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~~March 31, 2020

☐

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,~~May 7, 2020, there were ~~251,594,290~~244,087,060 shares of common stock outstanding, par value $0.01 per share.

TABLE OF CONTENTS

Index

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~~2019 and the following:

•NRG's ~~ability~~inability to ~~achieve~~estimate with any degree of certainty the ~~expected benefits~~future impact that COVID-19, any resurgence of ~~its Transformation Plan;~~COVID-19, or other pandemic may have on NRG's results of operations, financial position, risk exposure and liquidity;

•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;

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

•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 Notes, Senior Secured Notes and 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~~market 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 achieve the expected benefits of its Transformation Plan;

•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~~2019 Form 10-K						NRG’s Annual Report on Form 10-K for the year ended December 31, ~~2018~~2019
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
CARES Act						Coronavirus Aid, Relief, and Economic Security Act
Carlsbad						Carlsbad Energy Center, a 528 MW natural gas-fired project located in Carlsbad, CA
CCR						Coal Combustion Residuals
CDD						Cooling Degree Day
CDWR						California Department of Water Resources
CFTC						U.S. Commodity Futures Trading Commission
Chapter 11 Cases						Voluntary cases commenced by the GenOn Entities under the Bankruptcy Code in the Bankruptcy Court
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.
Convertible Senior Notes						As of March 31, 2020, consists of NRG’s $575 million unsecured 2.75% Convertible Senior Notes due 2048
Cottonwood						Cottonwood Generating Station, a 1,153 MW natural gas-fueled plant ~~which NRG is leasing through May 2025~~
COVID-19						Coronavirus Disease 2019
CPP						Clean Power Plan
CPUC						California Public Utilities Commission
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


ESCO						Energy Service Companies
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
Green Mountain Energy						Green Mountain Energy Company
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~~its 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
Pipeline						Projects that range from identified lead to shortlisted with an offtake, and represents a lower level of execution certainty
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~~Revolving Credit Facility						~~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~~The Company's $2.6 billion revolving credit facility, a component of the Senior Credit Facility, due 2024 was amended on May 28, 2019
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,~~March 31, 2020, 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
Senior Secured Notes						As of March 31, 2020, NRG’s $1.1 billion outstanding Senior Secured First Lien Notes consists of $600 million of the 3.75% Senior Secured First Lien Notes due 2024 and $500 million of the 4.45% Senior Secured First Lien 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~~TDSP						~~Transportation Services Agreement~~Transmission/distribution service provider

Transformation Plan

NRG's three-year plan announced in 2017, which includes targets related to operations and excellence, portfolio optimization, and capital structure and allocation enhancement

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

ZECs

Zero Emissions Credits

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,							Three months ended March 31,
(In millions, except for per share amounts)	(In millions, except for per share amounts)	2019		2018		2019		2018		(In millions, except for per share amounts)	2020		2019
Operating Revenues	Operating Revenues									Operating Revenues
Total operating revenues	Total operating revenues	$	2,996	$	2,960	$	7,626	$	7,486	Total operating revenues	$	2,019	$	2,165
Operating Costs and Expenses	Operating Costs and Expenses									Operating Costs and Expenses
Cost of operations	Cost of operations	2,153		2,238		5,649		5,512		Cost of operations	1,457		1,651
Depreciation and amortization	Depreciation and amortization	91		99		261		331		Depreciation and amortization	109		85
Impairment losses		—		—		1		74

Selling, general and administrative	Selling, general and administrative	210		211		615		587		Selling, general and administrative	209		194
Reorganization costs	Reorganization costs	1		27		16		70		Reorganization costs	3		13
Development costs	Development costs	1		1		5		9		Development costs	3		2
Total operating costs and expenses	Total operating costs and expenses	2,456		2,576		6,547		6,583		Total operating costs and expenses	1,781		1,945

Gain on sale of assets	Gain on sale of assets	—		14		2		30		Gain on sale of assets	6		1
Operating Income	Operating Income	540		398		1,081		933		Operating Income	244		221
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates		29		20		8		26
Other (Expense)/Income										Other (Expense)/Income
Equity in losses of unconsolidated affiliates										Equity in losses of unconsolidated affiliates	(11)		(21)
Impairment losses on investments	Impairment losses on investments	(107)		(1)		(107)		(16)		Impairment losses on investments	(18)		—
Other income, net	Other income, net	17		19		49		12		Other income, net	27		12
Loss on debt extinguishment, net		—		(19)		(47)		(22)

Interest expense	Interest expense	(99)		(122)		(318)		(361)		Interest expense	(98)		(114)
Total other expense	Total other expense	(160)		(103)		(415)		(361)		Total other expense	(100)		(123)
Income from Continuing Operations Before Income Taxes	Income from Continuing Operations Before Income Taxes	380		295		666		572		Income from Continuing Operations Before Income Taxes	144		98
Income tax expense	Income tax expense	6		8		9		19		Income tax expense	23		4
Income from Continuing Operations	Income from Continuing Operations	374		287		657		553		Income from Continuing Operations	121		94
(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.
Income from discontinued operations, net of income tax										Income from discontinued operations, net of income tax	—		388

Net Income										Net Income	$	121	$	482
Earnings per Share										Earnings per Share
Weighted average number of common shares outstanding — basic	Weighted average number of common shares outstanding — basic	254		299		266		309		Weighted average number of common shares outstanding — basic	248		278
Income from continuing operations per weighted average common share — basic	Income from continuing operations per weighted average common share — basic	$	1.47	$	0.88	$	2.47	$	1.79	Income from continuing operations per weighted average common share — basic	$	0.49	$	0.34
(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
Income from discontinued operations per weighted average common share — basic										Income from discontinued operations per weighted average common share — basic	$	—	$	1.39
Earnings per Weighted Average Common Share — Basic										Earnings per Weighted Average Common Share — Basic	$	0.49	$	1.73
Weighted average number of common shares outstanding — diluted	Weighted average number of common shares outstanding — diluted	256		299		268		313		Weighted average number of common shares outstanding — diluted	249		280
Income from continuing operations per weighted average common share — diluted	Income from continuing operations per weighted average common share — diluted	$	1.46	$	0.88	$	2.45	$	1.76	Income from continuing operations per weighted average common share — diluted	$	0.49	$	0.34
(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
Income from discontinued operations per weighted average common share — diluted										Income from discontinued operations per weighted average common share — diluted	$	—	$	1.38
Earnings per Weighted Average Common Share — Diluted										Earnings per Weighted Average Common Share — Diluted	$	0.49	$	1.72

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE ~~INCOME/(LOSS)~~INCOME

(Unaudited)

Three months ended 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


	Three months ended March 31,
(In millions)	2020		2019
Net Income	$	121	$	482
Other Comprehensive Loss

Foreign currency translation adjustments	(15)		1

Defined benefit plans	—		(3)
Other comprehensive loss	(15)		(2)


Comprehensive Income	$	106	$	480

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS


		September 30, 2019		December 31, 2018			March 31, 2020		December 31, 2019
(In millions, except share data)	(In millions, except share data)	(Unaudited)				(In millions, except share data)	(Unaudited)		(Audited)
ASSETS	ASSETS					ASSETS
Current Assets	Current Assets					Current Assets
Cash and cash equivalents	Cash and cash equivalents	$	243	$	563	Cash and cash equivalents	$	759	$	345
Funds deposited by counterparties	Funds deposited by counterparties	30		33		Funds deposited by counterparties	51		32
Restricted cash	Restricted cash	4		17		Restricted cash	8		8
Accounts receivable, net	Accounts receivable, net	1,376		1,024		Accounts receivable, net	915		1,025
Inventory	Inventory	364		412		Inventory	372		383
Derivative instruments	Derivative instruments	735		764		Derivative instruments	884		860
Cash collateral paid in support of energy risk management activities	Cash collateral paid in support of energy risk management activities	164		287		Cash collateral paid in support of energy risk management activities	200		190

Prepayments and other current assets	Prepayments and other current assets	271		302		Prepayments and other current assets	290		245
Current assets - held-for-sale		—		1
Current assets - discontinued operations		—		197

Total current assets	Total current assets	3,187		3,600		Total current assets	3,479		3,088
Property, plant and equipment, net	Property, plant and equipment, net	2,615		3,048		Property, plant and equipment, net	2,573		2,593
Other Assets	Other Assets					Other Assets
Equity investments in affiliates	Equity investments in affiliates	405		412		Equity investments in affiliates	350		388

Operating lease right-of-use assets, net	Operating lease right-of-use assets, net	482		—		Operating lease right-of-use assets, net	446		464
Goodwill	Goodwill	591		573		Goodwill	579		579
Intangible assets, net	Intangible assets, net	828		591		Intangible assets, net	769		789
Nuclear decommissioning trust fund	Nuclear decommissioning trust fund	756		663		Nuclear decommissioning trust fund	702		794
Derivative instruments	Derivative instruments	358		317		Derivative instruments	434		310
Deferred income taxes	Deferred income taxes	53		46		Deferred income taxes	3,265		3,286
Other non-current assets	Other non-current assets	252		289		Other non-current assets	225		240
Non-current assets - held-for-sale		—		77
Non-current assets - discontinued operations		—		1,012

Total other assets	Total other assets	3,725		3,980		Total other assets	6,770		6,850
Total Assets	Total Assets	$	9,527	$	10,628	Total Assets	$	12,822	$	12,531

LIABILITIES AND STOCKHOLDERS' EQUITY	LIABILITIES AND STOCKHOLDERS' EQUITY					LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities	Current Liabilities					Current Liabilities
Current portion of long-term debt and finance leases		$	302	$	72
Current portion of long-term debt						Current portion of long-term debt	$	640	$	88
Current portion of operating lease liabilities	Current portion of operating lease liabilities	73		—		Current portion of operating lease liabilities	71		73
Accounts payable	Accounts payable	866		863		Accounts payable	708		722

Derivative instruments	Derivative instruments	668		673		Derivative instruments	832		781
Cash collateral received in support of energy risk management activities	Cash collateral received in support of energy risk management activities	30		33		Cash collateral received in support of energy risk management activities	51		32
Accrued expenses and other current liabilities	Accrued expenses and other current liabilities	625		680		Accrued expenses and other current liabilities	550		663

Current liabilities - held-for-sale		—		5
Current liabilities - discontinued operations		—		72

Total current liabilities	Total current liabilities	2,564		2,398		Total current liabilities	2,852		2,359
Other Liabilities	Other Liabilities					Other Liabilities
Long-term debt and finance leases		5,798		6,449
Long-term debt						Long-term debt	5,807		5,803
Non-current operating lease liabilities	Non-current operating lease liabilities	500		—		Non-current operating lease liabilities	473		483
Nuclear decommissioning reserve	Nuclear decommissioning reserve	294		282		Nuclear decommissioning reserve	303		298
Nuclear decommissioning trust liability	Nuclear decommissioning trust liability	453		371		Nuclear decommissioning trust liability	390		487

Derivative instruments	Derivative instruments	364		304		Derivative instruments	370		322
Deferred income taxes	Deferred income taxes	70		65		Deferred income taxes	15		17
Other non-current liabilities						Other non-current liabilities	1,076		1,084

Other non-current liabilities		1,036		1,274
Non-current liabilities - held-for-sale		—		65
Non-current liabilities - discontinued operations		—		635

Total other liabilities	Total other liabilities	8,515		9,445		Total other liabilities	8,434		8,494
Total Liabilities	Total Liabilities	11,079		11,843		Total Liabilities	11,286		10,853
Redeemable noncontrolling interest in subsidiaries	Redeemable noncontrolling interest in subsidiaries	19		19		Redeemable noncontrolling interest in subsidiaries	—		20
Commitments and Contingencies	Commitments and Contingencies					Commitments and Contingencies
Stockholders' Equity	Stockholders' Equity					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
Common stock; $0.01 par value; 500,000,000 shares authorized; 422,979,893 and 421,890,790 shares issued and 245,623,854 and 248,996,189 shares outstanding at March 31, 2020 and December 31, 2019, respectively						Common stock; $0.01 par value; 500,000,000 shares authorized; 422,979,893 and 421,890,790 shares issued and 245,623,854 and 248,996,189 shares outstanding at March 31, 2020 and December 31, 2019, respectively	4		4
Additional paid-in-capital	Additional paid-in-capital	8,494		8,510		Additional paid-in-capital	8,498		8,501
Accumulated deficit	Accumulated deficit	(4,991)		(6,022)		Accumulated deficit	(1,570)		(1,616)
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)
Treasury stock, at cost - 177,356,039 and 172,894,601 shares at March 31, 2020 and December 31, 2019, respectively						Treasury stock, at cost - 177,356,039 and 172,894,601 shares at March 31, 2020 and December 31, 2019, respectively	(5,189)		(5,039)
Accumulated other comprehensive loss	Accumulated other comprehensive loss	(158)		(94)		Accumulated other comprehensive loss	(207)		(192)

Total Stockholders' Equity	Total Stockholders' Equity	(1,571)		(1,234)		Total Stockholders' Equity	1,536		1,658
Total Liabilities and Stockholders' Equity	Total Liabilities and Stockholders' Equity	$	9,527	$	10,628	Total Liabilities and Stockholders' Equity	$	12,822	$	12,531

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,							Three months ended March 31,
(In millions)	(In millions)	2019		2018		(In millions)	2020		2019
Cash Flows from Operating Activities	Cash Flows from Operating Activities					Cash Flows from Operating Activities
Net Income	Net Income	$	1,056	$	281	Net Income	$	121	$	482
Income/(loss) from discontinued operations, net of income tax		399		(272)
Income from discontinued operations, net of income tax						Income from discontinued operations, net of income tax	—		388
Income from continuing operations	Income from continuing operations	657		553		Income from continuing operations	121		94
Adjustments to reconcile net income to cash provided by operating activities:	Adjustments to reconcile net income to cash provided by operating activities:					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
Distributions from and equity in losses of unconsolidated affiliates						Distributions from and equity in losses of unconsolidated affiliates	16		21
Depreciation and amortization						Depreciation and amortization	109		85
Accretion of asset retirement obligations						Accretion of asset retirement obligations	11		7
Provision for credit losses						Provision for credit losses	24		26
Amortization of nuclear fuel	Amortization of nuclear fuel	40		38		Amortization of nuclear fuel	13		13
Amortization of financing costs and debt discount/premiums	Amortization of financing costs and debt discount/premiums	20		21		Amortization of financing costs and debt discount/premiums	6		7
Loss on debt extinguishment, net	Loss on debt extinguishment, net	47		22		Loss on debt extinguishment, net	1		—
Amortization of emissions allowances and out-of-market contracts		28		21
Amortization of emissions allowances and energy credits						Amortization of emissions allowances and energy credits	7		6
Amortization of unearned equity compensation	Amortization of unearned equity compensation	15		21		Amortization of unearned equity compensation	5		4
Gain on sale and disposal of assets		(20)		(50)
(Gain)/loss on sale of assets and disposal of assets						(Gain)/loss on sale of assets and disposal of assets	(14)		3

Impairment losses	Impairment losses	108		90		Impairment losses	18		—
Changes in derivative instruments	Changes in derivative instruments	36		(17)		Changes in derivative instruments	(46)		(15)
Changes in deferred income taxes and liability for uncertain tax benefits	Changes in deferred income taxes and liability for uncertain tax benefits	(3)		(6)		Changes in deferred income taxes and liability for uncertain tax benefits	19		(2)
Changes in collateral deposits in support of energy risk management activities	Changes in collateral deposits in support of energy risk management activities	129		(30)		Changes in collateral deposits in support of energy risk management activities	9		(123)
Changes in nuclear decommissioning trust liability	Changes in nuclear decommissioning trust liability	27		50		Changes in nuclear decommissioning trust liability	8		9
GenOn settlement		—		(125)
Loss on deconsolidation of Agua Caliente and Ivanpah projects		—		13

Changes in other working capital	Changes in other working capital	(602)		(361)		Changes in other working capital	(99)		(234)
Cash provided by continuing operations		853		671
Cash provided/(used) by continuing operations						Cash provided/(used) by continuing operations	208		(99)
Cash provided by discontinued operations	Cash provided by discontinued operations	8		396		Cash provided by discontinued operations	—		8
Net Cash Provided by Operating Activities		861		1,067
Net Cash Provided/(Used) by Operating Activities						Net Cash Provided/(Used) by Operating Activities	208		(91)
Cash Flows from Investing Activities	Cash Flows from Investing Activities					Cash Flows from Investing Activities
Payments for acquisitions of businesses	Payments for acquisitions of businesses	(348)		(209)		Payments for acquisitions of businesses	—		(16)
Capital expenditures	Capital expenditures	(183)		(343)		Capital expenditures	(66)		(49)
Net proceeds from notes receivable		2		—
Net proceeds from sale of emission allowances		14		24

Net purchases of emission allowances						Net purchases of emission allowances	(8)		—
Investments in nuclear decommissioning trust fund securities	Investments in nuclear decommissioning trust fund securities	(295)		(449)		Investments in nuclear decommissioning trust fund securities	(121)		(122)
Proceeds from the sale of nuclear decommissioning trust fund securities	Proceeds from the sale of nuclear decommissioning trust fund securities	271		398		Proceeds from the sale of nuclear decommissioning trust fund securities	112		113
Proceeds from sale of assets, net of cash disposed and sale of discontinued operations, net of fees	Proceeds from sale of assets, net of cash disposed and sale of discontinued operations, net of fees	1,293		1,555		Proceeds from sale of assets, net of cash disposed and sale of discontinued operations, net of fees	15		1,313
Deconsolidation of Agua Caliente and Ivanpah projects		—		(268)
Net contributions to investments in unconsolidated affiliates		(94)		(39)

Net distributions from investments in unconsolidated affiliates						Net distributions from investments in unconsolidated affiliates	—		4
Contributions to discontinued operations	Contributions to discontinued operations	(44)		(23)		Contributions to discontinued operations	—		(44)

Cash provided by continuing operations		616		646
Other						Other	—		(1)
Cash (used)/provided by continuing operations						Cash (used)/provided by continuing operations	(68)		1,198
Cash used by discontinued operations	Cash used by discontinued operations	(2)		(705)		Cash used by discontinued operations	—		(2)
Net Cash Provided/(Used) by Investing Activities		614		(59)
Net Cash (Used)/Provided by Investing Activities						Net Cash (Used)/Provided by Investing Activities	(68)		1,196
Cash Flows from Financing Activities	Cash Flows from Financing Activities					Cash Flows from Financing Activities
Payments of dividends to common stockholders	Payments of dividends to common stockholders	(24)		(28)		Payments of dividends to common stockholders	(74)		(8)
Payments for treasury stock		(1,286)		(1,000)
Payments for share repurchase activity						Payments for share repurchase activity	(179)		(783)

Payments for debt extinguishment costs		(24)		—
Distributions to noncontrolling interests from subsidiaries		(1)		(17)

Purchase of and distributions to noncontrolling interests from subsidiaries						Purchase of and distributions to noncontrolling interests from subsidiaries	(2)		(1)
Proceeds from issuance of common stock	Proceeds from issuance of common stock	3		15		Proceeds from issuance of common stock	—		2
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)
Proceeds from issuance of long-term debt						Proceeds from issuance of long-term debt	59		—

Repayments of long-term debt						Repayments of long-term debt	(60)		(37)
Net proceeds from Revolving Credit Facility						Net proceeds from Revolving Credit Facility	552		—

Other	Other	—		(4)		Other	(3)		—
Cash used by continuing operations		(1,805)		(1,054)
Cash provided/(used) by continuing operations						Cash provided/(used) by continuing operations	293		(827)
Cash provided by discontinued operations	Cash provided by discontinued operations	43		403		Cash provided by discontinued operations	—		43
Net Cash Used by Financing Activities		(1,762)		(651)
Effect of exchange rate changes on cash and cash equivalents		—		1
Net Cash Provided/(Used) by Financing Activities						Net Cash Provided/(Used) by Financing Activities	293		(784)

Change in Cash from discontinued operations	Change in Cash from discontinued operations	49		94		Change in Cash from discontinued operations	—		49
Net (Decrease)/increase in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash		(336)		264
Net Increase in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash						Net Increase in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash	433		272
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period	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 Beginning of Period	385		613
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	$	277	$	1,350	Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	$	818	$	885

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)


(In millions)	Common Stock		Additional Paid-In Capital		Accumulated Deficit		Treasury Stock		Accumulated Other Comprehensive Loss		Total Stock-holders' Equity
Balance at December 31, 2019	$	4	$	8,501	$	(1,616)	$	(5,039)	$	(192)	$	1,658
Net income					121						121
Other comprehensive loss									(15)		(15)
Repurchase of partners' equity interest in VIE			18								18

Share repurchases							(150)				(150)
Equity-based awards activity, net			(21)								(21)

Common stock dividends and dividend equivalents declared^(a)					(75)						(75)





Balance at March 31, 2020	$	4	$	8,498	$	(1,570)	$	(5,189)	$	(207)	$	1,536


(In millions)	Common Stock		Additional Paid-In Capital		Accumulated Deficit		Treasury Stock		Accumulated Other Comprehensive Loss		Total Stock-holders' Equity
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 awards activity, net			(32)								(32)
Issuance of common stock			5								5
Common stock dividends and dividend equivalents declared^(a)					(8)						(8)



Balance at March 31, 2019	$	4	$	8,473	$	(5,548)	$	(4,371)	$	(96)	$	(1,538)

(a) Dividends per common share ~~were~~was $0.30 for the quarter ended March 31, 2020 and $0.03 for ~~each of~~ the ~~quarters~~quarter 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.

1413

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~~integrated power company built on dynamic retail brands with diverse generation assets. NRG brings the power of energy to consumers by producing ~~selling~~ and ~~delivering~~selling electricity and related products and services in major competitive power markets in the U.S. and Canada in a manner that delivers value to all of NRG's stakeholders. NRG is a customer-driven business focused on perfecting the integrated model by balancing retail load with generation supply within its deregulated ~~markets, while evolving to a customer-driven business.~~markets. The Company sells energy, services, and innovative, sustainable products and services directly to retail customers under the brand names ~~"NRG", "Reliant"~~NRG, Reliant, Green Mountain Energy, Stream, and XOOM Energy, as well as other brand names owned by NRG, supported by approximately 23,000 MW of generation as of ~~September 30, 2019.~~March 31, 2020.

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 condensed consolidated financial statements in the Company's ~~2018~~2019 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,~~March 31, 2020, and the results of operations, comprehensive income, cash flows and statements of stockholders' equity for the three ~~and nine~~ months ended ~~September 30, 2019~~March 31, 2020 and ~~2018.~~2019.

~~Discontinued Operations~~Segments

~~During~~As part of perfecting the ~~fourth~~integrated model, in which the majority of the Company’s generation serves its retail customers, the Company began managing its operations based on the combined results of the retail and wholesale generation businesses with a geographical focus in 2020. As a result, the Company changed its business segments from Retail and Generation to Texas, East and West/Other beginning in the first quarter of ~~2018,~~2020. The Company's updated segment structure reflects how management currently makes financial decisions and allocates resources.

The Company's businesses are segregated as ~~described~~follows:

•Texas, which includes all activity related to customer, plant and market operations in ~~Note 4,~~ Texas;

•~~Acquisitions, Discontinued Operations~~East, which includes the remaining activity related to customer operations and ~~Dispositions~~all activity related to plant and market operations in the East;

•,West/Other, which includes the ~~Company concluded that~~following assets and activities: (i) all activity related to plant and market operations in the ~~sale of its South Central Portfolio~~West, (ii) activity related to ~~Cleco, excluding~~ the Cottonwood ~~facility, met held-for-sale criteria and should be presented as discontinued operations, as the sale, which closed~~power plant that was sold to Cleco on February 4, 2019 ~~represented a strategic shift~~and is being leased back until 2025, (iii) the remaining renewables activity, including the Company’s equity method investments in Ivanpah Master Holdings, LLC and Agua Caliente, the ~~business~~remaining Home Solar assets and the NFL stadium solar generating assets, and (iv) activity related to the Company’s equity method investment for the Gladstone power plant in ~~which NRG operates. The financial information for all historical periods has~~Australia; and

•Corporate activities.

All affected disclosures have 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~~changes for all ~~historical~~ periods ~~was recast~~presented. For further discussion of segment reporting, refer to ~~reflect~~Note 13, Segment Reporting.

COVID-19

In March 2020, the ~~presentation~~World Health Organization categorized COVID-19 as a pandemic and the President of ~~these entities, as well as~~ the ~~Carlsbad project, as discontinued operations~~United States declared the COVID-19 outbreak a national emergency. Electricity has been deemed a 'critical and essential business operation' under various state and federal governmental COVID-19 mandates. NRG remains focused on protecting the health and well-being of its employees, while supporting its customers and the communities in which it operates and assuring the ~~third quarter~~continuity of ~~2018.~~its operations.

NRG activated its Crisis Management Team ("CMT") in January 2020, which proactively began managing the Company's response to the impacts of COVID-19. The CMT implemented the business continuity plans for the Company and has taken a

variety of measures to ensure the ongoing availability of the Company’s services, while maintaining the Company's commitment to its core values of health and safety. Pursuant to the Company’s Infectious Disease & Pandemic Policy, NRG implemented restrictions on business travel and face-to-face sales channels, instituted remote work practices and enhanced cleaning and hygiene protocols in all of its facilities. In order to effectively serve the Company’s customers, select essential employees and contractors are continuing to report to plant and certain office locations. The Company is also requiring pre-entry screening, including temperature checks, separation of work crews, additional personal protective equipment for employees and contractors when social distancing cannot be maintained, and a ban on all non-essential visitors. As a result of ~~the sale of NRG Yield,~~these business continuity measures, the Company ~~no longer controls the Agua Caliente project. Due~~has not experienced any material disruptions in its ability to ~~this change in control, the Company also deconsolidated the Agua Caliente project from~~continue its ~~financial results and began accounting for the project as an equity method investment.~~business operations to date.

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;~~net and accumulated amortization included in intangible assets, ~~net and accumulated amortization included in out-of-market contracts,~~ net:


(In millions)						(In millions)	March 31, 2020		December 31, 2019
		September 30, 2019		December 31, 2018
		(In millions)
Accounts receivable allowance for doubtful accounts		$	57	$	32
Property, plant and equipment accumulated depreciation	Property, plant and equipment accumulated depreciation	1,759		1,811		Property, plant and equipment accumulated depreciation	$	1,832	$	1,752
Intangible assets accumulated amortization	Intangible assets accumulated amortization	1,215		1,149		Intangible assets accumulated amortization	1,237		1,262
Out-of-market contracts accumulated amortization		—		37

Credit Losses

On January 1, 2020, the Company adopted ASU No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, or ASU No. 2016-13, using the modified retrospective approach. Following the adoption of the new standard, the Company’s process of estimating expected credit losses remains materially consistent with its historical practice. Information prior to January 1, 2020, which was previously referred to as the allowance and provision for bad debt, has not been restated and continues to be reported under the accounting standards in effect for that period.

