ISO-NE, NYISO and MISO capacity auctions and are subject to penalties for non performance.

Disaggregated Revenues

The following tables represent the Company’s disaggregation of revenue from contracts with customers for the three and nine months ended September 30, 2019 and 2018 along with the reportable segment for each category:


	Three months ended September 30, 2019
			Generation
(In millions)	Retail		Texas		East/West/Other		Subtotal		Corporate/Eliminations		Total
Energy revenue^(a)(c)	$	—	$	773	$	237	$	1,010	$	(568)	$	442
Capacity revenue^(c)	—		—		151		151		1		152
Retail revenue
Mass customers	2,080		—		—		—		—		2,080
Business Solutions customers	465		—		—		—		—		465
Total retail revenue	2,545		—		—		—		—		2,545
Mark-to-market for economic hedging activities^(a)(b)	(1)		(240)		(16)		(256)		47		(210)

Other revenues^(c)	—		32		37		69		(2)		67
Total operating revenue	2,544		565		409		974		(522)		2,996
Less: Lease revenue	3		—		2		2		—		5
Less: Realized and unrealized ASC 815 revenue^(a)	(1)		944		66		1,010		(522)		487

Total revenue from contracts with customers	$	2,542	$	(379)	$	341	$	(38)	$	—	$	2,504





(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 and included in the amounts above:
	Retail		Texas		East/West/Other		Subtotal		Corporate/Eliminations		Total
Energy revenue	$	—	$	1,175	$	62	$	1,237	$	(569)	$	668
Capacity revenue	—		—		33		33		—		33
Other revenue	—		9		(13)		(4)		—		(4)


	Three months ended September 30, 2018
			Generation
(In millions)	Retail		Texas		East/West/Other		Subtotal		Corporate/Eliminations		Total
Energy revenue^(a)(c)	$	—	$	585	$	339	$	924	$	(479)	$	445
Capacity revenue^(c)	—		1		190		191		1		192
Retail revenue
Mass customers	1,768		—		—		—		(2)		1,766
Business Solutions customers	434		—		—		—		—		434
Total retail revenue	2,202		—		—		—		(2)		2,200
Mark-to-market for economic hedging activities^(a)(b)	1		259		36		295		(241)		55

Other revenues^(c)	—		8		60		68		—		68
Total operating revenue	2,203		853		625		1,478		(721)		2,960
Less: Lease revenue	3		—		3		3		—		6
Less: Realized and unrealized ASC 815 revenue^(a)	1		1,159		79		1,238		(716)		523

Total revenue from contracts with customers	$	2,199	$	(306)	$	543	$	237	$	(5)	$	2,431
(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 and included in the amounts above:
	Retail		Texas		East/West/Other		Subtotal		Corporate/Eliminations		Total
Energy revenue	$	—	$	901	$	(8)	$	893	$	(475)	$	418
Capacity revenue	—		—		45		45		—		45
Other revenue	—		(1)		6		5		—		5


	Nine months ended September 30, 2019
			Generation
(In millions)	Retail		Texas		East/West/Other		Subtotal		Corporate/Eliminations		Total
Energy revenue^(a)(c)	$	—	$	1,628	$	578	$	2,206	$	(1,209)	$	997
Capacity revenue^(c)	—		—		460		460		1		461
Retail revenue
Mass customers	4,802		—		—		—		(2)		4,800
Business Solutions customers	1,096		—		—		—		—		1,096
Total retail revenue	5,898		—		—		—		(2)		5,896
Mark-to-market for economic hedging activities^(a)(b)	1		233		40		273		(223)		51

Other revenues^(c)	—		77		148		225		(4)		221
Total operating revenue	5,899		1,938		1,226		3,164		(1,437)		7,626
Less: Lease revenue	9		—		6		6		—		15
Less: Realized and unrealized ASC 815 revenue^(a)	1		2,674		303		2,977		(1,433)		1,545

Total revenue from contracts with customers	$	5,889	$	(736)	$	917	$	181	$	(4)	$	6,066





(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 and included in the amounts above:
	Retail		Texas		East/West/Other		Subtotal		Corporate/Eliminations		Total
Energy revenue	$	—	$	2,417	$	192	$	2,609	$	(1,211)	$	1,398
Capacity revenue	—		—		80		80		1		81
Other revenue	—		24		(9)		15		—		15


	Nine months ended September 30, 2018
			Generation
(In millions)	Retail		Texas		East/West/Other		Subtotal		Corporate/Eliminations		Total
Energy revenue^(a)(c)	$	—	$	1,251	$	937	$	2,188	$	(890)	$	1,298
Capacity revenue^(c)	—		1		498		499		1		500
Retail revenue
Mass customers	4,321		—		—		—		(4)		4,317
Business Solutions customers	1,181		—		—		—		—		1,181
Total retail revenue	5,502		—		—		—		(4)		5,498
Mark-to-market for economic hedging activities^(a)(b)	(5)		(14)		9		(5)		(21)		(31)

Other revenues^(c)	—		72		162		234		(13)		221
Total operating revenue	5,497		1,310		1,606		2,916		(927)		7,486
Less: Lease revenue	10		—		7		7		—		17
Less: Realized and unrealized ASC 815 revenue^(a)	(5)		1,872		211		2,083		(901)		1,177

Total revenue from contracts with customers	$	5,492	$	(562)	$	1,388	$	826	$	(26)	$	6,292
(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 and included in the amounts above:
	Retail		Texas		East/West/Other		Subtotal		Corporate/Eliminations		Total
Energy revenue	$	—	$	1,883	$	78	$	1,961	$	(880)	$	1,081
Capacity revenue	—		—		110		110		—		110
Other revenue	—		3		14		17		—		17

Contract Balances

The following table reflects the contract assets and liabilities included in the Company’s balance sheet as of September 30, 2019 and December 31, 2018:


(In millions)	September 30, 2019		December 31, 2018
Deferred customer acquisition costs	$	130	$	111

Accounts receivable, net - Contracts with customers	1,311		999

Accounts receivable, net - Derivative instruments	63		20
Accounts receivable, net - Affiliate	4		5
Total accounts receivable, net	$	1,378	$	1,024

Unbilled revenues (included within Accounts receivable, net - Contracts with customers)	$	486	$	392

Deferred revenues^(a)	78		67

(a) Deferred revenues from contracts with customers for the nine months ended September 30, 2019 and the year ended December 31, 2018 were approximately $25 million and $19 million, respectively

The revenue recognized from contracts with customers during the nine months ended September 30, 2019 and 2018 relating to the deferred revenue balance at the beginning of each period was $13 million and $16 million, respectively. The revenue recognized from contracts with customers during the three months ended September 30, 2019 and 2018 relating to the deferred revenue balance at the beginning of each period was $21 million and $19 million, respectively. The change in deferred revenue balances during the three and nine months ended September 30, 2019 and 2018 was primarily due to the timing difference of when consideration was received and when the performance obligation was transferred.

Note 4 — Acquisitions, Discontinued Operations and Dispositions

Acquisitions

Stream Energy Acquisition — On August 1, 2019, the Company completed the acquisition of Stream Energy's retail electricity and natural gas business operating in 9 states and Washington, D.C. for $329 million, including working capital and other adjustments of approximately $29 million. The acquisition increased NRG's retail portfolio by approximately 600,000 RCEs or 450,000 customers. The purchase price was provisionally allocated as follows:


	(In millions)
Net current and non-current working capital	$	28
Other intangible assets	283
Goodwill^(a)	18
Stream Purchase Price	$	329

(a) Goodwill arising from the acquisition is attributed to the value of the platform acquired and the synergies expected from combining the operations of Stream Energy with NRG's existing businesses. Goodwill is assigned to the Retail segment and is not deductible for tax purposes.

XOOM Energy Acquisition — On June 1, 2018, the Company completed the acquisition of XOOM Energy, LLC, an electricity and natural gas retailer operating in 19 states, Washington, D.C. and Canada for $213 million, including working capital and other adjustments of $48 million. The acquisition increased NRG's retail portfolio by approximately 395,000 RCEs or 300,000 customers. The purchase price was allocated as follows:


	(In millions)
Net current and non-current working capital	$	46
Other intangible assets	133
Goodwill	34
XOOM Purchase Price	$	213

Discontinued Operations

Sale of South Central Portfolio

On February 4, 2019, the Company completed the sale of the South Central Portfolio to Cleco for cash consideration of $1 billion excluding working capital and other adjustments. The Company concluded that the divested business met the criteria for discontinued operations as of December 31, 2018, as the disposition represented a strategic shift in the business in which NRG operates and the criteria for held-for-sale were met. As such, all current and prior period results for the operations of the South Central Portfolio, except for the Cottonwood facility as discussed below, were reclassified as discontinued operations. In connection with the transaction, NRG also entered into a transition services agreement to provide certain corporate services to the divested business.

The South Central Portfolio includes the 1,153 MW Cottonwood natural gas generating facility. Upon the closing of the sale of the South Central Portfolio, NRG entered into an agreement with Cleco to leaseback the Cottonwood facility through May 2025. Due to its continuing involvement with the Cottonwood facility, NRG did not use discontinued operations treatment in accounting for historical and ongoing activity with Cottonwood.

Summarized results of the South Central Portfolio discontinued operations were as follows:


	Three months ended						Nine months ended
(In millions)	September 30, 2019		September 30, 2018		September 30, 2019		September 30, 2018
Operating revenues	$	—	$	101	$	31	$	310
Operating costs and expenses	—		(85)		(23)		(262)




Gain from discontinued operations, net of tax	—		16		8		48
(Loss)/gain on disposal of discontinued operations, net of tax	(1)		—		27		—
(Loss)/gain from discontinued operations, including disposal, net of tax	$	(1)	$	16	$	35	$	48

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 nine months ended September 30, 2019, the Company recorded an adjustment to reduce the purchase price by $16 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 nine months ended September 30, 2019, the Company reduced the liability related to the indemnification of NRG Yield for any increase in property taxes for certain solar properties by $22 million due to updated estimates.

Carlsbad

On February 6, 2018, NRG entered into an agreement with NRG Yield and GIP to sell 100% of its membership interests in Carlsbad Energy Holdings LLC, which owns the Carlsbad project, for $385 million of cash consideration, excluding working capital adjustments. The primary condition to close the Carlsbad transaction was the completion of the sale of NRG Yield and the Renewables Platform. At the time of the sale of NRG Yield and the Renewables Platform in August 2018, the Company concluded that the Carlsbad project met the criteria for discontinued operations and accordingly, all current and prior period results for Carlsbad were reclassified as discontinued operations. The transaction closed on February 27, 2019. Carlsbad continues to have a ground lease and easement agreement with NRG with an initial term ending in 2039 and two ten year extensions. As a result of the transaction, additional commitments related to the project totaled approximately $23 million as of December 31, 2018 and September 30, 2019.

Summarized results of NRG Yield, Inc. and the Renewables Platform and Carlsbad discontinued operations were as follows:


	Three months ended						Nine months ended
(In millions)	September 30, 2019		September 30, 2018		September 30, 2019		September 30, 2018
Operating revenues	$	—	$	297	$	19	$	925
Operating costs and expenses	—		(229)		(9)		(682)
Other expenses	—		(42)		(5)		(165)
Gain from operations of discontinued components, before tax	—		26		5		78
Income tax expense	—		9		—		4
Gain from discontinued operations, net of tax	—		17		5		74
(Loss)/gain on disposal of discontinued operations, net of tax	(1)		(139)		330		(139)
(Expense)/income from California property tax indemnification	—		(153)		22		(153)
(Expense)/income from other commitments, indemnification and fees	—		(77)		5		(77)
(Loss)/gain on disposal of discontinued operations, net of tax	(1)		(369)		357		(369)
(Loss)/gain from discontinued operations, including disposal, net of tax	$	(1)	$	(352)	$	362	$	(295)

The following table summarizes the major classes of assets and liabilities classified as discontinued operations of Carlsbad:


(In millions)	December 31, 2018

Restricted cash	$	4
Accounts receivable - trade, net	10
Other current assets	5
Current assets - discontinued operations	19
Property, plant and equipment, net	590
Intangible assets, net	9
Other non-current assets	4
Non-current assets - discontinued operations	603
Current portion of long-term debt and capital leases	20
Accounts payable	27
Other current liabilities	1
Current liabilities - discontinued operations	48
Long-term debt and capital leases	572
Other non-current liabilities	2
Non-current liabilities - discontinued operations	$	574

Sale of Assets to NRG Yield, Inc. Prior to Discontinued Operations

On June 19, 2018, the Company completed the UPMC Thermal Project and received cash consideration from NRG Yield of $84 million, plus an additional $3 million received at final completion in January 2019.

On March 30, 2018, the Company sold to NRG Yield, Inc. 100% of NRG's interests in Buckthorn Renewables, LLC, which owns a 154 MW construction-stage utility-scale solar generation project located in Texas. NRG Yield, Inc. paid cash consideration of $42 million, excluding working capital adjustments, and assumed non-recourse debt of $183 million.

GenOn

On June 14, 2017, the GenOn Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. As a result of the bankruptcy filings, NRG concluded that it no longer controlled GenOn as it was subject to the control of the Bankruptcy Court; and, accordingly, NRG deconsolidated GenOn for financial reporting purposes as of June 14, 2017.

By eliminating a large portion of its operations in the PJM market with the deconsolidation of GenOn, NRG concluded that GenOn met the criteria for discontinued operations, as this represented a strategic shift in the business in which NRG operates. As such, all prior period results for GenOn were reclassified as discontinued operations. GenOn's plan of reorganization was confirmed on December 14, 2018.

Summarized results of GenOn discontinued operations were as follows:


	Nine months ended
(In millions)	September 30, 2019		September 30, 2018
Interest income - affiliate	$	—	$	3
Pension and post-retirement liability assumption	—		(2)

Other	2		(26)
Gain/(loss) from discontinued operations, net of tax	$	2	$	(25)

GenOn Settlement

Effective July 16, 2018, NRG and GenOn consummated the GenOn Settlement whereby the Company paid GenOn approximately $125 million, which included (i) the settlement consideration of $261 million, (ii) the transition services credit of $28 million and (iii) the return of $15 million of collateral posted to NRG; offset by the (i) $151 million in borrowings under the intercompany secured revolving credit facility, (ii) related accrued interest and fees of $12 million, (iii) remaining payments due under the transition services agreement of $10 million, (iv) $4 million reduction of the settlement payment related to NRG assigning to GenOn approximately $8 million of historical claims against REMA and (v) certain other balances due to NRG totaling $2 million.

GenMA Settlement

The Bankruptcy Court approved settlement terms agreed to among the GenOn Entities, NRG, the Consenting Holders, GenOn Mid-Atlantic, and certain of GenOn Mid-Atlantic's stakeholders, or the GenMA Settlement, and directed the settlement parties to cooperate in good faith to negotiate definitive documentation consistent with the GenMA Settlement term sheet in order to pursue consummation of the GenMA Settlement. The definitive documentation effectuating the GenMA Settlement was finalized as of April 27, 2018. Certain terms of the compromise with respect to NRG and GenOn Mid-Atlantic are as follows:

•Settlement of all pending litigation and objections to the Plan (including with respect to releases and feasibility);

•NRG provided $37.5 million in letters of credit as new qualifying credit support to GenOn Mid-Atlantic; and

•NRG paid $6 million as reimbursement of professional fees incurred by certain of GenOn Mid- Atlantic's stakeholders in connection with the GenMA Settlement.

Dispositions

On August 1, 2018, the Company completed the sale of 100% of its ownership interests in BETM to Diamond Energy Trading and Marketing, LLC for $71 million, net of working capital adjustments, which resulted in a gain of $15 million on the sale. The sale also resulted in the release and return of approximately $119 million of letters of credit, $32 million of parent guarantees, and $4 million of net cash collateral to NRG.

On June 29, 2018, the Company completed the sale of Canal 3 to Stonepeak Kestrel for cash proceeds of $16 million and recorded a gain of $17 million. Prior to the sale, Canal 3 entered into a financing arrangement and received cash proceeds of $167 million, of which $151 million was distributed to the Company. The related debt was non-recourse to NRG and was transferred to Stonepeak Kestrel in connection with the sale of Canal 3. The Company entered into a project management agreement in 2018 to manage construction of Canal 3, and substantial completion was reached in June 2019.

The Company completed other asset sales for cash proceeds of $22 million and $21 million during the nine months ended September 30, 2019 and 2018, respectively.

Note 5 — Fair Value of Financial Instruments

For cash and cash equivalents, funds deposited by counterparties, accounts and other receivables, accounts payable, restricted cash, and cash collateral paid and received in support of energy risk management activities, the carrying amounts approximate fair values because of the short-term maturity of those instruments and are classified as Level 1 within the fair value hierarchy.

The estimated carrying amounts and fair values of NRG's recorded financial instruments not carried at fair market value are as follows:


	September 30, 2019						December 31, 2018
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Assets:
Notes receivable	$	11	$	8	$	17	$	14
Liabilities:
Long-term debt, including current portion^(a)	6,168		6,706		6,591		6,697

(a) Excludes deferred financing costs, which are recorded as a reduction to long-term debt in the Company's consolidated balance sheets

The fair value of the Company's publicly-traded long-term debt is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. The fair value of debt securities, non-publicly traded long-term debt and certain notes receivable of the Company are based on expected future cash flows discounted at market interest rates or current interest rates for similar instruments with equivalent credit quality and are classified as Level 3 within the fair value hierarchy. The following table presents the level within the fair value hierarchy for long-term debt, including current portion, as of September 30, 2019 and December 31, 2018:


	September 30, 2019						December 31, 2018
	Level 2		Level 3		Level 2		Level 3
	(In millions)
Long-term debt, including current portion	$	6,375	$	331	$	6,528	$	169

Recurring Fair Value Measurements

Debt securities, equity securities, and trust fund investments, which are comprised of various U.S. debt and equity securities, and derivative assets and liabilities, are carried at fair market value.

The following tables present assets and liabilities measured and recorded at fair value on the Company's condensed consolidated balance sheets on a recurring basis and their level within the fair value hierarchy:


	September 30, 2019

(In millions)	Total		Level 1		Level 2		Level 3
Investments in securities (classified within other current and non-current assets)	$	24	$	—	$	19	$	5

Nuclear trust fund investments:
Cash and cash equivalents	20		20		—		—
U.S. government and federal agency obligations	51		51		—		—
Federal agency mortgage-backed securities	97		—		97		—
Commercial mortgage-backed securities	27		—		27		—
Corporate debt securities	112		—		112		—
Equity securities	372		372		—		—
Foreign government fixed income securities	5		—		5		—
Other trust fund investments:
U.S. government and federal agency obligations	1		1		—		—
Derivative assets:
Commodity contracts	1,093		92		878		123


Measured using net asset value practical expedient:
Equity securities — nuclear trust fund investments	72
Equity securities	7
Total assets	$	1,881	$	536	$	1,138	$	128
Derivative liabilities:
Commodity contracts	$	1,032	$	151	$	771	$	110

Total liabilities	$	1,032	$	151	$	771	$	110


	December 31, 2018

(In millions)	Total		Level 1		Level 2		Level 3
Investments in securities (classified within other current and non-current assets)	$	39	$	2	$	18	$	19
Nuclear trust fund investments:
Cash and cash equivalents	19		19		—		—
U.S. government and federal agency obligations	46		46		—		—
Federal agency mortgage-backed securities	100		—		100		—
Commercial mortgage-backed securities	22		—		22		—
Corporate debt securities	96		—		96		—
Equity securities	312		312		—		—
Foreign government fixed income securities	4		—		4		—
Other trust fund investments:
U.S. government and federal agency obligations	1		1		—		—
Derivative assets:
Commodity contracts	1,042		137		796		109
Interest rate contracts	39		—		39		—

Measured using net asset value practical expedient:
Equity securities — nuclear trust fund investments	64
Equity securities	8
Total assets	$	1,792	$	517	$	1,075	$	128
Derivative liabilities:
Commodity contracts	$	977	$	224	$	664	$	89

Total liabilities	$	977	$	224	$	664	$	89

There were no transfers during the three and nine months ended September 30, 2019 and 2018 between Levels 1 and 2. The following tables reconcile, for the three and nine months ended September 30, 2019 and 2018, the beginning and ending balances for financial instruments that are recognized at fair value in the condensed consolidated financial statements, at least annually, using significant unobservable inputs:


	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Three months ended September 30, 2019										Nine months ended September 30, 2019
(In millions)	Debt Securities		Derivatives^(a)		Total		Debt Securities		Derivatives^(a)			Total
Beginning balance	$	19	$	97	$	116	$	19	$	20		$	39
Contracts added from acquisitions	—		(2)		(2)		—		(3)			(3)
Total (losses)/gains — realized/unrealized:
Included in earnings	—		(18)		(18)		1		(45)			(44)
Included in OCI	(14)		—		(14)		(14)		—			(14)
Cash received	—		—		—		(1)		—			(1)
Purchases	—		38		38		—		26			26
Transfers into Level 3^(b)	—		(126)		(126)		—		4			4
Transfers out of Level 3^(b)	—		24		24		—		11			11
Ending balance as of September 30, 2019	$	5	$	13	$	18	$	5	$	13		$	18
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 September 30, 2019	$	—	$	44	$	44	$	1	$	13		$	14

(a)Consists of derivative assets and liabilities, net

(b)Transfers into/out of Level 3 are related to the availability of external broker quotes and are valued as of the end of the reporting period. All transfers in/out are with Level 2


	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Three months ended September 30, 2018										Nine months ended September 30, 2018
(In millions)	Debt Securities		Derivatives^(a)		Total		Debt Securities		Derivatives^(a)			Total
Beginning balance	$	19	$	174	$	193	$	19	$	(15)		$	4
Contracts added in XOOM acquisition	—		—		—		—		12			12
Total (losses) — realized/unrealized included in earnings	—		—		—		—		(15)			(15)

Purchases	—		12		12		—		9			9
Transfers into Level 3^(b)	—		(201)		(201)		—		(4)			(4)
Transfers out of Level 3^(b)	—		2		2		—		—			—
Ending balance as of September 30, 2018	$	19	$	(13)	$	6	$	19	$	(13)		$	6
(Losses) for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of September 30, 2018	$	—	$	(3)	$	(3)	$	—	$	(18)		$	(18)

(a)Consists of derivative assets and liabilities, net

(b)Transfers into/out of Level 3 are related to the availability of external broker quotes and are valued as of the end of the reporting period. All transfers in/out are with Level 2

Derivative Fair Value Measurements

A portion of NRG's contracts are exchange-traded contracts with readily available quoted market prices. A majority of NRG's contracts are non-exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter and on-line exchanges. The remainder of the assets and liabilities represent contracts for which external sources or observable market quotes are not available. These contracts are valued based on various valuation techniques including, but not limited to, internal models based on a fundamental analysis of the market and extrapolation of the observable market data with similar characteristics. As of September 30, 2019, contracts valued with prices provided by models and other valuation techniques make up 11% of derivative assets and 11% of derivative liabilities.

