UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☒	Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
	For the Quarterly Period Ended:	June 30, 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 August 6, 2020, there were 244,137,848 shares of common stock outstanding, par value $0.01 per share.

1

TABLE OF CONTENTS

Index

CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION	3
GLOSSARY OF TERMS	5
PART I — FINANCIAL INFORMATION	9
ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES	9
ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	55
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	89
ITEM 4 — CONTROLS AND PROCEDURES	91
PART II — OTHER INFORMATION	92
ITEM 1 — LEGAL PROCEEDINGS	92
ITEM 1A — RISK FACTORS	92
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	94
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES	94
ITEM 4 — MINE SAFETY DISCLOSURES	94
ITEM 5 — OTHER INFORMATION	94
ITEM 6 — EXHIBITS	95
SIGNATURES	96

2

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q of NRG Energy, Inc., or NRG or the Company, includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. The words "believes," "projects," "anticipates," "plans," "expects," "intends," "estimates" and similar expressions are intended to identify forward-looking statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause NRG's actual results, performance and achievements, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. These factors, risks and uncertainties include the factors described under Risk Factors, in Part I, Item 1A of the Company's Annual Report on Form 10-K for the year ended December 31, 2019 and the following:

•NRG's inability to estimate with any degree of certainty the future impact that COVID-19, any resurgence of 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;

•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;

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

•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 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 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; and

3

•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.

4

GLOSSARY OF TERMS

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

2019 Form 10-K	NRG’s Annual Report on Form 10-K for the year ended December 31, 2019
2023 Term Loan Facility	The Company's 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 power 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
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
California Bankruptcy Court	United States Bankruptcy Court for the Northern District of California, San Francisco Division
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
CFTC	U.S. Commodity Futures Trading Commission
C&I	Commercial industrial and governmental/institutional
Centrica	Centrica plc
CES	Clean Energy Standard
Cleco	Cleco Corporate Holdings LLC
CO2	Carbon Dioxide
ComEd	Commonwealth Edison
Company	NRG Energy, Inc.
Convertible Senior Notes	As of June 30, 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
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
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
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

5

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.
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 Texas Bankruptcy Court on June 14, 2017
GHG	Greenhouse Gas
GIP	Global Infrastructure Partners
Green Mountain Energy	Green Mountain Energy Company
GWh	Gigawatt Hour
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
HSR Act	Hart-Scott-Rodino Act
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 long-term incentive plan ("LTIP") and the NRG GenOn LTIP
Mass Market	Residential and small commercial customers
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
NPNS	Normal Purchase Normal Sale
NRC	U.S. Nuclear Regulatory Commission
NRG	NRG Energy, Inc.
NRG Yield, Inc.	NRG Yield, Inc., which changed its name to Clearway Energy, Inc. following the sale by NRG of NRG Yield and the Renewables Platform to GIP

6

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
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
Petra Nova	Petra Nova Parish Holdings, LLC which is 50% owned by NRG and which owns and operates a 240 MWe carbon capture system and a 78 MW cogeneration facility, and owns an equity interest in an oilfield
PG&E	PG&E Corporation (NYSE: PCG) and its primary operating subsidiary, Pacific Gas and Electric Company
PJM	PJM Interconnection, LLC
PM2.5	Particulate Matter that has a diameter of less than 2.5 micrometers
PPA	Power Purchase Agreement
PUCT	Public Utility Commission of Texas
RCE	Residential Customer Equivalent is a unit of measure used by the energy industry to denote the typical annual commodity consumption by a single-family residential customer. 1 RCE represents 1,000 therms of natural gas or 10,000 kWh of electricity
RCRA	Resource Conservation and Recovery Act of 1976
Reliant Energy	Reliant Energy Retail Services, LLC
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.
Revolving Credit Facility	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, also referred to as ISOs
SEC	U.S. Securities and Exchange Commission
Securities Act	The Securities Act of 1933, as amended
Senior Credit Facility	NRG's senior secured credit facility, comprised of the Revolving Credit Facility and the 2023 Term Loan Facility. The 2023 Term Loan Facility was repaid in the second quarter of 2019
Senior Notes	As of June 30, 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 June 30, 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
TDSP	Transmission/distribution service provider
Texas Bankruptcy Court	United States Bankruptcy Court for the Southern District of Texas, Houston Division
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.
U.S.	United States of America

7

U.S. DOE	U.S. Department of Energy
Utility Scale Solar	Solar power projects, typically 20 MW or greater in size (on an alternating current basis), that are interconnected into the transmission or distribution grid to sell power at a wholesale level
VaR	Value at Risk
VIE	Variable Interest Entity
ZECs	Zero Emissions Credits

8

PART I — FINANCIAL INFORMATION

ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three months ended June 30,				Six months ended June 30,
(In millions, except for per share amounts)	2020		2019		2020		2019
Operating Revenues
Total operating revenues	$	2,238	$	2,465	$	4,257	$	4,630
Operating Costs and Expenses
Cost of operations	1,434		1,845		2,891		3,496
Depreciation and amortization	110		85		219		170
Impairment losses	—		1		—		1
Selling, general and administrative costs	208		211		417		405
Reorganization costs	—		2		3		15
Development costs	2		2		5		4
Total operating costs and expenses	1,754		2,146		3,535		4,091
Gain on sale of assets	—		1		6		2
Operating Income	484		320		728		541
Other Income/(Expense)
Equity in earnings/(losses) of unconsolidated affiliates	12		—		1		(21)
Impairment losses on investments	—		—		(18)		—
Other income, net	14		20		41		32
Loss on debt extinguishment, net	—		(47)		(1)		(47)
Interest expense	(96)		(105)		(193)		(219)
Total other expense	(70)		(132)		(170)		(255)
Income from Continuing Operations Before Income Taxes	414		188		558		286
Income tax expense/(benefit)	101		(1)		124		3
Income from Continuing Operations	313		189		434		283
Income from discontinued operations, net of income tax	—		13		—		401
Net Income	313		202		434		684
Less: Net income attributable to redeemable noncontrolling interests	—		1		—		1
Net Income Attributable to NRG Energy, Inc.	$	313	$	201	$	434	$	683
Earnings per Share
Weighted average number of common shares outstanding — basic	245		265		246		272
Income from continuing operations per weighted average common share — basic	$	1.28	$	0.71	$	1.76	$	1.04
Income from discontinued operations per weighted average common share — basic	$	—	$	0.05	$	—	$	1.47
Earnings per Weighted Average Common Share — Basic	$	1.28	$	0.76	$	1.76	$	2.51
Weighted average number of common shares outstanding — diluted	246		267		247		274
Income from continuing operations per weighted average common share — diluted	$	1.27	$	0.70	$	1.76	$	1.03
Income from discontinued operations per weighted average common share — diluted	$	—	$	0.05	$	—	$	1.46
Earnings per Weighted Average Common Share — Diluted	$	1.27	$	0.75	$	1.76	$	2.49

See accompanying notes to condensed consolidated financial statements.

9

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three months ended June 30,				Six months ended June 30,
(In millions)	2020		2019		2020		2019
Net Income	$	313	$	202	$	434	$	684
Other Comprehensive Income/(Loss)
Foreign currency translation adjustments	13		(1)		(2)		—
Available-for-sale securities	—		1		—		1
Defined benefit plans	—		(3)		—		(6)
Other comprehensive income/(loss)	13		(3)		(2)		(5)
Comprehensive Income	326		199		432		679
Less: Comprehensive income attributable to redeemable noncontrolling interest	—		1		—		1
Comprehensive Income Attributable to NRG Energy, Inc.	$	326	$	198	$	432	$	678

See accompanying notes to condensed consolidated financial statements.

10

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

	June 30, 2020		December 31, 2019
(In millions, except share data)	(Unaudited)		(Audited)
ASSETS
Current Assets
Cash and cash equivalents	$	418	$	345
Funds deposited by counterparties	36		32
Restricted cash	8		8
Accounts receivable, net	1,015		1,025
Inventory	388		383
Derivative instruments	791		860
Cash collateral paid in support of energy risk management activities	136		190
Prepayments and other current assets	284		245
Total current assets	3,076		3,088
Property, plant and equipment, net	2,533		2,593
Other Assets
Equity investments in affiliates	372		388
Operating lease right-of-use assets, net	429		464
Goodwill	579		579
Intangible assets, net	733		789
Nuclear decommissioning trust fund	794		794
Derivative instruments	439		310
Deferred income taxes	3,170		3,286
Other non-current assets	212		240
Total other assets	6,728		6,850
Total Assets	$	12,337	$	12,531
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Current portion of long-term debt	$	7	$	88
Current portion of operating lease liabilities	69		73
Accounts payable	736		722
Derivative instruments	728		781
Cash collateral received in support of energy risk management activities	36		32
Accrued expenses and other current liabilities	581		663
Total current liabilities	2,157		2,359
Other Liabilities
Long-term debt	5,810		5,803
Non-current operating lease liabilities	458		483
Nuclear decommissioning reserve	307		298
Nuclear decommissioning trust liability	478		487
Derivative instruments	299		322
Deferred income taxes	17		17
Other non-current liabilities	1,061		1,084
Total other liabilities	8,430		8,494
Total Liabilities	10,587		10,853
Redeemable noncontrolling interest in subsidiaries	—		20
Commitments and Contingencies
Stockholders' Equity
Common stock; $0.01 par value; 500,000,000 shares authorized; 423,031,777 and 421,890,790 shares issued and 244,137,848 and 248,996,189 shares outstanding at June 30, 2020 and December 31, 2019, respectively	4		4
Additional paid-in-capital	8,505		8,501
Accumulated deficit	(1,331)		(1,616)
Treasury stock, at cost - 178,893,929 and 172,894,601 shares at June 30, 2020 and December 31, 2019, respectively	(5,234)		(5,039)
Accumulated other comprehensive loss	(194)		(192)
Total Stockholders' Equity	1,750		1,658
Total Liabilities and Stockholders' Equity	$	12,337	$	12,531

See accompanying notes to condensed consolidated financial statements.

11

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six months ended June 30,
(In millions)	2020		2019
Cash Flows from Operating Activities
Net Income	$	434	$	684
Income from discontinued operations, net of income tax	—		401
Income from continuing operations	434		283
Adjustments to reconcile net income to cash provided by operating activities:
Distributions from and equity in (earnings)/losses of unconsolidated affiliates	7		22
Depreciation and amortization	219		170
Accretion of asset retirement obligations	18		14
Provision for credit losses	48		52
Amortization of nuclear fuel	25		27
Amortization of financing costs and debt discount/premiums	12		13
Loss on debt extinguishment, net	1		47
Amortization of emissions allowances and energy credits	33		14
Amortization of unearned equity compensation	12		10
(Gain)/loss on sale of assets and disposal of assets	(15)		1
Impairment losses	18		1
Changes in derivative instruments	(131)		(22)
Changes in deferred income taxes and liability for uncertain tax benefits	116		(5)
Changes in collateral deposits in support of energy risk management activities	58		125
Changes in nuclear decommissioning trust liability	36		17
Changes in other working capital	(199)		(352)
Cash provided by continuing operations	692		417
Cash provided by discontinued operations	—		8
Net Cash Provided by Operating Activities	692		425
Cash Flows from Investing Activities
Payments for acquisitions of businesses	(5)		(21)
Capital expenditures	(116)		(107)
Net purchases of emission allowances	(4)		(1)
Investments in nuclear decommissioning trust fund securities	(257)		(209)
Proceeds from the sale of nuclear decommissioning trust fund securities	220		191
Proceeds from sale of assets, net of cash disposed and sale of discontinued operations, net of fees	15		1,289
Net distributions from investments in unconsolidated affiliates	2		7
Contributions to discontinued operations	—		(44)
Cash (used)/provided by continuing operations	(145)		1,105
Cash used by discontinued operations	—		(2)
Net Cash (Used)/Provided by Investing Activities	(145)		1,103
Cash Flows from Financing Activities
Payments of dividends to common stockholders	(148)		(16)
Payments for share repurchase activity	(229)		(1,075)
Payments for debt extinguishment costs	—		(24)
Purchase of and distributions to noncontrolling interests from subsidiaries	(2)		(1)
Proceeds from issuance of common stock	1		2
Proceeds from issuance of long-term debt	59		1,833
Payment of debt issuance costs	(1)		(33)
Repayments of long-term debt	(61)		(2,485)
Net repayment of Revolving Credit Facility	(83)		—
Other	(5)		—
Cash used by continuing operations	(469)		(1,799)
Cash provided by discontinued operations	—		43
Net Cash Used by Financing Activities	(469)		(1,756)
Effect of exchange rate changes on cash and cash equivalents	(1)		—
Change in Cash from discontinued operations	—		49
Net Increase/(Decrease) in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash	77		(277)
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	$	462	$	336

See accompanying notes to condensed consolidated financial statements.

12

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(Unaudited)

(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 attributable to NRG Energy, Inc.					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
Net income attributable to NRG Energy, Inc.					313						313
Other comprehensive income									13		13
Shares reissuance for ESPP							2				2
Share repurchases							(47)				(47)
Equity-based awards activity, net			6								6
Issuance of common stock			1								1
Common stock dividends and dividend equivalents declared(a)					(74)						(74)
Balance at June 30, 2020	$	4	$	8,505	$	(1,331)	$	(5,234)	$	(194)	$	1,750

(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 attributable to NRG Energy, Inc.					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)
Net income attributable to NRG Energy, Inc.					201						201
Other comprehensive loss									(3)		(3)
Share repurchases			10				(315)				(305)
Equity-based awards activity, net			5								5
Common stock dividends and dividend equivalents declared(a)					(8)						(8)
Balance at June 30, 2019	$	4	$	8,488	$	(5,355)	$	(4,686)	$	(99)	$	(1,648)

(a) Dividends per common share were $0.30 for each of the quarters ended June 30, 2020 and March 31, 2020 and $0.03 for each of the quarters ended June 30, 2019 and March 31, 2019

See accompanying notes to condensed consolidated financial statements.

13

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 integrated power company built on dynamic retail brands with diverse generation assets. NRG brings the power of energy to consumers by producing and 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. The Company sells energy, services, and innovative, sustainable products and services directly to retail customers under the brand names 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 June 30, 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 2019 Form 10-K and the Current Report on Form 8-K filed May 7, 2020, which provides retrospectively revised historical financial information to correspond with the Company's current segment structure. Interim results are not necessarily indicative of results for a full year.

In the opinion of management, the accompanying unaudited interim condensed consolidated financial statements contain all material adjustments consisting of normal and recurring accruals necessary to present fairly the Company's consolidated financial position as of June 30, 2020, and the results of operations, comprehensive income, cash flows and statements of stockholders' equity for the three and six months ended June 30, 2020 and 2019.

Segments

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. The Company's updated segment structure reflects how management currently makes financial decisions and allocates resources.

The Company's businesses are segregated as follows:

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

•East, which includes the remaining activity related to customer operations and all activity related to plant and market operations in the East;

•West/Other, which includes the following assets and activities: (i) all activity related to plant and market operations in the West, (ii) activity related to the Cottonwood power plant that was sold to Cleco on February 4, 2019 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 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 Australia; and

•Corporate activities.

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

COVID-19

In March 2020, the World Health Organization categorized COVID-19 as a pandemic and the President of the United States declared the COVID-19 outbreak a national emergency. Electricity was deemed a 'critical and essential business operation' under various state and federal governmental COVID-19 mandates. NRG had activated its Crisis Management Team ("CMT") in January 2020 to proactively manage the Company's response to the impacts of COVID-19.

NRG continues to remain 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. During the second quarter of 2020, the Company began to evaluate and implement protocols for return to normal work operations.

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The Company continues to maintain certain restrictions on business travel and face-to-face sales channels, remote work practices remain in place and there are enhanced cleaning and hygiene protocols in all of its facilities. In addition, select essential employees and contractors are continuing to report to plant and certain office locations. The Company also continues to require 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. The Company has not experienced any material disruptions in its ability to continue its 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

Other Balance Sheet Information

The following table presents the accumulated depreciation included in property, plant and equipment, net and accumulated amortization included in intangible assets, net:

(In millions)	June 30, 2020		December 31, 2019
Property, plant and equipment accumulated depreciation	$	1,868	$	1,752
Intangible assets accumulated amortization	1,279		1,262

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 and six months ended June 30, 2020:

(In millions)	Three months ended June 30, 2020		Six months ended June 30, 2020
Beginning balance	$	39	$	43
Provision for credit losses	24		48
Write-offs	(20)		(52)
Recoveries collected	4		8
Ending balance	$	47	$	47

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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:

(In millions)	June 30, 2020		December 31, 2019
Cash and cash equivalents	$	418	$	345
Funds deposited by counterparties	36		32
Restricted cash	8		8
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows	$	462	$	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 within the Company's projects that are restricted for specific uses.

Pension Plan Contributions

On March 27, 2020, the Senate passed the CARES Act to provide necessary emergency relief related to the COVID-19 pandemic. The CARES Act allows NRG and other pension plan sponsors to postpone 2020 contributions until January 1, 2021. As a result, NRG will consider deferring approximately $47 million in cash contributions previously planned to be made to the Company's pension plans in 2020. NRG’s pension and postretirement benefit plans are further described in Note 15, Benefit Plans and Other Postretirement Benefits, to the Company’s 2019 Form 10-K.

Recent Accounting Developments - Guidance Adopted in 2020

ASU 2018-17 — In October 2018, the FASB issued ASU No. 2018-17, Consolidations (Topic 810): Targeted Improvements to Related Party Guidance for Variable Interest Entities, 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.

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ASU 2016-13 — In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Statements, or ASU No. 2016-13, which was further amended through various updates issued by the FASB thereafter. The guidance in 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 loss was incurred. The estimate of expected credit losses is to be based on consideration of past events, current conditions and reasonable and supportable forecasts of future conditions. The Company adopted the standard and its subsequent corresponding updates effective January 1, 2020 using the modified retrospective approach. Results for the reporting 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's adoption of Topic 326 did not have a material impact on the Company's results of operations, cash flows, or statement of financial position.

Recent Accounting Developments - Guidance Not Yet Adopted

ASU 2019-12 — In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes, or ASU No. 2019-12, to simplify various aspects related to accounting for income taxes. The guidance in ASU 2019-12 amends the 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 a consolidated group. ASU 2019-12 is effective for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years,. Early adoption is permitted, including adoption in an interim period. The Company is currently in the process of assessing the impact of this guidance on the consolidated financial statements.