Retail trade receivables are reported on the balance sheet net of the allowance for credit losses. The Company accrues an allowance for current expected credit losses based on (i) estimates of uncollectible revenues by analyzing accounts receivable aging and current and reasonable forecasts of expected economic factors including, but not limited to, unemployment rates and weather-related events, (ii) historical collections and delinquencies, and (iii) counterparty credit ratings for commercial and industrial customers.

The following table represents the activity in the allowance for credit losses for the three months ended March 31, 2020:


	(In millions)
Balance at January 1, 2020	$	43
Provision for credit losses	24
Write-offs	(32)
Recoveries collected	4
Balance at March 31, 2020	$	39

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)
(In millions)						(In millions)	March 31, 2020		December 31, 2019
Cash and cash equivalents	Cash and cash equivalents	$	243	$	563	Cash and cash equivalents	$	759	$	345
Funds deposited by counterparties	Funds deposited by counterparties	30		33		Funds deposited by counterparties	51		32
Restricted cash	Restricted cash	4		17		Restricted cash	8		8
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows	Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows	$	277	$	613	Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows	$	818	$	385

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~~Contributions

~~During~~On March 27, 2020, the ~~third quarter of 2019, STPNOC announced that~~Senate passed the ~~defined benefit~~CARES Act to provide necessary emergency relief related to the COVID-19 pandemic. The CARES Act allows NRG and other pension plan ~~will be frozen for non-union employees on December 31,~~sponsors to postpone 2020 contributions until January 1, 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~~will consider deferring approximately $47 million ~~related~~in cash contributions previously planned to be made to the ~~curtailment of benefits~~Company's pension plans in 2020. NRG’s pension and ~~an increase of $32 million to the pension liability was recorded to other comprehensive income. The STP defined~~postretirement benefit ~~plan is~~plans are further described in Note 1315, , Benefit Plans and Other Postretirement Benefits, to the Company’s ~~2018~~2019 Form 10-K.

Recent Accounting Developments - Guidance Adopted in ~~2019~~2020

ASU ~~2016-02~~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, or ASU No. 2018-17, in response to stakeholders’ observations that Topic 810, Consolidations, could be improved thereby improving general purpose financial reporting. Specifically, ASU No. 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. The adoption did not have a material impact on the Company's results of operations, cash flows, or statement of financial position.

ASU 2018-15 — In August 2018, the FASB issued ASU No. 2018-15, Intangibles – Goodwill and Other – Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in Cloud Computing Arrangement That Is a Service Contract, or ASU No. 2018-15. The amendments in ASU No. 2018-15 align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing costs incurred to develop or obtain internal-use software (and hosting arrangement that include an internal-use software license). The amendment also requires the customer to amortize the capitalized implementation costs of a hosting arrangement that is a service contract over the term of the hosting arrangement. The Company adopted the amendments effective January 1, 2020 using the prospective approach. The adoption did not have a material impact on the Company's results of operations, cash flows, or statement of financial position.

ASU 2018-13 — In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework - Changes to the Disclosure Requirement for Fair value Measurement), or ASU No. 2018-13. The amendments in ASU No. 2018-13 eliminate such disclosures as the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy and 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. Certain disclosures in ASU No. 2018-13 are required to be applied on a retrospective basis and others on a prospective basis. The Company adopted the amendments effective January 1, 2020. As the amendments contemplates changes in disclosures only, it did not have an impact on the Company's results of operations, cash flows, or statement of financial position.

ASU 2016-13 — In ~~February~~June 2016, the FASB issued ASU No. ~~2016-02,~~2016-13, ~~Leases~~Financial Instruments - Credit Losses (Topic ~~842)~~326): Measurement of Credit Losses on Financial Statements, , or ~~Topic 842,~~ASU No. 2016-13, 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.thereafter. The guidance in ~~Topic 842~~ASU No. 2016-13 provides a new model for recognizing credit losses on financial assets carried at amortized cost using an estimate of expected credit losses, instead of the "incurred loss" methodology previously required for recognizing credit losses that delayed recognition until it was probable that a ~~lessee that may have previously accounted for a lease as an operating lease under~~loss was incurred. The estimate of expected credit losses is to be based on consideration of past events, current ~~GAAP should recognize the assets~~conditions and ~~liabilities that arise from a lease on the balance sheet. In addition, Topic 842 expands the required quantitative~~reasonable and ~~qualitative disclosures with regards to lease arrangements.~~supportable forecasts of future conditions. The Company adopted the standard and its subsequent corresponding updates effective January 1, ~~2019 under~~2020 using 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 meetapproach. Results for the reporting ~~requirements of the standard.~~periods after January 1, 2020 are presented under Topic 326 while prior period amounts continue to be reported in accordance with previously applicable GAAP. The ~~Company established operating lease liabilities of $404 million and right-of-use assets of $321 million upon adoption, before considering deferred taxes. The~~Company's adoption of Topic ~~842~~326 did not have a material impact on the ~~statements~~Company's results of operations, cash flows, or ~~cash flows. See Note 8,~~ ~~Leases,~~ ~~for further discussion.~~statement of financial position.

Recent Accounting Developments - Guidance Not Yet Adopted

ASU ~~2018-17~~2019-12 — - In ~~October 2018,~~December 2019, the FASB issued ASU No. ~~2018-17,~~2019-12, ~~Consolidations~~Income Taxes (Topic ~~810)~~740): ~~Targeted Improvements to Related Party Guidance~~Simplifying the Accounting for ~~Variable Interest Entities~~Income Taxes, ~~, 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~~or ASU No. ~~2018-13,~~ ~~Fair Value Measurement (Topic 820): Disclosure Framework - Changes~~2019-12, to ~~the Disclosure Requirement~~simplify various aspects related to accounting for ~~Fair value Measurement)~~.income taxes. The guidance in ASU ~~No. 2018-13 eliminates such disclosures as~~2019-12 amends the ~~amount~~general principles in Topic 740 to eliminate certain exceptions for recognizing deferred taxes for investment, performing intraperiod allocation and calculating income taxes in interim periods. This ASU also includes guidance to reduce complexity in certain areas, including recognizing deferred taxes for tax goodwill and allocating taxes to members of ~~and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy. The amendments in~~a consolidated group. ASU ~~No. 2018-13 add new disclosure requirements for Level 3 measurements. ASU No. 2018-13~~2019-12 is effective for fiscal years beginning after December 15, ~~2019,~~2020, and interim periods within those fiscal years, ~~with early~~. Early adoption is permitted, ~~for any eliminated or modified disclosures. Certain disclosures~~including adoption in ~~ASU No. 2018-13 are required to be applied on a retrospective basis and others on a prospective basis. As~~an interim period. The Company is currently in the ~~amendment contemplates changes in disclosures only, it will have no material~~process of assessing the impact of this guidance on the ~~Company's results of operations, cash flows, or statement of~~consolidated financial ~~position.~~statements.

Note 3 — Revenue Recognition

Performance Obligations

As of ~~September 30, 2019,~~March 31, 2020, estimated future fixed fee performance obligations are ~~$136~~$442 million for the remaining ~~three~~nine months of fiscal year ~~2019,~~2020, and ~~$532~~$607 million, ~~$586~~$305 million, ~~$297~~$42 million and ~~$29~~$8 million for the ~~entirety of~~ fiscal years ~~2020,~~ 2021, 2022, 2023 and ~~2023,~~2024, 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~~March 31, 2020 and ~~2018 along with the reportable segment for each category:~~2019:

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


	Three months ended March 31, 2020
(In millions)	Texas		East		West/Other		Corporate/Eliminations		Total
Retail revenue:
Mass Market	$	1,032	$	347	$	—	$	(1)	$	1,378
Business Solutions	260		23		—		—		283
Total retail revenue	1,292		370		—		(1)		1,661
Energy revenue^(a)	5		45		75		(1)		124
Capacity revenue^(a)	—		134		15		—		149
Mark-to-market for economic hedging activities^(b)	—		(20)		15		1		(4)

Other revenue^(a)	61		10		20		(2)		89
Total operating revenue	1,358		539		125		(3)		2,019
Less: Lease revenue	—		—		5		—		5
Less: Realized and unrealized ASC 815 revenue	7		39		44		(1)		89

Total revenue from contracts with customers	$	1,351	$	500	$	76	$	(2)	$	1,925
(a) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 and included in the amounts above:
(In millions)	Texas		East		West/Other		Corporate/Eliminations		Total
Energy revenue	$	—	$	35	$	19	$	(1)	$	53
Capacity revenue	—		24		—		—		24
Other revenue	7		—		10		(1)		16
(b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815

1817

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


	Three months ended March 31, 2019
(In millions)	Texas		East		West/Other		Corporate/Eliminations		Total
Retail revenue:
Mass Market	$	995	$	320	$	—	$	(2)	$	1,313
Business Solutions	258		18		—		—		276
Total retail revenue	1,253		338		—		(2)		1,589
Energy revenue^(a)	105		126		58		1		290
Capacity revenue^(a)	—		144		12		—		156
Mark-to-market for economic hedging activities^(b)	31		(15)		4		—		20

Other revenue^(a)	77		16		19		(2)		110
Total operating revenue	1,466		609		93		(3)		2,165
Less: Lease revenue	—		—		5		—		5
Less: Realized and unrealized ASC 815 revenue	315		54		12		—		381

Total revenue from contracts with customers	$	1,151	$	555	$	76	$	(3)	$	1,779
(a) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 and included in the amounts above:
(In millions)	Texas		East		West/Other		Corporate/Eliminations		Total
Energy revenue	$	271	$	47	$	2	$	—	$	320
Capacity revenue	—		18		—		—		18
Other revenue	13		4		6		—		23
(b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815

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~~March 31, 2020 and December 31, ~~2018:~~2019:


(In millions)	(In millions)	September 30, 2019		December 31, 2018		(In millions)	March 31, 2020		December 31, 2019
Deferred customer acquisition costs	Deferred customer acquisition costs	$	130	$	111	Deferred customer acquisition costs	$	133	$	133

Accounts receivable, net - Contracts with customers	Accounts receivable, net - Contracts with customers	1,311		999		Accounts receivable, net - Contracts with customers	885		1,002

Accounts receivable, net - Derivative instruments	Accounts receivable, net - Derivative instruments	63		20		Accounts receivable, net - Derivative instruments	26		18
Accounts receivable, net - Affiliate	Accounts receivable, net - Affiliate	4		5		Accounts receivable, net - Affiliate	4		5
Total accounts receivable, net	Total accounts receivable, net	$	1,378	$	1,024	Total accounts receivable, net	$	915	$	1,025

Unbilled revenues (included within Accounts receivable, net - Contracts with customers)	Unbilled revenues (included within Accounts receivable, net - Contracts with customers)	$	486	$	392	Unbilled revenues (included within Accounts receivable, net - Contracts with customers)	$	328	$	402

Deferred revenues^(a)	Deferred revenues^(a)	78		67		Deferred revenues^(a)	87		82

(a) Deferred revenues from contracts with customers for the ~~nine~~three months ended ~~September 30, 2019~~March 31, 2020 and the year ended December 31, ~~2018~~2019 were approximately ~~$25~~$27 million and ~~$19~~$24 million, respectively

The revenue recognized from contracts with customers during both the ~~nine~~three months ended ~~September 30,~~March 31, 2020 and 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.million. The change in deferred revenue balances during the three ~~and nine~~ months ended ~~September 30,~~March 31, 2020 and 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.~~operations at

December 31, 2018. 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 held-for-sale or discontinued operations treatment in accounting for ~~historical and ongoing activity with Cottonwood.~~the Cottonwood facility.

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:~~

Three months ended

(In millions)

~~December~~March 31, ~~2018~~2019

~~Cash and cash equivalents~~Operating revenues

8931

~~Accounts receivable - trade, net~~Operating costs and expenses

49 (23)

~~Inventory~~Gain from operations of discontinued components

358

~~Other current assets~~Gain on disposal of discontinued operations, net of tax

527

~~Current assets - discontinued operations~~

~~178~~

~~Property, plant and equipment, net~~

~~408~~

~~Other non-current assets~~

~~Non-current assets -~~Gain from discontinued operations,

~~409~~

~~Accounts payable~~

~~Other current liabilities~~

~~Current liabilities - discontinued operations~~

~~Out-of-market contracts,~~ including disposal, net

~~Other non-current liabilities~~

~~Non-current liabilities - discontinued operations~~ of tax

6135

~~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 2 ten year extensions. As a result of the transaction, additional commitments related to the project totaled approximately $23 million as of March 31, 2020 and 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:~~

Three months ended

(In millions)

~~December~~March 31, ~~2018~~2019

~~Restricted cash~~Operating revenues

419

~~Accounts receivable - trade, net~~Operating costs and expenses

10 (9)

Other ~~current assets~~expenses

(5)

Gain from operations of discontinued components

~~Current assets -~~Gain on disposal of discontinued operations, net of tax

19348

~~Property, plant and equipment, net~~

~~590~~

~~Intangible assets, net~~

~~Other non-current assets~~

~~Non-current assets - discontinued operations~~

~~603~~

~~Current portion of long-term debt and capital leases~~

~~Accounts payable~~

~~Other current liabilities~~

~~Current liabilities -~~Gain from discontinued operations,

~~Long-term debt and capital leases~~

~~572~~

~~Other non-current liabilities~~

~~Non-current liabilities - discontinued operations~~ including disposal, net of tax

~~574~~353

~~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~~$7 million and ~~$21~~$10 million during the ~~nine~~three months ended ~~September 30,~~March 31, 2020 and 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~~posted 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							March 31, 2020				December 31, 2019
		Carrying Amount		Fair Value		Carrying Amount		Fair Value
(In millions)										(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
		(In millions)
Assets:	Assets:									Assets:
Notes receivable	Notes receivable	$	11	$	8	$	17	$	14	Notes receivable	$	10	$	7	$	11	$	8
Liabilities:	Liabilities:									Liabilities:
Long-term debt, including current portion^(a)	Long-term debt, including current portion^(a)	6,168		6,706		6,591		6,697		Long-term debt, including current portion^(a)	6,510		6,634		5,956		6,504

(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~~March 31, 2020 and December 31, ~~2018:~~2019:

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


	March 31, 2020						December 31, 2019
(In millions)	Level 2		Level 3		Level 2		Level 3
Long-term debt, including current portion	$	5,967	$	667	$	6,388	$	116

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															March 31, 2020

(In millions)	(In millions)	Total		Level 1		Level 2		Level 3		(In millions)	Total		Level 1		Level 2		Level 3
Investments in securities (classified within other current and non-current assets)	Investments in securities (classified within other current and non-current assets)	$	24	$	—	$	19	$	5	Investments in securities (classified within other current and non-current assets)	$	13	$	—	$	13	$	—

Nuclear trust fund investments:	Nuclear trust fund investments:									Nuclear trust fund investments:
Cash and cash equivalents	Cash and cash equivalents	20		20		—		—		Cash and cash equivalents	21		21		—		—
U.S. government and federal agency obligations	U.S. government and federal agency obligations	51		51		—		—		U.S. government and federal agency obligations	57		56		1		—
Federal agency mortgage-backed securities	Federal agency mortgage-backed securities	97		—		97		—		Federal agency mortgage-backed securities	93		—		93		—
Commercial mortgage-backed securities	Commercial mortgage-backed securities	27		—		27		—		Commercial mortgage-backed securities	33		—		33		—
Corporate debt securities	Corporate debt securities	112		—		112		—		Corporate debt securities	125		—		125		—
Equity securities	Equity securities	372		372		—		—		Equity securities	308		308		—		—
Foreign government fixed income securities	Foreign government fixed income securities	5		—		5		—		Foreign government fixed income securities	5		—		5		—
Other trust fund investments:	Other trust fund investments:									Other trust fund investments:
U.S. government and federal agency obligations	U.S. government and federal agency obligations	1		1		—		—		U.S. government and federal agency obligations	1		1		—		—
Derivative assets:	Derivative assets:									Derivative assets:
Commodity contracts	Commodity contracts	1,093		92		878		123		Commodity contracts	1,318		111		1,015		192

Measured using net asset value practical expedient:	Measured using net asset value practical expedient:									Measured using net asset value practical expedient:
Equity securities — nuclear trust fund investments	Equity securities — nuclear trust fund investments	72								Equity securities — nuclear trust fund investments	60
Equity securities	Equity securities	7								Equity securities	6
Total assets	Total assets	$	1,881	$	536	$	1,138	$	128	Total assets	$	2,040	$	497	$	1,285	$	192
Derivative liabilities:	Derivative liabilities:									Derivative liabilities:
Commodity contracts	Commodity contracts	$	1,032	$	151	$	771	$	110	Commodity contracts	$	1,202	$	193	$	890	$	119

Total liabilities	Total liabilities	$	1,032	$	151	$	771	$	110	Total liabilities	$	1,202	$	193	$	890	$	119

2520


		December 31, 2018															December 31, 2019

(In millions)	(In millions)	Total		Level 1		Level 2		Level 3		(In millions)	Total		Level 1		Level 2		Level 3
Investments in securities (classified within other current and non-current assets)	Investments in securities (classified within other current and non-current assets)	$	39	$	2	$	18	$	19	Investments in securities (classified within other current and non-current assets)	$	20	$	—	$	20	$	—
Nuclear trust fund investments:	Nuclear trust fund investments:									Nuclear trust fund investments:
Cash and cash equivalents	Cash and cash equivalents	19		19		—		—		Cash and cash equivalents	17		17		—		—
U.S. government and federal agency obligations	U.S. government and federal agency obligations	46		46		—		—		U.S. government and federal agency obligations	68		68		—		—
Federal agency mortgage-backed securities	Federal agency mortgage-backed securities	100		—		100		—		Federal agency mortgage-backed securities	100		—		100		—
Commercial mortgage-backed securities	Commercial mortgage-backed securities	22		—		22		—		Commercial mortgage-backed securities	29		—		29		—
Corporate debt securities	Corporate debt securities	96		—		96		—		Corporate debt securities	109		—		109		—
Equity securities	Equity securities	312		312		—		—		Equity securities	388		388		—		—
Foreign government fixed income securities	Foreign government fixed income securities	4		—		4		—		Foreign government fixed income securities	5		—		5		—
Other trust fund investments:	Other trust fund investments:									Other trust fund investments:
U.S. government and federal agency obligations	U.S. government and federal agency obligations	1		1		—		—		U.S. government and federal agency obligations	1		1		—		—
Derivative assets:	Derivative assets:									Derivative assets:
Commodity contracts	Commodity contracts	1,042		137		796		109		Commodity contracts	1,170		84		893		193
Interest rate contracts		39		—		39		—

Measured using net asset value practical expedient:	Measured using net asset value practical expedient:									Measured using net asset value practical expedient:
Equity securities — nuclear trust fund investments	Equity securities — nuclear trust fund investments	64								Equity securities — nuclear trust fund investments	78
Equity securities	Equity securities	8								Equity securities	8
Total assets	Total assets	$	1,792	$	517	$	1,075	$	128	Total assets	$	1,993	$	558	$	1,156	$	193
Derivative liabilities:	Derivative liabilities:									Derivative liabilities:
Commodity contracts	Commodity contracts	$	977	$	224	$	664	$	89	Commodity contracts	$	1,103	$	143	$	805	$	155

Total liabilities	Total liabilities	$	977	$	224	$	664	$	89	Total liabilities	$	1,103	$	143	$	805	$	155

~~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,~~table reconciles, for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2020 and 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)																							Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
		Three months ended September 30, 2018										Nine months ended September 30, 2018										Three months ended March 31, 2020				Three months ended March 31, 2019
(In millions)	(In millions)	Debt Securities		Derivatives^(a)		Total		Debt Securities		Derivatives^(a)			Total		(In millions)	Derivatives^(a)		Debt Securities		Derivatives^(a)			Total
Beginning balance	Beginning balance	$	19	$	174	$	193	$	19	$	(15)		$	4	Beginning balance	$	38	$	19	$	20		$	39
Contracts added in XOOM acquisition		—		—		—		—		12			12
Total (losses) — realized/unrealized included in earnings		—		—		—		—		(15)			(15)

Total gains/(losses) realized/unrealized— included in earnings															Total gains/(losses) realized/unrealized— included in earnings	22		—		(10)			(10)

Cash received															Cash received	—		(1)		—			(1)
Purchases	Purchases	—		12		12		—		9			9		Purchases	8		—		(2)			(2)
Transfers into Level 3^(b)	Transfers into Level 3^(b)	—		(201)		(201)		—		(4)			(4)		Transfers into Level 3^(b)	8		—		17			17
Transfers out of Level 3^(b)	Transfers out of Level 3^(b)	—		2		2		—		—			—		Transfers out of Level 3^(b)	(3)		—		(27)			(27)
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)
Ending balance															Ending balance	$	73	$	18	$	(2)		$	16
(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 period end															(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 period end	$	(9)	$	—	$	(12)		$	(12)

(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,~~March 31, 2020, contracts valued with prices provided by models and other valuation techniques make up ~~11%~~15% of derivative assets and ~~11%~~10% 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~~March 31, 2020 and December 31, ~~2018:~~2019:


		September 30, 2019																							March 31, 2020
		Fair Value										Input/Range									Fair Value						Input/Range
		Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low		High		Weighted Average
		(In millions)
(In millions)														(In millions)	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low		High		Weighted Average
Power Contracts	Power Contracts	$	89	$	98	Discounted Cash Flow	Forward Market Price (per MWh)	$	6	$	217	$	22	Power Contracts	$	150	$	107	Discounted Cash Flow	Forward Market Price (per MWh)	$	6	$	165	$	25

FTRs	FTRs	34		12		Discounted Cash Flow	Auction Prices (per MWh)	(134)		60		0		FTRs	42		12		Discounted Cash Flow	Auction Prices (per MWh)	(380)		91		0
		$	123	$	110										$	192	$	119


		December 31, 2018																							December 31, 2019
		Fair Value										Input/Range									Fair Value						Input/Range
		Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low		High		Weighted Average
		(In millions)
(In millions)														(In millions)	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low		High		Weighted Average
Power Contracts	Power Contracts	$	89	$	75	Discounted Cash Flow	Forward Market Price (per MWh)	$	1	$	214	$	31	Power Contracts	$	151	$	139	Discounted Cash Flow	Forward Market Price (per MWh)	$	8	$	218	$	24

FTRs	FTRs	20		14		Discounted Cash Flow	Auction Prices (per MWh)	(90)		34		0		FTRs	42		16		Discounted Cash Flow	Auction Prices (per MWh)	(105)		213		0
		$	109	$	89										$	193	$	155

The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable inputs as of ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018:~~2019:

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,~~March 31, 2020, the credit reserve resulted in a $1$2 million decrease in operating revenue and cost of operations. As of December 31, ~~2018,~~2019, 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~~2019 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.

2822

Counterparty Credit Risk

The Company's counterparty credit risk policies are disclosed in its ~~2018~~2019 Form 10-K. As of ~~September 30, 2019,~~March 31, 2020, counterparty credit exposure, excluding credit exposure from RTOs, ISOs, registered commodity exchanges and certain long-term agreements, was ~~$242~~$346 million and NRG held collateral (cash and letters of credit) against those positions of ~~$55~~$54 million, resulting in a net exposure of ~~$226~~$293 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%~~54% of the Company's exposure before collateral is expected to roll off by the end of ~~2020.~~2021. 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	8481	%
Financial institutions	1619

Total as of ~~September 30, 2019~~March 31, 2020	100	%


	Net Exposure ^(a)(b)
Category by Counterparty Credit Quality	(% of Total)
Investment grade	5453	%
Non-investment grade/non-rated	4647
Total as of ~~September 30, 2019~~March 31, 2020	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 0$47 million of exposure to one wholesale ~~counterparties~~counterparty in excess of 10% of total net exposure discussed above as of ~~September 30, 2019.~~March 31, 2020. 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,~~March 31, 2020, aggregate credit risk exposure managed by NRG to these counterparties was approximately ~~$518~~$689 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,~~ Caliente.

~~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,~~March 31, 2020, 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. The Company is also subject to risk with respect to its residential solar customers. Current economic conditions may affect the Company's customers' ability to pay bills in a timely manner, which could increase customer delinquencies and may lead to an increase in credit losses.