NRG's significant positions classified as Level 3 include physical and financial power executed in illiquid markets, as well as financial transmission rights, or FTRs. The significant unobservable inputs used in developing fair value include illiquid power location pricing, which is derived as a basis to liquid locations. The basis spread is based on observable market data when available or derived from historic prices and forward market prices from similar observable markets when not available. For FTRs, NRG uses the most recent auction prices to derive the fair value.

The following tables quantify the significant unobservable inputs used in developing the fair value of the Company's Level 3 positions as of September 30, 2019 and December 31, 2018:



	September 30, 2019
	Fair Value										Input/Range
	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low		High		Weighted Average
	(In millions)
Power Contracts	$	89	$	98	Discounted Cash Flow	Forward Market Price (per MWh)	$	6	$	217	$	22

FTRs	34		12		Discounted Cash Flow	Auction Prices (per MWh)	(134)		60		0
	$	123	$	110



	December 31, 2018
	Fair Value										Input/Range
	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low		High		Weighted Average
	(In millions)
Power Contracts	$	89	$	75	Discounted Cash Flow	Forward Market Price (per MWh)	$	1	$	214	$	31

FTRs	20		14		Discounted Cash Flow	Auction Prices (per MWh)	(90)		34		0
	$	109	$	89

The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable inputs as of September 30, 2019 and December 31, 2018:

Significant Unobservable Input

Position

Change In Input

Impact on Fair Value Measurement

Forward Market Price Power

Buy

Increase/(Decrease)

Higher/(Lower)

Forward Market Price Power

Sell

Increase/(Decrease)

Lower/(Higher)

FTR Prices

Buy

Increase/(Decrease)

Higher/(Lower)

FTR Prices

Sell

Increase/(Decrease)

Lower/(Higher)

The fair value of each contract is discounted using a risk-free interest rate. In addition, the Company applies a credit reserve to reflect credit risk, which is calculated based on published default probabilities. As of September 30, 2019, the credit reserve resulted in a $1 million decrease in cost of operations. As of December 31, 2018, the credit reserve did not result in a significant change in fair value in operating revenue and cost of operations.

Concentration of Credit Risk

In addition to the credit risk discussion as disclosed in Note 2, Summary of Significant Accounting Policies, to the Company's 2018 Form 10-K, the following is a discussion of the concentration of credit risk for the Company's contractual obligations. Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. NRG is exposed to counterparty credit risk through various activities including wholesale sales, fuel purchases and retail supply arrangements, as well as retail customer credit risk through its retail load activities.

Counterparty Credit Risk

The Company's counterparty credit risk policies are disclosed in its 2018 Form 10-K. As of September 30, 2019, counterparty credit exposure, excluding credit exposure from RTOs, ISOs, registered commodity exchanges and certain long-term agreements, was $242 million and NRG held collateral (cash and letters of credit) against those positions of $55 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 42% of the Company's exposure before collateral is expected to roll off by the end of 2020. Counterparty credit exposure is valued through observable market quotes and discounted at a risk free interest rate. The following tables highlight net counterparty credit exposure by industry sector and by counterparty credit quality. Net counterparty credit exposure is defined as the aggregate net asset position for NRG with counterparties where netting is permitted under the enabling agreement and includes all cash flow, mark-to-market and NPNS, and non-derivative transactions. The exposure is shown net of collateral held and includes amounts net of receivables or payables.


	Net Exposure^(a)(b)
Category by Industry Sector	(% of Total)

Utilities, energy merchants, marketers and other	84	%
Financial institutions	16

Total as of September 30, 2019	100	%


	Net Exposure ^{(a) (b)}
Category by Counterparty Credit Quality	(% of Total)
Investment grade	54	%
Non-investment grade/non-rated	46
Total as of September 30, 2019	100	%

(a)Counterparty credit exposure excludes uranium and coal transportation contracts because of the unavailability of market prices

(b)The figures in the tables above exclude potential counterparty credit exposure related to RTOs, ISOs, registered commodity exchanges and certain long-term contracts

The Company currently has no exposure to wholesale counterparties in excess of 10% of total net exposure discussed above as of September 30, 2019. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration. Given the credit quality, diversification and term of the exposure in the portfolio, NRG does not anticipate a material impact on its financial position or results of operations from nonperformance by any of NRG's counterparties.

RTOs and ISOs

The Company participates in the organized markets of CAISO, ERCOT, ISO-NE, MISO, NYISO and PJM, known as RTOs or ISOs. Trading in these markets is approved by FERC, or in the case of ERCOT, approved by the PUCT, and includes credit policies that, under certain circumstances, require that losses arising from the default of one member on spot market transactions be shared by the remaining participants. As a result, the counterparty credit risk to these markets is limited to NRG’s share of the overall market and are excluded from the above exposures.

Exchange Traded Transactions

The Company enters into commodity transactions on registered exchanges, notably ICE, NYMEX and Nodal. These clearinghouses act as the counterparty and transactions are subject to extensive collateral and margining requirements. As a result, these commodity transactions have limited counterparty credit risk.

Long-Term Contracts

Counterparty credit exposure described above excludes credit risk exposure under certain long-term contracts, primarily solar PPAs. As external sources or observable market quotes are not available to estimate such exposure, the Company values these contracts based on various techniques including, but not limited to, internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. Based on these valuation techniques, as of September 30, 2019, aggregate credit risk exposure managed by NRG to these counterparties was approximately $518 million for the next five years, including exposure to PG&E as described below.

NRG, through its unconsolidated affiliates Ivanpah and Agua Caliente, has exposure to PG&E of approximately $322 million for the next five years. For further discussion see Note 11, Investments Accounted for Using the Equity Method and Variable Interest Entities, or VIEs.

Retail Customer Credit Risk

The Company is exposed to retail credit risk through the Company's retail electricity providers, which serve C&I customers and the Mass market. Retail credit risk results in losses when a customer fails to pay for services rendered. The losses may result from both non-payment 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 September 30, 2019, the Company's retail customer credit exposure to C&I and Mass customers was diversified across many customers and various industries, as well as government entities.

Note 6 — Nuclear Decommissioning Trust Fund

NRG's Nuclear Decommissioning Trust Fund assets, which are for the decommissioning of its 44% interest in STP, are comprised of securities classified as available-for-sale and recorded at fair value based on actively quoted market prices. NRG accounts for the Nuclear Decommissioning Trust Fund in accordance with ASC 980, Regulated Operations, because the Company's nuclear decommissioning activities are subject to approval by the PUCT with regulated rates that are designed to recover all decommissioning costs and that can be charged to and collected from the ratepayers per PUCT mandate. Since the Company is in compliance with PUCT rules and regulations regarding decommissioning trusts and the cost of decommissioning is the responsibility of the Texas ratepayers, not NRG, all realized and unrealized gains or losses (including other-than-temporary impairments) related to the Nuclear Decommissioning Trust Fund are recorded to the Nuclear Decommissioning Trust liability and are not included in net income or accumulated OCI, consistent with regulatory treatment.

The following table summarizes the aggregate fair values and unrealized gains and losses for the securities held in the trust funds, as well as information about the contractual maturities of those securities.


	As of September 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	$	20	$	—	$	—	—	$	19	$	—	$	—	—
U.S. government and federal agency obligations	51		5		—		13	46		1		—		12
Federal agency mortgage-backed securities	97		3		—		24	100		1		2		23
Commercial mortgage-backed securities	27		1		1		24	22		—		1		22
Corporate debt securities	112		6		—		11	96		1		2		11
Equity securities	444		295		—		—	376		231		1		—
Foreign government fixed income securities	5		—		—		10	4		—		—		9
Total	$	756	$	310	$	1		$	663	$	234	$	6

The following table summarizes proceeds from sales of available-for-sale securities held in the trust funds and the related realized gains and losses from these sales. The cost of securities sold is determined on the specific identification method.


	Nine months ended September 30,
	2019		2018
	(In millions)
Realized gains	$	8	$	8
Realized losses	(7)		(8)
Proceeds from sale of securities	271		398

Note 7 — Accounting for Derivative Instruments and Hedging Activities

Energy-Related Commodities

As of September 30, 2019, NRG had energy-related derivative instruments extending through 2034. The Company marks these derivatives to market through the statement of operations. NRG has executed power purchase agreements extending through 2033 that qualified for the NPNS exception and were therefore exempt from fair value accounting treatment.

Interest Rate Swaps

NRG was exposed to changes in interest rates through the Company's issuance of variable rate debt. In order to manage the Company's interest rate risk, NRG entered into interest rate swap agreements. As of September 30, 2019, NRG had no interest rate derivative instruments as a result of the early termination of such contracts in connection with the repayment of the 2023 Term Loan Facility during the second quarter of 2019. See Note 10, Debt and Finance 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 September 30, 2019 and December 31, 2018. Option contracts are reflected using delta volume. Delta volume equals the notional volume of an option adjusted for the probability that the option will be in-the-money at its expiration date.


		Total Volume
		September 30, 2019		December 31, 2018
Category	Units	(In millions)
Emissions	Short Ton	2		(2)
Renewable Energy Certificates	Certificates	1		1
Coal	Short Ton	4		13
Natural Gas	MMBtu	(273)		(330)
Oil	Barrels	—		1
Power	MWh	37		1
Capacity	MW/Day	(1)		(1)
Interest	Dollars	$	—	$	1,000

The decrease in the natural gas position was primarily the result of additional retail hedge positions and settlement of generation hedges. The increase in the power position was primarily the result of additional retail hedge positions and the settlement of generation hedges. The decrease in the interest position was the result of the early settlement of the interest rate swaps.

Fair Value of Derivative Instruments

The following table summarizes the fair value within the derivative instrument valuation on the balance sheets:


	Fair Value
	Derivative Assets						Derivative Liabilities
	September 30, 2019		December 31, 2018		September 30, 2019		December 31, 2018
	(In millions)




Derivatives Not Designated as Cash Flow or Fair Value Hedges:
Interest rate contracts current	$	—	$	17	$	—	$	—
Interest rate contracts long-term	—		22		—		—
Commodity contracts current	735		747		668		673
Commodity contracts long-term	358		295		364		304
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges	$	1,093	$	1,081	$	1,032	$	977

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 September 30, 2019 Balance Sheet
	Gross Amounts of Recognized Assets / Liabilities		Derivative Instruments		Cash Collateral (Held) / Posted		Net Amount
	(In millions)
Commodity contracts:
Derivative assets	$	1,093	$	(869)	$	(5)	$	219
Derivative liabilities	(1,032)		869		70		(93)
Total commodity contracts	$	61	$	—	$	65	$	126


	Gross Amounts Not Offset in the December 31, 2018 Balance Sheet
	Gross Amounts of Recognized Assets / Liabilities		Derivative Instruments		Cash Collateral (Held) / Posted		Net Amount
	(In millions)
Commodity contracts:
Derivative assets	$	1,042	$	(778)	$	(31)	$	233
Derivative liabilities	(977)		778		114		(85)
Total commodity contracts	65		—		83		148
Interest rate contracts:
Derivative assets	39		—		—		39

Total interest rate contracts	39		—		—		39


Total derivative instruments	$	104	$	—	$	83	$	187

Accumulated Other Comprehensive Loss

The following table summarizes the effects on the Company's accumulated OCL balance attributable to cash flow hedge derivatives, net of tax:


	Interest Rate Contracts
	Three months ended		Nine months ended
	September 30, 2018		September 30, 2018

	(In millions)
Accumulated OCL beginning balance	$	(23)	$	(54)
Reclassified from accumulated OCL to income:
Due to realization of previously deferred amounts	1		8
Mark-to-market of cash flow hedge accounting contracts	(3)		21
Sale of NRG Yield and Renewables Platform	25		25
Accumulated OCL ending balance, net of $0 tax	$	—	$	—

Amounts reclassified from accumulated OCL into income are recorded in discontinued operations.

Impact of Derivative Instruments on the Statements of Operations

Unrealized gains and losses associated with changes in the fair value of derivative instruments not accounted for as cash flow hedges are reflected in current period results of operations.

The following table summarizes the pre-tax effects of economic hedges that have not been designated as cash flow hedges and trading activity on the Company's statement of operations. The effect of commodity hedges is included within operating revenues and cost of operations and the effect of interest rate hedges is included in interest expense.


	Three months ended September 30,						Nine months ended September 30,
	2019		2018		2019		2018
Unrealized mark-to-market results	(In millions)
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges	$	(118)	$	(84)	$	(88)	$	(85)
Reversal of acquired (gain) positions related to economic hedges	(3)		(10)		(4)		(11)
Net unrealized gains on open positions related to economic hedges	57		26		69		158
Total unrealized mark-to-market (losses)/gains for economic hedging activities	(64)		(68)		(23)		62
Reversal of previously recognized unrealized (gains) on settled positions related to trading activity	(1)		(4)		(8)		(10)
Net unrealized (losses)/gains on open positions related to trading activity	(3)		8		23		27
Total unrealized mark-to-market (losses)/gains for trading activity	(4)		4		15		17
Total unrealized (losses)/gains	$	(68)	$	(64)	$	(8)	$	79


	Three months ended September 30,						Nine months ended September 30,
	2019		2018		2019		2018
	(In millions)
Unrealized (losses)/ gains included in operating revenues	$	(214)	$	59	$	66	$	(14)
Unrealized gains/(losses) included in cost of operations	146		(123)		(74)		93
Total impact to statement of operations — energy commodities	$	(68)	$	(64)	$	(8)	$	79
Total impact to statement of operations — interest rate contracts	$	—	$	2	$	(38)	$	17

The reversals of acquired gain or loss positions were valued based upon the forward prices on the acquisition date. The roll-off amounts were offset by realized gains or losses at the settled prices and are reflected in operating revenue or cost of operations during the same period.

For the nine months ended September 30, 2019, the $69 million unrealized gain from open economic hedge positions was primarily the result of an increase in value of forward purchases of ERCOT heat rate due to ERCOT heat rate expansion.

For the nine months ended September 30, 2018, the $158 million unrealized gain from open economic hedge positions was primarily the result of an increase in value of forward purchases of ERCOT heat rate and ERCOT electricity contracts due to ERCOT heat rate expansion and increases in ERCOT power prices.

Credit Risk Related Contingent Features

Certain of the Company's hedging agreements contain provisions that require the Company to post additional collateral if the counterparty determines that there has been deterioration in credit quality, generally termed “adequate assurance” under the agreements, or require the Company to post additional collateral if there were a one notch downgrade in the Company's credit rating. The collateral required for contracts with adequate assurance clauses that are in a net liability position as of September 30, 2019 was $39 million. The collateral required for contracts with credit rating contingent features that are in a net liability position as of September 30, 2019 was $18 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 $2 million as of September 30, 2019.

See Note 5, Fair Value of Financial Instruments, 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 September 30, 2019		Nine months ended September 30, 2019




Operating lease cost	$	26	$	82
Short-term lease cost	1		2
Variable lease cost	1		4
Sublease income	(4)		(13)
Total lease cost	$	24	$	75

Other information:


(In millions)	Nine months ended September 30, 2019

Cash paid for amounts included in the measurement of lease liabilities:


Operating cash flows from operating leases	$	77


Right-of-use assets obtained in exchange for new operating lease liabilities	215

Lease Term and Discount Rate for operating leases:


	September 30, 2019

Weighted average remaining lease term (in years)	7.9



Weighted average discount rate	5.74	%

As of September 30, 2019, annual payments based on the maturities of NRG's leases are expected to be as follows:


	(In millions)
Remainder of 2019	$	26
2020	94
2021	86
2022	86
2023	86
Thereafter	372
Total undiscounted lease payments	$	750
Less: present value adjustment	(177)
Total discounted lease payments	$	573

Note 9 —Impairments

2019 Impairment Losses

Petra Nova — During the third quarter of 2019, NRG contributed $95 million in cash to Petra Nova and posted a $12 million letter of credit to cover certain project debt reserve requirements. The cash portion of the contribution was used by Petra Nova to prepay a significant portion of the project debt. As a result, the previously disclosed guarantee of up to $124 million related to the project level debt provided by NRG was canceled and the remaining project debt has now become non-recourse to NRG. In relation to this contribution, the Company evaluated the project for impairment and determined that the carrying amount of the Company’s equity method investment exceeded the fair value of the investment and that the decline is considered to be other-than-temporary. In determining the fair value, the Company utilized an income approach and considered project specific assumptions for the estimated future project cash flows. The Company measured the impairment loss as the difference between the carrying amount and the fair value of the investment and recorded an impairment loss of $101 million.

Other Impairments — During the nine months ended September 30, 2019, the Company recorded $7 million of impairment losses on cost investments and intangible assets.

2018 Impairment Losses

Keystone and Conemaugh — On June 29, 2018, the Company entered into an agreement to sell its approximately 3.7% interests in the Keystone and Conemaugh generating stations. NRG recorded impairment losses of $14 million for Keystone and $14 million for Conemaugh to adjust the carrying amount of the assets to fair value based on the contractual sale price. The transaction closed on September 5, 2018.

Dunkirk — During the second quarter of 2018, NRG ceased its development of the project to add gas capability at the Dunkirk generating station. The project was put on hold in 2015 pending the resolution of a lawsuit filed by Entergy Corporation against the NYSPSC, which challenged the legality of its contract with Dunkirk. The lawsuit was later dropped and development continued, but the delay imposed a new requirement on Dunkirk to enter into the NYISO interconnection study process. The NYISO studies concluded that extensive electric system upgrades would be necessary for the station to return to service. This would cause the Company to incur a material increase in cost and delay the project schedule, which would render the project impractical. Consequently, the Company recorded an impairment loss of $46 million during the second quarter of 2018, reducing the carrying amount of the related assets to $0.

Other Impairments — During the nine months ended September 30, 2018, the Company recorded impairment losses on equity method investments of $16 million.

Note 10 — Debt and Finance Leases

Long-term debt and finance leases consisted of the following:


(In millions, except rates)	September 30, 2019		December 31, 2018		September 30, 2019 Interest rate %

Recourse debt:
Senior Notes, due 2024	$	—	$	733	6.250
Senior Notes, due 2026	1,000		1,000		7.250
Senior Notes, due 2027	1,230		1,230		6.625
Senior Notes, due 2028	821		821		5.750
Senior Notes, due 2029	733		—		5.250
Convertible Senior Notes, due 2048	575		575		2.750
Senior Secured First Lien Notes, due 2024	600		—		3.750
Senior Secured First Lien Notes, due 2029	500		—		4.450
Term Loan Facility ^(a)	—		1,698		L+ 0.0175
Revolver Facility ^(b)	215		—		L+ 0.0175 - P+ 0.0075
Tax-exempt bonds	466		466		0.04125 - 0.06
Subtotal recourse debt	6,140		6,523
Non-recourse debt:
Agua Caliente Borrower 1, due 2038	83		86		5.430
Midwest Generation	—		48		4.390
Other	34		34		various
Subtotal all non-recourse debt	117		168
Subtotal long-term debt (including current maturities)	6,257		6,691
Finance leases	—		1		6.500


Subtotal long-term debt and finance leases (including current maturities)	6,257		6,692
Less current maturities	(302)		(72)
Less debt issuance costs	(68)		(70)
Discounts	(89)		(101)
Total long-term debt and finance leases	$	5,798	$	6,449

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

(b) As of September 30, 2019, L is equal to 1-week LIBOR and P is equal to Prime Rate

Recourse Debt

Senior Notes

Issuance of 2029 Senior Notes

On May 14, 2019, NRG issued $733 million of aggregate principal amount at par of 5.25% senior unsecured notes due 2029, or the 2029 Senior Notes. The 2029 Senior Notes are senior unsecured obligations of NRG and are guaranteed by certain of its subsidiaries. Interest will be paid semi-annually beginning on December 15, 2019, until the maturity date of June 15, 2029. The proceeds from the issuance of the 2029 Senior Notes were utilized to redeem the Company's remaining 6.25% Senior Notes due 2024.

Issuance of 2024 and 2029 Senior Secured First Lien Notes

On May 28, 2019, NRG issued $1.1 billion of aggregate principal amount of senior secured first lien notes, consisting of $600 million 3.75% senior secured first lien notes due 2024 and $500 million 4.45% senior secured first lien notes due 2029, or the Senior Secured First Lien Notes, at a discount. The Senior Secured First Lien Notes are guaranteed on a first-priority basis by each of NRG’s current and future subsidiaries that guarantee indebtedness under its credit agreement. The Senior Secured First Lien Notes will be secured by a first priority security interest in the same collateral that is pledged for the benefit of the lenders under NRG’s credit agreement, which consists of a substantial portion of the property and assets owned by NRG and the guarantors. The collateral securing the Senior Secured First Lien Notes will be released if the Company obtains an investment grade rating from two out of the three rating agencies, subject to an obligation to reinstate the collateral if such rating agencies withdraw the Company's investment grade rating or downgrade its rating below investment grade. Interest will be paid semi-annually beginning on December 15, 2019, until the maturity dates of June 15, 2024 and June 15, 2029. The proceeds from the issuance of the Senior Secured First Lien Notes, together with cash on hand, were used to repay the Company's 2023 Term Loan Facility.

2024 Senior Notes Redemption

During the second quarter of 2019, the Company redeemed $733 million of its 6.25% Senior Notes due 2024 and recorded a loss on debt extinguishment of $29 million, which included the write-off of previously deferred debt issuance costs of $5 million.

Senior Credit Facility

2023 Term Loan Facility Repayment

On May 28, 2019, the Company repaid its $1.7 billion 2023 Term Loan Facility using the proceeds from the issuance of the Senior Secured First Lien Notes, as well as cash on hand, resulting in a decrease of $594 million to long-term debt outstanding. The Company recorded a loss on debt extinguishment of $17 million, which included the write-off of previously deferred debt issuance costs of $13 million. As a result of the repayment of the outstanding 2023 Term Loan Facility, the Company terminated the related interest rate swap agreements, which were in-the-money, and received $25 million that was recorded as a reduction to interest expense.

Revolving Credit Facility Modification

On May 28, 2019, the Company amended its existing credit agreement to, among other things, (i) provide for a $184 million increase in revolving commitments, resulting in aggregate revolving commitments under the amended credit agreement equal to $2.6 billion, (ii) extend the maturity date of the revolving loans and commitments under the amended credit agreement to May 28, 2024, (iii) provide for a release of the collateral securing the amended credit agreement if NRG obtains an investment grade rating from two out of the three rating agencies, subject to an obligation to reinstate the collateral if such rating agencies withdraw NRG’s investment grade rating or downgrade NRG’s rating below investment grade, (iv) reduce the applicable margins for borrowings under (a) ABR Revolving Loans from 1.25% to 0.75% and (b) Eurodollar Revolving Loans from 2.25% to 1.75%, (v) add a sustainability-linked pricing metric that permits an interest rate adjustment tied to NRG meeting targets related to environmental sustainability and (vi) make certain other changes to the existing covenants. As of September 30, 2019, $215 million of borrowings were outstanding, which was fully repaid as of November 7, 2019.