Note 3 — Revenue Recognition

Performance Obligations

As of June 30, 2020, estimated future fixed fee performance obligations are $314 million for the remaining six months of fiscal year 2020, and $620 million, $307 million, $42 million and $8 million for the fiscal years 2021, 2022, 2023 and 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 six months ended June 30, 2020 and 2019:

	Three months ended June 30, 2020
(In millions)	Texas		East		West/Other		Corporate/Eliminations		Total
Retail revenue:
Mass Market	$	1,273	$	291	$	—	$	—	$	1,564
Business Solutions	248		20		—		—		268
Total retail revenue	1,521		311		—		—		1,832
Energy revenue(a)	5		19		60		(1)		83
Capacity revenue(a)	—		179		16		—		195
Mark-to-market for economic hedging activities(b)	—		40		1		2		43
Other revenue(a)	52		17		17		(1)		85
Total operating revenue	1,578		566		94		—		2,238
Less: Lease revenue	—		1		4		—		5
Less: Realized and unrealized ASC 815 revenue	7		85		16		1		109
Total revenue from contracts with customers	$	1,571	$	480	$	74	$	(1)	$	2,124
(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	$	—	$	2	$	10	$	(1)	$	11
Capacity revenue	—		41		—		—		41
Other revenue	7		2		5		—		14
(b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815

17

	Three months ended June 30, 2019
(In millions)	Texas		East		West/Other		Corporate/Eliminations		Total
Retail revenue:
Mass Market	$	1,161	$	235	$	—	$	(1)	$	1,395
Business Solutions	272		18		—		—		290
Total retail revenue	1,433		253		—		(1)		1,685
Energy revenue(a)	136		48		52		—		236
Capacity revenue(a)	—		195		6		—		201
Mark-to-market for economic hedging activities(b)	210		16		16		(1)		241
Other revenue(a)	58		12		32		—		102
Total operating revenue	1,837		524		106		(2)		2,465
Less: Lease revenue	—		1		4		—		5
Less: Realized and unrealized ASC 815 revenue	579		64		34		—		677
Total revenue from contracts with customers	$	1,258	$	459	$	68	$	(2)	$	1,783
(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	$	355	$	20	$	5	$	—	$	380
Capacity revenue	—		29		—		1		30
Other revenue	14		(1)		13		—		26
(b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815

	Six months ended June 30, 2020
(In millions)	Texas		East		West/Other		Corporate/Eliminations		Total
Retail revenue:
Mass Market	$	2,305	$	638	$	—	$	(1)	$	2,942
Business Solutions	508		43		—		—		551
Total retail revenue	2,813		681		—		(1)		3,493
Energy revenue(a)	10		64		135		(2)		207
Capacity revenue(a)	—		313		31		—		344
Mark-to-market for economic hedging activities(b)	—		20		16		3		39
Other revenue(a)	113		27		37		(3)		174
Total operating revenue	2,936		1,105		219		(3)		4,257
Less: Lease revenue	—		1		9		—		10
Less: Realized and unrealized ASC 815 revenue	14		124		60		—		198
Total revenue from contracts with customers	$	2,922	$	980	$	150	$	(3)	$	4,049
(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	$	—	$	37	$	29	$	(2)	$	64
Capacity revenue	—		65		—		—		65
Other revenue	14		2		15		(1)		30
(b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815

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	Six months ended June 30, 2019
(In millions)	Texas		East		West/Other		Corporate/Eliminations		Total
Retail revenue:
Mass Market	$	2,156	$	555	$	—	$	(3)	$	2,708
Business Solutions	530		36		—		—		566
Total retail revenue	2,686		591		—		(3)		3,274
Energy revenue(a)	241		174		110		1		526
Capacity revenue(a)	—		339		18		—		357
Mark-to-market for economic hedging activities(b)	241		1		20		(1)		261
Other revenue(a)	135		28		51		(2)		212
Total operating revenue	3,303		1,133		199		(5)		4,630
Less: Lease revenue	—		1		9		—		10
Less: Realized and unrealized ASC 815 revenue	894		118		46		—		1,058
Total revenue from contracts with customers	$	2,409	$	1,014	$	144	$	(5)	$	3,562
(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	$	626	$	67	$	7	$	—	$	700
Capacity revenue	—		47		—		1		48
Other revenue	27		3		19		—		49
(b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815

Contract Balances

The following table reflects the contract assets and liabilities included in the Company’s balance sheet as of June 30, 2020 and December 31, 2019:

(In millions)	June 30, 2020		December 31, 2019
Deferred customer acquisition costs	$	133	$	133
Accounts receivable, net - Contracts with customers	981		1,002
Accounts receivable, net - Derivative instruments	30		18
Accounts receivable, net - Affiliate	4		5
Total accounts receivable, net	$	1,015	$	1,025
Unbilled revenues (included within Accounts receivable, net - Contracts with customers)	$	328	$	402
Deferred revenues(a)	84		82

(a) Deferred revenues from contracts with customers for the three months ended June 30, 2020 and the year ended December 31, 2019 were approximately $33 million and $24 million, respectively

The revenue recognized from contracts with customers during both the six months ended June 30, 2020 and 2019 relating to the deferred revenue balance at the beginning of each period was $13 million. The revenue recognized during the three months ended June 30, 2020 and 2019 relating to the deferred revenue balance at the beginning of each period was $25 million and $19 million, respectively. The change in deferred revenue balances during the three and six months ended June 30, 2020 and 2019 was primarily due to the timing difference of when consideration was received and when the performance obligation was transferred.

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Note 4 — Acquisitions, Discontinued Operations and Dispositions

Acquisitions

Stream Energy Acquisition

On August 1, 2019, the Company acquired Stream Energy's retail electricity and natural gas 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 allocated as follows:

	(In millions)
Account receivable	$	98
Accounts payable	(73)
Other net current and non-current working capital	5
Marketing partnership	154
Customer relationships	85
Trade name	28
Other intangible assets	26
Goodwill (a)	6
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 of $5 million and $1 million was assigned to the Texas and East segments, respectively, and is not deductible for tax purposes

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 prior period results for the operations of the South Central Portfolio, except for the Cottonwood facility as discussed below, were reclassified as discontinued 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 2025. Due to its continuing involvement with the Cottonwood facility, NRG did not use held-for-sale or discontinued operations treatment in accounting for the Cottonwood facility.

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

	Three months ended			Six months ended
(In millions)		June 30, 2019			June 30, 2019
Operating revenues		$	—		$	31
Operating costs and expenses		—			(23)
Gain from operations of discontinued components		—			8
Gain on disposal of discontinued operations, net of tax		1			28
Gain from discontinued operations, including disposal, net of tax		$	1		$	36

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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 prior period results for Carlsbad were reclassified as discontinued operations. The transaction closed on February 27, 2019. Carlsbad continues to have a ground lease and easement agreement with NRG with an initial term ending in 2039 and two, ten-year extensions. As a result of the transaction, additional commitments related to the project totaled approximately $23 million as of June 30, 2020 and December 31, 2019.

Summarized results of Carlsbad discontinued operations were as follows: 

	Three months ended			Six months ended
(In millions)		June 30, 2019		June 30, 2019
Operating revenues		$	—	$	19
Operating costs and expenses		—		(9)
Other expenses		—		(5)
Gain from discontinued operations, net of tax		—		5
(Loss)/gain on disposal of discontinued operations, net of tax		(17)		331
Other Commitments, Indemnification and Fees		27		27
Gain on disposal of discontinued operations, net of tax		10		358
Gain from discontinued operations, including disposal, net of tax		$	10	$	363

GenOn

On June 14, 2017, the GenOn Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Texas 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 Texas Bankruptcy Court; and accordingly, NRG deconsolidated GenOn and its subsidiaries for financial reporting purposes as of such date.

Summarized results of GenOn discontinued operations were as follows:

	Three months ended		Six months ended
(In millions)	June 30, 2019		June 30, 2019
Gain from discontinued operations, net of tax	$	2	$	2

Dispositions

The Company completed other asset sales for cash proceeds of $15 million and $18 million during the six months ended June 30, 2020 and 2019, respectively.

Note 5 — Fair Value of Financial Instruments

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

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

	June 30, 2020				December 31, 2019
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Assets:
Notes receivable	$	10	$	7	$	11	$	8
Liabilities:
Long-term debt, including current portion (a)	5,878		6,208		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

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The fair value of the Company's publicly-traded long-term debt is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. The fair value of debt securities, non-publicly traded long-term debt and certain notes receivable of the Company are based on expected future cash flows discounted at market interest rates or current interest rates for similar instruments with equivalent credit quality and are classified as Level 3 within the fair value hierarchy. The following table presents the level within the fair value hierarchy for long-term debt, including current portion, as of June 30, 2020 and December 31, 2019:

	June 30, 2020				December 31, 2019
(In millions)	Level 2		Level 3		Level 2		Level 3
Long-term debt, including current portion	$	6,176	$	32	$	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:

	June 30, 2020
(In millions)	Total		Level 1		Level 2		Level 3
Investments in securities (classified within other current and non-current assets)	$	13	$	—	$	13	$	—
Nuclear trust fund investments:
Cash and cash equivalents	26		26		—		—
U.S. government and federal agency obligations	48		47		1		—
Federal agency mortgage-backed securities	87		—		87		—
Commercial mortgage-backed securities	38		—		38		—
Corporate debt securities	148		—		148		—
Equity securities	371		371		—		—
Foreign government fixed income securities	7		—		7		—
Other trust fund investments:
U.S. government and federal agency obligations	1		1		—		—
Derivative assets:
Commodity contracts	1,230		87		677		466
Measured using net asset value practical expedient:
Equity securities — nuclear trust fund investments	69
Equity securities	7
Total assets	$	2,045	$	532	$	971	$	466
Derivative liabilities:
Commodity contracts	$	1,027	$	151	$	562	$	314
Total liabilities	$	1,027	$	151	$	562	$	314

22

	December 31, 2019
(In millions)	Total		Level 1		Level 2		Level 3
Investments in securities (classified within other current and non-current assets)	$	20	$	—	$	20	$	—
Nuclear trust fund investments:
Cash and cash equivalents	17		17		—		—
U.S. government and federal agency obligations	68		68		—		—
Federal agency mortgage-backed securities	100		—		100		—
Commercial mortgage-backed securities	29		—		29		—
Corporate debt securities	109		—		109		—
Equity securities	388		388		—		—
Foreign government fixed income securities	5		—		5		—
Other trust fund investments:
U.S. government and federal agency obligations	1		1		—		—
Derivative assets:
Commodity contracts	1,170		84		893		193
Measured using net asset value practical expedient:
Equity securities — nuclear trust fund investments	78
Equity securities	8
Total assets	$	1,993	$	558	$	1,156	$	193
Derivative liabilities:
Commodity contracts	$	1,103	$	143	$	805	$	155
Total liabilities	$	1,103	$	143	$	805	$	155

The following tables reconcile, for the three and six months ended June 30, 2020 and 2019, the beginning and ending balances for financial instruments that are recognized at fair value in the condensed consolidated financial statements, using significant unobservable inputs:

	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Three months ended June 30, 2020		Six months ended June 30, 2020
(In millions)	Derivatives(a)		Derivatives(a)
Beginning balance	$	73	$	38
Total gains realized/unrealized— included in earnings	52		74
Purchases	8		16
Transfers into Level 3(b)	25		33
Transfers out of Level 3(b)	(6)		(9)
Ending balance	$	152	$	152
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 period end	$	36	$	27

(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

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	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Three months ended June 30, 2019						Six months ended June 30, 2019
(In millions)	Debt Securities		Derivatives(a)		Total		Debt Securities	Derivatives(a)		Total
Beginning balance	$	18	$	(2)	$	16	19	$	20	$	39
Contracts added from acquisitions	—		(1)		(1)		—	(1)		(1)
Total gains/(losses) realized/unrealized— included in earnings	1		(17)		(16)		1	(27)		(26)
Cash received	—		—		—		(1)	—		(1)
Purchases	—		(10)		(10)		—	(12)		(12)
Transfers into Level 3(b)	—		113		113		—	130		130
Transfers out of Level 3(b)	—		14		14		—	(13)		(13)
Ending balance	19		97		116		19	97		116
Gains/(losses) for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of period end	1		(19)		(18)		1	(31)		(30)

(a)Consists of derivative assets and liabilities, net

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

Derivative Fair Value Measurements

A portion of NRG's contracts are exchange-traded contracts with readily available quoted market prices. A majority of NRG's contracts are non-exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter and on-line exchanges. The remainder of the assets and liabilities represent contracts for which external sources or observable market quotes are not available. These contracts are valued based on various valuation techniques including, but not limited to, internal models based on a fundamental analysis of the market and extrapolation of the observable market data with similar characteristics. As of June 30, 2020, contracts valued with prices provided by models and other valuation techniques make up 38% of derivative assets and 31% of derivative liabilities.

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

The following tables quantify the significant unobservable inputs used in developing the fair value of the Company's Level 3 positions as of June 30, 2020 and December 31, 2019:

	June 30, 2020
	Fair Value						Input/Range
(In millions)	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low		High		Weighted Average
Power Contracts	$	431	$	306	Discounted Cash Flow	Forward Market Price (per MWh)	$	4	$	181	$	26
FTRs	35		8		Discounted Cash Flow	Auction Prices (per MWh)	(55)		48		0
	$	466	$	314

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	December 31, 2019
	Fair Value						Input/Range
(In millions)	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low		High		Weighted Average
Power Contracts	$	151	$	139	Discounted Cash Flow	Forward Market Price (per MWh)	$	8	$	218	$	24
FTRs	42		16		Discounted Cash Flow	Auction Prices (per MWh)	(105)		213		0
	$	193	$	155

The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable inputs as of June 30, 2020 and December 31, 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 June 30, 2020, the credit reserve resulted in a $1 million decrease in operating revenue and cost of operations. As of December 31, 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 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.

Counterparty Credit Risk

The Company's counterparty credit risk policies are disclosed in its 2019 Form 10-K. As of June 30, 2020, counterparty credit exposure, excluding credit exposure from RTOs, ISOs, registered commodity exchanges and certain long-term agreements, was $339 million and NRG held collateral (cash and letters of credit) against those positions of $76 million, resulting in a net exposure of $263 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 49% of the Company's exposure before collateral is expected to roll off by the end of 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.

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	Net Exposure(a)(b)
Category by Industry Sector	(% of Total)
Utilities, energy merchants, marketers and other	77	%
Financial institutions	23
Total as of June 30, 2020	100	%

	Net Exposure (a)(b)
Category by Counterparty Credit Quality	(% of Total)
Investment grade	59	%
Non-investment grade/non-rated	41
Total as of June 30, 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 $57 million of exposure to two wholesale counterparties in excess of 10% of total net exposure discussed above as of June 30, 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 June 30, 2020, aggregate credit risk exposure managed by NRG to these counterparties was approximately $672 million for the next five years.

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 June 30, 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.

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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 June 30, 2020							As of December 31, 2019
(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	$	26	$	—	$	—	—	$	17	$	—	$	—	—
U.S. government and federal agency obligations	48		8		—		13	68		4		—		11
Federal agency mortgage-backed securities	87		4		—		24	100		3		—		24
Commercial mortgage-backed securities	38		2		—		27	29		1		1		24
Corporate debt securities	148		12		1		12	109		6		—		11
Equity securities	440		298		—		—	466		324		—		—
Foreign government fixed income securities	7		1		—		10	5		—		—		10
Total	$	794	$	325	$	1		$	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.

	Six months ended June 30,
(In millions)	2020		2019
Realized gains	$	7	$	5
Realized losses	(9)		(5)
Proceeds from sale of securities	220		191

Note 7 — Accounting for Derivative Instruments and Hedging Activities

Energy-Related Commodities

As of June 30, 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 2037 that qualified for the NPNS exception and were therefore exempt from fair value accounting treatment.

Interest Rate Swaps

NRG was exposed to changes in interest rates through the Company's issuance of variable rate debt. In order to manage the Company's interest rate risk, NRG entered into interest rate swap agreements. As of June 30, 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.

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Volumetric Underlying Derivative Transactions

The following table summarizes the net notional volume buy/(sell) of NRG's open derivative transactions broken out by category, excluding those derivatives that qualified for the NPNS exception, as of June 30, 2020 and December 31, 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 (In millions)
Category	Units	June 30, 2020	December 31, 2019
Emissions	Short Ton	1	3
Renewable Energy Certificates	Certificates	1	1
Coal	Short Ton	5	10
Natural Gas	MMBtu	(237)	(181)
Power	MWh	56	38
Capacity	MW/Day	(1)	(1)

Fair Value of Derivative Instruments

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

	Fair Value
	Derivative Assets				Derivative Liabilities
(In millions)	June 30, 2020		December 31, 2019		June 30, 2020		December 31, 2019
Derivatives Not Designated as Cash Flow or Fair Value Hedges:
Commodity contracts current	$	791	$	860	$	728	$	781
Commodity contracts long-term	439		310		299		322
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges	$	1,230	$	1,170	$	1,027	$	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 Statement of Financial Position
(In millions)	Gross Amounts of Recognized Assets / Liabilities		Derivative Instruments		Cash Collateral (Held) / Posted		Net Amount
As of June 30, 2020
Commodity contracts:
Derivative assets	$	1,230	$	(921)	$	(22)	$	287
Derivative liabilities	(1,027)		921		38		(68)
Total commodity contracts	$	203	$	—	$	16	$	219

	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

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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.

(In millions)	Three months ended June 30,				Six months ended June 30,
Unrealized mark-to-market results	2020		2019		2020		2019
Reversal of previously recognized unrealized losses on settled positions related to economic hedges	$	30	$	11	$	39	$	30
Reversal of acquired loss/(gain) positions related to economic hedges	3		1		4		(1)
Net unrealized gains on open positions related to economic hedges	54		9		88		12
Total unrealized mark-to-market gains for economic hedging activities	87		21		131		41
Reversal of previously recognized unrealized (gains) on settled positions related to trading activity	(5)		(1)		(7)		(7)
Net unrealized gains on open positions related to trading activity	4		13		17		26
Total unrealized mark-to-market (losses)/gains for trading activity	(1)		12		10		19
Total unrealized gains	$	86	$	33	$	141	$	60

	Three months ended June 30,				Six months ended June 30,
(In millions)	2020		2019		2020		2019
Unrealized gains included in operating revenues	$	42	$	253	$	49	$	280
Unrealized gains/(losses) included in cost of operations	44		(220)		92		(220)
Total impact to statement of operations — energy commodities	$	86	$	33	$	141	$	60
Total impact to statement of operations — interest rate contracts	$	—	$	(29)	$	—	$	(38)

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

For the six months ended June 30, 2020, the $88 million unrealized gain from open economic hedge positions was primarily the result of an increase in value of forward positions as a result of increases in outer year ERCOT power prices and decreases in New York capacity, New York power, and West/Other power prices.