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													As of March 31, 2020			As of December 31, 2019
(In millions, except maturities)	(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)	(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	Cash and cash equivalents	$	20	$	—	$	—	—	$	19	$	—	$	—	—	Cash and cash equivalents	$	21	$	—	$	—	—	$	17	$	—	$	—	—
U.S. government and federal agency obligations	U.S. government and federal agency obligations	51		5		—		13	46		1		—		12	U.S. government and federal agency obligations	57		10		—		14	68		4		—		11
Federal agency mortgage-backed securities	Federal agency mortgage-backed securities	97		3		—		24	100		1		2		23	Federal agency mortgage-backed securities	93		4		—		24	100		3		—		24
Commercial mortgage-backed securities	Commercial mortgage-backed securities	27		1		1		24	22		—		1		22	Commercial mortgage-backed securities	33		1		1		26	29		1		1		24
Corporate debt securities	Corporate debt securities	112		6		—		11	96		1		2		11	Corporate debt securities	125		5		4		12	109		6		—		11
Equity securities	Equity securities	444		295		—		—	376		231		1		—	Equity securities	368		228		1		—	466		324		—		—
Foreign government fixed income securities	Foreign government fixed income securities	5		—		—		10	4		—		—		9	Foreign government fixed income securities	5		—		—		10	5		—		—		10
Total	Total	$	756	$	310	$	1		$	663	$	234	$	6		Total	$	702	$	248	$	6		$	794	$	338	$	1

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,							Three months ended March 31,
		2019		2018
		(In millions)
(In millions)						(In millions)	2020		2019
Realized gains	Realized gains	$	8	$	8	Realized gains	$	2	$	3
Realized losses	Realized losses	(7)		(8)		Realized losses	(5)		(2)
Proceeds from sale of securities	Proceeds from sale of securities	271		398		Proceeds from sale of securities	112		113

3024

Note 7 — Accounting for Derivative Instruments and Hedging Activities

Energy-Related Commodities

As of ~~September 30, 2019,~~March 31, 2020, 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~~2036 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,~~March 31, 2020, 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~~March 31, 2020 and December 31, ~~2018.~~2019. 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

Total Volume (In millions)

Category

Units

March 31, 2020

December 31, 2019

Emissions

Short Ton

(2)

Emissions

Short Ton

Renewable Energy Certificates

Certificates

Renewable Energy Certificates

Certificates

Coal

Short Ton

Coal

Short Ton

Natural Gas

MMBtu

(273)

(330)

Natural Gas

MMBtu

(152)

(181)

Oil

Barrels

—

Power

MWh

Power

MWh

Capacity

MW/Day

(1)

Capacity

MW/Day

(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															Fair Value
		Derivative Assets						Derivative Liabilities							Derivative Assets				Derivative Liabilities
		September 30, 2019		December 31, 2018		September 30, 2019		December 31, 2018
		(In millions)
(In millions)										(In millions)	March 31, 2020		December 31, 2019		March 31, 2020		December 31, 2019

Derivatives Not Designated as Cash Flow or Fair Value Hedges:	Derivatives Not Designated as Cash Flow or Fair Value Hedges:									Derivatives Not Designated as Cash Flow or Fair Value Hedges:
Interest rate contracts current		$	—	$	17	$	—	$	—
Interest rate contracts long-term		—		22		—		—

Commodity contracts current	Commodity contracts current	735		747		668		673		Commodity contracts current	$	884	$	860	$	832	$	781
Commodity contracts long-term	Commodity contracts long-term	358		295		364		304		Commodity contracts long-term	434		310		370		322
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges	Total Derivatives Not Designated as Cash Flow or Fair Value Hedges	$	1,093	$	1,081	$	1,032	$	977	Total Derivatives Not Designated as Cash Flow or Fair Value Hedges	$	1,318	$	1,170	$	1,202	$	1,103

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 Not Offset in the Statement of Financial Position
		Gross Amounts of Recognized Assets / Liabilities		Derivative Instruments		Cash Collateral (Held) / Posted		Net Amount
		(In millions)
(In millions)										(In millions)	Gross Amounts of Recognized Assets / Liabilities		Derivative Instruments		Cash Collateral (Held) / Posted		Net Amount
As of March 31, 2020										As of March 31, 2020
Commodity contracts:	Commodity contracts:									Commodity contracts:
Derivative assets	Derivative assets	$	1,093	$	(869)	$	(5)	$	219	Derivative assets	$	1,318	$	(1,010)	$	(17)	$	291
Derivative liabilities	Derivative liabilities	(1,032)		869		70		(93)		Derivative liabilities	(1,202)		1,010		94		(98)
Total commodity contracts	Total commodity contracts	$	61	$	—	$	65	$	126	Total commodity contracts	$	116	$	—	$	77	$	193

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~~25

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


	Gross Amounts Not Offset in the Statement of Financial Position
(In millions)	Gross Amounts of Recognized Assets / Liabilities		Derivative Instruments		Cash Collateral (Held) / Posted		Net Amount
As of December 31, 2019
Commodity contracts:
Derivative assets	$	1,170	$	(909)	$	(7)	$	254
Derivative liabilities	(1,103)		909		73		(121)
Total commodity contracts	$	67	$	—	$	66	$	133

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 and fair value 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 or fair value 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


(In millions)	Three months ended March 31,
Unrealized mark-to-market results	2020		2019
Reversal of previously recognized unrealized losses on settled positions related to economic hedges	$	9	$	19
Reversal of acquired loss/(gain) positions related to economic hedges	1		(2)
Net unrealized gains on open positions related to economic hedges	34		3
Total unrealized mark-to-market gains for economic hedging activities	44		20
Reversal of previously recognized unrealized (gains) on settled positions related to trading activity	(2)		(6)
Net unrealized gains on open positions related to trading activity	13		13
Total unrealized mark-to-market gains for trading activity	11		7
Total unrealized gains	$	55	$	27


		Three months ended September 30,						Nine months ended September 30,							Three months ended March 31,
		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
(In millions)										(In millions)	2020		2019
Unrealized gains included in operating revenues										Unrealized gains included in operating revenues	$	7	$	27
Unrealized gains included in cost of operations										Unrealized gains included in cost of operations	48		—
Total impact to statement of operations — energy commodities	Total impact to statement of operations — energy commodities	$	(68)	$	(64)	$	(8)	$	79	Total impact to statement of operations — energy commodities	$	55	$	27
Total impact to statement of operations — interest rate contracts	Total impact to statement of operations — interest rate contracts	$	—	$	2	$	(38)	$	17	Total impact to statement of operations — interest rate contracts	$	—	$	(9)

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

For the ~~nine~~three months ended ~~September 30, 2019,~~March 31, 2020, the ~~$69~~$34 million unrealized gain from open economic hedge positions was primarily the result of an increase in value of forward ~~purchases~~power positions due to a decrease in West/Other power prices, as well as an increase in value of ERCOT heat rate positions due to ERCOT heat rate expansion.

For the ~~nine~~three months ended ~~September 30, 2018,~~March 31, 2019, the ~~$158~~$3 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~~power positions due to ~~ERCOT heat rate expansion and increases~~a decrease 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~~March 31, 2020 was ~~$39~~$12 million. The collateral required for contracts with credit rating contingent features that are in a net liability position as of ~~September 30, 2019~~March 31, 2020 was ~~$18~~$25 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$1 million as of ~~September 30, 2019.~~March 31, 2020.

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~~Impairments

Petra Nova Parish Holdings — — During the ~~third~~first 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 related2020, due to the ~~project level debt provided by~~decline in oil prices, 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~~to estimate 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~~$18 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~~Texas segment, which includes the ~~carrying amount~~anticipated drawdown of the ~~assets~~$12 million letter of credit posted in September 2019 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~~cover certain 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.~~debt reserve requirements.

Note 109 — Long-term Debt ~~and Finance Leases~~

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


(In millions, except rates)	(In millions, except rates)	September 30, 2019		December 31, 2018		September 30, 2019 Interest rate %	(In millions, except rates)	March 31, 2020		December 31, 2019		Interest rate %

Recourse debt:	Recourse debt:						Recourse debt:
Senior Notes, due 2024		$	—	$	733	6.250
Senior Notes, due 2026	Senior Notes, due 2026	1,000		1,000		7.250	Senior Notes, due 2026	$	1,000	$	1,000	7.250
Senior Notes, due 2027	Senior Notes, due 2027	1,230		1,230		6.625	Senior Notes, due 2027	1,230		1,230		6.625
Senior Notes, due 2028	Senior Notes, due 2028	821		821		5.750	Senior Notes, due 2028	821		821		5.750
Senior Notes, due 2029	Senior Notes, due 2029	733		—		5.250	Senior Notes, due 2029	733		733		5.250
Convertible Senior Notes, due 2048	Convertible Senior Notes, due 2048	575		575		2.750	Convertible Senior Notes, due 2048	575		575		2.750
Senior Secured First Lien Notes, due 2024	Senior Secured First Lien Notes, due 2024	600		—		3.750	Senior Secured First Lien Notes, due 2024	600		600		3.750
Senior Secured First Lien Notes, due 2029	Senior Secured First Lien Notes, due 2029	500		—		4.450	Senior Secured First Lien Notes, due 2029	500		500		4.450
Term Loan Facility ^(a)		—		1,698		L+ 0.0175
Revolver Facility ^(b)		215		—		L+ 0.0175 - P+ 0.0075
Revolving Credit Facility^(a)							Revolving Credit Facility^(a)	635		83		L+ 1.750
Tax-exempt bonds	Tax-exempt bonds	466		466		0.04125 - 0.06	Tax-exempt bonds	466		466		1.300 - 6.000
Subtotal recourse debt	Subtotal recourse debt	6,140		6,523			Subtotal recourse debt	6,560		6,008
Non-recourse debt:	Non-recourse debt:						Non-recourse debt:
Agua Caliente Borrower 1, due 2038		83		86		5.430
Midwest Generation		—		48		4.390

Other	Other	34		34		various	Other	32		34		various
Subtotal all non-recourse debt	Subtotal all non-recourse debt	117		168			Subtotal all non-recourse debt	32		34
Subtotal long-term debt (including current maturities)	Subtotal long-term debt (including current maturities)	6,257		6,691			Subtotal long-term debt (including current maturities)	6,592		6,042
Finance leases		—		1		6.500

Subtotal long-term debt and finance leases (including current maturities)		6,257		6,692

Less current maturities	Less current maturities	(302)		(72)			Less current maturities	(640)		(88)
Less debt issuance costs	Less debt issuance costs	(68)		(70)			Less debt issuance costs	(63)		(65)
Discounts	Discounts	(89)		(101)			Discounts	(82)		(86)
Total long-term debt and finance leases		$	5,798	$	6,449
Total long-term debt							Total long-term debt	$	5,807	$	5,803

(a) As of ~~December~~March 31, ~~2018,~~2020, the ~~interest rate was 1-month LIBOR plus 1.75%~~

~~(b) As~~Company had drawn under its Revolving Credit Facility using a mix of ~~September 30, 2019, L is equal to~~ 1-week LIBOR and ~~P is equal to Prime Rate~~1-month LIBOR + 1.750

Recourse Debt

Revolving Credit Facility

~~Senior Notes~~The Company had $635 million and $83 million outstanding under its Revolving Credit Facility as of March 31, 2020 and December 31, 2019, respectively. Due to market conditions, primarily as a result of COVID-19, the Company drew upon the facility in the first quarter of 2020 as a precaution and to proportionally increase cash on hand. As of May 7, 2020, the Company had $250 million outstanding under its Revolving Credit Facility.

~~Issuance of 2029 Senior Notes~~

Tax-Exempt Bonds

On ~~May 14, 2019,~~March 11, 2020, NRG issued ~~$733~~$59 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~~in aggregate principal amount of ~~senior secured first lien notes, consisting of $600 million 3.75% senior secured first lien notes~~NRG Dunkirk 2020 1.30% tax-exempt refinancing bonds due ~~2024 and $500 million 4.45% senior secured first lien notes due 2029, or~~ 2042 ("the ~~Senior Secured First Lien Notes, at a discount.~~Bonds"). The ~~Senior Secured First Lien Notes~~Bonds 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~~Bonds are 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~~Bonds will, at the request of NRG, be released if ~~the Company obtains~~NRG satisfies certain conditions, including receipt of an investment grade rating on its senior, unsecured debt securities from two out of the three rating agencies, subject to ~~an obligation to reinstate the collateral~~reversion if ~~such~~those rating agencies withdraw ~~the Company's~~their investment grade rating of the Bonds or any of NRG’s senior, unsecured debt securities or downgrade ~~its~~such rating below investment grade. ~~Interest will be paid semi-annually beginning~~The Bonds are subject to mandatory tender and purchase on ~~December 15, 2019, until the maturity dates of June 15, 2024~~April 3, 2023 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~~have 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 thefinal 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.

April 1, 2042.

3727

NRG used the net proceeds from the offering to redeem the existing principal amount of outstanding Dunkirk Power LLC 5.875% tax exempt bonds due 2042.

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,~~March 31, 2020, the full $80 million was issued.

Note 1110 — 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 primary operating subsidiary utility PG&E filed for Chapter 11 ~~bankruptcy protection. As part of their filing, PG&E asked~~relief in the United States Bankruptcy Court ~~to confirm exclusive jurisdiction over their "rights to reject" PPAs or other contracts regulated by FERC~~for the Northern District of California (the "California Bankruptcy Court").. As a result of the bankruptcy filing, ~~the~~ Agua Caliente and the two Ivanpah ~~projects~~units have issued notices of events of default under their respective loan agreements. The Ivanpah project signed a forbearance agreement with the ~~Department of Energy~~U.S. DOE 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~~There are many conditions that must be satisfied before the PG&E plan and assumption of ~~unsecured creditors filed a competing plan of reorganization that would also assume all~~the power purchase agreements can become effective, including, ~~those held~~but not limited to, formal approvals by various classes of creditors, the ~~Agua Caliente project~~California Bankruptcy Court, and the ~~two Ivanpah units.~~ CPUC. A hearing before the California Bankruptcy Court to consider whether the PG&E plan will be approved and confirmed is currently expected to occur on May 29, 2020.

NRG's maximum exposure to loss is limited to its equity investment, which was $213 million for Agua Caliente and ~~$28~~$6 million for Ivanpah as of ~~September 30, 2019. See Note 10,~~ ~~Debt and Finance Leases,~~ ~~for further discussion on Agua Caliente.~~March 31, 2020.

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 ~~3 solar electric generating projects located in~~ the ~~Mojave Desert with a total capacity of 393 MW.~~Ivanpah projects. 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~~2019 Form 10-K. During the first quarter of 2020, the Company repurchased its partners' equity interest in one of the partnerships. As the Company retains control of its interest, the repurchase was recorded to equity.

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


(In millions)	(In millions)	September 30, 2019		December 31, 2018		(In millions)	March 31, 2020		December 31, 2019
Current assets	Current assets	$	3	$	3	Current assets	$	1	$	3
Net property, plant and equipment	Net property, plant and equipment	73		76		Net property, plant and equipment	—		71
Other long-term assets	Other long-term assets	28		28		Other long-term assets	26		27
Total assets	Total assets	104		107		Total assets	27		101
Current liabilities	Current liabilities	1		2		Current liabilities	4		4
Long-term debt	Long-term debt	28		29		Long-term debt	24		24

Other long-term liabilities	Other long-term liabilities	8		7		Other long-term liabilities	4		8
Total liabilities	Total liabilities	37		38		Total liabilities	32		36
Redeemable noncontrolling interest	Redeemable noncontrolling interest	19		19		Redeemable noncontrolling interest	—		20

Net assets less noncontrolling interest	Net assets less noncontrolling interest	$	48	$	50	Net assets less noncontrolling interest	$	(5)	$	45

Note 1211 — Changes in Capital Structure

As of ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018,~~2019, 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


	Issued	Treasury	Outstanding
Balance as of December 31, 2019	421,890,790	(172,894,601)	248,996,189
Shares issued under LTIPs	1,089,103	—	1,089,103

Shares repurchased	—	(4,461,438)	(4,461,438)
Balance as of March 31, 2020	422,979,893	(177,356,039)	245,623,854
Shares issued under LTIPs	1,096	—	1,096
Shares issued under ESPP	—	63,455	63,455
Shares repurchased	—	(1,601,345)	(1,601,345)
Balance as of May 7, 2020	422,980,989	(178,893,929)	244,087,060

Share Repurchases

The Company adopted in the fourth quarter of 2019 a long-term capital allocation policy that targets 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 below, supplemented by share repurchases. The following repurchases have been made during the ~~nine~~three months ended ~~September 30, 2019~~March 31, 2020 and through ~~October 31, 2019 under the share repurchase programs:~~May 7, 2020:

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


	Total number of shares purchased	Average price paid per share	Amounts paid for shares purchased (in millions)
2020 repurchases:
Repurchases	4,461,438		$	150
Equivalent shares purchased in lieu of tax withholdings on equity compensation issuances^(a)	710,063		27

Total Share Repurchases during the three months ended March 31, 2020	5,171,501	$34.20	177
Repurchases made subsequent to March 31, 2020	1,601,345		$	47
Total Share Repurchases January 1, 2020 through May 7, 2020	6,772,846	$33.05	$	224

(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~~NRG elected to ~~repurchase a total~~pay cash for tax withholding on equity awards instead of ~~$400 million of outstanding common stock based on a volume weighted average price. The Company received initial~~issuing actual 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.~~management. The average price ~~paid for all the~~per equivalent shares ~~delivered under the ASR Agreement~~withheld 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.~~$38.24

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~~April 2020, 63,455 shares of common stock were issued to employee accounts from treasury stock for the offering period of ~~April~~October 1, 2019 to ~~September 30, 2019.~~March 31, 2020.

NRG Common Stock Dividends

Beginning in the first quarter of 2020, NRG increased the annual dividend to $1.20 from $0.12 per share and expects to target an annual dividend growth rate of 7-9% per share in subsequent years. A quarterly dividend of ~~$0.03~~$0.30 per share was paid on the Company's common stock during the three months ended ~~September 30, 2019.~~March 31, 2020. On ~~October 17, 2019,~~April 15, 2020, NRG declared a quarterly dividend on the Company's common stock of ~~$0.03~~$0.30 per share, payable ~~November~~May 15, ~~2019,~~2020 to stockholders of record as of ~~November~~May 1, ~~2019, representing $0.12 per share on an annualized basis.~~2020.

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.~~

4029

Note 1312 — Earnings Per Share

Basic ~~earnings~~income 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~~income 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


	Three months ended March 31,
(In millions, except per share data)	2020		2019
Basic income per share:
Net income available to common shareholders	$	121	$	482
Weighted average number of common shares outstanding - basic	248		278
Income per weighted average common share — basic	$	0.49	$	1.73

Diluted income per share:


Net income available to common shareholders	$	121	$	482
Weighted average number of common shares outstanding - basic	248		278
Incremental shares attributable to the issuance of equity compensation (treasury stock method)	1		2
Weighted average number of common shares outstanding - dilutive	249		280
Income per weighted average common share — diluted	$	0.49	$	1.72

~~The following table summarizes NRG’s~~As of March 31, 2020 and 2019 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 — —
share were not significant.

Note 1413 — Segment Reporting

As part of perfecting the integrated model, in which the majority of the Company’s generation serves its retail customers, the Company began managing its operations based on the combined results of the retail and wholesale generation businesses with a geographical focus in 2020. As a result, the Company changed its business segments from Retail and Generation to Texas, East and West/Other beginning in the first quarter of 2020, as further described in Note 1, Nature of Business. The Company's updated 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.resources The financial information for the ~~nine~~three months ended ~~September 30, 2018 has been~~March 31, 2019 was recast to reflect the current segment structure.

OnIn February 4, 2019, as described in Note 4, ~~Acquisitions,~~ Discontinued Operations and Dispositions, the Company completed the ~~sale~~sales of ~~and deconsolidated~~ the South Central ~~Portfolio. On August 31, 2018, as described in Note 4,~~ ~~Acquisitions, Discontinued Operations~~Portfolio and ~~Dispositions,~~ ~~NRG deconsolidated NRG Yield, Inc., its Renewables Platform and Carlsbadfor financial reporting purposes.~~Carlsbad. The financial information for the three months ended March 31, 2019 presented below ~~has been recast to reflect~~reflects 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 allocation of capital, ~~for allocation,~~ as well as net income/(loss) ~~and net income/(loss) attributable to NRG Energy, Inc.~~.

4130

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


	Three months ended March 31, 2020
(In millions)	Texas		East		West/Other		Corporate		Eliminations		Total
Operating revenues	$	1,358	$	539	$	125	$	—	$	(3)	$	2,019
Depreciation and amortization	59		33		8		9		—		109

Reorganization costs	1		—		—		2		—		3
Gain on sale of assets	—		—		1		5		—		6
Equity in losses of unconsolidated affiliates	—		—		(11)		—		—		(11)

Income/(loss) from continuing operations before income taxes	162		24		41		(82)		(1)		144



Net income/(loss)	$	162	$	24	$	41	$	(105)	$	(1)	$	121

^(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)


	Three months ended March 31, 2019
(In millions)	Texas		East		West/Other		Corporate		Eliminations		Total
Operating revenues	$	1,466	$	609	$	93	$	(1)	$	(2)	$	2,165
Depreciation and amortization	40		26		11		8		—		85

Reorganization costs	1		—		—		12		—		13
Gain on sale of assets	—		1		—		—		—		1
Equity in losses of unconsolidated affiliates	(3)		—		(18)		—		—		(21)


Income/(loss) from continuing operations before income taxes	150		99		(23)		(127)		(1)		98
Income/(loss) from continuing operations	150		99		(23)		(131)		(1)		94
Income from discontinued operations, net of tax	—		—		—		388		—		388

Net income/(loss)	$	150	$	99	$	(23)	$	257	$	(1)	$	482

^(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 1514 — 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 %


	Three months ended March 31,
(In millions, except rates)	2020			2019
Income from continuing operations before income taxes	$	144		$	98
Income tax expense from continuing operations	23			4

Effective income tax rate	16.0		%	4.1		%

For the three ~~and nine~~ months ended ~~September 30, 2019 and 2018, NRG's overall~~March 31, 2020, the effective tax ~~rates were~~rate was lower than the statutory rate of 21%, primarily due to an excess tax benefit related to share-based compensation, partially offset by state tax expense. For the three months ended March 31, 2019, the effective tax rate was lower than the statutory rate of 21%, primarily due to the tax benefit for the change in valuation allowance, partially offset by ~~current~~ state tax expense.

On March 27, 2020, the Senate passed the CARES Act to provide emergency relief related to the COVID-19 pandemic. The CARES Act contains federal income tax provisions which, among other things: (i) increases the amount of interest expense that businesses are allowed to deduct by increasing the adjusted taxable income limitation from 30% to 50% for tax years that begin in 2019 and 2020; (ii) permits businesses to carry back to each of the five tax years NOLs arising from tax years beginning after December 31, 2017 and before January 1, 2020; and (iii) temporarily removes the 80% limitation on NOLs until tax years beginning after 2020. NRG does not expect the CARES Act provisions to have a material impact on the tax positions of the Company.

Uncertain Tax Benefits

As of ~~September 30, 2019,~~March 31, 2020, NRG ~~has recorded~~had a non-current tax liability of ~~$29~~$16 million for uncertain tax benefits from positions taken on various state income tax returns ~~including~~and accrued interest. For the ~~nine~~three months ended ~~September 30, 2019,~~March 31, 2020, NRG accrued an immaterial amount of interest relating to the uncertain tax benefits. As of ~~September 30, 2019,~~March 31, 2020, NRG had cumulative interest and penalties related to these uncertain tax benefits of $5$2 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.~~Australia and Canada. The Company is no longer subject to U.S. federal income tax examinations for years prior to ~~2015.~~2016. With few exceptions, state and local income tax examinations are no longer open for years ~~before 2010.~~prior to 2011.

Note 1615 — Related Party Transactions

NRG provides services to some of its equity method investments under operations and maintenance agreements. Fees for the services under these agreements include recovery of NRG's costs of operating the plants. Certain agreements also include fees for administrative service, a base monthly fee, profit margin and/or annual incentive bonus.

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


		Three months ended September 30,						Nine months ended September 30,							Three months ended March 31,
(In millions)										(In millions)	2020		2019
Revenues from Related Parties Included in Operating Revenues										Revenues from Related Parties Included in Operating Revenues
Gladstone										Gladstone	$	1	$	1

Ivanpah^(a)										Ivanpah^(a)	13		10
Midway-Sunset										Midway-Sunset	1		1
		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	Total	$	11	$	21	$	32	$	72	Total	$	15	$	12

~~Gladstone~~(a) ~~— NRG provides services to Gladstone, an equity method investment,~~Also includes fees 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~~agreements 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.company

Note 1716 — Commitments and Contingencies

Commitments

First Lien Structure

NRG has granted first liens to certain counterparties on a substantial portion of ~~the Company's~~property and assets ~~excluding NRG's assets that have project-level financing~~owned by NRG and the ~~assets~~guarantors of ~~certain non-guarantor subsidiaries,~~its senior debt. NRG uses the first lien structure to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or ~~MWh equivalents. The Company's lien~~gas used as a proxy for power. To the extent that the underlying hedge positions for a counterparty are out-of-the-money to NRG, the counterparties ~~may~~would have a claim ~~on NRG's assets to~~under the ~~extent market prices exceed the hedged price.~~first lien program. As of ~~September 30, 2019,~~March 31, 2020, all hedges under the first lien were in-the-money for NRG on a counterparty aggregate basis.

Jewett Mine Lignite Contract

The Company's Limestone facility historically ~~blended~~burned 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. The cost of the reclamation may exceed the value of the 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,~~17, Regulatory Matters, and Note ~~19,~~18, 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,~~In February 2020, 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~~dismissed this lawsuit without prejudice for lack of subject matter ~~jurisdiction, which~~jurisdiction. A motion to reconsider the judgement is ~~scheduled~~pending with the District Court. This matter has been appealed to ~~be argued on January 16, 2020.~~the United States Court of Appeals for the Fifth Circuit. 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 4 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.~~issues, which the court granted in part and denied in part on February 6, 2020. 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.

XOOM Energy Litigation — XOOM is a defendant in 2 purported class action lawsuits pending in Maryland and New York. The plaintiffs generally claim that they did not receive the savings they were promised in their natural gas and electricity bills. The parties in the Maryland lawsuit are briefing summary judgment and class certification. In the New York case, XOOM filed a motion to dismiss, which the court granted on September 21, 2018, later entering judgment in XOOM's favor on September 24, 2018. The plaintiffs in the New York case appealed to the U.S. Court of Appeals for the Second Circuit. On July 26, 2019, the Second Circuit reversed the judgment of the district court and remanded to the district court with instructions that plaintiffs be permitted to proceed on their proposed amended complaint. This matter was known and accrued for at the time of the acquisition.

Note 1817 — Regulatory Matters

Environmental regulatory matters are discussed within Note ~~19,~~18, 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.

California Station Power — As the result of unfavorable final and non-appealable litigation, the Company accrued a liability associated with consumption of station power at the Company's Encina power plant facility in California after August 30, 2010. The Company has established an appropriate accrual pending potential regulatory action by San Diego Gas & Electric regarding the Company's Encina facility.

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.~~2020.

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 1918 — 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 had 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,~~FGD, 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~~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. ~~Accordingly,~~On November 22, 2019, the EPA proposed amending the 2015 ELG rule by: (x) decreasing the stringency of the selenium limit (but increasing the stringency of the nitrate and mercury limits) for FGD wastewater; (y) relaxing the zero-discharge requirement for bottom ash transport water; and (z) changing several deadlines. The Company has eliminated its estimate of the environmental capital expenditures that would have been required to comply with permits ~~incorporating~~incorporation 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. On December 2, 2019, the EPA released for comment "Closure Part A Proposal" to revise the CCR Rule to address the D.C. Circuit's 2018 decision regarding the adequacy of clay-lined impoundments, obligations to close all unlined impoundments and related deadlines. On February 20, 2020, the EPA proposed the framework for developing and implementing a federal permit program for states that are not approved to administer the CCR rule. On March 3, 2020, the EPA proposed for comment "A Holistic Approach to Closure Part B," which proposes procedures for obtaining approval to operate existing impoundments with alternative liners. 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.

4734

Note 2019 — Condensed Consolidating Financial Information

As of ~~September 30, 2019,~~March 31, 2020, the Company had outstanding $4.4 billion of Senior Notes due from ~~2024~~2026 to 2048 and outstanding $1.1 billion of Senior Secured First Lien Notes due from 2024 to 2029, as shown in Note ~~10,~~9, Long-term 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:~~March 31, 2020:


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

4836

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.