Non-Recourse Debt

Agua Caliente Borrower 1

On January 22, 2019, the lenders of the Agua Caliente Borrower 1 debt notified Agua Caliente Borrower 1, a subsidiary of the Company, of certain defaults under the financing agreement as it relates to the bankruptcy filing made by PG&E on January 29, 2019. PG&E is the offtaker of the underlying contracts, which are material to the project. The financing was entered into along with Agua Caliente Borrower 2, LLC, a subsidiary of Clearway Energy Inc., which is joint and several to the parties. On October 21, 2019, the Company repaid the outstanding amount on the notes at 102% plus accrued interest through the payment date.

Cottonwood - Letters of Credit

On January 4, 2019, the Company entered into an $80 million credit agreement to issue letters of credit, which is currently supporting the Cottonwood facility lease. Annual fees of 1.33% on the facility are paid quarterly in advance. As of September 30, 2019, the full $80 million was issued.

Note 11 — Investments Accounted for Using the Equity Method and Variable Interest Entities, or VIEs

Entities that are not Consolidated

NRG accounts for the Company's significant investments using the equity method of accounting. NRG's carrying value of equity investments can be impacted by a number of elements including impairments, unrealized gains and losses on derivatives and movements in foreign currency exchange rates.

PG&E Bankruptcy — The Agua Caliente project and two of the three Ivanpah units are party to PPAs with PG&E. Both projects have project financing with the U.S. DOE. On January 29, 2019, PG&E Corp. and subsidiary utility PG&E filed for Chapter 11 bankruptcy protection. As part of their filing, PG&E asked the Bankruptcy Court to confirm exclusive jurisdiction over their "rights to reject" PPAs or other contracts regulated by FERC. As a result of the bankruptcy filing, the Agua Caliente and Ivanpah projects have issued notices of events of default under their respective loan agreements. The Ivanpah project signed a forbearance agreement with the Department of Energy on October 25, 2019. The Company's subsidiaries are working with their partners on the projects and the loan counterparties.

On September 9, 2019, PG&E filed a plan of reorganization that would assume all power purchase agreements, including those held by the Agua Caliente project and the two Ivanpah units. On October 17, 2019, a group of unsecured creditors filed a competing plan of reorganization that would also assume all power purchase agreements, including those held by the Agua Caliente project and the two Ivanpah units. NRG's maximum exposure to loss is limited to its equity investment, which was $213 million for Agua Caliente and $28 million for Ivanpah as of September 30, 2019. See Note 10, Debt and Finance Leases, for further discussion on Agua Caliente.

Variable Interest Entities that are not consolidated

NRG accounts for its interests in certain entities that are considered VIEs under ASC 810, Consolidation, for which NRG is not the primary beneficiary, under the equity method.

Through its consolidated subsidiary, NRG Solar Ivanpah LLC, NRG owns a 54.5% interest in Ivanpah Master Holdings LLC, or Ivanpah, the owner of three solar electric generating projects located in the Mojave Desert with a total capacity of 393 MW. NRG considers this investment a VIE under ASC 810 and NRG is not considered the primary beneficiary. The Company accounts for its interest under the equity method of accounting.

The Ivanpah solar electric generating projects were funded in large part by loans guaranteed by the U.S. DOE and equity from the projects' partners. During the first quarter of 2018, all interested parties sought a restructuring of Ivanpah's debt in order to avoid a potential event of default with respect to the loans and entered into a settlement during the second quarter of 2018. The settlement resulted in certain transactions, including the release of reserves totaling $95 million to fund equity distributions to the partners, which reduced the equity at risk, and the prepayment of certain of the debt balance outstanding, and the amendment of certain of Ivanpah's governing documents. The equity distributions and prepayment of debt were funded by the agreed upon release of reserve funds. These events were considered to be a reconsideration event in accordance with ASC 810. As a result, NRG determined that it is not the primary beneficiary and deconsolidated Ivanpah. NRG recognized a loss of $22 million on the deconsolidation and subsequent recognition of Ivanpah as an equity method investment during the nine months ended September 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.

Variable Interest Entities that are Consolidated

The Company has a controlling financial interest in certain entities that have been identified as VIEs under ASC 810. These arrangements are primarily related to tax equity arrangements entered into with third-parties in order to finance the cost of solar energy systems under operating leases eligible for certain tax credits as further described in Note 2, Summary of Significant Accounting Policies, to the Company's 2018 Form 10-K.

The summarized financial information for the Company's consolidated VIEs consisted of the following:


(In millions)	September 30, 2019		December 31, 2018
Current assets	$	3	$	3
Net property, plant and equipment	73		76
Other long-term assets	28		28
Total assets	104		107
Current liabilities	1		2
Long-term debt	28		29


Other long-term liabilities	8		7
Total liabilities	37		38
Redeemable noncontrolling interest	19		19

Net assets less noncontrolling interest	$	48	$	50

Note 12 — Changes in Capital Structure

As of September 30, 2019 and December 31, 2018, the Company had 500,000,000 shares of common stock authorized. The following table reflects the changes in NRG's common stock issued and outstanding:


	Issued	Treasury	Outstanding
Balance as of December 31, 2018	420,288,886	(136,638,847)	283,650,039
Shares issued under LTIPs	1,570,958	—	1,570,958

Shares repurchased	—	(33,235,480)	(33,235,480)
Balance as of September 30, 2019	421,859,844	(169,874,327)	251,985,517
Shares issued under LTIPs subsequent to September 30, 2019	3,757	—	3,757
Shares issued under ESPP	—	46,128	46,128
Shares repurchased subsequent to September 30, 2019	—	(441,112)	(441,112)
Balance as of October 31, 2019	421,863,601	(170,269,311)	251,594,290

Share Repurchases

The following repurchases have been made during the nine months ended September 30, 2019 and through October 31, 2019 under the share repurchase programs:


	Total number of shares purchased	Average price paid per share		Amounts paid for shares purchased (in millions)
Board Authorized Share Repurchases
2018 program:
Repurchases made during January-February to complete the 2018 program	6,153,415	$	40.61	$	250
2019 programs:



Repurchases under February 28, 2019 Accelerated Share Repurchase Agreement- $1.0 billion share repurchase program^(a)	9,438,671			400
Other repurchases under the $1.0 billion share repurchase program ^(a)	16,615,479			600
Total $1.0 billion share repurchase program	26,054,150	38.38		1,000
Repurchases made through September 30, 2019 under the $250 million share repurchase program ^(b)	1,027,915	36.99		38

Total Share Repurchases during the nine months ended September 30, 2019	33,235,480			$	1,288
Repurchases made subsequent to September 30, 2019 under the $250 million program^(b)	441,112	39.10		$	17
Total Share Repurchases during the period ended October 31, 2019	33,676,592			$	1,305

(a) The $1 billion share repurchase program was announced in February 2019

(b) The $250 million share repurchase program was announced in August 2019

On February 28, 2019, the Company executed an accelerated share repurchase agreement, or ASR Agreement, with a financial institution to repurchase a total of $400 million of outstanding common stock based on a volume weighted average price. The Company received initial shares of 9,086,903, which were recorded in treasury stock at fair value based on the closing price on March 12, 2019, of $390 million, with the remaining $10 million recorded in additional paid in capital, representing the value of the forward contract to purchase additional shares. In April 2019, the financial institution delivered the remaining shares pursuant to the ASR agreement and the Company received 351,768 additional shares. The average price paid for all the shares delivered under the ASR Agreement was $42.38 per share. Upon receipt of the additional shares in April 2019, the Company transferred the $10 million from additional paid in capital to treasury stock.

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. In October 2019, 46,128 shares of common stock were issued to employee accounts from treasury stock for the offering period of April 1, 2019 to September 30, 2019.

NRG Common Stock Dividends

A quarterly dividend of $0.03 per share was paid on the Company's common stock during the three months ended September 30, 2019. On October 17, 2019, NRG declared a quarterly dividend on the Company's common stock of $0.03 per share, payable November 15, 2019, to stockholders of record as of November 1, 2019, representing $0.12 per share on an annualized basis.

The Company's common stock dividends are subject to available capital, market conditions, and compliance with associated laws, regulations and other contractual obligations. Beginning in the first quarter of 2020, NRG will increase the annual dividend to $1.20 per share and expects to target an annual dividend growth rate of 7-9% per share in subsequent years.

Note 13 — Earnings Per Share

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

The reconciliation of NRG's basic and diluted income per share is shown in the following table:


	Three months ended September 30,						Nine months ended September 30,
(In millions, except per share data)	2019		2018		2019		2018
Basic income per share attributable to NRG Energy, Inc;
Net income/(loss) attributable to NRG Energy, Inc. common stockholders	$	372	$	(72)	$	1,055	$	280
Weighted average number of common shares outstanding - basic	254		299		266		309
Income/(loss) per weighted average common share — basic	$	1.46	$	(0.24)	$	3.97	$	0.91

Diluted income per share attributable to NRG Energy, Inc;


Net income/(loss) attributable to NRG Energy, Inc. available to common shareholders	$	372	$	(72)	$	1,055	280
Weighted average number of common shares outstanding - basic	254		299		266		309
Incremental shares attributable to the issuance of equity compensation (treasury stock method)	2		—		2		4
Weighted average number of common shares outstanding - dilutive	256		299		268		313
Income/(loss) per weighted average common share — diluted	$	1.45	$	(0.24)	$	3.94	$	0.89

The following table summarizes NRG’s outstanding equity instruments that are anti-dilutive and were not included in the computation of the Company’s diluted income per share:


	Three months ended September 30,			Nine months ended September 30,
(In millions of shares)	2019	2018	2019	2018
Equity compensation plans	—	4	—	—

Note 14 — 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. Retail includes Mass customers and Business Solutions, which includes C&I customers and other distributed and reliability products. Intersegment sales are accounted for at market. Generation includes all power plant activities, domestic and international, as well as renewables. The financial information for the nine months ended September 30, 2018 has been recast to reflect the current segment structure.

On February 4, 2019, as described in Note 4, Acquisitions, Discontinued Operations and Dispositions, the Company completed the sale of and deconsolidated the South Central Portfolio. On August 31, 2018, as described in Note 4, Acquisitions, Discontinued Operations and Dispositions, NRG deconsolidated NRG Yield, Inc., its Renewables Platform and Carlsbad for financial reporting purposes. The financial information presented below has been recast to reflect the presentation of these entities as discontinued operations within the corporate segment.

NRG’s chief operating decision maker, its chief executive officer, evaluates the performance of its segments based on operational measures including adjusted earnings before interest, taxes, depreciation and amortization, or Adjusted EBITDA, free cash flow and capital for allocation, as well as net income/(loss) and net income/(loss) attributable to NRG Energy, Inc.


	Three months ended September 30, 2019 ^(a)
	Retail		Generation		Corporate		Eliminations		Total
	(In millions)
Operating revenues^(b)	$	2,544	$	974	$	—	$	(522)	$	2,996
Depreciation and amortization	37		47		7		—		91

Reorganization costs	1		—		—		—		1
(Loss)/gain on sale of assets	(1)		1		—		—		—
Equity in earnings of unconsolidated affiliates	—		29		—		—		29

Income/(loss) from continuing operations before income taxes	422		64		(107)		1		380
Income/(loss) from continuing operations	422		63		(112)		1		374
Loss from discontinued operations, net of tax	—		—		(2)		—		(2)
Net income/(loss)	422		63		(114)		1		372
Net income/(loss) attributable to NRG Energy, Inc.	$	422	$	63	$	(114)	$	1	$	372


^(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:	$	1	$	513	$	8	$	—	$	522


	Three months ended September 30, 2018^(a)
	Retail		Generation		Corporate		Eliminations		Total
	(In millions)
Operating revenues^(b)	$	2,203	$	1,478	$	1	$	(722)	$	2,960
Depreciation and amortization	30		60		7		2		99

Reorganization costs	6		3		18		—		27
Equity in earnings of unconsolidated affiliates	—		20		3		(3)		20

Loss on debt extinguishment, net	—		—		(19)		—		(19)
(Loss)/income from continuing operations before income taxes	(128)		575		(145)		(7)		295
(Loss)/income from continuing operations	(128)		574		(152)		(7)		287
Loss from discontinued operations, net of tax	—		—		(336)		—		(336)
Net (loss)/income	(128)		574		(488)		(7)		(49)
Net (loss)/income attributable to NRG Energy, Inc.	$	(128)	$	559	$	(498)	$	(5)	$	(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:	$	1	$	739	$	(18)	$	—	$	722


	Nine months ended September 30, 2019 ^(a)
	Retail		Generation		Corporate		Eliminations		Total
	(In millions)
Operating revenues^(b)	$	5,899	$	3,164	$	—	$	(1,437)	$	7,626
Depreciation and amortization	100		138		23		—		261
Impairment losses	1		—		—		—		1
Reorganization costs	4		1		11		—		16
(Loss)/gain on sale of assets	(1)		2		1		—		2
Equity in earnings of unconsolidated affiliates	—		8		—		—		8
Loss on debt extinguishment, net	—		—		(47)		—		(47)
Income/(loss) from continuing operations before income taxes	253		795		(382)		—		666
Income/(loss) from continuing operations	252		794		(389)		—		657
Income from discontinued operations, net of tax	—		—		399		—		399
Net income	252		794		10		—		1,056
Net income attributable to NRG Energy, Inc. common stockholders	$	251	$	794	$	10	$	—	$	1,055


^(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	$	1,375	$	56	$	—	$	1,437


	Nine months ended September 30, 2018 ^(a)
	Retail		Generation		Corporate		Eliminations		Total
	(In millions)
Operating revenues^(b)	$	5,497	$	2,916	$	—	$	(927)	$	7,486
Depreciation and amortization	86		220		25		—		331
Impairment losses	—		74		—		—		74
Reorganization costs	10		10		50		—		70
Gain on sale of assets	—		1		29		—		30
Equity in earnings of unconsolidated affiliates	—		27		4		(5)		26
Income/(loss) from continuing operations before income taxes	732		256		(412)		(4)		572
Income/(loss) from continuing operations	732		255		(430)		(4)		553
Loss from discontinued operations, net of tax	—		—		(272)		—		(272)
Net income/(loss)	732		255		(702)		(4)		281
Net income/(loss) attributable to NRG Energy, Inc. common stockholders	$	731	$	246	$	(697)	$	—	$	280


^(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:	$	7	$	944	$	(24)	$	—	$	927

Note 15 — Income Taxes

Effective Income Tax Rate

The income tax provision consisted of the following:


	Three months ended September 30,									Nine months ended September 30,
(In millions, except rates)	2019			2018			2019			2018
Income from continuing operations before income taxes	$	380		$	295		$	666		$	572
Income tax expense from continuing operations	6			8			9			19

Effective income tax rate	1.6		%	2.7		%	1.4		%	3.3		%

For the three and nine months ended September 30, 2019 and 2018, NRG's overall effective tax rates were lower than the statutory rate of 21%, primarily due to the tax benefit for the change in valuation allowance, partially offset by current state tax expense.

Uncertain Tax Benefits

As of September 30, 2019, NRG has recorded a non-current tax liability of $29 million for uncertain tax benefits from positions taken on various state income tax returns, including accrued interest. For the nine months ended September 30, 2019, NRG accrued an immaterial amount of interest relating to the uncertain tax benefits. As of September 30, 2019, NRG had cumulative interest and penalties related to these uncertain tax benefits of $5 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 16 — Related Party Transactions

The following table summarizes NRG's material related party transactions with third party affiliates:


	Three months ended September 30,						Nine months ended September 30,
	2019		2018		2019		2018
	(In millions)
Revenues from Related Parties Included in Operating Revenues
Gladstone	$	2	$	1	$	3	$	2
GenConn	—		1		—		4
Ivanpah	7		8		25		13
Midway-Sunset	2		—		4		—
Revenues from Related Parties recorded against selling, general and administrative expenses
GenOn	—		11		—		53
Total	$	11	$	21	$	32	$	72

Gladstone — NRG provides services to Gladstone, an equity method investment, under an operations and maintenance agreement. Fees for services under this contract primarily include recovery of NRG's costs of operating the plant, as approved in the annual budget, as well as a base monthly fee.

GenConn — NRG provides services to GenConn under operations and maintenance agreements with GenConn Devon and GenConn Middletown that began in June 2010 and June 2011, respectively. NRG no longer has an ownership interest in GenConn as a result of the sale of its ownership interests in NRG Yield, Inc. and its Renewables Platform.

Ivanpah — NRG provides services to Ivanpah, an equity method investment, under an operations and maintenance agreement and a project management agreement with each project company. Fees for the services under these contracts primarily include recovery of NRG's costs of operating the plant and providing administrative services, plus a profit margin. Ivanpah became a related party to NRG upon deconsolidation in the second quarter of 2018.

Midway-Sunset — NRG provides services to Midway-Sunset, an equity method investment, under an operations and maintenance agreement. Fees for the services under this contract primarily include recovery of NRG's costs of operating the plant, as approved in the annual budget, as well as a base monthly fee and an annual incentive bonus.

GenOn — NRG provided various management, personnel and other services to GenOn under the transition services agreement in conjunction with the confirmation of the GenOn Entities' plan of reorganization. GenOn provided notice to NRG of its intent to terminate the transition services agreement effective August 15, 2018 and all amounts owed and payable to NRG were settled.

Note 17 — Commitments and Contingencies

Commitments

First Lien Structure

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. On or about March 15, 2019, the Jewett mine and related lignite supply agreement with NRG were acquired by Westmoreland Mining LLC pursuant to a plan of reorganization confirmed by the U.S. Bankruptcy Court for the Southern District of Texas. Active mining under the lignite supply agreement ceased as of December 31, 2016; however, under the terms of the lignite supply agreement, the mine operator remains responsible for undertaking reclamation activities and NRG is responsible for reclamation costs. NRG 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 Jewett mine, which NRG supports through surety bonds. Additionally, the lignite supply agreement obligates NRG to provide additional performance assurance if required by the Railroad Commission of Texas.

Contingencies

The Company's material legal proceedings are described below. The Company believes that it has valid defenses to these legal proceedings and intends to defend them vigorously. NRG records accruals for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. As applicable, the Company has established an adequate accrual for the applicable legal matters, including regulatory and environmental matters as further discussed in Note 18, Regulatory Matters, and Note 19, Environmental Matters. In addition, legal costs are expensed as incurred. Management has assessed each of the following matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought, and the probability of success. Unless specified below, the Company is unable to predict the outcome of these legal proceedings or reasonably estimate the scope or amount of any associated costs and potential liabilities. As additional information becomes available, management adjusts its assessment and estimates of such contingencies accordingly. Because litigation is subject to inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate resolution of the Company's liabilities and contingencies could be at amounts that are different from its currently recorded accruals and that such difference could be material.

In addition to the legal proceedings noted below, NRG and its subsidiaries are party to other litigation or legal proceedings arising in the ordinary course of business. In management's opinion, the disposition of these ordinary course matters will not materially adversely affect NRG's consolidated financial position, results of operations, or cash flows.

Midwest Generation Asbestos Liabilities — The Company, through certain of its subsidiaries, settled the indemnification claims brought by Commonwealth Edison Company and Exelon Generation Company LLC (collectively, "ComEd") as a result of the Company's acquisition of EME. Pursuant to a settlement agreement dated as of May 29, 2019, the Company paid $26 million to ComEd during the second quarter of 2019, which was previously accrued. In addition, ComEd released all claims that were or could have been asserted in its claims in the EME bankruptcy case and certain of the Company's subsidiaries released all permissive and compulsory counter claims they could have asserted in response to the ComEd claims.

California Department of Water Resources and San Diego Gas & Electric Company v. Sunrise Power Company LLC — On January 29, 2016, CDWR and SDG&E (plaintiffs) filed a lawsuit against Sunrise Power Company, along with NRG and Chevron Power Corporation (defendants). In June 2001, CDWR and Sunrise entered into a 10-year PPA under which Sunrise would construct and operate a generating facility and provide power to CDWR. At the time the PPA was entered into, Sunrise had a transportation services agreement, or TSA, to purchase natural gas from Kern River through April 30, 2018. In August 2003, CDWR entered into an agreement with Sunrise and Kern River in which CDWR accepted assignment of the TSA through the term of the PPA. After the PPA expired, Kern River demanded that any reassignment be to a party which met certain creditworthiness standards which Sunrise did not. As such, the plaintiffs brought this lawsuit against the defendants alleging breach of contract, breach of covenant of good faith and fair dealing and improper distributions. Plaintiffs generally claim damages of $1.2 million per month for the remaining 70 months of the TSA. On April 20, 2016, the defendants filed objections in response to the plaintiffs' complaint. The objections were granted on June 14, 2016; however, the plaintiffs were allowed to

file amended complaints on July 1, 2016. On July 27, 2016, defendants filed objections to the amended complaints. On November 18, 2016, the court sustained the objections and allowed plaintiffs another opportunity to file a second amended lawsuit which they did on January 13, 2017. On April 21, 2017, the court issued an order sustaining the objections without leave to amend. On July 14, 2017, plaintiffs filed a notice of appeal. On January 10, 2018, plaintiffs filed their opening appellate brief. Defendants filed their opposition brief on April 10, 2018. On May 30, 2018, plaintiffs filed their reply brief. Oral argument on the appeal occurred on October 23, 2019, and on November 4, 2019, the appellate court affirmed the trial court's decision to dismiss the lawsuit.

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. LaGen filed its answer and affirmative defenses on November 17, 2017. On September 6, 2019, the court continued the trial that had been scheduled to begin on October 21, 2019 and will reset the trial date after it addresses a pending motion regarding subject matter jurisdiction, which is scheduled to be argued on January 16, 2020. On February 4, 2019, NRG sold the South Central Portfolio, including the entities subject to this litigation. However, NRG has agreed to indemnify the purchaser for certain losses suffered in connection therewith.

Sierra club et al. v. Midwest Generation LLC — In 2012, several environmental groups filed a complaint against Midwest Generation with the Illinois Pollution Control Board ("IPCB") alleging violations of environmental law resulting in groundwater contamination. In June 2019, the IPCB found that Midwest Generation violated the law because it had improperly handled coal ash at four facilities in Illinois and caused or allowed coal ash constituents to impact groundwater. On September 9, 2019, Midwest Generation filed a Motion to Reconsider numerous issues. The IPCB will hold hearings to determine the appropriate relief. Midwest Generation has been working with the Illinois EPA to address the groundwater issues since 2010.

Note 18 — Regulatory Matters

Environmental regulatory matters are discussed within Note 19, Environmental Matters, to this Form 10-Q.

NRG operates in a highly regulated industry and is subject to regulation by various federal and state agencies. As such, NRG is affected by regulatory developments at both the federal and state levels and in the regions in which NRG operates. In addition, NRG is subject to the market rules, procedures, and protocols of the various ISO and RTO markets in which NRG participates. These power markets are subject to ongoing legislative and regulatory changes that may impact NRG's wholesale and retail businesses.

In addition to the regulatory proceedings noted below, NRG and its subsidiaries are parties to other regulatory proceedings arising in the ordinary course of business or have other regulatory exposure. In management's opinion, the disposition of these ordinary course matters will not materially adversely affect NRG's consolidated financial position, results of operations, or cash flows.

