UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☒

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

For the Quarterly Period Ended:

September 30, ~~2022~~2023

☐

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.)


910 Louisiana Street	Houston	Texas	77002
(Address of principal executive offices)			(Zip Code)

(713) 537-3000

(Registrant’s telephone number, including area code)

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


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

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

Yes ☒ No ☐

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

Yes ☒ No ☐

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

Large Accelerated Filer

☒

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

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

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

Yes ☐ No ☒

As of October 31, ~~2022,~~2023, there were ~~230,384,205~~225,764,436 shares of common stock outstanding, par value $0.01 per share.

TABLE OF CONTENTS

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," ~~"targets"~~"should," "forecasts," and similar expressions are intended to identify forward-looking statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors, many of which are beyond NRG's control, 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. Forward-looking statements are not guarantees of future results. These factors, risks and uncertainties include the factors described under Risk Factors, in Part I,II, Item 1A of ~~the Company's Annual Report on~~this Form ~~10-K for the year ended December 31, 2021~~10-Q and the following:

•Business uncertainties related to ~~the integration of~~NRG's ability to integrate the operations of ~~Direct Energy~~Vivint Smart Home with its own;

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

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

•Volatile power and gas supply costs and demand for power and ~~gas;~~gas, including the impacts of weather;

•Changes in law, including judicial and regulatory decisions;

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

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

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

•NRG's inability to estimate with any degree of certainty the future impact that COVID-19, any resurgence of COVID-19 or variants thereof, or other pandemic may have on NRG's results of operations, financial position, risk exposure and liquidity;

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

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

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

•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;

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

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

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

•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;

•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 NRG's corporate credit agreements, and in debt and other agreements of certain of NRG subsidiaries and project affiliates generally;

•The ability of NRG and its counterparties to develop and build new power generation facilities;

•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; and

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

In addition, unlisted factors may present significant additional obstacles to the realization of forward-looking statements. 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 except as otherwise required by applicable laws. The foregoing factors that could cause NRG's actual results to differ materially from those contemplated in any forward-looking statements included in this Quarterly Report on Form 10-Q should not be construed as exhaustive.

GLOSSARY OF TERMS

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


~~2021~~2022 Form 10-K						NRG’s Annual Report on Form 10-K for the year ended December 31, ~~2021~~2022
ACE						Affordable Clean Energy
Adjusted EBITDA						Adjusted earnings before interest, taxes, depreciation and amortization
AESO						Alberta Electric System Operator
~~Agua Caliente~~						~~Agua Caliente Solar Project, a 290 MW photovoltaic power station located in Yuma County, Arizona in which NRG owned a 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~~
BTU						British Thermal Unit
Business						NRG Business, which serves business customers
CAA						Clean Air Act
CAISO						California Independent System Operator
~~CARES Act~~						~~Coronavirus Aid, Relief, and Economic Security Act of 2020~~
CDD						Cooling Degree Day
CEJA						Climate and Equitable Jobs Act
CFTC						U.S. Commodity Futures Trading Commission

~~Centrica~~						~~Centrica plc~~
CO2						Carbon Dioxide
Company						NRG Energy, Inc.
Convertible Senior Notes						As of September 30, ~~2022,~~2023, consists of NRG’s $575 million unsecured 2.75% Convertible Senior Notes due 2048
Cottonwood						Cottonwood Generating Station, a ~~1,177 MW~~ natural gas-fueled plant
~~COVID-19~~						~~Coronavirus Disease 2019~~ located in Deweyville, Texas, which NRG is leasing through May 2025
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
Dth						Dekatherms
Economic gross margin						Sum of retail revenue, energy revenue, capacity revenue and other revenue, less cost of fuels and purchased energy 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
ESPP						NRG Energy, Inc. Amended and Restated Employee Stock Purchase Plan
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.
GHG						Greenhouse Gas
Green Mountain Energy						Green Mountain Energy Company
GW						Gigawatts
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
Home						NRG Home, which serves residential customers


HLW						High-level radioactive waste
ICE						Intercontinental Exchange
IESO						Independent Electricity System Operator
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
LSEs						Load Serving Entities
LTIPs						Collectively, the NRG long-term incentive plan ("LTIP") and the NRG ~~GenOn~~Vivint LTIP
MDth						Thousand Dekatherms
Midwest Generation						Midwest Generation, LLC
MISO						Midcontinent Independent System Operator, Inc.
MMBtu						Million British Thermal Units
MW						Megawatts
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

Net Exposure						Counterparty credit exposure to NRG, net of collateral
Net Revenue Rate						Sum of retail revenues less TDSP transportation charges
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.


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

OCI/OCL						Other Comprehensive Income/(Loss)
~~ORDC~~						~~Operating Reserve Demand Curve~~
~~ORDPA~~						~~Online Reliability Deployment Price Adder~~
~~Petra Nova~~						~~Petra Nova Parish Holdings, LLC~~
PG&E						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
RCRA						Resource Conservation and Recovery Act of 1976


Receivables Facility						NRG Receivables LLC, a bankruptcy remote, special purpose, wholly-owned indirect subsidiary of the Company's ~~$1.0~~$1.4 billion accounts receivables securitization facility due ~~2023,~~2024, which was last amended on ~~July 26, 2021 and July 26, 2022~~October 6, 2023
Receivables Securitization Facilities						Collectively, the Receivables Facility and the Repurchase Facility
Renewable PPA						A third-party PPA entered into directly with a renewable generation facility for the offtake of the Renewable Energy Certificates or other similar environmental attributes generated by such facility, couple with the associated power generated by that facility
REP						Retail electric provider


Repurchase Facility						NRG's $150 million uncommitted repurchase facility related to the Receivables Facility due ~~2023,~~2024, which was last amended on ~~July 26, 2021, February 9, 2022 and July 26, 2022~~October 6, 2023
Revolving Credit Facility						The Company's ~~$3.7~~$4.3 billion revolving credit facility due ~~2024,~~2028, was last amended on ~~May 28, 2019 and August 20, 2020~~March 13, 2023
RGGI						Regional Greenhouse Gas Initiative
~~RMR~~						~~Reliability Must-Run~~
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 Notes						As of September 30, ~~2022,~~2023, NRG's $4.6 billion outstanding unsecured senior notes consisting of $375 million of the 6.625% senior notes due 2027, $821 million of 5.75% senior notes due 2028, $733 million of the 5.25% senior notes due 2029, $500 million of the 3.375% senior notes due 2029, $1.0 billion of the 3.625% senior notes due 2031 and $1.1 billion of the 3.875% senior notes due 2032
Senior Secured First Lien Notes						As of September 30, ~~2022,~~2023, NRG’s ~~$2.5~~$3.2 billion outstanding Senior Secured First Lien Notes consists of $600 million of the 3.75% Senior Secured First Lien Notes due 2024, $500 million of the 2.0% Senior Secured First Lien Notes due 2025, $900 million of the 2.45% Senior Secured First Lien Notes due 2027, ~~and~~ $500 million of the 4.45% Senior Secured First Lien Notes due 2029 and $740 million of the 7.000% Senior Secured First Lien Notes due 2033
Services						NRG Services, which primarily includes the services businesses acquired in the Direct Energy ~~Acquisition~~acquisition and the Goal Zero business

SNF						Spent Nuclear Fuel
SO2						Sulfur Dioxide
SOFR						Secured overnight financing rate
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~~owned a 44% interest. NRG closed on the sale of its interest in STP on November 1, 2023
STPNOC						South Texas Project Nuclear Operating Company

TDSP						Transmission/distribution service provider

TWh						Terawatt Hour
U.S.						United States of America
U.S. DOE						U.S. Department of Energy
VaR						Value at Risk
VIE						Variable Interest Entity

Winter Storm Elliott						A major winter storm that had impacts across the majority of the United States and parts of Canada occurring in December 2022
Winter Storm Uri						A major winter and ice storm that had widespread impacts across North America occurring in February 2021

PART I — FINANCIAL INFORMATION

ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


		Three months ended September 30,				Nine months ended September 30,					Three months ended September 30,				Nine months ended September 30,
(In millions, except for per share amounts)	(In millions, except for per share amounts)	2022		2021		2022		2021		(In millions, except for per share amounts)	2023		2022		2023		2022
Revenue	Revenue									Revenue
Revenue	Revenue	$	8,510	$	6,609	$	23,688	$	19,943	Revenue	$	7,946	$	8,510	$	22,016	$	23,688
Operating Costs and Expenses	Operating Costs and Expenses									Operating Costs and Expenses
Cost of operations (excluding depreciation and amortization shown below)	Cost of operations (excluding depreciation and amortization shown below)	7,802		3,692		18,619		13,496		Cost of operations (excluding depreciation and amortization shown below)	6,421		7,802		20,161		18,619
Depreciation and amortization	Depreciation and amortization	145		199		485		569		Depreciation and amortization	308		145		813		485
Impairment losses	Impairment losses	43		—		198		306		Impairment losses	—		43		—		198
Selling, general and administrative costs	Selling, general and administrative costs	326		318		973		973		Selling, general and administrative costs	638		378		1,586		1,076
Provision for credit losses		52		64		103		715

Acquisition-related transaction and integration costs	Acquisition-related transaction and integration costs	8		17		26		81		Acquisition-related transaction and integration costs	18		8		111		26
Total operating costs and expenses	Total operating costs and expenses	8,376		4,290		20,404		16,140		Total operating costs and expenses	7,385		8,376		22,671		20,404

Gain on sale of assets	Gain on sale of assets	22		—		51		17		Gain on sale of assets	—		22		202		51
Operating Income		156		2,319		3,335		3,820
Operating Income/(Loss)										Operating Income/(Loss)	561		156		(453)		3,335
Other Income/(Expense)	Other Income/(Expense)									Other Income/(Expense)
Equity in earnings of unconsolidated affiliates	Equity in earnings of unconsolidated affiliates	11		15		—		23		Equity in earnings of unconsolidated affiliates	6		11		16		—

Other income, net	Other income, net	21		8		33		42		Other income, net	14		21		43		33
Loss on debt extinguishment		—		(57)		—		(57)

Interest expense	Interest expense	(105)		(122)		(313)		(374)		Interest expense	(173)		(105)		(472)		(313)
Total other expense	Total other expense	(73)		(156)		(280)		(366)		Total other expense	(153)		(73)		(413)		(280)
Income Before Income Taxes		83		2,163		3,055		3,454
Income tax expense		16		545		739		840
Income/(Loss) Before Income Taxes										Income/(Loss) Before Income Taxes	408		83		(866)		3,055
Income tax expense/(benefit)										Income tax expense/(benefit)	65		16		(182)		739

Net Income		$	67	$	1,618	$	2,316	$	2,614
Net Income/(Loss)										Net Income/(Loss)	$	343	$	67	$	(684)	$	2,316
Less: Cumulative dividends attributable to Series A Preferred Stock										Less: Cumulative dividends attributable to Series A Preferred Stock	17		—		38		—
Net Income/(Loss) Available for Common Stockholders										Net Income/(Loss) Available for Common Stockholders	$	326	$	67	$	(722)	$	2,316
Income/(Loss) per Share										Income/(Loss) per Share
Weighted average number of common shares outstanding — basic										Weighted average number of common shares outstanding — basic	230		235		230		238

Income per Share
Income/(Loss) per Weighted Average Common Share — Basic										Income/(Loss) per Weighted Average Common Share — Basic	$	1.42	$	0.29	$	(3.14)	$	9.73
Weighted average number of common shares outstanding — diluted										Weighted average number of common shares outstanding — diluted	232		235		230		238

Weighted average number of common shares outstanding — basic and diluted		235		245		238		245

Income per Weighted Average Common Share —Basic and Diluted		$	0.29	$	6.60	$	9.73	$	10.67
Income/(Loss) per Weighted Average Common Share —Diluted										Income/(Loss) per Weighted Average Common Share —Diluted	$	1.41	$	0.29	$	(3.14)	$	9.73

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

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

(Unaudited)


		Three months ended September 30,				Nine months ended September 30,					Three months ended September 30,				Nine months ended September 30,
(In millions)	(In millions)	2022		2021		2022		2021		(In millions)	2023		2022		2023		2022
Net Income		$	67	$	1,618	$	2,316	$	2,614
Net Income/(Loss)										Net Income/(Loss)	$	343	$	67	$	(684)	$	2,316
Other Comprehensive (Loss)/Income	Other Comprehensive (Loss)/Income									Other Comprehensive (Loss)/Income

Foreign currency translation adjustments	Foreign currency translation adjustments	(32)		(11)		(45)		(6)		Foreign currency translation adjustments	(8)		(32)		—		(45)

Defined benefit plans	Defined benefit plans	(2)		1		17		20		Defined benefit plans	1		(2)		—		17
Other comprehensive (loss)/income	Other comprehensive (loss)/income	(34)		(10)		(28)		14		Other comprehensive (loss)/income	(7)		(34)		—		(28)
Comprehensive Income		$	33	$	1,608	$	2,288	$	2,628
Comprehensive Income/(Loss)										Comprehensive Income/(Loss)	$	336	$	33	$	(684)	$	2,288

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS
September 30, 2022 December 31, 2021
(In millions, except share data) (Unaudited) (Audited)
ASSETS
Current Assets
Cash and cash equivalents $ 333 $ 250
Funds deposited by counterparties 3,134 845
Restricted cash 46 15
Accounts receivable, net 4,061 3,245
Uplift securitization proceeds receivable from ERCOT — 689
Inventory 772 498
Derivative instruments 9,938 4,613
Cash collateral paid in support of energy risk management activities 262 291
Prepayments and other current assets 417 395
Total current assets 18,963 10,841
Property, plant and equipment, net 1,598 1,688
Other Assets
Equity investments in affiliates 126 157
Operating lease right-of-use assets, net 236 271
Goodwill 1,650 1,795
Intangible assets, net 2,227 2,511
Nuclear decommissioning trust fund 789 1,008
Derivative instruments 4,914 2,527
Deferred income taxes 1,516 2,155
Other non-current assets 224 229
Total other assets 11,682 10,653
Total Assets $ 32,243 $ 23,182
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Current portion of long-term debt and finance leases $ 62 $ 4
Current portion of operating lease liabilities 82 81
Accounts payable 2,871 2,274
Derivative instruments 6,841 3,387
Cash collateral received in support of energy risk management activities 3,134 845
Accrued expenses and other current liabilities 1,376 1,324
Total current liabilities 14,366 7,915
Other Liabilities
Long-term debt and finance leases 7,974 7,966
Non-current operating lease liabilities 197 236
Nuclear decommissioning reserve 335 321
Nuclear decommissioning trust liability 433 666
Derivative instruments 2,802 1,412
Deferred income taxes 84 73
Other non-current liabilities 922 993
Total other liabilities 12,747 11,667
Total Liabilities 27,113 19,582
Commitments and Contingencies
Stockholders' Equity
Common stock; $0.01 par value; 500,000,000 shares authorized; 423,894,539 and 423,547,174 shares issued and 232,125,137 and 243,753,899 shares outstanding at September 30, 2022 and December 31, 2021, respectively 4 4
Additional paid-in-capital 8,450 8,531
Retained earnings 2,584 464
Treasury stock, at cost 191,769,402 and 179,793,275 shares at September 30, 2022 and December 31, 2021, respectively (5,754) (5,273)
Accumulated other comprehensive loss (154) (126)
Total Stockholders' Equity 5,130 3,600
Total Liabilities and Stockholders' Equity $ 32,243 $ 23,182