For the six months ended June 30, 2019, the $12 million unrealized gain from open economic hedge positions was primarily the result of an increase in value of forward power positions due to a decrease in 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 downgrade in the Company's credit rating. The collateral required for contracts with adequate assurance clauses that are in a net liability position as of June 30, 2020 was $33 million. The Company is also party to certain marginable agreements under which it has net liability position, but the counterparty has not called for the collateral due, which was $8 million as of June 30, 2020. There will be no additional collateral required for all contracts with credit rating contingent features as of June 30, 2020.

See Note 5, Fair Value of Financial Instruments, for discussion regarding concentration of credit risk.

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Note 8 — Impairments

Petra Nova Parish Holdings — During the first quarter of 2020, due to the decline in oil prices, NRG 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 to estimate future project cash flows. The Company recorded an impairment loss of $18 million in the Texas segment, which included the anticipated drawdown of the $12 million letter of credit posted in September 2019 to cover certain project debt reserve requirements.

Note 9 — Long-term Debt

Long-term debt consisted of the following:

(In millions, except rates)	June 30, 2020		December 31, 2019		Interest rate %
Recourse debt:
Senior Notes, due 2026	$	1,000	$	1,000	7.250
Senior Notes, due 2027	1,230		1,230		6.625
Senior Notes, due 2028	821		821		5.750
Senior Notes, due 2029	733		733		5.250
Convertible Senior Notes, due 2048(a)	575		575		2.750
Senior Secured First Lien Notes, due 2024	600		600		3.750
Senior Secured First Lien Notes, due 2029	500		500		4.450
Revolving Credit Facility(b)	—		83		L+ 1.750
Tax-exempt bonds	466		466		1.30 - 6.00
Subtotal recourse debt	5,925		6,008
Non-recourse debt:
Other	32		34		various
Subtotal all non-recourse debt	32		34
Subtotal long-term debt (including current maturities)	5,957		6,042
Less current maturities	(7)		(88)
Less debt issuance costs	(61)		(65)
Discounts	(79)		(86)
Total long-term debt	$	5,810	$	5,803

(a)As of July 31, 2020, the Convertible Notes were convertible at a price of $46.65, which is equivalent to a conversion rate of approximately 21.44 shares of common stock per $1,000 principal amount.

(b)As of December 31, 2019, the Company had drawn under its Revolving Credit Facility at 1-week LIBOR + 1.750

Recourse Debt

Revolving Credit Facility

The Company had $83 million outstanding under its Revolving Credit Facility as of December 31, 2019, which was used to repay the outstanding indebtedness on the Agua Caliente Borrower 1 notes on a leverage-neutral basis during the fourth quarter of 2019. 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, and fully repaid the outstanding borrowings during the second quarter of 2020.

Tax-Exempt Bonds

On March 11, 2020, NRG issued $59 million in aggregate principal amount of 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 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 Bonds will, at the request of NRG, be released if 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 reversion if those rating agencies withdraw their investment grade rating of the Bonds or any of NRG’s senior, unsecured debt securities or downgrade such rating below investment grade. The Bonds are subject to mandatory tender and purchase on April 3, 2023 and have a final maturity date of April 1, 2042.

30

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

Cottonwood - Letters of Credit

On January 4, 2019, the Company entered into an $80 million credit agreement to issue letters of credit, which is currently supporting the Cottonwood facility lease. Annual fees of 1.33% on the facility are paid quarterly in advance. As of June 30, 2020, the full $80 million was issued.

Note 10 — 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 — Agua Caliente 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 relief in the California Bankruptcy Court. As a result of the bankruptcy filing, Agua Caliente and the two Ivanpah units were issued notices of events of default under their respective loan agreements. On September 9, 2019, PG&E filed a plan of reorganization that would assume all power purchase agreements, including those held by Agua Caliente and the two Ivanpah units. The California Bankruptcy Court approved the PG&E plan and the Confirmation Order was entered on June 19, 2020. The plan went effective, and PG&E emerged from bankruptcy on July 1, 2020. On July 22, 2020 and July 24, 2020, the U.S. DOE agreed to waivers of the bankruptcy-related events of default with respect to the Agua Caliente and Ivanpah projects, respectively. The Company is working with the U.S. DOE and the partners on the Agua Caliente and Ivanpah projects to resume distributions from the projects in the near future. NRG renewed its efforts to sell its 35% interest in Agua Caliente in July 2020, following PG&E's emergence from bankruptcy.

NRG's maximum exposure to loss is limited to its equity investment, which was $220 million for Agua Caliente and $10 million for Ivanpah as of June 30, 2020.

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 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)	June 30, 2020		December 31, 2019
Current assets	$	1	$	3
Net property, plant and equipment	—		71
Other long-term assets	25		27
Total assets	26		101
Current liabilities	4		4
Long-term debt	24		24
Other long-term liabilities	4		8
Total liabilities	32		36
Redeemable noncontrolling interest	—		20
Net assets less noncontrolling interest	$	(6)	$	45

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Note 11 — Changes in Capital Structure

As of June 30, 2020 and December 31, 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, 2019	421,890,790	(172,894,601)	248,996,189
Shares issued under LTIPs	1,140,987	—	1,140,987
Shares issued under ESPP	—	63,455	63,455
Shares repurchased	—	(6,062,783)	(6,062,783)
Balance as of June 30, 2020	423,031,777	(178,893,929)	244,137,848

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 six months ended June 30, 2020:

	Total number of shares purchased	Average price paid per share	Amounts paid for shares purchased (in millions)
2020 repurchases:
Repurchases	6,062,783		$	197
Equivalent shares purchased in lieu of tax withholdings on equity compensation issuances(a)	710,474		27
Total Share Repurchases during the six months ended June 30, 2020	6,773,257	$33.05	$	224

(a) NRG elected to pay cash for tax withholding on equity awards instead of issuing actual shares to management. The average price per equivalent shares withheld was $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.

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 $0.30 per share was paid on the Company's common stock during the three months ended June 30, 2020. On July 17, 2020, NRG declared a quarterly dividend on the Company's common stock of $0.30 per share, payable August 17, 2020 to stockholders of record as of August 3, 2020.

The Company's common stock dividends are subject to available capital, market conditions, and compliance with associated laws, regulations and other contractual obligations.

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Note 12 — Earnings Per Share

Basic 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 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 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 Convertible Senior Notes due to the Company’s expectation to settle the liability in cash.

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

	Three months ended June 30,				Six months ended June 30,
(In millions, except per share data)	2020		2019		2020		2019
Basic income per share:
Net income available to common shareholders	$	313	$	201	$	434	$	683
Weighted average number of common shares outstanding - basic	245		265		246		272
Income per weighted average common share — basic	$	1.28	$	0.76	$	1.76	$	2.51
Diluted income per share:
Net income available to common shareholders	$	313	$	201	$	434	$	683
Weighted average number of common shares outstanding - basic	245		265		246		272
Incremental shares attributable to the issuance of equity compensation (treasury stock method)	1		2		1		2
Weighted average number of common shares outstanding - dilutive	246		267		247		274
Income per weighted average common share — diluted	$	1.27	$	0.75	$	1.76	$	2.49

As of June 30, 2020 and 2019, the Company had an insignificant number of outstanding equity instruments that are anti-dilutive and were not included in the computation of the Company’s diluted income per share.

Note 13 — 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 financial information for the three and six months ended June 30, 2019 was recast to reflect the current segment structure.

In February 2019, as described in Note 4, Acquisitions, Discontinued Operations and Dispositions, the Company completed the sales of the South Central Portfolio and Carlsbad. The financial information for the three and six months ended June 30, 2019 presented below 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, as well as net income/(loss).

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	Three months ended June 30, 2020
(In millions)	Texas		East		West/Other		Corporate		Eliminations		Total
Operating revenues	$	1,578	$	566	$	94	$	—	$	—	$	2,238
Depreciation and amortization	59		33		8		10		—		110
Equity in (losses)/earnings of unconsolidated affiliates	(3)		—		15		—		—		12
Income/(loss) from continuing operations before income taxes	350		146		26		(109)		1		414
Income/(loss) from continuing operations	350		146		25		(209)		1		313
Net income/(loss) attributable to NRG Energy, Inc	$	350	$	146	$	25	$	(209)	$	1	$	313

	Three months ended June 30, 2019
(In millions)	Texas		East		West/Other		Corporate		Eliminations		Total
Operating revenues	$	1,837	$	524	$	106	$	1	$	(3)	$	2,465
Depreciation and amortization	40		30		7		8		—		85
Impairment losses	1		—		—		—		—		1
Reorganization costs	3		—		—		(1)		—		2
Gain on sale of assets	—		—		—		1		—		1
Equity in (losses)/earnings of unconsolidated affiliates	(3)		—		3		—		—		—
Loss on debt extinguishment, net	—		—		—		(47)		—		(47)
Income/(loss) from continuing operations before income taxes	259		60		18		(149)		—		188
Income/(loss) from continuing operations	259		60		18		(148)		—		189
Income from discontinued operations, net of tax	—		—		—		13		—		13
Net income/(loss)	259		60		18		(135)		—		202
Net income/(loss) attributable to NRG Energy, Inc.	$	259	$	60	$	17	$	(135)	$	—	$	201

	Six months ended June 30, 2020
(In millions)	Texas		East		West/Other		Corporate		Eliminations		Total
Operating revenues	$	2,936	$	1,105	$	219	$	—	$	(3)	$	4,257
Depreciation and amortization	118		66		16		19		—		219
Reorganization costs	1		—		—		2		—		3
Gain on sale of assets	—		—		1		5		—		6
Equity in (losses)/earnings of unconsolidated affiliates	(3)		—		4		—		—		1
Impairment losses on investments	(18)		—		—		—		—		(18)
Loss on debt extinguishment, net	—		(1)		—		—		—		(1)
Income/(loss) from continuing operations before income taxes	512		170		67		(191)		—		558
Income/(loss) from continuing operations	512		170		66		(314)		—		434
Net income/(loss) attributable to NRG Energy, Inc	$	512	$	170	$	66	$	(314)	$	—	$	434

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	Six months ended June 30, 2019
(In millions)	Texas		East		West/Other		Corporate		Eliminations		Total
Operating revenues	$	3,303	$	1,133	$	199	$	—	$	(5)	$	4,630
Depreciation and amortization	80		56		18		16		—		170
Impairment losses	1		—		—		—		—		1
Reorganization costs	4		—		—		11		—		15
Gain on sale of assets	—		1		—		1		—		2
Equity in (losses) of unconsolidated affiliates	(6)		—		(15)		—		—		(21)
Loss on debt extinguishment, net	—		—		—		(47)		—		(47)
Income/(loss) from continuing operations before income taxes	409		159		(5)		(276)		(1)		286
Income/(loss) from continuing operations	409		159		(5)		(279)		(1)		283
Income from discontinued operations, net of tax	—		—		—		401		—		401
Net income/(loss)	409		159		(5)		122		(1)		684
Net income/(loss) attributable to NRG Energy, Inc.	$	409	$	159	$	(6)	$	122	$	(1)	$	683

Note 14 — Income Taxes

Effective Income Tax Rate

The income tax provision consisted of the following:

	Three months ended June 30,						Six months ended June 30,
(In millions, except rates)	2020			2019			2020			2019
Income from continuing operations before income taxes	$	414		$	188		$	558		$	286
Income tax expense/(benefit) from continuing operations	101			(1)			124			3
Effective income tax rate	24.4		%	(0.5)		%	22.2		%	1.0		%

For the three and six months ended June 30, 2020, the effective tax rates were higher than the statutory rate of 21% due to state tax expense partially offset by an excess tax benefit related to share-based compensation. For the same periods in 2019, the effective tax rates were lower than the statutory rate of 21% primarily due to the tax benefit for the change in valuation allowance partially offset by 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 June 30, 2020, NRG had a non-current tax liability of $18 million for uncertain tax benefits from positions taken on various state income tax returns and accrued interest. For the six months ended June 30, 2020, NRG accrued an immaterial amount of interest relating to the uncertain tax benefits. As of June 30, 2020, NRG had cumulative interest and penalties related to these uncertain tax benefits of $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 and Canada. The Company is no longer subject to U.S. federal income tax examinations for years prior to 2016. With few exceptions, state and local income tax examinations are no longer open for years prior to 2011.

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Note 15 — 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 June 30,				Six months ended June 30,
(In millions)	2020		2019		2020		2019
Revenues from Related Parties Included in Operating Revenues
Gladstone	$	—	$	1	$	1	$	1
Ivanpah(a)	10		7		23		18
Midway-Sunset	2		1		3		2
Total	$	12	$	9	$	27	$	21

(a) Also includes fees under project management agreements with each project company

Note 16 — Commitments and Contingencies

Commitments

First Lien Structure

NRG has granted first liens to certain counterparties on a substantial portion of property and assets owned by NRG and the guarantors of 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 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 would have a claim under the first lien program. As of June 30, 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 burned lignite obtained from the Jewett mine, which was operated by TWCC. On or about March 15, 2019, the Jewett mine and related lignite supply agreement with NRG were acquired by Westmoreland Jewett Mining LLC ("Jewett Mining"), a subsidiary of Westmoreland Mining LLC pursuant to a plan of reorganization confirmed by the Texas Bankruptcy Court. Effective August 5, 2020, NRG's subsidiary, NRG Texas LLC, acquired all of the equity interests of Jewett Mining. Active mining under the lignite supply agreement ceased as of December 31, 2016; however, under the terms of the lignite supply agreement, Jewett Mining remains responsible for undertaking reclamation activities and NRG is responsible for all 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 17, Regulatory Matters, and Note 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.

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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.

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 LaGen in the United States District Court for the Middle District of Louisiana. The plaintiffs claimed 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 sought damages for the alleged improper charges and a declaration as to which charges were proper under the contract. In February 2020, the court dismissed this lawsuit without prejudice for lack of subject matter jurisdiction. This matter had been appealed to the United States Court of Appeals for the Fifth Circuit, which dismissed the appeals on July 13, 2020. On March 17, 2020, plaintiffs filed a lawsuit in the Nineteenth Judicial District Court for the Parish of East Baton Rouge in Louisiana alleging substantially the same matters. On February 4, 2019, NRG sold the South Central Portfolio, including the entities subject to this litigation. However, NRG has agreed to indemnify the purchaser for certain losses suffered in connection therewith.

Sierra club et al. v. Midwest Generation LLC — In 2012, several environmental groups filed a complaint against Midwest Generation with the Illinois Pollution Control Board ("IPCB") alleging violations of environmental law resulting in groundwater contamination. In June 2019, the IPCB found that Midwest Generation violated the law because it had improperly handled coal ash at four facilities in Illinois and caused or allowed coal ash constituents to impact groundwater. On September 9, 2019, Midwest Generation filed a Motion to Reconsider numerous issues, 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 two 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 17 — Regulatory Matters

Environmental regulatory matters are discussed within Note 18, Environmental Matters.

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 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. The Company expects a preliminary finding from FERC in 2020.

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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 its commercial business decision making.

Note 18 — 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.

Water

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 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 was anticipated. The Company will revisit these estimates after the rule is revised and as permits are renewed.

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. On July 29, 2020, the EPA released a prepublication (non-official) version of the final rule "A Holistic Approach to Closure Part A: Deadline to Initiate Closure," which when published in the Federal Register will amend the April 2015 Rule to address the August 2018 D.C. Circuit decision and extend some of the deadlines. The Company anticipates that the EPA will promulgate additional regulations to further amend the existing rule. The Company will update estimates of required environmental capital expenditures as the rule is revised.

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Note 19 — Subsequent Events

Direct Energy Acquisition

On July 24, 2020, the Company entered into a definitive purchase agreement with Centrica to acquire Direct Energy, a North American subsidiary of Centrica (the "Purchase Agreement"). Direct Energy is a leading retail provider of electricity, natural gas, and home and business energy related products and services in North America, with operations in all 50 U.S. states and 6 Canadian provinces. The acquisition will add over 3 million customers to NRG's business and build on and complement its integrated model, enabling better matching of power generation with customer demand. It will also broaden the Company's presence in the Northeast and into states and locales where it does not currently operate, supporting NRG's objective to diversify its business.

The Company will pay an aggregate purchase price of $3.6 billion in cash, subject to a purchase price adjustment, including a working capital adjustment. The Company expects to fund the purchase price using a combination of cash on hand, approximately $2.4 billion in newly-issued secured and unsecured corporate debt and approximately $750 million in convertible preferred stock or other equity-linked instruments. The Company also expects to increase its collective collateral facilities by $3.5 billion through a combination of new letter of credit facilities and increase to the existing Revolving Credit Facility.

The acquisition is subject to approval by the shareholders of Centrica, as well as customary closing conditions, consents and regulatory approvals, including the expiration or termination of the applicable waiting period under the HSR Act, and the receipt of approvals or expiration of applicable waiting periods under the Federal Power Act and the Canadian Competition Act.

The acquisition is targeted to close by December 31, 2020. There are no assurances that the conditions to the consummation of the acquisition of Direct Energy will be satisfied, that Centrica will not seek or enter into an alternative transaction as discussed below, or that the acquisition of Direct Energy will be consummated on the terms agreed to, or at all.

Prior to the approval of the transaction by its shareholders, Centrica is permitted to respond to unsolicited acquisition proposals that constitute or are reasonably likely to lead to a superior proposal, and to engage in negotiations with, and provide information to, parties that submit these proposals. Centrica can terminate the Purchase Agreement to accept a superior proposal. In addition, the board of directors of Centrica can change its recommendation in favor of NRG's transaction if the failure to do so would be inconsistent with the fiduciary duties of the Centrica directors, in which case the Purchase Agreement would automatically terminate. In the event of a termination of the Purchase Agreement in connection with (i) Centrica's decision to accept a superior proposal, (ii) the failure to obtain Centrica shareholder approval, or (iii) a change of recommendation by the Centrica board, Centrica would be obligated to pay NRG a termination fee of approximately $30 million.