South Central — On August 4, 2016, NRG received a document hold notice from FERC regarding conduct in the MISO and PJM markets. It required NRG to retain communications related to multiple generating units in the South Central region. Since sending the notice, FERC has been investigating potential violations of MISO rules involving bidding for the Big Cajun 2 facility, as well as other aspects of NRG’s operations in MISO. FERC has the authority to require disgorgement of profits and to impose penalties and NRG retains any liability following the sale of the South Central Portfolio. We expect a preliminary finding from FERC in 2019.

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

Note 19 — Environmental Matters

NRG is subject to a wide range of environmental laws in the development, construction, ownership and operation of projects. These laws generally require that governmental permits and approvals be obtained before construction and during operation of power plants. NRG is also subject to laws regarding the protection of wildlife, including migratory birds, eagles and threatened and endangered species. The electric generation industry has been facing requirements regarding GHGs, combustion byproducts, water discharge and use, and threatened and endangered species that have been put in place in recent years. However, under the current U.S. presidential administration, some of these rules are being reconsidered and reviewed. In general, future laws are expected to require the addition of emissions controls or other environmental controls or to impose certain restrictions on the operations of the Company's facilities, which could have a material effect on the Company's consolidated financial position, results of operations, or cash flows. Federal and state environmental laws generally have become more stringent over time, although this trend could slow or pause in the near term with respect to federal laws under the current U.S. presidential administration.

Air

On July 8, 2019, EPA promulgated the ACE rule, which rescinded the CPP, which sought to broadly regulate CO₂ emissions from the power sector. The ACE rule requires states that have coal-fired EGUs to develop plans to seek heat rate improvements from coal-fired EGUs. Numerous parties have challenged the ACE rule in the D.C. Circuit and numerous parties have filed petitions for reconsideration with the EPA.

In February 2012, the EPA promulgated standards (the MATS rule) to control emissions of HAPs from coal and oil-fired electric generating units. The rule established limits for mercury, non-mercury metals, certain organics and acid gases, which had to be met beginning in April 2015. In December 2018, the EPA proposed a finding that regulating HAPs was not "appropriate and necessary" because the costs far exceed the benefits. Nonetheless, the EPA proposed keeping the substantive requirements of the MATS rule. While NRG cannot predict the final outcome of this rulemaking, NRG believes that because it has already invested in pollution controls and cleaner technologies, the fleet is well-positioned to comply with the MATS rule.

Water

Once Through Cooling Regulation — In August 2014, the EPA finalized the regulation regarding the use of water for once through cooling at existing facilities to address impingement and entrainment concerns. NRG anticipates that more stringent requirements will be incorporated into some of its water discharge permits over the next several years as NPDES permits are renewed. The Company anticipates the cost of complying with these requirements to be immaterial.

Effluent Limitations Guidelines — In November 2015, the EPA revised the Effluent Limitations Guidelines for Steam Electric Generating Facilities, which would have imposed more stringent requirements (as individual permits were renewed) for wastewater streams from flue gas desulfurization, fly ash, bottom ash, and flue gas mercury control. On September 18, 2017, the EPA promulgated a final rule that, among other things, postpones the compliance dates to preserve the status quo for FGD wastewater and bottom ash transport water by two years to November 2020 until the EPA completes its next rulemaking. On April 12, 2019, the United States Court of Appeals for the Fifth Circuit released its opinion remanding portions of the rule to the EPA. Accordingly, the Company has eliminated its estimate of the environmental capital expenditures that would have been required to comply with permits incorporating the revised guidelines. The Company will revisit these estimates after the rule is revised.

Byproducts, Wastes, Hazardous Materials and Contamination

In April 2015, the EPA finalized the rule regulating byproducts of coal combustion (e.g., ash and gypsum) as solid wastes under the RCRA. In 2017, the EPA agreed to reconsider the rule. On July 30, 2018, the EPA promulgated a rule that amends the existing ash rule by extending some of the deadlines and providing more flexibility for compliance. On August 21, 2018, the D.C. Circuit found, among other things, that the EPA had not adequately regulated unlined ponds and legacy ponds. On August 14, 2019, the EPA proposed targeted changes to the April 2015 Rule including changes to address the August 2018 D.C. Circuit decision. We anticipate that the EPA will promulgate new regulations to address these and other issues as it reconsiders other aspects of the existing rule. The Company will determine estimates of the cost of compliance after the rule is revised.

Note 20 — Condensed Consolidating Financial Information

As of September 30, 2019, the Company had outstanding $4.4 billion of Senior Notes due from 2024 to 2048 and outstanding $1.1 billion of Senior Secured First Lien Notes due from 2024 to 2029, as shown in Note 10, Debt and Finance Leases. These Senior Notes and Senior Secured First Lien Notes are guaranteed by certain of NRG's current and future 100% owned domestic subsidiaries, or guarantor subsidiaries. These guarantees are both joint and several. The non-guarantor subsidiaries include all of NRG's foreign subsidiaries and certain domestic subsidiaries.

Unless otherwise noted below, each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes and the Senior Secured First Lien Notes as of September 30, 2019:


Ace Energy, Inc.	NRG Business Services LLC	NRG PacGen Inc.
Allied Home Warranty GP LLC	NRG Cabrillo Power Operations Inc.	NRG Portable Power LLC
Allied Warranty LLC	NRG California Peaker Operations LLC	NRG Power Marketing LLC
Arthur Kill Power LLC	NRG Cedar Bayou Development Company, LLC	NRG Reliability Solutions LLC
Astoria Gas Turbine Power LLC	NRG Connected Home LLC	NRG Renter's Protection LLC
BidURenergy, Inc.	NRG Connecticut Affiliate Services Inc.	NRG Retail LLC
Cabrillo Power I LLC	NRG Construction LLC	NRG Retail Northeast LLC
Cabrillo Power II LLC	NRG Curtailment Solutions, Inc	NRG Rockford Acquisition LLC
Carbon Management Solutions LLC	NRG Development Company Inc.	NRG Saguaro Operations Inc.
Cirro Group, Inc.	NRG Devon Operations Inc.	NRG Security LLC
Cirro Energy Services, Inc.	NRG Dispatch Services LLC	NRG Services Corporation
Connecticut Jet Power LLC	NRG Distributed Energy Resources Holdings LLC	NRG SimplySmart Solutions LLC
Devon Power LLC	NRG Distributed Generation PR LLC	NRG South Central Affiliate Services Inc.
Dunkirk Power LLC	NRG Dunkirk Operations Inc.	NRG South Central Operations Inc.
Eastern Sierra Energy Company LLC	NRG ECOKAP Holdings LLC	NRG South Texas LP
El Segundo Power, LLC	NRG El Segundo Operations Inc.	NRG Texas C&I Supply LLC
El Segundo Power II LLC	NRG Energy Labor Services LLC	NRG Texas Gregory LLC
Energy Alternatives Wholesale, LLC	NRG Energy Services Group LLC	NRG Texas Holding Inc.
Energy Choice Solutions LLC	NRG Energy Services International Inc.	NRG Texas LLC
Energy Plus Holdings LLC	NRG Energy Services LLC	NRG Texas Power LLC
Energy Plus Natural Gas LLC	NRG Generation Holdings, Inc.	NRG Warranty Services LLC
Energy Protection Insurance Company	NRG Greenco LLC	NRG West Coast LLC
Everything Energy LLC	NRG Home & Business Solutions LLC	NRG Western Affiliate Services Inc.
Forward Home Security, LLC	NRG Home Services LLC	O'Brien Cogeneration, Inc. II
GCP Funding Company, LLC	NRG Home Solutions LLC	ONSITE Energy, Inc.
Green Mountain Energy Company	NRG Home Solutions Product LLC	Oswego Harbor Power LLC
Gregory Partners, LLC	NRG Homer City Services LLC	Reliant Energy Northeast LLC
Gregory Power Partners LLC	NRG Huntley Operations Inc.	Reliant Energy Power Supply, LLC
Huntley Power LLC	NRG HQ DG LLC	Reliant Energy Retail Holdings, LLC
Independence Energy Alliance LLC	NRG Identity Protect LLC	Reliant Energy Retail Services, LLC
Independence Energy Group LLC	NRG Ilion Limited Partnership	RERH Holdings, LLC
Independence Energy Natural Gas LLC	NRG Ilion LP LLC	Saguaro Power LLC
Indian River Operations Inc.	NRG International LLC	Somerset Operations Inc.
Indian River Power LLC	NRG Maintenance Services LLC	Somerset Power LLC
Meriden Gas Turbines LLC	NRG Mextrans Inc.	Texas Genco GP, LLC
Middletown Power LLC	NRG MidAtlantic Affiliate Services Inc.	Texas Genco Holdings, Inc.
Montville Power LLC	NRG Middletown Operations Inc.	Texas Genco LP, LLC
NEO Corporation	NRG Montville Operations Inc.	Texas Genco Services, LP
New Genco GP, LLC	NRG North Central Operations Inc.	US Retailers LLC
Norwalk Power LLC	NRG Northeast Affiliate Services Inc.	Vienna Operations Inc.
NRG Advisory Services LLC	NRG Norwalk Harbor Operations Inc.	Vienna Power LLC
NRG Affiliate Services Inc.	NRG Operating Services, Inc.	WCP (Generation) Holdings LLC
NRG Arthur Kill Operations Inc.	NRG Oswego Harbor Power Operations Inc.	West Coast Power LLC
NRG Astoria Gas Turbine Operations Inc.

NRG conducts much of its business through and derives much of its income from its subsidiaries. Therefore, the Company's ability to make required payments with respect to its indebtedness and other obligations depends on the financial results and condition of its subsidiaries and NRG's ability to receive funds from its subsidiaries. There are no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to NRG. However, there may be restrictions for certain non-guarantor subsidiaries.

The following condensed consolidating financial information presents the financial information of NRG Energy, Inc., the guarantor subsidiaries and the non-guarantor subsidiaries in accordance with Rule 3-10 of Regulation S-X of the Securities Act. The financial information may not necessarily be indicative of results of operations or financial position had the guarantor subsidiaries or non-guarantor subsidiaries operated as independent entities.

In this presentation, NRG Energy, Inc. consists of parent company operations. Guarantor subsidiaries and non-guarantor subsidiaries of NRG are reported on an equity basis. For companies acquired, the fair values of the assets and liabilities acquired have been presented on a push-down accounting basis.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the three months ended September 30, 2019

(Unaudited)


	Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)		Eliminations^(a)		Consolidated
	(In millions)
Operating Revenues
Total operating revenues	$	2,473	$	525	$	—	$	(2)	$	2,996
Operating Costs and Expenses
Cost of operations	1,728		421		6		(2)		2,153
Depreciation and amortization	52		32		7		—		91

Selling, general and administrative	132		28		50		—		210
Reorganization costs	—		—		1		—		1
Development costs	—		—		1		—		1
Total operating costs and expenses	1,912		481		65		(2)		2,456


Operating Income/(Loss)	561		44		(65)		—		540
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries	20		—		537		(557)		—
Equity in earnings of unconsolidated affiliates	—		29		—		—		29
Impairment losses on investments	—		(101)		(6)		—		(107)
Other income, net	11		1		5		—		17

Interest expense	(4)		(3)		(92)		—		(99)
Total other income/(expense)	27		(74)		444		(557)		(160)
Income/(Loss) from Continuing Operations Before Income Taxes	588		(30)		379		(557)		380
Income tax expense	—		1		5		—		6
Income/(Loss) from Continuing Operations	588		(31)		374		(557)		374
Income/(loss) from discontinued operations, net of income tax	—		—		(2)		—		(2)


Net Income/(Loss) Attributable to NRG Energy, Inc.	$	588	$	(31)	$	372	$	(557)	$	372

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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the nine months ended September 30, 2019

(Unaudited)


	Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)		Eliminations^(a)		Consolidated
	(In millions)
Operating Revenues
Total operating revenues	$	6,382	$	1,252	$	—	$	(8)	$	7,626
Operating Costs and Expenses
Cost of operations	4,676		956		25		(8)		5,649
Depreciation and amortization	157		81		23		—		261
Impairment losses	1		—		—		—		1
Selling, general and administrative	366		56		193		—		615
Reorganization costs	—		—		16		—		16
Development costs	—		1		4		—		5
Total operating costs and expenses	5,200		1,094		261		(8)		6,547

Gain on sale of assets	1		1		—		—		2
Operating Income/(Loss)	1,183		159		(261)		—		1,081
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries	32		—		1,266		(1,298)		—
Equity in earnings of unconsolidated affiliates	—		8		—		—		8
Impairment losses on investments	—		(101)		(6)		—		(107)
Other income, net	19		10		20		—		49
Loss on debt extinguishment, net	—		—		(47)		—		(47)
Interest expense	(11)		(12)		(295)		—		(318)
Total other income/(expense)	40		(95)		938		(1,298)		(415)
Income from Continuing Operations Before Income Taxes	1,223		64		677		(1,298)		666
Income tax expense	—		2		7		—		9
Income from Continuing Operations	1,223		62		670		(1,298)		657
Income from discontinued operations, net of income tax	9		5		385		—		399
Net Income	1,232		67		1,055		(1,298)		1,056
Less: Net income attributable to redeemable noncontrolling interests	—		1		—		—		1
Net Income Attributable to NRG Energy, Inc.	$	1,232	$	66	$	1,055	$	(1,298)	$	1,055

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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

For the three months ended September 30, 2019

(Unaudited)


	Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)		Eliminations^(a)		Consolidated
	(In millions)
Net Income/(Loss)	$	588	$	(31)	$	372	$	(557)	$	372
Other Comprehensive Loss

Foreign currency translation adjustments, net	(5)		(4)		(4)		9		(4)
Available-for-sale securities, net	—		—		(14)		—		(14)
Defined benefit plans, net	(40)		—		(41)		40		(41)
Other comprehensive loss	(45)		(4)		(59)		49		(59)


Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.	$	543	$	(35)	$	313	$	(508)	$	313

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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME

For the nine months ended September 30, 2019

(Unaudited)


	Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)		Eliminations^(a)		Consolidated
	(In millions)
Net Income	$	1,232	$	67	$	1,055	$	(1,298)	$	1,056
Other Comprehensive Loss

Foreign currency translation adjustments, net	(5)		(4)		(4)		9		(4)
Available-for-sale securities, net	—		—		(13)		—		(13)
Defined benefit plans, net	(40)		—		(47)		40		(47)
Other comprehensive loss	(45)		(4)		(64)		49		(64)
Comprehensive Income	1,187		63		991		(1,249)		992
Less: Comprehensive income attributable to redeemable noncontrolling interests	—		1		—		—		1
Comprehensive Income Attributable to NRG Energy, Inc.	$	1,187	$	62	$	991	$	(1,249)	$	991

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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

September 30, 2019

(Unaudited)


	Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)		Eliminations^(a)		Consolidated
ASSETS	(In millions)
Current Assets
Cash and cash equivalents	$	—	$	26	$	217	$	—	$	243
Funds deposited by counterparties	30		—		—		—		30
Restricted cash	2		1		1		—		4
Accounts receivable, net	2,049		194		426		(1,293)		1,376
Inventory	248		116		—		—		364
Derivative instruments	740		28		—		(33)		735
Cash collateral paid in support of energy risk management activities	146		18		—		—		164

Prepayments and other current assets	178		15		78		—		271


Total current assets	3,393		398		722		(1,326)		3,187
Property, plant and equipment, net	1,494		965		156		—		2,615
Other Assets
Investment in subsidiaries	786		—		4,677		(5,463)		—
Equity investments in affiliates	—		405		—		—		405

Operating lease right-of-use assets, net	85		271		126		—		482
Goodwill	359		232		—		—		591
Intangible assets, net	390		438		—		—		828
Nuclear decommissioning trust fund	756		—		—		—		756
Derivative instruments	356		14		—		(12)		358
Deferred income taxes	—		53		—		—		53
Other non-current assets	151		30		71		—		252


Total other assets	2,883		1,443		4,874		(5,475)		3,725
Total Assets	$	7,770	$	2,806	$	5,752	$	(6,801)	$	9,527
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt	$	—	$	87	$	215	$	—	$	302
Current portion of operating lease liabilities	21		31		21		—		73
Accounts payable	1,315		146		698		(1,293)		866

Derivative instruments	683		18		—		(33)		668
Cash collateral received in support of energy risk management activities	30		—		—		—		30
Accrued expenses and other current liabilities	271		51		303		—		625



Total current liabilities	2,320		333		1,237		(1,326)		2,564
Other Liabilities
Long-term debt	245		85		5,468		—		5,798
Non-current operating lease liabilities	70		307		123		—		500
Nuclear decommissioning reserve	294		—		—		—		294
Nuclear decommissioning trust liability	453		—		—		—		453

Derivative instruments	374		2		—		(12)		364
Deferred income taxes	(10)		67		13		—		70

Other non-current liabilities	412		160		464		—		1,036


Total other liabilities	1,838		621		6,068		(12)		8,515
Total Liabilities	4,158		954		7,305		(1,338)		11,079
Redeemable noncontrolling interest in subsidiaries	—		19		—		—		19
Stockholders’ Equity	3,612		1,833		(1,553)		(5,463)		(1,571)
Total Liabilities and Stockholders’ Equity	$	7,770	$	2,806	$	5,752	$	(6,801)	$	9,527

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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the nine months ended September 30, 2019

(Unaudited)


	Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)		Eliminations^(a)		Consolidated
	(In millions)
Cash Flows from Operating Activities
Net income	$	1,232	$	67	$	1,055	$	(1,298)	$	1,056
Income from discontinued operations	9		5		385		—		399
Income from continuing operations	1,223		62		670		(1,298)		657
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	(32)		(5)		(1,266)		1,298		(5)
Depreciation, amortization and accretion	181		85		23		—		289
Provision for bad debts	72		11		4		—		87
Amortization of nuclear fuel	40		—		—		—		40
Amortization of financing costs and debt discount/premiums	—		—		20		—		20
Loss on debt extinguishment, net	—		—		47		—		47
Amortization of emission allowances	21		7		—		—		28
Amortization of unearned equity compensation	—		—		15		—		15
(Gain)/loss on sale and disposal of assets	(25)		2		3		—		(20)

Impairment losses	1		101		6		—		108
Changes in derivative instruments	10		(12)		38		—		36
Changes in deferred income taxes and liability for uncertain tax benefits	—		(1)		(2)		—		(3)
Changes in collateral deposits in support of energy risk management activities	136		(7)		—		—		129
Changes in nuclear decommissioning trust liability	27		—		—		—		27


Changes in other working capital	(401)		(120)		(81)		—		(602)
Cash provided/(used) by continuing operations	1,253		123		(523)		—		853
Cash provided/(used) by discontinued operations	17		(9)		—		—		8
Net Cash Provided/(Used) by Operating Activities	1,270		114		(523)		—		861
Cash Flows from Investing Activities
Intercompany dividends	—		—		1,665		(1,665)		—
Payments for acquisitions of businesses	(348)		—		—		—		(348)
Capital expenditures	(135)		(23)		(25)		—		(183)
Net proceeds from notes receivable	—		—		2		—		2
Net proceeds from sale of emission allowances	14		—		—		—		14
Investments in nuclear decommissioning trust fund securities	(295)		—		—		—		(295)
Proceeds from the sale of nuclear decommissioning trust fund securities	271		—		—		—		271
Proceeds from sale of assets, net of cash disposed and sale of discontinued operations, net of fees	1		400		892				1,293

Net contributions to investments in unconsolidated affiliates	—		(94)		—		—		(94)
Contributions to discontinued operations	—		(44)		—		—		(44)

Cash (used)/provided by continuing operations	(492)		239		2,534		(1,665)		616
Cash used by discontinued operations	—		(2)		—		—		(2)
Net Cash (Used)/Provided by Investing Activities	(492)		237		2,534		(1,665)		614
Cash Flows from Financing Activities
Payments from/(for) intercompany loans	784		(260)		(524)		—		—
Intercompany dividends	(1,608)		(57)		—		1,665		—
Payment of dividends to common stockholders	—		—		(24)		—		(24)
Payments for treasury stock	—		—		(1,286)		—		(1,286)

Payments for debt extinguishment costs	—		—		(24)		—		(24)
Distributions to noncontrolling interests from subsidiaries	—		(1)		—		—		(1)
Proceeds from issuance of common stock	—		—		3		—		3
Proceeds from issuance of long-term debt	—		—		2,048		—		2,048
Payment of debt issuance costs	—		—		(34)		—		(34)
Payments for long-term debt	—		(55)		(2,432)		—		(2,487)


Cash used by continuing operations	(824)		(373)		(2,273)		1,665		(1,805)
Cash provided by discontinued operations	—		43		—		—		43
Net Cash Used by Financing Activities	(824)		(330)		(2,273)		1,665		(1,762)

Change in cash from discontinued operations	17		32		—		—		49
Net Decrease in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash	(63)		(11)		(262)		—		(336)
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period	95		38		480		—		613
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	$	32	$	27	$	218	$	—	$	277

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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the three months ended September 30, 2018

(Unaudited)


	Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)		Eliminations^(a)		Consolidated
	(In millions)
Operating Revenues
Total operating revenues	$	2,521	$	441	$	—	$	(2)	$	2,960
Operating Costs and Expenses
Cost of operations	1,937		294		9		(2)		2,238
Depreciation and amortization	54		36		9		—		99

Selling, general and administrative	123		19		142		(73)		211
Reorganization costs	—		—		27		—		27
Development costs	—		(2)		3		—		1
Total operating costs and expenses	2,114		347		190		(75)		2,576

Gain on sale of assets	—		14		—		—		14
Operating Income/(Loss)	407		108		(190)		73		398
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries	6		—		470		(476)		—
Equity in earnings/(losses) of unconsolidated affiliates	—		21		(1)		—		20
Impairment losses on investments	—		(1)		—		—		(1)
Other income, net	4		9		6		—		19
Loss on debt extinguishment, net	—		—		(19)		—		(19)
Interest expense	(4)		(8)		(110)		—		(122)
Total other income/(expense)	6		21		346		(476)		(103)
Income from Continuing Operations Before Income Taxes	413		129		156		(403)		295
Income tax expense/(benefit)	122		42		(156)		—		8
Income from Continuing Operations	291		87		312		(403)		287
Income/(loss) from discontinued operations, net of income tax	16		20		(372)		—		(336)
Net Income/(Loss)	307		107		(60)		(403)		(49)
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest	—		(62)		12		73		23
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	307	$	169	$	(72)	$	(476)	$	(72)

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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the nine months ended September 30, 2018

(Unaudited)


	Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)		Eliminations^(a)		Consolidated
	(In millions)
Operating Revenues
Total operating revenues	$	6,437	$	1,061	$	—	$	(12)	$	7,486
Operating Costs and Expenses
Cost of operations	4,794		713		18		(13)		5,512
Depreciation and amortization	177		128		26		—		331
Impairment losses	—		74		—		—		74
Selling, general and administrative	335		46		279		(73)		587
Reorganization costs	3		—		67		—		70
Development costs	—		—		10		(1)		9
Total operating costs and expenses	5,309		961		400		(87)		6,583