4937

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the three months ended ~~September 30, 2019~~March 31, 2020

(Unaudited)


		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)		Eliminations^(a)		Consolidated
		(In millions)
(In millions)												(In millions)	Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)		Eliminations^(a)		Consolidated
Operating Revenues	Operating Revenues											Operating Revenues
Total operating revenues	Total operating revenues	$	2,473	$	525	$	—	$	(2)	$	2,996	Total operating revenues	$	1,778	$	252	$	—	$	(11)	$	2,019
Operating Costs and Expenses	Operating Costs and Expenses											Operating Costs and Expenses
Cost of operations	Cost of operations	1,728		421		6		(2)		2,153		Cost of operations	1,290		202		(24)		(11)		1,457
Depreciation and amortization	Depreciation and amortization	52		32		7		—		91		Depreciation and amortization	80		19		10		—		109

Selling, general and administrative	Selling, general and administrative	132		28		50		—		210		Selling, general and administrative	140		5		64		—		209
Reorganization costs	Reorganization costs	—		—		1		—		1		Reorganization costs	—		—		3		—		3
Development costs	Development costs	—		—		1		—		1		Development costs	—		—		3		—		3
Total operating costs and expenses	Total operating costs and expenses	1,912		481		65		(2)		2,456		Total operating costs and expenses	1,510		226		56		(11)		1,781

Gain on sale of assets												Gain on sale of assets	—		1		5		—		6
Operating Income/(Loss)	Operating Income/(Loss)	561		44		(65)		—		540		Operating Income/(Loss)	268		27		(51)		—		244
Other Income/(Expense)	Other Income/(Expense)											Other Income/(Expense)
Equity in earnings of consolidated subsidiaries	Equity in earnings of consolidated subsidiaries	20		—		537		(557)		—		Equity in earnings of consolidated subsidiaries	3		—		262		(265)		—
Equity in earnings of unconsolidated affiliates		—		29		—		—		29
Equity in losses of unconsolidated affiliates												Equity in losses of unconsolidated affiliates	—		(11)		—		—		(11)
Impairment losses on investments	Impairment losses on investments	—		(101)		(6)		—		(107)		Impairment losses on investments	—		(18)		—		—		(18)
Other income, net		11		1		5		—		17
Other income/(loss), net												Other income/(loss), net	3		(1)		25		—		27

Interest expense	Interest expense	(4)		(3)		(92)		—		(99)		Interest expense	(5)		(1)		(92)		—		(98)
Total other income/(expense)	Total other income/(expense)	27		(74)		444		(557)		(160)		Total other income/(expense)	1		(31)		195		(265)		(100)
Income/(Loss) from Continuing Operations Before Income Taxes	Income/(Loss) from Continuing Operations Before Income Taxes	588		(30)		379		(557)		380		Income/(Loss) from Continuing Operations Before Income Taxes	269		(4)		144		(265)		144
Income tax expense	Income tax expense	—		1		5		—		6		Income tax expense	—		—		23		—		23
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

Net Income/(Loss)												Net Income/(Loss)	$	269	$	(4)	$	121	$	(265)	$	121

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

5038

~~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~~March 31, 2020

(Unaudited)


		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)		Eliminations^(a)		Consolidated
		(In millions)
(In millions)												(In millions)	Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)		Eliminations^(a)		Consolidated
Net Income/(Loss)	Net Income/(Loss)	$	588	$	(31)	$	372	$	(557)	$	372	Net Income/(Loss)	$	269	$	(4)	$	121	$	(265)	$	121
Other Comprehensive Loss	Other Comprehensive Loss											Other Comprehensive Loss

Foreign currency translation adjustments, net	Foreign currency translation adjustments, net	(5)		(4)		(4)		9		(4)		Foreign currency translation adjustments, net	(15)		(15)		(15)		30		(15)
Available-for-sale securities, net		—		—		(14)		—		(14)

Defined benefit plans, net	Defined benefit plans, net	(40)		—		(41)		40		(41)		Defined benefit plans, net	2		—		—		(2)		—
Other comprehensive loss	Other comprehensive loss	(45)		(4)		(59)		49		(59)		Other comprehensive loss	(13)		(15)		(15)		28		(15)

Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.		$	543	$	(35)	$	313	$	(508)	$	313
Comprehensive Income/(Loss)												Comprehensive Income/(Loss)	$	256	$	(19)	$	106	$	(237)	$	106

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

5239

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING ~~STATEMENTS OF COMPREHENSIVE INCOME~~BALANCE SHEETS

~~For the nine months ended September 30, 2019~~March 31, 2020

(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


(In millions)	Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)		Eliminations^(a)		Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	—	$	19	$	740	$	—	$	759
Funds deposited by counterparties	51		—		—		—		51
Restricted cash	7		—		1		—		8
Accounts receivable, net	1,684		137		533		(1,439)		915
Inventory	287		85		—		—		372
Derivative instruments	882		35		—		(33)		884
Cash collateral paid in support of energy risk management activities	197		3		—		—		200

Prepayments and other current assets	222		8		60		—		290


Total current assets	3,330		287		1,334		(1,472)		3,479
Property, plant and equipment, net	1,372		1,046		155		—		2,573
Other Assets
Investment in subsidiaries	158		—		5,122		(5,280)		—
Equity investments in affiliates	—		350		—		—		350

Operating lease right-of-use assets, net	79		251		116		—		446
Goodwill	400		179		—		—		579
Intangible assets, net	729		40		—		—		769
Nuclear decommissioning trust fund	702		—		—		—		702
Derivative instruments	434		13		—		(13)		434
Deferred income taxes	435		(32)		2,862		—		3,265
Other non-current assets	163		27		35		—		225


Total other assets	3,100		828		8,135		(5,293)		6,770
Total Assets	$	7,802	$	2,161	$	9,624	$	(6,765)	$	12,822
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt	$	1	$	4	$	635	$	—	$	640
Current portion of operating lease liabilities	20		31		20		—		71
Accounts payable	1,016		125		1,006		(1,439)		708

Derivative instruments	852		13��		—		(33)		832
Cash collateral received in support of energy risk management activities	51		—		—		—		51
Accrued expenses and other current liabilities	259		31		260		—		550



Total current liabilities	2,199		204		1,921		(1,472)		2,852
Other Liabilities
Long-term debt	248		24		5,535		—		5,807
Non-current operating lease liabilities	64		295		114		—		473
Nuclear decommissioning reserve	303		—		—		—		303
Nuclear decommissioning trust liability	390		—		—		—		390

Derivative instruments	382		1		—		(13)		370
Deferred income taxes	—		15		—		—		15
Other non-current liabilities	438		120		518		—		1,076


Total other liabilities	1,825		455		6,167		(13)		8,434
Total Liabilities	4,024		659		8,088		(1,485)		11,286

Stockholders’ Equity	3,778		1,502		1,536		(5,280)		1,536
Total Liabilities and Stockholders’ Equity	$	7,802	$	2,161	$	9,624	$	(6,765)	$	12,822

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

5340

~~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~~three months ended ~~September 30, 2019~~March 31, 2020

(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


(In millions)	Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)		Eliminations^(a)		Consolidated
Cash Flows from Operating Activities
Net income/(loss)	$	269	$	(4)	$	121	$	(265)	$	121


Adjustments to reconcile net income/(loss) to cash provided by operating activities:
Distributions from and equity in earnings/(losses) of unconsolidated affiliates and consolidated subsidiaries	(3)		16		(262)		265		16
Depreciation and amortization	80		20		9		—		109
Accretion of asset retirement obligations	4		7		—		—		11
Provision for credit losses	24		—		—		—		24
Amortization of nuclear fuel	13		—		—		—		13
Amortization of financing costs and debt discount/premiums	—		—		6		—		6
Loss on debt extinguishment, net	—		—		1		—		1
Amortization of emission allowances and energy credits	2		5		—		—		7
Amortization of unearned equity compensation	—		—		5		—		5
Net gain on sale of assets and disposal of assets	(8)		(1)		(5)		—		(14)

Impairment losses	—		18		—		—		18
Changes in derivative instruments	(46)		—		—		—		(46)
Changes in deferred income taxes and liability for uncertain tax benefits	(14)		11		22		—		19
Changes in collateral deposits in support of energy risk management activities	4		5		—		—		9
Changes in nuclear decommissioning trust liability	8		—		—		—		8


Changes in other working capital	(130)		(14)		45		—		(99)


Net Cash Provided/(Used) by Operating Activities	203		63		(58)		—		208
Cash Flows from Investing Activities
Intercompany dividends	—		—		757		(757)		—

Capital expenditures	(50)		(6)		(10)		—		(66)

Net purchases of emission allowances	(8)		—		—		—		(8)
Investments in nuclear decommissioning trust fund securities	(121)		—		—		—		(121)
Proceeds from the sale of nuclear decommissioning trust fund securities	112		—		—		—		112
Proceeds from sale of assets, net of cash disposed and sale of discontinued operations, net of fees	10		—		5				15






Net Cash (Used)/Provided by Investing Activities	(57)		(6)		752		(757)		(68)
Cash Flows from Financing Activities

Intercompany dividends and transfers	(63)		(56)		(638)		757		—
Payments of dividends to common stockholders	—		—		(74)		—		(74)
Payments for share repurchase activity	—		—		(179)		—		(179)


Purchase of and distributions to noncontrolling interests from subsidiaries	—		(2)		—		—		(2)

Proceeds from issuance of long-term debt	—		—		59		—		59

Repayments of long-term debt	(59)		(1)		—		—		(60)
Net proceeds from Revolving Credit Facility	—		—		552		—		552

Other	(3)		—		—		—		(3)


Net Cash (Used)/Provided by Financing Activities	(125)		(59)		(280)		757		293


Net Increase/(Decrease) in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash	21		(2)		414		—		433
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period	37		21		327		—		385
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	$	58	$	19	$	741	$	—	$	818

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

5541

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the three months ended ~~September 30, 2018~~March 31, 2019

(Unaudited)


		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)		Eliminations^(a)		Consolidated
		(In millions)
(In millions)												(In millions)	Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)		Eliminations^(a)		Consolidated
Operating Revenues	Operating Revenues											Operating Revenues
Total operating revenues	Total operating revenues	$	2,521	$	441	$	—	$	(2)	$	2,960	Total operating revenues	$	1,769	$	395	$	—	$	1	$	2,165
Operating Costs and Expenses	Operating Costs and Expenses											Operating Costs and Expenses
Cost of operations	Cost of operations	1,937		294		9		(2)		2,238		Cost of operations	1,358		283		9		1		1,651
Depreciation and amortization	Depreciation and amortization	54		36		9		—		99		Depreciation and amortization	54		23		8		—		85

Selling, general and administrative	Selling, general and administrative	123		19		142		(73)		211		Selling, general and administrative	122		16		56		—		194
Reorganization costs	Reorganization costs	—		—		27		—		27		Reorganization costs	—		—		13		—		13
Development costs	Development costs	—		(2)		3		—		1		Development costs	—		—		2		—		2
Total operating costs and expenses	Total operating costs and expenses	2,114		347		190		(75)		2,576		Total operating costs and expenses	1,534		322		88		1		1,945

Gain on sale of assets	Gain on sale of assets	—		14		—		—		14		Gain on sale of assets	1		—		—		—		1
Operating Income/(Loss)	Operating Income/(Loss)	407		108		(190)		73		398		Operating Income/(Loss)	236		73		(88)		—		221
Other Income/(Expense)	Other Income/(Expense)											Other Income/(Expense)
Equity in earnings of consolidated subsidiaries	Equity in earnings of consolidated subsidiaries	6		—		470		(476)		—		Equity in earnings of consolidated subsidiaries	10		—		299		(309)		—
Equity in earnings/(losses) of unconsolidated affiliates		—		21		(1)		—		20
Impairment losses on investments		—		(1)		—		—		(1)
Equity in losses of unconsolidated affiliates												Equity in losses of unconsolidated affiliates	—		(21)		—		—		(21)

Other income, net	Other income, net	4		9		6		—		19		Other income, net	4		1		7		—		12
Loss on debt extinguishment, net		—		—		(19)		—		(19)

Interest expense	Interest expense	(4)		(8)		(110)		—		(122)		Interest expense	(4)		(4)		(106)		—		(114)
Total other income/(expense)	Total other income/(expense)	6		21		346		(476)		(103)		Total other income/(expense)	10		(24)		200		(309)		(123)
Income from Continuing Operations Before Income Taxes	Income from Continuing Operations Before Income Taxes	413		129		156		(403)		295		Income from Continuing Operations Before Income Taxes	246		49		112		(309)		98
Income tax expense/(benefit)		122		42		(156)		—		8
Income tax expense												Income tax expense	—		—		4		—		4
Income from Continuing Operations	Income from Continuing Operations	291		87		312		(403)		287		Income from Continuing Operations	246		49		108		(309)		94
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)
Income from discontinued operations, net of income tax												Income from discontinued operations, net of income tax	9		5		374		—		388

Net Income												Net Income	$	255	$	54	$	482	$	(309)	$	482

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

5642

~~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~~three months ended ~~September 30, 2018~~March 31, 2019

(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


(In millions)	Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)		Eliminations^(a)		Consolidated
Net Income	$	255	$	54	$	482	$	(309)	$	482
Other Comprehensive Income/(Loss)

Foreign currency translation adjustments, net	1		1		1		(2)		1

Defined benefit plans, net	—		—		(3)		—		(3)
Other comprehensive income/(loss)	1		1		(2)		(2)		(2)


Comprehensive Income	$	256	$	55	$	480	$	(311)	$	480

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

5943

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

December 31, ~~2018~~2019


		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)		Eliminations^(a)		Consolidated
(In millions)												(In millions)	Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)		Eliminations^(a)			Consolidated
ASSETS	ASSETS	(In millions)																			ASSETS
Current Assets	Current Assets											Current Assets
Cash and cash equivalents	Cash and cash equivalents	$	55	$	28	$	480	$	—	$	563	Cash and cash equivalents	$	—	$	20	$	325	$	—		$	345
Funds deposited by counterparties	Funds deposited by counterparties	33		—		—		—		33		Funds deposited by counterparties	32		—		—		—			32
Restricted cash	Restricted cash	7		10		—		—		17		Restricted cash	5		1		2		—			8
Accounts receivable, net	Accounts receivable, net	1,354		115		309		(754)		1,024		Accounts receivable, net	1,293		239		233		(740)			1,025
Inventory	Inventory	278		134		—		—		412		Inventory	272		111		—		—			383
Derivative instruments	Derivative instruments	779		50		16		(81)		764		Derivative instruments	856		45		—		(41)			860
Cash collateral paid in support of energy risk management activities	Cash collateral paid in support of energy risk management activities	275		12		—		—		287		Cash collateral paid in support of energy risk management activities	182		8		—		—			190

Prepayments and other current assets	Prepayments and other current assets	180		32		90		—		302		Prepayments and other current assets	170		8		67		—			245
Current assets - held-for-sale		—		1		—		—		1
Current assets - discontinued operations		177		20		—		—		197

Total current assets	Total current assets	3,138		402		895		(835)		3,600		Total current assets	2,810		432		627		(781)			3,088
Property, plant and equipment, net	Property, plant and equipment, net	1,938		957		153		—		3,048		Property, plant and equipment, net	1,483		952		158		—			2,593
Other Assets	Other Assets											Other Assets
Investment in subsidiaries	Investment in subsidiaries	446		—		4,707		(5,153)		—		Investment in subsidiaries	710		—		4,785		(5,495)			—
Equity investments in affiliates	Equity investments in affiliates	—		412		—		—		412		Equity investments in affiliates	—		388		—		—			388

Operating lease right-of-use assets, net												Operating lease right-of-use assets, net	81		261		122		—			464
Goodwill	Goodwill	359		214		—		—		573		Goodwill	359		220		—		—			579
Intangible assets, net	Intangible assets, net	422		169		—		—		591		Intangible assets, net	375		414		—		—			789
Nuclear decommissioning trust fund	Nuclear decommissioning trust fund	663		—		—		—		663		Nuclear decommissioning trust fund	794		—		—		—			794
Derivative instruments	Derivative instruments	296		4		22		(5)		317		Derivative instruments	308		15		—		(13)			310
Deferred income taxes	Deferred income taxes	6		(143)		183		—		46		Deferred income taxes	421		(19)		2,884		—			3,286
Other non-current assets	Other non-current assets	133		71		97		(12)		289		Other non-current assets	145		30		65		—			240
Non-current assets - held for sale		—		77		—		—		77
Non-current assets - discontinued operations		405		607		—		—		1,012

Total other assets	Total other assets	2,730		1,411		5,009		(5,170)		3,980		Total other assets	3,193		1,309		7,856		(5,508)			6,850
Total Assets	Total Assets	$	7,806	$	2,770	$	6,057	$	(6,005)	$	10,628	Total Assets	$	7,486	$	2,693	$	8,641	$	(6,289)		$	12,531
LIABILITIES AND STOCKHOLDERS’ EQUITY	LIABILITIES AND STOCKHOLDERS’ EQUITY											LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities	Current Liabilities											Current Liabilities
Current portion of long-term debt and finance leases		$	—	$	55	$	17	$	—	$	72

Current portion of long-term debt												Current portion of long-term debt	$	—	$	5	$	83	$	—		$	88
Current portion of operating lease liabilities												Current portion of operating lease liabilities	20		32		21		—			73
Accounts payable	Accounts payable	1,368		(185)		434		(754)		863		Accounts payable	918		141		403		(740)			722

Derivative instruments	Derivative instruments	713		41		—		(81)		673		Derivative instruments	797		25		—		(41)			781
Cash collateral received in support of energy risk management activities	Cash collateral received in support of energy risk management activities	33		—		—		—		33		Cash collateral received in support of energy risk management activities	32		—		—		—			32
Accrued expenses and other current liabilities	Accrued expenses and other current liabilities	291		36		353		—		680		Accrued expenses and other current liabilities	280		44		339		—			663

Current liabilities - held-for-sale		—		5		—		—		5
Current liabilities - discontinued operations		24		48		—		—		72

Total current liabilities	Total current liabilities	2,429		—		804		(835)		2,398		Total current liabilities	2,047		247		846		(781)			2,359
Other Liabilities	Other Liabilities											Other Liabilities
Long-term debt and finance leases		244		192		6,025		(12)		6,449

Long-term debt												Long-term debt	302		28		5,473		—			5,803
Non-current operating lease liabilities												Non-current operating lease liabilities	64		301		118		—			483
Nuclear decommissioning reserve	Nuclear decommissioning reserve	282		—		—		—		282		Nuclear decommissioning reserve	298		—		—		—			298
Nuclear decommissioning trust liability	Nuclear decommissioning trust liability	371		—		—		—		371		Nuclear decommissioning trust liability	487		—		—		—			487

Derivative instruments	Derivative instruments	306		3		—		(5)		304		Derivative instruments	334		1		—		(13)			322
Deferred income taxes	Deferred income taxes	112		61		(108)		—		65		Deferred income taxes	—		17		—		—			17
Other non-current liabilities												Other non-current liabilities	399		153		532		—			1,084

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	Total other liabilities	1,775		1,218		6,469		(17)		9,445		Total other liabilities	1,884		500		6,123		(13)			8,494
Total Liabilities	Total Liabilities	4,204		1,218		7,273		(852)		11,843		Total Liabilities	3,931		747		6,969		(794)			10,853
Redeemable noncontrolling interest in subsidiaries	Redeemable noncontrolling interest in subsidiaries	—		19		—		—		19		Redeemable noncontrolling interest in subsidiaries	—		20		—		—			20
Stockholders’ Equity	Stockholders’ Equity	3,602		1,533		(1,216)		(5,153)		(1,234)		Stockholders’ Equity	3,555		1,926		1,672		(5,495)			1,658
Total Liabilities and Stockholders’ Equity	Total Liabilities and Stockholders’ Equity	$	7,806	$	2,770	$	6,057	$	(6,005)	$	10,628	Total Liabilities and Stockholders’ Equity	$	7,486	$	2,693	$	8,641	$	(6,289)		$	12,531

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

6044

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the ~~nine~~three months ended ~~September 30, 2018~~March 31, 2019

(Unaudited)


(In millions)												(In millions)	Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)		Eliminations^(a)		Consolidated
Cash Flows from Operating Activities												Cash Flows from Operating Activities
Net income												Net income	$	255	$	54	$	482	$	(309)	$	482
Income from discontinued operations												Income from discontinued operations	9		5		374		—		388
Income from continuing operations												Income from continuing operations	246		49		108		(309)		94
Adjustments to reconcile net income to cash provided by operating activities:												Adjustments to reconcile net income to cash provided by operating activities:
Distributions from and equity in earnings/(losses) of unconsolidated affiliates and consolidated subsidiaries												Distributions from and equity in earnings/(losses) of unconsolidated affiliates and consolidated subsidiaries	(10)		21		(299)		309		21
Depreciation and amortization												Depreciation and amortization	54		23		8		—		85
Accretion of asset retirement obligations												Accretion of asset retirement obligations	5		2		—		—		7
Provision for credit losses												Provision for credit losses	23		3		—		—		26
Amortization of nuclear fuel												Amortization of nuclear fuel	13		—		—		—		13
Amortization of financing costs and debt discount/premiums												Amortization of financing costs and debt discount/premiums	—		—		7		—		7

Amortization of emission allowances and energy credits												Amortization of emission allowances and energy credits	6		—		—		—		6
Amortization of unearned equity compensation												Amortization of unearned equity compensation	—		—		4		—		4
Net loss on sale of assets and disposal of assets												Net loss on sale of assets and disposal of assets	—		—		3		—		3

		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	Changes in derivative instruments	(38)		40		(4)		(15)		(17)		Changes in derivative instruments	(29)		5		9		—		(15)
Changes in deferred income taxes and liability for uncertain tax benefits	Changes in deferred income taxes and liability for uncertain tax benefits	343		11		(360)		—		(6)		Changes in deferred income taxes and liability for uncertain tax benefits	—		1		(3)		—		(2)
Changes in collateral deposits in support of energy risk management activities	Changes in collateral deposits in support of energy risk management activities	(16)		(14)		—		—		(30)		Changes in collateral deposits in support of energy risk management activities	(114)		(9)		—		—		(123)
Changes in nuclear decommissioning trust liability	Changes in nuclear decommissioning trust liability	50		—		—		—		50		Changes in nuclear decommissioning trust liability	9		—		—		—		9
GenOn Settlement		—		—		(125)		—		(125)
Loss on deconsolidation of Agua Caliente and Ivanpah projects		—		13		—		—		13

Changes in other working capital	Changes in other working capital	(385)		(266)		290		—		(361)		Changes in other working capital	(211)		(137)		114		—		(234)
Cash provided/(used) by continuing operations		1,029		84		(442)		—		671
Cash provided by discontinued operations		72		324		—		—		396
Cash used by continuing operations												Cash used by continuing operations	(8)		(42)		(49)		—		(99)
Cash provided/(used) by discontinued operations												Cash provided/(used) by discontinued operations	17		(9)		—		—		8
Net Cash Provided/(Used) by Operating Activities	Net Cash Provided/(Used) by Operating Activities	1,101		408		(442)		—		1,067		Net Cash Provided/(Used) by Operating Activities	9		(51)		(49)		—		(91)
Cash Flows from Investing Activities	Cash Flows from Investing Activities											Cash Flows from Investing Activities
Intercompany dividends	Intercompany dividends	—		—		1,273		(1,273)		—		Intercompany dividends	—		—		311		(311)		—
Payments for acquisitions of businesses	Payments for acquisitions of businesses	(2)		(207)		—		—		(209)		Payments for acquisitions of businesses	(16)		—		—		—		(16)
Capital expenditures	Capital expenditures	(156)		(150)		(37)		—		(343)		Capital expenditures	(36)		(6)		(7)		—		(49)

Net proceeds from sale of emission allowances		24		—		—		—		24

Investments in nuclear decommissioning trust fund securities	Investments in nuclear decommissioning trust fund securities	(449)		—		—		—		(449)		Investments in nuclear decommissioning trust fund securities	(122)		—		—		—		(122)
Proceeds from the sale of nuclear decommissioning trust fund securities	Proceeds from the sale of nuclear decommissioning trust fund securities	398		—		—		—		398		Proceeds from the sale of nuclear decommissioning trust fund securities	113		—		—		—		113
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)
Proceeds from sale of assets, net of cash disposed and sale of discontinued operations, net of fees												Proceeds from sale of assets, net of cash disposed and sale of discontinued operations, net of fees	1		404		908		—		1,313

Net distributions from investments in unconsolidated affiliates												Net distributions from investments in unconsolidated affiliates	—		4		—		—		4
Contributions to discontinued operations	Contributions to discontinued operations	—		(23)		—		—		(23)		Contributions to discontinued operations	—		(44)		—		—		(44)

Other												Other	—		—		(1)		—		(1)
Cash (used)/provided by continuing operations	Cash (used)/provided by continuing operations	(175)		(679)		2,773		(1,273)		646		Cash (used)/provided by continuing operations	(60)		358		1,211		(311)		1,198
Cash used by discontinued operations	Cash used by discontinued operations	(2)		(703)		—		—		(705)		Cash used by discontinued operations	—		(2)		—		—		(2)
Net Cash (Used)/Provided by Investing Activities	Net Cash (Used)/Provided by Investing Activities	(177)		(1,382)		2,773		(1,273)		(59)		Net Cash (Used)/Provided by Investing Activities	(60)		356		1,211		(311)		1,196
Cash Flows from Financing Activities	Cash Flows from Financing Activities											Cash Flows from Financing Activities
Payments from/(for) intercompany loans		476		170		(646)		—		—
Intercompany dividends		(1,273)		—		—		1,273		—

Intercompany dividends and transfers												Intercompany dividends and transfers	(4)		(290)		(17)		311		—
Payment of dividends to common stockholders	Payment of dividends to common stockholders	—		—		(28)		—		(28)		Payment of dividends to common stockholders	—		—		(8)		—		(8)
Payments for treasury stock		—		—		(1,000)		—		(1,000)
Payments for share repurchase activity												Payments for share repurchase activity	—		—		(783)		—		(783)

Distributions to noncontrolling interests from subsidiaries		—		(17)		—		—		(17)
Net distributions to noncontrolling interests from subsidiaries												Net distributions to noncontrolling interests from subsidiaries	—		(1)		—		—		(1)
Proceeds from issuance of common stock	Proceeds from issuance of common stock	—		—		15		—		15		Proceeds from issuance of common stock	—		—		2		—		2
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)

Payments for long-term debt												Payments for long-term debt	—		(33)		(4)		—		(37)

Cash used by continuing operations												Cash used by continuing operations	(4)		(324)		(810)		311		(827)
Cash provided by discontinued operations	Cash provided by discontinued operations	—		403		—		—		403		Cash provided by discontinued operations	—		43		—		—		43
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
Net Cash Used by Financing Activities												Net Cash Used by Financing Activities	(4)		(281)		(810)		311		(784)

Change in cash from discontinued operations	Change in cash from discontinued operations	70		24		—		—		94		Change in cash from discontinued operations	17		32		—		—		49
Net Increase/(Decrease) in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash		57		(388)		595		—		264
Net (Decrease)/Increase in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash												Net (Decrease)/Increase in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash	(72)		(8)		352		—		272
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period	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 Beginning of Period	95		38		480		—		613
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	$	98	$	37	$	1,215	$	—	$	1,350	Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	$	23	$	30	$	832	$	—	$	885

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

6145

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~~presents the results of operations for the three ~~and nine~~ months ended ~~September 30, 2019~~March 31, 2020 and ~~2018.~~2019. Also refer to NRG's ~~2018~~2019 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~~The Company determined in ~~Note 4,~~ ~~Acquisitions, Discontinued Operations and Dispositions, the Company is treating~~prior years that the following businesses aswere discontinued operations and ~~has~~ recast prior periods to present their results 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~~integrated power company built on dynamic retail brands with diverse generation assets. NRG brings the power of energy to ~~consumers~~customers by producing ~~selling~~ and ~~delivering~~selling electricity and related products and services in major competitive power markets in the U.S. and Canada in a manner that delivers value to all of NRG's stakeholders. NRG is a customer-driven business focused on perfecting the integrated model by balancing retail load with generation supply within its deregulated ~~markets, while evolving to a customer-driven business.~~markets. The Company sells energy, services, and innovative, sustainable products and services directly to retail customers under the names ~~"NRG"~~NRG, Reliant, Green Mountain Energy, Stream, and ~~"Reliant" and~~XOOM Energy, as well as other brand names owned by NRG, supported by approximately 23,000 MW of generation as of ~~September 30, 2019.~~March 31, 2020. NRG was incorporated as a Delaware corporation on May 29, 1992.