NRG will be required to pay Centrica a termination fee of $180 million if the Purchase Agreement is terminated (i) by either Centrica or NRG because the transaction has not been completed by July 24, 2021 (as such date may be extended for two separate three month periods if necessary to obtain required regulatory approvals, through January 24, 2022), and at the time of termination all of the mutual conditions to the obligations of NRG and Centrica to close the acquisition, and all the conditions to NRG's obligations to close the acquisition, have been satisfied other than receipt of the required antitrust and competition approvals, (ii) by either Centrica or NRG if a governmental entity has issued a judgment with respect to an antitrust or competition law that permanently prohibits the completion of the transaction and the judgment has become final and non-appealable, (iii) by NRG if a governmental entity has imposed a condition on its willingness to approve the acquisition on antitrust or competition grounds and the condition has a material adverse effect as described in the Purchase Agreement or (iv) by Centrica because NRG has breached its obligations under the Purchase Agreement to seek to obtain the antitrust and competition approvals required to complete the transaction.

Midwest Generation Lease Purchase

On July 22, 2020, Midwest Generation signed purchase agreements to acquire all of the ownership interests in the Powerton facility and Units 7 and 8 of the Joliet facility, which were being leased through 2034 and 2030, respectively, for approximately $260 million. The Company intends to fund the purchase with borrowings under its Revolving Credit Facility in an amount equal to the existing operating lease liabilities of $148 million as of June 30, 2020 and the remainder from cash-on-hand. The closing is conditioned, among other items, on the receipt of regulatory approvals from FERC and under the HSR Act.

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Note 20 — Condensed Consolidating Financial Information

As of June 30, 2020, the Company had outstanding $4.4 billion of Senior Notes and Convertible Senior Notes due from 2026 to 2048 and outstanding $1.1 billion of Senior Secured Notes due from 2024 to 2029, as shown in Note 9, Long-term Debt. These Senior Notes and Senior Secured 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.

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Unless otherwise noted below, each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes, Convertible Senior Notes and Senior Secured Notes as of June 30, 2020:

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

41

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.

42

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the three months ended June 30, 2020

(Unaudited)

(In millions)	Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)		Eliminations(a)		Consolidated
Operating Revenues
Total operating revenues	$	2,055	$	181	$	—	$	2	$	2,238
Operating Costs and Expenses
Cost of operations	1,271		154		7		2		1,434
Depreciation and amortization	80		20		10		—		110
Selling, general and administrative costs	137		7		64		—		208
Development costs	—		1		1		—		2
Total operating costs and expenses	1,488		182		82		2		1,754
Operating Income/(Loss)	567		(1)		(82)		—		484
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries	3		—		583		(586)		—
Equity in earnings of unconsolidated affiliates	—		12		—		—		12
Other income, net	7		5		2		—		14
Interest expense	(4)		(2)		(90)		—		(96)
Total other income/(expense)	6		15		495		(586)		(70)
Income from Continuing Operations Before Income Taxes	573		14		413		(586)		414
Income tax expense	—		1		100		—		101
Net Income	$	573	$	13	$	313	$	(586)	$	313

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

43

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the six months ended June 30, 2020

(Unaudited)

(In millions)	Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)		Eliminations(a)		Consolidated
Operating Revenues
Total operating revenues	$	3,833	$	433	$	—	$	(9)	$	4,257
Operating Costs and Expenses
Cost of operations	2,561		356		(17)		(9)		2,891
Depreciation and amortization	160		39		20		—		219
Selling, general and administrative costs	277		12		128		—		417
Reorganization costs	—		—		3		—		3
Development costs	—		1		4		—		5
Total operating costs and expenses	2,998		408		138		(9)		3,535
Gain on sale of assets	—		1		5		—		6
Operating Income/(Loss)	835		26		(133)		—		728
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries	6		—		845		(851)		—
Equity in earnings of unconsolidated affiliates	—		1		—		—		1
Impairment losses on investments	—		(18)		—		—		(18)
Other income, net	10		4		27		—		41
Loss on debt extinguishment, net	—		—		(1)		—		(1)
Interest expense	(9)		(3)		(181)		—		(193)
Total other income/(expense)	7		(16)		690		(851)		(170)
Income from Continuing Operations Before Income Taxes	842		10		557		(851)		558
Income tax expense	—		1		123		—		124
Net Income	$	842	$	9	$	434	$	(851)	$	434

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

44

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

For the three months ended June 30, 2020

(Unaudited)

(In millions)	Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)		Eliminations(a)		Consolidated
Net Income	$	573	$	13	$	313	$	(586)	$	313
Other Comprehensive Income
Foreign currency translation adjustments, net	12		13		13		(25)		13
Defined benefit plans, net	1		—		—		(1)		—
Other comprehensive income	13		13		13		(26)		13
Comprehensive Income	$	586	$	26	$	326	$	(612)	$	326

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

45

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME

For the six months ended June 30, 2020

(Unaudited)

(In millions)	Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)		Eliminations(a)		Consolidated
Net Income	$	842	$	9	$	434	$	(851)	$	434
Other Comprehensive Loss
Foreign currency translation adjustments, net	(3)		(2)		(2)		5		(2)
Defined benefit plans, net	3		—		—		(3)		—
Other comprehensive loss	—		(2)		(2)		2		(2)
Comprehensive Income	$	842	$	7	$	432	$	(849)	$	432

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

46

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

June 30, 2020

(Unaudited)

(In millions)	Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)		Eliminations(a)		Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	—	$	20	$	398	$	—	$	418
Funds deposited by counterparties	36		—		—		—		36
Restricted cash	7		—		1		—		8
Accounts receivable, net	987		111		1,267		(1,350)		1,015
Inventory	306		82		—		—		388
Derivative instruments	789		22		—		(20)		791
Cash collateral paid in support of energy risk management activities	133		3		—		—		136
Prepayments and other current assets	247		10		27		—		284
Total current assets	2,505		248		1,693		(1,370)		3,076
Property, plant and equipment, net	1,336		1,046		151		—		2,533
Other Assets
Investment in subsidiaries	170		—		4,525		(4,695)		—
Equity investments in affiliates	—		372		—		—		372
Operating lease right-of-use assets, net	73		244		112		—		429
Goodwill	400		179		—		—		579
Intangible assets, net	695		38		—		—		733
Nuclear decommissioning trust fund	794		—		—		—		794
Derivative instruments	439		9		—		(9)		439
Deferred income taxes	435		(33)		2,768		—		3,170
Other non-current assets	150		27		35		—		212
Total other assets	3,156		836		7,440		(4,704)		6,728
Total Assets	$	6,997	$	2,130	$	9,284	$	(6,074)	$	12,337
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt	$	3	$	4	$	—	$	—	$	7
Current portion of operating lease liabilities	19		31		19		—		69
Accounts payable	809		187		1,090		(1,350)		736
Derivative instruments	739		9		—		(20)		728
Cash collateral received in support of energy risk management activities	36		—		—		—		36
Accrued expenses and other current liabilities	296		31		254		—		581
Total current liabilities	1,902		262		1,363		(1,370)		2,157
Other Liabilities
Long-term debt	245		24		5,541		—		5,810
Non-current operating lease liabilities	58		290		110		—		458
Nuclear decommissioning reserve	307		—		—		—		307
Nuclear decommissioning trust liability	478		—		—		—		478
Derivative instruments	307		1		—		(9)		299
Deferred income taxes	—		17		—		—		17
Other non-current liabilities	421		120		520		—		1,061
Total other liabilities	1,816		452		6,171		(9)		8,430
Total Liabilities	3,718		714		7,534		(1,379)		10,587
Stockholders’ Equity	3,279		1,416		1,750		(4,695)		1,750
Total Liabilities and Stockholders’ Equity	$	6,997	$	2,130	$	9,284	$	(6,074)	$	12,337

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

47

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the six months ended June 30, 2020

(Unaudited)

(In millions)	Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)		Eliminations(a)		Consolidated
Cash Flows from Operating Activities
Net income	$	842	$	9	$	434	$	(851)	$	434
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	(6)		7		(845)		851		7
Depreciation and amortization	160		39		20		—		219
Accretion of asset retirement obligations	10		8		—		—		18
Provision for credit losses	47		1		—		—		48
Amortization of nuclear fuel	25		—		—		—		25
Amortization of financing costs and debt discount/premiums	—		—		12		—		12
Loss on debt extinguishment, net	—		—		1		—		1
Amortization of emission allowances and energy credits	24		9		—		—		33
Amortization of unearned equity compensation	—		—		12		—		12
Net gain on sale of assets and disposal of assets	(9)		(1)		(5)		—		(15)
Impairment losses	—		18		—		—		18
Changes in derivative instruments	(144)		13		—		—		(131)
Changes in deferred income taxes and liability for uncertain tax benefits	1,212		(154)		(942)		—		116
Changes in collateral deposits in support of energy risk management activities	53		5		—		—		58
Changes in nuclear decommissioning trust liability	36		—		—		—		36
Changes in other working capital	(124)		(19)		(56)		—		(199)
Net Cash Provided/(Used) by Operating Activities	2,126		(65)		(1,369)		—		692
Cash Flows from Investing Activities
Intercompany dividends	—		—		1,889		(1,889)		—
Payments for acquisitions of businesses	(5)		—		—		—		(5)
Capital expenditures	(78)		(20)		(18)		—		(116)
Net purchases of emission allowances	(4)		—		—		—		(4)
Investments in nuclear decommissioning trust fund securities	(257)		—		—		—		(257)
Proceeds from the sale of nuclear decommissioning trust fund securities	220		—		—		—		220
Proceeds from sale of assets, net of cash disposed and sale of discontinued operations, net of fees	10		—		5		—		15
Net contributions to investments in unconsolidated affiliates	—		2		—		—		2
Net Cash (Used)/Provided by Investing Activities	(114)		(18)		1,876		(1,889)		(145)
Cash Flows from Financing Activities
Intercompany dividends and transfers	(1,941)		86		(34)		1,889		—
Payments of dividends to common stockholders	—		—		(148)		—		(148)
Payments for share repurchase activity	—		—		(229)		—		(229)
Purchase of and distributions to noncontrolling interests from subsidiaries	—		(2)		—		—		(2)
Proceeds from issuance of common stock	—		—		1		—		1
Proceeds from issuance of long-term debt	—		—		59		—		59
Payment of debt issuance costs	—		—		(1)		—		(1)
Repayments of long-term debt	(60)		(1)		—		—		(61)
Net repayment of Revolving Credit Facility	—		—		(83)		—		(83)
Other	(5)		—		—		—		(5)
Net Cash (Used)/Provided by Financing Activities	(2,006)		83		(435)		1,889		(469)
Effect of exchange rate changes on cash and cash equivalents	—		(1)		—		—		(1)
Net Increase/(Decrease) in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash	6		(1)		72		—		77
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	$	43	$	20	$	399	$	—	$	462

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

48

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the three months ended June 30, 2019

(Unaudited)

(In millions)	Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)		Eliminations(a)		Consolidated
Operating Revenues
Total operating revenues	$	2,140	$	332	$	—	$	(7)	$	2,465
Operating Costs and Expenses
Cost of operations	1,590		252		10		(7)		1,845
Depreciation and amortization	51		26		8		—		85
Impairment losses	1		—		—		—		1
Selling, general and administrative costs	112		12		87		—		211
Reorganization costs	—		—		2		—		2
Development costs	—		1		1		—		2
Total operating costs and expenses	1,754		291		108		(7)		2,146
Gain on sale of assets	—		1		—		—		1
Operating Income/(Loss)	386		42		(108)		—		320
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries	2		—		430		(432)		—
Other income, net	4		8		8		—		20
Loss on debt extinguishment, net	—		—		(47)		—		(47)
Interest expense	(3)		(5)		(97)		—		(105)
Total other income/(expense)	3		3		294		(432)		(132)
Income from Continuing Operations Before Income Taxes	389		45		186		(432)		188
Income tax expense/(benefit)	—		1		(2)		—		(1)
Income from Continuing Operations	389		44		188		(432)		189
Income from discontinued operations, net of income tax	—		—		13		—		13
Net Income	389		44		201		(432)		202
Less: Net income attributable to noncontrolling interest and redeemable noncontrolling interest	—		1		—		—		1
Net Income Attributable to NRG Energy, Inc.	$	389	$	43	$	201	$	(432)	$	201

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

49

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the six months ended June 30, 2019

(Unaudited)

(In millions)	Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)		Eliminations(a)		Consolidated
Operating Revenues
Total operating revenues	$	3,909	$	727	$	—	$	(6)	$	4,630
Operating Costs and Expenses
Cost of operations	2,948		535		19		(6)		3,496
Depreciation and amortization	105		49		16		—		170
Impairment losses	1		—		—		—		1
Selling, general and administrative costs	234		28		143		—		405
Reorganization costs	—		—		15		—		15
Development costs	—		1		3		—		4
Total operating costs and expenses	3,288		613		196		(6)		4,091
Gain on sale of assets	1		1		—		—		2
Operating Income/(Loss)	622		115		(196)		—		541
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries	12		—		729		(741)		—
Equity in losses of unconsolidated affiliates	—		(21)		—		—		(21)
Other income, net	8		9		15		—		32
Loss on debt extinguishment, net	—		—		(47)		—		(47)
Interest expense	(7)		(9)		(203)		—		(219)
Total other income/(expense)	13		(21)		494		(741)		(255)
Income from Continuing Operations Before Income Taxes	635		94		298		(741)		286
Income tax expense	—		1		2		—		3
Income from Continuing Operations	635		93		296		(741)		283
Income from discontinued operations, net of income tax	9		5		387		—		401
Net Income	644		98		683		(741)		684
Less: Net income attributable to noncontrolling interest and redeemable noncontrolling interest	—		1		—		—		1
Net Income Attributable to NRG Energy, Inc.	$	644	$	97	$	683	$	(741)	$	683

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

50

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME

For the three months ended June 30, 2019

(Unaudited)

(In millions)	Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)		Eliminations(a)		Consolidated
Net Income	$	389	$	44	$	201	$	(432)	$	202
Other Comprehensive Loss
Foreign currency translation adjustments, net	(1)		(1)		(1)		2		(1)
Available-for-sale securities, net	—		—		1		—		1
Defined benefit plans, net	—		—		(3)		—		(3)
Other comprehensive loss	(1)		(1)		(3)		2		(3)
Comprehensive Income	388		43		198		(430)		199
Less: Comprehensive income attributable to redeemable noncontrolling interest	—		1		—		—		1
Comprehensive Income Attributable to NRG Energy, Inc.	$	388	$	42	$	198	$	(430)	$	198

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

51

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME

For the six months ended June 30, 2019

(Unaudited)

(In millions)	Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)		Eliminations(a)		Consolidated
Net Income	$	644	$	98	$	683	$	(741)	$	684
Other Comprehensive Loss
Available-for-sale securities, net	—		—		1		—		1
Defined benefit plans, net	—		—		(6)		—		(6)
Other comprehensive loss	—		—		(5)		—		(5)
Comprehensive Income	644		98		678		(741)		679
Less: Comprehensive income attributable to redeemable noncontrolling interest	—		1		—		—		1
Comprehensive Income Attributable to NRG Energy, Inc.	$	644	$	97	$	678	$	(741)	$	678

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

52

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

December 31, 2019

(In millions)	Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)		Eliminations(a)		Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	—	$	20	$	325	$	—	$	345
Funds deposited by counterparties	32		—		—		—		32
Restricted cash	5		1		2		—		8
Accounts receivable, net	1,293		239		233		(740)		1,025
Inventory	272		111		—		—		383
Derivative instruments	856		45		—		(41)		860
Cash collateral paid in support of energy risk management activities	182		8		—		—		190
Prepayments and other current assets	170		8		67		—		245
Total current assets	2,810		432		627		(781)		3,088
Property, plant and equipment, net	1,483		952		158		—		2,593
Other Assets
Investment in subsidiaries	710		—		4,785		(5,495)		—
Equity investments in affiliates	—		388		—		—		388
Operating lease right-of-use assets, net	81		261		122		—		464
Goodwill	359		220		—		—		579
Intangible assets, net	375		414		—		—		789
Nuclear decommissioning trust fund	794		—		—		—		794
Derivative instruments	308		15		—		(13)		310
Deferred income taxes	421		(19)		2,884		—		3,286
Other non-current assets	145		30		65		—		240
Total other assets	3,193		1,309		7,856		(5,508)		6,850
Total Assets	$	7,486	$	2,693	$	8,641	$	(6,289)	$	12,531
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt	$	—	$	5	$	83	$	—	$	88
Current portion of operating lease liabilities	20		32		21		—		73
Accounts payable	918		141		403		(740)		722
Derivative instruments	797		25		—		(41)		781
Cash collateral received in support of energy risk management activities	32		—		—		—		32
Accrued expenses and other current liabilities	280		44		339		—		663
Total current liabilities	2,047		247		846		(781)		2,359
Other Liabilities
Long-term debt	302		28		5,473		—		5,803
Non-current operating lease liabilities	64		301		118		—		483
Nuclear decommissioning reserve	298		—		—		—		298
Nuclear decommissioning trust liability	487		—		—		—		487
Derivative instruments	334		1		—		(13)		322
Deferred income taxes	—		17		—		—		17
Other non-current liabilities	399		153		532		—		1,084
Total other liabilities	1,884		500		6,123		(13)		8,494
Total Liabilities	3,931		747		6,969		(794)		10,853
Redeemable noncontrolling interest in subsidiaries	—		20		—		—		20
Stockholders’ Equity	3,555		1,926		1,672		(5,495)		1,658
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

53

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the six months ended June 30, 2019

(Unaudited)