Gain on sale of assets	3		27		—		—		30
Operating Income/(Loss)	1,131		127		(400)		75		933
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries	14		—		1,156		(1,170)		—
Equity in earnings/(losses) of unconsolidated affiliates	—		28		(2)		—		26
Impairment losses on investments	—		(16)		—		—		(16)
Other income/(loss), net	12		(11)		11		—		12
Loss on debt extinguishment, net	—		—		(22)		—		(22)
Interest expense	(11)		(42)		(308)		—		(361)
Total other income/(expense)	15		(41)		835		(1,170)		(361)
Income from Continuing Operations Before Income Taxes	1,146		86		435		(1,095)		572
Income tax expense/(benefit)	343		26		(350)		—		19
Income from Continuing Operations	803		60		785		(1,095)		553
Income/(loss) from discontinued operations, net of income tax	46		80		(398)		—		(272)
Net Income	849		140		387		(1,095)		281
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest	—		(181)		107		75		1
Net Income Attributable to NRG Energy, Inc.	$	849	$	321	$	280	$	(1,170)	$	280

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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

For the three months ended September 30, 2018

(Unaudited)


	Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)		Eliminations^(a)		Consolidated
	(In millions)
Net Income/(Loss)	$	307	$	107	$	(60)	$	(403)	$	(49)
Other Comprehensive (Loss)/Income
Unrealized gain/(loss) on derivatives, net	—		10		(12)		7		5
Foreign currency translation adjustments, net	(2)		(2)		(1)		3		(2)

Defined benefit plans, net	—		—		(1)		—		(1)
Other comprehensive (loss)/income	(2)		8		(14)		10		2
Comprehensive Income/(Loss)	305		115		(74)		(393)		(47)
Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable interests	—		(58)		11		73		26
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.	$	305	$	173	$	(85)	$	(466)	$	(73)

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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME

For the nine months ended September 30, 2018

(Unaudited)


	Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)		Eliminations^(a)		Consolidated
	(In millions)
Net Income	$	849	$	140	$	387	$	(1,095)	$	281
Other Comprehensive (Loss)/Income
Unrealized gain on derivatives, net	—		30		9		(15)		24
Foreign currency translation adjustments, net	(8)		(8)		(9)		17		(8)
Available-for-sale securities, net	—		—		1		—		1
Defined benefit plans, net	—		—		(3)		—		(3)
Other comprehensive (loss)/income	(8)		22		(2)		2		14
Comprehensive Income	841		162		385		(1,093)		295
Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable interests	—		(167)		107		75		15
Comprehensive Income Attributable to NRG Energy, Inc.	$	841	$	329	$	278	$	(1,168)	$	280

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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

December 31, 2018


	Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)		Eliminations^(a)		Consolidated
ASSETS	(In millions)
Current Assets
Cash and cash equivalents	$	55	$	28	$	480	$	—	$	563
Funds deposited by counterparties	33		—		—		—		33
Restricted cash	7		10		—		—		17
Accounts receivable, net	1,354		115		309		(754)		1,024
Inventory	278		134		—		—		412
Derivative instruments	779		50		16		(81)		764
Cash collateral paid in support of energy risk management activities	275		12		—		—		287

Prepayments and other current assets	180		32		90		—		302
Current assets - held-for-sale	—		1		—		—		1
Current assets - discontinued operations	177		20		—		—		197
Total current assets	3,138		402		895		(835)		3,600
Property, plant and equipment, net	1,938		957		153		—		3,048
Other Assets
Investment in subsidiaries	446		—		4,707		(5,153)		—
Equity investments in affiliates	—		412		—		—		412


Goodwill	359		214		—		—		573
Intangible assets, net	422		169		—		—		591
Nuclear decommissioning trust fund	663		—		—		—		663
Derivative instruments	296		4		22		(5)		317
Deferred income taxes	6		(143)		183		—		46
Other non-current assets	133		71		97		(12)		289
Non-current assets - held for sale	—		77		—		—		77
Non-current assets - discontinued operations	405		607		—		—		1,012
Total other assets	2,730		1,411		5,009		(5,170)		3,980
Total Assets	$	7,806	$	2,770	$	6,057	$	(6,005)	$	10,628
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and finance leases	$	—	$	55	$	17	$	—	$	72

Accounts payable	1,368		(185)		434		(754)		863

Derivative instruments	713		41		—		(81)		673
Cash collateral received in support of energy risk management activities	33		—		—		—		33
Accrued expenses and other current liabilities	291		36		353		—		680

Current liabilities - held-for-sale	—		5		—		—		5
Current liabilities - discontinued operations	24		48		—		—		72
Total current liabilities	2,429		—		804		(835)		2,398
Other Liabilities
Long-term debt and finance leases	244		192		6,025		(12)		6,449

Nuclear decommissioning reserve	282		—		—		—		282
Nuclear decommissioning trust liability	371		—		—		—		371

Derivative instruments	306		3		—		(5)		304
Deferred income taxes	112		61		(108)		—		65

Other non-current liabilities	402		320		552		—		1,274
Non-current liabilities - held-for-sale	—		65		—		—		65
Non-current liabilities - discontinued operations	58		577		—		—		635
Total other liabilities	1,775		1,218		6,469		(17)		9,445
Total Liabilities	4,204		1,218		7,273		(852)		11,843
Redeemable noncontrolling interest in subsidiaries	—		19		—		—		19
Stockholders’ Equity	3,602		1,533		(1,216)		(5,153)		(1,234)
Total Liabilities and Stockholders’ Equity	$	7,806	$	2,770	$	6,057	$	(6,005)	$	10,628

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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the nine months ended September 30, 2018

(Unaudited)


	Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)		Eliminations^(a)		Consolidated
	(In millions)
Cash Flows from Operating Activities
Net income	$	849	$	140	$	387	$	(1,095)	$	281
Income/(loss) from discontinued operations	46		80		(398)		—		(272)
Income from continuing operations	803		60		785		(1,095)		553
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	(14)		9		(1,095)		1,110		10
Depreciation, amortization and accretion	201		137		26		—		364
Provision for bad debts	55		2		—		—		57
Amortization of nuclear fuel	38		—		—		—		38
Amortization of financing costs and debt discount/premiums	—		23		(2)		—		21
Loss on debt extinguishment, net	—		—		22		—		22
Amortization of emission allowances and out-of-market contracts	15		6		—		—		21
Amortization of unearned equity compensation	—		—		21		—		21
Gain on sale and disposal of assets	(23)		(27)		—		—		(50)

Impairment losses	—		90		—		—		90
Changes in derivative instruments	(38)		40		(4)		(15)		(17)
Changes in deferred income taxes and liability for uncertain tax benefits	343		11		(360)		—		(6)
Changes in collateral deposits in support of energy risk management activities	(16)		(14)		—		—		(30)
Changes in nuclear decommissioning trust liability	50		—		—		—		50
GenOn Settlement	—		—		(125)		—		(125)
Loss on deconsolidation of Agua Caliente and Ivanpah projects	—		13		—		—		13
Changes in other working capital	(385)		(266)		290		—		(361)
Cash provided/(used) by continuing operations	1,029		84		(442)		—		671
Cash provided by discontinued operations	72		324		—		—		396
Net Cash Provided/(Used) by Operating Activities	1,101		408		(442)		—		1,067
Cash Flows from Investing Activities
Intercompany dividends	—		—		1,273		(1,273)		—
Payments for acquisitions of businesses	(2)		(207)		—		—		(209)
Capital expenditures	(156)		(150)		(37)		—		(343)

Net proceeds from sale of emission allowances	24		—		—		—		24
Investments in nuclear decommissioning trust fund securities	(449)		—		—		—		(449)
Proceeds from the sale of nuclear decommissioning trust fund securities	398		—		—		—		398
Proceeds from sale of assets, net of cash disposed of	10		8		1,537		—		1,555
Deconsolidation of Agua Caliente and Ivanpah projects	—		(268)		—		—		(268)
Net contributions to investments in unconsolidated affiliates	—		(39)		—		—		(39)
Contributions to discontinued operations	—		(23)		—		—		(23)

Cash (used)/provided by continuing operations	(175)		(679)		2,773		(1,273)		646
Cash used by discontinued operations	(2)		(703)		—		—		(705)
Net Cash (Used)/Provided by Investing Activities	(177)		(1,382)		2,773		(1,273)		(59)
Cash Flows from Financing Activities
Payments from/(for) intercompany loans	476		170		(646)		—		—
Intercompany dividends	(1,273)		—		—		1,273		—
Payment of dividends to common stockholders	—		—		(28)		—		(28)
Payments for treasury stock	—		—		(1,000)		—		(1,000)


Distributions to noncontrolling interests from subsidiaries	—		(17)		—		—		(17)
Proceeds from issuance of common stock	—		—		15		—		15
Proceeds from issuance of short and long-term debt	—		163		832		—		995
Payment of debt issuance costs	—		—		(19)		—		(19)
Payments for short and long-term debt	—		(106)		(864)		—		(970)
Receivable from affiliate	—		—		(26)		—		(26)
Other	—		(4)		—		—		(4)
Cash (used)/provided by continuing operations	(797)		206		(1,736)		1,273		(1,054)
Cash provided by discontinued operations	—		403		—		—		403
Net Cash (Used)/Provided by Financing Activities	(797)		609		(1,736)		1,273		(651)
Effect of exchange rate changes on cash and cash equivalents	—		1		—		—		1
Change in cash from discontinued operations	70		24		—		—		94
Net Increase/(Decrease) in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash	57		(388)		595		—		264
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period	41		425		620		—		1,086
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	$	98	$	37	$	1,215	$	—	$	1,350

(a)All significant intercompany transactions have been eliminated in 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 nine months ended September 30, 2019 and 2018. Also refer to NRG's 2018 Form 10-K, which includes detailed discussions of various items impacting the Company's business, results of operations and financial condition, including: Introduction and Overview section; NRG's Business Strategy section; Business section, including how regulation, weather, and other factors affect NRG's business; and Critical Accounting Policies and Estimates section.

The discussion and analysis below has been organized as follows:

•Executive summary, including introduction and overview, business strategy, and changes to the business environment during the period, including environmental and regulatory matters;

•Results of operations;

•Financial condition, addressing liquidity position, sources and uses of liquidity, capital resources and requirements, commitments, and off-balance sheet arrangements; and

•Known trends that may affect NRG's results of operations and financial condition in the future.

As further described in Note 4, Acquisitions, Discontinued Operations and Dispositions, the Company is treating the following businesses as discontinued operations, and has recast prior periods to present in the corporate segment:

•South Central Portfolio

•NRG Yield, Inc. and its Renewables Platform

•Carlsbad

•GenOn

Executive Summary

Introduction and Overview

NRG Energy, Inc., or NRG or the Company, is an energy company built on dynamic retail brands with diverse generation assets. NRG brings the power of energy to consumers by producing, selling and delivering electricity and related products and services in major competitive power markets in the U.S. in a manner that delivers value to all of NRG's stakeholders. NRG is perfecting the integrated model by balancing retail load with generation supply within its deregulated markets, while evolving to a customer-driven business. The Company sells energy, services, and innovative, sustainable products and services directly to retail customers under the names "NRG" and "Reliant" and other brand names owned by NRG supported by approximately 23,000 MW of generation as of September 30, 2019. NRG was incorporated as a Delaware corporation on May 29, 1992.

The following table summarizes NRG's global generation portfolio as of September 30, 2019, by operating segment:


	Global Generation Portfolio^(a)
	(In MW)
	Generation
Generation Type	Texas^(b)	East/West^(c)(d)	Other^(e)	Total Global
Natural gas	4,759	4,994	—	9,753
Coal	4,174	3,745	—	7,919
Oil	—	3,600	—	3,600
Nuclear	1,126	—	—	1,126
Utility Scale Solar	—	321	—	321
Battery Storage & Distributed Solar	2	—	60	62
Total generation capacity	10,061	12,660	60	22,781

(a) All Utility Scale Solar and Distributed Solar facilities are described in MW on an alternating current basis. MW figures provided represent nominal summer net MW capacity of power generated as adjusted for the Company's owned or leased interest excluding capacity from inactive/mothballed units

(b) Does not include Cottonwood, which is included in East/West

(d) Includes 1,153 MW for the Cottonwood facility that was sold to Cleco on February 4, 2019, which the company is leasing until 2025

(e) The Distributed Solar figure within "Other" includes the aggregate production capacity of installed and activated residential solar energy systems

Strategy

NRG's strategy is to maximize stockholder value through the safe production and sale of reliable power to its customers in the markets served by the Company, while positioning the Company to provide innovative solutions to the end-use energy consumer. This strategy is intended to enable the Company to optimize the integrated model to generate predictable cash flow, significantly strengthen earnings and cost competitiveness, and lower risk and volatility. Sustainability is an integral piece of NRG's strategy and ties directly to business success, reduced risks and brand value.

To effectuate the Company’s strategy, NRG is focused on: (i) serving the energy needs of end-use residential, commercial and industrial customers in competitive markets through multiple brands and channels with a variety of retail energy products and services differentiated by innovative features, premium service, sustainability, and loyalty/affinity programs; (ii) deploying innovative and renewable energy solutions for consumers within its retail businesses; (iii) excellence in operating performance of its existing assets including optimal hedging of generation assets and retail load operations; and (iv) engaging in a proactive capital allocation plan within the dictates of prudent balance sheet management.

On September 24, 2019, NRG announced the acceleration of its science-based GHG emissions reduction goals to align with prevailing climate science, limiting warming to a 1.5 degree Celsius scenario. Under its new GHG emissions reduction timeline, NRG is targeting to achieve a 50% reduction by 2025 and net-zero emissions by 2050.

Transformation Plan

NRG is well underway in executing its Transformation Plan. The Company expects to fully implement the Transformation Plan by the end of 2020, with a significant portion of the plan completed in 2018. The three-part, three-year plan is comprised of the following targets, and the Company's achievements towards such targets are as follows:

Operations and cost excellence - Recurring cost savings and margin enhancement of $1,065 million, which consists of $590 million of cumulative cost savings, a $215 million net margin enhancement program, $50 million annual reduction in maintenance capital expenditures, and $210 million in permanent selling, general and administrative expense reduction associated with asset sales. The Company realized annual cost savings of $532 million and $32 million of margin enhancements during the year ended December 31, 2018, and expects to realize $590 million of cost savings and $135 million of margin enhancements in 2019.

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

Portfolio Optimization - Targeted and completed $3.0 billion of asset sale cash proceeds, including $1.4 billion in the first quarter of 2019 from the sales of the South Central portfolio, the Carlsbad project and Guam.

Capital Structure and Allocation - As of December 31, 2018, the Company achieved the planned credit ratio of 3.0x net debt / adjusted EBITDA^(a). During the first quarter of 2019, the Company revised its credit metrics target in order to further strengthen its balance sheet by reducing leverage.

Energy Regulatory Matters

The Company’s regulatory matters are described in the Company’s 2018 Form 10-K in Item 1, Business — Regulatory Matters. These matters have been updated below and in Note 18, Regulatory Matters, of this Form 10-Q.

As participants in wholesale and retail energy markets and owners of power plants, certain NRG entities are subject to regulation by various federal and state government agencies. These include the CFTC, FERC, NRC, and the PUCT, as well as other public utility commissions in certain states where NRG's generating or distributed generation assets are located. In addition, NRG is subject to the market rules, procedures and protocols of the various ISO and RTO markets in which it participates. Likewise, certain NRG entities participating in the retail markets are subject to rules and regulations established by the states in which NRG entities are licensed to sell at retail. NRG must also comply with the mandatory reliability requirements imposed by NERC and the regional reliability entities in the regions where NRG operates.

NRG's operations within the ERCOT footprint are not subject to rate regulation by FERC, as they are deemed to operate solely within the ERCOT market and not in interstate commerce. These operations are subject to regulation by the PUCT, as well as to regulation by the NRC with respect to NRG's ownership interest in STP.

Federal Energy Regulation

PG&E Corporation Bankruptcy Filing — On January 18, 2019, NextEra Energy, Inc., filed a petition for declaratory order requesting that FERC assert its jurisdiction over PG&E's wholesale contracts prior to PG&E's formal bankruptcy filing. Exelon Corporation and EDF Renewables filed similar complaints. On January 25, 2019, FERC found that it and the bankruptcy courts have concurrent jurisdiction to review and address the disposition of wholesale power contracts. Separately, the PG&E bankruptcy court ruled on June 7, 2019 that it does not share concurrent jurisdiction with FERC and has unilateral discretion to address the disposition of wholesale power contracts. On June 26, 2019, PG&E appealed the FERC order that was issued on January 25, 2019. The issue of jurisdiction over wholesale power contracts remains in litigation. On September 9, 2019, PG&E filed a plan of reorganization that would assume all power purchase agreements, including those held by the Agua Caliente project and two of the Ivanpah units. On October 17, 2019, a group of unsecured creditors filed a competing plan of reorganization that would also assume all power purchase agreements, including those held by the Agua Caliente project and the two Ivanpah units.

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

State Energy Regulation

State Out-Of-Market Subsidy Proposals — NRG has opposed efforts to provide out-of-market subsidies for nuclear generators and intends to continue opposing them in the future. Nuclear subsidy programs have either been implemented, are in the process of being implemented, or have been introduced for discussion in Connecticut, Illinois, New Jersey, New York, Ohio and Pennsylvania. NRG and others were unsuccessful in challenging the legality of the subsidies in Illinois and New York, and the U.S. Supreme Court has declined to review the lower court decisions.

Illinois Legislature Considers Changes to the Generator Business Model — In Illinois, in addition to legislation to provide more subsidies to nuclear power plants in the state, the Legislature is also considering several bills that may affect NRG’s wholesale and retail revenues, including a bill that would replace the PJM capacity market with a state-run capacity market. Illinois ended its regular session on May 31, 2019 without passing these significant energy bills. NRG continues to oppose the ongoing legislative effort and supports 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 — The New York State Legislature enacted 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 it finds that the program impedes safe and adequate electric service, likely impairs "existing obligations and agreements," and/or increases consumer late payments or service disconnections. The legislation includes provision for offsets, including carbon capture and sequestration, but electric generation sources are not eligible to participate in the offsets mechanism.

Regional Regulatory Developments

NRG is affected by rule and tariff changes that occur in the ISO regions. For further discussion on regulatory developments see Note 18, Regulatory Matters, to the Condensed Consolidated Financial Statements.

East/West

PJM

Capacity Market Reforms Filing — FERC is considering various proposals to reform the PJM capacity market, including whether to accommodate state subsidies in the wholesale market or to mitigate subsidized resources, along with other changes. On July 25, 2019, FERC directed PJM to wait to have the Base Residual Auction for 2022/2023 delivery year until new rules are in place. On September 27, 2019, PJM announced it was suspending all auction deadlines relating to Base Residual Auctions for 2022/2023 and 2023/2024 delivery year, consistent with FERC’s July 25, 2019 Order. Decisions around harmonizing federal and state policy initiatives are a critical factor for setting future prices.

PJM's Operational Reserve Demand Curve Filing — On March 29, 2019, PJM proposed energy and reserve market reforms to enhance price formation in reserve markets, which includes modifying its Operating Reserve Demand Curve and aligning market-based reserve products in Day-Ahead and Real-Time markets. The matter is pending at FERC. If the proposal were approved as filed, energy and reserve market prices could increase.

Independent Market Monitor Market Seller Offer Cap Complaint — On February 21, 2019, the Independent Market Monitor filed a complaint alleging that the current Market Seller Offer Cap is too high. On April 9, 2019, PJM filed its answer arguing that as a threshold matter the Independent Market Monitor is not authorized to file a complaint against PJM and among other things, that the Market Monitor failed to support its claim that expected number of performance assessment hours used to calculate the cap is overstated. The Company’s trade organization filed a protest in the docket echoing PJM’s concerns. The Market Monitor subsequently filed answers in the docket and the docket remains pending. If the request is granted, default market offer caps could be lower.

PJM’s Fast Start Pricing Filing — On April 19, 2019, FERC ordered PJM to implement fast start pricing because it found that the existing fast-start pricing practices are unjust and unreasonable because they do not allow prices to reflect the marginal cost of serving load. PJM made its compliance filing on August 30, 2019, which currently is pending. The changes could provide more accurate pricing to reflect the marginal cost of serving load.

New England

ISO-NE Retention of Mystic Units — ISO-NE is currently engaged in extensive litigation at FERC regarding how to ensure system reliability in a gas-constrained system. In particular, FERC has approved ISO-NE's proposal to retain units at the Mystic generating station, which utilizes liquefied natural gas for fuel security. Among other things, FERC specifically will allow resources retained for fuel security to enter a zero bid in the Forward Capacity Auction, and also ordered ISO-NE to provide a long-term market-based solution for fuel security. On January 2, 2019, multiple parties filed for rehearing. The motions for rehearing are pending at FERC. The outcome of this matter may affect future capacity market prices.

ISO-NE Inventoried Energy Compensation Proposal — On March 25, 2019, ISO-NE proposed an interim measure to address near-term fuel security concerns. The proposal would provide payment for inventoried energy during winter months. NRG protested, among other things, the payment rate proposed by the ISO for inventoried energy. After ISO-NE supplemented its filings due to a deficiency notice from FERC, NRG filed comments to ISO-NE's response on June 27, 2019. On August 6, 2019, FERC issued a notice stating that due to lack of quorum, ISO-NE's proposal became effective by operation of law. Multiple parties filed for rehearing. Those rehearings were denied. ISO-NE's proposal will affect future capacity market prices and the compensation fuel secure units receive.

New York

New York State Public Service Commission Retail Energy Market Proceedings — On February 23, 2016, the NYSPSC issued an order referred to as the Retail Reset Order. Among other things, the Retail Reset Order placed a price cap on energy supply offers and imposed burdensome new regulations on customers. Various parties have challenged the NYSPSC's authority to regulate prices charged by competitive suppliers. On May 9, 2019 the New York Court of Appeals, the state’s highest tribunal, issued a decision affirming the NYSPSC’s authority to regulate Energy Service Companies’ prices as a condition of access to the utilities’ infrastructure. In conjunction with the court challenge, the NYSPSC also noticed an evidentiary proceeding, which is still open before the NYSPSC. The matter is fully briefed and a decision is pending.

Texas

ORDC Reforms — In January 2019, the PUCT directed ERCOT to implement changes to its scarcity pricing structure, known as the ORDC, which is designed to increase the likelihood of scarcity pricing to support existing generation and new investment. The PUCT directed ORDC reforms to be implemented in two phases of gradually increasing magnitude. The first phase became effective on March 1, 2019 and the second phase will become effective on March 1, 2020. To date, the ORDC reforms have produced a noticeable improvement in scarcity pricing.

Environmental Regulatory Matters

NRG is subject to numerous environmental laws in the development, construction, ownership and operation of projects. These laws generally require that governmental permits and approvals be obtained before construction and during operation of power plants. Federal and state environmental laws historically have become more stringent over time. Future laws may require the addition of emissions controls or other environmental controls or impose restrictions on our operations, which could affect the Company's operations. Complying with environmental laws often involves significant capital and operating expenses, as well as occasionally curtailing operations. NRG decides to invest capital for environmental controls based on the relative certainty of the requirements, an evaluation of compliance options, and the expected economic returns on capital.