	September 30, 2023		December 31, 2022
(In millions, except share data and liquidation preference on preferred stock)	(Unaudited)		(Audited)
ASSETS
Current Assets
Cash and cash equivalents	$	401	$	430
Funds deposited by counterparties	263		1,708
Restricted cash	11		40
Accounts receivable, net	3,764		4,773

Inventory	630		751
Derivative instruments	3,710		7,886
Cash collateral paid in support of energy risk management activities	2		260

Prepayments and other current assets	601		383
Current assets - held-for-sale	86		—

Total current assets	9,468		16,231
Property, plant and equipment, net	1,779		1,692
Other Assets
Equity investments in affiliates	146		133

Operating lease right-of-use assets, net	206		225
Goodwill	5,143		1,650
Customer relationships, net	2,299		943
Other intangible assets, net	1,907		1,189
Nuclear decommissioning trust fund	—		838
Derivative instruments	2,530		4,108
Deferred income taxes	2,540		1,881
Other non-current assets	739		251
Non-current assets - held-for-sale	1,153		5

Total other assets	16,663		11,223
Total Assets	$	27,910	$	29,146


	September 30, 2023		December 31, 2022
(In millions, except share data and liquidation preference on preferred stock)	(Unaudited)		(Audited)

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities

Current portion of long-term debt and finance leases	$	920	$	63

Current portion of operating lease liabilities	91		83
Accounts payable	2,200		3,643

Derivative instruments	3,128		6,195
Cash collateral received in support of energy risk management activities	263		1,708
Deferred revenue current	731		176
Accrued expenses and other current liabilities	1,553		1,110

Current liabilities - held-for-sale	44		4

Total current liabilities	8,930		12,982
Other Liabilities
Long-term debt and finance leases	10,741		7,976
Non-current operating lease liabilities	148		180
Nuclear decommissioning reserve	—		340
Nuclear decommissioning trust liability	—		477

Derivative instruments	1,552		2,246
Deferred income taxes	129		134
Deferred revenue non-current	989		10
Other non-current liabilities	977		942
Non-current liabilities - held-for-sale	926		31

Total other liabilities	15,462		12,336
Total Liabilities	24,392		25,318

Commitments and Contingencies
Stockholders' Equity
Preferred stock; 10,000,000 shares authorized; 650,000 Series A shares issued and outstanding at September 30, 2023 (liquidation preference $1,000); 0 shares issued and outstanding at December 31, 2022	650		—
Common stock; $0.01 par value; 500,000,000 shares authorized; 424,908,449 and 423,897,001 shares issued and 229,336,853 and 229,561,030 shares outstanding at September 30, 2023 and December 31, 2022, respectively	4		4
Additional paid-in-capital	8,527		8,457
Retained earnings	425		1,408
Treasury stock, at cost 195,571,596 and 194,335,971 shares at September 30, 2023 and December 31, 2022, respectively	(5,911)		(5,864)
Accumulated other comprehensive loss	(177)		(177)

Total Stockholders' Equity	3,518		3,828
Total Liabilities and Stockholders' Equity	$	27,910	$	29,146

See accompanying notes to condensed consolidated financial statements.

1011

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


		Nine months ended September 30,					Nine months ended September 30,
(In millions)	(In millions)	2022		2021		(In millions)	2023		2022
Cash Flows from Operating Activities	Cash Flows from Operating Activities					Cash Flows from Operating Activities
Net Income		$	2,316	$	2,614
Net (Loss)/Income						Net (Loss)/Income	$	(684)	$	2,316

Adjustments to reconcile net income to cash provided by operating activities:
Distributions from and equity in earnings of unconsolidated affiliates		7		8
Adjustments to reconcile net (loss)/income to cash (used)/provided by operating activities:						Adjustments to reconcile net (loss)/income to cash (used)/provided by operating activities:
Equity in and distributions from (earnings)/losses of unconsolidated affiliates						Equity in and distributions from (earnings)/losses of unconsolidated affiliates	(16)		7
Depreciation and amortization	Depreciation and amortization	485		569		Depreciation and amortization	813		485
Accretion of asset retirement obligations	Accretion of asset retirement obligations	20		21		Accretion of asset retirement obligations	14		20
Provision for credit losses	Provision for credit losses	103		715		Provision for credit losses	165		103
Amortization of nuclear fuel	Amortization of nuclear fuel	42		39		Amortization of nuclear fuel	42		42
Amortization of financing costs and debt discounts	Amortization of financing costs and debt discounts	17		30		Amortization of financing costs and debt discounts	42		17
Loss on debt extinguishment		—		57

Amortization of in-the-money contracts and emissions allowances	Amortization of in-the-money contracts and emissions allowances	122		111		Amortization of in-the-money contracts and emissions allowances	111		122
Amortization of unearned equity compensation	Amortization of unearned equity compensation	21		16		Amortization of unearned equity compensation	87		21
Net gain on sale and disposal of assets		(82)		(29)
Net gain on sale of assets and disposal of assets						Net gain on sale of assets and disposal of assets	(187)		(82)

Impairment losses	Impairment losses	198		306		Impairment losses	—		198
Changes in derivative instruments	Changes in derivative instruments	(4,480)		(4,419)		Changes in derivative instruments	1,553		(4,480)
Changes in deferred income taxes and liability for uncertain tax benefits		688		782
Changes in collateral deposits in support of energy risk management activities		2,321		1,970
Changes in current and deferred income taxes and liability for uncertain tax benefits						Changes in current and deferred income taxes and liability for uncertain tax benefits	(225)		688
Changes in collateral deposits in support of risk management activities						Changes in collateral deposits in support of risk management activities	(1,188)		2,321
Changes in nuclear decommissioning trust liability	Changes in nuclear decommissioning trust liability	2		38		Changes in nuclear decommissioning trust liability	(4)		2

Uplift securitization proceeds received from ERCOT	Uplift securitization proceeds received from ERCOT	689		—		Uplift securitization proceeds received from ERCOT	—		689
Changes in other working capital	Changes in other working capital	(711)		(973)		Changes in other working capital	(985)		(711)
Cash provided by operating activities		1,758		1,855
Cash (used)/provided by operating activities						Cash (used)/provided by operating activities	(462)		1,758

Cash Flows from Investing Activities	Cash Flows from Investing Activities					Cash Flows from Investing Activities
Payments for acquisitions of businesses and assets, net of cash acquired	Payments for acquisitions of businesses and assets, net of cash acquired	(60)		(3,534)		Payments for acquisitions of businesses and assets, net of cash acquired	(2,502)		(60)
Capital expenditures	Capital expenditures	(250)		(219)		Capital expenditures	(493)		(250)

Net (purchases)/sales of emission allowances		(4)		6
Net purchases of emissions allowances						Net purchases of emissions allowances	(25)		(4)
Investments in nuclear decommissioning trust fund securities	Investments in nuclear decommissioning trust fund securities	(361)		(460)		Investments in nuclear decommissioning trust fund securities	(293)		(361)
Proceeds from the sale of nuclear decommissioning trust fund securities	Proceeds from the sale of nuclear decommissioning trust fund securities	363		424		Proceeds from the sale of nuclear decommissioning trust fund securities	280		363
Proceeds from sales of assets, net of cash disposed	Proceeds from sales of assets, net of cash disposed	107		198		Proceeds from sales of assets, net of cash disposed	229		107

Proceeds from insurance recoveries for property, plant and equipment, net						Proceeds from insurance recoveries for property, plant and equipment, net	173		—

Cash used by investing activities	Cash used by investing activities	(205)		(3,585)		Cash used by investing activities	(2,631)		(205)

Cash Flows from Financing Activities	Cash Flows from Financing Activities					Cash Flows from Financing Activities
Payments of dividends to common stockholders		(252)		(239)
Payments for share repurchase activity		(484)		(9)
Proceeds from issuance of preferred stock, net of fees						Proceeds from issuance of preferred stock, net of fees	635		—
Payments of dividends to preferred and common stockholders						Payments of dividends to preferred and common stockholders	(295)		(252)
Payments for share repurchase activity(a)						Payments for share repurchase activity(a)	(69)		(484)
Net receipts from settlement of acquired derivatives that include financing elements	Net receipts from settlement of acquired derivatives that include financing elements	1,596		396		Net receipts from settlement of acquired derivatives that include financing elements	332		1,596

Net proceeds of Revolving Credit Facility						Net proceeds of Revolving Credit Facility	300		—
Proceeds from issuance of long-term debt						Proceeds from issuance of long-term debt	731		—
Payments of debt issuance costs						Payments of debt issuance costs	(29)		(1)
Repayments of long-term debt and finance leases	Repayments of long-term debt and finance leases	(4)		(1,360)		Repayments of long-term debt and finance leases	(15)		(4)
Proceeds from issuance of long-term debt		—		1,100
Payments for debt extinguishment costs		—		(48)

Payments of debt issuance costs		(1)		(18)
Proceeds from issuance of common stock		—		1

Cash provided/(used) by financing activities		855		(177)

Cash provided by financing activities						Cash provided by financing activities	1,590		855

Effect of exchange rate changes on cash and cash equivalents	Effect of exchange rate changes on cash and cash equivalents	(5)		(2)		Effect of exchange rate changes on cash and cash equivalents	—		(5)

Net Increase/(Decrease) in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash		2,403		(1,909)
Net (Decrease)/Increase in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash						Net (Decrease)/Increase in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash	(1,503)		2,403
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period	Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period	1,110		3,930		Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period	2,178		1,110
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	$	3,513	$	2,021	Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	$	675	$	3,513

(a)Includes $(19) million and $(6) million of equivalent shares purchased in lieu of tax withholdings on equity compensation issuances during the nine months ended September 30, 2023 and September 30, 2022, respectively

See accompanying notes to condensed consolidated financial statements.

1112

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(Unaudited)

(In millions) Common
Stock Additional
Paid-In
Capital Retained Earnings Treasury
Stock Accumulated
Other
Comprehensive
Loss Total
Stock-holders'
Equity
Balance at December 31, 2021 $ 4 $ 8,531 $ 464 $ (5,273) $ (126) $ 3,600
Net income 1,736 1,736
Other comprehensive income 8 8
Share repurchases (187) (187)
Equity-based awards activity, net(a)
2 2
Common stock dividends and dividend equivalents declared(b)
(86) (86)
Adoption of ASU 2020-06 (100) 57 (43)
Balance at March 31, 2022 $ 4 $ 8,433 $ 2,171 $ (5,460) $ (118) $ 5,030
Net income 513 513
Other comprehensive loss (2) (2)
Shares reissuance for ESPP 1 2 3
Share repurchases (168) (168)
Equity-based awards activity, net 8 8
Common stock dividends and dividend equivalents declared(b)
(84) (84)
Balance at June 30, 2022 $ 4 $ 8,442 $ 2,600 $ (5,626) $ (120) $ 5,300
Net income 67 67
Other comprehensive loss (34) (34)
Share repurchases (128) (128)
Equity-based awards activity, net 8 8
Common stock dividends and dividend equivalents declared(b)
(83) (83)
Balance at September 30, 2022 $ 4 $ 8,450 $ 2,584 $ (5,754) $ (154) $ 5,130


(In millions)	(In millions)	Common Stock		Additional Paid-In Capital		Accumulated Deficit		Treasury Stock		Accumulated Other Comprehensive Loss		Total Stock-holders' Equity		(In millions)	Preferred Stock		Common Stock		Additional Paid-In Capital		Retained Earnings		Treasury Stock		Accumulated Other Comprehensive Loss		Total Stock-holders' Equity
Balance at December 31, 2020		$	4	$	8,517	$	(1,403)	$	(5,232)	$	(206)	$	1,680
Balance at December 31, 2022														Balance at December 31, 2022	$	—	$	4	$	8,457	$	1,408	$	(5,864)	$	(177)	$	3,828
Net loss	Net loss					(82)						(82)		Net loss							(1,335)						(1,335)
Issuance of Series A Preferred Stock														Issuance of Series A Preferred Stock	650				(14)								636
Other comprehensive income	Other comprehensive income									3		3		Other comprehensive income											1		1

Equity-based awards activity, net(a)	Equity-based awards activity, net(a)			(5)								(5)		Equity-based awards activity, net(a)					38								38
Issuance of common stock				1								1
Common stock dividends and dividend equivalents declared(b)						(80)						(80)
Balance at March 31, 2021		$	4	$	8,513	$	(1,565)	$	(5,232)	$	(203)	$	1,517
Net income						1,078						1,078
Other comprehensive income										21		21

Shares reissuance for ESPP								2				2

Equity-based awards activity, net				6								6

Common stock dividends and dividend equivalents declared(b)	Common stock dividends and dividend equivalents declared(b)					(80)						(80)		Common stock dividends and dividend equivalents declared(b)							(88)						(88)

Balance at June 30, 2021		$	4	$	8,519	$	(567)	$	(5,230)	$	(182)	$	2,544
Balance at March 31, 2023														Balance at March 31, 2023	$	650	$	4	$	8,481	$	(15)	$	(5,864)	$	(176)	$	3,080
Net income	Net income					1,618						1,618		Net income							308						308
Other comprehensive loss										(10)		(10)
Issuance of Series A Preferred Stock														Issuance of Series A Preferred Stock					(1)								(1)
Other comprehensive income														Other comprehensive income											6		6
Shares reissuance for ESPP														Shares reissuance for ESPP					1				3				4

Equity-based awards activity, net				6								6
Equity-based awards activity, net(a)														Equity-based awards activity, net(a)					23								23

Common stock dividends and dividend equivalents declared(b)	Common stock dividends and dividend equivalents declared(b)					(80)						(80)		Common stock dividends and dividend equivalents declared(b)							(88)						(88)

Balance at June 30, 2023														Balance at June 30, 2023	$	650	$	4	$	8,504	$	205	$	(5,861)	$	(170)	$	3,332
Net income														Net income							343						343
Other comprehensive loss														Other comprehensive loss											(7)		(7)
Share repurchases														Share repurchases									(50)				(50)
Equity-based awards activity, net(a)														Equity-based awards activity, net(a)					23								23