(In millions)	Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)		Eliminations(a)		Consolidated
Cash Flows from Operating Activities
Net income	$	644	$	98	$	683	$	(741)	$	684
Income from discontinued operations	9		5		387		—		401
Income from continuing operations	635		93		296		(741)		283
Adjustments to reconcile net income to cash provided by operating activities:
Distributions from and equity in earnings/(losses) of unconsolidated affiliates and consolidated subsidiaries	(12)		22		(729)		741		22
Depreciation and amortization	104		50		16		—		170
Accretion of asset retirement obligations	11		3		—		—		14
Provision for credit losses	42		4		6		—		52
Amortization of nuclear fuel	27		—		—		—		27
Amortization of financing costs and debt discount/premiums	—		—		13		—		13
Loss on debt extinguishment, net	—		—		47		—		47
Amortization of emission allowances and energy credits	13		1		—		—		14
Amortization of unearned equity compensation	—		—		10		—		10
Net loss on sale of assets and disposal of assets	(3)		1		3		—		1
Impairment losses	1		—		—		—		1
Changes in derivative instruments	(28)		(32)		38		—		(22)
Changes in deferred income taxes and liability for uncertain tax benefits	—		(3)		(2)		—		(5)
Changes in collateral deposits in support of energy risk management activities	128		(3)		—		—		125
Changes in nuclear decommissioning trust liability	17		—		—		—		17
Changes in other working capital	(343)		(64)		55		—		(352)
Cash provided/(used) by continuing operations	592		72		(247)		—		417
Cash provided/(used) by discontinued operations	17		(9)		—		—		8
Net Cash Provided/(Used) by Operating Activities	609		63		(247)		—		425
Cash Flows from Investing Activities
Intercompany dividends	—		—		2,209		(2,209)		—
Payments for acquisitions of businesses	(21)		—		—		—		(21)
Capital expenditures	(77)		(15)		(15)		—		(107)
Net purchases of emission allowances	(1)		—		—		—		(1)
Investments in nuclear decommissioning trust fund securities	(209)		—		—		—		(209)
Proceeds from the sale of nuclear decommissioning trust fund securities	191		—		—		—		191
Proceeds from sale of assets, net of cash disposed and sale of discontinued operations, net of fees	1		400		888		—		1,289
Net distributions from investments in unconsolidated affiliates	—		7		—		—		7
Contributions to discontinued operations	—		(44)		—		—		(44)
Cash (used)/provided by continuing operations	(116)		348		3,082		(2,209)		1,105
Cash used by discontinued operations	—		(2)		—		—		(2)
Net Cash (Used)/Provided by Investing Activities	(116)		346		3,082		(2,209)		1,103
Cash Flows from Financing Activities
Intercompany dividends and transfers	(532)		(375)		(1,302)		2,209		—
Payment of dividends to common stockholders	—		—		(16)		—		(16)
Payments for share repurchase activity	—		—		(1,075)		—		(1,075)
Payments for debt extinguishment	—		—		(24)		—		(24)
Net distributions to noncontrolling interests from subsidiaries	—		(1)		—		—		(1)
Proceeds from issuance of common stock	—		—		2		—		2
Proceeds from issuance of long-term debt	—		—		1,833		—		1,833
Payment of debt issuance costs	—		—		(33)		—		(33)
Payments for long-term debt	—		(53)		(2,432)		—		(2,485)
Cash used by continuing operations	(532)		(429)		(3,047)		2,209		(1,799)
Cash provided by discontinued operations	—		43		—		—		43
Net Cash Used by Financing Activities	(532)		(386)		(3,047)		2,209		(1,756)
Change in cash from discontinued operations	17		32		—		—		49
Net Decrease in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash	(56)		(9)		(212)		—		(277)
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period	95		38		480		—		613
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	$	39	$	29	$	268	$	—	$	336

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

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ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

As you read this discussion and analysis, refer to NRG's Condensed Consolidated Statements of Operations to this Form 10-Q, which present the results of operations for the three and six months ended June 30, 2020 and 2019. Also refer to NRG's 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. In addition, refer to the Current Report on Form 8-K filed with the SEC on May 7, 2020, which provides retrospectively revised historical financial information to correspond with the Company's current segment structure.

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.

The Company determined in prior years that the following businesses were discontinued operations and recast prior periods to present their results in the corporate segment:

•South Central Portfolio

•Carlsbad

•GenOn

Executive Summary

Introduction and Overview

NRG Energy, Inc., or NRG or the Company, is an integrated power company built on dynamic retail brands with diverse generation assets. NRG brings the power of energy to customers by producing and 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. The Company sells energy, services, and innovative, sustainable products and services directly to retail customers under the names 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 June 30, 2020. NRG was incorporated as a Delaware corporation on May 29, 1992.

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. The Company's updated segment structure reflects how management currently makes financial decisions and allocates resources.

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The following table summarizes NRG's generation portfolio in MW as of June 30, 2020 by operating segment:

Generation Type	Texas	East	West/Other (a)(b)	Total
Natural gas	4,759	2,686	2,308	9,753
Coal	4,174	3,140	605	7,919
Oil	—	3,600	—	3,600
Nuclear	1,132	—	—	1,132
Utility Scale Solar	—	—	321	321
Battery Storage & Distributed Solar	2	—	60	62
Total generation capacity (c)	10,067	9,426	3,294	22,787

(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

COVID-19

In March 2020, the World Health Organization categorized COVID-19 as a pandemic and the President of the United States declared the COVID-19 outbreak a national emergency. Electricity was deemed a ‘critical and essential business operation’ under various state and federal governmental COVID-19 mandates.

NRG continues to remain 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, during the second quarter of 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 aided 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.

NRG had 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, in March 2020, 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. During the second quarter of 2020, the Company began to evaluate alternatives for return to normal work operations. In addition, 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 requires 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.

The Company continues to utilize the communication protocol established in January 2020, including a central information hub on its intranet, telehealth services, and its Emergency Relief Fund for financially-impacted employees.

While the pandemic may present new risks, as further described in Part II, Item 1A — Risk Factors of this Form 10-Q, to the Company’s business, there was not a material adverse impact on the Company’s 2020 results of operations for the six months ended June 30, 2020. 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 $2.2 billion as of June 30, 2020, consisting of cash on hand and its Revolving Credit Facility.

Following the President's declaration of COVID-19 outbreak being a national emergency, the Governors of the majority of states in which the Company operates issued executive orders that every person should, except where necessary to 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 state restrictions have been eased or lifted, loads have begun to recover in those markets in which the Company operates. The rebound in demand has varied across the Company's market footprint, as restrictions vary regionally. The Company expects demand uncertainty to continue in the near future.

Specifically, in Texas, the PUCT adopted the COVID-19 Electricity Relief Program (“ERP”) to mitigate the impact of COVID-19 on Texas retail electric customers experiencing economic hardship as a result of the pandemic. The COVID-19 ERP

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provides temporary disconnection protection for eligible customers and establishes funds to offset some of the costs incurred by retail electric providers to continue service to those customers. Consistent with the PUCT's orders, NRG is also offering deferred payment plans to all residential and small commercial customers while the declaration of emergency in Texas is in place.

The situation surrounding COVID-19 remains fluid and the potential for a material adverse impact on 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, and any resurgence of COVID-19, may have on the Company’s results of operations, financial position, and liquidity. The extent to which the COVID-19 pandemic may impact the Company’s business, operating results, financial condition, risk exposure or liquidity will depend on future developments, including the duration of the outbreak, travel restrictions, business and 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 of this Form 10-Q.

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.

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) offering innovative and renewable energy solutions for customers; (iii) excellence in operating performance of its existing assets; (iv) optimal hedging of NRG's net retail and generation positions; and (v) engaging in disciplined and transparent capital allocation.

Sustainability is an integral part of NRG's strategy and ties directly to business success, reduced risks and brand value. In 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 increase. Under its new GHG emissions reduction timeline, NRG is targeting to achieve a 50% reduction by 2025 and net-zero emissions by 2050 from a 2014 baseline.

Energy Regulatory Matters

The Company’s regulatory matters are described in the Company’s 2019 Form 10-K in Item 1, Business — Regulatory Matters. These matters have been updated below and in Note 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

D.C. Circuit Ruling on FERC's Use of Tolling Orders — On June 30, 2020, the U.S. Court of Appeals for the D.C. Circuit issued a decision stating that FERC's ability to "toll" actions on rehearing beyond the statutory 30-day period is unlawful. Chairman Chatterjee and Commissioner Glick issued a joint statement asking Congress to give FERC a reasonable amount of time to make a decision on rehearing requests under the Natural Gas Act and the Federal Power Act. This decision impacts an array of appeals related to the PJM MOPR order and will impact how rehearings are decided and appeals filed.

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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 NRG's PJM trade organization, it is also currently participating in an appeal of NJBPU's Order regarding ZECs.

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 17, Regulatory Matters.

East/West

PJM

Capacity Market Reforms Filing — On December 19, 2019, FERC issued an order on the pending proposals to reform the PJM market to mitigate subsidized resources in the capacity market. FERC directed PJM to apply the Minimum Offer Price Rule, or MOPR, to 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 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 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 this filing a timetable for when it proposes to hold the previously postponed Base Residual Auctions for the 2022/2023 and 2023/2024 delivery years. Multiple parties filed for rehearing and clarification. FERC ruled on April 16, 2020 to largely uphold its December 2019 Order, after which, multiple parties, including NRG, filed for appeal at various circuit courts. On March 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 the compliance filing. Comments to the compliance filing are extended until May 15, 2020. Pursuant to the April 16, 2020 Order, PJM was required to make an additional compliance filing within 45 days of that Order. PJM made that compliance filing on June 1, 2020 and proposed to (i) hold the previously postponed Base Residual Auction for the 2022/2023 deliver year six and a half months after FERC issues an Order to (ii) hold the additional outstanding auctions four and half months after the 2022/2023 auction is held. 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. NRG submitted initial comments on May 20, 2020, and subsequently filed reply comments on June 24, 2020. On September 18, 2020, the NJBPU will hold a technical conference. The proceeding is pending. Any actions taken by the NJBPU could affect market prices in PJM.

New England

ISO-NE Inventoried Energy Compensation Proposal — On March 25, 2019, ISO-NE proposed an interim measure to address near-term fuel security concerns. 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. On June 18, 2020, FERC issued an order accepting the Inventoried Energy Compensation Proposal. 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. Multiple parties filed comments and protests. The matter is pending at FERC. The outcome of the matter will affect market prices in ISO-NE.

Mystic's Complaint on Transmission Reliability Review — On June 10, 2020, Constellation Mystic Power LLC filed a complaint at FERC against ISO-NE alleging that ISO-NE violated its Tariff in its addition of language to its planning procedure and in its conduct in carrying out a competitive transmission REP to address the retirements of Mystic Units 8 and 9. NRG, through its trade associations, filed comments on June 30, 2020. The outcome of this proceeding could affect the retirement of the Mystic Units 8 and 9, thereby affecting capacity prices in ISO-NE.

Paper Hearing on ISO-NE's New Entrant Rule — On July 1, 2020, FERC issued an order establishing a Section 206 hearing initiated by FERC's preliminary finding that the "new entrant rules" may be unjust and unreasonable, specifically as it

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relates to the seven-year price-lock rule. This order is a result of the D.C. Circuit February 2, 2018 remand of a FERC order regarding how generators that previously received a seven-year "price lock" should be priced in future auctions. The price-lock mechanism permits qualified new resources that clear the auction to receive their first-year clearing price for seven years. Because several auctions have been held under the existing rules, any subsequent order from FERC could affect future capacity prices in ISO-NE, as well as affect the price that non-price locked resources could receive from prior capacity auctions.

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 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. 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 at least 50% greater than the prevailing NY Renewable Energy Standard for load serving entities. The 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 stay of the Order. On March 2, 2020, the NYSPSC issued a notice seeking comments by April 13, 2020 on the petitions for rehearing. NRG has been granted multiple extensions, resulting in the current effective date of October 9, 2020 to meet the compliance requirements for its retail products. 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 NYSPSC has engaged The Brattle Group to evaluate the multiple alternative resource adequacy structures that were recommended by the parties in the proceeding. The NYSPSC held a technical conference on July 10, 2020. The proceeding is pending. Any actions taken by the NYSPSC could affect market design and market prices in New York.

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. On July 16, 2020, FERC accepted a large part of NYISO's April compliance filing. 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. On June 18, 2020, the NYSPSC filed petitions for review with the D.C. Circuit regarding these buyer side mitigation orders. 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 was put into effect on March 1, 2020. To date, the ORDC reforms have produced a noticeable improvement in scarcity pricing.

Public Utility 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 the end of August 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

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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. The late fees waiver ended on May 15, 2020.

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 proposed decision on April 15, 2020. On June 11, 2020, the CPUC adopted the decision mandating the central procurement of multi-year local resource adequacy capacity to begin for the 2023 compliance year for PG&E and SCE service areas. The CPUC also rejected the proposed settlement filed by various entities, including NRG. The CPUC decision represents a retreat from market-based solutions ensuring reliable capacity in California.

Environmental Regulatory Matters

NRG is subject to numerous environmental laws in the development, construction, ownership and operation of 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 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 the Company from complying with certain of its 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 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 2019 Form 10-K in Item 1, Business - Environmental Matters and Item 1A, Risk Factors. These matters have been updated in Note 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.

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.

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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. On July 29, 2020, the EPA released a prepublication (non-official) version of the final rule "A Holistic Approach to Closure Part A: Deadline to Initiate Closure," which when published in the Federal Register will amend the April 2015 Rule to address the August 2018 D.C. Circuit decision and extend some of the deadlines. The Company anticipates that the EPA will promulgate additional regulations to further amend the existing rule. The Company will update estimates of required environmental capital expenditures as 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 16, 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 has been extended twice through addendums to cover payments through December 31, 2019. The Department of Justice has proposed to extend the existing settlement for three additional years through December 31, 2022. STPNOC has agreed to this proposal and steps to obtain approval of the settlement by the authorized representative of the Attorney General are in progress. 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.

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 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 was anticipated. The Company will revisit these estimates after the EPA revises the rule and as permits are renewed.

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Regional Environmental Developments

NY NOx — On December 31, 2019, the New York State Department of Environmental Conservation finalized a more stringent NOx regulation that will result in the retirement of the Company's combustion turbines in Astoria, New 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 at surface impoundments. On March 30, 2020, the state released its proposed implementing regulations. The Company expects the state to promulgate the final implementing regulations in March 2021, at which time regulated entities will then prepare and submit permit applications.

Significant Events

The following significant events have occurred during 2020 as further described within this Management's Discussion and Analysis and the Condensed Consolidated Financial Statements:

Direct Energy Acquisition

On July 24, 2020, the Company entered into a definitive purchase agreement with Centrica to acquire Direct Energy, a North American subsidiary of Centrica (the "Purchase Agreement"). Direct Energy is a leading retail provider of electricity, natural gas, and home and business energy related products and services in North America, with operations in all 50 U.S. states and 6 Canadian provinces. The acquisition will add over 3 million customers to NRG's business and build on and complement its integrated model, enabling better matching of power generation with customer demand. It will also broaden the Company's presence in the Northeast and into states and locales where it does not currently operate, supporting NRG's objective to diversify its business.

The Company will pay an aggregate purchase price of $3.6 billion in cash, subject to a purchase price adjustment, including a working capital adjustment. The Company expects to fund the purchase price using a combination of cash on hand, approximately $2.4 billion in newly-issued secured and unsecured corporate debt and approximately $750 million in convertible preferred stock or other equity-linked instruments. The Company also expects to increase its collective collateral facilities by $3.5 billion through a combination of new letter of credit facilities and increase to the existing Revolving Credit Facility.

The acquisition is subject to approval by the shareholders of Centrica, as well as customary closing conditions, consents and regulatory approvals, including the expiration or termination of the applicable waiting period under the HSR Act, and the receipt of approvals or expiration of applicable waiting periods under the Federal Power Act and the Canadian Competition Act.

The acquisition is targeted to close by December 31, 2020. There are no assurances that the conditions to the consummation of the acquisition of Direct Energy will be satisfied, that Centrica will not seek or enter into an alternative transaction, or that the acquisition of Direct Energy will be consummated on the terms agreed to, or at all.

Share Repurchases

During the six months ended June 30, 2020, the Company completed $224 million of share repurchases at an average price of $33.05 per share, including $27 million of equivalent shares purchased in lieu of tax withholdings on equity compensation issuance.

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 June 30, 2020, NRG has entered into PPAs totaling approximately 1,600 MWs with third-party project developers and other counterparties. The tenor of these agreements is an average of eleven years. The Company expects to continue evaluating and executing similar agreements that support the needs of the business.

COVID-19

For discussion of COVID-19 related considerations, refer to Management’s Discussion and Analysis of Financial Condition and Results of Operations – Executive Summary and Liquidity and Capital Resources.

Midwest Generation Lease Purchase

On July 22, 2020, Midwest Generation signed purchase agreements to acquire all of the ownership interests in the Powerton facility and Units 7 and 8 of the Joliet facility, which were being leased through 2034 and 2030, respectively, for approximately $260 million. The Company intends to fund the purchase with borrowings under its Revolving Credit Facility in an amount equal to the existing operating lease liabilities of $148 million as of June 30, 2020 and the remainder from cash-on-hand. The closing is conditioned, among other items, on the receipt of regulatory approvals from FERC and under the HSR Act. Upon closing, lease expense related to these facilities, which totaled approximately $14 million in 2019, will be eliminated.

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Trends Affecting Results of Operations and Future Business Performance

The Company’s trends are described in the Company’s 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, for a discussion of recent accounting developments.

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Consolidated Results of Operations

The following table provides selected financial information for the Company:

	Three months ended June 30,							Six months ended June 30,
(In millions, except as otherwise noted)	2020		2019		Change			2020		2019		Change
Operating Revenues
Retail revenue	$	1,832	$	1,685	$	147		$	3,493	$	3,274	$	219
Energy revenue(a)	83		236		(153)			207		526		(319)
Capacity revenue(a)	195		201		(6)			344		357		(13)
Mark-to-market for economic hedging activities	43		241		(198)			39		261		(222)
Other revenues (a)(b)	85		102		(17)			174		212		(38)
Total operating revenues	2,238		2,465		(227)			4,257		4,630		(373)
Operating Costs and Expenses
Cost of Sales (c)	1,135		1,273		138			2,284		2,614		330
Mark-to-market for economic hedging activities	(44)		220		264			(92)		220		312
Contract and emissions credit amortization (c)	1		6		5			2		11		9
Operations and maintenance	279		284		5			572		531		(41)
Other cost of operations	63		62		(1)			125		120		(5)
Total cost of operations	1,434		1,845		411			2,891		3,496		605
Depreciation and amortization	110		85		(25)			219		170		(49)
Impairment losses	—		1		1			—		1		1
Selling, general and administrative costs	208		211		3			417		405		(12)
Reorganization costs	—		2		2			3		15		12
Development costs	2		2		—			5		4		(1)
Total operating costs and expenses	1,754		2,146		392			3,535		4,091		556
Gain on sale of assets	—		1		(1)			6		2		4
Operating Income	484		320		164			728		541		187
Other Income/(Expense)
Equity in earnings/(losses) of unconsolidated affiliates	12		—		12			1		(21)		22
Impairment losses on investments	—		—		—			(18)		—		(18)
Other income, net	14		20		(6)			41		32		9
Loss on debt extinguishment, net	—		(47)		47			(1)		(47)		46
Interest expense	(96)		(105)		9			(193)		(219)		26
Total other expense	(70)		(132)		62			(170)		(255)		85
Income from Continuing Operations Before Income Taxes	414		188		226			558		286		272
Income tax expense/(benefit)	101		(1)		(102)			124		3		(121)
Income from Continuing Operations	313		189		124			434		283		151
Income from discontinued operations, net of income tax	—		13		(13)			—		401		(401)
Net Income	313		202		111			434		684		(250)
Less: Net income attributable to redeemable noncontrolling interests	—		1		(1)			—		1		(1)
Net Income Attributable to NRG Energy, Inc.	$	313	$	201	$	112		$	434	$	683	$	(249)
Business Metrics
Average natural gas price — Henry Hub ($/MMBtu)	$	1.72	$	2.64	(35)		%	$	1.83	$	2.89	(37)		%

(a) Includes gains and losses from financially settled transactions

(b) Includes trading gains and losses

(c) Includes amortization of SO₂ and NO_x credits and excludes amortization of RGGI credits  

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Management’s discussion of the results of operations for the three months ended June 30, 2020 and 2019

Electricity Prices

The following table summarizes average on peak power prices for each of the major markets in which NRG operates for the three months ended June 30, 2020 and 2019. The average on-peak power prices decreased across all regions due to mild winter weather and lower demand due to COVID-19.