The following table summarizes NRG's ~~global~~ generation portfolio in MW as of ~~September 30, 2019,~~March 31, 2020 by operating segment:


		Global Generation Portfolio^(a)
		(In MW)
		Generation
Generation Type	Generation Type	Texas^(b)	East/West^(c)(d)	Other^(e)	Total Global	Generation Type	Texas	East	West/Other^(a)(b)	Total
Natural gas	Natural gas	4,759	4,994	—	9,753	Natural gas	4,759	2,686	2,308	9,753
Coal	Coal	4,174	3,745	—	7,919	Coal	4,174	3,140	605	7,919
Oil	Oil	—	3,600	—	3,600	Oil	—	3,600	—	3,600
Nuclear	Nuclear	1,126	—	—	1,126	Nuclear	1,126	—	—	1,126
Utility Scale Solar	Utility Scale Solar	—	321	—	321	Utility Scale Solar	—	—	321	321
Battery Storage & Distributed Solar	Battery Storage & Distributed Solar	2	—	60	62	Battery Storage & Distributed Solar	2	—	60	62
Total generation capacity		10,061	12,660	60	22,781
Total generation capacity ^(c)						Total generation capacity ^(c)	10,061	9,426	3,294	22,781

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

(b) The Distributed Solar figure in West/Other includes the aggregate production capacity of installed and activated residential solar energy systems

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

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

~~(c) Includes International~~COVID-19

In March 2020, the World Health Organization categorized COVID-19 as a pandemic and the ~~remaining Renewables generation assets~~President of the United States declared the COVID-19 outbreak a national emergency. Electricity has been deemed a ‘critical and essential business operation’ under various state and federal governmental COVID-19 mandates. NRG remains focused on protecting the health and well-being of its employees, while supporting its customers and the communities in which it operates and assuring the continuity of its operations. In addition, on April 1, 2020, NRG committed $2 million to COVID-19 relief efforts, including funding for urgently needed safety equipment supporting first responders, as well as funds that aid local communities and teachers. The Company also allocated additional funding to the NRG Employee Relief Fund to assist employees adversely impacted by natural disasters and other extraordinary events.

~~(d) Includes 1,153 MW~~NRG activated its Crisis Management Team ("CMT") in January 2020, which proactively began managing the Company's response to the impacts of COVID-19. The CMT implemented the business continuity plans for the ~~Cottonwood facility~~Company and has taken a variety of measures to ensure the ongoing availability of the Company’s services, while maintaining the Company's commitment to its core values of health and safety. Pursuant to the Company’s Infectious Disease & Pandemic Policy, NRG implemented restrictions on business travel and face-to-face sales channels, instituted remote work practices and enhanced cleaning and hygiene protocols in all of its facilities. In order to effectively serve the Company’s customers, select essential employees and contractors are continuing to report to plant and certain office locations. The Company is also requiring pre-entry screening, including temperature checks, separation of work crews, additional personal protective equipment for employees and contractors when social distancing cannot be maintained, and a ban on all non-essential visitors. As a result of these business continuity measures, the Company has not experienced any material disruptions in its ability to continue its business operations to date.

In order to support our employees, the Company also established a communication protocol in January 2020, including a central information hub on its intranet, made telehealth services available, and activated its Emergency Relief Fund for financially-impacted employees.

NRG believes it has sufficient liquidity on hand to continue business operations. As disclosed in the Liquidity and Capital Resources section, the Company has total available liquidity of $1,950 million as of March 31, 2020, consisting of cash on hand and a revolving credit facility.

While the pandemic may present new risks to the Company’s business, there was not a material adverse impact on the Company’s first quarter 2020 results of operations.

Following the President's declaration of COVID-19 outbreak being a national emergency, the Governors of the majority of states in which we operate issued executive orders that ~~was sold~~every person should, except where necessary to ~~Cleco~~provide or obtain essential services, minimize social gatherings and minimize in-person contact with people who are not in the same household. The impact of these orders closed schools, restaurants and bars, except in certain cases for takeout, and other non-essential businesses. As a result, there has been a reduction in load within the markets in which we operate and we expect demand uncertainty to continue until the economy recovers.

Specifically, in Texas, the PUCT adopted the COVID-19 Electricity Relief Program (“ERP”), which, among other things, creates an assistance program for eligible residential customers in the competitive retail electric market who are experiencing economic hardship as a result of the pandemic. Consistent with the PUCT orders, NRG is waiving late fees for residential and

small commercial customers and offering deferred payment plans to those customers, as well as temporarily suspending disconnect and reconnect fees.

The situation surrounding COVID-19 remains fluid and the potential for a material adverse impact on ~~February 4, 2019,~~the Company increases the longer the virus impacts the level of economic activity in the United States and globally. For this reason, NRG cannot reasonably estimate with any degree of certainty the full impact COVID-19, or any resurgence of COVID-19, may have on the Company’s results of operations, financial position, and liquidity. The extent to which the ~~company is leasing until 2025~~

~~(e) The Distributed Solar figure within "Other" includes~~COVID-19 pandemic may impact the ~~aggregate production capacity~~Company’s business, operating results, financial condition, risk exposure or liquidity will depend on future developments, including the duration of ~~installed~~the outbreak, travel restrictions, business and ~~activated residential solar energy systems~~workforce disruptions, any resurgence of the outbreak and the effectiveness of actions taken to contain, mitigate and treat the disease. See Part II, Item 1A - Risk Factors.

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 stable and 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~~offering innovative and renewable energy solutions for ~~consumers within its retail businesses;~~customers; (iii) excellence in operating performance of its existing ~~assets including~~assets; (iv) optimal hedging of NRG's net retail and generation ~~assets~~positions; and ~~retail load operations; and (iv)~~(v) engaging in ~~a proactive~~disciplined and transparent capital ~~allocation plan within the dictates~~allocation.

Sustainability is an integral part of ~~prudent balance sheet management.~~

NRG's strategy and ties directly to business success, reduced risks and brand value. 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~~2019 Form 10-K in Item 1, Business — Regulatory Matters. These matters have been updated below and in Note ~~18,~~17, 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. Through our PJM trade organization, NRG is also currently participating in an appeal of NJBPU's Order regarding ZECs.

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. Due to the COVID-19 pandemic in 2020, the legislative sessions have been curtailed, and the Illinois ~~ended its regular session~~General Assembly has primarily been focused on ~~May 31, 2019 without passing these significant energy bills.~~essential bills needed to address the pandemic. NRG continues to oppose the ongoing legislative effort and supports a competitive clean energy market design that would competitively ~~procure additional zero~~ reduce greenhouse gas

emission ~~power~~through the procurement of clean energy resources 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,~~17, Regulatory Matters, to the Condensed Consolidated Financial Statements.

East/West

PJM

Capacity Market Reforms Filing — On December 19, 2019, FERC ~~is considering various~~issued an order on the pending 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,~~in the capacity market. FERC directed PJM to ~~wait~~apply the Minimum Offer Price Rule, or MOPR, to ~~have~~new and existing resources receiving state subsidies and subject them to default offer floor prices in their capacity bids. The Order provided for various category specific exemptions to the ~~Base Residual Auction~~MOPR, as well as a unit specific exemption, which permits any resource that can justify an offer lower than the default offer price floor to submit such capacity bids to PJM for ~~2022/2023 delivery year until new rules are~~review. As part of the December 19, 2019 FERC Order, FERC gave PJM 90 days to make a compliance filing and submit tariff language to reflect the requirements of the Order and directed PJM to include in ~~place. On September 27, 2019, PJM announced~~this filing a timetable for when it ~~was suspending all auction deadlines relating~~proposes to hold the previously postponed Base Residual Auctions for the 2022/2023 and 2023/2024 delivery ~~year, consistent with FERC’s July 25,~~years. Multiple parties filed for rehearing and clarification. FERC ruled on April 16, 2020 to largely uphold its December 2019 ~~Order. Decisions around harmonizing federal and state policy initiatives are a critical factor~~Order, after which, multiple parties filed for ~~setting future prices.~~

~~PJM's Operational Reserve Demand Curve Filing~~ —appeal at various circuit courts. 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.18, 2020, PJM made its compliance filing, which among other things, stated that it would hold its next capacity auction six and a half months after a ruling on ~~August 30, 2019, which currently~~the compliance filing. Comments to the compliance filing are extended until May 15, 2020. Pursuant to the April 16, 2020 Order, PJM is required to make an additional compliance filing within 45 days of that Order. Subjecting subsidized resources to default offer floors in the capacity market should protect the market from further price suppression. The impact of these changes on capacity markets outcomes depends on, among other factors, bidding behavior, load forecast changes, new resource entry, and existing resource exit.

New Jersey Board of Public Utilities’ Investigation on Resource Adequacy Alternatives — On March 25, 2020, the NJBPU initiated a proceeding to investigate resource adequacy alternatives for New Jersey. The proceeding is pending. ~~The changes~~Any actions taken by the NJBPU could ~~provide more accurate pricing to reflect the marginal cost of serving load.~~affect market prices in PJM.

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. Subsequently, multiple parties filed an appeal of FERC's Order to the Court of Appeals for the D.C. Circuit. On April 14, 2020, FERC filed a motion for a voluntary remand. On April 21, 2020, the Court of Appeals for the D.C. Circuit remanded the case back to FERC. The case is pending. ISO-NE's proposal will affect future capacity market prices and the compensation that fuel secure units receive.

ISO-NE Fuel Security Improvements Proposal — On April 15, 2020, ISO-NE filed a compliance filing proposing improvements to the wholesale market design to address winter fuel security issues as directed by FERC. The outcome of the matter will affect market prices in ISO-NE.

Connecticut Department of Energy and Environmental Protection Integrated Resource Plan Proceeding — In Connecticut's ongoing proceeding related to its Integrated Resource Plan, the Connecticut Department of Energy and Environmental Protection issued a notice of technical meeting and opportunity for public comment on January 8, 2020 seeking comment on two issues: (1) the compatibility of state goals and those of ISO-NE and (2) the possibility of alternative market designs that would be more in line with the state's goals. On January 22, 2020, NRG presented its thoughts and on February 5, 2020, NRG filed comments advocating for competitive markets and proposed its competitive clean energy market design. On February 28, 2020, the Connecticut Departments of Energy and Environmental Protection held a second technical meeting.

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’~~ESCO’s prices as a condition of access to the utilities’

infrastructure. In conjunction with the court challenge, the NYSPSC also noticed an evidentiary ~~proceeding, which~~proceeding. On December 12, 2019, the NYSPSC issued an order adopting changes to the retail access energy market based on the record in the evidentiary proceeding. The Order limits ESCO offers to three compliant products: guaranteed savings from the utility default rate, a fixed term capped at 5% of the rolling 12-month average utility default rate, or NY-sourced renewable energy that is ~~still open before~~at least 50% greater than the ~~NYSPSC.~~prevailing NY Renewable Energy Standard for load serving entities. The ~~matter is fully briefed~~Order also establishes new ESCO eligibility criteria and certification process, as well as re-certification of current ESCOs. The NYSPSC ordered compliance effective February 10, 2020. On January 13, 2020, multiple parties filed motions for rehearing and a ~~decision~~stay of the Order. On March 2, 2020, the NYSPSC issued a notice seeking comments by April 13, 2020 on the petitions for rehearing. On January 17, 2020, NRG filed a request for a 90-day extension of the February 10, 2020 effective date, and, on January 22, 2020, the NYSPSC granted an extension for compliance to May 11, 2020. On March 17, 2020, NRG filed a request for an additional 90-day extension of the effective date of the Order. On April 7, 2020, the NYSPSC granted the extension with a new effective date of August 9, 2020. The limited offerings imposed by the Order, as issued, may negatively impact the Company's retail sales in New York.

New York State Public Service Commission Resource Adequacy Proceeding — On August 8, 2019, the NYSPSC established an investigation into New York's resource adequacy market design. On November 8, 2019, NRG filed comments and recommendations, specifically putting forth NRG's Forward Clean Energy Market Proposal, that would allow New York to maintain a reliable system while advancing its environmental goals. The proceeding is pending. Any actions taken by the NYSPSC could affect market design and market prices in New York.

Independent Power Producers of New York ("IPPNY") Complaint — On January 9, 2017, EPSA requested FERC to promptly direct NYISO to file tariff provisions to address pending market concerns related to out-of-market payments to existing generation in NYISO.On April 5, 2018, EPSA filed a motion for renewed request for expedited action on the MOPR. On February 20, 2020, FERC rejected IPPNY's rehearing request asking FERC to direct NYISO to require that capacity from existing generation resources that would have exited the market but for out-of-market payments be mitigated. FERC found that NYISO complied with the initial order to establish a stakeholder process to consider whether buyer side mitigation measures are needed to address these agreements. Failure to implement buyer-side mitigation measures could result in uneconomic entry, which artificially decreases capacity prices below competitive market levels.

New York Buyer Side Mitigation Proceedings — On February 20, 2020, FERC issued multiple orders pertaining to the NYISO capacity market. The orders narrowed certain exemptions to buyer side mitigation measures. Specifically, FERC stated that certain renewable and self-supply resources would be exempt from offer floor mitigation but rejected NYISO’s proposal of a 1,000 MW cap on renewable resources that could qualify for the exemption. FERC ordered NYISO to make a compliance filing narrowly tailoring its cap. On April 7, 2020, NYISO submitted its compliance filing proposing a formula that sets the Renewable Exemption Limit based generally on projected load growth and generator requirements. On April 28, 2020, the generator trade association filed comments seeking clarification related to the Renewable Exemption Limit formula. FERC also rejected a complaint to exempt new electric storage resources. It also rejected a blanket exemption to demand response providers currently subject to mitigation but granted a request for new demand response to receive a blanket exemption from the buyer side mitigation measures. Implementation of buyer side mitigation measures to address price suppression provides more accurate capacity price signals in the competitive market.

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~~was put into effect on March 1, 2020. To date, the ORDC reforms have produced a noticeable improvement in scarcity pricing.

Public Utilities Commission of Texas’ Actions Related to COVID-19 — On March 26, 2020, the PUCT adopted the COVID-19 Electricity Relief Program ("ERP") aimed to mitigate the impact of COVID-19 on residential customers in the competitive retail electric market who are experiencing economic hardship as a result of the pandemic. The COVID-19 ERP protects residential customers deemed eligible by the PUCT’s third party administrator from disconnection for nonpayment until July 17, 2020, unless extended by the PUCT. The COVID-19 ERP also establishes an emergency fund to allow Retail Electric Providers ("REPs") to recover a certain amount of credit losses incurred while continuing to serve these customers. REPs may recover from the fund a proxy for a portion of their costs (at a fixed rate of $0.04 per kWh) related to eligible residential customers with an unpaid, past due electric bill subject to a disconnection for non-payment notice. On March 26, 2020, the PUCT issued an order that required REPs to suspend charging residential and small commercial customers late fees as part of the response to the Governor's disaster declaration relating to COVID-19. On April 17, 2020, the PUCT narrowed the scope of the late fees waiver to just residential customers, with a May 15, 2020 end date unless extended by the PUCT.

CAISO

Resource Adequacy Central Procurement Proceeding — On March 26, 2020, a CPUC Administrative Law Judge issued a proposed decision adopting implementation details for the central procurement of multi-year local resource adequacy capacity to begin for the 2023 compliance year for the PG&E and Southern California Edison ("SCE") service areas, under which PG&E and SCE would be the respective central procurement entities. The March 26, 2020 proposed decision declined to adopt a central procurement framework for the San Diego Gas and Electric service area and rejected a proposed settlement filed by various entities including NRG, which included the expansion of multi-year requirements to all categories of resource adequacy (system, flexible and local) and a residual procurement model for the central procurement entity. NRG submitted comments opposing the March 26, 2020 proposed decision on April 15, 2020. The rulemaking remains pending. The ultimate decision in this docket could fundamentally change the resource adequacy market in California.

Environmental Regulatory Matters

NRG is subject to numerous environmental laws in the development, construction, ownership and operation of ~~projects.~~power plants. 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 specialized human resources and significant capital and operating expenses, as well as occasionally curtailing operations. The COVID-19 pandemic may prevent us from complying with certain of our environmental requirements, which federal and state regulators have recognized. 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 storage and 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 revisions and legal challenges are resolved. The Company’s environmental matters are described in the Company’s ~~2018~~2019 Form 10-K in Item 1, Business - Environmental Matters and Item 1A, Risk Factors. These matters have been updated in Note ~~19,~~18, 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 had 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. Texas, Illinois and Delaware have started working on plans to comply with the ACE rule. 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. On December 2, 2019, the EPA released for comment "Closure Part A Proposal" to revise the CCR Rule to address the D.C. Circuit's 2018 decision regarding the adequacy of clay-lined impoundments, obligations to close all unlined impoundments and related deadlines. On February 20, 2020, the EPA proposed the framework for developing and implementing a federal permit program for states that are not approved to administer the CCR rule. On March 3, 2020, the EPA proposed for comment "A Holistic Approach to Closure Part B," which proposes procedures for obtaining approval to operate

existing impoundments with alternative liners. 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,~~16, ~~Environmental Matters~~Commitments and Contingencies, to the Condensed 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~~has been extended twice through ~~an addendum dated January 24, 2014,~~addendums to cover payments through December 31, ~~2016. On December 12, 2016,~~2019. STPNOC ~~received~~expects the ~~federal government's offer of~~settlement to be extended for another three-year ~~extension of payment for continued failure to accept SNF and HLW. The proposal was reviewed and accepted.~~period. 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,~~FGD, 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. On November 22, 2019, the EPA proposed amending the 2015 ELG rule by: (x) decreasing the stringency of the selenium limit (but increasing the stringency of the nitrate and mercury limits) for FGD wastewater; (y) relaxing the zero-discharge requirement for bottom ash transport water; and (z) changing several deadlines. 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~~On December 31, 2019, ~~NY DEC proposed~~the New York State Department of Environmental Conservation finalized a more stringent NOx regulation that ~~depending on the outcome of the regulatory process, may~~will result in the retirement of ~~some of our~~the Company's combustion turbines in Astoria, New ~~York. In August 2019, NY DEC proposed additional revisions to this rule and solicited additional comments.~~York in 2023.

Ash Regulation in Illinois — On July 30, 2019, Illinois enacted legislation that will require the state to promulgate regulations regarding coal ~~ash.~~ash at surface impoundments. On March 30, 2020, the state released its proposed implementing regulations. We expect the state to promulgate the final implementing regulations in March 2021, at which time regulated entities will then prepare and submit permit applications.

6852

Significant Events

The following significant events have occurred during ~~2019, in addition to the Transformation Plan events,~~2020 as further described within this Management's Discussion and Analysis and the Condensed Consolidated Financial Statements:

Share Repurchases

During the three months ended March 31, 2020, the Company completed $177 million of share repurchases at an average price of $34.20 per share, including $27 million of equivalent shares purchased in lieu of tax withholdings on equity compensation issuance. Through May 7, 2020, the Company completed an additional $47 million of share repurchases at an average price of $29.33 per share.

Renewable Power Purchase Agreements

During 2019, NRG began execution of its strategy to procure mid to long-term generation through renewable power purchase agreements. As of ~~September 30, 2019,~~March 31, 2020, NRG has entered into PPAs totaling approximately ~~1,400~~1,600 MWs with third-party project developers and other counterparties. The tenor of these agreements is an average of ~~ten~~eleven years. The Company expects to continue evaluating and executing similar agreements ~~such as these,~~ that support the ~~mid to longer-term~~ needs of ~~its~~the 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 issued $1.1 billion of aggregate principal amount of senior secured first lien notes, consisting of $600 million 3.75% senior secured first lien notes due 2024 and $500 million 4.45% senior secured first lien notes due 2029, or the Senior Secured First Lien Notes, at a discount. The proceeds from the issuance of the Senior Secured First Lien Notes, as well as cash on hand, were used to repay the Company's $1.7 billion 2023 Term Loan facility, resulting in a decrease of $594 million to long-term debt outstanding.COVID-19

~~On May 28, 2019, NRG amended its existing credit agreement~~For discussion of COVID-19 related considerations, refer 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~~Management’s Discussion and ~~Finance Leases,~~Analysis of Financial Condition and Results of Operations – Executive Summary ~~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~~Liquidity 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.

Capital Resources

Trends Affecting Results of Operations and Future Business Performance

The Company’s trends are described in the Company’s ~~2018~~2019 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, to the Condensed Consolidated Financial Statements for a discussion of recent accounting developments.

6953

Consolidated Results of Operations

The following table provides selected financial information for the Company:


		Three months ended September 30,											Nine months ended September 30,											Three months ended March 31,
(In millions, except as otherwise noted)	(In millions, except as otherwise noted)	2019		2018		Change			2019		2018		Change			(In millions, except as otherwise noted)	2020		2019		Change
Operating Revenues	Operating Revenues															Operating Revenues
Retail revenue																Retail revenue	$	1,661	$	1,589	$	72
Energy revenue^(a)	Energy revenue^(a)	$	442	$	445	$	(3)		$	997	$	1,298	$	(301)		Energy revenue^(a)	124		290		(166)
Capacity revenue ^(a)	Capacity revenue ^(a)	152		192		(40)			461		500		(39)			Capacity revenue^(a)	149		156		(7)
Retail revenue		2,545		2,200		345			5,896		5,498		398
Mark-to-market for economic hedging activities	Mark-to-market for economic hedging activities	(210)		55		(265)			51		(31)		82			Mark-to-market for economic hedging activities	(4)		20		(24)

Other revenues ^(b)		67		68		(1)			221		221		—
Other revenues ^(a)(b)																Other revenues ^(a)(b)	89		110		(21)
Total operating revenues	Total operating revenues	2,996		2,960		36			7,626		7,486		140			Total operating revenues	2,019		2,165		(146)
Operating Costs and Expenses	Operating Costs and Expenses															Operating Costs and Expenses
Cost of Sales ^(c)	Cost of Sales ^(c)	1,948		1,785		(163)			4,562		4,559		(3)			Cost of Sales ^(c)	1,149		1,341		192
Mark-to-market for economic hedging activities	Mark-to-market for economic hedging activities	(146)		123		269			74		(93)		(167)			Mark-to-market for economic hedging activities	(48)		—		48
Contract and emissions credit amortization ^(c)	Contract and emissions credit amortization ^(c)	5		7		2			16		20		4			Contract and emissions credit amortization ^(c)	1		5		4
Operations and maintenance	Operations and maintenance	263		243		(20)			794		817		23			Operations and maintenance	293		248		(45)
Other cost of operations	Other cost of operations	83		80		(3)			203		209		6			Other cost of operations	62		57		(5)
Total cost of operations	Total cost of operations	2,153		2,238		85			5,649		5,512		(137)			Total cost of operations	1,457		1,651		194
Depreciation and amortization	Depreciation and amortization	91		99		8			261		331		70			Depreciation and amortization	109		85		(24)
Impairment losses		—		—		—			1		74		73

Selling, general and administrative	Selling, general and administrative	210		211		1			615		587		(28)			Selling, general and administrative	209		194		(15)
Reorganization costs	Reorganization costs	1		27		26			16		70		54			Reorganization costs	3		13		10
Development costs	Development costs	1		1		—			5		9		4			Development costs	3		2		(1)
Total operating costs and expenses	Total operating costs and expenses	2,456		2,576		120			6,547		6,583		36			Total operating costs and expenses	1,781		1,945		164

Gain on sale of assets	Gain on sale of assets	—		14		(14)			2		30		(28)			Gain on sale of assets	6		1		5
Operating Income	Operating Income	540		398		142			1,081		933		148			Operating Income	244		221		23
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates		29		20		9			8		26		(18)
Other (Expense)/Income																Other (Expense)/Income
Equity in losses of unconsolidated affiliates																Equity in losses of unconsolidated affiliates	(11)		(21)		10
Impairment losses on investments	Impairment losses on investments	(107)		(1)		(106)			(107)		(16)		(91)			Impairment losses on investments	(18)		—		(18)
Other income, net	Other income, net	17		19		(2)			49		12		37			Other income, net	27		12		15
Loss on debt extinguishment, net		—		(19)		19			(47)		(22)		(25)

Interest expense	Interest expense	(99)		(122)		23			(318)		(361)		43			Interest expense	(98)		(114)		16
Total other expense	Total other expense	(160)		(103)		(57)			(415)		(361)		(54)			Total other expense	(100)		(123)		23
Income from Continuing Operations Before Income Taxes	Income from Continuing Operations Before Income Taxes	380		295		85			666		572		94			Income from Continuing Operations Before Income Taxes	144		98		46
Income tax expense	Income tax expense	6		8		2			9		19		10			Income tax expense	23		4		(19)
Income from Continuing Operations	Income from Continuing Operations	374		287		87			657		553		104			Income from Continuing Operations	121		94		27

(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
Income from discontinued operations, net of income tax																Income from discontinued operations, net of income tax	—		388		(388)

Net Income																Net Income	$	121	$	482	$	(361)
Business Metrics	Business Metrics															Business Metrics
Average natural gas price — Henry Hub ($/MMBtu)	Average natural gas price — Henry Hub ($/MMBtu)	$	2.23	$	2.90	(23)		%	$	2.67	$	2.90	(8)		%	Average natural gas price — Henry Hub ($/MMBtu)	$	1.95	$	3.15	(38)		%

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

(b) Includes ~~unrealized~~ trading gains and losses

7054

Management’s discussion of the results of operations for the three months ended ~~September 30,~~March 31, 2020 and 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~~March 31, 2020 and ~~2018. The average on-peak power prices increased in Texas due to higher power prices in August.~~2019. The average on-peak power prices decreased ~~in East/West~~across all regions due to mild winter weather and lower gas ~~prices, along with lower summer prices in California.~~prices.