Balance at September 30, 2021		$	4	$	8,525	$	971	$	(5,230)	$	(192)	$	4,078
Common stock dividends and dividend equivalents declared(b)														Common stock dividends and dividend equivalents declared(b)							(89)						(89)
Series A Preferred Stock dividends(c)														Series A Preferred Stock dividends(c)							(34)						(34)
Balance at September 30, 2023														Balance at September 30, 2023	$	650	$	4	$	8,527	$	425	$	(5,911)	$	(177)	$	3,518

(a)Includes ~~$(6)~~$(8) million, $(8) million and ~~$(9)~~$(3) million of equivalent shares purchased in lieu of tax withholding on equity compensation issuances for the quarters ended March 31, ~~2022~~2023, June 30, 2023 and ~~2021,~~September 30, 2023, respectively

(b)Dividends per common share were $0.3775 for the quarters ended September 30, June 30 and March 31, 2023

(c)Dividend per Series A Preferred Stock was $52.96


(In millions)	Common Stock		Additional Paid-In Capital		Retained Earnings		Treasury Stock		Accumulated Other Comprehensive Loss		Total Stock-holders' Equity
Balance at December 31, 2021	$	4	$	8,531	$	464	$	(5,273)	$	(126)	$	3,600
Net income					1,736						1,736
Other comprehensive income									8		8

Share repurchases							(187)				(187)
Equity-based awards activity, net(a)			2								2

Common stock dividends and dividend equivalents declared(b)					(86)						(86)
Adoption of ASU 2020-06			(100)		57						(43)
Balance at March 31, 2022	$	4	$	8,433	$	2,171	$	(5,460)	$	(118)	$	5,030
Net income					513						513
Other comprehensive loss									(2)		(2)

Shares reissuance for ESPP			1				2				3
Share repurchases							(168)				(168)
Equity-based awards activity, net			8								8

Common stock dividends and dividend equivalents declared(b)					(84)						(84)






Balance at June 30, 2022	$	4	$	8,442	$	2,600	$	(5,626)	$	(120)	$	5,300
Net income					67						67
Other comprehensive loss									(34)		(34)

Share repurchases							(128)				(128)
Equity-based awards activity, net			8								8

Common stock dividends and dividend equivalents declared(b)					(83)						(83)




Balance at September 30, 2022	$	4	$	8,450	$	2,584	$	(5,754)	$	(154)	$	5,130

(a)Includes $(6) million of equivalent shares purchased in lieu of tax withholding on equity compensation issuances for the quarter ended March 31, 2022

(b)Dividends per common share were $0.35 for the quarters ended September 30, June 30 and March 31, 2022 ~~and $0.325 for the quarters ended September 30, June 30 and March 31, 2021~~

See accompanying notes to condensed consolidated financial statements.

1214

NRG ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 — Nature of Business and Basis of Presentation

General

NRG Energy, Inc., or NRG or the Company, is a ~~consumer~~leading energy, smart home and services company ~~built on dynamic retail brands. NRG brings~~fueled by market-leading brands, proprietary technologies, and complementary sales channels. Across the ~~power of energy to customers by producing and selling energy and related products and services, nation-wide in the U.S.~~United States and Canada, ~~in a manner that~~NRG delivers ~~value to all of NRG's stakeholders. NRG sells power, natural gas, home and power services, and develops~~ innovative, sustainable solutions, predominately under ~~the~~ brand names such as NRG, Reliant, Direct Energy, Green Mountain Energy ~~Stream,~~ and ~~XOOM Energy.~~Vivint, while also advocating for competitive energy markets and customer choice. The Company has a customer base that includes approximately ~~5.5~~7.5 million ~~Home customers as well as~~residential consumers in addition to commercial, industrial, and wholesale customers, supported by approximately 1615 GW of ~~generation.~~

~~The Company manages its operations based on the combined results~~generation as of ~~the retail and wholesale generation businesses with a geographical focus.~~September 30, 2023.

The Company's business is segmented as follows:

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

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

•West/Services/Other, which includes the following assets and activities: (i) all activity related to customer, plant and market operations in the West and Canada, (ii) the Services businesses (iii) activity related to the Cottonwood facility, (iv) the remaining renewables activity, including the Company’s equity method investment in Ivanpah Master Holdings, LLC, and (v) activity related to the Company’s equity method investment for the Gladstone power plant in Australia;

•Vivint Smart Home; and

•Corporate activities.

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~~GAAP for complete financial statements. The following notes should be read in conjunction with the accounting policies and other disclosures as set forth in the notes to the consolidated financial statements in the Company's ~~2021~~2022 Form 10-K. Interim results are not necessarily indicative of results for a full year.

In the opinion of management, the accompanying unaudited interim condensed consolidated financial statements contain all material adjustments consisting of normal and recurring accruals necessary to present fairly the Company's consolidated financial position as of September 30, ~~2022,~~2023, and the results of operations, comprehensive income, cash flows and statements of stockholders' equity for the three and nine months ended September 30, ~~2022~~2023 and ~~2021.~~2022.

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 period amounts have been reclassified for comparative purposes. The reclassifications did not affect consolidated results from operations, net assets or consolidated cash flows.

Note 2 — Summary of Significant Accounting Policies

Vivint Smart Home Flex Pay

Under the Flex Pay plan (“Flex Pay”), offered by Vivint Smart Home, subscribers pay separately for smart home products and smart home and security services. The subscriber has the ability to pay for Vivint Smart Home products in the following three ways: (i) qualified subscribers may finance the purchase through third-party financing providers ("Consumer Financing Program" or “CFP”), (ii) Vivint Smart Home generally offers a limited number of subscribers not eligible for the CFP, but who qualify under Vivint Smart Home underwriting criteria, the option to enter into a retail installment contract directly with Vivint Smart Home or (iii) subscribers may conduct purchases by check, automatic clearing house payments, credit or debit card or by obtaining short term financing (generally no more than six-month installment terms) through Vivint Smart Home.

Although subscribers pay separately for products and services under Flex Pay, the Company has determined that the sale of products and services are one single performance obligation resulting in deferred revenue for the gross amount of products

sold. For products financed through the CFP, gross deferred revenues are reduced by (i) any fees the third-party financing provider (“Financing Provider”) is contractually entitled to receive at the time of loan origination, and (ii) the present value of expected future payments due to the Financing Providers. Loans are issued on either an installment or revolving basis with repayment terms ranging from 6 to 60 months.

For certain Financing Provider loans:

•Vivint Smart Home pays a monthly fee based on either the average daily outstanding balance of the installment loans, or the number of outstanding loans.

•Vivint Smart Home incurs fees at the time of the loan origination and receives proceeds that are net of these fees.

•Vivint Smart Home also shares liability for credit losses, with Vivint Smart Home being responsible for between 2.6% and 100% of lost principal balances.

Due to the nature of these provisions, the Company records a derivative liability at its fair value when the Financing Provider originates loans to subscribers, which reduces the amount of estimated revenue recognized on the provision of the services. The derivative liability is reduced as payments are made by Vivint Smart Home to the Financing Provider. Subsequent changes to the fair value of the derivative liability are realized through other income, net in the consolidated statements of operations. For further discussion, see Note 7, Accounting for Derivative Instruments and Hedging Activities.

Capitalized Contract Costs

Capitalized contract costs represent the costs directly related and incremental to the origination of new contracts, modification of existing contracts or to the fulfillment of the related subscriber contracts. These costs include installed products, commissions, other compensation and the cost of installation of new or upgraded customer contracts. The Company calculates amortization by accumulating all deferred contract costs into separate portfolios based on the initial month of service and amortizes those deferred contract costs on a straight-line basis over the expected period of benefit, consistent with the pattern in which the Company provides services to its customers. The expected period of benefit for customers is approximately five years. The Company updates its estimate of the expected period of benefit periodically and whenever events or circumstances indicate that the expected period of benefit could change significantly. Such changes, if any, are accounted for prospectively as a change in estimate. Amortization of capitalized contract costs related to fulfillment are included in cost of operations and amortization of capitalized contract costs related to customer acquisition are included in selling, general and administrative costs in the consolidated statements of operations. Contract costs not directly related and incremental to the origination of new contracts, modification of existing contracts or to the fulfillment of the related subscriber contracts are expensed as incurred.

Other Balance Sheet Information

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


(In millions)	(In millions)	September 30, 2022		December 31, 2021		(In millions)	September 30, 2023		December 31, 2022
Property, plant and equipment accumulated depreciation	Property, plant and equipment accumulated depreciation	$	1,456	$	1,308	Property, plant and equipment accumulated depreciation	$	1,390	$	1,478
Intangible assets accumulated amortization		1,989		1,636
Customer relationships and other intangible assets accumulated amortization						Customer relationships and other intangible assets accumulated amortization	2,563		2,112

Credit Losses

Retail trade receivables are reported on the consolidated balance sheet net of the allowance for credit ~~losses.~~losses within accounts receivables, net. Long-term receivables are recorded net in other non-current assets on the consolidated balance sheet. The Company accrues a provision 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 nine months ended September 30, ~~2022~~2023 and ~~2021:~~2022:


		Three months ended September 30,				Nine months ended September 30,					Three months ended September 30,				Nine months ended September 30,
(In millions)	(In millions)	2022		2021		2022		2021		(In millions)	2023		2022		2023		2022
Beginning balance	Beginning balance	$	627	$	761	$	683	$	67	Beginning balance	$	120	$	627	$	133	$	683
Acquired balance from Direct Energy		—		—		—		112
Acquired balance from Vivint Smart Home										Acquired balance from Vivint Smart Home	—		—		22		—
Provision for credit losses	Provision for credit losses	52		64		103		715		Provision for credit losses	85		52		165		103
Write-offs	Write-offs	(50)		(41)		(171)		(124)		Write-offs	(59)		(50)		(203)		(171)
Recoveries collected	Recoveries collected	9		8		23		22		Recoveries collected	9		9		30		23
Other										Other	3		—		11		—
Ending balance	Ending balance	$	638	$	792	$	638	$	792	Ending balance	$	158	$	638	$	158	$	638

The decrease in the provision for credit losses during the nine months ended September 30, 2022, compared to the same period in 2021 was primarily due to the impacts of Winter Storm Uri during the prior year on bilateral finance hedging risk of $403 million, counterparty credit risk of $152 million and ERCOT default shortfall payments of $83 million.

Cash and Cash Equivalents, Funds Deposited by Counterparties and 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)	(In millions)	September 30, 2022		December 31, 2021		(In millions)	September 30, 2023		December 31, 2022
Cash and cash equivalents	Cash and cash equivalents	$	333	$	250	Cash and cash equivalents	$	401	$	430
Funds deposited by counterparties	Funds deposited by counterparties	3,134		845		Funds deposited by counterparties	263		1,708
Restricted cash	Restricted cash	46		15		Restricted cash	11		40
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows	Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows	$	3,513	$	1,110	Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows	$	675	$	2,178

Funds deposited by counterparties consist of cash held by the Company as a result of collateral posting obligations from its counterparties related to NRG's hedging program. The ~~increase~~decrease in funds deposited by counterparties is driven by the significant ~~increase~~decrease in forward positions as a result of ~~increases~~decreases in natural gas and power prices compared to December 31, ~~2021.~~2022. Though some amounts are segregated into separate accounts, not all funds are contractually restricted. Based on the Company's intention, these funds are not available for the payment of general corporate obligations; however, they are available for liquidity management. Depending on market fluctuations and the settlement of the underlying contracts, the Company will refund this collateral to the counterparties pursuant to the terms and conditions of the underlying trades. Since collateral requirements fluctuate daily and the Company cannot predict if any collateral will be held for more than twelve months, the funds deposited by counterparties are classified as a current asset on the Company's balance sheet, with an offsetting liability for this cash collateral received within current liabilities.

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

~~Winter Storm Uri Uplift Securitization Proceeds~~

The Texas Legislature passed House Bill ("HB") 4492 in May of 2021 for ERCOT to mitigate exceptionally high price adders and ancillary service costs incurred by LSEs during Winter Storm Uri. HB 4492 authorized ERCOT to obtain $2.1 billion of financing to distribute to LSEs that were charged and paid to ERCOT those highly priced ancillary service and ORDPA during Winter Storm Uri.

In December 2021, ERCOT filed with the PUCT a calculation of each LSE’s share of proceeds based on the settlement methodology. The Company accounted for the proceeds by analogy to the contribution model within ASC 958-605, ~~Not-for-Profit Entities- Revenue Recognition~~ ~~and the grant model within IAS 20,~~ ~~Accounting for Government Grants and Disclosure of Government Assistance~~, as a reduction to cost of operations within its consolidated statements of operations in the 2021 annual period for which the proceeds were intended to compensate. The Company received proceeds of $689 million from ERCOT in June 2022.

Goodwill

The following table ~~represents~~presents the changes in goodwill during the nine months ended September 30, ~~2022:~~2023:

(In millions) Texas East West/Services/Other Total
Balance as of December 31, 2021 $ 751 $ 853 $ 191 $ 1,795
Impairment — (130) — (130)
Asset sales (6) — — (6)
Foreign Currency Translation — — (9) (9)
Balance as of September 30, 2022 $ 745 $ 723 $ 182 $ 1,650


(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Total
Balance as of December 31, 2022	$	710	$	723	$	217	$	—	$	1,650
Goodwill resulting from the acquisition of Vivint Smart Home	—		—		—		3,494		3,494

Sale of business	—		(2)		—		—		(2)
Foreign currency translation adjustments	—		—		1		—		1
Balance as of September 30, 2023	$	710	$	721	$	218	$	3,494	$	5,143

Recent Accounting Developments - Guidance Adopted in ~~2022~~2023

ASU ~~2020-06~~ 2021-08— In ~~August 2020,~~October 2021, the FASB issued ASU No. ~~2020-06,~~2021-08, ~~Debt - Debt~~Business Combinations (Topic 805): Accounting for Contract Assets and Contract Liabilities from Contracts with ~~Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40)~~Customers, or ASU ~~2020-06.~~2021-08, which requires that an entity recognize and measure contract assets and contract liabilities acquired in a business combination as if it had originated the contracts in accordance with ASC 606, Revenue from Contracts with Customers. As a result, an acquirer should recognize and

measure the acquired contract assets and contract liabilities consistently with how they were recognized and measured in the acquiree’s financial statements. The ~~guidance~~amendments per ASU 2021-08 apply only to contract assets and contract liabilities from contracts with customers, as defined in Topic 606, such as refund liabilities and upfront payments to customers. Assets and liabilities under related Topics, such as deferred costs under Subtopic 340-40, Other Assets and Deferred Costs — Contracts with Customers, are not within the scope of amendments per ASU ~~2020-06 reduces the number of accounting models for convertible debt instruments and convertible preferred stock. In addition, ASU 2020-06 improves and amends the related earnings per share guidance.~~2021-08. The Company adopted ~~this standard on~~ASU 2021-08 prospectively effective January 1, ~~2022 using the modified retrospective approach. As a result of the provisions of~~2023 and applied the amended ~~guidance,~~requirements to the Company recorded a $100 million decrease to additional paid-in capital, a $57 million decrease to debt discount, a $57 million increase to retained earnings and a $14 million decrease to long-term deferred tax liabilities. The adoptionacquisition of ~~ASU 2020-06 did not have a material impact on the Company's statement of operations, statement of cash flow or earnings per share amounts.~~Vivint Smart Home.