	Average on Peak Power Price ($/MWh)
	Three months ended June 30,
Region	2020		2019		Change %
Texas
ERCOT - Houston(a)	$	24.34	$	31.88	(24)	%
ERCOT - North(a)	20.03		30.13		(34)	%
East
NY J/NYC(b)	$	19.01	$	29.52	(36)	%
NEPOOL(b)	20.25		27.15		(25)	%
COMED (PJM)(b)	19.28		26.78		(28)	%
PJM West Hub(b)	20.79		28.54		(27)	%
West
MISO - Louisiana Hub(b)	$	22.06	$	33.40	(34)	%
CAISO - SP15(b)	19.21		23.30		(18)	%

^(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 NRG, including the impact of settled hedges, for the three months ended June 30, 2020 and 2019:

	Average Realized Power Price ($/MWh)
	Three months ended June 30,
Region	2020		2019		Change %
East(a)	$	28.41	$	31.91	(11)	%
West/Other	27.45		33.29		(18)	%

^(a)Average Realized Power Price reflects energy sales from the generation fleet, omitting sales to the retail component of the East Segment. Intercompany financial transactions hedging generation with the retail business make up $12.99/MWh in the three months ended June 30, 2020 and $5.95/MWh in the three months ended June 30, 2019 

The average realized power prices decreased for the three months ended June 30, 2020 as compared to the same period in 2019 due to lower power 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.

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The below tables present the composition and reconciliation of gross margin and economic gross margin for the three months ended June 30, 2020 and 2019:

	Three months ended June 30, 2020
($ In millions)	Texas		East		West/Other		Corporate/Eliminations		Total
Retail revenue	$	1,521	$	311	$	—	$	—	$	1,832
Energy revenue	5		19		60		(1)		83
Capacity revenue	—		179		16		—		195
Mark-to-market for economic hedging activities	—		40		1		2		43
Other revenue	52		17		17		(1)		85
Operating revenue	1,578		566		94		—		2,238
Cost of fuel	(123)		(19)		(30)		—		(172)
Purchased power	(203)		(97)		(3)		3		(300)
Other cost of sales(a)(b)	(554)		(98)		(10)		(1)		(663)
Mark-to-market for economic hedging activities	41		5		—		(2)		44
Contract and emission credit amortization	(1)		—		—		—		(1)
Gross margin	$	738	$	357	$	51	$	—	$	1,146
Less: Mark-to-market for economic hedging activities, net	41		45		1		—		87
Less: Contract and emission credit amortization, net	(1)		—		—		—		(1)
Economic gross margin	$	698	$	312	$	50	$	—	$	1,060
(a) Includes capacity and emissions credits
(b) Includes $485 million and $3 million of TDSP expense in Texas and East, respectively
Business Metrics
Mass Market electricity sales volume (GWh)	9,763		2,355		—				12,118
C&I electricity sales volume (GWh)	4,213		365		—				4,578
Natural gas sales volume (MDth)	—		3,591		—				3,591
Average retail Mass Market customer count (in thousands)	2,442		1,190		—				3,632
Ending retail Mass Market customer count (in thousands)	2,447		1,171		—				3,618
GWh sold	7,565		1,232		2,186				10,983
GWh generated:(a)
Coal	3,777		59		—				3,836
Gas	1,341		479		2,246				4,066
Nuclear	2,260		—		—				2,260
Oil	—		66		—				66
Total	7,378		604		2,246				10,228
(a) Includes owned and leased generation, and excludes equity investments

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	Three months ended June 30, 2019
($ In millions)	Texas		East		West/Other		Corporate/Eliminations		Total
Retail revenue	$	1,433	$	253	$	—	$	(1)	$	1,685
Energy revenue	136		48		52		—		236
Capacity revenue	—		195		6		—		201
Mark-to-market for economic hedging activities	210		16		16		(1)		241
Other revenue	58		12		32		—		102
Operating revenue	1,837		524		106		(2)		2,465
Cost of fuel	(200)		(34)		(32)		—		(266)
Purchased power	(301)		(108)		(2)		—		(411)
Other cost of sales(a)(b)	(500)		(90)		(6)		—		(596)
Mark-to-market for economic hedging activities	(216)		(2)		(3)		1		(220)
Contract and emission credit amortization	(6)		—		—		—		(6)
Gross margin	$	614	$	290	$	63	$	(1)	$	966
Less: Mark-to-market for economic hedging activities, net	(6)		14		13		—		21
Less: Contract and emission credit amortization, net	(6)		—		—		—		(6)
Economic gross margin	$	626	$	276	$	50	$	(1)	$	951
(a) Includes capacity and emissions credits
(b) Includes $443 million and $2 million of TDSP expense in Texas and East, respectively
Business Metrics
Mass Market electricity sales volume (GWh)	9,129		1,913		—				11,042
C&I electricity sales volume (GWh)	4,720		288		—				5,008
Natural gas sales volume (MDth)	—		3,054		—				3,054
Average retail Mass Market customer count (in thousands)	2,269		1,029		—				3,298
Ending retail Mass Market customer count (in thousands)	2,239		1,038		—				3,277
GWh sold	11,401		1,849		1,562				14,812
GWh generated:(a)
Coal	6,403		479		—				6,882
Gas	1,720		472		1,568				3,760
Nuclear	2,522		—		—				2,522
Oil	—		14		—				14
Renewables	—		—		2				2
Total	10,645		965		1,570				13,180
(a) Includes owned and leased generation, and excludes equity investments

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The table below represents the weather metrics for the three months ended June 30, 2020 and 2019:

	Three months ended June 30,
Weather Metrics	Texas	East	West/Other (b)
2020
CDDs (a)	1,012	353	562
HDDs (a)	70	634	178
2019
CDDs	934	348	513
HDDs	70	465	192
10-year average
CDDs	1,002	361	552
HDDs	60	501	206

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

(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

Gross margin increased $180 million and economic gross margin increased $109 million, both of which include intercompany sales, during the three months ended June 30, 2020, compared to the same period in 2019.

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

Texas

	(In millions)
Higher gross margin primarily due to lower costs to serve the retail load, driven by a reduction of power and fuel prices resulting from lower natural gas prices	$	100
Higher gross margin from higher retail net revenue of $91 million, due to increased volumes from the acquisition of Stream in August 2019, higher net revenue rates of $23 million, or $2.50 per MWh, driven by customer term, product and mix, and increased load of 256,000 MWhs from favorable weather of $21 million, partially offset by a decrease of $87 million due to attrition and customer mix	48
Lower gross margin due to a decrease in net sales of generation to third parties, as the supply was fully utilized to serve the Company's retail load in 2020	(67)
Lower gross margin from market optimization activities	(8)
Other	(1)
Increase in economic gross margin	$	72
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	47
Increase in contract and emission credit amortization	5
Increase in gross margin	$	124

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East

	(In millions)
Higher gross margin due to higher revenues of approximately $10 million, or $4.50 per MWh, and lower supply costs driven by lower electricity and natural gas prices of approximately $8 million, or $3.50 per MWh	$	18
Higher gross margin driven by a 42% increase in New York realized capacity prices	12
Higher gross margin due to increased volumes from the acquisition of Stream Energy in August 2019	11
Higher gross margin from market optimization activities	4
Lower gross margin due to a 25% decrease in New England capacity prices	(10)
Other	1
Increase in economic gross margin	$	36
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	31
Increase in gross margin	$	67

West/Other

	(In millions)
Higher gross margin driven by increased California resource adequacy pricing	$	10
Higher gross margin due to spark spread expansion at Cottonwood	6
Lower gross margin due to the Canal 3 substantial completion payment earned in 2019	(8)
Lower gross margin from market optimization activities	(7)
Other	(1)
Economic gross margin	$	—
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(12)
Decrease in gross margin	$	(12)

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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 $66 million during the three months ended June 30, 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 June 30, 2020
(In millions)	Texas		East		West/Other		Eliminations		Total
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(1)	$	18	$	—	$	1	$	18
Net unrealized gains on open positions related to economic hedges	1		22		1		1		25
Total mark-to-market gains in operating revenues	$	—	$	40	$	1	$	2	$	43
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	14	$	—	$	(1)	$	(1)	$	12
Reversal of acquired loss positions related to economic hedges	2		1		—		—		3
Net unrealized gains on open positions related to economic hedges	25		4		1		(1)		29
Total mark-to-market gains in operating costs and expenses	$	41	$	5	$	—	$	(2)	$	44

	Three months ended June 30, 2019
(In millions)	Texas		East		West/Other		Eliminations		Total
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(13)	$	12	$	1	$	—	$	—
Net unrealized gains on open positions related to economic hedges	223		4		15		(1)		241
Total mark-to-market gains in operating revenues	$	210	$	16	$	16	$	(1)	$	241
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	12	$	(1)	$	—	$	—	$	11
Reversal of acquired loss positions related to economic hedges	—		1		—		—		1
Net unrealized (losses) on open positions related to economic hedges	(228)		(2)		(3)		1		(232)
Total mark-to-market (losses) in operating costs and expenses	$	(216)	$	(2)	$	(3)	$	1	$	(220)

`

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

For the three months ended June 30, 2020, the $43 million gain in operating revenues from economic hedge positions was driven primarily by an increase in the value of open positions as a result of decreases in New York capacity prices, as well as the reversal of previously recognized unrealized losses on contracts that settled during the period. The $44 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 increases in ERCOT power prices, as well as the reversal of previously recognized unrealized losses on contracts that settled during the period.

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

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In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the three months ended June 30, 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 June 30,
(In millions)	2020		2019
Trading gains/(losses)
Realized	$	16	$	15
Unrealized	(1)		12
Total trading gains	$	15	$	27

Operations and Maintenance Expense

Operations and maintenance expense are comprised of the following:

(In millions)	Texas		East		West/Other		Corporate		Eliminations		Total
Three months ended June 30, 2020	$	158	$	94	$	26	$	2	$	(1)	$	279
Three months ended June 30, 2019	152		101		32		1		(2)		284

Operations and maintenance expense decreased by $5 million for the three months ended June 30, 2020, compared to the same period in 2019, due to the following:

	(In millions)
Decrease in deactivation costs primarily due to work done at Midwest Generation in 2019	$	(10)
Decrease due to return to service costs at Gregory in June 2019	(7)
Decrease in variable chemical costs due to a reduction in East generation volumes	(4)
Increase in outages primarily due to planned outages at Midwest Generation in 2020 of $4 million, as well as incremental expenses of $4 million related to COVID-19	8
Increase due to the acquisition of Stream Energy in August 2019	3
Other	5
Decrease in operations and maintenance expense	$	(5)

Other Cost of Operations

Other cost of operations are comprised of the following:

(In millions)	Texas		East		West/Other		Total
Three months ended June 30, 2020	$	38	$	21	$	4	$	63
Three months ended June 30, 2019	37		20		5		62

Other costs of operations increased $1 million for the three months ended June 30, 2020, compared to the same period in 2019, due to an increase in gross revenue tax due to the acquisition of Stream Energy in August 2019.

Depreciation and Amortization

Depreciation and amortization are comprised of the following:

(In millions)	Texas		East		West/Other		Corporate		Total
Three months ended June 30, 2020	$	59	$	33	$	8	$	10	$	110
Three months ended June 30, 2019	40		30		7		8		85

Depreciation and amortization increased by $25 million, primarily due to the acquisition of Stream Energy in August 2019.

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Selling, General and Administrative Costs

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

(In millions)	Texas		East		West/Other		Corporate		Total
Three months ended June 30, 2020	$	131	$	62	$	7	$	8	$	208
Three months ended June 30, 2019	121		75		10		5		211

Selling, general and administrative costs decreased by $3 million for the three months ended June 30, 2020, compared to the same period in 2019, due to the following:

	(In millions)
Decrease in corporate and legal litigation accruals	$	(10)
Decrease in bad debt expense primarily due to a one-time provision in 2019, partially offset by increase due to the acquisition of Stream Energy and the impact of COVID-19	(4)
Increase due to the acquisition of Stream Energy in August 2019	9
Increase in amortization of commissions	4
Other	(2)
Decrease in selling, general and administrative costs	$	(3)

Reorganization Costs

Reorganization costs, primarily related to employee severance and contract cancellation costs, decreased by $2 million for the three months ended June 30, 2020, compared to the same period in 2019, driven by significant achievement of the operations and cost excellence portion of the Transformation Plan during 2019.

Other Income, Net

Other income, net decreased by $6 million for the three months ended June 30, 2020, compared to the same period in 2019, primarily due to decreases in interest income and dividends received from cost method investments in 2020, partially offset by an increase in pension and postretirement income.

Loss on Debt Extinguishment

A loss on debt extinguishment of $47 million was recorded during the three months ended June 30, 2019, driven by the redemption of the 2024 Senior Notes and the repayment of the 2023 Term Loan Facility.

Interest Expense

Interest expense decreased by $9 million for the three months ended June 30, 2020, compared to the same period in 2019, primarily due to the debt reduction of $600 million and refinancing of $1.8 billion at lower interest rates in 2019.

Income Tax Expense/(Benefit)

For the three months ended June 30, 2020, income tax expense of $101 million was recorded on pre-tax income of $414 million. For the same period in 2019, an income tax benefit of $1 million was recorded on pre-tax income of $188 million. The effective tax rates were 24.4% and (0.5)% for the three months ended June 30, 2020 and 2019, respectively.

For the three months ended June 30, 2020, the effective tax rate was higher than the statutory rate of 21%, due to state tax expense partially offset by an excess tax benefit related to share-based compensation. For the same period in 2019, the effective tax rates was lower than the statutory rate of 21%, primarily due to the tax benefit for the change in valuation allowance, partially offset by state tax expense.

Income from Discontinued Operations, Net of Income Tax

(In millions)	Three months ended June 30, 2019
South Central Portfolio	$	1
Carlsbad	10
GenOn	2
Income from discontinued operations, net of tax	$	13

For the three months ended June 30, 2019, NRG recorded income from discontinued operations, net of income tax of $13 million, as further described in Note 4, Acquisitions, Discontinued Operations and Dispositions.

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Management’s discussion of the results of operations for the six months ended June 30, 2020 and 2019

Electricity Prices

The following table summarizes average on peak power prices for each of the major markets in which NRG operates for the six months ended June 30, 2020 and 2019. The average on-peak power prices decreased due to mild winter weather and lower demand due to COVID-19.

	Average on Peak Power Price ($/MWh)
	Six months ended June 30,
Region	2020		2019		Change %
Texas
ERCOT - Houston (a)	$	24.84	$	30.04	(17)	%
ERCOT - North(a)	22.23		29.08		(24)	%
East
NY J/NYC(b)	21.42		37.34		(43)	%
NEPOOL(b)	22.43		37.28		(40)	%
COMED (PJM)(b)	20.29		28.44		(29)	%
PJM West Hub(b)	21.63		31.17		(31)	%
West
MISO - Louisiana Hub(b)	22.10		33.12		(33)	%
CAISO - SP15(b)	23.93		36.86		(35)	%

(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 NRG, including the impact of settled hedges, for the six months ended June 30, 2020 and 2019:

	Average Realized Power Price ($/MWh)
	Six months ended June 30,
Region	2020		2019		Change %
East(a)	$	36.63	$	36.57	—	%
West/Other	28.45		31.41		(9)	%

^(a) Average Realized Power Price reflects energy sales from the generation fleet, omitting sales to the retail component of the East Segment. Intercompany financial transactions hedging generation with the retail business make up $19.64/MWh in the six months ended June 30, 2020 and $6.84/MWh in the six months ended June 30, 2019 

The average realized power prices were flat in the East region for the six months ended June 30, 2020 as compared to the same period in 2019 due to the Company's hedged positions. The average realized power prices decreased in the West/Other region due to lower power 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.