A number of regulations that may affect the Company are under review by the EPA, including ESPS for GHGs, ash disposal requirements, NAAQS revisions and implementation and effluent limitation guidelines. NRG will evaluate the impact of these regulations as they are revised but cannot fully predict the impact of each until anticipated legal challenges are resolved. The Company’s environmental matters are described in the Company’s 2018 Form 10-K in Item 1, Business - Environmental Matters and Item 1A, Risk Factors. These matters have been updated in Note 19, Environmental Matters, to the Condensed Consolidated Financial Statements of this Form 10-Q and as follows.

Air

The CAA and the resulting regulations (as well as similar state and local requirements) have the potential to affect air emissions, operating practices and pollution control equipment required at power plants. Under the CAA, the EPA sets NAAQS for certain pollutants including SO₂, ozone, and PM2.5. Many of the Company's facilities are located in or near areas that are classified by the EPA as not achieving certain NAAQS (non-attainment areas). The relevant NAAQS have become more stringent. The Company maintains a comprehensive compliance strategy to address continuing and new requirements. Complying with increasingly stringent air regulations could require the installation of additional emissions control equipment at some NRG facilities or retiring of units if installing such controls is not economic. Significant changes to air regulatory programs affecting the Company are described below.

MATS — In 2012, the EPA promulgated standards (the MATS rule) to control emissions of HAPs from coal and oil-fired electric generating units. The rule established limits for mercury, non-mercury metals, certain organics and acid gases, which had to be met beginning in April 2015. In December 2018, the EPA proposed a finding that regulating HAPs was not "appropriate and necessary" because the costs far exceed the benefits. Nonetheless, the EPA proposed keeping the substantive requirements of the MATS rule. While NRG cannot predict the final outcome of this rulemaking, NRG believes that because it has already invested in pollution controls and cleaner technologies, the fleet is well-positioned to comply with the MATS rule.

Clean Power Plan — The attention in recent years on GHG emissions has resulted in federal regulations and state legislative and regulatory action. In October 2015, the EPA finalized the CPP, addressing GHG emissions from existing EGUs. On February 9, 2016, the U.S. Supreme Court stayed the CPP. In July 2019, EPA promulgated the ACE rule, which rescinded the CPP, which sought to broadly regulate CO2 emissions from the power sector. The ACE rule requires states that have coal-fired EGUs to develop plans to seek heat rate improvements from coal-fired EGUs. Numerous parties have challenged the ACE rule in the D.C. Circuit and numerous parties have filed petitions for reconsideration with the EPA.

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. On August 14, 2019, the EPA proposed targeted changes to the April 2015 Rule including changes to address the August 2018 D.C. Circuit decision. We anticipate that the EPA will promulgate new regulations to address these issues and others as it reconsiders other aspects of the existing rule. The Company will provide estimates of the cost of compliance after the rule is revised.

Domestic Site Remediation Matters

Under certain federal, state and local environmental laws, a current or previous owner or operator of a facility, including an electric generating facility, may be required to investigate and remediate releases or threatened releases of hazardous or toxic substances or petroleum products. NRG may be responsible for property damage, personal injury and investigation and remediation costs incurred by a party in connection with hazardous material releases or threatened releases. These laws impose liability without regard to whether the owner knew of or caused the presence of the hazardous substances, and the courts have interpreted liability under such laws to be strict (without fault) and joint and several. Cleanup obligations can often be triggered during the closure or decommissioning of a facility, in addition to spills during its operations. Further discussions of affected NRG sites can be found in Note 19, Environmental Matters, to the Consolidated Financial Statements.

Nuclear Waste — The federal government's program to construct a nuclear waste repository at Yucca Mountain, Nevada was discontinued in 2010. Since 1998, the U.S. DOE has been in default of the federal government's obligations to begin accepting spent nuclear fuel, or SNF, and high-level radioactive waste, or HLW, under the Nuclear Waste Policy Act. Owners of nuclear plants, including the owners of STP, had been required to enter into contracts setting out the obligations of the owners and the U.S. DOE, including the fees to be paid by the owners for the U.S. DOE's services to license a spent fuel repository. Effective May 16, 2014, the U.S. DOE stopped collecting the fees.

On February 5, 2013, STPNOC entered into a settlement agreement with the U.S. DOE for payment of damages relating to the U.S. DOE's failure to accept SNF and HLW under the Nuclear Waste Policy Act through December 31, 2013, which was extended through an addendum dated January 24, 2014, to December 31, 2016. On December 12, 2016, STPNOC received the federal government's offer of another three-year extension of payment for continued failure to accept SNF and HLW. The proposal was reviewed and accepted. There are no facilities for the reprocessing or permanent disposal of SNF currently in operation in the U.S., nor has the NRC licensed any such facilities. STPNOC currently stores all SNF generated by its nuclear generating facilities on-site. STPNOC plans to continue to assert claims against the U.S. DOE for damages relating to the U.S. DOE's failure to accept SNF and HLW.

Under the federal Low-Level Radioactive Waste Policy Act of 1980, as amended in 1985, the state of Texas is required to provide, either on its own or jointly with other states in a compact, for the disposal of all low-level radioactive waste generated within the state. Texas is currently in a compact with the state of Vermont, and the compact low-level waste facility located in Andrews County in Texas has been operational since 2012.

Water

The Company is required under the CWA to comply with intake and discharge requirements, requirements for technological controls and operating practices. As with air quality regulations, federal and state water regulations have become more stringent and imposed new requirements.

Once Through Cooling Regulation — In August 2014, EPA finalized the regulation regarding the use of water for once through cooling at existing facilities to address impingement and entrainment concerns. While NRG anticipates that more stringent requirements will be incorporated into some of its water discharge permits over the next several years as NPDES permits are renewed, the Company anticipates the cost of complying with these restrictions to be immaterial.

Effluent Limitations Guidelines — In November 2015, the EPA revised the Effluent Limitations Guidelines for Steam Electric Generating Facilities, which would have imposed more stringent requirements (as individual permits were renewed) for wastewater streams from flue gas desulfurization, fly ash, bottom ash, and flue gas mercury control. On September 18, 2017, the EPA promulgated a final rule that, among other things, postpones the compliance dates to preserve the status quo for FGD wastewater and bottom ash transport water by two years to November 2020 until the EPA completes its next rulemaking. On April 12, 2019, the United States Court of Appeals for the Fifth circuit addressed challenges to the rule brought by several environmental groups related to legacy wastewaters and coal ash leachate and remanded portions of the rule to the EPA. The Company has eliminated its estimate of the environmental capital expenditures that would have been required to comply with permits incorporating the revised guidelines. The Company will revisit these estimates after the EPA revises the rule.

Regional Environmental Developments

Burton Island Old Ash Landfill — In January 2006, NRG's Indian River Power LLC was notified that it may be a potentially responsible party with respect to Burton Island Old Ash Landfill, a historic captive landfill located at the Indian River facility. In December 2015, DNREC approved the Company's remediation design, the Company's Closure Report and the Company's Long Term Stewardship Plan. The cost of completing the work required by the approved remediation plan is consistent with amounts budgeted in early 2016 and remediation was completed in 2017. The estimated cost to comply with the Long-Term Stewardship Plan was added to the liability in 2016.

In addition to the VCP, on May 29, 2008, DNREC requested that NRG's Indian River Power LLC participate in the development and performance of a Natural Resource Damage Assessment at the Burton Island Old Ash Landfill. NRG is working with DNREC and other trustees to close out the assessment process.

NY NOx — In February 2019, NY DEC proposed a more stringent NOx regulation that depending on the outcome of the regulatory process, may result in the retirement of some of our combustion turbines in New York. In August 2019, NY DEC proposed additional revisions to this rule and solicited additional comments.

Ash Regulation in Illinois — On July 30, 2019, Illinois enacted legislation that will require the state to promulgate regulations regarding coal ash. We expect the state to promulgate the implementing regulations in March 2021 at which time regulated entities will then prepare and submit permit applications.

Significant Events

The following significant events have occurred during 2019, in addition to the Transformation Plan events, as further described within this Management's Discussion and Analysis and the Condensed Consolidated Financial Statements:

Renewable Power Purchase Agreements

During 2019, NRG began execution of its strategy to procure mid to long-term generation through power purchase agreements. As of September 30, 2019, NRG has entered into PPAs totaling approximately 1,400 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 repurchase program at an average price of $40.61 per share. The $1.0 billion share repurchase program announced in February 2019 was completed at an average price of $38.38 per share during the nine months ended September 30, 2019. Through October 31, 2019, the Company completed an additional $55 million of share repurchases at an average price of $37.62 per share under the $250 million share repurchase program announced in August 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 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 Finance Leases, for further discussion.

As a result of the financing activities discussed above, interest savings are expected to be approximately $15 million in 2019 and annualized interest savings are expected to be approximately $25 million.

Stream Energy Acquisition

On August 1, 2019, the Company completed the acquisition of Stream Energy's retail electricity and natural gas business operating in 9 states and Washington, D.C. for $329 million, including working capital and other adjustments of approximately $29 million. The acquisition increased NRG's retail portfolio by approximately 600,000 RCEs or 450,000 customers.

Trends Affecting Results of Operations and Future Business Performance

The Company’s trends are described in the Company’s 2018 Form 10-K in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations - Business Environment.

Changes in Accounting Standards

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

Consolidated Results of Operations

The following table provides selected financial information for the Company:


	Three months ended September 30,											Nine months ended September 30,
(In millions, except as otherwise noted)	2019		2018		Change			2019		2018		Change
Operating Revenues
Energy revenue^(a)	$	442	$	445	$	(3)		$	997	$	1,298	$	(301)
Capacity revenue ^(a)	152		192		(40)			461		500		(39)
Retail revenue	2,545		2,200		345			5,896		5,498		398
Mark-to-market for economic hedging activities	(210)		55		(265)			51		(31)		82

Other revenues ^(b)	67		68		(1)			221		221		—
Total operating revenues	2,996		2,960		36			7,626		7,486		140
Operating Costs and Expenses
Cost of Sales ^(c)	1,948		1,785		(163)			4,562		4,559		(3)
Mark-to-market for economic hedging activities	(146)		123		269			74		(93)		(167)
Contract and emissions credit amortization ^(c)	5		7		2			16		20		4
Operations and maintenance	263		243		(20)			794		817		23
Other cost of operations	83		80		(3)			203		209		6
Total cost of operations	2,153		2,238		85			5,649		5,512		(137)
Depreciation and amortization	91		99		8			261		331		70
Impairment losses	—		—		—			1		74		73
Selling, general and administrative	210		211		1			615		587		(28)
Reorganization costs	1		27		26			16		70		54
Development costs	1		1		—			5		9		4
Total operating costs and expenses	2,456		2,576		120			6,547		6,583		36

Gain on sale of assets	—		14		(14)			2		30		(28)
Operating Income	540		398		142			1,081		933		148
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates	29		20		9			8		26		(18)
Impairment losses on investments	(107)		(1)		(106)			(107)		(16)		(91)
Other income, net	17		19		(2)			49		12		37
Loss on debt extinguishment, net	—		(19)		19			(47)		(22)		(25)
Interest expense	(99)		(122)		23			(318)		(361)		43
Total other expense	(160)		(103)		(57)			(415)		(361)		(54)
Income from Continuing Operations Before Income Taxes	380		295		85			666		572		94
Income tax expense	6		8		2			9		19		10
Income from Continuing Operations	374		287		87			657		553		104


(Loss)/income from discontinued operations, net of income tax	(2)		(336)		334			399		(272)		671
Net Income/(Loss)	372		(49)		421			1,056		281		775
Less: Net income attributable to noncontrolling interest and redeemable interests	—		23		(23)			1		1		—
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	372	$	(72)	$	444		$	1,055	$	280	$	775
Business Metrics
Average natural gas price — Henry Hub ($/MMBtu)	$	2.23	$	2.90	(23)		%	$	2.67	$	2.90	(8)		%

(a) Includes realized gains and losses from financially settled transactions

(b) Includes unrealized trading gains and losses

Management’s discussion of the results of operations for the three months ended September 30, 2019 and 2018

Electricity Prices

The following table summarizes average on peak power prices for each of the major markets in which NRG operates for the three months ended September 30, 2019 and 2018. The average on-peak power prices increased in Texas due to higher power prices in August. The average on-peak power prices decreased in East/West due to lower gas prices, along with lower summer prices in California.


	Average on Peak Power Price ($/MWh)
	Three months ended September 30,
Region	2019		2018		Change %
Texas
ERCOT - Houston^(a)	$	120.55	$	40.34	199	%
ERCOT - North^(a)	$	120.49	$	40.23	200	%
MISO - Louisiana Hub^(b)	$	29.75	$	41.22	(28)	%
East/West
NY J/NYC^(b)	$	31.13	$	46.82	(34)	%
NEPOOL^(b)	$	29.52	$	43.53	(32)	%
COMED (PJM)^(b)	$	29.86	$	37.31	(20)	%
PJM West Hub^(b)	$	31.17	$	40.06	(22)	%
CAISO - SP15^(b)	$	37.32	$	74.86	(50)	%

^(a) Average on peak power prices based on real time settlement prices as published by the respective ISOs

^(b) Average on peak power prices based on day ahead settlement prices as published by the respective ISOs

The following table summarizes average realized power prices for each region in which NRG operates, including the impact of settled hedges, for the three months ended September 30, 2019 and 2018:


	Average Realized Power Price ($/MWh)
	Three months ended September 30,
Region	2019		2018		Change %
Texas	$	57.59	$	45.64	26	%
East/West/Other^(a)(b)	34.79		38.16		(9)	%

(a) Does not include BETM energy revenue of $5 million for 2018, which was sold in July 2018

(b) Does not include Agua Caliente energy revenue of $33 million, as it was deconsolidated in August 2018

The average realized power prices fluctuated at different rates for the three months ended September 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 three months ended September 30, 2019 and 2018:


	Three months ended September 30, 2019
			Generation
($ In millions)	Retail		Texas		East/West/Other^(a)		Subtotal		Corporate/Eliminations		Total
Energy revenue	$	—	$	773	$	237	$	1,010	$	(568)	$	442
Capacity revenue	—		—		151		151		1		152
Retail revenue	2,545		—		—		—		—		2,545
Mark-to-market for economic hedging activities	(1)		(240)		(16)		(256)		47		(210)

Other revenue	—		32		37		69		(2)		67
Operating revenue	2,544		565		409		974		(522)		2,996
Cost of fuel	(10)		(234)		(135)		(369)		2		(377)
Other cost of sales^(b)	(2,001)		(68)		(69)		(137)		567		(1,571)
Mark-to-market for economic hedging activities	192		2		(1)		1		(47)		146
Contract and emission credit amortization	—		(5)		—		(5)		—		(5)
Gross margin	$	725	$	260	$	204	$	464	$	—	$	1,189
Less: Mark-to-market for economic hedging activities, net	191		(238)		(17)		(255)		—		(64)
Less: Contract and emission credit amortization, net	—		(5)		—		(5)		—		(5)
Economic gross margin	$	534	$	503	$	221	$	724	$	—	$	1,258
Business Metrics
MWh sold (thousands)			13,422		6,812
MWh generated (thousands)			11,880		5,659
(a) Includes International, Renewables, and Generation eliminations
(b) Includes purchased energy, capacity and emissions credits


	Three months ended September 30, 2018
			Generation
($ In millions)	Retail		Texas		East/West/Other^(a)(b)		Subtotal		Corporate/Eliminations		Total
Energy revenue	$	—	$	585	$	339	$	924	$	(479)	$	445
Capacity revenue	—		1		190		191		1		192
Retail revenue	2,202		—		—		—		(2)		2,200
Mark-to-market for economic hedging activities	1		259		36		295		(241)		55

Other revenue	—		8		60		68		—		68
Operating revenue	2,203		853		625		1,478		(721)		2,960
Cost of fuel	(2)		(245)		(201)		(446)		(2)		(450)
Other cost of sales^(c)	(1,700)		(51)		(61)		(112)		477		(1,335)
Mark-to-market for economic hedging activities	(360)		—		(4)		(4)		241		(123)
Contract and emission credit amortization	—		(7)		—		(7)		—		(7)
Gross margin	$	141	$	550	$	359	$	909	$	(5)	$	1,045
Less: Mark-to-market for economic hedging activities, net	(359)		259		32		291		—		(68)
Less: Contract and emission credit amortization, net	—		(7)		—		(7)		—		(7)
Economic gross margin	$	500	$	298	$	327	$	625	$	(5)	$	1,120
Business Metrics
MWh sold (thousands)			12,797		8,035
MWh generated (thousands)			11,774		7,359
(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 three months ended September 30, 2019 and 2018:


	Three months ended September 30,
Weather Metrics	Texas	East/West/Other^(b)
2019
CDDs ^(a)	1,840	1,102
HDDs ^(a)	—	16
2018
CDDs	1,656	1,099
HDDs	1	18
10-year average
CDDs	1,672	1,021
HDDs	6	28

(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.


	Three months ended September 30,
(In millions, except as otherwise noted)	2019		2018
Retail revenue	$	2,425	$	2,084
Supply management revenue	78		55
Capacity revenue	42		63
Customer mark-to-market	(1)		1


Operating revenue^(a)	2,544		2,203
Cost of sales^(b)	(2,011)		(1,702)
Mark-to-market for economic hedging activities	192		(360)

Gross Margin	$	725	$	141
Less: Mark-to-market for economic hedging activities, net	191		(359)

Economic Gross Margin	$	534	$	500

Business Metrics
Mass electricity sales volume — GWh - Texas	13,468		12,110
Mass electricity sales volume — GWh - All other regions	2,934		2,547
C&I electricity sales volume — GWh - All regions	5,364		5,669
Natural gas sales volumes (MDth)	1,693		1,431
Average Retail Mass customer count (in thousands)	3,560		3,162
Ending Retail Mass customer count (in thousands)	3,697		3,167

(a)Includes intercompany sales of $2 million and $1 million in 2019 and 2018, respectively, representing sales from Retail to the Texas region

(b)Includes intercompany purchases of $574 million and $485 million in 2019 and 2018, respectively, inclusive of the internal transfer of large average annualized market price transactions

Retail gross margin increased $584 million and economic gross margin increased $34 million for the three months ended September 30, 2019, compared to the same period in 2018, due to:


	(In millions)
Higher gross margin from Mass driven by higher volumes from Stream Energy and other customer acquisitions	$	51
Higher gross margin due to the favorable impact from weather driven by an increase in load of 560,000 MWh in 2019 as compared to 2018	27
Higher gross margin from Mass due to higher revenues of approximately $8.75 per MWh or $122 million primarily driven by margin enhancement initiatives, partially offset by higher supply costs of approximately $8.25 per MWh or $115 million driven by an increase in power prices	7
Lower gross margin due to the unfavorable impact of purchasing incremental supply at escalated prices above $1,000/MWh during periods of extreme weather	(41)
Lower gross margin from demand response activities due to lower cleared auction prices in PJM base capacity in 2019 as compared to 2018	(10)


Increase in economic gross margin	$	34
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	550

Increase in gross margin	$	584

Generation Gross Margin and Economic Gross Margin

Generation gross margin decreased $445 million and economic gross margin increased $99 million, both of which include intercompany sales, during the three months ended September 30, 2019, compared to the same period in 2018.

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

Texas Region


	(In millions)
Higher gross margin due to a 26% increase in average realized prices due to heat rate expansion, partially offset by the intersegment transactions at annual average power prices	$	140
Higher gross margin due to Gregory return to service	35
Higher gross margin due to a 36% increase in gas generation volume attributed to spark spread expansion, partially offset by increased forced outages at WA Parish	16
Higher gross margin from commercial optimization activities	11
Higher gross margin due to margin enhancement initiatives from reduced fuel supply costs	4
Other	(1)
Increase in economic gross margin	$	205
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(497)
Decrease in contract and emission credit amortization	2
Decrease in gross margin	$	(290)

East/West/Other


	(In millions)
Lower gross margin primarily due to the sale of BETM and Keystone and Conemaugh in the third quarter of 2018 and the retirement of Encina in December 2018	$	(35)
Lower gross margin due to the deconsolidations of Agua Caliente in August 2018	(31)
Lower gross margin due to an 18% decrease in realized capacity in New England, a 17% decrease in New York and a 7% decrease in PJM	(27)
Lower gross margin driven by a 14% decrease in economic generation volumes primarily due to dark spread contractions in the northeast along with forced outages in 2019	(19)
Lower gross margin from commercial optimization activities	(16)
Higher gross margin due to lower supply costs coupled with an increase in load contract volumes	13
Higher gross margin due to insurance proceeds from outages in 2019	8
Higher gross margin primarily due to an increase in average realized prices primarily due to a 10% increase in the West	5
Other	(4)

Decrease 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	(49)

Decrease in gross margin	$	(155)

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 $4 million during the three months ended September 30, 2019, compared to the same period in 2018.

The breakdown of gains and losses included in operating revenues and operating costs and expenses by region was as follows:


	Three months ended September 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 losses on settled positions related to economic hedges	$	3	$	409	$	33	$	(389)	$	56

Net unrealized (losses) on open positions related to economic hedges	(4)		(649)		(49)		436		(266)
Total mark-to-market (losses) in operating revenues	$	(1)	$	(240)	$	(16)	$	47	$	(210)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(565)	$	2	$	—	$	389	$	(174)
Reversal of acquired gain positions related to economic hedges	(3)		—		—		—		(3)
Net unrealized gains/(losses) on open positions related to economic hedges	760		—		(1)		(436)		323
Total mark-to-market gains/(losses) in operating costs and expenses	$	192	$	2	$	(1)	$	(47)	$	146

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


	Three months ended September 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 losses on settled positions related to economic hedges	$	—	$	175	$	5	$	(179)	$	1

Net unrealized gains on open positions related to economic hedges	1		84		31		(62)		54
Total mark-to-market gains in operating revenues	$	1	$	259	$	36	$	(241)	$	55
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges	$	(260)	$	(1)	$	(3)	$	179	$	(85)
Reversal of acquired gain positions related to economic hedges	(10)		—		—		—		(10)
Net unrealized (losses)/gains on open positions related to economic hedges	(90)		1		(1)		62		(28)
Total mark-to-market (losses) in operating costs and expenses	$	(360)	$	—	$	(4)	$	241	$	(123)

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

Mark-to-market results consist of unrealized gains and losses on contracts that are not yet settled. The settlement of these transactions is reflected in the same revenue or cost caption as the items being hedged.

For the three months ended September 30, 2019, the $210 million loss in operating revenues from economic hedge positions was driven primarily by a decrease in the value of open positions as a result of ERCOT heat rate expansion, partially offset by the reversal of previously recognized unrealized losses on contracts that settled during the period. The $146 million gain in operating costs and expenses from economic hedge positions was driven primarily by an increase in the value of open positions as a result of ERCOT heat rate expansion, partially offset by the reversal of previously recognized unrealized gains on contracts that settled during the period.

For the three months ended September 30, 2018, the $55 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 a decrease in New York capacity prices and outer year natural gas prices. The $123 million loss in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized gains on contracts that settled during the period and acquired positions, as well as a decrease in value of open positions as a result of lower near-term natural gas prices.

In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the three months ended September 30, 2019 and 2018. The realized and unrealized financial and physical trading results are included in operating revenue within the Generation segment. The Company's trading activities are subject to limits based on the Company's Risk Management Policy.