Note 3 — Revenue Recognition

Vivint Smart Home Retail Revenue

Vivint Smart Home offers its subscribers combinations of smart home products and services, which together create an integrated smart home system that allows the Company's subscribers to monitor, control and protect their homes. As the products and services included in the subscriber's contract are integrated and highly interdependent, and because the products (including installation) and services must work together to deliver the monitoring, controlling and protection of their home, the Company has concluded that the products and services contracted for by the subscriber are generally not distinct within the context of the contract and, therefore, constitute a single, combined performance obligation. Revenues for this single, combined performance obligation are recognized on a straight-line basis over the subscriber's contract term, which is the period in which the parties to the contract have enforceable rights and obligations. The Company has determined that certain contracts that do not require a long-term commitment for monitoring services by the subscriber contain a material right to renew the contract, because the subscriber does not have to purchase the products upon renewal. Proceeds allocated to the material right are recognized over the expected period of benefit. The majority of Vivint Smart Home's subscription contracts are five years and are generally non-cancelable. These contracts generally convert into month-to-month agreements at the end of the initial term, while some subscribers are month-to-month from inception. Payment for Vivint Smart Home services is generally due in advance on a monthly basis. Product sales and other one-time fees are invoiced to subscribers at time of sale. Revenues for any products or services that are considered separate performance obligations are recognized upon delivery. Payments received or billed in advance are reported as deferred revenues.

Performance Obligations

As of September 30, ~~2022,~~2023, estimated future fixed fee performance obligations are ~~$31~~$414 million for the remaining three months of fiscal year ~~2022,~~2023, and ~~$77~~$1.4 billion, $1.0 billion, $722 million, ~~$23~~$434 million and $2$103 million for the fiscal years ~~2023,~~ 2024, 2025, 2026, 2027 and ~~2025,~~2028, respectively. These performance obligations ~~are for~~include Vivint Smart Home products and services as well as cleared auction MWs in the PJM, ISO-NE, NYISO and MISO capacity ~~auctions and~~auctions. The cleared auction MWs are subject to penalties for non-performance.

1518

Disaggregated Revenues

The following tables represent the Company’s disaggregation of revenue from contracts with customers for the three and nine months ended September 30, ~~2022~~2023 and ~~2021:~~2022:


		Three months ended September 30, 2022											Three months ended September 30, 2023
(In millions)	(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total		(In millions)	Texas		East		West/Services/Other		Vivint Smart Home(a)		Corporate/Eliminations		Total
Retail revenue:	Retail revenue:											Retail revenue:
Home(a)	Home(a)	$	2,074	$	546	$	429	$	—	$	3,049	Home(a)	$	2,397	$	544	$	390	$	478	$	(1)	$	3,808
Business	Business	931		3,317		561		—		4,809		Business	1,092		2,089		532		—		—		3,713
Total retail revenue(b)	Total retail revenue(b)	3,005		3,863		990		—		7,858		Total retail revenue(b)	3,489		2,633		922		478		(1)		7,521
Energy revenue(b)	Energy revenue(b)	48		212		180		10		450		Energy revenue(b)	51		152		59		—		(1)		261
Capacity revenue(b)	Capacity revenue(b)	—		38		—		—		38		Capacity revenue(b)	—		64		(4)		—		(1)		59
Mark-to-market for economic hedging activities(c)	Mark-to-market for economic hedging activities(c)	4		32		(7)		4		33		Mark-to-market for economic hedging activities(c)	—		(60)		(10)		—		—		(70)
Contract amortization	Contract amortization	—		(10)		4		—		(6)		Contract amortization	—		(6)		1		—		—		(5)
Other revenue(b)	Other revenue(b)	92		45		2		(2)		137		Other revenue(b)	146		26		10		—		(2)		180
Total revenue	Total revenue	3,149		4,180		1,169		12		8,510		Total revenue	3,686		2,809		978		478		(5)		7,946
Less: Revenues accounted for under topics other than ASC 606 and ASC 815	Less: Revenues accounted for under topics other than ASC 606 and ASC 815	—		3		14		(1)		16		Less: Revenues accounted for under topics other than ASC 606 and ASC 815	—		8		10		—		—		18
Less: Realized and unrealized ASC 815 revenue	Less: Realized and unrealized ASC 815 revenue	15		93		13		14		135		Less: Realized and unrealized ASC 815 revenue	16		58		(7)		—		—		67
Total revenue from contracts with customers	Total revenue from contracts with customers	$	3,134	$	4,084	$	1,142	$	(1)	$	8,359	Total revenue from contracts with customers	$	3,670	$	2,743	$	975	$	478	$	(5)	$	7,861
(a) Home includes Services
(a) Home includes Services and Vivint Smart Home												(a) Home includes Services and Vivint Smart Home
(b) 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)	(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total		(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue	Retail revenue	$	—	$	90	$	—	$	—	$	90	Retail revenue	$	—	$	14	$	—	$	—	$	—	$	14
Energy revenue	Energy revenue	—		(39)		27		11		(1)		Energy revenue	—		77		—		—		—		77
Capacity revenue	Capacity revenue	—		7		—		—		7		Capacity revenue	—		27		—		—		—		27
Other revenue	Other revenue	11		3		(7)		(1)		6		Other revenue	16		—		3		—		—		19
(c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815	(c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815											(c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815

1619


		Three months ended September 30, 2021											Three months ended September 30, 2022
(In millions)	(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total		(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Retail revenue:	Retail revenue:											Retail revenue:
Home(a)	Home(a)	$	1,776	$	470	$	399	$	1	$	2,646	Home(a)	$	2,068	$	530	$	435	$	—	$	3,033
Business	Business	727		2,228		350		—		3,305		Business	931		3,333		561		—		4,825
Total retail revenue	Total retail revenue	2,503		2,698		749		1		5,951		Total retail revenue	2,999		3,863		996		—		7,858
Energy revenue(b)	Energy revenue(b)	18		201		113		4		336		Energy revenue(b)	48		212		180		10		450
Capacity revenue(b)	Capacity revenue(b)	—		172		17		—		189		Capacity revenue(b)	—		38		—		—		38
Mark-to-market for economic hedging activities(c)	Mark-to-market for economic hedging activities(c)	(1)		(3)		(6)		13		3		Mark-to-market for economic hedging activities(c)	4		32		(7)		4		33
Contract amortization	Contract amortization	—		(7)		4		—		(3)		Contract amortization	—		(10)		4		—		(6)
Other revenue(b)	Other revenue(b)	115		16		6		(4)		133		Other revenue(b)	94		43		2		(2)		137
Total revenue	Total revenue	2,635		3,077		883		14		6,609		Total revenue	3,145		4,178		1,175		12		8,510
Less: Revenues accounted for under topics other than ASC 606 and ASC 815	Less: Revenues accounted for under topics other than ASC 606 and ASC 815	—		(7)		6		—		(1)		Less: Revenues accounted for under topics other than ASC 606 and ASC 815	—		3		14		(1)		16
Less: Realized and unrealized ASC 815 revenue	Less: Realized and unrealized ASC 815 revenue	38		76		(8)		14		120		Less: Realized and unrealized ASC 815 revenue	15		93		13		14		135
Total revenue from contracts with customers	Total revenue from contracts with customers	$	2,597	$	3,008	$	885	$	—	$	6,490	Total revenue from contracts with customers	$	3,130	$	4,082	$	1,148	$	(1)	$	8,359
(a) Home includes Services																							(b) 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)	(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total		(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Retail revenue												Retail revenue	$	—	$	90	$	—	$	—	$	90
Energy revenue	Energy revenue	$	—	$	38	$	2	$	1	$	41	Energy revenue	—		(39)		27		11		(1)
Capacity revenue	Capacity revenue	—		42		—		—		42		Capacity revenue	—		7		—		—		7
Other revenue	Other revenue	39		(1)		(4)		—		34		Other revenue	11		3		(7)		(1)		6
(c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815	(c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815											(c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815


		Nine months ended September 30, 2022											Nine months ended September 30, 2023
(In millions)	(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total		(In millions)	Texas		East		West/Services/Other		Vivint Smart Home(a)(b)		Corporate/Eliminations		Total
Retail revenue:	Retail revenue:											Retail revenue:
Home~~(a)~~(b)	Home~~(a)~~(b)	$	5,024	$	1,674	$	1,663	$	(1)	$	8,360	Home~~(a)~~(b)	$	5,196	$	1,641	$	1,421	$	1,070	$	(1)	$	9,327
Business	Business	2,504		10,110		1,405		—		14,019		Business	2,646		7,366		1,572		—		—		11,584
Total retail revenue~~(b)~~(c)	Total retail revenue~~(b)~~(c)	7,528		11,784		3,068		(1)		22,379		Total retail revenue~~(b)~~(c)	7,842		9,007		2,993		1,070		(1)		20,911
Energy revenue~~(b)~~(c)	Energy revenue~~(b)~~(c)	101		544		365		24		1,034		Energy revenue~~(b)~~(c)	71		254		147		—		—		472
Capacity revenue~~(b)~~(c)	Capacity revenue~~(b)~~(c)	—		242		2		—		244		Capacity revenue~~(b)~~(c)	—		154		(3)		—		(1)		150
Mark-to-market for economic hedging activities~~(c)~~(d)	Mark-to-market for economic hedging activities~~(c)~~(d)	1		(204)		(63)		18		(248)		Mark-to-market for economic hedging activities~~(c)~~(d)	—		27		80		—		(11)		96
Contract amortization	Contract amortization	—		(30)		2		—		(28)		Contract amortization	—		(24)		—		—		—		(24)
Other revenue~~(b)~~(c)	Other revenue~~(b)~~(c)	238		78		3		(12)		307		Other revenue~~(b)~~(c)	322		70		27		—		(8)		411
Total revenue	Total revenue	7,868		12,414		3,377		29		23,688		Total revenue	8,235		9,488		3,244		1,070		(21)		22,016
Less: Revenues accounted for under topics other than ASC 606 and ASC 815	Less: Revenues accounted for under topics other than ASC 606 and ASC 815	—		(10)		33		(1)		22		Less: Revenues accounted for under topics other than ASC 606 and ASC 815	—		13		26		—		—		39
Less: Realized and unrealized ASC 815 revenue	Less: Realized and unrealized ASC 815 revenue	(5)		(96)		(99)		41		(159)		Less: Realized and unrealized ASC 815 revenue	28		270		97		—		(10)		385
Total revenue from contracts with customers	Total revenue from contracts with customers	$	7,873	$	12,520	$	3,443	$	(11)	$	23,825	Total revenue from contracts with customers	$	8,207	$	9,205	$	3,121	$	1,070	$	(11)	$	21,592
(a) Home includes Services
(b) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 and included in the amounts above:
(a) Includes results of operations following the acquisition date of March 10, 2023												(a) Includes results of operations following the acquisition date of March 10, 2023
(b) Home includes Services and Vivint Smart Home												(b) Home includes Services and Vivint Smart Home
(c) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 and included in the amounts above:												(c) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 and included in the amounts above:
(In millions)	(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total		(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue	Retail revenue	$	—	$	90	$	—	$	—	$	90	Retail revenue	$	—	$	57	$	—	$	—	$	—	$	57
Energy revenue	Energy revenue	—		(13)		(13)		24		(2)		Energy revenue	—		137		10		—		1		148
Capacity revenue	Capacity revenue	—		29		—		—		29		Capacity revenue	—		50		—		—		—		50
Other revenue	Other revenue	(6)		2		(23)		(1)		(28)		Other revenue	28		(1)		7		—		—		34
(c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815
(d) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815												(d) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815

1720


		Nine months ended September 30, 2021											Nine months ended September 30, 2022
(In millions)	(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total		(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Retail revenue:	Retail revenue:											Retail revenue:
Home(a)	Home(a)	$	4,484	$	1,469	$	1,439	$	(1)	$	7,391	Home(a)	$	5,006	$	1,526	$	1,681	$	(1)	$	8,212
Business	Business	2,091		6,560		887		—		9,538		Business	2,504		10,258		1,405		—		14,167
Total retail revenue	Total retail revenue	6,575		8,029		2,326		(1)		16,929		Total retail revenue	7,510		11,784		3,086		(1)		22,379
Energy revenue~~(c)~~(b)	Energy revenue~~(c)~~(b)	317		428		238		6		989		Energy revenue~~(c)~~(b)	101		544		365		24		1,034
Capacity revenue~~(c)~~(b)	Capacity revenue~~(c)~~(b)	—		568		47		—		615		Capacity revenue~~(c)~~(b)	—		242		2		—		244
Mark-to-market for economic hedging activities~~(d)~~(c)	Mark-to-market for economic hedging activities~~(d)~~(c)	(5)		(53)		(60)		19		(99)		Mark-to-market for economic hedging activities~~(d)~~(c)	1		(204)		(63)		18		(248)
Contract amortization	Contract amortization	—		(15)		(4)		—		(19)		Contract amortization	—		(30)		2		—		(28)
Other revenue~~(c)~~(b)	Other revenue~~(c)~~(b)	1,475		45		17		(9)		1,528		Other revenue~~(c)~~(b)	245		71		3		(12)		307
Total revenue	Total revenue	8,362		9,002		2,564		15		19,943		Total revenue	7,857		12,407		3,395		29		23,688
Less: Revenues accounted for under topics other than ASC 606 and ASC 815	Less: Revenues accounted for under topics other than ASC 606 and ASC 815	—		(14)		1		—		(13)		Less: Revenues accounted for under topics other than ASC 606 and ASC 815	—		(10)		33		(1)		22
Less: Realized and unrealized ASC 815 revenue	Less: Realized and unrealized ASC 815 revenue	129		193		(73)		20		269		Less: Realized and unrealized ASC 815 revenue	(5)		(96)		(99)		41		(159)
Total revenue from contracts with customers	Total revenue from contracts with customers	$	8,233	$	8,823	$	2,636	$	(5)	$	19,687	Total revenue from contracts with customers	$	7,862	$	12,513	$	3,461	$	(11)	$	23,825
(a) Home includes Services
(b) Other Revenue in Texas includes ancillary revenues of $1.2 billion driven by high pricing during Winter Storm Uri
(c) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 and included in the amounts above:
(b) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 and included in the amounts above:												(b) 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)	(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total		(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Retail revenue												Retail revenue	$	—	$	90	$	—	$	—	$	90
Energy revenue	Energy revenue	$	—	$	122	$	(4)	$	2	$	120	Energy revenue	—		(13)		(13)		24		(2)
Capacity revenue	Capacity revenue	—		119		—		—		119		Capacity revenue	—		29		—		—		29
Other revenue	Other revenue	134		5		(9)		(1)		129		Other revenue	(6)		2		(23)		(1)		(28)
(d) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815
(c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815												(c) 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 September 30, ~~2022~~2023 and December 31, ~~2021:~~2022:


(In millions)	(In millions)	September 30, 2022		December 31, 2021		(In millions)	September 30, 2023		December 31, 2022
Deferred customer acquisition costs		$	117	$	133
Capitalized contract costs						Capitalized contract costs	$	639	$	126

Accounts receivable, net - Contracts with customers	Accounts receivable, net - Contracts with customers	3,768		3,057		Accounts receivable, net - Contracts with customers	3,553		4,704
Accounts receivable, net - Accounted for under topics other than ASC 606	Accounts receivable, net - Accounted for under topics other than ASC 606	290		182		Accounts receivable, net - Accounted for under topics other than ASC 606	188		64
Accounts receivable, net - Affiliate	Accounts receivable, net - Affiliate	3		6		Accounts receivable, net - Affiliate	23		5
Total accounts receivable, net	Total accounts receivable, net	$	4,061	$	3,245	Total accounts receivable, net	$	3,764	$	4,773

Unbilled revenues (included within Accounts receivable, net - Contracts with customers)	Unbilled revenues (included within Accounts receivable, net - Contracts with customers)	$	1,464	$	1,574	Unbilled revenues (included within Accounts receivable, net - Contracts with customers)	$	1,336	$	1,952

Deferred revenues(a)	Deferred revenues(a)	213		227		Deferred revenues(a)	1,720		186

(a) Deferred revenues from contracts with customers ~~for the nine months ended~~as of September 30, ~~2022~~2023 and ~~the year ended~~ December 31, ~~2021~~2022 were approximately ~~$207~~$1.7 billion and $175 million, ~~and $224 million, respectively~~respectively. The increase in deferred revenues is primarily due to the acquisition of Vivint Smart Home

The revenue recognized from contracts with customers during the nine months ended September 30, ~~2022~~2023 and ~~2021~~2022 relating to the deferred revenue balance at the beginning of each period was $168 million and $173 million, respectively. The change in deferred revenue balances recognized during the nine months ended September 30, 2023 and ~~$23 million, respectively.~~2022 was primarily due to the timing difference of when consideration was received and when the performance obligation was transferred. The revenue recognized from contracts with customers during the three months ended September 30, ~~2022~~2023 and ~~2021~~2022 relating to the deferred revenue balance at the beginning of each period was ~~$159~~$310 million and ~~$162~~$159 million, respectively. The change in deferred revenue balances recognized during the three ~~and nine~~ months ended September 30, ~~2022 and 2021~~2023 was primarily due to the ~~usage~~acquisition of ~~customer bill credits by certain C&I customers, which were as a result of power pricing during Winter Storm Uri.~~Vivint Smart Home.

1821

Note 4 — Acquisitions and Dispositions

Acquisitions

~~2021~~Vivint Smart Home Acquisition ~~of Direct Energy~~

On ~~January 5, 2021,~~March 10, 2023 (the "Acquisition Closing Date"), the Company ~~acquired all~~completed the acquisition of Vivint Smart Home, Inc., pursuant to the Agreement and Plan of Merger, dated as of December 6, 2022, by and among the Company, Vivint Smart Home, Inc. and Jetson Merger Sub, Inc., a wholly-owned subsidiary of the ~~issued~~Company (“Merger Sub”) pursuant to which Merger Sub merged with and ~~outstanding common shares of Direct Energy, which had been~~into Vivint Smart Home, Inc., with Vivint Smart Home, Inc. surviving the merger as a ~~North American~~wholly-owned subsidiary of ~~Centrica. Direct Energy is a leading retail provider of electricity, natural gas, and~~the Company. Dedicated to redefining the home ~~and business energy related~~experience with intelligent products and services, ~~in North America, with operations in all 50 U.S. states~~Vivint Smart Home brings approximately two million subscribers to NRG. Vivint Smart Home's single, expandable platform incorporates artificial intelligence and ~~8 Canadian provinces.~~machine learning into its operating system and its vertically integrated business model includes hardware, software, sales, installation, support and professional monitoring, enabling superior subscriber experiences and a complete end-to-end smart home experience. The acquisition accelerates the realization of NRG's consumer-focused growth strategy and creates a leading essential home services platform fueled by market-leading brands, unparalleled insights, proprietary technologies and complementary sales channels.

NRG paid $12 per share, or $2.6 billion in cash. The Company funded the acquisition using:

•proceeds of $724 million from newly issued $740 million 7.000% Senior Secured First Lien Notes due 2033, net of issuance costs and discount;

•proceeds of $635 million from newly issued $650 million 10.25% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock, net of issuance costs;

•proceeds of approximately $900 million drawn from its Revolving Credit Facility and Receivables Securitization Facilities; and

•cash on hand.

In February 2023, the Company increased ~~NRG's retail portfolio~~its Revolving Credit Facility by ~~over 3~~$600 million ~~customers~~to meet the additional liquidity requirements related to the acquisition. For further discussion, see Note 9, Long-term Debt and ~~strengthens its integrated model. It also broadens~~Finance Leases.

Acquisition costs of $38 million for the nine months ended September 30, 2023 are included in acquisition-related transaction and integration costs in the Company's ~~presence~~consolidated statement of operations.

The acquisition has been recorded as a business combination under ASC 805, with identifiable assets and liabilities acquired provisionally recorded at their estimated Acquisition Closing Date fair value. The initial accounting for the business combination is not complete because the evaluation necessary to assess the fair value of certain net assets acquired and the amount of goodwill to be recognized is still in process. The provisional amounts are subject to revision until the evaluations are completed to the extent that additional information is obtained about the facts and circumstances that existed as of the Acquisition Closing Date.

The total consideration of $2.623 billion includes:


	(In millions)
Vivint Smart Home, Inc. common shares outstanding as of March 10, 2023 of 216,901,639 at $12.00 per share	$	2,603
Other Vivint Smart Home, Inc. equity instruments (Cash out RSUs and PSUs, Stock Appreciation Rights, Private Placement Warrants)	6
Total Cash Consideration	$	2,609
Fair value of acquired Vivint Smart Home, Inc. equity awards attributable to pre-combination service	14
Total Consideration	$	2,623

The purchase price is provisionally allocated as follows:


	(In millions)
Current Assets
Cash and cash equivalents	$	120
Accounts receivable, net	60
Inventory	113
Prepayments and other current assets	37
Total current assets	330
Property, plant and equipment, net	49
Other Assets
Operating lease right-of-use assets, net	35
Goodwill(a)	3,494
Intangible assets, net(b):
Customer relationships	1,740
Technology	860
Trade name	160
Sales channel contract	10
Intangible assets, net	2,770
Deferred income taxes	382
Other non-current assets	14
Total other assets	6,695
Total Assets	$	7,074

Current Liabilities
Current portion of long-term debt and finance leases	$	14
Current portion of operating lease liabilities	13
Accounts payable	109
Derivatives instruments	80
Deferred revenue current	518
Accrued expenses and other current liabilities	207
Total current liabilities	941
Other Liabilities
Long-term debt and finance leases	2,572
Non-current operating lease liabilities	28
Derivatives instruments	32
Deferred income taxes	18
Deferred revenue non-current	837
Other non-current liabilities	23
Total other liabilities	3,510
Total Liabilities	$	4,451

Vivint Smart Home Purchase Price	$	2,623

(a)Goodwill arising from the acquisition is attributed to the value of the platform acquired, cross-selling opportunities, subscriber growth and the synergies expected from combining the operations of Vivint Smart Home with NRG's existing businesses. None of the goodwill recorded is expected to be deductible for tax purposes

(b)The weighted average amortization period for total amortizable intangible assets is approximately ten years

Measurement Period Adjustments

The following measurement period adjustments were recognized during the three months ended September 30, 2023:


	(In millions)




Goodwill	$	2

Deferred income taxes	1
Total increase in assets	$	3
Liabilities
Deferred revenue current	$	1

Deferred revenue non-current	2
Total increase in liabilities	$	3
Net change in net assets acquired	$	—

The measurement period adjustments to the provisional amounts are primarily attributable to refinement of the underlying assumptions used to estimate the fair value of assets and liabilities acquired as more information was obtained about facts and circumstances that existed as of the Acquisition Closing Date.

Fair Value Measurement of Intangible Assets

The fair values of intangible assets as of the Acquisition Closing Date were measured primarily based on significant inputs that are observable and unobservable in the ~~Northeast~~market and ~~into states~~thus represent Level 2 and ~~locales where it did~~Level 3 measurements, respectively. Significant inputs were as follows:

Customer relationships – Customer relationships, reflective of Vivint Smart Home’s subscriber base, were valued using an excess earning method of the income approach, and is classified as Level 3. Under this approach, the Company estimated the present value of expected future cash flows resulting from existing subscriber relationships, considering attrition and charges for contributory assets (such as net working capital, fixed assets, workforce, trade name and technology) utilized in the business, discounted using a weighted average cost of capital of comparable companies. The subscriber relationships are amortized to depreciation and amortization, ratably based on discounted future cash flows. The weighted average amortization period is twelve years.

Technology – Developed technology was valued using a "relief from royalty" method of the income approach, and is classified as Level 3. Under this approach, the fair value was estimated to be the present value of royalties saved which assumed the value of the asset based on discounted cash flows of the amount that would be paid by a hypothetical market participant had they not ~~previously operate, supporting NRG's objective~~owned the asset and instead licensed the asset from another company. The estimated cash flows from the developed technology considered the obsolescence factor and was discounted using a weighted average cost of capital of comparable companies. The developed technology is amortized to ~~diversify its business.~~depreciation and amortization, ratably based on discounted future cash flows.The weighted average amortization period is five years.

Trade name – Trade name was valued using a "relief from royalty" method of the income approach, and is classified as Level 3. Under this approach, the fair value is estimated to be the present value of royalties saved which assumed the value of the asset based on discounted cash flows of the amount that would be paid by a hypothetical market participant had they not owned the asset and instead licensed the asset from another company. The estimated cash flows from the trade name considered the expected probable use of the asset and was discounted using a weighted average cost of capital of comparable companies. The trade name is amortized to depreciation and amortization, on a straight line basis, over an amortization period of ten years.

Fair Value Measurement of Acquired Vivint Smart Home Debt

The Company ~~paid an~~acquired $2.7 billion in aggregate principal of Vivint Smart Home’s 2027 Senior Secured Notes, 2029 Senior notes and 2028 Senior Secured Term Loan (together, the "Acquired Vivint Smart Home Debt") which were recorded at fair value as of the Acquisition Closing Date. The difference between the fair value at the Acquisition Closing Date and the principal outstanding of the Acquired Vivint Smart Home Debt, of $152 million, is being amortized through interest expense over the remaining term of the debt. The Acquired Vivint Smart Home Debt is classified as Level 2 and were measured at fair value using observable market inputs based on interest rates at the Acquisition Closing Date. For additional discussion, seeNote 9, Long-term Debt and Finance Leases.

Fair Value Measurement of Derivatives Liabilities

The derivative liabilities are recorded in connection with the contractual future payment obligations with the financing providers under Vivint Smart Home’s Consumer Financing Program. The fair values of the derivatives liabilities as of the

Acquisition Closing Date were valued using a discounted cash flow model, with inputs consisting of available market data, such as market yield discount rates, as well as unobservable internally derived assumptions, such as collateral prepayment rates, collateral default rates and credit loss rates. These derivatives are priced using a credit valuation adjustment methodology, and are classified as Level 3. Changes to the fair value are recorded through other income, net in the consolidated statement of operations. For additional discussion, see Note 7, Accounting for Derivative Instruments and Hedging Activities.

Supplemental Pro Forma Financial Information for the three and nine months ended September 30, 2023 and 2022

The following table provides pro forma combined financial information of NRG and Vivint Smart Home, after giving effect to the Vivint Smart Home acquisition and related financing transactions as if they had occurred on January 1, 2022. The pro forma financial information has been prepared for illustrative and informational purposes only, and is not intended to project future operating results or be indicative of what the Company's financial performance would have been had the transactions occurred on the date acquired. No effect has been given to prospective operating synergies.


	Three months ended September 30,				Nine months ended September 30,
(In millions)	2023		2022		2023		2022
Total operating revenues	$	7,946	$	8,949	$	22,302	$	24,927
Net income/(loss)	367		(4)		(588)		2,013

Amounts above reflect certain pro forma adjustments that were directly attributable to the Vivint Smart Home acquisition. These adjustments include the following:

(i)Income statement effects of fair value adjustments based on the preliminary purchase price allocation including amortization of ~~$3.625~~intangible assets, reversal of historical Vivint Smart Home amortization of capitalized contract costs and reversal of historical Vivint Smart Home other income recorded for the change in fair value of warrant derivative liabilities, as the warrants are assumed to be cashed out upon the Acquisition Closing Date.

(ii)One-time expenses directly related to the acquisition.

(iii)Adjustments to reflect all acquisition and related transactions costs in the nine months ended September 30, 2022.

(iv)Interest expense assumes the financing transactions directly attributable to the Vivint Smart Home acquisition occurred on January 1, 2022.

(v)Adjustments related to recording Vivint Smart Home's historical debt at Acquisition Closing Date fair value.

(vi)Adjustments to reflect the write-off of short-term deferred financing costs related to the bridge facility put in place for the acquisition prior to securing permanent financing during the nine months ended September 30, 2022 instead of the nine months ended September 30, 2023.

(vii) Income tax effect of the acquisition accounting adjustments and financing adjustments (adjusted for permanent book/tax differences) based on combined blended federal/state tax rate for all periods presented.

Dispositions

Sale of the 44% equity interest in STP

On November 1, 2023, the Company closed on the previously announced sale of its 44% equity interest in STP to Constellation Energy Generation ("Constellation"). Proceeds of $1.75 billion ~~in cash~~were reduced by preliminary working capital and ~~total purchase price adjustment~~other adjustments of ~~$99~~$96 million, resulting in ~~an adjusted purchase price~~net proceeds of ~~$3.724~~$1.654 billion. For ~~additional information refer to Note 4,~~ ~~Acquisitions, Discontinued Operations and Dispositions~~,discussion of the litigation matter related to the ~~Company's 2021 Form 10-K.~~transaction, see Note 16, Commitments and Contingencies.

~~Dispositions~~Sale of Gregory

On ~~September 9, 2022,~~October 2, 2023, the Company ~~entered into a definitive purchase agreement to sell~~closed on the sale of its 100% ownership in the Gregory natural gas generating facility in Texas for $102 million.