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The below tables present the composition and reconciliation of gross margin and economic gross margin for the six months ended June 30, 2020 and 2019:

	Six months ended June 30, 2020
($ In millions)	Texas		East		West/Other		Corporate/Eliminations		Total
Retail revenue	$	2,813	$	681	$	—	$	(1)	$	3,493
Energy revenue	10		64		135		(2)		207
Capacity revenue	—		313		31		—		344
Mark-to-market for economic hedging activities	—		20		16		3		39
Other revenue	113		27		37		(3)		174
Operating revenue	2,936		1,105		219		(3)		4,257
Cost of fuel	(226)		(74)		(66)		—		(366)
Purchased power	(468)		(249)		(9)		3		(723)
Other cost of sales (a) (b)	(1,016)		(189)		10		—		(1,195)
Mark-to-market for economic hedging activities	90		5		—		(3)		92
Contract and emission credit amortization	(2)		—		—		—		(2)
Gross margin	$	1,314	$	598	$	154	$	(3)	$	2,063
Less: Mark-to-market for economic hedging activities, net	90		25		16		—		131
Less: Contract and emission credit amortization, net	(2)		—		—		—		(2)
Economic gross margin	$	1,226	$	573	$	138	$	(3)	$	1,934
(a)Includes capacity and emission credits
(b)Includes $914 million and $5 million of TDSP expense in Texas and East, respectively
Business Metrics
Mass Market electricity sales volume (GWh)	17,511		4,903		—				22,414
C&I electricity sales volume (GWh)	8,669		754		—				9,423
Natural gas sales volume (MDth)	—		14,100		—				14,100
Average retail Mass Market customer count (in thousands)	2,443		1,205		—				3,648
Ending retail Mass Market customer count (in thousands)	2,447		1,171		—				3,618
GWh sold	13,574		3,767		4,745				22,086
GWh generated (a)
Coal	6,837		394		—				7,231
Gas	2,015		628		4,601				7,244
Nuclear	4,562		—		—				4,562
Oil	—		84		—				84
Total	13,414		1,106		4,601				19,121
(a) Includes owned and leased generation, and excludes equity investments

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	Six months ended June 30, 2019
($ In millions)	Texas		East		West/Other		Corporate/Eliminations		Total
Retail revenue	$	2,686	$	591	$	—	$	(3)	$	3,274
Energy revenue	241		174		110		1		526
Capacity revenue	—		339		18		—		357
Mark-to-market for economic hedging activities	241		1		20		(1)		261
Other revenue	135		28		51		(2)		212
Operating revenue	3,303		1,133		199		(5)		4,630
Cost of fuel	(349)		(100)		(68)		—		(517)
Purchased Power	(628)		(299)		(2)		—		(929)
Other cost of sales (a) (b)	(986)		(165)		(17)		—		(1,168)
Mark-to-market for economic hedging activities	(221)		1		(1)		1		(220)
Contract and emission credit amortization	(11)		—		—		—		(11)
Gross margin	$	1,108	$	570	$	111	$	(4)	$	1,785
Less: Mark-to-market for economic hedging activities, net	20		2		19		—		41
Less: Contract and emission credit amortization, net	(11)		—		—		—		(11)
Economic gross margin	$	1,099	$	568	$	92	$	(4)	$	1,755
(a) Includes capacity and emissions credits
(b) Includes $865 million and $5 million of TDSP expense in Texas and East, respectively
Business Metrics
Mass Market electricity sales voldume (GWh)	17,119		4,407		—				21,526
C&I electricity sales volume (GWh)	9,269		570		—				9,839
Natural gas sales volume (MDth)	—		13,601		—				13,601
Average retail Mass Market customer count (in thousands)	2,288		1,029		—				3,317
Ending retail Mass Market customer count (in thousands)	2,239		1,038		—				3,277
GWh sold	20,329		5,852		3,502				29,683
GWh generated (a)
Coal	11,010		2,805		—				13,815
Gas	2,209		623		3,500				6,332
Nuclear	5,060		—		—				5,060
Oil	—		19		—				19
Renewables	—		—		10				10
Total	18,279		3,447		3,510				25,236
(a) Includes owned and leased generation, and excludes equity investments

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The table below represents the weather metrics for the six months ended June 30, 2020 and 2019:

	Six months ended June 30,
Weather Metrics	Texas	East	West/Other (b)
2020
CDDs (a)	1,182	409	638
HDDs (a)	861	2,679	1,172
2019
CDDs	1,008	382	544
HDDs	1,111	2,922	1,384
10-year average
CDDs	1,106	396	598
HDDs	1,055	2,959	1,316

(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 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

Gross margin increased $278 million and economic gross margin increased $179 million, both of which include intercompany sales, during the six months ended June 30, 2020, compared to the same period in 2019.

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

Texas

	(In millions)
Higher gross margin primarily due to lower costs to serve the retail load, driven by a reduction of power and fuel prices due to lower natural gas prices	$	158
Higher gross margin from increased net revenue rates of $168 million due to increased volumes from the acquisition of Stream Energy in August 2019, and higher net revenue rates of $51 million, or $2.50 per MWh, driven by customer term, product and mix, partially offset by $140 million due to attrition and customer mix	79
Lower gross margin from net sales of generation to third parties, as the supply was fully utilized to serve the Company's retail load in 2020	(86)
Lower gross margin from market optimization activities	(14)
Lower gross margin due to the sale of emissions in 2019	(13)
Other	3
Increase in economic gross margin	$	127
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	70
Increase in contract and emission credit amortization	9
Increase in gross margin	$	206

76

East

	(In millions)
Higher gross margin due to lower supply costs of $31 million driven by lower electricity prices of approximately $6 per MWh and lower natural gas prices, partially offset by lower revenues of approximately $2 million, or $0.25 per MWh	$	29
Higher gross margin due to increased volumes from the acquisition of Stream Energy in August 2019	25
Higher gross margin due to lower supply costs coupled with an increase in load contract volumes	21
Higher gross margin driven by a 43% increase in New York realized capacity prices	17
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 68% decrease in economic generation volumes primarily due to dark spread contractions and planned outages	(20)
Lower gross margin due to a 25% decrease in New England capacity prices	(20)
Lower gross margin due to a 7% decrease in PJM capacity prices	(11)
Lower gross margin from market optimization activities	(6)
Other	(1)
Increase in economic gross margin	$	5
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 gross margin	$	28

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 driven by increased California resource adequacy pricing and lower capacity purchases due to the 2019 Sunrise outage	18
Higher gross margin due to spark spread expansion at Cottonwood	11
Higher gross margin due to an extended forced outage at the Sunrise facility in 2019	9
Lower gross margin from market optimization activities	(11)
Lower gross margin due to the Canal 3 substantial completion payment earned in 2019	(8)
Other	(3)
Increase in economic gross margin	$	46
Decrease to mark-to-market for economic hedges primarily due to net unrealized gains/losses on open positions related to economic hedges	(3)
Increase in gross margin	$	43

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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 $90 million during the six months ended June 30, 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:

	Six months ended June 30, 2020
(In millions)	Texas		East		West/Other		Eliminations		Total
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(1)	$	4	$	(5)	$	2	$	—
Net unrealized gains on open positions related to economic hedges	1		16		21		1		39
Total mark-to-market gains in operating revenues	$	—	$	20	$	16	$	3	$	39
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	36	$	6	$	(1)	$	(2)	$	39
Reversal of acquired loss positions related to economic hedges	4		—		—		—		4
Net unrealized gains/(losses) on open positions related to economic hedges	50		(1)		1		(1)		49
Total mark-to-market gains in operating costs and expenses	$	90	$	5	$	—	$	(3)	$	92

	Six months ended June 30, 2019
(In millions)	Texas		East		West/Other		Eliminations		Total
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(2)	$	(8)	$	2	$	—	$	(8)
Net unrealized gains on open positions related to economic hedges	243		9		18		(1)		269
Total mark-to-market gains in operating revenues	$	241	$	1	$	20	$	(1)	$	261
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	35	$	4	$	(1)	$	—	$	38
Reversal of acquired (gain) positions related to economic hedges	—		(1)		—		—		(1)
Net unrealized (losses) on open positions related to economic hedges	(256)		(2)		—		1		(257)
Total mark-to-market (losses)/gains in operating costs and expenses	$	(221)	$	1	$	(1)	$	1	$	(220)

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

For the six months ended June 30, 2020, the $39 million gain in operating revenues from economic hedge positions was driven by an increase in the value of open positions as a result of decreases in New York capacity, New York power, and West/Other power prices. The $92 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 increases in outer year ERCOT power prices, as well as the reversal of previously recognized unrealized losses on contracts that settled during the period.

For the six months ended June 30, 2019, the $261 million gain in operating revenues from economic hedge positions was driven primarily by an increase in value of open positions as a result of decreases in natural gas prices, ERCOT heat rate contraction, and decreases in ERCOT power prices, partially offset by the reversal of previously recognized unrealized gains on contracts that settled during the period. The $220 million loss in operating costs and expenses from economic hedge positions was driven primarily by a decrease in the value of open positions as a result of decreases in natural gas prices, ERCOT heat rate contraction, and decreases in ERCOT power prices, partially offset by the reversal of previously recognized unrealized losses on contracts that settled during the period.

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

	Six months ended June 30,
(In millions)	2020		2019
Trading gains
Realized	$	23	$	31
Unrealized	10		19
Total trading gains	$	33	$	50

Operations and Maintenance Expense

Operations and maintenance expense are comprised of the following:

(In millions)	Texas		East		West/Other		Corporate		Eliminations		Total
Six months ended June 30, 2020	$	333	$	182	$	56	$	4	$	(3)	$	572
Six months ended June 30, 2019	303		167		60		4		(3)		531

Operations and maintenance expense increased by $41 million for the six months ended June 30, 2020, compared to the same period in 2019, due to the following:

	(In millions)
Increase in outages primarily due to planned outages at STP and Midwest Generation in 2020 of $28 million, as well as incremental expenses of $3 million related to COVID-19	$	31
Increase due to settlement of the asbestos liability for Midwest Generation and the resulting reduction of the accrual in 2019	27
Increase due to the Stream Energy acquisition in August 2019	12
Decrease in variable chemical costs due to a reduction in East generation volumes partially offset by an increase at Sunrise in 2020 as a result of higher volumes	(13)
Decrease in deactivation costs primarily due to work done at Midwest Generation and Encina in 2019	(12)
Decrease due to return to service costs at Gregory in June 2019	(7)
Other	3
Increase in operations and maintenance expense	$	41

Other Cost of Operations

Other Cost of operations are comprised of the following:

(In millions)	Texas		East		West/Other		Total
Six months ended June 30, 2020	$	71	$	47	$	7	$	125
Six months ended June 30, 2019	70		41		9		120

Other cost of operations increased by $5 million for the six months ended June 30, 2020, compared to the same period in 2019, due to the following:

	(In millions)
Increase in ARO expense at the Joliet plant as a result of regulatory requirements	$	5
Increase in gross revenue tax due to the acquisition of Stream Energy in August 2019	2
Other	(2)
Increase in other cost of operations	$	5

79

Depreciation and Amortization

Depreciation and amortization expenses are comprised of the following:

(In millions)	Texas		East		West/Other		Corporate		Total
Six months ended June 30, 2020	$	118	$	66	$	16	$	19	$	219
Six months ended June 30, 2019	80		56		18		16		170

Depreciation and amortization increased by $49 million for the six months ended June 30, 2020, compared to the same period in 2019, driven primarily by the acquisition of Stream Energy in August 2019.

Selling, General and Administrative Costs

Selling, general and administrative costs comprised of the following:

(In millions)	Texas		East		West/Other		Corporate		Total
Six months ended June 30, 2020	$	261	$	126	$	16	$	14	$	417
Six months ended June 30, 2019	238		140		17		10		405

Selling, general and administrative costs increased by $12 million for the six months ended June 30, 2020, compared to the same period in 2019, due to the following:

	(In millions)
Increase due to the acquisition of Stream Energy in August 2020	$	19
Increase due to higher amortization of commissions	9
Decrease in selling and marketing spend due to the impact of COVID-19	(7)
Decrease in legal litigation accruals	(6)
Decrease in bad debt expense primarily due to a one-time provision in 2019, partially offset by increases due to the acquisition of Stream Energy and the impact of COVID-19	(4)
Other	1
Increase in selling, general and administrative costs	$	12

Reorganization Costs  

Reorganization costs, primarily related to employee severance and contract cancellation costs, decreased by $12 million for the six months ended June 30, 2020, compared to the same period in 2019, driven by significant achievement of the operations and cost excellence portion of the Transformation Plan during 2019.

Gain on Sale of Assets

The gain on sale of assets of $6 million for the six months ended June 30, 2020 is related to the sale of land and investments in January 2020.

Equity in Earnings/ Losses of Unconsolidated Affiliates

Equity in losses of unconsolidated affiliates was $21 million for the six months ended June 30, 2019, primarily driven by losses for Ivanpah.

Impairment losses on investments

Impairment losses on investments of $18 million were recorded during the six months ended June 30, 2020, related to Petra Nova Parish Holdings, as further discussed in Note 8, Impairments.

Other Income, Net

Other income increased by $9 million for the six months ended June 30, 2020, compared to the same period in 2019, driven primarily by income from insurance proceeds received of $11 million in 2020 and an increase in pension and postretirement income, partially offset by decreases in interest income and dividends received from cost method investments in 2020.

Loss on Debt Extinguishment

A loss on debt extinguishment of $47 million was recorded during the six months ended June 30, 2019, driven by the redemption of the 2024 Senior Notes and the repayment of the 2023 Term Loan Facility.

80

Interest Expense

Interest expense decreased by $26 million for the six months ended June 30, 2020, compared to the same period in 2019, due to the following:

	(In millions)
Decrease related to the debt reduction of $600 million and refinancing $1.8 billion of debt at lower interest rates in 2019	$	(14)
Decrease in derivative interest expense due to the termination of interest rate swaps in 2019	(8)
Other	(4)
Decrease in interest expense	$	(26)

Income Tax Expense

For the six months ended June 30, 2020, income tax expense of $124 million was recorded on pre-tax income of $558 million. For the same period in 2019, income tax expense of $3 million was recorded on a pre-tax income of $286 million. The effective tax rates were 22.2% and 1.0% for the six months ended June 30, 2020 and 2019, respectively.

For the six months ended June 30, 2020, NRG's overall effective tax rate was higher than the statutory rate of 21% due to state tax expense partially offset by an excess tax benefit related to share-based compensation. For the same period in 2019, NRG's overall effective tax rate was lower that the statutory rate of 21% primarily due to the change in valuation allowance partially offset by the current state tax expense.

Income from Discontinued Operations, Net of Income Tax

	Six months ended June 30,
(In millions)		2019
South Central Portfolio		$	36
Carlsbad		363
GenOn		2
Income from discontinued operations, net of income tax		$	401

For the six months ended June 30, 2019, NRG recorded income from discontinued operations, net of income tax of $401 million, as further described in Note 4, Acquisitions, Discontinued Operations and Dispositions.

Liquidity and Capital Resources

Liquidity Position

As of June 30, 2020 and December 31, 2019, NRG's total liquidity, excluding funds deposited by counterparties, of approximately $2.2 billion and $2.1 billion, respectively, was comprised of the following:

(In millions)	June 30, 2020		December 31, 2019
Cash and cash equivalents	$	418	$	345
Restricted cash - operating	4		4
Restricted cash - reserves(a)	4		4
Total	426		353
Total credit facility availability	1,782		1,794
Total liquidity, excluding funds deposited by counterparties	$	2,208	$	2,147

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

For the six months ended June 30, 2020, total liquidity, excluding funds deposited by counterparties, increased by $61 million. Changes in cash and cash equivalent balances are further discussed hereinafter under the heading Cash Flow Discussion. Cash and cash equivalents at June 30, 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.

81

On July 24, 2020, Standard & Poor's upgraded NRG's issuer credit rating and senior unsecured debt rating from BB to BB+ with a stable outlook. The agency affirmed NRG's senior secured debt rating at BBB-. In addition, Moody's reaffirmed NRG's corporate family rating of Ba1 with a positive outlook on July 24, 2020.

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 9, Long-term Debt, to this Form 10-Q. The Company's financing arrangements consist mainly of the Senior Notes, Convertible Senior Notes, Senior Secured Notes, Senior Credit Facility, and tax-exempt bonds.

The Company's requirements for liquidity and capital resources, other 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.

Direct Energy Acquisition

On July 24, 2020, the Company entered into the Purchase Agreement with Centrica to acquire Direct Energy, a North American subsidiary of Centrica. Direct Energy is a leading retail provider of electricity, natural gas, and home and business energy related products and services in North America, with operations in all 50 U.S. states and 6 Canadian provinces. The acquisition will add over 3 million customers to NRG's business and build on and complement its integrated model, enabling better matching of power generation with customer demand. It will also broaden the Company's presence in the Northeast and into states and locales where it does not currently operate, supporting NRG's objective to diversify its business.

The Company will pay an aggregate purchase price of $3.6 billion in cash, subject to a purchase price adjustment, including a working capital adjustment. The Company expects to fund the purchase price using a combination of cash on hand, approximately $2.4 billion in newly-issued secured and unsecured corporate debt and approximately $750 million in convertible preferred stock or other equity-linked instruments. The Company also expects to increase its collective collateral facilities by $3.5 billion through a combination of new letter of credit facilities and increase to the existing Revolving Credit Facility.

The acquisition is subject to approval by the shareholders of Centrica, as well as customary closing conditions, consents and regulatory approvals, including the expiration or termination of the applicable waiting period under the HSR Act, and the receipt of approvals or expiration of applicable waiting periods under the Federal Power Act and the Canadian Competition Act.

The acquisition is targeted to close by December 31, 2020. There are no assurances that the conditions to the consummation of the acquisition of Direct Energy will be satisfied, that Centrica will not seek or enter into an alternative transaction as discussed below, or that the acquisition of Direct Energy will be consummated on the terms agreed to, or at all.

Prior to the approval of the transaction by its shareholders, Centrica is permitted to respond to unsolicited acquisition proposals that constitute or are reasonably likely to lead to a superior proposal, and to engage in negotiations with, and provide information to, parties that submit these proposals. Centrica can terminate the Purchase Agreement to accept a superior proposal. In addition, the board of directors of Centrica can change its recommendation in favor of NRG's transaction if the failure to do so would be inconsistent with the fiduciary duties of the Centrica directors, in which case the Purchase Agreement would automatically terminate. In the event of a termination of the Purchase Agreement in connection with (i) Centrica's decision to accept a superior proposal, (ii) the failure to obtain Centrica shareholder approval, or (iii) a change of recommendation by the Centrica board, Centrica would be obligated to pay NRG a termination fee of approximately $30 million.

NRG will be required to pay Centrica a termination fee of $180 million if the Purchase Agreement is terminated (i) by either Centrica or NRG because the transaction has not been completed by July 24, 2021 (as such date may be extended for two separate three month periods if necessary to obtain required regulatory approvals, through January 24, 2022), and at the time of termination all of the mutual conditions to the obligations of NRG and Centrica to close the acquisition, and all the conditions to NRG's obligations to close the acquisition, have been satisfied other than receipt of the required antitrust and competition approvals, (ii) by either Centrica or NRG if a governmental entity has issued a judgment with respect to an antitrust or competition law that permanently prohibits the completion of the transaction and the judgment has become final and non-appealable, (iii) by NRG if a governmental entity has imposed a condition on its willingness to approve the acquisition on antitrust or competition grounds and the condition has a material adverse effect as described in the Purchase Agreement or (iv) by Centrica because NRG has breached its obligations under the Purchase Agreement to seek to obtain the antitrust and competition approvals required to complete the transaction.

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Revolving Credit Facility

The Company had $83 million outstanding under its Revolving Credit Facility as of December 31, 2019, which was used to repay the outstanding indebtedness on the Agua Caliente Borrower 1 notes on a leverage-neutral basis during the fourth quarter of 2019. 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, and fully repaid the outstanding borrowings during the second quarter of 2020.