		Average on Peak Power Price ($/MWh)											Average on Peak Power Price ($/MWh)
		Three months ended September 30,											Three months ended March 31,
Region	Region	2019		2018		Change %		Region	2020		2019		Change %
Texas	Texas							Texas
ERCOT - Houston^(a)	ERCOT - Houston^(a)	$	120.55	$	40.34	199	%	ERCOT - Houston^(a)	$	25.33	$	28.20	(10)	%
ERCOT - North^(a)	ERCOT - North^(a)	$	120.49	$	40.23	200	%	ERCOT - North^(a)	24.43		28.03		(13)	%
MISO - Louisiana Hub^(b)		$	29.75	$	41.22	(28)	%
East/West

East								East
NY J/NYC^(b)	NY J/NYC^(b)	$	31.13	$	46.82	(34)	%	NY J/NYC^(b)	$	23.83	$	45.16	(47)	%
NEPOOL^(b)	NEPOOL^(b)	$	29.52	$	43.53	(32)	%	NEPOOL^(b)	24.61		47.40		(48)	%
COMED (PJM)^(b)	COMED (PJM)^(b)	$	29.86	$	37.31	(20)	%	COMED (PJM)^(b)	21.29		30.09		(29)	%
PJM West Hub^(b)	PJM West Hub^(b)	$	31.17	$	40.06	(22)	%	PJM West Hub^(b)	22.47		33.79		(34)	%
West								West
MISO - Louisiana Hub^(b)								MISO - Louisiana Hub^(b)	$	22.14	$	32.84	(33)	%
CAISO - SP15^(b)	CAISO - SP15^(b)	$	37.32	$	74.86	(50)	%	CAISO - SP15^(b)	28.64		50.42		(43)	%

^(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~~March 31, 2020 and ~~2018:~~2019:

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) %


	Average Realized Power Price ($/MWh)
	Three months ended March 31,
Region	2020		2019		Change %
East	$	17.75	$	31.48	(44)	%
West/Other	29.31		29.90		(2)	%

~~(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~~March 31, 2020 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~~lower power ~~prices in summer 2019.~~and gas prices.

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~~March 31, 2020 and ~~2018:~~2019:


		Three months ended September 30, 2019
				Generation															Three months ended March 31, 2020
($ In millions)	($ In millions)	Retail		Texas		East/West/Other^(a)		Subtotal		Corporate/Eliminations		Total		($ In millions)	Texas		East		West/Other		Corporate/Eliminations		Total
Retail revenue														Retail revenue	$	1,292	$	370	$	—	$	(1)	$	1,661
Energy revenue	Energy revenue	$	—	$	773	$	237	$	1,010	$	(568)	$	442	Energy revenue	5		45		75		(1)		124
Capacity revenue	Capacity revenue	—		—		151		151		1		152		Capacity revenue	—		134		15		—		149
Retail revenue		2,545		—		—		—		—		2,545
Mark-to-market for economic hedging activities	Mark-to-market for economic hedging activities	(1)		(240)		(16)		(256)		47		(210)		Mark-to-market for economic hedging activities	—		(20)		15		1		(4)

Other revenue	Other revenue	—		32		37		69		(2)		67		Other revenue	61		10		20		(2)		89
Operating revenue	Operating revenue	2,544		565		409		974		(522)		2,996		Operating revenue	1,358		539		125		(3)		2,019
Cost of fuel	Cost of fuel	(10)		(234)		(135)		(369)		2		(377)		Cost of fuel	(103)		(55)		(36)		—		(194)
Other cost of sales^(b)		(2,001)		(68)		(69)		(137)		567		(1,571)
Purchased power														Purchased power	(265)		(152)		(6)		—		(423)
Other cost of sales^(a)(b)														Other cost of sales^(a)(b)	(462)		(91)		20		1		(532)
Mark-to-market for economic hedging activities	Mark-to-market for economic hedging activities	192		2		(1)		1		(47)		146		Mark-to-market for economic hedging activities	49		—		—		(1)		48
Contract and emission credit amortization	Contract and emission credit amortization	—		(5)		—		(5)		—		(5)		Contract and emission credit amortization	(1)		—		—		—		(1)
Gross margin	Gross margin	$	725	$	260	$	204	$	464	$	—	$	1,189	Gross margin	$	576	$	241	$	103	$	(3)	$	917
Less: Mark-to-market for economic hedging activities, net	Less: Mark-to-market for economic hedging activities, net	191		(238)		(17)		(255)		—		(64)		Less: Mark-to-market for economic hedging activities, net	49		(20)		15		—		44
Less: Contract and emission credit amortization, net	Less: Contract and emission credit amortization, net	—		(5)		—		(5)		—		(5)		Less: Contract and emission credit amortization, net	(1)		—		—		—		(1)
Economic gross margin	Economic gross margin	$	534	$	503	$	221	$	724	$	—	$	1,258	Economic gross margin	$	528	$	261	$	88	$	(3)	$	874
^(a) Includes capacity and emissions credits														^(a) Includes capacity and emissions credits
^(b) Includes $429 million and $2 million of TDSP expense in Texas and East, respectively														^(b) Includes $429 million and $2 million of TDSP expense in Texas and East, respectively
Business Metrics	Business Metrics													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
Mass Market electricity sales volume (GWh)														Mass Market electricity sales volume (GWh)	7,748		2,548		—				10,296
C&I electricity sales volume (GWh)														C&I electricity sales volume (GWh)	4,456		389		—				4,845
Natural gas sales volume (MDth)														Natural gas sales volume (MDth)	—		10,509		—				10,509
Average retail Mass Market customer count (in thousands)														Average retail Mass Market customer count (in thousands)	2,442		1,220		—				3,662
Ending retail Mass Market customer count (in thousands)														Ending retail Mass Market customer count (in thousands)	2,439		1,212		—				3,651
GWh sold														GWh sold	67		2,535		2,559				5,161
GWh generated:^(a)														GWh generated:^(a)
Coal														Coal	3,060		335		—				3,395
Gas														Gas	674		149		2,355				3,178
Nuclear														Nuclear	2,302		—		—				2,302
Oil														Oil	—		18		—				18

Total														Total	6,036		502		2,355				8,893
^(a) Includes owned generation, and excludes equity investments														^(a) Includes owned generation, and excludes equity investments

7256


		Three months ended September 30, 2018
				Generation															Three months ended March 31, 2019
($ In millions)	($ In millions)	Retail		Texas		East/West/Other^(a)(b)		Subtotal		Corporate/Eliminations		Total		($ In millions)	Texas		East		West/Other		Corporate/Eliminations		Total
Retail revenue														Retail revenue	$	1,253	$	338	$	—	$	(2)	$	1,589
Energy revenue	Energy revenue	$	—	$	585	$	339	$	924	$	(479)	$	445	Energy revenue	105		126		58		1		290
Capacity revenue	Capacity revenue	—		1		190		191		1		192		Capacity revenue	—		144		12		—		156
Retail revenue		2,202		—		—		—		(2)		2,200
Mark-to-market for economic hedging activities	Mark-to-market for economic hedging activities	1		259		36		295		(241)		55		Mark-to-market for economic hedging activities	31		(15)		4		—		20

Other revenue	Other revenue	—		8		60		68		—		68		Other revenue	77		16		19		(2)		110
Operating revenue	Operating revenue	2,203		853		625		1,478		(721)		2,960		Operating revenue	1,466		609		93		(3)		2,165
Cost of fuel	Cost of fuel	(2)		(245)		(201)		(446)		(2)		(450)		Cost of fuel	(149)		(66)		(36)		—		(251)
Purchased power														Purchased power	(327)		(191)		—		—		(518)
Other cost of sales^(c)(b)	Other cost of sales^(c)(b)	(1,700)		(51)		(61)		(112)		477		(1,335)		Other cost of sales^(c)(b)	(486)		(75)		(11)		—		(572)
Mark-to-market for economic hedging activities	Mark-to-market for economic hedging activities	(360)		—		(4)		(4)		241		(123)		Mark-to-market for economic hedging activities	(5)		3		2		—		—
Contract and emission credit amortization	Contract and emission credit amortization	—		(7)		—		(7)		—		(7)		Contract and emission credit amortization	(5)		—		—		—		(5)
Gross margin	Gross margin	$	141	$	550	$	359	$	909	$	(5)	$	1,045	Gross margin	$	494	$	280	$	48	$	(3)	$	819
Less: Mark-to-market for economic hedging activities, net	Less: Mark-to-market for economic hedging activities, net	(359)		259		32		291		—		(68)		Less: Mark-to-market for economic hedging activities, net	26		(12)		6		—		20
Less: Contract and emission credit amortization, net	Less: Contract and emission credit amortization, net	—		(7)		—		(7)		—		(7)		Less: Contract and emission credit amortization, net	(5)		—		—		—		(5)
Economic gross margin	Economic gross margin	$	500	$	298	$	327	$	625	$	(5)	$	1,120	Economic gross margin	$	473	$	292	$	42	$	(3)	$	804
(a) Includes capacity and emissions credits														(a) Includes capacity and emissions credits
(b) Includes $422 million and $3 million of TDSP expense in the Texas and East segments, respectively														(b) Includes $422 million and $3 million of TDSP expense in the Texas and East segments, respectively
Business Metrics	Business Metrics													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
Mass Market electricity sales volume (GWh)														Mass Market electricity sales volume (GWh)	7,990		2,494		—				10,484
C&I electricity sales volume (GWh)														C&I electricity sales volume (GWh)	4,549		282		—				4,831
Natural gas sales volume (MDth)														Natural gas sales volume (MDth)	—		10,547		—				10,547
Average retail Mass Market customer count (in thousands)														Average retail Mass Market customer count (in thousands)	2,308		1,020		—				3,328
Ending retail Mass Market customer count (in thousands)														Ending retail Mass Market customer count (in thousands)	2,290		1,035		—				3,325
GWh sold														GWh sold	8,928		4,003		1,940				14,871
GWh generated:^(a)														GWh generated:^(a)
Coal														Coal	4,607		2,326		—				6,933
Gas														Gas	489		151		1,932				2,572
Nuclear														Nuclear	2,538		—		—				2,538
Oil														Oil	—		5		—				5
Renewables														Renewables	—		—		8				8
Total														Total	7,634		2,482		1,940				12.056
^(a) Includes owned generation, and excludes equity investments														^(a) Includes owned generation, and excludes equity investments

The table below represents the weather metrics for the three months ended ~~September 30, 2019~~March 31, 2020 and ~~2018:~~2019:


		Three months ended September 30,				Three months ended March 31,
Weather Metrics	Weather Metrics	Texas	East/West/Other^(b)	Weather Metrics	Texas	East	West/Other ^(b)
2019
2020				2020
CDDs ^(a)	CDDs ^(a)	1,840	1,102	CDDs ^(a)	170	56	76
HDDs ^(a)	HDDs ^(a)	—	16	HDDs ^(a)	791	2,045	994
2018
2019				2019
CDDs	CDDs	1,656	1,099	CDDs	75	34	31
HDDs	HDDs	1	18	HDDs	1,041	2,457	1,192
10-year average	10-year average			10-year average
CDDs	CDDs	1,672	1,021	CDDs	104	35	46
HDDs	HDDs	6	28	HDDs	995	2,458	1,110

(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

Gross margin increased $98 million and economic gross margin increased $70 million, both of which include intercompany sales, during the three months ended March 31, 2020, compared to the same period in 2019.

The ~~following is a discussion of~~tables below describe the changes in gross margin and economic gross margin ~~for Retail.~~by segment:

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~~due to lower costs to serve the retail load, including $43 million driven by ~~higher~~a reduction of power and fuel prices due to lower natural gas prices, and $15 million due to a 2% reduction in volumes ~~from Stream Energy and other customer acquisitions~~				$	5158
Higher gross margin due to a $35 million increase in revenue from the ~~favorable impact from weather~~acquisition of Stream Energy in August 2019 and higher net rates of $34 million, driven by ~~an increase in load~~customer term, product and mix, partially offset by $38 million due to lower volumes of ~~560,000 MWh in 2019 as compared to 2018~~	115,000 MWhs from the unfavorable impact of weather			2731
~~Higher~~Lower gross margin from ~~Mass due~~net sales of generation 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 increasethird parties, as the Company's Texas generation was fully utilized to serve its retail customers in ~~power prices~~	2020			7 (19)
Lower gross margin due to the ~~unfavorable impact~~sale of ~~purchasing incremental supply at escalated prices above $1,000/MWh during periods of extreme weather~~	emissions in 2019			~~(41)~~(13)
Lower gross margin ~~from demand response activities~~ due to ~~lower cleared auction prices in PJM base capacity in 2019 as compared to 2018~~	market optimization activities			~~(10)~~(6)
Other	4

Increase in economic gross margin		$	3455
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges			~~550~~23
Increase in contract and emission credit amortization	4
Increase in gross margin		$	~~584~~82

7458

~~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~~East


		(In millions)
~~Higher~~Lower gross margin due to a ~~26% increase~~lower of cost or market adjustment on oil inventory in ~~average realized prices due to heat rate expansion, partially offset by the intersegment transactions at annual average power prices~~2020		$	~~140~~ (29)
Lower gross margin primarily due to a 79% decrease in economic generation volumes primarily due to dark spread contractions and planned outages in 2019		~~Higher~~(17)
Lower gross margin from market optimization activities		(13)
Lower gross margin due to ~~Gregory return to service~~a 24% decrease in New England generation capacity prices		35 (11)
Higher gross margin due to ~~a 36%~~lower supply costs coupled with an increase in ~~gas generation volume attributed to spark spread expansion, partially offset by increased forced outages at WA Parish~~load contract volumes		1619
Higher gross margin due to increased volumes from ~~commercial optimization activities~~the acquisition of Stream Energy in August 2019		12
Higher gross margin due to lower supply costs driven by lower electricity and natural gas prices of approximately $8 per MWh, or $23 million, offset by lower revenues of approximately $3 per MWh, or $12 million		11
~~Higher gross margin due to margin enhancement initiatives from reduced fuel supply costs~~Other	4
~~Other~~	~~(1)~~(3)
~~Increase~~Decrease in economic gross margin		$	~~205~~ (31)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges		~~(497)~~(8)
~~Decrease in contract and emission credit amortization~~	2
Decrease in gross margin		$	~~(290)~~(39)

~~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~~Higher gross margin due to ~~the deconsolidations of Agua Caliente~~generation outage insurance proceeds received 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~~2020 for forced outages in 2019	~~(19)~~$
~~Lower gross margin from commercial optimization activities~~	~~(16)~~30
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~~extended forced outage at the Sunrise facility in 2019	810
Higher gross margin ~~primarily~~driven by increased California resource adequacy pricing and lower capacity purchases due to ~~an increase in average realized prices primarily due to a 10% increase in~~ the ~~West~~Sunrise outage	57
Other	~~(4)~~(1)

~~Decrease~~Increase in economic gross margin	$	~~(106)~~46
~~Decrease~~Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	~~(49)~~9

~~Decrease~~Increase in gross margin	$	~~(155)~~55

7559

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$24 million during the three months ended ~~September 30, 2019,~~March 31, 2020, compared to the same period in ~~2018.~~2019.

The breakdown of gains and losses included in operating revenues and operating costs and expenses by ~~region~~segment 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


	Three months ended March 31, 2020
(In millions)	Texas		East		West/Other		Eliminations		Total
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges	$	—	$	(14)	$	(5)	$	1	$	(18)

Net unrealized (losses)/gains on open positions related to economic hedges	—		(6)		20		—		14
Total mark-to-market (losses)/gains in operating revenues	$	—	$	(20)	$	15	$	1	$	(4)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses on settled positions related to economic hedges	$	22	$	6	$	—	$	(1)	$	27
Reversal of acquired loss/(gain) positions related to economic hedges	2		(1)		—		—		1
Net unrealized gains/(losses) on open positions related to economic hedges	25		(5)		—		—		20
Total mark-to-market gains in operating costs and expenses	$	49	$	—	$	—	$	(1)	$	48

~~(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)


	Three months ended March 31, 2019
(In millions)	Texas		East		West/Other		Eliminations		Total
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	11	$	(20)	$	1	$	—	$	(8)

Net unrealized gains on open positions related to economic hedges	20		5		3		—		28
Total mark-to-market gains/(losses) in operating revenues	$	31	$	(15)	$	4	$	—	$	20
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	23	$	5	$	(1)	$	—	$	27
Reversal of acquired (gain) positions related to economic hedges	—		(2)		—		—		(2)
Net unrealized (losses)/gains on open positions related to economic hedges	(28)		—		3		—		(25)
Total mark-to-market (losses)/gains in operating costs and expenses	$	(5)	$	3	$	2	$	—	$	—

~~(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,~~March 31, 2020, the ~~$210~~$4 million loss in operating revenues from economic hedge positions was driven primarily by ~~a decrease~~the reversal of previously recognized unrealized gains on contracts that settled during the period, largely offset 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 losses~~gains on ~~contracts that settled during the period.~~power positions due to declines in West/Other power prices. The ~~$146~~$48 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~~losses on contracts that settled during the ~~period.~~

period, as well as gains on ERCOT heat rate positions due to heat rate expansion.

For the three months ended ~~September 30, 2018,~~March 31, 2019, the ~~$55~~$20 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~~gains on power positions due to declines in ~~New York capacity~~power prices, ~~and outer year natural gas prices.~~partially offset by the reversal of previously recognized unrealized gains on contracts that settled during the period. The ~~$123 million loss~~flat change in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized ~~gains~~unrealized losses on contracts that ~~settled~~settles during the period, ~~and acquired positions, as well as~~offset by a decrease in the value of open positions as a result of ~~lower near-term natural gas prices.~~ERCOT heat rate contraction and the reversal of acquired gain positions.

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~~March 31, 2020 and ~~2018.~~2019. The realized and unrealized financial and physical trading results are included in operating ~~revenue within the Generation segment.~~revenue. The Company's trading activities are subject to limits based on the Company's Risk Management Policy.


		Three months ended September 30,							Three months ended March 31,
(In millions)	(In millions)	2019		2018		(In millions)	2020		2019
Trading gains/(losses)
Trading gains						Trading gains
Realized	Realized	$	13	$	23	Realized	$	7	$	16
Unrealized	Unrealized	(4)		4		Unrealized	11		7
Total trading gains	Total trading gains	$	9	$	27	Total trading gains	$	18	$	23

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~~


(In millions)	Texas		East		West/Other		Corporate		Eliminations		Total

Three months ended March 31, 2020	$	175	$	88	$	30	$	2	$	(2)	$	293
Three months ended March 31, 2019	151		67		28		3		(1)		248

Operations and maintenance ~~expenses~~expense increased by ~~$20~~$45 million for the three months ended ~~September 30, 2019,~~March 31, 2020, compared to the same period in ~~2018,~~2019, due to the following:


	(In millions)
Increase due to the final settlement of the asbestos liability for Midwest Generation and the resulting reduction of the accrual in 2019	$	27
Increase in outages primarily due to ~~forced~~planned outages at ~~WA Parish~~STP and Midwest Generation in 2020	$		11
~~Increase primarily related to the lease of Cottonwood from February 4, 2019~~	1025
Increase due to ~~XOOM and~~acquisition of Stream Energy ~~acquisitions~~ in ~~June 2018 and~~ August 2019 ~~respectively~~	59
~~Increase in costs due to Gregory return to service~~	4
~~Increase for margin enhancement initiatives~~	3
Decrease in variable chemical costs due to a reduction in East generation volumes	~~(13)~~(12)
~~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 (4)
Increase in operations and maintenance expense	$	2045

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


(In millions)	Texas		East		West/Other		Total

Three months ended March 31, 2020	$	33	$	26	$	3	$	62
Three months ended March 31, 2019	33		20		4		57

Increase in other cost of operations is primarily due to additional ARO expense of $5 million at the Joliet plant, as a result of regulatory requirements.

Depreciation and Amortization

Depreciation and amortization ~~decreased~~are comprised of the following:


(In millions)	Texas		East		West/Other		Corporate		Total
Three months ended March 31, 2020	$	59	$	33	$	8	$	9	$	109
Three months ended March 31, 2019	40		26		11		8		85

Depreciation and amortization increased by $8$24 million, ~~for the three months ended September 30, 2019, compared~~primarily due 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


(In millions)	Texas		East		West/Other		Corporate		Total
Three months ended March 31, 2020	$	130	$	64	$	9	$	6	$	209
Three months ended March 31, 2019	117		65		7		5		194

Selling, general and administrative expenses ~~decreased~~increased by $1$15 million for the three months ended ~~September 30, 2019,~~March 31, 2020, compared to the same period in ~~2018,~~2019, primarily 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)~~

acquisition of Stream Energy in August 2019.

Reorganization Costs

Reorganization costs, primarily related to employee severance and contract cancellation costs, decreased by ~~$26~~$10 million for the three months ended ~~September 30, 2019~~March 31, 2020, compared to the same period in ~~2018,~~2019, driven primarily by significant achievement of the operations and cost excellence portion of the Transformation Plan during ~~2018.~~2019.

Gain on Sale of Assets

A gain on sale of assets of ~~$14~~$6 million was recorded for the three months ended ~~September 30, 2018, primarily driven by~~March 31, 2020, related to the sale of ~~BETM.~~land and investments in January 2020.

Equity in ~~earnings~~losses of unconsolidated affiliates

Equity in ~~earnings~~losses of unconsolidated affiliates ~~increased~~decreased by $9$10 million for the three months ended ~~September 30, 2019,~~March 31, 2020, compared to the three months ended ~~September 30, 2018. The increase is~~March 31, 2019, primarily due to ~~higher earnings at Ivanpah and Agua Caliente, associated with favorable weather and operational improvements and two additional months~~an increase in interest expense on an investment in 2019 as a result of ~~earnings in~~ the ~~current period, respectively, partially~~PG&E bankruptcy, offset by ~~lower fuel costs at Watson~~earnings received in ~~2018.~~2020 from an investment, due to a favorable property tax assessment.

Impairment losses on investments

Impairment losses on investments of ~~$107~~$18 million ~~was~~were recorded for the three months ended ~~September 30, 2019, primarily~~March 31, 2020, related to ~~the impairment of~~ Petra Nova Parish Holdings, as further discussed in Note 118, ~~Investments Accounted for Using the Equity Method and Variable Interest Entities, or VIEs.~~Impairments.

~~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~~Gross Margin

Economic Gross Margin

The below tables present the composition and reconciliation of gross margin and economic gross margin for the three months ended March 31, 2020 and 2019:


	Three months ended March 31, 2020
($ In millions)	Texas		East		West/Other		Corporate/Eliminations		Total
Retail revenue	$	1,292	$	370	$	—	$	(1)	$	1,661
Energy revenue	5		45		75		(1)		124
Capacity revenue	—		134		15		—		149
Mark-to-market for economic hedging activities	—		(20)		15		1		(4)

Other revenue	61		10		20		(2)		89
Operating revenue	1,358		539		125		(3)		2,019
Cost of fuel	(103)		(55)		(36)		—		(194)
Purchased power	(265)		(152)		(6)		—		(423)
Other cost of sales^(a)(b)	(462)		(91)		20		1		(532)
Mark-to-market for economic hedging activities	49		—		—		(1)		48
Contract and emission credit amortization	(1)		—		—		—		(1)
Gross margin	$	576	$	241	$	103	$	(3)	$	917
Less: Mark-to-market for economic hedging activities, net	49		(20)		15		—		44
Less: Contract and emission credit amortization, net	(1)		—		—		—		(1)
Economic gross margin	$	528	$	261	$	88	$	(3)	$	874
^(a) Includes capacity and emissions credits
^(b) Includes $429 million and $2 million of TDSP expense in Texas and East, respectively
Business Metrics
Mass Market electricity sales volume (GWh)	7,748		2,548		—				10,296
C&I electricity sales volume (GWh)	4,456		389		—				4,845
Natural gas sales volume (MDth)	—		10,509		—				10,509
Average retail Mass Market customer count (in thousands)	2,442		1,220		—				3,662
Ending retail Mass Market customer count (in thousands)	2,439		1,212		—				3,651
GWh sold	67		2,535		2,559				5,161
GWh generated:^(a)
Coal	3,060		335		—				3,395
Gas	674		149		2,355				3,178
Nuclear	2,302		—		—				2,302
Oil	—		18		—				18

Total	6,036		502		2,355				8,893
^(a) Includes owned generation, and excludes equity investments


	Three months ended March 31, 2019
($ In millions)	Texas		East		West/Other		Corporate/Eliminations		Total
Retail revenue	$	1,253	$	338	$	—	$	(2)	$	1,589
Energy revenue	105		126		58		1		290
Capacity revenue	—		144		12		—		156
Mark-to-market for economic hedging activities	31		(15)		4		—		20

Other revenue	77		16		19		(2)		110
Operating revenue	1,466		609		93		(3)		2,165
Cost of fuel	(149)		(66)		(36)		—		(251)
Purchased power	(327)		(191)		—		—		(518)
Other cost of sales^(a)(b)	(486)		(75)		(11)		—		(572)
Mark-to-market for economic hedging activities	(5)		3		2		—		—
Contract and emission credit amortization	(5)		—		—		—		(5)
Gross margin	$	494	$	280	$	48	$	(3)	$	819
Less: Mark-to-market for economic hedging activities, net	26		(12)		6		—		20
Less: Contract and emission credit amortization, net	(5)		—		—		—		(5)
Economic gross margin	$	473	$	292	$	42	$	(3)	$	804
(a) Includes capacity and emissions credits
(b) Includes $422 million and $3 million of TDSP expense in the Texas and East segments, respectively
Business Metrics
Mass Market electricity sales volume (GWh)	7,990		2,494		—				10,484
C&I electricity sales volume (GWh)	4,549		282		—				4,831
Natural gas sales volume (MDth)	—		10,547		—				10,547
Average retail Mass Market customer count (in thousands)	2,308		1,020		—				3,328
Ending retail Mass Market customer count (in thousands)	2,290		1,035		—				3,325
GWh sold	8,928		4,003		1,940				14,871
GWh generated:^(a)
Coal	4,607		2,326		—				6,933
Gas	489		151		1,932				2,572
Nuclear	2,538		—		—				2,538
Oil	—		5		—				5
Renewables	—		—		8				8
Total	7,634		2,482		1,940				12.056
^(a) Includes owned generation, and excludes equity investments

The table below represents the weather metrics for the three months ended March 31, 2020 and 2019:


	Three months ended March 31,
Weather Metrics	Texas	East	West/Other ^(b)
2020
CDDs ^(a)	170	56	76
HDDs ^(a)	791	2,045	994
2019
CDDs	75	34	31
HDDs	1,041	2,457	1,192
10-year average
CDDs	104	35	46
HDDs	995	2,458	1,110

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

Gross Margin and Economic Gross Margin

The tables below describe the changes in gross margin and economic gross margin by segment:

Texas


	(In millions)
Higher gross margin due to lower costs to serve the retail load, including $43 million driven by a reduction of power and fuel prices due to lower natural gas prices, and $15 million due to a 2% reduction in volumes	$	58
Higher gross margin due to a $35 million increase in revenue from the acquisition of Stream Energy in August 2019 and higher net rates of $34 million, driven by customer term, product and mix, partially offset by $38 million due to lower volumes of 115,000 MWhs from the unfavorable impact of weather	31
Lower gross margin from net sales of generation to third parties, as the Company's Texas generation was fully utilized to serve its retail customers in 2020	(19)
Lower gross margin due to the sale of emissions in 2019	(13)
Lower gross margin due to market optimization activities	(6)
Other	4
Increase in economic gross margin	$	55
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	23
Increase in contract and emission credit amortization	4
Increase in gross margin	$	82

East


	(In millions)
Lower gross margin due to a lower of cost or market adjustment on oil inventory in 2020	$	(29)
Lower gross margin primarily due to a 79% decrease in economic generation volumes primarily due to dark spread contractions and planned outages in 2019	(17)
Lower gross margin from market optimization activities	(13)
Lower gross margin due to a 24% decrease in New England generation capacity prices	(11)
Higher gross margin due to lower supply costs coupled with an increase in load contract volumes	19
Higher gross margin due to increased volumes from the acquisition of Stream Energy in August 2019	12
Higher gross margin due to lower supply costs driven by lower electricity and natural gas prices of approximately $8 per MWh, or $23 million, offset by lower revenues of approximately $3 per MWh, or $12 million	11
Other	(3)
Decrease in economic gross margin	$	(31)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(8)

Decrease in gross margin	$	(39)

West/Other


	(In millions)
Higher gross margin due to generation outage insurance proceeds received in 2020 for forced outages in 2019	$	30
Higher gross margin due to an extended forced outage at the Sunrise facility in 2019	10
Higher gross margin driven by increased California resource adequacy pricing and lower capacity purchases due to the Sunrise outage	7
Other	(1)

Increase in economic gross margin	$	46
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	9

Increase in gross margin	$	55

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 $24 million during the three months ended March 31, 2020, compared to the same period in 2019.