Sale of Astoria

On January 6, 2023, the Company closed on the sale of land and related generation assets from the Astoria site, within the East region of operations, for initial proceeds of $212 million, subject to ~~purchase price adjustments~~transaction fees of $3 million and certain ~~other indemnifications.~~indemnifications, resulting in a $199 million gain. As part of the transaction, NRG ~~will enter~~entered into an agreement to lease the land back for the purpose of operating the Astoria ~~facility through the planned April 30, 2023 retirement date.~~gas turbines. The ~~operating~~ lease agreement is expected to terminate by the end ~~six months~~of the year after ~~the facility's actual retirement date. The transaction~~decommissioning is ~~expected to close in the fourth quarter~~complete.

Sale of ~~2022 and is subject to various closing conditions.~~Watson

On June 1, 2022, the Company closed on the sale of its 49% ownership in the Watson natural gas generating facility for $59 million. The Company recorded a gain on the sale of $46 million.

~~On February 3, 2021,~~Held-for-sale

As of September 30, 2023, the ~~Company closed on the sale of its 35% ownership~~following is classified as held-for-sale in the ~~Agua Caliente solar project~~consolidated balance sheets, which are primarily related to ~~Clearway Energy, Inc. for $202 million. NRG recognized a gain on~~ the ~~sale~~sales of ~~$17 million, including cash disposed~~STP and Gregory within the Texas segment:


	(In millions)
Inventory	$	68
Prepayments and other current assets	18
Current assets - held-for-sale	$	86

Property, plant and equipment, net	$	248
Intangible assets, net	12
Nuclear decommissioning trust fund	893
Non-current assets - held-for-sale	$	1,153
Total assets held-for-sale	$	1,239

Current liabilities - held-for-sale	$	44

Nuclear decommissioning reserve	$	341
Nuclear decommissioning trust liability	518
Other non-current liabilities	67
Non-current liabilities - held-for-sale	$	926
Total liabilities held-for-sale	$	970

The Company recorded income before income taxes from its 44% equity interest in STP as follows:


	Three months ended September 30,				Nine months ended September 30,
(In millions)	2023		2022		2023		2022
Income before income taxes(a)	$	188	$	175	$	195	$	331

(a)Excludes the impact of ~~$7 million.~~the Company's hedges at the portfolio level

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 value and fair value of the Company's ~~financial instruments not carried at fair market value are~~long-term debt, including current portion, is as follows:


		September 30, 2022				December 31, 2021					September 30, 2023				December 31, 2022
(In millions)	(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value		(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value

Convertible Senior Notes	Convertible Senior Notes	$	575	$	611	$	518	$	677	Convertible Senior Notes	$	575	$	612	$	575	$	576

Other long-term debt, including current portion	Other long-term debt, including current portion	7,523		6,473		7,522		7,650		Other long-term debt, including current portion	11,137		10,028		7,523		6,432
Total long-term debt, including current portion(a)	Total long-term debt, including current portion(a)	$	8,098	$	7,084	$	8,040	$	8,327	Total long-term debt, including current portion(a)	$	11,712	$	10,640	$	8,098	$	7,008

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

The fair value of the Company's publicly-traded long-term debt isand the Vivint Smart Home Senior Secured Term Loan are based on quoted market prices and isare classified as Level 2 within the fair value hierarchy. The estimated fair value of the borrowing under the Revolving Credit Facility approximates the carrying value because the interest rates vary with market interest rates, and is classified as Level 3 within the fair value hierarchy. The following table presents the level within the fair value hierarchy for long-term debt, including current portion, as of September 30, 2023 and December 31, 2022:


	September 30, 2023				December 31, 2022
(In millions)	Level 2		Level 3		Level 2		Level 3
Convertible Senior Notes	$	612	$	—	$	576	$	—

Other long-term debt, including current portion	9,728		300		6,432		—
Total long-term debt, including current portion	$	10,340	$	300	$	7,008	$	—

Recurring Fair Value Measurements

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

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


		September 30, 2022										September 30, 2023
				Fair Value
(In millions)	(In millions)	Total			Level 1		Level 2		Level 3		(In millions)	Total		Level 1		Level 2		Level 3
Investments in securities (classified within other current and non-current assets)	Investments in securities (classified within other current and non-current assets)	$	19		$	—	$	19	$	—	Investments in securities (classified within other current and non-current assets)	$	19	$	—	$	19	$	—

Nuclear trust fund investments:
Nuclear trust fund investments (classified within non-current assets - held-for-sale):											Nuclear trust fund investments (classified within non-current assets - held-for-sale):
Cash and cash equivalents	Cash and cash equivalents	17			17		—		—		Cash and cash equivalents	25		25		—		—
U.S. government and federal agency obligations	U.S. government and federal agency obligations	85			83		2		—		U.S. government and federal agency obligations	76		74		2		—
Federal agency mortgage-backed securities	Federal agency mortgage-backed securities	101			—		101		—		Federal agency mortgage-backed securities	110		—		110		—
Commercial mortgage-backed securities	Commercial mortgage-backed securities	37			—		37		—		Commercial mortgage-backed securities	31		—		31		—
Corporate debt securities	Corporate debt securities	104			—		104		—		Corporate debt securities	111		—		111		—
Equity securities	Equity securities	372			372		—		—		Equity securities	451		451		—		—
Foreign government fixed income securities	Foreign government fixed income securities	2			—		2		—		Foreign government fixed income securities	1		—		1		—
Other trust fund investments (classified within other non-current assets):
U.S. government and federal agency obligations		1			1		—		—

Derivative assets:	Derivative assets:										Derivative assets:
Foreign exchange contracts	Foreign exchange contracts	30			—		30		—		Foreign exchange contracts	12		—		12		—
Commodity contracts	Commodity contracts	14,822			2,873		10,936		1,013		Commodity contracts	6,196		1,123		4,264		809

Interest rate contracts											Interest rate contracts	32		—		32		—

Measured using net asset value practical expedient:	Measured using net asset value practical expedient:										Measured using net asset value practical expedient:
Equity securities — nuclear trust fund investments		71
Equity securities — nuclear trust fund investments (classified within non-current assets - held-for-sale)											Equity securities — nuclear trust fund investments (classified within non-current assets - held-for-sale)	88		—		—		—
Equity securities (classified within other non-current assets)	Equity securities (classified within other non-current assets)	6									Equity securities (classified within other non-current assets)	6		—		—		—
Total assets	Total assets	$	15,667		$	3,346	$	11,231	$	1,013	Total assets	$	7,158	$	1,673	$	4,582	$	809
Derivative liabilities:	Derivative liabilities:										Derivative liabilities:
Foreign exchange contracts											Foreign exchange contracts	$	1	$	—	$	1	$	—
Commodity contracts											Commodity contracts	4,551		910		3,253		388

Commodity contracts		9,643			1,228		8,084		331
Consumer Financing Program											Consumer Financing Program	128		—		—		128
Total liabilities	Total liabilities	$	9,643		$	1,228	$	8,084	$	331	Total liabilities	$	4,680	$	910	$	3,254	$	516

2027


		December 31, 2021										December 31, 2022
				Fair Value
(In millions)	(In millions)	Total			Level 1		Level 2		Level 3		(In millions)	Total		Level 1		Level 2		Level 3
Investments in securities (classified within other current and non-current assets)	Investments in securities (classified within other current and non-current assets)	$	32		$	15	$	17	$	—	Investments in securities (classified within other current and non-current assets)	$	19	$	—	$	19	$	—
Nuclear trust fund investments:	Nuclear trust fund investments:										Nuclear trust fund investments:
Cash and cash equivalents	Cash and cash equivalents	33			33		—		—		Cash and cash equivalents	15		15		—		—
U.S. government and federal agency obligations	U.S. government and federal agency obligations	112			111		1		—		U.S. government and federal agency obligations	86		84		2		—
Federal agency mortgage-backed securities	Federal agency mortgage-backed securities	100			—		100		—		Federal agency mortgage-backed securities	101		—		101		—
Commercial mortgage-backed securities	Commercial mortgage-backed securities	44			—		44		—		Commercial mortgage-backed securities	35		—		35		—
Corporate debt securities	Corporate debt securities	122			—		122		—		Corporate debt securities	114		—		114		—
Equity securities	Equity securities	494			494		—		—		Equity securities	403		403		—		—
Foreign government fixed income securities	Foreign government fixed income securities	4			—		4		—		Foreign government fixed income securities	1		—		1		—
Other trust fund investments (classified within other non-current assets):	Other trust fund investments (classified within other non-current assets):										Other trust fund investments (classified within other non-current assets):
U.S. government and federal agency obligations	U.S. government and federal agency obligations	1			1		—		—		U.S. government and federal agency obligations	1		1		—		—
Derivative assets:	Derivative assets:										Derivative assets:
Foreign exchange contracts	Foreign exchange contracts	1			—		1		—		Foreign exchange contracts	18		—		18		—
Commodity contracts	Commodity contracts	7,139			981		5,701		457		Commodity contracts	11,976		1,929		8,796		1,251

Measured using net asset value practical expedient:	Measured using net asset value practical expedient:										Measured using net asset value practical expedient:
Equity securities — nuclear trust fund investments	Equity securities — nuclear trust fund investments	99									Equity securities — nuclear trust fund investments	83		—		—		—
Equity securities (classified within other non-current assets)	Equity securities (classified within other non-current assets)	7									Equity securities (classified within other non-current assets)	6		—		—		—
Total assets	Total assets	$	8,188		$	1,635	$	5,990	$	457	Total assets	$	12,858	$	2,432	$	9,086	$	1,251
Derivative liabilities:	Derivative liabilities:										Derivative liabilities:
Foreign exchange contracts	Foreign exchange contracts	$	1		$	—	$	1	$	—	Foreign exchange contracts	$	2	$	—	$	2	$	—
Commodity contracts	Commodity contracts	4,798			626		4,008		164		Commodity contracts	8,439		1,244		6,449		746

Total liabilities	Total liabilities	$	4,799		$	626	$	4,009	$	164	Total liabilities	$	8,441	$	1,244	$	6,451	$	746

The following table reconciles, for the three and nine months ended September 30, ~~2022~~2023 and ~~2021,~~2022, the beginning and ending balances for financial instruments that are recognized at fair value in the condensed consolidated financial statements, using significant unobservable ~~inputs:~~inputs, for commodity derivatives:


		Fair Value Measurement Using Significant Unobservable Inputs (Level 3)									Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
		Derivatives(a)									Commodity Derivatives(a)
(In millions)	(In millions)	Three months ended September 30, 2022		Three months ended September 30, 2021		Nine months ended September 30, 2022		Nine months ended September 30, 2021		(In millions)	Three months ended September 30, 2023		Three months ended September 30, 2022		Nine months ended September 30, 2023		Nine months ended September 30, 2022
Beginning balance										Beginning balance	$	905	$	1,403	$	505	$	293

Beginning balance		$	1,403	$	574	$	293	$	(16)
Contracts added from Direct Energy acquisition		—		—		—		(15)

Total (losses)/gains realized/unrealized — included in earnings		(314)		(175)		145		187

Total gains/(losses) realized/unrealized included in earnings										Total gains/(losses) realized/unrealized included in earnings	5		(314)		(172)		145
Purchases	Purchases	60		—		89		78		Purchases	(115)		60		25		89
Transfers into Level 3(b)	Transfers into Level 3(b)	(466)		(108)		155		64		Transfers into Level 3(b)	(374)		(466)		64		155
Transfers out of Level 3(b)	Transfers out of Level 3(b)	(1)		20		—		13		Transfers out of Level 3(b)	—		(1)		(1)		—
Ending balance	Ending balance	$	682	$	311	$	682	$	311	Ending balance	$	421	$	682	$	421	$	682
(Losses)/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		$	(240)	$	(237)	$	294	$	184
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										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	$	75	$	(240)	$	(56)	$	294

(a)Consists of derivative assets and liabilities, net, excluding derivatives liabilities from Consumer Financing Program, which are presented in a separate table below

(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

Realized and unrealized gains and losses included in earnings that are related to the ~~energy~~commodity derivatives are recorded in revenues and cost of operations.

2128

The following table reconciles, for the three and nine months ended September 30, 2023 the beginning and ending balances of the contractual obligations from the Consumer Financing Program 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)
	Consumer Financing Program
(In millions)	Three months ended September 30, 2023		Nine months ended September 30, 2023
Beginning balance	$	115	$	—
Contractual obligations added from the acquisition of Vivint Smart Home	—		112
New contractual obligations	33		55
Settlements	(21)		(43)
Total losses included in earnings	1		4
Ending balance	$	128	$	128

Gains and losses that are related to the Consumer Financing Program derivative are recorded in other income, net.

Derivative Fair Value Measurements

A portion of NRG's contracts are exchange-traded contracts with readily available quoted market prices. A majority of NRG's contracts are non-exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter and on-line exchanges. The remainder of the assets and liabilities represent contracts for which external sources or observable market quotes are not available. These contracts are valued based on various valuation techniques including, but not limited to, internal models based on a fundamental analysis of the market and extrapolation of the observable market data with similar characteristics. As of September 30, ~~2022,~~2023, contracts valued with prices provided by models and other valuation techniques make up 7%13% of derivative assets and 3%11% of derivative liabilities.

NRG's significant positions classified as Level 3 include physical and financial natural gas and power contracts executed in illiquid markets, as well as FTRs. The significant unobservable inputs used in developing fair value include illiquid natural gas and 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 Consumer Financing Program derivatives are valued using a discounted cash flow model, with inputs consisting of available market data, such as market yield discount rates, as well as unobservable internally derived assumptions, such as collateral prepayment rates, collateral default rates and credit loss rates. These derivatives are priced quarterly using a credit valuation adjustment methodology.