	Three months ended September 30,
(In millions)	2019		2018
Trading gains/(losses)
Realized	$	13	$	23
Unrealized	(4)		4
Total trading gains	$	9	$	27

Operations and Maintenance Expense

Operations and maintenance expense are comprised of the following:


			Generation						Corporate		Eliminations
	Retail		Texas		East/West/Other								Total
	(In millions)
Three months ended September 30, 2019	$	64	$	102	$	96	$	2	$	(1)	$	263
Three months ended September 30, 2018	$	55	$	91	$	97	$	1	$	(1)	$	243

(a) Includes International, Renewables, and Generation eliminations

Operations and maintenance expenses increased by $20 million for the three months ended September 30, 2019, compared to the same period in 2018, due to the following:


	(In millions)
Increase in outages primarily due to forced outages at WA Parish	$	11
Increase primarily related to the lease of Cottonwood from February 4, 2019	10
Increase due to XOOM and Stream Energy acquisitions in June 2018 and August 2019, respectively	5
Increase in costs due to Gregory return to service	4
Increase for margin enhancement initiatives	3
Decrease in variable chemical costs due to reduction in East generation volumes	(13)
Decrease due to retirement of Encina and the sale of Keystone and Conemaugh	(3)
Decrease due to payments in settlement of certain legal matters during 2018	(3)
Other	6
Increase in operations and maintenance expense	$	20

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 September 30, 2019	$	39	$	16	$	28	$	83
Three months ended September 30, 2018	$	34	$	26	$	20	$	80

Depreciation and Amortization

Depreciation and amortization decreased by $8 million for the three months ended September 30, 2019, compared to the three months ended September 30, 2018, driven primarily by the deconsolidation of Agua Caliente in August 2018 and the sale of Cottonwood in February 2019, partially offset by the acquisition of Stream Energy in August 2019.

Selling, General and Administrative

Selling, general and administrative expenses are comprised of the following:


	Retail		Generation		Corporate		Total
	(In millions)
Three months ended September 30, 2019	$	161	$	43	$	6	$	210
Three months ended September 30, 2018	144		55		12		211

Selling, general and administrative expenses decreased by $1 million for the three months ended September 30, 2019, compared to the same period in 2018, due to the following:


	(In millions)
Decrease due to a legal matter in 2018	$	(10)
Decrease due to the sale of BETM in 2018	(4)

Increase in selling expense due to the acquisition of XOOM in June 2018 and Stream Energy in August 2019, partially offset by fees incurred in the acquisition of businesses	6
Increase in bad debt expense primarily due to increased customer attrition and higher revenue rates	6
Increase in selling and marketing expenses for margin enhancement initiatives	6


Other	(5)
Decrease in selling, general and administrative expenses	$	(1)

Reorganization Costs

Reorganization costs, primarily related to employee severance and contract cancellation costs, decreased by $26 million for the three months ended September 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

A gain on sale of assets of $14 million was recorded for the three months ended September 30, 2018, primarily driven by the sale of BETM.

Equity in earnings of unconsolidated affiliates

Equity in earnings of unconsolidated affiliates increased by $9 million for the three months ended September 30, 2019, compared to the three months ended September 30, 2018. The increase is due to higher earnings at Ivanpah and Agua Caliente, associated with favorable weather and operational improvements and two additional months of earnings in the current period, respectively, partially offset by lower fuel costs at Watson in 2018.

Impairment losses on investments

Impairment losses on investments of $107 million was recorded for the three months ended September 30, 2019, primarily related to the impairment of Petra Nova as further discussed in Note 11, Investments Accounted for Using the Equity Method and Variable Interest Entities, or VIEs.

Loss on Debt Extinguishment

A loss on debt extinguishment of $19 million was recorded during the three months ended September 30, 2018, primarily driven by the repurchase of Senior Notes at a price above par value, combined with the write-off of unamortized debt issuance costs.

Interest Expense

Interest expense decreased by $23 million for the three months ended September 30, 2019, compared to the same period in 2018, due to the following:


	(In millions)
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	$	(24)
Decrease related to the deconsolidation of Agua Caliente in 2018	(4)
Other	5
Decrease in interest expense	$	(23)

Income Tax Expense

For the three months ended September 30, 2019, income tax expense of $6 million was recorded on pre-tax income of $380 million. For the same period in 2018, income tax expense of $8 million was recorded on pre-tax income of $295 million. The effective tax rate was 1.6% and 2.7% for the three months ended September 30, 2019 and 2018, respectively.

For the three months ended September 30, 2019 and 2018, NRG's overall effective tax rates were lower than the statutory rate of 21%, primarily due to the tax benefit for the change in valuation allowance, partially offset by current state tax expense.

Income from Discontinued Operations, Net of Income Tax


	Three months ended September 30,
(In millions)	2019		2018		Change
South Central Portfolio	$	(1)	$	16	$	(17)
Yield Renewables Platform & Carlsbad	(1)		(352)		351

(Loss)/Income from discontinued operations, net of tax	$	(2)	$	(336)	$	334

For the three months ended September 30, 2019, NRG recorded loss from discontinued operations, net of income tax of $2 million, a decrease of $334 million from loss of $336 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 $0 million for the three months ended September 30, 2019, compared to $23 million for three months ended September 30, 2018. For the three months ended September 30, 2018, NRG Yield, Inc.'s, Agua Caliente, and Ivanpah's share of net income was partially offset by the net losses allocated to tax equity investors in tax equity arrangements using the hypothetical liquidation at book value, or HLBV, method. As a result of the disposition of NRG Yield Inc. and its Renewables Platform, as well as the deconsolidation of the Ivanpah and Agua Caliente projects, the Company does not anticipate material NCI in the future.

Management’s discussion of the results of operations for the nine months ended September 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 nine months ended September 30, 2019 and 2018. The average on-peak power prices increased in Texas primarily driven by higher power prices in August. The average on-peak power prices decreased in East/West due to lower gas prices, along with lower winter prices in the northeast and lower summer prices in California.


	Average on Peak Power Price ($/MWh)
	Nine months ended September 30,
Region	2019		2018		Change %
Texas
ERCOT - Houston ^(a)	$	60.21	$	36.10	67	%
ERCOT - North^(a)	59.55		35.60		67	%
MISO - Louisiana Hub^(b)	32.00		43.88		(27)	%
East/West
NY J/NYC^(b)	35.27		48.40		(27)	%
NEPOOL^(b)	34.69		48.56		(29)	%
COMED (PJM)^(b)	28.91		34.13		(15)	%
PJM West Hub^(b)	31.17		42.41		(27)	%

CAISO - SP15^(b)	37.01		46.02		(20)	%

(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 nine months ended September 30, 2019 and 2018:


	Average Realized Power Price ($/MWh)
	Nine months ended September 30,
Region	2019		2018		Change %
Texas	$	48.24	$	38.93	24	%
East/West/Other^{(a) (b)}	35.75		38.89		(8)	%

(a) Does not include BETM energy revenue of $37 million for 2018

(b) Does not include Ivanpah or Agua Caliente energy revenue of $127 million, as they were deconsolidated in April 2018 and August 2018, respectively

The average realized power prices fluctuated at different rates for the nine months ended September 30, 2019 as compared to the same period in 2018 due to two factors:

•The Company's multi-year hedging program

Gross Margin

Economic Gross Margin

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 nine months ended September 30, 2019 and 2018:


	Nine months ended September 30, 2019
			Generation
($ In millions)	Retail		Texas		East/West/Other^(a)		Subtotal		Corporate/Eliminations		Total
Energy revenue	$	—	$	1,628	$	578	$	2,206	$	(1,209)	$	997
Capacity revenue	—		—		460		460		1		461
Retail revenue	5,898		—		—		—		(2)		5,896
Mark-to-market for economic hedging activities	1		233		40		273		(223)		51

Other revenue	—		77		148		225		(4)		221
Operating revenue	5,899		1,938		1,226		3,164		(1,437)		7,626
Cost of fuel	(61)		(586)		(300)		(886)		5		(942)
Other cost of sales ^(b)	(4,473)		(137)		(217)		(354)		1,207		(3,620)
Mark-to-market for economic hedging activities	(302)		4		1		5		223		(74)
Contract and emission credit amortization	—		(16)		—		(16)		—		(16)
Gross margin	$	1,063	$	1,203	$	710	$	1,913	$	(2)	$	2,974
Less: Mark-to-market for economic hedging activities, net	(301)		237		41		278		—		(23)
Less: Contract and emission credit amortization, net	—		(16)		—		(16)		—		(16)
Economic gross margin	$	1,364	$	982	$	669	$	1,651	$	(2)	$	3,013
Business Metrics
MWh sold (thousands)			33,751		16,160
MWh generated (thousands)			30,159		12,607
(a) Includes International, Renewables, and Generation eliminations
(b) Includes purchased energy, capacity and emissions credits


	Nine months ended September 30, 2018
			Generation
($ In millions)	Retail		Texas		East/West/Other^(a)(b)		Subtotal		Corporate/Eliminations		Total
Energy revenue	$	—	$	1,251	$	937	$	2,188	$	(890)	$	1,298
Capacity revenue	—		1		498		499		1		500
Retail revenue	5,502		—		—		—		(4)		5,498
Mark-to-market for economic hedging activities	(5)		(14)		9		(5)		(21)		(31)

Other revenue	—		72		162		234		(13)		221
Operating revenue	5,497		1,310		1,606		2,916		(927)		7,486
Cost of fuel	(13)		(556)		(440)		(996)		(3)		(1,012)
Other cost of sales ^(b)	(4,117)		(113)		(215)		(328)		898		(3,547)
Mark-to-market for economic hedging activities	86		(5)		(9)		(14)		21		93
Contract and emission credit amortization	—		(19)		(1)		(20)		—		(20)
Gross margin	$	1,453	$	617	$	941	$	1,558	$	(11)	$	3,000
Less: Mark-to-market for economic hedging activities, net	81		(19)		—		(19)		—		62
Less: Contract and emission credit amortization, net	—		(19)		(1)		(20)		—		(20)
Economic gross margin	$	1,372	$	655	$	942	$	1,597	$	(11)	$	2,958
Business Metrics
MWh sold (thousands)			32,137		20,642
MWh generated (thousands)			29,078		17,316
(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 nine months ended September 30, 2019 and 2018:


	Nine months ended September 30,
Weather Metrics	Texas	East/West/Other^(b)
2019
CDDs ^(a)	2,848	1,593
HDDs ^(a)	1,111	1,912
2018
CDDs	2,902	1,672
HDDs	1,059	1,862
10-year average
CDDs	2,787	1,550
HDDs	1,037	1,878

(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.


	Nine months ended September 30,
(In millions, except as otherwise noted)	2019		2018
Retail revenue	$	5,644	$	5,215
Supply management revenue	162		130
Capacity revenue	92		157
Customer mark-to-market	1		(5)


Operating revenue^(a)	5,899		5,497
Cost of sales ^(b)	(4,534)		(4,130)
Mark-to-market for economic hedging activities	(302)		86

Gross Margin	$	1,063	$	1,453
Less: Mark-to-market for economic hedging activities, net	(301)		81

Economic Gross Margin	$	1,364	$	1,372

Business Metrics
Mass electricity sales volume — GWh - Texas	30,588		29,847
Mass electricity sales volume — GWh - All other regions	7,341		5,828
C&I electricity sales volume — GWh - All regions	15,203		16,099
Natural gas sales volumes (MDth)	15,293		4,850
Average Retail Mass customer count (in thousands)	3,398		3,001
Ending Retail Mass customer count (in thousands)	3,697		3,167

(a)Includes intercompany sales of $6 million and $7 million in 2019 and 2018, respectively, representing sales from Retail to the Texas region

(b)Includes intercompany purchases of $1,250 million and $900 million in 2019 and 2018, respectively, inclusive of the internal transfer of large average annualized market price transactions

Retail gross margin decreased $390 million and economic gross margin decreased $8 million for the nine months ended September 30, 2019, compared to the same period in 2018, due to:


	(In millions)
Lower gross margin from demand response activities due to lower auction clearing prices and fewer MW's sold primarily in PJM in 2019 as compared to 2018	$	(37)
Lower gross margin from weather driven by a decrease in load of 385,000 MWh partially offset by the impact of selling back excess supply in 2019 as compared to 2018	(25)
Lower gross margin due to the unfavorable impact of purchasing incremental supply at escalated prices above $1,000/MWh during periods of extreme weather	(24)
Lower gross margin from Mass due to higher supply costs driven by an increase in power prices of approximately $7.25 per MWh or $249 million, partially offset by higher revenues primarily driven by margin enhancement initiatives of approximately $6.75 per MWh or $234 million	(15)

Higher gross margin driven by higher volume from XOOM and Stream acquisitions	93
Decrease in economic gross margin	$	(8)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(382)
Decrease in gross margin	$	(390)

Generation Gross Margin and Economic Gross Margin

Generation gross margin increased $355 million and economic gross margin increased $54 million, both of which include intercompany sales, during the nine months ended September 30, 2019, compared to the same period in 2018.

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

Texas Region


	(In millions)
Higher gross margin due to a 24% increase in average realized prices due to heat rate expansion	$	229
Higher gross margin due to a 2% increase in generation volumes driven by a planned outage at STP and a forced outage at T.H.Wharton in 2018, partially offset by current year forced outages at coal facilities	51
Higher gross margin due to Gregory return to service	35
Higher gross margin from commercial optimization activities	20
Higher gross margin due to margin enhancement initiatives from reduced fuel supply costs	13
Lower gross margin from lower sales of NOx emission credits	(22)
Other	1
Increase in economic gross margin	$	327
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	256
Increase in contract and emission credit amortization	3
Increase in gross margin	$	586

East/West/Other


	(In millions)
Lower gross margin due to Ivanpah and Agua deconsolidations in April 2018 and August 2018, respectively	$	(118)
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	(111)
Lower gross margin due to 17% decrease in economic generation volumes due to dark spread and spark spread contractions and outages in 2019	(54)
Lower gross margin driven by a decrease in New York realized capacity	(30)
Lower gross margin from commercial optimization activities	(14)
Lower gross margin due to insurance proceeds from outages in 2018, partially offset by business interruption proceeds	(6)
Higher gross margin due to a 16% increase in PJM capacity prices	29
Higher gross margin due to lower supply costs coupled with an increase in load contract volumes	16
Higher gross margin mainly due to 7% increase in weighted average realized prices, primarily at Midwest Generation	15

Decrease in economic gross margin	$	(273)
Increase to mark-to-market for economic hedges primarily due to net unrealized gains/losses on open positions related to economic hedges	42
Decrease in gross margin	$	(231)

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 $85 million during the nine months ended September 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:


	Nine months ended September 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 losses on settled positions related to economic hedges	$	2	$	256	$	27	$	(237)	$	48

Net unrealized (losses)/gains on open positions related to economic hedges	(1)		(23)		13		14		3
Total mark-to-market gains in operating revenues	$	1	$	233	$	40	$	(223)	$	51
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(381)	$	6	$	2	$	237	$	(136)
Reversal of acquired gain positions related to economic hedges	(4)		—		—		—		(4)
Net unrealized gains/(losses) on open positions related to economic hedges	83		(2)		(1)		(14)		66
Total mark-to-market (losses)/gains in operating costs and expenses	$	(302)	$	4	$	1	$	223	$	(74)

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


	Nine months ended September 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)/losses on settled positions related to economic hedges	$	(1)	$	87	$	(1)	$	(148)	$	(63)

Net unrealized (losses)/gains on open positions related to economic hedges	(4)		(101)		10		127		32
Total mark-to-market (losses)/gains in operating revenues	$	(5)	$	(14)	$	9	$	(21)	$	(31)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges	$	(156)	$	(3)	$	(11)	$	148	$	(22)
Reversal of acquired gain positions related to economic hedges	(11)		—		—		—		(11)
Net unrealized gains/(losses) on open positions related to economic hedges	253		(2)		2		(127)		126
Total mark-to-market gains/(losses) in operating costs and expenses	$	86	$	(5)	$	(9)	$	21	$	93

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

For the nine months ended September 30, 2019, the $51 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 a decrease in PJM power prices, partially offset by a decrease in value of open positions as a result of ERCOT heat rate expansion. The $74 million loss in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period, partially offset by an increase in value of open positions as a result of ERCOT heat rate expansion.

For the nine months ended September 30, 2018, the $31 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, partially offset by an increase in the value of open positions as a result of decreases in outer year natural gas prices. The $93 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, partially offset by the reversal of previously recognized unrealized gains on contracts that settled during the period and acquired deals.

In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the nine months ended September 30, 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.


	Nine months ended September 30,
(In millions)	2019		2018
Trading gains
Realized	$	44	$	63
Unrealized	15		17
Total trading gains	$	59	$	80

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)
Nine months ended September 30, 2019	$	172	$	330		$	288		$	6	$	(2)	$	794
Nine months ended September 30, 2018	$	151	$	335		$	333		$	2	$	(4)	817

(a) Includes International, Renewables, and Generation eliminations

Operations and maintenance expense decreased by $23 million for the nine months ended September 30, 2019, compared to the same period in 2018, due to the following:


	(In millions)
Decrease due to the final settlement of the asbestos liability and resulting reduction of the accrual for Midwest Generation	$	(27)
Decrease due to the deconsolidations of Ivanpah and Agua Caliente in 2018	(20)
Decrease in variable chemical costs due to reduction in East generation volumes	(14)
Decrease due to payments in settlement of certain legal matters during 2018	(13)
Decrease due to retirement of Encina and the sale of Keystone and Conemaugh	(12)
Decrease due to planned STP outages in 2018, offset by both planned and forced outages in 2019	(4)
Increase primarily related to the lease of Cottonwood from February 4, 2019	27
Increase in investments in Texas plants in preparation for summer operations	21
Increase due to XOOM and Stream Energy acquisitions in June 2018 and August 2019, respectively	13

Other	6
Decrease in operations and maintenance expense	$	(23)

Other Cost of Operations

Other Cost of operations are comprised of the following:


			Generation
	Retail		Texas		East/West/Other		Total
	(In millions)
Nine months ended September 30, 2019	$	92	$	48	$	63	$	203
Nine months ended September 30, 2018	$	85	$	62	$	62	$	209

Other cost of operations decreased by $6 million for the nine months ended September 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 due to deconsolidations of Ivanpah and Agua Caliente in 2018	(5)
Decrease in ARO accretion expense due to prior year write-off of S.R. Bertron, as well as a decrease in accretion of Norwalk and Jewett, offset by increased Encina decommissioning in 2019	(4)
Increase in taxes due to the Stream Energy acquisition and higher revenue from increased rates and customer counts	8

Decrease in other cost of operations	$	(6)

Depreciation and Amortization

Depreciation and amortization decreased by $70 million for the nine months ended September 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 and the sale of Cottonwood in February 2019, partially offset by the acquisitions of Stream Energy and XOOM.

Selling, General and Administrative

Selling, general and administrative expenses comprised of the following:


	Retail		Generation		Corporate		Total
	(In millions)
Nine months ended September 30, 2019	$	438	$	160	$	17	$	615
Nine months ended September 30, 2018	385		164		38		587

Selling, general and administrative expenses increased by $28 million for the nine months ended September 30, 2019, compared to the same period in 2018, due to the following:


	(In millions)
Increase in selling and marketing expenses for margin enhancement initiatives	$	40
Increase in bad debt expense primarily due to increased customer attrition and higher revenue rates	28
Increase in selling expense due to the acquisition of XOOM in June 2018 and Stream Energy in August 2019	21

Decrease in general and administrative expense from cost efficiencies as a result of the Transformation Plan	(25)
Decrease due to the sale of BETM in 2018	(19)
Decrease due to a legal matter in 2018	(10)
Decrease related to fees incurred in the acquisition of businesses	(6)
Other	(1)

Increase in selling, general and administrative expenses	$	28

Reorganization Costs

Reorganization costs, primarily related to employee severance and contract cancellation costs, decreased by $54 million for the nine months ended September 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 nine months ended September 30, 2018 consisted primarily of the gain on the sale of BETM and Canal 3.

Equity in Earnings of Unconsolidated Affiliates

Equity in earnings of unconsolidated affiliates decreased by $18 million for the nine months ended September 30, 2019, compared to the nine months ended September 30, 2018, primarily driven by five months of losses for Ivanpah in 2019 as a result of the deconsolidations in 2018.

Impairment losses on investments

Impairment losses on investments of $107 million was recorded for the nine months ended September 30, 2019, primarily related to the impairment of Petra Nova as further discussed in Note 11, Investments Accounted for Using the Equity Method and Variable Interest Entities, or VIEs

Other Income, Net

Other income increased by $37 million for the nine months ended September 30, 2019, compared to the same period in 2018, driven primarily by the loss on deconsolidation of Ivanpah in 2018.

Loss on Debt Extinguishment

A loss on debt extinguishment of $47 million was recorded during the nine months ended September 30, 2019, driven by the redemption of the 2024 Senior Notes and the repayment of the 2023 Term Loan Facility. For the same period in 2018, a loss on debt extinguishment of $22 million was recorded, primarily driven by the repurchase of Senior Notes at a price above par value, combined with the write-off of unamortized debt issuance costs.

Interest Expense

Interest expense decreased by $43 million for the nine months ended September 30, 2019, compared to the same period in 2018, due to the following:


	(In millions)
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	$	(54)
Decrease related to the deconsolidations of Ivanpah and Agua Caliente in 2018	(27)
Decrease related to the termination of in-the-money interest rate swaps	(25)
Increase in derivative interest expense due to the termination of interest rate swaps in 2019	52
Increase due to California property tax indemnification accretion	6
Increase due to the amortization of the Convertible Note premium	5

Decrease in interest expense	$	(43)

Income Tax Expense

For the nine months ended September 30, 2019, income tax expense of $9 million was recorded on pre-tax income of $666 million. For the same period in 2018, income tax expense of $19 million was recorded on a pre-tax income of $572 million. The effective tax rate was 1.4% and 3.3% for the nine months ended September 30, 2019 and 2018, respectively.

For the nine months ended September 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


	Nine months ended September 30,
(In millions)	2019		2018		Change
South Central Portfolio	$	35	$	48	$	(13)
Yield Renewables Platform & Carlsbad	362		(295)		657
GenOn	2		(25)		27
Income/(Loss) from discontinued operations, net of tax	$	399	$	(272)	$	671

For the nine months ended September 30, 2019, NRG recorded income from discontinued operations, net of income tax of $399 million, an increase of $671 million from loss of $272 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 nine months ended September 30, 2019, compared to $1 million for the nine months ended September 30, 2018. For the nine months ended September 30, 2018, the net income primarily reflects NRG Yield, Inc.'s and Agua Caliente's share of net income partially offset by the net losses allocated to tax equity investors in tax equity arrangements using the hypothetical liquidation at book value, or HLBV, method and Ivanpah's share of net losses. As a result of the disposition of NRG Yield Inc. and its Renewables Platform, as well as the deconsolidation of the Ivanpah and Agua Caliente projects, the Company does not anticipate material NCI in the future.