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


	Three months ended March 31, 2020
(In millions)	Texas		East		West/Other		Eliminations		Total
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges	$	—	$	(14)	$	(5)	$	1	$	(18)

Net unrealized (losses)/gains on open positions related to economic hedges	—		(6)		20		—		14
Total mark-to-market (losses)/gains in operating revenues	$	—	$	(20)	$	15	$	1	$	(4)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses on settled positions related to economic hedges	$	22	$	6	$	—	$	(1)	$	27
Reversal of acquired loss/(gain) positions related to economic hedges	2		(1)		—		—		1
Net unrealized gains/(losses) on open positions related to economic hedges	25		(5)		—		—		20
Total mark-to-market gains in operating costs and expenses	$	49	$	—	$	—	$	(1)	$	48


	Three months ended March 31, 2019
(In millions)	Texas		East		West/Other		Eliminations		Total
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	11	$	(20)	$	1	$	—	$	(8)

Net unrealized gains on open positions related to economic hedges	20		5		3		—		28
Total mark-to-market gains/(losses) in operating revenues	$	31	$	(15)	$	4	$	—	$	20
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	23	$	5	$	(1)	$	—	$	27
Reversal of acquired (gain) positions related to economic hedges	—		(2)		—		—		(2)
Net unrealized (losses)/gains on open positions related to economic hedges	(28)		—		3		—		(25)
Total mark-to-market (losses)/gains in operating costs and expenses	$	(5)	$	3	$	2	$	—	$	—

For the three months ended March 31, 2020, the $4 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, largely offset by an increase in the value of open positions, as a result of gains on power positions due to declines in West/Other power prices. The $48 million gain in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized losses on contracts that settled during the period, as well as gains on ERCOT heat rate positions due to heat rate expansion.

For the three months ended March 31, 2019, the $20 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 gains on power positions due to declines in power prices, partially offset by the reversal of previously recognized unrealized gains on contracts that settled during the period. The flat change in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized losses on contracts that settles during the period, offset by a decrease in the value of open positions as a result of ERCOT heat rate contraction and the reversal of acquired gain positions.

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 March 31, 2020 and 2019. The realized and unrealized financial and physical trading results are included in operating revenue. The Company's trading activities are subject to limits based on the Company's Risk Management Policy.


	Three months ended March 31,
(In millions)	2020		2019
Trading gains
Realized	$	7	$	16
Unrealized	11		7
Total trading gains	$	18	$	23

Operations and Maintenance Expense

~~Interest~~Operations and maintenance expense ~~decreased~~are comprised of the following:


(In millions)	Texas		East		West/Other		Corporate		Eliminations		Total

Three months ended March 31, 2020	$	175	$	88	$	30	$	2	$	(2)	$	293
Three months ended March 31, 2019	151		67		28		3		(1)		248

Operations and maintenance expense increased by ~~$23~~$45 million for the three months ended ~~September 30, 2019,~~March 31, 2020, compared to the same period in ~~2018,~~2019, due to the following:


	(In millions)
~~Decrease related~~Increase due to the ~~debt~~final settlement of the asbestos liability for Midwest Generation and the resulting reduction of ~~$1.2 billion and refinancing $2.4 billion of debt at lower interest rates~~the accrual in 2019 ~~and 2018~~	$	~~(24)~~27
Increase in outages primarily due to planned outages at STP and Midwest Generation in 2020	25
Increase due to acquisition of Stream Energy in August 2019	9
Decrease ~~related~~in variable chemical costs due to ~~the deconsolidation of Agua Caliente~~a reduction in ~~2018~~East generation volumes	(12)




Other	(4)
~~Other~~	5
~~Decrease~~Increase in ~~interest~~operations and maintenance expense	$	~~(23)~~45

~~Income Tax Expense~~

~~For~~Other Cost of Operations

Other cost of operations are comprised of the ~~three months ended September 30, 2019, income tax~~following:


(In millions)	Texas		East		West/Other		Total

Three months ended March 31, 2020	$	33	$	26	$	3	$	62
Three months ended March 31, 2019	33		20		4		57

Increase in other cost of operations is primarily due to additional ARO expense of $6$5 million ~~was recorded on pre-tax income~~at the Joliet plant, as a result of ~~$380 million. For~~regulatory requirements.

Depreciation and Amortization

Depreciation and amortization are comprised of the ~~same period in 2018, income tax expense of $8~~following:


(In millions)	Texas		East		West/Other		Corporate		Total
Three months ended March 31, 2020	$	59	$	33	$	8	$	9	$	109
Three months ended March 31, 2019	40		26		11		8		85

Depreciation and amortization increased by $24 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~~acquisition of Stream Energy in August 2019.

Selling, General and Administrative

Selling, general and administrative expenses are comprised of the ~~change in valuation allowance, partially offset~~following:


(In millions)	Texas		East		West/Other		Corporate		Total
Three months ended March 31, 2020	$	130	$	64	$	9	$	6	$	209
Three months ended March 31, 2019	117		65		7		5		194

Selling, general and administrative expenses increased 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~~$15 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~~March 31, 2020, 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, primarily due to the ~~increased forward power prices~~acquisition of Stream Energy in ~~summer~~August 2019.

Reorganization Costs

Reorganization costs, primarily related to employee severance and contract cancellation costs, decreased by $10 million for the three months ended March 31, 2020, compared to the same period in 2019, driven primarily by significant achievement of the operations and cost excellence portion of the Transformation Plan during 2019.

Gain on Sale of Assets

A gain on sale of assets of $6 million was recorded for the three months ended March 31, 2020, related to the sale of land and investments in January 2020.

Equity in losses of unconsolidated affiliates

Equity in losses of unconsolidated affiliates decreased by $10 million for the three months ended March 31, 2020, compared to the three months ended March 31, 2019, primarily due to an increase in interest expense on an investment in 2019 as a result of the PG&E bankruptcy, offset by earnings received in 2020 from an investment, due to a favorable property tax assessment.

Impairment losses on investments

Impairment losses on investments of $18 million were recorded for the three months ended March 31, 2020, related to Petra Nova Parish Holdings, as further discussed in Note 8, Impairments.

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~~three months ended ~~September 30, 2019~~March 31, 2020 and ~~2018:~~2019:


		Nine months ended September 30, 2019
				Generation															Three months ended March 31, 2020
($ In millions)	($ In millions)	Retail		Texas		East/West/Other^(a)		Subtotal		Corporate/Eliminations		Total		($ In millions)	Texas		East		West/Other		Corporate/Eliminations		Total
Retail revenue														Retail revenue	$	1,292	$	370	$	—	$	(1)	$	1,661
Energy revenue	Energy revenue	$	—	$	1,628	$	578	$	2,206	$	(1,209)	$	997	Energy revenue	5		45		75		(1)		124
Capacity revenue	Capacity revenue	—		—		460		460		1		461		Capacity revenue	—		134		15		—		149
Retail revenue		5,898		—		—		—		(2)		5,896
Mark-to-market for economic hedging activities	Mark-to-market for economic hedging activities	1		233		40		273		(223)		51		Mark-to-market for economic hedging activities	—		(20)		15		1		(4)

Other revenue	Other revenue	—		77		148		225		(4)		221		Other revenue	61		10		20		(2)		89
Operating revenue	Operating revenue	5,899		1,938		1,226		3,164		(1,437)		7,626		Operating revenue	1,358		539		125		(3)		2,019
Cost of fuel	Cost of fuel	(61)		(586)		(300)		(886)		5		(942)		Cost of fuel	(103)		(55)		(36)		—		(194)
Other cost of sales ^(b)		(4,473)		(137)		(217)		(354)		1,207		(3,620)
Purchased power														Purchased power	(265)		(152)		(6)		—		(423)
Other cost of sales^(a)(b)														Other cost of sales^(a)(b)	(462)		(91)		20		1		(532)
Mark-to-market for economic hedging activities	Mark-to-market for economic hedging activities	(302)		4		1		5		223		(74)		Mark-to-market for economic hedging activities	49		—		—		(1)		48
Contract and emission credit amortization	Contract and emission credit amortization	—		(16)		—		(16)		—		(16)		Contract and emission credit amortization	(1)		—		—		—		(1)
Gross margin	Gross margin	$	1,063	$	1,203	$	710	$	1,913	$	(2)	$	2,974	Gross margin	$	576	$	241	$	103	$	(3)	$	917
Less: Mark-to-market for economic hedging activities, net	Less: Mark-to-market for economic hedging activities, net	(301)		237		41		278		—		(23)		Less: Mark-to-market for economic hedging activities, net	49		(20)		15		—		44
Less: Contract and emission credit amortization, net	Less: Contract and emission credit amortization, net	—		(16)		—		(16)		—		(16)		Less: Contract and emission credit amortization, net	(1)		—		—		—		(1)
Economic gross margin	Economic gross margin	$	1,364	$	982	$	669	$	1,651	$	(2)	$	3,013	Economic gross margin	$	528	$	261	$	88	$	(3)	$	874
^(a) Includes capacity and emissions credits														^(a) Includes capacity and emissions credits
^(b) Includes $429 million and $2 million of TDSP expense in Texas and East, respectively														^(b) Includes $429 million and $2 million of TDSP expense in Texas and East, respectively
Business Metrics	Business Metrics													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
Mass Market electricity sales volume (GWh)														Mass Market electricity sales volume (GWh)	7,748		2,548		—				10,296
C&I electricity sales volume (GWh)														C&I electricity sales volume (GWh)	4,456		389		—				4,845
Natural gas sales volume (MDth)														Natural gas sales volume (MDth)	—		10,509		—				10,509
Average retail Mass Market customer count (in thousands)														Average retail Mass Market customer count (in thousands)	2,442		1,220		—				3,662
Ending retail Mass Market customer count (in thousands)														Ending retail Mass Market customer count (in thousands)	2,439		1,212		—				3,651
GWh sold														GWh sold	67		2,535		2,559				5,161
GWh generated:^(a)														GWh generated:^(a)
Coal														Coal	3,060		335		—				3,395
Gas														Gas	674		149		2,355				3,178
Nuclear														Nuclear	2,302		—		—				2,302
Oil														Oil	—		18		—				18

Total														Total	6,036		502		2,355				8,893
^(a) Includes owned generation, and excludes equity investments														^(a) Includes owned generation, and excludes equity investments

8156


		Nine months ended September 30, 2018
				Generation															Three months ended March 31, 2019
($ In millions)	($ In millions)	Retail		Texas		East/West/Other^(a)(b)		Subtotal		Corporate/Eliminations		Total		($ In millions)	Texas		East		West/Other		Corporate/Eliminations		Total
Retail revenue														Retail revenue	$	1,253	$	338	$	—	$	(2)	$	1,589
Energy revenue	Energy revenue	$	—	$	1,251	$	937	$	2,188	$	(890)	$	1,298	Energy revenue	105		126		58		1		290
Capacity revenue	Capacity revenue	—		1		498		499		1		500		Capacity revenue	—		144		12		—		156
Retail revenue		5,502		—		—		—		(4)		5,498
Mark-to-market for economic hedging activities	Mark-to-market for economic hedging activities	(5)		(14)		9		(5)		(21)		(31)		Mark-to-market for economic hedging activities	31		(15)		4		—		20

Other revenue	Other revenue	—		72		162		234		(13)		221		Other revenue	77		16		19		(2)		110
Operating revenue	Operating revenue	5,497		1,310		1,606		2,916		(927)		7,486		Operating revenue	1,466		609		93		(3)		2,165
Cost of fuel	Cost of fuel	(13)		(556)		(440)		(996)		(3)		(1,012)		Cost of fuel	(149)		(66)		(36)		—		(251)
Other cost of sales ^(b)		(4,117)		(113)		(215)		(328)		898		(3,547)
Purchased power														Purchased power	(327)		(191)		—		—		(518)
Other cost of sales^(a)(b)														Other cost of sales^(a)(b)	(486)		(75)		(11)		—		(572)
Mark-to-market for economic hedging activities	Mark-to-market for economic hedging activities	86		(5)		(9)		(14)		21		93		Mark-to-market for economic hedging activities	(5)		3		2		—		—
Contract and emission credit amortization	Contract and emission credit amortization	—		(19)		(1)		(20)		—		(20)		Contract and emission credit amortization	(5)		—		—		—		(5)
Gross margin	Gross margin	$	1,453	$	617	$	941	$	1,558	$	(11)	$	3,000	Gross margin	$	494	$	280	$	48	$	(3)	$	819
Less: Mark-to-market for economic hedging activities, net	Less: Mark-to-market for economic hedging activities, net	81		(19)		—		(19)		—		62		Less: Mark-to-market for economic hedging activities, net	26		(12)		6		—		20
Less: Contract and emission credit amortization, net	Less: Contract and emission credit amortization, net	—		(19)		(1)		(20)		—		(20)		Less: Contract and emission credit amortization, net	(5)		—		—		—		(5)
Economic gross margin	Economic gross margin	$	1,372	$	655	$	942	$	1,597	$	(11)	$	2,958	Economic gross margin	$	473	$	292	$	42	$	(3)	$	804
(a) Includes capacity and emissions credits														(a) Includes capacity and emissions credits
(b) Includes $422 million and $3 million of TDSP expense in the Texas and East segments, respectively														(b) Includes $422 million and $3 million of TDSP expense in the Texas and East segments, respectively
Business Metrics	Business Metrics													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
Mass Market electricity sales volume (GWh)														Mass Market electricity sales volume (GWh)	7,990		2,494		—				10,484
C&I electricity sales volume (GWh)														C&I electricity sales volume (GWh)	4,549		282		—				4,831
Natural gas sales volume (MDth)														Natural gas sales volume (MDth)	—		10,547		—				10,547
Average retail Mass Market customer count (in thousands)														Average retail Mass Market customer count (in thousands)	2,308		1,020		—				3,328
Ending retail Mass Market customer count (in thousands)														Ending retail Mass Market customer count (in thousands)	2,290		1,035		—				3,325
GWh sold														GWh sold	8,928		4,003		1,940				14,871
GWh generated:^(a)														GWh generated:^(a)
Coal														Coal	4,607		2,326		—				6,933
Gas														Gas	489		151		1,932				2,572
Nuclear														Nuclear	2,538		—		—				2,538
Oil														Oil	—		5		—				5
Renewables														Renewables	—		—		8				8
Total														Total	7,634		2,482		1,940				12.056
^(a) Includes owned generation, and excludes equity investments														^(a) Includes owned generation, and excludes equity investments

The table below represents the weather metrics for the ~~nine~~three months ended ~~September 30, 2019~~March 31, 2020 and ~~2018:~~2019:


		Nine months ended September 30,				Three months ended March 31,
Weather Metrics	Weather Metrics	Texas	East/West/Other^(b)	Weather Metrics	Texas	East	West/Other ^(b)
2019
2020				2020
CDDs ^(a)	CDDs ^(a)	2,848	1,593	CDDs ^(a)	170	56	76
HDDs ^(a)	HDDs ^(a)	1,111	1,912	HDDs ^(a)	791	2,045	994
2018
2019				2019
CDDs	CDDs	2,902	1,672	CDDs	75	34	31
HDDs	HDDs	1,059	1,862	HDDs	1,041	2,457	1,192
10-year average	10-year average			10-year average
CDDs	CDDs	2,787	1,550	CDDs	104	35	46
HDDs	HDDs	1,037	1,878	HDDs	995	2,458	1,110

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

~~Retail~~ Gross Margin and Economic Gross Margin

The ~~following is a discussion of~~tables below describe the changes in gross margin and economic gross margin ~~for Retail.~~by segment:

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
Texas


	(In millions)
Higher gross margin due to lower costs to serve the retail load, including $43 million driven by a reduction of power and fuel prices due to lower natural gas prices, and $15 million due to a 2% reduction in volumes	$	58
Higher gross margin due to a $35 million increase in revenue from the acquisition of Stream Energy in August 2019 and higher net rates of $34 million, driven by customer term, product and mix, partially offset by $38 million due to lower volumes of 115,000 MWhs from the unfavorable impact of weather	31
Lower gross margin from net sales of generation to third parties, as the Company's Texas generation was fully utilized to serve its retail customers in 2020	(19)
Lower gross margin due to the sale of emissions in 2019	(13)
Lower gross margin due to market optimization activities	(6)
Other	4
Increase in economic gross margin	$	55
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	23
Increase in contract and emission credit amortization	4
Increase in gross margin	$	82

~~(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:~~58

East


	(In millions)
Lower gross margin ~~from demand response activities~~ due to a lower ~~auction clearing prices and fewer MW's sold primarily~~of cost or market adjustment on oil inventory in ~~PJM in 2019 as compared to 2018~~2020	$	~~(37)~~(29)
Lower gross margin primarily due to a 79% decrease in economic generation volumes primarily due to dark spread contractions and planned outages in 2019	(17)
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~~market optimization activities	~~(25)~~(13)
Lower gross margin due to ~~the unfavorable impact of purchasing incremental supply at escalated~~a 24% decrease in New England generation capacity prices ~~above $1,000/MWh during periods of extreme weather~~	~~(24)~~(11)
~~Lower~~Higher gross margin ~~from Mass~~ due to ~~higher~~lower supply costs ~~driven by~~coupled with 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~~load contract volumes	~~(15)~~19

Higher gross margin due to increased volumes from the acquisition of Stream Energy in August 2019	12
Higher gross margin due to lower supply costs driven by ~~higher volume from XOOM~~lower electricity and ~~Stream acquisitions~~natural gas prices of approximately $8 per MWh, or $23 million, offset by lower revenues of approximately $3 per MWh, or $12 million	11
Other	93 (3)
Decrease in economic gross margin	$	~~(8)~~(31)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	~~(382)~~(8)

Decrease in gross margin	$	~~(390)~~(39)

~~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~~West/Other


	(In millions)
Higher gross margin due to ~~a 24% increase~~generation outage insurance proceeds received in ~~average realized prices due to heat rate expansion~~2020 for forced outages in 2019	$	~~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	5130
Higher gross margin due to ~~Gregory return to service~~an extended forced outage at the Sunrise facility in 2019	3510
Higher gross margin ~~from commercial optimization activities~~	20
~~Higher gross margin~~driven by increased California resource adequacy pricing and lower capacity purchases due to ~~margin enhancement initiatives from reduced fuel supply costs~~the Sunrise outage	13
~~Lower gross margin from lower sales of NOx emission credits~~	~~(22)~~7
Other	1 (1)

Increase in economic gross margin	$	~~327~~46
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	~~256~~9
~~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)~~55

8459

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~~increased by ~~$85~~$24 million during the ~~nine~~three months ended ~~September 30, 2019,~~March 31, 2020, compared to the same period in ~~2018.~~2019.

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


		Nine months ended September 30, 2019																	Three months ended March 31, 2020
				Generation
		Retail		Texas		East/West/Other		Eliminations^(a)		Total
		(In millions)
(In millions)												(In millions)	Texas		East		West/Other		Eliminations		Total
Mark-to-market results in operating revenues	Mark-to-market results in operating revenues											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
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges												Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges	$	—	$	(14)	$	(5)	$	1	$	(18)

Net unrealized (losses)/gains on open positions related to economic hedges	Net unrealized (losses)/gains on open positions related to economic hedges	(1)		(23)		13		14		3		Net unrealized (losses)/gains on open positions related to economic hedges	—		(6)		20		—		14
Total mark-to-market gains in operating revenues		$	1	$	233	$	40	$	(223)	$	51
Total mark-to-market (losses)/gains in operating revenues												Total mark-to-market (losses)/gains in operating revenues	$	—	$	(20)	$	15	$	1	$	(4)
Mark-to-market results in operating costs and expenses	Mark-to-market results in operating costs and expenses											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)
Reversal of previously recognized unrealized losses on settled positions related to economic hedges												Reversal of previously recognized unrealized losses on settled positions related to economic hedges	$	22	$	6	$	—	$	(1)	$	27
Reversal of acquired loss/(gain) positions related to economic hedges												Reversal of acquired loss/(gain) positions related to economic hedges	2		(1)		—		—		1
Net unrealized gains/(losses) on open positions related to economic hedges	Net unrealized gains/(losses) on open positions related to economic hedges	83		(2)		(1)		(14)		66		Net unrealized gains/(losses) on open positions related to economic hedges	25		(5)		—		—		20
Total mark-to-market (losses)/gains in operating costs and expenses		$	(302)	$	4	$	1	$	223	$	(74)
Total mark-to-market gains in operating costs and expenses												Total mark-to-market gains in operating costs and expenses	$	49	$	—	$	—	$	(1)	$	48

~~(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


	Three months ended March 31, 2019
(In millions)	Texas		East		West/Other		Eliminations		Total
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	11	$	(20)	$	1	$	—	$	(8)

Net unrealized gains on open positions related to economic hedges	20		5		3		—		28
Total mark-to-market gains/(losses) in operating revenues	$	31	$	(15)	$	4	$	—	$	20
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	23	$	5	$	(1)	$	—	$	27
Reversal of acquired (gain) positions related to economic hedges	—		(2)		—		—		(2)
Net unrealized (losses)/gains on open positions related to economic hedges	(28)		—		3		—		(25)
Total mark-to-market (losses)/gains in operating costs and expenses	$	(5)	$	3	$	2	$	—	$	—

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

For the ~~nine~~three months ended ~~September 30, 2019,~~March 31, 2020, 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~~$4 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~~largely offset by an increase in the value of open positions, as a result of ~~decreases~~gains on power positions due to declines in ~~outer year natural gas~~West/Other power prices. The ~~$93~~$48 million gain in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized losses on contracts that settled during the period, as well as gains on ERCOT heat rate positions due to heat rate expansion.

For the three months ended March 31, 2019, the $20 million gain in operating revenues from economic hedge positions was driven primarily by an increase in the value of open positions as a result of ~~ERCOT heat rate expansion and increases~~gains on power positions due to declines in ~~ERCOT electricity~~power prices, partially offset by the reversal of previously recognized unrealized gains on contracts that settled during the period. The flat change in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized losses on contracts that settles during the period, offset by a decrease in the value of open positions as a result of ERCOT heat rate contraction and the reversal of acquired ~~deals.~~gain positions.

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~~three months ended ~~September 30, 2019~~March 31, 2020 and ~~2018.~~2019. The realized and unrealized financial and physical trading results are included in operating ~~revenue within the Generation segment.~~revenue. The Company's trading activities are subject to limits based on the Company's Risk Management Policy.


		Nine months ended September 30,							Three months ended March 31,
(In millions)	(In millions)	2019		2018		(In millions)	2020		2019
Trading gains	Trading gains					Trading gains
Realized	Realized	$	44	$	63	Realized	$	7	$	16
Unrealized	Unrealized	15		17		Unrealized	11		7
Total trading gains	Total trading gains	$	59	$	80	Total trading gains	$	18	$	23

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~~


(In millions)	Texas		East		West/Other		Corporate		Eliminations		Total

Three months ended March 31, 2020	$	175	$	88	$	30	$	2	$	(2)	$	293
Three months ended March 31, 2019	151		67		28		3		(1)		248

Operations and maintenance expense ~~decreased~~increased by ~~$23~~$45 million for the ~~nine~~three months ended ~~September 30, 2019,~~March 31, 2020, compared to the same period in ~~2018,~~2019, due to the following:


	(In millions)
~~Decrease~~Increase due to the final settlement of the asbestos liability for Midwest Generation and the resulting reduction of the accrual ~~for Midwest Generation~~in 2019	$	~~(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~~outages primarily due to planned outages at STP and Midwest Generation in ~~Texas plants in preparation for summer operations~~2020	2125
Increase due to ~~XOOM and~~acquisition of Stream Energy ~~acquisitions~~ in ~~June 2018 and~~ August 2019 ~~respectively~~	13 9
Decrease in variable chemical costs due to a reduction in East generation volumes	(12)




Other	6 (4)
~~Decrease~~ Increase in operations and maintenance expense	$	~~(23)~~45

Other Cost of Operations

Other ~~Cost~~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


(In millions)	Texas		East		West/Other		Total

Three months ended March 31, 2020	$	33	$	26	$	3	$	62
Three months ended March 31, 2019	33		20		4		57

Increase in other cost of operations is primarily due to additional ARO expense of $5 million at the Joliet plant, as a result of regulatory requirements.

~~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~~are comprised of the following:


(In millions)	Texas		East		West/Other		Corporate		Total
Three months ended March 31, 2020	$	59	$	33	$	8	$	9	$	109
Three months ended March 31, 2019	40		26		11		8		85

Depreciation and amortization increased by ~~$70~~$24 million, ~~for the nine months ended September 30, 2019, compared~~primarily due 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 acquisitionsacquisition of Stream Energy ~~and XOOM.~~in August 2019.

Selling, General and Administrative

Selling, general and administrative expenses are 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


(In millions)	Texas		East		West/Other		Corporate		Total
Three months ended March 31, 2020	$	130	$	64	$	9	$	6	$	209
Three months ended March 31, 2019	117		65		7		5		194

Selling, general and administrative expenses increased by ~~$28~~$15 million for the ~~nine~~three months ended ~~September 30, 2019,~~March 31, 2020, compared to the same period in ~~2018,~~2019, primarily 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

acquisition of Stream Energy in August 2019.

Reorganization Costs

Reorganization costs, primarily related to employee severance and contract cancellation costs, decreased by ~~$54~~$10 million for the ~~nine~~three months ended ~~September 30, 2019,~~March 31, 2020, compared to the same period in ~~2018,~~2019, driven primarily by significant achievement of the operations and cost excellence portion of the Transformation Plan during ~~2018.~~2019.