The following tables quantify the significant, unobservable inputs used in developing the fair value of the Company's Level 3 positions as of September 30, ~~2022~~2023 and December 31, ~~2021:~~2022:


		September 30, 2022													September 30, 2023
		Fair Value						Input/Range							Fair Value						Input/Range
(In millions)	(In millions)	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low		High		Weighted Average		(In millions)	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low			High			Weighted Average
Natural Gas Contracts	Natural Gas Contracts	$	90	$	46	Discounted Cash Flow	Forward Market Price (per MMBtu)	$	3	$	35	$	11	Natural Gas Contracts	$	94	$	113	Discounted Cash Flow	Forward Market Price (per MMBtu)	$	1		$	16		$	3
Power Contracts	Power Contracts	842		221		Discounted Cash Flow	Forward Market Price (per MWh)	20		263		55		Power Contracts	683		222		Discounted Cash Flow	Forward Market Price (per MWh)	1			196			43
FTRs	FTRs	81		64		Discounted Cash Flow	Auction Prices (per MWh)	(67)		46		1		FTRs	32		53		Discounted Cash Flow	Auction Prices (per MWh)	(30)			190			1
Consumer Financing Program														Consumer Financing Program	—		128		Discounted Cash Flow	Collateral Default Rates	0.94		%	99.85		%	7.66		%
		$	1,013	$	331														Discounted Cash Flow	Collateral Prepayment Rates	2.00		%	3.00		%	2.95		%
																			Discounted Cash Flow	Credit Loss Rates	6.00		%	60.00		%	12.24		%
															$	809	$	516

December 31, 2021
Fair Value Input/Range
(In millions) Assets Liabilities Valuation Technique Significant Unobservable Input Low High Weighted Average
Natural Gas Contracts $ 16 $ 1 Discounted Cash Flow Forward Market Price (per MMBtu) $ 3 $ 40 $ 15
Power Contracts 392 121 Discounted Cash Flow Forward Market Price (per MWh) 3 212 35
FTRs 49 42 Discounted Cash Flow Auction Prices (per MWh) (122) 43 0
$ 457 $ 164



	December 31, 2022
	Fair Value						Input/Range
(In millions)	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low		High		Weighted Average
Natural Gas Contracts	$	340	$	448	Discounted Cash Flow	Forward Market Price (per MMBtu)	$	2	$	48	$	6
Power Contracts	843		216		Discounted Cash Flow	Forward Market Price (per MWh)	3		431		48
FTRs	68		82		Discounted Cash Flow	Auction Prices (per MWh)	(32)		610		0
	$	1,251	$	746

The following table provides sensitivity of fair value measurements to increases/(decreases) in significant, unobservable inputs as of September 30, ~~2022~~2023 and December 31, ~~2021:~~2022:

Significant Unobservable Input

Position

Change In Input

Impact on Fair Value Measurement

Forward Market Price Natural Gas/Power

Buy

Increase/(Decrease)

Higher/(Lower)

Forward Market Price Natural Gas/Power

Sell

Increase/(Decrease)

Lower/(Higher)

FTR Prices

Buy

Increase/(Decrease)

Higher/(Lower)

FTR Prices

Sell

Increase/(Decrease)

Lower/(Higher)

Collateral Default Rates

n/a

Increase/(Decrease)

Higher/(Lower)

Collateral Prepayment Rates

n/a

Increase/(Decrease)

Lower/(Higher)

Credit Loss Rates

n/a

Increase/(Decrease)

Higher/(Lower)

The fair value of each contract is discounted using a risk-free interest rate. In addition, the Company applies a credit reserve to reflect credit risk, which is calculated based on published default probabilities. As of September 30, ~~2022,~~2023, the credit reserve resulted in a ~~$11~~$19 million decrease primarily within cost of operations. As of December 31, ~~2021,~~2022, the credit reserve resulted in a ~~$11~~$9 million decrease primarily within 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 ~~2021~~2022 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 ~~2021~~2022 Form 10-K. As of September 30, ~~2022,~~2023, counterparty credit exposure, excluding credit exposure from RTOs, ISOs, registered commodity exchanges and certain long-term agreements, was ~~$3.2~~$1.7 billion and NRG held collateral (cash and letters of credit) against those positions of ~~$1.8 billion,~~$494 million, resulting in a net exposure of ~~$1.4~~$1.2 billion. 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 ~~75%~~36% of the Company's exposure before collateral is expected to roll off by the end of ~~2023.~~2024. Counterparty credit exposure is valued through observable market quotes and discounted at a risk free interest rate. The following tables highlight net counterparty credit exposure by industry sector and by counterparty credit quality. Net counterparty credit exposure is defined as the aggregate net asset position for NRG with counterparties where netting is permitted under the enabling agreement and includes all cash flow, mark-to-market and NPNS, and non-derivative transactions. The exposure is shown net of collateral held and includes amounts net of receivables or payables.


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

Utilities, energy merchants, marketers and other	6168	%
Financial institutions	3932

Total as of September 30, ~~2022~~2023	100	%


	Net Exposure (a)(b)
Category by Counterparty Credit Quality	(% of Total)
Investment grade	6856	%
Non-investment grade/non-rated	3244
Total as of September 30, ~~2022~~2023	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 exposure to one wholesale counterparty in excess of 10% of total net exposure ~~discussed above~~ as of September 30, ~~2022.~~2023. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration.

During the first quarter of 2021, during Winter Storm Uri, the Company experienced a nonperformance by a counterparty in one of its bilateral financial hedging transactions, resulting in exposure of $403 million. The Company is pursuing all means available to enforce its obligations under this transaction but, given the size of the exposure and the counterparty filing for Chapter 11 bankruptcy protection, cannot determine with certainty what the amount of its ultimate recovery will be. The full exposure was provided for in the allowance for credit losses since March 31, 2021.

RTOs and ISOs

The Company participates in the organized markets of CAISO, ERCOT, AESO, IESO, ISO-NE, MISO, NYISO and PJM, known as RTOs or ISOs. Trading in the majority of these markets is approved by FERC, whereas in the case of ERCOT, it is approved by the PUCT, and whereas in the case of AESO and IESO, both exist provincially with AESO primarily subject to Alberta Utilities Commission and the IESO to the Ontario Energy Board. These ISOs may include 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~~Renewable PPAs. As external sources or observable market quotes are not always available to estimate such exposure, the Company values these contracts based on various techniques including, but not limited to, internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. Based on these valuation techniques, as of September 30, ~~2022,~~2023, aggregate credit risk exposure managed by NRG to these counterparties was approximately ~~$1.1~~$1.0 billion for the next five years.

Retail Customer Credit Risk

The Company is exposed to retail credit risk through the Company's retail electricity and gas providers as well as through Vivint Smart Home, which serve both Home and Business customers. 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~~in-

the-money forward value. The Company manages retail credit risk ~~through the use of~~by using established credit policies, ~~that~~which include monitoring of the portfolio and the use of credit mitigation measures such as deposits or prepayment arrangements.

As of September 30, ~~2022,~~2023, the Company's retail customer credit exposure to Home and Business customers was diversified across many customers and various industries, as well as government entities. Current economic conditions may affect the Company’s customers’ ability to pay bills in a timely manner, which could increase customer delinquencies and may lead to an increase in credit losses.

Note 6 — Nuclear Decommissioning Trust Fund

NRG's Nuclear Decommissioning Trust Fund assets, which are for the decommissioning of its 44% interest in STP, are comprised of securities classified as available-for-sale and recorded at fair value based on actively quoted market prices. NRG accounts for the Nuclear Decommissioning Trust Fund in accordance with ASC 980, Regulated Operations, because the Company's nuclear decommissioning activities are subject to approval by the PUCT with regulated rates that are designed to recover all decommissioning costs and that can be charged to and collected from the ratepayers per PUCT mandate. Since the Company is in compliance with PUCT rules and regulations regarding decommissioning trusts and the cost of decommissioning is the responsibility of the Texas ratepayers, not NRG, all realized and unrealized gains or losses (including other-than-temporary impairments) related to the Nuclear Decommissioning Trust Fund are recorded to the Nuclear Decommissioning Trust liability and are not included in net income or accumulated OCI, consistent with regulatory treatment. As of September 30, 2023, the trust liability is classified within non-current liabilities - held-for-sale on the Company's condensed consolidated balance sheet.

The following table summarizes the aggregate fair values and unrealized gains and losses for the securities held in the trust funds, as well as information about the contractual maturities of those securities. As of September 30, 2023, the trust funds are classified within non-current assets - held-for-sale on the Company's condensed consolidated balance sheet.

As of September 30, 2022 As of December 31, 2021
(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 $ 17 $ — $ — — $ 33 $ — $ — —
U.S. government and federal agency obligations 85 — 10 11 112 5 1 10
Federal agency mortgage-backed securities 101 — 12 25 100 2 — 25
Commercial mortgage-backed securities 37 — 4 28 44 1 — 27
Corporate debt securities 104 — 15 13 122 7 1 14
Equity securities 443 301 — — 593 456 — —
Foreign government fixed income securities 2 — — 18 4 — — 13
Total $ 789 $ 301 $ 41 $ 1,008 $ 471 $ 2


	As of September 30, 2023							As of December 31, 2022
(In millions, except maturities)	Fair Value		Unrealized Gains		Unrealized Losses		Weighted-average Maturities (In years)	Fair Value		Unrealized Gains		Unrealized Losses		Weighted-average Maturities (In years)
Cash and cash equivalents	$	25	$	—	$	—	—	$	15	$	—	$	—	—
U.S. government and federal agency obligations	76		—		9		12	86		—		5		11
Federal agency mortgage-backed securities	110		—		13		24	101		—		11		26
Commercial mortgage-backed securities	31		—		4		29	35		—		4		30
Corporate debt securities	111		—		11		12	114		—		13		12
Equity securities	539		390		—		—	486		346		3		—
Foreign government fixed income securities	1		—		—		14	1		—		—		17
Total	$	893	$	390	$	37		$	838	$	346	$	36

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


		Nine months ended September 30,					Nine months ended September 30,
(In millions)	(In millions)	2022		2021		(In millions)	2023		2022
Realized gains	Realized gains	$	12	$	10	Realized gains	$	7	$	12
Realized losses	Realized losses	(19)		(6)		Realized losses	(15)		(19)
Proceeds from sale of securities	Proceeds from sale of securities	363		424		Proceeds from sale of securities	280		363

Note 7 — Accounting for Derivative Instruments and Hedging Activities

Energy-Related Commodities

As of September 30, ~~2022,~~2023, NRG had energy-related derivative instruments extending through 2036. The Company marks these derivatives to market through the consolidated statement of operations. NRG has executed energy-related contracts extending through ~~2038~~2036 that qualified for the NPNS exception and were therefore exempt from fair value accounting treatment.

Interest Rate Swaps

NRG is exposed to changes in interest rate through the Company's issuance of variable rate debt. To manage the Company's interest rate risk, NRG enters into interest rate swap agreements. In the first quarter of 2023, the Company entered into $1.0 billion of interest rate swaps through 2027 to hedge the floating rate on the Term Loan acquired with the Vivint Smart Home acquisition. Additionally, the Company entered into interest rate swaps to hedge the floating rate on the Revolving Credit Facility extending through 2024, with $300 million outstanding as of September 30, 2023.

Foreign Exchange Contracts

NRG is exposed to changes in foreign currency primarily associated with the purchase of ~~USD~~U.S. dollar denominated natural gas for its Canadian business. ~~In order to~~To manage the Company's foreign exchange risk, NRG entered into foreign exchange contracts. As of September 30, ~~2022,~~2023, NRG had foreign exchange contracts extending through ~~2026.~~2027. The Company marks these derivatives to market through the consolidated statement of operations.

Consumer Financing Program

Under the Consumer Financing Program, Vivint Smart Home pays a monthly fee to Financing Providers based on either the average daily outstanding balance of the loans or the number of outstanding loans. For certain loans, Vivint Smart Home incurs fees at the time of the loan origination and receives proceeds that are net of these fees. Vivint Smart Home also shares the liability for credit losses, depending on the credit quality of the subscriber. Due to the nature of certain provisions under the Consumer Financing Program, the Company records a derivative liability that is not designated as a hedging instrument and is adjusted to fair value, measured using the present value of the estimated future payments. Changes to the fair value are recorded through other income, net in the consolidated statement of operations. The following represent the contractual future payment obligations with the Financing Providers under the Consumer Financing Program that are components of the derivative:

• Vivint Smart Home pays either a monthly fee based on the average daily outstanding balance of the loans, or the number of outstanding loans, depending on the Financing Provider;

• Vivint Smart Home shares the liability for credit losses depending on the credit quality of the subscriber; and

• Vivint Smart Home pays transactional fees associated with subscriber payment processing.

The derivative is classified as a Level 3 instrument. The derivative positions are valued using a discounted cash flow model, with inputs consisting of available market data, such as market yield discount rates, as well as unobservable internally derived assumptions, such as collateral prepayment rates, collateral default rates and credit loss rates. These derivatives are priced quarterly using a credit valuation adjustment methodology. In summary, the fair value represents an estimate of the present value of the cash flows Vivint Smart Home will be obligated to pay to the Financing Provider for each component of the derivative.

Volumetric Underlying Derivative Transactions

The following table summarizes the net notional volume buy/(sell) of NRG's open derivative transactions broken out by category, excluding those derivatives that qualified for the NPNS exception, as of September 30, ~~2022~~2023 and December 31, ~~2021.~~2022. 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

September 30, 2023

December 31, 2022

Emissions

Short Ton

Emissions

Short Ton

—

Renewable Energy Certificates

Certificates

Renewable Energy Certificates

Certificates

Coal

Short Ton

Coal

Short Ton

Natural Gas

MMBtu

748

813

Natural Gas

MMBtu

841

422

Oil

Barrels

—

Oil

Barrels

—

Power

MWh

176

185

Power

MWh

201

192

Consumer Financing Program

Dollars

1,142

—

Foreign Exchange

Dollars

502

279

Foreign Exchange

Dollars

566

569

Interest

Dollars

1,300

—

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) September 30, 2022 December 31, 2021 September 30, 2022 December 31, 2021
Derivatives Not Designated as Cash Flow or Fair Value Hedges:
Foreign exchange contracts - current $ 16 $ — $ — $ 1
Foreign exchange contracts - long-term 14 1 — —
Commodity contracts - current 9,922 4,613 6,841 3,386
Commodity contracts - long-term 4,900 2,526 2,802 1,412
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges $ 14,852 $ 7,140 $ 9,643 $ 4,799


	Fair Value
	Derivative Assets				Derivative Liabilities
(In millions)	September 30, 2023		December 31, 2022		September 30, 2023		December 31, 2022




Derivatives Not Designated as Cash Flow or Fair Value Hedges:
Interest rate contracts - current	$	21	$	—	$	—	$	—
Interest rate contracts - long-term	11		—		—		—
Foreign exchange contracts - current	7		11		—		1
Foreign exchange contracts - long-term	5		7		1		1
Consumer Financing Program - short-term	—		—		83		—
Consumer Financing Program - long-term	—		—		45		—
Commodity contracts - current	3,682		7,875		3,045		6,194
Commodity contracts - long-term	2,514		4,101		1,506		2,245
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges	$	6,240	$	11,994	$	4,680	$	8,441

The Company has elected to present derivative assets and liabilities on the consolidated 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 consolidated 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 September 30, 2022
Foreign exchange contracts:
Derivative assets $ 30 $ — $ — $ 30
Commodity contracts:
Derivative assets $ 14,822 $ (8,987) $ (3,081) $ 2,754
Derivative liabilities (9,643) 8,987 29 (627)
Total commodity contracts $ 5,179 $ — $ (3,052) $ 2,127
Total derivative instruments $ 5,209 $ — $ (3,052) $ 2,157


		Gross Amounts Not Offset in the Statement of Financial Position									Gross Amounts Not Offset in the Statement of Financial Position
(In millions)	(In millions)	Gross Amounts of Recognized Assets / Liabilities		Derivative Instruments		Cash Collateral (Held) / Posted		Net Amount		(In millions)	Gross Amounts of Recognized Assets / Liabilities		Derivative Instruments		Cash Collateral (Held) /Posted		Net Amount
As of December 31, 2021
As of September 30, 2023										As of September 30, 2023
Foreign exchange contracts:	Foreign exchange contracts:									Foreign exchange contracts:
Derivative assets	Derivative assets	$	1	$	(1)	$	—	$	—	Derivative assets	$	12	$	(1)	$	—	$	11
Derivative liabilities	Derivative liabilities	(1)		1		—		—		Derivative liabilities	(1)		1		—		—
Total foreign exchange contracts	Total foreign exchange contracts	$	—	$	—	$	—	$	—	Total foreign exchange contracts	$	11	$	—	$	—	$	11
Commodity contracts:	Commodity contracts:									Commodity contracts:
Derivative assets	Derivative assets	$	7,139	$	(4,440)	$	(831)	$	1,868	Derivative assets	$	6,196	$	(4,331)	$	(269)	$	1,596
Derivative liabilities	Derivative liabilities	(4,798)		4,440		17		(341)		Derivative liabilities	(4,551)		4,331		11		(209)
Total commodity contracts	Total commodity contracts	$	2,341	$	—	$	(814)	$	1,527	Total commodity contracts	$	1,645	$	—	$	(258)	$	1,387

Consumer Financing Program:										Consumer Financing Program:
Derivative liabilities										Derivative liabilities	$	(128)	$	—	$	—	$	(128)
Interest rate contracts:										Interest rate contracts:
Derivative assets										Derivative assets	$	32	$	—	$	—	$	32

Total derivative instruments	Total derivative instruments	$	2,341	$	—	$	(814)	$	1,527	Total derivative instruments	$	1,560	$	—	$	(258)	$	1,302

2634


	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, 2022
Foreign exchange contracts:
Derivative assets	$	18	$	(2)	$	—	$	16
Derivative liabilities	(2)		2		—		—
Total foreign exchange contracts	$	16	$	—	$	—	$	16
Commodity contracts:
Derivative assets	$	11,976	$	(7,897)	$	(1,659)	$	2,420
Derivative liabilities	(8,439)		7,897		20		(522)
Total commodity contracts	$	3,537	$	—	$	(1,639)	$	1,898






Total derivative instruments	$	3,553	$	—	$	(1,639)	$	1,914

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 consolidated statement of operations. The effect of foreign exchange and commodity hedges are included within revenues and cost of operations.