Midwest Generation Lease Purchase

On July 22, 2020, Midwest Generation signed purchase agreements to acquire all of the ownership interests in the Powerton facility and Units 7 and 8 of the Joliet facility, which were being leased through 2034 and 2030, respectively, for approximately $260 million. The Company intends to fund the purchase with borrowings under its Revolving Credit Facility in an amount equal to the existing operating lease liabilities of $148 million as of June 30, 2020 and the remainder from cash-on-hand. The closing is conditioned, among other items, on the receipt of regulatory approvals from FERC and under the HSR Act.

Marketing of Agua Caliente

NRG renewed its efforts to sell its 35% interest in Agua Caliente in July 2020, following PG&E's emergence from bankruptcy.

COVID-19

On 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) received $34 million of refundable AMT credits on August 4, 2020, inclusive of $17 million that was originally scheduled to be received in 2021. Of the amount received, $11 million is due to GenOn for their share of the AMT credits.

Tax-Exempt Bonds

On March 11, 2020, NRG issued $59 million in aggregate principal amount of 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 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 Bonds will, at the request of NRG, be released if 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 reversion if those rating agencies withdraw their investment grade rating of the Bonds or any of NRG’s senior, unsecured debt securities or downgrade such rating below investment 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 net proceeds from the offering to redeem the existing principal amount of outstanding Dunkirk Power LLC 5.875% tax exempt bonds due 2042.

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 June 30, 2020, the Company had total cash collateral outstanding of $136 million and $804 million outstanding in letters of credit to third parties primarily to support its market activities. As of June 30, 2020, total funds deposited by counterparties were $36 million in cash and $133 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 depend on the Company's credit ratings and general perception of its creditworthiness.

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First Lien Structure

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

The Company's first lien counterparties may have a claim on its assets to the extent market prices exceed the hedged prices. As of June 30, 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 June 30, 2020:

Equivalent Net Sales Secured by First Lien Structure(a)	2020	2021	2022	2023
In MW	401	694	692	699
As a percentage of total net coal and nuclear capacity(b)	9%	15%	15%	15%

(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

Capital Expenditures

The following tables and descriptions summarize the Company's capital expenditures for maintenance, environmental and growth investments for the six months ended June 30, 2020, and the estimated capital expenditures forecast for the remainder of 2020.

(In millions)	Maintenance		Environmental		Growth Investments(a)		Total
Texas	$	(52)	$	—	$	(13)	$	(65)
East	(7)		(1)		(7)		(15)
West/Other	(19)		—		—		(19)
Corporate	(4)		—		(13)		(17)
Total cash capital expenditures for the six months ended June 30, 2020	(82)		(1)		(33)		(116)
Other investments(b)	—		—		(7)		(7)
Total capital expenditures and investments, net of financings	(82)		(1)		(40)		(123)
Estimated capital expenditures for the remainder of 2020(c)(d)	$	(88)	$	(4)	$	(71)	$	(163)

(a) Includes other investments, acquisitions, digital NRG and costs to achieve. Excludes Midwest Generation lease buyout

(b) Includes $3 million of expenditures for Encina site improvements classified as asset retirement obligation payments

(c) Growth investments include costs to achieve associated with the Transformation Plan

(d) Growth investments include $22 million of capital expenditures for Encina site improvements

Environmental Capital Expenditures

NRG estimates that environmental capital expenditures from 2020 through 2024 required to comply with environmental laws will be approximately $43 million.

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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, supplemented by share repurchases.

During the six months ended June 30, 2020, the Company completed $224 million of share repurchases at an average price of $33.05 per share, including $27 million of equivalent shares purchased in lieu of tax withholdings on equity compensation issuance.

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 $0.30 per share was paid on the Company's common stock during the three months ended June 30, 2020. On July 17, 2020, NRG declared a quarterly dividend on the Company's common stock of $0.30 per share, payable August 17, 2020 to stockholders of record as of August 3, 2020.

Cash Flow Discussion

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

	Six months ended June 30,
(In millions)	2020		2019		Change
Net Cash Provided by Operating Activities	$	692	$	425	$	267
Net Cash (Used)/Provided by Investing Activities	(145)		1,103		(1,248)
Net Cash Used by Financing Activities	(469)		(1,756)		1,287

Net Cash Provided by Operating Activities

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

	(In millions)
Increase in operating income adjusted for other non-cash items	$	189
Increase primarily due to decreased pension contributions in 2020 due to CARES Act deferrals and reduced commissions due to changes in sales channels as a result of COVID-19	76
Increase in accounts payable primarily due to increased customer counts and timing of fuel shipments and renewable energy credit purchases	67
Changes in cash collateral in support of risk management activities due to change in commodity prices	(67)
Decrease in accounts receivable primarily driven by favorable days outstanding from the Texas retail portfolio	32
Decrease in cash provided by discontinued operations	(8)
Decrease in other working capital	(22)
	$	267

Net Cash (Used)/Provided by Investing Activities

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

	(In millions)
Decrease in proceeds from sales of assets and discontinued operations primarily due to sales of South Central and Carlsbad in 2019	$	(1,274)
Decrease in contributions to discontinued operations	44
Increase in purchases of investments in nuclear decommissioning trust fund securities, net of proceeds from sales	(19)
Decrease in cash paid for acquisitions	16
Increase in capital expenditures	(9)
Other	(6)
	$	(1,248)

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Net Cash Used by Financing Activities

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

	(In millions)
Decrease in payments of long-term debt	$	2,424
Decrease in proceeds from issuance of long-term debt	(1,774)
Decrease in payments for share repurchase activity	846
Increase in payments of dividends to common stockholders	(132)
Repayment of Revolving Credit Facility	(83)
Decrease in payments of debt extinguishment costs and deferred issuance costs	56
Decrease in cash provided by discontinued operations	(43)
Other	(7)
	$	1,287

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

For the six months ended June 30, 2020, the Company had domestic pre-tax book income of $550 million and foreign pre-tax book income of $8 million. As of December 31, 2019, the Company had cumulative domestic Federal NOL carryforwards of $10.1 billion, which will begin expiring in 2031, and cumulative state NOL carryforwards of $5.5 billion for financial statement purposes. NRG also has cumulative foreign NOL carryforwards of $357 million, which do not have an expiration date. In addition to the above NOLs, NRG has $384 million of tax credits to be utilized in future years. 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 $18 million in 2020.

The Company has recorded a non-current tax liability of $18 million, inclusive of accrued interest, for uncertain tax benefits taken on various state income tax 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 2016. With few exceptions, state and local income tax examinations are no longer open for years prior to 2011.

Net deferred tax balance — As of both June 30, 2020 and December 31, 2019, NRG recorded a net deferred tax asset, excluding valuation allowance, of $3.4 billion. The Company believes certain state net operating losses may not be realizable under the more-likely-than-not measurement and as such, a valuation allowance was recorded as of June 30, 2020 as discussed below.

Valuation allowance — As of June 30, 2020 and December 31, 2019, the Company's tax-effected valuation allowance was $241 million and $242 million, respectively, consisting of state NOL carryforwards and foreign NOL carryforwards. The valuation allowance was recorded based on the assessment of cumulative and forecasted pre-tax book earnings and the future reversal of 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 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 June 30, 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 10, Investments Accounted for Using the Equity Method and Variable Interest Entities, or VIEs, to this Form 10-Q.

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NRG's pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $859 million as of June 30, 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 2019 Form 10-K.

Contractual Obligations and Market Commitments

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

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 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 June 30, 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 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 June 30, 2020, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at June 30, 2020.

Derivative Activity Gains	(In millions)
Fair Value of Contracts as of December 31, 2019	$	67
Contracts realized or otherwise settled during the period	31
Changes in fair value	105
Fair Value of Contracts as of June 30, 2020	$	203

	Fair Value of Contracts as of June 30, 2020
(In millions)	Maturity
Fair value hierarchy (Losses)/Gains	1 Year or Less		Greater than 1 Year to 3 Years		Greater than 3 Years to 5 Years		Greater than 5 Years		Total Fair Value
Level 1	$	(53)	$	(11)	$	(1)	$	1	$	(64)
Level 2	23		92		9		(9)		115
Level 3	93		22		6		31		152
Total	$	63	$	103	$	14	$	23	$	203

The Company has elected to present derivative assets and liabilities on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. Also, collateral received or paid on the Company's derivative assets or liabilities are recorded on a separate line item on the balance sheet. Consequently, the magnitude of the changes in individual current and non-current derivative assets or liabilities is higher than the underlying credit and market risk of the Company's portfolio. As discussed in Item 3, Quantitative and Qualitative Disclosures About Market Risk, Commodity Price Risk, to this Form 10-Q, NRG measures the sensitivity of the Company's portfolio to potential changes in market prices using VaR, a statistical model which attempts to predict risk of loss based on market price and volatility. NRG's risk management policy places a limit on one-day holding period VaR, which limits the Company's net open position. As the Company's trade-by-trade derivative accounting results in a gross-up of the Company's derivative assets and liabilities, the net derivative asset and liability position is a better indicator of NRG's hedging activity. As of June 30, 2020, NRG's net derivative asset was $203 million, an increase to total fair value of $136 million as compared to December 31, 2019. This increase was primarily driven by gains in fair value, as well as roll-off of trades that settled during the period.

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Based on a sensitivity analysis using simplified assumptions, the impact of a $0.50 per MMBtu increase in natural gas prices across the term of the derivative contracts would result in an increase of approximately $166 million in the net value of derivatives as of June 30, 2020. The impact of a $0.50 per MMBtu decrease in natural gas prices across the term of derivative contracts would result in a decrease of approximately $167 million in the net value of derivatives as of June 30, 2020.

Critical Accounting Policies and Estimates

NRG's discussion and analysis of the financial condition and results of operations are based upon the 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 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 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 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 require the most difficult, subjective and/or complex judgments by management regarding estimates about matters that are inherently uncertain. NRG's critical accounting policies include derivative instruments, income taxes and valuation allowance for deferred tax assets, impairment of long-lived assets and investments, goodwill and other intangible assets, and contingencies.

The Company's significant accounting policies are outlined in Note 2, Summary of Significant Accounting Policies, of this Form 10-Q, and in Note 2, Summary of Significant Accounting Policies, under Part IV, Item 15 of the Company's 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 2019 Form 10-K. There have been no material changes to the Company's critical accounting policies and estimates since the 2019 Form 10-K, except as noted below.

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 to Texas, East and West/Other beginning in the first quarter of 2020, as further described in Note 1, 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.

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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, 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 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 six months ending June 30, 2020 and 2019:

(In millions)	2020		2019
VaR as of June 30,	$	25	$	33
Three months ended June 30,
Average	$	26	$	40
Maximum	31		46
Minimum	22		33
Six months ended June 30,
Average	$	27	$	43
Maximum	47		49
Minimum	22		33

In order to provide additional information, 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 for the entire term of these instruments entered into for both asset management and trading, was $15 million, as of June 30, 2020, primarily driven by asset-backed transactions.

Liquidity Risk

Liquidity risk arises from the general funding needs of 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 June 30, 2020, a $0.50 per MMBtu decrease in natural gas prices across the term of the marginable contracts would cause an increase in margin collateral posted of approximately $180 million and a 1.00 MMBtu/MWh decrease in heat rates for heat rate positions would result in an increase in margin collateral posted of approximately $46 million. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of June 30, 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.

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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 June 30, 2020, NRG had no interest rate derivative instruments.

As of June 30, 2020, the fair value and related carrying value of the Company's debt was $6.2 billion and $5.9 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 June 30, 2020 by $510 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.

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ITEM 4 — CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

There were no changes in NRG's internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred in the quarter ended June 30, 2020 that materially affected, or are reasonably likely to materially affect, NRG's internal control over financial reporting.

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PART II — OTHER INFORMATION

ITEM 1 — LEGAL PROCEEDINGS

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

ITEM 1A — RISK FACTORS

Except as set forth below, during the six months ended June 30, 2020, there were no material changes to the Risk Factors disclosed in Part I, Item 1A, Risk Factors, 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 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 the Company's 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 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 on the Company’s results of operations, financial position, risk exposure and liquidity.

Risks related to the proposed acquisition of Direct Energy

The Company may be unable to consummate the acquisition of Direct Energy because it may not be able to obtain the approvals necessary to do so, or the combined company may be required to comply with material restrictions or conditions that might impact the parties' interests in consummating the transaction.

On July 24, 2020, the Company entered into a definitive purchase agreement with Centrica to acquire its North American retail business, Direct Energy (the "Purchase Agreement"). Before the acquisition may be completed, Centrica will need to obtain shareholder approval in connection with the proposed transaction. In addition, the completion of the acquisition is conditioned on certain customary closing conditions, including the expiration or termination of the applicable waiting period under the HSR Act, and the receipt of approvals or expiration of applicable waiting periods under the Federal Power Act and the Canadian Competition Act. These governmental authorities may impose conditions on the completion, or require changes to the terms, of the transaction, including conditions on or changes to the business, or operations of the combined company following completion of the acquisition. These conditions or changes could impose additional costs on or limit the revenues or income of the combined company following the acquisition, which could have a material adverse effect on the financial results of the combined company and/or cause either NRG or Centrica to abandon the acquisition. In addition, the regulatory review

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processes to be pursued in connection with the transaction, and any litigation that may arise from these processes or otherwise, may materially delay the closing of the acquisition.

Furthermore, prior to the approval of the transaction by its shareholders, Centrica is permitted to respond to unsolicited acquisition proposals that constitute or are reasonably likely to lead to a superior proposal, and to engage in negotiations with, and provide information to, parties that submit these proposals. As a result, Centrica can terminate the Purchase Agreement to accept a superior proposal. In addition, the board of directors of Centrica can change its recommendation for the NRG transaction if the failure to do so would be inconsistent with the fiduciary duties of the Centrica directors, in which case the Purchase Agreement would automatically terminate

If the Company is unable to complete the acquisition, it will still incur and will remain liable for significant transaction costs, including financing, legal, accounting, filing, and other costs relating to the transaction. Also, if the transaction is not completed due to the failure to obtain antitrust or competition approvals for the acquisition, or the Company decides to terminate the transaction in accordance with the purchase agreement due to conditions imposed or sought to be imposed in connection with obtaining these approvals, the Company will be required to pay Centrica a termination fee of $180 million.

If completed, the acquisition of Direct Energy may not achieve its intended results.

The Company entered into the Purchase Agreement with the expectation that the acquisition would result in various benefits, including, among other things, cost savings and operating efficiencies. Achieving the anticipated benefits of the acquisition is subject to a number of uncertainties, including whether the businesses of NRG and Direct Energy are integrated in an efficient and effective manner. Failure to achieve these anticipated benefits could result in increased costs, lower-than-expected revenues or income generated by the combined company and diversion of management's time and energy and could have an adverse effect on the Company's business, financial results and prospects.

The Company will be subject to business uncertainties and contractual restrictions while the acquisition of Direct Energy is pending that could adversely affect its financial results.

Uncertainty about the effects of the acquisition of Direct Energy on employees, customers and suppliers may have an adverse effect on NRG's business. Although the Company intends to take steps designed to reduce any adverse effects, these uncertainties may impair its ability to attract, retain and motivate key personnel until the acquisition is completed and for a period of time thereafter, and could cause customers, suppliers and others that deal with it to seek to change existing business relationships.

Employee retention and recruitment may be particularly challenging prior to the completion of the acquisition, as employees and prospective employees may experience uncertainty about their future roles with the combined company. If, despite the Company's retention and recruiting efforts, key employees depart or fail to accept employment with NRG because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with the combined company, the Company's financial results could be affected.

The pursuit of the acquisition and the preparation for the integration of NRG and Direct Energy may place a significant burden on management and internal resources. The diversion of management attention away from ongoing business concerns and any difficulties encountered in the transition and integration process could affect the Company's business, results of operations and financial condition.

In addition, the Company is obligated under the Purchase Agreement to take all actions necessary to obtain antitrust and competition approvals for the acquisition, subject to its right not to take actions that would have a material adverse effect as described in the Purchase Agreement. If the antitrust and competition approvals required for the transaction are not obtained and either NRG or Centrica terminates the Purchase Agreement for this reason, the Company will be required to pay Centrica a termination fee of $180 million. In addition, the Company has agreed not to take any actions that would materially delay the satisfaction of any of the closing conditions to the transaction or prevent any of those conditions from being satisfied. This restriction on the Company's actions may prevent it from pursuing otherwise attractive business opportunities and making other changes to its business prior to completion of the acquisition or termination of the Purchase Agreement.

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

The table below sets forth the information with respect to purchases made by or on behalf of NRG or any "affiliated purchaser" (as defined in Rule 10b-18(a)(3) under the Exchange Act), of NRG's common stock during the quarter ended June 30, 2020.

For the three months ended June 30, 2020	Total Number of Shares Purchased(a)	Average Price Paid per Share(b)		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs(a)
Month #1
(April 1, 2020 to April 30, 2020)	1,601,345	$	29.33	—	$	—
Month #2
(May 1, 2020 to May 31, 2020)	—	$	—	—	$	—
Month #3
(June 1, 2020 to June 30, 2020)	—	$	—	—	$	—
Total at June 30, 2020	1,601,345	$	29.33	—

(a)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

(b)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.

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ITEM 6 — EXHIBITS

Number	Description	Method of Filing
2.1	Purchase Agreement, dated as of July 24, 2020, by and between the Company, Parent, Centrica Beta Holdings Limited, Centrica Gamma Holdings Limited, Centrica US Holdings Inc. and Direct Energy Marketing Limited.	Incorporated herein by reference to Exhibit 2.1 to the Registrant's Current Report on Form 8-K, filed on July 30, 2020.
2.2	Commitment Letter, dated as of July 24, 2020, by and between the Company, Citi and Credit Suisse.	Incorporated herein by reference to Exhibit 2.2 to the Registrant's Current Report on Form 8-K, filed on July 30, 2020.
31.1	Rule 13a-14(a)/15d-14(a) certification of Mauricio Gutierrez.	Filed herewith.
31.2	Rule 13a-14(a)/15d-14(a) certification of Kirkland B. Andrews.	Filed herewith.
31.3	Rule 13a-14(a)/15d-14(a) certification of David Callen.	Filed herewith.
32	Section 1350 Certification.	Furnished herewith.
101 INS	Inline XBRL Instance Document.	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.

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SIGNATURES

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

	NRG ENERGY, INC. (Registrant)
	/s/ MAURICIO GUTIERREZ
	Mauricio Gutierrez
	Chief Executive Officer (Principal Executive Officer)
	/s/ KIRKLAND B. ANDREWS
	Kirkland B. Andrews
	Chief Financial Officer (Principal Financial Officer)
	/s/ DAVID CALLEN
	David Callen
Date: August 6, 2020	Chief Accounting Officer (Principal Accounting Officer)

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