Gain on Sale of Assets

~~The~~A gain on sale of assets of $6 million was recorded for the ~~nine~~three months ended ~~September 30, 2018 consisted primarily of the gain on~~March 31, 2020, related to the sale of ~~BETM~~land and ~~Canal 3.~~

E~~quity~~investments in ~~Earnings of Unconsolidated Affiliates~~January 2020.

Equity in ~~earnings~~losses of unconsolidated affiliates

Equity in losses of unconsolidated affiliates decreased by ~~$18~~$10 million for the ~~nine~~three months ended ~~September 30, 2019,~~March 31, 2020, compared to the ~~nine~~three months ended ~~September 30, 2018,~~March 31, 2019, primarily ~~driven by five months of losses for Ivanpah~~due to an increase in interest expense on an investment in 2019 as a result of the ~~deconsolidations~~PG&E bankruptcy, offset by earnings received in ~~2018.~~2020 from an investment, due to a favorable property tax assessment.

Impairment losses on investments

Impairment losses on investments of ~~$107~~$18 million ~~was~~were recorded for the ~~nine~~three months ended ~~September 30, 2019, primarily~~March 31, 2020, related to ~~the impairment of~~ Petra Nova Parish Holdings, as further discussed in Note 118, ~~Investments Accounted for Using the Equity Method and Variable Interest Entities, or VIEs~~Impairments

~~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~~$16 million for the ~~nine~~three months ended ~~September 30, 2019,~~March 31, 2020, compared to the same period in ~~2018,~~2019, 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 $	(9)
~~Increase due~~Decrease related to ~~California property tax indemnification accretion~~debt reduction of $600 million and refinancing $1.8 billion of debt at lower interest rates	6 (5)
~~Increase due to the amortization of the Convertible Note premium~~Other	5 (2)

Decrease in interest expense	$	~~(43)~~(16)

Income Tax Expense

For the ~~nine~~three months ended ~~September 30, 2019,~~March 31, 2020, income tax expense of $9$23 million was recorded on pre-tax income of ~~$666~~$144 million. For the same period in ~~2018,~~2019, income tax expense of ~~$19~~$4 million was recorded on a pre-tax income of ~~$572~~$98 million. The effective tax rate was ~~1.4%~~16.0% and ~~3.3%~~4.1% for the ~~nine~~three months ended ~~September 30,~~March 31, 2020 and 2019, ~~and 2018,~~ respectively.

For the ~~nine~~three months ended ~~September 30,~~March 31, 2020, the effective tax rate was lower than the statutory rate of 21%, primarily due to an excess tax benefit related to share-based compensation, partially offset by state tax expense. For the three months ended March 31, 2019, ~~and 2018, NRG's overall~~the effective tax rates ~~were~~was 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


(In millions)	Three months ended March 31, 2019
South Central Portfolio	$	35
Yield Renewables Platform & Carlsbad	353

Income from discontinued operations, net of tax	$	388

For the ~~nine~~three months ended ~~September 30,~~March 31, 2019, NRG recorded income from discontinued operations, net of income tax of ~~$399~~$388 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.

8962

Liquidity and Capital Resources

Liquidity Position

As of ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018,~~2019, NRG's total liquidity, excluding funds deposited by counterparties, of approximately ~~$1.5~~$2.0 billion and ~~$2.0~~$2.1 billion, respectively, was comprised of the following:


(In millions)	(In millions)	September 30, 2019		December 31, 2018		(In millions)	March 31, 2020		December 31, 2019
Cash and cash equivalents	Cash and cash equivalents	$	243	$	563	Cash and cash equivalents	$	759	$	345
Restricted cash - operating	Restricted cash - operating	2		6		Restricted cash - operating	5		4
Restricted cash - reserves^(a)	Restricted cash - reserves^(a)	2		11		Restricted cash - reserves^(a)	3		4
Total	Total	247		580		Total	767		353
Total credit facility availability	Total credit facility availability	1,297		1,397		Total credit facility availability	1,183		1,794
Total liquidity, excluding funds deposited by counterparties	Total liquidity, excluding funds deposited by counterparties	$	1,544	$	1,977	Total liquidity, excluding funds deposited by counterparties	$	1,950	$	2,147

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

For the ~~nine~~three months ended ~~September 30, 2019,~~March 31, 2020, total liquidity, excluding funds deposited by counterparties, decreased by ~~$433~~$197 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~~March 31, 2020 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,~~9, Long-term Debt ~~and Finance Leases~~, to this Form 10-Q. The Company's financing arrangements consist mainly of the Senior Notes, the Senior Secured Notes, the Senior Credit Facility, and ~~project-related financings.~~tax-exempt bonds.

The ~~table below represents the approximate cash proceeds received from sale transactions~~Company's requirements for liquidity and ~~related financings, net of working~~ capital ~~and~~resources, other ~~adjustments, completed~~than for operating its facilities, can generally be categorized by the following: (i) market operations activities; (ii) debt service obligations; (iii) capital expenditures, including maintenance, repowering, development, and environmental; and (iv) allocations in connection with acquisition opportunities, debt repayments, share repurchases and dividend payments to stockholders.

Revolving Credit Facility

The Company ~~during~~had $635 million and $83 million outstanding under its Revolving Credit Facility as of March 31, 2020 and December 31, 2019, respectively. Due to market conditions, primarily as a result of COVID-19, the ~~nine months ended September 30, 2019:~~Company drew upon the facility in the first quarter of 2020 as a precaution and to proportionally increase cash on hand. As of May 7, 2020, $250 million of borrowings were outstanding.


~~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~~COVID-19

On ~~May 14,~~March 27, 2020, the U.S. government enacted the CARES Act, which provides, among other things, the option to defer payments of certain 2019 employer payroll taxes incurred after the date of enactment and pension contributions due in 2020, as well as claim a refund now for AMT credits from the IRS that were previously refundable over several years. As a result, the Company (i) expects to defer the payment of approximately $17 million for the employer share of social security taxes that would otherwise have been due in 2020, with 50% due by December 31, 2021 and the remaining 50% due by December 31, 2022, (ii) will consider deferring until January 1, 2021 approximately $47 million of cash contributions to the Company’s pension plans previously planned to be made in 2020 and (iii) reclassified $17 million of refundable AMT credits from non-current to current as of March 31, 2020.

Tax-Exempt Bonds

On March 11, 2020, NRG issued ~~$733~~$59 million of aggregate principal amount at par of 5.25% senior unsecured notes due 2029. The proceeds from the issuance of the 2029 Senior Notes were utilized to redeem the Company's remaining 6.25% Senior Notes due 2024.

~~Issuance of 2024 and 2029 Senior Secured Notes~~

~~On May 28, 2019, NRG issued $1.1 billion of~~in aggregate principal amount of ~~senior~~NRG Dunkirk 2020 1.30% tax-exempt refinancing bonds due 2042 (the "Bonds"). The Bonds are guaranteed on a first-priority basis by each of NRG’s current and future subsidiaries that guarantee indebtedness under its credit agreement. The Bonds are secured by a first ~~lien notes, consisting of $600 million 3.75% senior secured first lien notes due 2024 and $500 million 4.45% senior secured first lien notes due 2029, at a discount. The proceeds from~~priority security interest in the ~~issuance~~same collateral that is pledged for the benefit of the ~~Senior Secured First Lien Notes, together with cash on hand, were used to repay~~lenders under NRG’s credit agreement, which consists of a substantial portion of the ~~Company's 2023 Term Loan Facility, resulting in a decrease of $594 million to long-term debt outstanding.~~

property and assets owned by NRG and the guarantors. The collateral securing the Bonds will, at the

9063

~~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 daterequest 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~~NRG, be released if NRG ~~obtains~~satisfies certain conditions, including receipt of an investment grade rating on its senior unsecured debt securities from two out of the three rating agencies, subject to ~~an obligation to reinstate the collateral~~reversion if ~~such~~those rating agencies withdraw ~~NRG’s~~their investment grade rating of the Bonds or any of NRG’s senior unsecured debt securities or downgrade ~~NRG’s~~such rating below investment ~~grade, (iv) reduce~~grade. The Bonds are subject to mandatory tender and purchase on April 3, 2023 and have a final maturity date of April 1, 2042.

NRG used the ~~applicable margins for borrowings under (a) ABR Revolving Loans~~net proceeds from ~~1.25%~~the offering 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 toredeem the existing ~~covenants.~~principal amount of outstanding Dunkirk Power LLC 5.875% tax exempt bonds due 2042, which will result in annualized interest savings of $3 million for the Company.

Market Operations

The Company's market 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, $215~~March 31, 2020, the Company had total cash collateral outstanding of $200 million and $767 million outstanding in letters of credit to third parties primarily to support its market activities. As of March 31, 2020, total funds deposited by counterparties were $51 million in cash and $120 million of ~~borrowings were outstanding, which was fully repaid as~~letters of ~~November 7, 2019.~~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 depend on the Company's credit ratings and general perception of its creditworthiness.

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,~~March 31, 2020, 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:~~March 31, 2020:


Equivalent Net Sales Secured by First Lien Structure^(a)	Equivalent Net Sales Secured by First Lien Structure^(a)	2019	2020	2021	2022	2023	Equivalent Net Sales Secured by First Lien Structure^(a)	2020	2021	2022	2023
In MW	In MW	714	717	655	725	786	In MW	546	646	672	724
As a percentage of total net coal and nuclear capacity^(b)	As a percentage of total net coal and nuclear capacity^(b)	16%	16%	14%	16%	17%	As a percentage of total net coal and nuclear capacity^(b)	12%	14%	15%	16%

(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

9164

~~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, environmental and growth investments ~~and environmental~~ for the ~~nine~~three months ended ~~September 30, 2019,~~March 31, 2020, and the estimated capital expenditures forecast for the remainder of ~~2019.~~2020.

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


(In millions)	Maintenance		Environmental		Growth Investments^(a)		Total
Texas	$	37	$	—	$	5	$	42
East	5		—		4		9
West/Other	6		—		—		6
Corporate	—		—		9		9
Total cash capital expenditures for the three months ended March 31, 2020	48		—		18		66



Other investments^(b)	—		—		2		2
Total capital expenditures and investments, net of financings	48		—		20		68




Estimated capital expenditures for the remainder of 2020^(c)(d)	$	122	$	5	$	41	$	168

(a) Includes ~~International, Renewables~~other investments, acquisitions and ~~Cottonwood~~costs to achieve

(b) Includes $2 million of expenditures for Encina site improvements classified as ssset retirement obligation payments

~~(c) Includes other~~(d) Growth investments ~~acquisitions and costs to achieve~~include $23 million of capital expenditures for Encina site improvements

~~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~~2020 through ~~2023~~2024 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~~.$40 million.

~~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.Share Repurchases

The ~~Company's common stock dividends are subject to available capital, market conditions, and compliance with associated laws and regulations. Beginning~~Company adopted in the ~~first~~fourth 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~~2019 a long-term capital allocation policy that ~~will target~~targets 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~~

During ~~January and February,~~the three months ended March 31, 2020, 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$177 million of share repurchases at an average price of ~~$37.62~~$34.20 per share, ~~under the $250 million share repurchase program announced in August 2019.~~

~~Senior Note Repurchases~~

~~During the second quarter of 2019, the Company redeemed $733~~including $27 million of ~~its 6.25% Senior Notes due 2024 and recorded a loss~~equivalent shares purchased in lieu of tax withholdings on ~~debt extinguishment of $29 million, which included the write-off of previously deferred debt issuance costs of $5 million.~~

~~2023 Term Loan Facility Repayment~~

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

~~Stream Energy Acquisition~~

~~On August 1, 2019,~~7, 2020, the Company completed an additional $47 million of share repurchases at an average price of $29.33 per share.

Common Stock Dividends

Beginning in 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.

~~Petra Nova Debt Repayment~~

~~During the third~~first quarter of ~~2019,~~2020, NRG ~~contributed approximately $95 million~~increased the annual dividend to $1.20 from $0.12 per share and expects to target an annual dividend growth rate of 7-9% per share in ~~cash~~subsequent years. A quarterly dividend of $0.30 per share was paid on the Company's common stock during the three months ended March 31, 2020. On April 15, 2020, NRG declared a quarterly dividend on the Company's common stock of $0.30 per share, payable May 15, 2020 to ~~Petra Nova and posted a $12 million letter~~stockholders of ~~credit to cover certain project debt reserve requirements. The cash portion~~record as 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.May 1, 2020.

Cash Flow Discussion

The following table reflects the changes in cash flows for the comparative ~~nine~~three 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)


	Three months ended March 31,
(In millions)	2020		2019		Change
Net Cash Provided/(Used) by Operating Activities	$	208	$	(91)	$	299
Net Cash (Used)/Provided by Investing Activities	(68)		1,196		(1,264)
Net Cash Provided/(Used) by Financing Activities	293		(784)		1,077

Net Cash ~~Provided~~Provided/(Used) by Operating Activities

Changes to net cash ~~provided~~provided/(used) 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~~$	132
Change in accounts payable primarily due to fluctuations in natural gas prices and timing of fuel shipments	124
Increase in operating income adjusted for other non-cash items	~~139~~40
~~GenOn settlement~~Increase in ~~July 2018~~other working capital	~~125~~ 11
Decrease in cash provided by discontinued operations	(8)



	$	~~(206)~~299

Net Cash ~~Provided/~~(Used)/Provided by Investing Activities

Changes to net cash ~~provided/~~(used)/provided 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 primarily due to sale of South Central and Carlsbad in 2019	~~(262)~~$	(1,298)
Decrease in contributions to discontinued operations	44
Increase in ~~cash paid for acquisitions primarily due to Stream Energy acquisition in 2019~~capital expenditures	~~(139)~~(17)
~~Change~~Decrease in cash paid for acquisitions due to deferred acquisition payment made in 2019	16
Decrease in distributions from investments in unconsolidated affiliates	~~(55)~~
~~Increase in contributions to discontinued operations~~	~~(21)~~(4)
Other	~~(8)~~(5)
	$	~~673~~ (1,264)

Net Cash ~~Used~~Provided/(Used) by Financing Activities

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


	(In millions)
Increase in net proceeds from Revolving Credit Facility	$	552
Decrease in payments for share repurchase activity	604
Increase in payments of ~~short and long-term debt~~dividends to common stockholders	$		~~(1,517)~~(66)
~~Change~~Proceeds from issuance of long-term debt in 2020	59
Decrease in cash provided by discontinued operations	~~(360)~~(43)
Increase in ~~payments for treasury stock~~	~~(286)~~
~~Increase in payments~~repayments 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 (23)
Other	~~(4)~~(6)


	$	~~(1,111)~~1,077

9466

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

For the ~~nine~~three months ended ~~September 30, 2019,~~March 31, 2020, the Company had domestic pre-tax book income of ~~$655~~$144 million and foreign pre-tax book income of ~~$11 million.~~$400 thousand. As of December 31, ~~2018,~~2019, the Company had cumulative domestic Federal NOL carryforwards of ~~$10.7~~$10.1 billion, which will begin expiring in 2031, and cumulative state NOL carryforwards of ~~$5.6~~$5.5 billion for financial statement purposes. NRG also has cumulative foreign NOL carryforwards of ~~$213~~$357 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~~$384 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~~$16 million in ~~2019.~~2020.

The Company has recorded a non-current tax liability of ~~$29~~$16 million, ~~until final resolution with the related taxing authority. The $29 million non-current tax liability~~inclusive of accrued interest, for uncertain tax benefits ~~is from positions~~ taken on various state income tax ~~returns, including accrued interest.~~positions until final resolution is reached with the related taxing authority.

The Company is no longer subject to U.S. federal income tax examinations for years prior to ~~2015.~~2016. With few exceptions, state and local income tax examinations are no longer open for years ~~before 2010.~~prior to 2011.

Net deferred tax balance — As of ~~September 30, 2019~~both March 31, 2020 and December 31, ~~2018,~~2019, NRG recorded a net deferred tax asset, excluding valuation allowance, of $3.5 billion. The Company believes certain state net operating losses may not be realizable under the ~~Company had~~more-likely-than-not measurement and as such, a valuation allowance ~~on its domestic net deferred tax assets~~was recorded as of ~~$3.6 billion~~March 31, 2020 as discussed below.

Valuation allowance — As of March 31, 2020 and ~~$3.8 billion,~~December 31, 2019, the Company's tax-effected valuation allowance was $240 million and $242 million, respectively, ~~due to its history~~consisting of ~~net operating losses.~~state NOL carryforwards and foreign NOL carryforwards. The ~~realization of net deferred tax assets is dependent~~valuation allowance was recorded based on the ~~Company's ability to generate sufficient future taxable income during periods prior to the expiration~~assessment of ~~the tax attributes. Given the Company's current~~cumulative and forecasted pre-tax book earnings and ~~forecasted~~the future ~~earnings, there is a reasonable possibility that within the next three months there may be sufficient positive evidence to allow for the release~~reversal 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.existing taxable temporary differences.

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~~market 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,~~March 31, 2020, 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,~~10, 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~~$865 million as of ~~September 30, 2019.~~March 31, 2020. 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~~2019 Form 10-K.

Contractual Obligations and ~~Commercial~~Market Commitments

NRG has a variety of contractual obligations and other ~~commercial~~market commitments that represent prospective cash requirements in addition to the Company's capital expenditure programs, as disclosed in the Company's ~~2018~~2019 Form 10-K. See also Note 8,9, ~~Leases, Note 10,~~ Long-term Debt ~~and Finance Leases~~, and Note ~~17,~~16, Commitments and Contingencies, to this Form 10-Q for a discussion of new commitments and contingencies that also include contractual obligations and ~~commercial~~market commitments that occurred during the three ~~and nine~~ months ended ~~September 30, 2019.~~March 31, 2020.

9567

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~~power plants 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,~~March 31, 2020, 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~~2019 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,~~March 31, 2020, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at ~~September 30, 2019.~~March 31, 2020.


Derivative Activity ~~Gains/(Losses)~~Gains	(In millions)
Fair Value of Contracts as of December 31, ~~2018~~2019	$	~~104~~67
Contracts realized or otherwise settled during the period	~~(138)~~
~~Contracts acquired during the period~~	~~(12)~~2
Changes in fair value	~~107~~47
Fair Value of Contracts as of ~~September 30, 2019~~March 31, 2020	$	61116


		Fair Value of Contracts as of September 30, 2019																			Fair Value of Contracts as of March 31, 2020
		Maturity
(In millions)												(In millions)	Maturity
Fair value hierarchy (Losses)/Gains	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		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	Level 1	$	(34)	$	(23)	$	(2)	$	—	$	(59)	Level 1	$	(60)	$	(21)	$	(2)	$	1	$	(82)
Level 2	Level 2	79		52		(13)		(11)		107		Level 2	73		62		—		(10)		125
Level 3	Level 3	22		10		—		(19)		13		Level 3	39		21		5		8		73
Total	Total	$	67	$	39	$	(15)	$	(30)	$	61	Total	$	52	$	62	$	3	$	(1)	$	116

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,~~March 31, 2020, NRG's net derivative asset was ~~$61~~$116 million, ~~a decrease~~an increase to total fair value of ~~$43~~$49 million as compared to December 31, ~~2018.~~2019. This ~~decrease~~increase was primarily driven by gains in fair value, as well as roll-off of trades that settled during the ~~period and contracts acquired, partially offset by gains in fair value.~~period.

Based on a sensitivity analysis using simplified assumptions, the impact of a $0.50 per MMBtu increase in natural gas prices across the term of the derivative contracts would result in ~~a decrease~~an increase of approximately ~~$23~~$132 million in the net value of derivatives as of ~~September 30, 2019.~~March 31, 2020. The impact of a $0.50 per MMBtu decrease in natural gas prices across the term of derivative contracts would result in ~~an increase~~a decrease of approximately ~~$24~~$131 million in the net value of derivatives as of ~~September 30, 2019.~~

March 31, 2020.

9668

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,~~Condensed 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~~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 of the Company's ~~2018~~2019 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~~2019 Form 10-K. There have been no material changes to the Company's critical accounting policies and estimates since the ~~2018~~2019 Form ~~10-K.~~10-K, except as noted below.

Nature of Business. As a result, the Company identified its reporting units as Texas (included in the Texas segment), East Retail (included in the East segment) and Midwest Generation (included in the East segment). The Company performed a quantitative assessment, using primarily an income approach, for each of the Company's new reporting units as of January 1, 2020. Under the income approach, the Company estimated the fair value of each reporting unit's cash flow exceeded its carrying value and, as such, the Company concluded that goodwill associated with each of the reporting units was not impaired as of January 1, 2020 as a result of the change in reporting units.

9769

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, interest rate 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~~2019 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~~March 31, 2020 and ~~2018:~~2019:


(In millions)	(In millions)	2019		2018		(In millions)	2020		2019
VaR as of September 30,		$	49	$	72
Three months ended September 30,
VaR as of March 31,						VaR as of March 31,	$	29	$	45
Three months ended March 31,						Three months ended March 31,
Average	Average	$	46	$	67	Average	$	27	$	45
Maximum	Maximum	55		75		Maximum	47		49
Minimum	Minimum	37		61		Minimum	22		42
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$19 million, as of March 31, 2020, 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~~the Company'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 as of March 31, 2020, a $0.50 per MMBtu ~~change~~decrease in natural gas prices across the term of the marginable contracts would cause ~~a change~~an increase in margin collateral posted of approximately ~~$106~~$266 million ~~as of September 30, 2019,~~ and a 11.00 MMBtu/MWh ~~change~~decrease in heat rates for heat rate positions would result in ~~a change~~an increase in margin collateral posted of approximately ~~$116 million as of September 30, 2019.~~$142 million. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of ~~September 30, 2019.~~March 31, 2020.

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.

Interest Rate Risk

NRG was previously 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 previously entered into interest rate swaps. As of March 31, 2020, NRG had no interest rate derivative instruments.

As of March 31, 2020, the fair value and related carrying value of the Company's debt was $6.6 billion and $6.5 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 as of March 31, 2020 by $489 million.

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.

9971

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~~March 31, 2020 that materially affected, or are reasonably likely to materially affect, NRG's internal control over financial reporting.

~~100~~72

PART II — OTHER INFORMATION

ITEM 1 — LEGAL PROCEEDINGS

For a discussion of material legal proceedings in which NRG was involved through ~~September 30, 2019,~~March 31, 2020, see Note ~~17,~~16, Commitments and Contingencies, to this Form 10-Q.

ITEM 1A — RISK FACTORS

~~Information regarding risk factors appears~~Except as set forth below, during the three months ended March 31, 2020, there were no material changes to the Risk Factors disclosed in Part I, Item 1A, Risk Factors, ~~Related~~of the Company's 2019 Form 10-K.

Public health threats or outbreaks of communicable diseases could have a material adverse effect on the Company’s operations and financial results.

The Company may face risks related to public health threats or outbreaks of communicable diseases. A widespread healthcare crisis, such as an outbreak of a communicable disease, could adversely affect the global economy and the Company’s ability to conduct its business for an indefinite period of time. For example, the ongoing global COVID-19 pandemic has negatively impacted local and global economies, disrupted financial markets and international trade, resulted in increased unemployment levels and impacted local and global supply chains, all of which negatively impact the electricity industry and the Company’s business. In addition, federal, state, and local governments have implemented various mitigation measures, including travel restrictions, border closings, restrictions on public gatherings, shelter-in-place orders and limitations on business activities. Although the operations of the Company are considered an essential service, some of these measures have adversely impacted the ability of NRG ~~Energy, Inc.,~~ employees, contractors, suppliers, customers, and other business partners to conduct business activities. This could have a material adverse effect on the Company’s results of operations, financial condition, risk exposure and liquidity.

In particular, the continued spread of COVID-19 and efforts to contain the virus could:

•adversely impact demand for the Company’s electricity services and other products and services and the ability of customers to pay their bills;

•cause an increase in costs for the Company as a result of emergency measures taken by state and local regulatory authorities in response to the COVID-19 crisis, including regulatory changes prohibiting customer disconnects and late fees;

•impact the ability of our partners or counterparties to perform their obligations under existing arrangements, including development projects, power purchase and sale arrangements, hedging arrangements or other commercial activities; and

•cause other unpredicted events which may have an adverse impact on the Company’s results of operations, financial condition, risk exposure and liquidity.

The situation surrounding COVID-19 remains fluid and the potential for a material impact on the Company’s results of operations, financial condition, risk exposure and liquidity increases the longer the virus impacts the level of economic activity in the ~~Company's 2018 Form 10-K. There~~United States and globally. NRG cannot reasonably estimate with any degree of certainty the future impact of COVID-19, or any resurgence of COVID-19 or other pandemic may have ~~been no material changes in~~on the ~~Company's~~Company’s results of operations, financial position, risk ~~factors since those reported in its 2018 Form 10‑K.~~exposure and liquidity.

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.~~March 31, 2020.

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


For the three months ended March 31, 2020	Total Number of Shares Purchased^(a)(b)	Average Price Paid per Share^(c)		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)(b)
Month #1
(January 1, 2020 to January 31, 2020	1,932,000	$	37.73	738,381	$	—
Month #2
(February 1, 2020 to February 29, 2020	649,145	$	36.67	—	$	—
Month #3
(March 1, 2020 to March 31, 2020)	1,880,293	$	28.21	—	$	—

Total at March 31, 2020	4,461,438	$	33.56	738,381

(a)~~Includes commissions paid~~

~~(b)Includes share repurchases~~The Company's board of directors authorized the Company to repurchase $1.25 billion of its common stock under ~~the 2019 $1~~a $1.0 billion program ~~that was~~ announced on February 28, 2019

~~(c)Includes 636,536 share repurchases under the 2019 $1~~ and a $0.25 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. The Company completed these programs in January 2020

(b)The Company adopted in the fourth quarter of 2019 a long-term capital allocation policy that targets 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 beginning in 2020, supplemented by share repurchases made in open-market repurchases

(c)The average price per share excludes commissions of $0.02 per share paid in connection with the open-market share repurchases

ITEM 3 — DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4 — MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5 — OTHER INFORMATION

None.

~~101~~74

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~~75

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~~May 7, ~~2019~~2020

Chief Accounting Officer

(Principal Accounting Officer)

~~103~~76


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			6246
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			9870
ITEM 4 — CONTROLS AND PROCEDURES			~~100~~72
PART II — OTHER INFORMATION			~~101~~73
ITEM 1 — LEGAL PROCEEDINGS			~~101~~73
ITEM 1A — RISK FACTORS			~~101~~73
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			~~101~~74
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES			~~101~~74
ITEM 4 — MINE SAFETY DISCLOSURES			~~101~~74
ITEM 5 — OTHER INFORMATION			~~101~~74
ITEM 6 — EXHIBITS			~~102~~75
SIGNATURES			~~103~~76


	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


	(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


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


^(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


^(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


	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