Liquidity and Capital Resources

Liquidity Position

As of September 30, 2019 and December 31, 2018, NRG's total liquidity, excluding funds deposited by counterparties, of approximately $1.5 billion and $2.0 billion, respectively, was comprised of the following:


(In millions)	September 30, 2019		December 31, 2018
Cash and cash equivalents	$	243	$	563
Restricted cash - operating	2		6
Restricted cash - reserves^(a)	2		11
Total	247		580
Total credit facility availability	1,297		1,397
Total liquidity, excluding funds deposited by counterparties	$	1,544	$	1,977

^(a) Includes reserves primarily for debt service, performance obligations, and capital expenditures

For the nine months ended September 30, 2019, total liquidity, excluding funds deposited by counterparties, decreased by $433 million. Changes in cash and cash equivalent balances are further discussed hereinafter under the heading Cash Flow Discussion. Cash and cash equivalents at September 30, 2019 were predominantly held in money market funds invested in treasury securities, treasury repurchase agreements or government agency debt.

Management believes that the Company's liquidity position and cash flows from operations will be adequate to finance operating and maintenance capital expenditures, to fund dividends to NRG's common stockholders, and to fund other liquidity commitments. Management continues to regularly monitor the Company's ability to finance the needs of its operating, financing and investing activity within the dictates of prudent balance sheet management.

Sources of Liquidity

The principal sources of liquidity for NRG's future operating and maintenance capital expenditures are expected to be derived from cash on hand, cash flows from operations, and financing arrangements, as described in Note 10, Debt and Finance Leases, to this Form 10-Q. The Company's financing arrangements consist mainly of the Senior Notes, the Senior Credit Facility, and project-related financings.

The table below represents the approximate cash proceeds received from sale transactions and related financings, net of working capital and other adjustments, completed by the Company during the nine months ended September 30, 2019:


Sales	Cash Proceeds (in millions)
South Central Portfolio	$	962
Carlsbad	396
Guam	8
Other	14
Sales transactions during the nine months ended September 30, 2019	$	1,380

Issuance of 2029 Senior Notes

Issuance of 2024 and 2029 Senior Secured Notes

Revolving Credit Facility Modification

First Lien Structure

NRG has granted first liens to certain counterparties on a substantial portion of the Company's assets, excluding NRG's assets that have project-level financing and the assets of certain non-guarantor subsidiaries, to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or MWh equivalents. To the extent that the underlying hedge positions for a counterparty are out-of-the-money to NRG, the counterparty would have a claim under the first lien program. The first lien program limits the volume that can be hedged, not the value of underlying out-of-the-money positions. The first lien program does not require NRG to post collateral above any threshold amount of exposure. Within the first lien structure, the Company can hedge up to 80% of its coal and nuclear capacity, and 10% of its other assets, with these counterparties for the first 60 months and then declining thereafter. Net exposure to a counterparty on all trades must be positively correlated to the price of the relevant commodity for the first lien to be available to that counterparty. The first lien structure is not subject to unwind or termination upon a ratings downgrade of a counterparty and has no stated maturity date.

The Company's first lien counterparties may have a claim on its assets to the extent market prices exceed the hedged prices. As of September 30, 2019, all hedges under the first liens were in-the-money on a counterparty aggregate basis.

The following table summarizes the amount of MW hedged against the Company's coal and nuclear assets and as a percentage relative to the Company's coal and nuclear capacity under the first lien structure as of September 30, 2019:


Equivalent Net Sales Secured by First Lien Structure^(a)	2019	2020	2021	2022	2023
In MW	714	717	655	725	786
As a percentage of total net coal and nuclear capacity^(b)	16%	16%	14%	16%	17%

(a)Equivalent Net Sales include natural gas swaps converted using a weighted average heat rate by region

(b)Net coal and nuclear capacity represents 80% of the Company’s total coal and nuclear assets eligible under the first lien, which excludes coal assets acquired with Midwest Generation and NRG's assets that have project level financing

Uses of Liquidity

The Company's requirements for liquidity and capital resources, other than for operating its facilities, can generally be categorized by the following: (i) commercial operations activities; (ii) debt service obligations; (iii) capital expenditures, including repowering, development, and environmental; (iv) allocations in connection with acquisition opportunities, debt repayments, share repurchases, return of capital and dividend payments to stockholders; and (v) costs necessary to execute the Transformation Plan.

Commercial Operations

The Company's commercial operations activities require a significant amount of liquidity and capital resources. These liquidity requirements are primarily driven by: (i) margin and collateral posted with counterparties; (ii) margin and collateral required to participate in physical markets and commodity exchanges; (iii) timing of disbursements and receipts (i.e. buying fuel before receiving energy revenues); and (iv) initial collateral for large structured transactions. As of September 30, 2019, the Company had total cash collateral outstanding of $164 million and $996 million outstanding in letters of credit to third parties primarily to support its commercial activities for both wholesale and retail transactions. As of September 30, 2019, total funds deposited by counterparties was $31 million in cash and $81 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, growth investments, and environmental for the nine months ended September 30, 2019, and the estimated capital expenditures forecast for the remainder of 2019.


	Maintenance		Environmental		Growth Investments^(c)		Total
	(In millions)
Retail	$	15	$	—	$	34	$	49
Generation
Texas	77		—		—		77
East/West/Other^(a)	33		2		—		35
Corporate	6		—		16		22
Total cash capital expenditures for the nine months ended September 30, 2019	131		2		50		183


Stream acquisition	—		—		321		321
Other investments	—		—		165		165
Total capital expenditures and investments, net of financings	131		2		536		669




Estimated capital expenditures for the remainder of 2019^(b)	$	24	$	1	$	17	$	42

(a) Includes International, Renewables and Cottonwood

(b) Growth investments includes $17 million of costs to achieve associated with the Transformation Plan

Growth Investments Capital Expenditures

For the nine months ended September 30, 2019, the Company's growth investments capital expenditures included $39 million for cost to achieve projects associated with the Transformation Plan and $11 million for the Company's other growth projects.

Environmental Capital Expenditures

NRG estimates that environmental capital expenditures from 2019 through 2023 required to comply with environmental laws will be approximately $39 million, which does not yet include amounts relating to environmental capital expenditures that may result from the regulations being reconsidered described in Note 19, Environmental Matters.

Common Stock Dividends

Dividends of $0.09 per share were paid on the Company's common stock during the nine months ended September 30, 2019. On October 17, 2019, NRG declared a quarterly dividend on the Company's common stock of $0.03 per share, payable November 15, 2019, to stockholders of record as of November 1, 2019, representing $0.12 per share on an annualized basis.

The Company's common stock dividends are subject to available capital, market conditions, and compliance with associated laws and regulations. Beginning in the first quarter of 2020, NRG will increase the annual dividend to $1.20 per share and expects to target an annual dividend growth rate of 7-9% per share.

In addition, the Company has adopted a long-term capital allocation policy that will target allocating 50% of cash available for allocation generated each year to growth investments and 50% to be returned to shareholders. The return of capital to shareholders is expected to be completed through the increased dividend discussed above, supplemented by share repurchases.

Share Repurchases

Senior Note Repurchases

2023 Term Loan Facility Repayment

On May 28, 2019, the Company repaid its $1.7 billion 2023 Term Loan Facility using the proceeds from the issuance of the Senior Secured First Lien Notes, as well as cash on hand. The Company recorded a loss on debt extinguishment of $17 million, which included the write-off of previously deferred debt issuance costs of $13 million. As a result of the repayment of the outstanding 2023 Term Loan Facility, the Company terminated the related interest rate swap agreements, which were in-the-money, and received $25 million that was recorded as a reduction to interest expense.

Stream Energy Acquisition

Petra Nova Debt Repayment

During the third quarter of 2019, NRG contributed approximately $95 million in cash to Petra Nova and posted a $12 million letter of credit to cover certain project debt reserve requirements. The cash portion of the contribution was used by Petra Nova to prepay a significant portion of the project debt. As a result, the financial guarantees previously provided by NRG were canceled and the remaining project debt has now become non-recourse to NRG.

Balance Sheet Target Ratio

NRG revised its credit metrics target in order to further strengthen its balance sheet by reducing leverage. During the second quarter of 2019, the Company reduced total outstanding debt by $594 million with the repayment of the 2023 Term Loan facility.

Cash Flow Discussion

The following table reflects the changes in cash flows for the comparative nine month periods:


	Nine months ended September 30,
	2019		2018		Change
	(In millions)
Net Cash Provided by Operating Activities	$	861	$	1,067	$	(206)
Net Cash Provided/(Used) by Investing Activities	614		(59)		673
Net Cash Used by Financing Activities	(1,762)		(651)		(1,111)

Net Cash Provided by Operating Activities

Changes to net cash provided by operating activities were driven by:


	(In millions)
Change in cash provided by discontinued operations	$	(388)
Decrease in accounts payable primarily due to transformation plan benefits achieved in 2018	(124)
Decrease in other working capital	(63)
Increase in accounts receivable primarily due to increase in revenues	(54)
Changes in cash collateral in support of risk management activities due to change in commodity prices	159
Increase in operating income adjusted for other non-cash items	139
GenOn settlement in July 2018	125



	$	(206)

Net Cash Provided/(Used) by Investing Activities

Changes to net cash provided/(used) by investing activities were driven by:


	(In millions)
Decrease in cash used by discontinued operations	$	703
Cash removed due to deconsolidation of Agua Caliente and Ivanpah projects	268
Decrease in capital expenditures	160
Increase in proceeds received from sales of nuclear decommissioning trust fund securities, net of purchases	27
Decrease in proceeds from sale of assets and discontinued operations	(262)
Increase in cash paid for acquisitions primarily due to Stream Energy acquisition in 2019	(139)
Change in investments in unconsolidated affiliates	(55)
Increase in contributions to discontinued operations	(21)
Other	(8)
	$	673

Net Cash Used by Financing Activities

Changes to net cash used by financing activities were driven by:


	(In millions)
Increase in payments of short and long-term debt	$	(1,517)
Change in cash provided by discontinued operations	(360)
Increase in payments for treasury stock	(286)
Increase in payments of debt extinguishment costs and deferred issuance costs	(39)
Increase in proceeds from issuance of short and long-term debt	1,053
Decrease in notes issued to affiliate	26
Decrease in distributions to noncontrolling interests from subsidiaries	16
Other	(4)


	$	(1,111)

NOLs, Deferred Tax Assets and Uncertain Tax Position Implications, under ASC 740

For the nine months ended September 30, 2019, the Company had domestic pre-tax book income of $655 million and foreign pre-tax book income of $11 million. As of December 31, 2018, the Company had cumulative domestic Federal NOL carryforwards of $10.7 billion, which will begin expiring in 2031, and cumulative state NOL carryforwards of $5.6 billion for financial statement purposes. NRG also has cumulative foreign NOL carryforwards of $213 million, which do not have an expiration date. In addition to the above NOLs, NRG has a $442 million carryforward for interest deductions, as well as $381 million of tax credits to be utilized in future years. The Company has $24 million of tax effected uncertain tax benefits. As a result of the Company's tax position, and based on current forecasts, NRG anticipates income tax payments, primarily to state and local jurisdictions, of up to $20 million in 2019.

The Company has recorded a non-current tax liability of $29 million until final resolution with the related taxing authority. The $29 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 September 30, 2019 and December 31, 2018, the Company had a valuation allowance on its domestic net deferred tax assets of $3.6 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 three 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 September 30, 2019, NRG has investments in energy and energy-related entities that are accounted for under the equity method of accounting. NRG’s investment in Ivanpah is a variable interest entity for which NRG is not the primary beneficiary. See also Note 11, Investments Accounted for Using the Equity Method and Variable Interest Entities, or VIEs, to this Form 10-Q.

NRG's pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $888 million as of September 30, 2019. This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to NRG. See also Note 15, Investments Accounted for by the Equity Method and Variable Interest Entities, to the Company's 2018 Form 10-K.

Contractual Obligations and Commercial Commitments

NRG has a variety of contractual obligations and other commercial commitments that represent prospective cash requirements in addition to the Company's capital expenditure programs, as disclosed in the Company's 2018 Form 10-K. See also Note 8, Leases, Note 10, Debt and Finance Leases, and Note 17, Commitments and Contingencies, to this Form 10-Q for a discussion of new commitments and contingencies that also include contractual obligations and commercial commitments that occurred during the three and nine months ended September 30, 2019.

Fair Value of Derivative Instruments

NRG may enter into power purchase and sales contracts, fuel purchase contracts and other energy-related financial instruments to mitigate variability in earnings due to fluctuations in spot market prices and to hedge fuel requirements at generation facilities or retail load obligations. Historically, in order to mitigate interest rate risk associated with the issuance of the Company's variable rate and fixed rate debt, NRG entered into interest rate swap agreements. As of September 30, 2019, NRG had no interest rate derivative instruments. The following disclosures about fair value of derivative instruments provide an update to, and should be read in conjunction with, Fair Value of Derivative Instruments in Item 7 — Management's Discussion and Analysis of Financial Condition and Results of Operations, of the Company's 2018 Form 10-K.

The tables below disclose the activities that include both exchange and non-exchange traded contracts accounted for at fair value in accordance with ASC 820, Fair Value Measurements and Disclosures, or ASC 820. Specifically, these tables disaggregate realized and unrealized changes in fair value; disaggregate estimated fair values at September 30, 2019, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at September 30, 2019.


Derivative Activity Gains/(Losses)	(In millions)
Fair Value of Contracts as of December 31, 2018	$	104
Contracts realized or otherwise settled during the period	(138)
Contracts acquired during the period	(12)
Changes in fair value	107
Fair Value of Contracts as of September 30, 2019	$	61


	Fair Value of Contracts as of September 30, 2019
	Maturity
Fair value hierarchy (Losses)/Gains	1 Year or Less		Greater than 1 Year to 3 Years		Greater than 3 Years to 5 Years		Greater than 5 Years		Total Fair Value
	(In millions)
Level 1	$	(34)	$	(23)	$	(2)	$	—	$	(59)
Level 2	79		52		(13)		(11)		107
Level 3	22		10		—		(19)		13
Total	$	67	$	39	$	(15)	$	(30)	$	61

The Company has elected to present derivative assets and liabilities on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. Also, collateral received or paid on the Company's derivative assets or liabilities are recorded on a separate line item on the balance sheet. Consequently, the magnitude of the changes in individual current and non-current derivative assets or liabilities is higher than the underlying credit and market risk of the Company's portfolio. As discussed in Item 3, Quantitative and Qualitative Disclosures About Market Risk, Commodity Price Risk, to this Form 10-Q, NRG measures the sensitivity of the Company's portfolio to potential changes in market prices using VaR, a statistical model which attempts to predict risk of loss based on market price and volatility. NRG's risk management policy places a limit on one-day holding period VaR, which limits the Company's net open position. As the Company's trade-by-trade derivative accounting results in a gross-up of the Company's derivative assets and liabilities, the net derivative asset and liability position is a better indicator of NRG's hedging activity. As of September 30, 2019, NRG's net derivative asset was $61 million, a decrease to total fair value of $43 million as compared to December 31, 2018. This decrease was driven by roll-off of trades that settled during the period and contracts acquired, partially offset by gains in fair value.

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 $23 million in the net value of derivatives as of September 30, 2019. The impact of a $0.50 per MMBtu decrease in natural gas prices across the term of derivative contracts would result in an increase of approximately $24 million in the net value of derivatives as of September 30, 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's significant accounting policies are outlined in Note 2, Summary of Significant Accounting Policies, of this Form 10-Q, and in Note 2, Summary of Significant Accounting Policies, under Part IV, Item 15 the Company's 2018 Form 10-K. The Company's critical accounting estimates are described in Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, in the Company's 2018 Form 10-K. There have been no material changes to the Company's critical accounting policies and estimates since the 2018 Form 10-K.

ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

NRG is exposed to several market risks in the Company's normal business activities. Market risk is the potential loss that may result from market changes associated with the Company's merchant power generation or with an existing or forecasted financial or commodity transaction. The types of market risks the Company is exposed to are commodity price risk, interest rate risk, liquidity risk, credit risk and currency exchange risk. The following disclosures about market risk provide an update to, and should be read in conjunction with, Item 7A — Quantitative and Qualitative Disclosures About Market Risk, of the Company's 2018 Form 10-K.

Commodity Price Risk

Commodity price risks result from exposures to changes in spot prices, forward prices, volatilities and correlations between various commodities, such as natural gas, electricity, coal, oil and emissions credits. NRG manages the commodity price risk of the Company's merchant generation operations and load serving obligations by entering into various derivative or non-derivative instruments to hedge the variability in future cash flows from forecasted sales and purchases of electricity and fuel. NRG measures the risk of the Company's portfolio using several analytical methods, including sensitivity tests, scenario tests, stress tests, position reports and VaR. NRG uses a Monte Carlo simulation based VaR model to estimate the potential loss in the fair value of its energy assets and liabilities, which includes generation assets, load obligations and bilateral physical and financial transactions.

The following table summarizes average, maximum and minimum VaR for NRG's commodity portfolio, including generation assets, load obligations and bilateral physical and financial transactions, calculated using the VaR model for the three and nine months ending September 30, 2019 and 2018:


(In millions)	2019		2018
VaR as of September 30,	$	49	$	72
Three months ended September 30,
Average	$	46	$	67
Maximum	55		75
Minimum	37		61
Nine months ended September 30,
Average	$	44	$	62
Maximum	55		75
Minimum	33		48

In order to provide additional information for comparative purposes to NRG's peers, the Company also uses VaR to estimate the potential loss of derivative financial instruments that are subject to mark-to-market accounting. These derivative instruments include transactions that were entered into for both asset management and trading purposes. The VaR for the derivative financial instruments calculated using the diversified VaR model as of September 30, 2019, for the entire term of these instruments entered into for both asset management and trading, was $9 million, primarily driven by asset-backed transactions.

Interest Rate Risk

NRG was exposed to fluctuations in interest rates through its issuance of variable rate debt. Exposures to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, caps, collars and put or call options. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt obligations when taking into account the combination of the variable rate debt and the interest rate derivative instrument. NRG's risk management policies allow the Company to reduce interest rate exposure from variable rate debt obligations.

The Company has previously entered into interest rate swaps. As of September 30, 2019, NRG had no interest rate derivative instruments. See Note 11, Debt and Capital Leases, of the Company's 2018 Form 10-K for more information on the Company's interest rate swaps.

As of September 30, 2019, the fair value and related carrying value of the Company's debt was $6.7 billion and $6.2 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 $570 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 $106 million as of September 30, 2019, and a 1 MMBtu/MWh change in heat rates for heat rate positions would result in a change in margin collateral posted of approximately $116 million as of September 30, 2019. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of September 30, 2019.

Credit Risk

Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. NRG is exposed to counterparty credit risk through various activities including wholesale sales, fuel purchases and retail supply arrangements, and retail customer credit risk through its retail load activities. See Note 5, Fair Value of Financial Instruments, to this Form 10-Q for discussions regarding counterparty credit risk and retail customer credit risk, and Note 7, Accounting for Derivative Instruments and Hedging Activities, to this Form 10-Q for discussion regarding credit risk contingent features.

Currency Exchange Risk

NRG's foreign earnings and investments may be subject to foreign currency exchange risk, which NRG generally does not hedge. As these earnings and investments are not material to NRG's consolidated results, the Company's foreign currency exposure is limited.

ITEM 4 — CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision and with the participation of NRG's management, including its principal executive officer, principal financial officer and principal accounting officer, NRG conducted an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures, as such term is defined in Rules 13a-15(e) or 15d-15(e) of the Exchange Act. Based on this evaluation, the Company's principal executive officer, principal financial officer and principal accounting officer concluded that the disclosure controls and procedures were effective as of the end of the period covered by this Quarterly Report on Form 10-Q.

Changes in Internal Control over Financial Reporting

There were no changes in NRG's internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred in the quarter ended September 30, 2019 that materially affected, or are reasonably likely to materially affect, NRG's internal control over financial reporting.

100

PART II — OTHER INFORMATION

ITEM 1 — LEGAL PROCEEDINGS

For a discussion of material legal proceedings in which NRG was involved through September 30, 2019, see Note 17, Commitments and Contingencies, to this Form 10-Q.

ITEM 1A — RISK FACTORS

Information regarding risk factors appears in Part I, Item 1A, Risk Factors Related to NRG Energy, Inc., in the Company's 2018 Form 10-K. There have been no material changes in the Company's risk factors since those reported in its 2018 Form 10‑K.

ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

During the three months ended September 30, 2019 the Company had two share repurchase programs in place. The $1.0 billion share repurchase program that was announced in February 2019, and the $250 million of share repurchase program that was announced in August 2019. The $1.0 billion share repurchase program was completed in August 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 September 30, 2019.


For the three months ended September 30, 2019	Total Number of Shares Purchased	Average Price Paid per Share		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
(July 1, 2019 to July 31, 2019)^(b)	4,950,000	$	35.17	4,950,000	$	21,598,889
Month #2
(August 1, 2019 to August 31, 2019)^(c)	1,153,269	$	34.78	1,153,269	$	231,466,402
Month #3
(September 1, 2019 to September 30, 2019)	511,182	$	38.84	511,182	$	211,603,397

Total at September 30, 2019	6,614,451			6,614,451

(a)Includes commissions paid

(b)Includes share repurchases under the 2019 $1 billion program that was announced on February 28, 2019

(c)Includes 636,536 share repurchases under the 2019 $1 billion program that was announced on February 28,2019 and 516,733 share repurchases under the $250 million program that was announced on August 7, 2019

ITEM 3 — DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4 — MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5 — OTHER INFORMATION

None.

101

ITEM 6 — EXHIBITS

Number

Description

Method of Filing

10.1

A copy of the Fourth Amendment dated as of May 28, 2019 to the Second Amended and Restated Credit Agreement dated as of June 30, 2016, included as Annex A thereto a clean, conformed copy of the Second Amended and Restated Credit Agreement.

Filed herewith.

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.

Section 1350 Certification.

Furnished herewith.

101 INS

Inline XBRL Instance Document.

The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.

101 SCH

Inline XBRL Taxonomy Extension Schema.

Filed herewith.

101 CAL

Inline XBRL Taxonomy Extension Calculation Linkbase.

Filed herewith.

101 DEF

Inline XBRL Taxonomy Extension Definition Linkbase.

Filed herewith.

101 LAB

Inline XBRL Taxonomy Extension Label Linkbase.

Filed herewith.

101 PRE

Inline XBRL Taxonomy Extension Presentation Linkbase.

Filed herewith.

104

Cover Page Interactive Data File (the cover page interactive data file does not appear in Exhibit 104 because it's Inline XBRL tags are embedded within the Inline XBRL document).

Filed herewith.

102

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

NRG ENERGY, INC.
(Registrant)

/s/ MAURICIO GUTIERREZ

Mauricio Gutierrez

Chief Executive Officer

(Principal Executive Officer)

/s/ KIRKLAND B. ANDREWS

Kirkland B. Andrews

Chief Financial Officer

(Principal Financial Officer)

/s/ DAVID CALLEN

David Callen

Date: November 7, 2019

Chief Accounting Officer

(Principal Accounting Officer)

103