(In millions) Three months ended September 30, Nine months ended September 30,
Unrealized mark-to-market results 2022 2021 2022 2021
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges $ (387) $ (97) $ (992) $ (58)
Reversal of acquired (gain)/loss positions related to economic hedges (15) (42) (27) 206
Net unrealized gains on open positions related to economic hedges 313 1,924 3,926 3,875
Total unrealized mark-to-market (losses)/gains for economic hedging activities (89) 1,785 2,907 4,023
Reversal of previously recognized unrealized losses/(gains) on settled positions related to trading activity 2 (6) 11 (16)
Net unrealized gains/(losses) on open positions related to trading activity 7 14 (18) 18
Total unrealized mark-to-market gains/(losses) for trading activity 9 8 (7) 2
Total unrealized (losses)/gains $ (80) $ 1,793 $ 2,900 $ 4,025
The effect of the interest rate contracts are included within interest expense. The effect of the Consumer Financing Program is included in other income, net.

Three months ended September 30, Nine months ended September 30,
(In millions) 2022 2021 2022 2021
Unrealized gains/(losses) included in revenues - commodities $ 42 $ 11 $ (255) $ (97)
Unrealized (losses)/gains included in cost of operations - commodities (148) 1,777 3,124 4,121
Unrealized gains included in cost of operations - foreign exchange 26 5 31 1
Total impact to statement of operations - commodities $ (80) $ 1,793 $ 2,900 $ 4,025


(In millions)	Three months ended September 30,				Nine months ended September 30,
Unrealized mark-to-market results	2023		2022		2023		2022
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges	$	(522)	$	(387)	$	(1,519)	$	(992)
Reversal of acquired (gain)/loss positions related to economic hedges	(6)		(15)		4		(27)
Net unrealized gains/(losses) on open positions related to economic hedges	475		313		(418)		3,926
Total unrealized mark-to-market (losses)/gains for economic hedging activities	(53)		(89)		(1,933)		2,907
Reversal of previously recognized unrealized losses on settled positions related to trading activity	—		2		11		11

Net unrealized (losses)/gains on open positions related to trading activity	(1)		7		13		(18)
Total unrealized mark-to-market (losses)/gains for trading activity	(1)		9		24		(7)
Total unrealized (losses)/gains - commodities and foreign exchange	$	(54)	$	(80)	$	(1,909)	$	2,900


	Three months ended September 30,				Nine months ended September 30,
(In millions)	2023		2022		2023		2022
Unrealized (losses)/gains included in revenues - commodities	$	(71)	$	42	$	120	$	(255)
Unrealized gains/(losses) included in cost of operations - commodities	8		(148)		(2,024)		3,124
Unrealized gains/(losses) included in cost of operations - foreign exchange	9		26		(5)		31
Total impact to statement of operations - commodities and foreign exchange	$	(54)	$	(80)	$	(1,909)	$	2,900
Total impact to statement of operations - consumer financing program	$	(1)	$	—	$	(4)	$	—
Total impact to statement of operations - interest rate contracts	$	8	$	—	$	32	$	—

The reversals of acquired (gain)/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 revenue or cost of operations during the same period.

For the nine months ended September 30, ~~2022 and 2021,~~2023, the $418 million unrealized ~~gains~~loss from open economic hedge positions was primarily the result of a decrease in the value of forward positions as a result of decreases in natural gas and power prices in the East and West.

For the nine months ended September 30, 2022, the $3.9 billion ~~and $3.9 billion, respectively, were~~unrealized gain from open economic hedge positions was primarily due to increases in the value of forward positions as a result of increases in natural gas and power prices.

Credit Risk Related Contingent Features

Certain of the Company's trading agreements contain provisions that entitle the counterparty to demand that the Company post additional collateral if the counterparty determines that there has been deterioration in the Company's 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 potentially required for all contracts with adequate assurance clauses that are in a net liability position as of September 30, ~~2022~~2023 was ~~$1.3 billion.~~$647 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 approximately ~~$131~~$70 million as of September 30, ~~2022.~~2023. In the event of a downgrade in the Company's credit rating and if called for by the counterparty, ~~$30~~$3 million of additional collateral would be required for all contracts with credit rating contingent features as of September 30, ~~2022.~~2023.

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

Note 8 — Impairments

2022 Impairment Losses

Astoria Redevelopment Impairment — During the third quarter of 2022, the Company entered into a purchase and sale agreement for the sale of the land and related assets at the Astoria generating site and the planned withdrawal and cancellation of its proposed Astoria redevelopment project. As a result, the Company impaired $43 million of Astoria project spend in the East segment.

PJM Asset Impairments — During the second quarter of 2022, the results of the PJM Base Residual Auction for the 2023/2024 delivery year were released leading the Company to revise its long-term view of certain facilities and announce the planned retirement of the Joliet generating facility in ~~May~~ 2023. The Company considered the near-term retirement date of Joliet and the decline in PJM capacity prices to be a trigger for impairment and performed impairment tests on the PJM generating assets and the goodwill associated with Midwest Generation. The Company measured the impairment losses on the PJM generating assets and Midwest Generation goodwill as the difference between the carrying amount and the fair value of the PJM generating assets and Midwest Generation reporting unit, respectively. Fair values were determined using an income approach in which the Company applied a discounted cash flow methodology to the long-term budgets for the plants and reporting unit. Significant inputs impacting the income approach include the Company's long-term view of capacity and fuel prices, projected generation, the physical and economic characteristics of each plant and the reporting unit as a whole, and the discount rate applied to the after-tax cash flow projections. Impairment losses of $20 million and $130 million were recorded in the ~~East segment on the PJM generating assets and Midwest Generation goodwill, respectively.~~

~~2021 Impairment Losses~~

~~PJM Asset Impairments —~~ ~~During the~~ second quarter of 2021, the results of the PJM Base Residual Auction for the 2022/2023 delivery year were released leading the Company to announce the near-term retirement of a significant portion of its PJM coal generating assets in June 2022. The Company considered the decline in PJM capacity prices and the near-term retirement dates of certain assets to be a trigger for impairment and performed impairment tests on the PJM generating assets and the goodwill associated with Midwest Generation. The Company measured the impairment losses on the PJM generating assets and Midwest Generation goodwill as the difference between the carrying amount and the fair value of the PJM generating assets and Midwest Generation reporting unit, respectively. Fair values were determined using an income approach in which the Company applied a discounted cash flow methodology to the long-term budgets for the plants and reporting unit. Significant inputs impacting the income approach include the Company's long-term view of capacity and fuel prices, projected generation, the physical and economic characteristics of each plant, and the discount rate applied to the after-tax cash flow projections. Impairment losses of $271 million and $35 million were recorded2022 in the East segment on the PJM generating assets and Midwest Generation goodwill, respectively.

2836

Note 9 — Long-term Debt and Finance Leases

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


(In millions, except rates)	(In millions, except rates)	September 30, 2022		December 31, 2021		Interest rate %	(In millions, except rates)	September 30, 2023		December 31, 2022		Interest rate %
Recourse debt:	Recourse debt:						Recourse debt:
Senior Notes, due 2027	Senior Notes, due 2027	$	375	$	375	6.625	Senior Notes, due 2027	$	375	$	375	6.625
Senior Notes, due 2028	Senior Notes, due 2028	821		821		5.750	Senior Notes, due 2028	821		821		5.750
Senior Notes, due 2029	Senior Notes, due 2029	733		733		5.250	Senior Notes, due 2029	733		733		5.250
Senior Notes, due 2029	Senior Notes, due 2029	500		500		3.375	Senior Notes, due 2029	500		500		3.375
Senior Notes, due 2031	Senior Notes, due 2031	1,030		1,030		3.625	Senior Notes, due 2031	1,030		1,030		3.625
Senior Notes, due 2032	Senior Notes, due 2032	1,100		1,100		3.875	Senior Notes, due 2032	1,100		1,100		3.875
Convertible Senior Notes, due 2048(a)	Convertible Senior Notes, due 2048(a)	575		575		2.750	Convertible Senior Notes, due 2048(a)	575		575		2.750
Senior Secured First Lien Notes, due 2024	Senior Secured First Lien Notes, due 2024	600		600		3.750	Senior Secured First Lien Notes, due 2024	600		600		3.750
Senior Secured First Lien Notes, due 2025	Senior Secured First Lien Notes, due 2025	500		500		2.000	Senior Secured First Lien Notes, due 2025	500		500		2.000
Senior Secured First Lien Notes, due 2027	Senior Secured First Lien Notes, due 2027	900		900		2.450	Senior Secured First Lien Notes, due 2027	900		900		2.450
Senior Secured First Lien Notes, due 2029	Senior Secured First Lien Notes, due 2029	500		500		4.450	Senior Secured First Lien Notes, due 2029	500		500		4.450
Senior Secured First Lien Notes, due 2033							Senior Secured First Lien Notes, due 2033	740		—		7.000
Revolving Credit Facility							Revolving Credit Facility	300		—		various

Tax-exempt bonds	Tax-exempt bonds	466		466		1.250 - 4.750	Tax-exempt bonds	466		466		1.250 - 4.750

Subtotal recourse debt	Subtotal recourse debt	8,100		8,100			Subtotal recourse debt	9,140		8,100

Non-recourse debt:							Non-recourse debt:
Vivint Smart Home Senior Secured Notes, due 2027							Vivint Smart Home Senior Secured Notes, due 2027	600		—		6.750
Vivint Smart Home Senior Notes, due 2029							Vivint Smart Home Senior Notes, due 2029	800		—		5.750
Vivint Smart Home Senior Secured Term Loan, due 2028							Vivint Smart Home Senior Secured Term Loan, due 2028	1,323		—		various
Subtotal all Vivint Smart Home non-recourse debt							Subtotal all Vivint Smart Home non-recourse debt	2,723		—
Subtotal long-term debt (including current maturities)							Subtotal long-term debt (including current maturities)	11,863		8,100
Finance leases	Finance leases	12		13		various	Finance leases	19		11		various
Subtotal long-term debt and finance leases (including current maturities)	Subtotal long-term debt and finance leases (including current maturities)	8,112		8,113			Subtotal long-term debt and finance leases (including current maturities)	11,882		8,111
Less current maturities	Less current maturities	(62)		(4)			Less current maturities	(920)		(63)
Less debt issuance costs	Less debt issuance costs	(74)		(83)			Less debt issuance costs	(70)		(70)
Discounts	Discounts	(2)		(60)			Discounts	(151)		(2)
Total long-term debt and finance leases	Total long-term debt and finance leases	$	7,974	$	7,966		Total long-term debt and finance leases	$	10,741	$	7,976

(a)As of the ex-dividend date of October 31, ~~2022,~~2023, the Convertible Senior Notes were convertible at a price of ~~$43.46,~~$41.83, which is equivalent to a conversion rate of approximately ~~23.0116~~23.9079 shares of common stock per $1,000 principal ~~amount.~~amount

Recourse Debt

Issuance of 2033 Senior Secured First Lien Notes

On March 9, 2023, the Company issued $740 million of aggregate principal amount of 7.000% senior secured first lien notes due 2033 (the "2033 Senior Secured First Lien Notes"). The 2033 Senior Secured First Lien Notes are senior secured obligations of NRG and are guaranteed by certain of its subsidiaries that guarantee indebtedness under the Revolving Credit Facility. The 2033 Senior Secured First Lien Notes are secured by a first priority security interest in the same collateral that is pledged for the benefit of the lenders under the Revolving Credit Facility, which collateral consists of a substantial portion of the property and assets owned by the Company and the guarantors. The collateral securing the 2033 Senior Secured First Lien Notes will be released at the Company’s request if the senior unsecured long-term debt securities of the Company are rated investment grade by any two of the three rating agencies, subject to reversion if such rating agencies withdraw such investment grade rating or downgrade such rating below investment grade. Interest is paid semi-annually beginning on September 15, 2023 until the maturity date of March 15, 2033. The proceeds of the 2033 Senior Secured First Lien Notes, along with cash on hand and proceeds from certain other financings, were used to fund the acquisition of Vivint Smart Home.

2048 Convertible Senior Notes

~~Accounting for Convertible Senior Notes —~~ Upon issuance in 2018, the Convertible Senior Notes were separated into liability and equity components for accounting purposes. The carrying amounts of the liability component was initially calculated by measuring the fair value of similar liabilities that do not have an associated convertible feature. The carrying amount of the equity component representing the conversion option was determined by deducting the fair value of the liability component from the par value of the Convertible Senior Notes. This difference represented the debt discount that was amortized to interest expense over seven years, which was determined to be the expected life of the Convertible Senior Notes, using the effective interest rate method. The equity component was recorded in additional paid-in capital and was not remeasured as it continued to meet the conditions for equity classification.

Following the adoption of ASU 2020-06 as of January 1, 2022, the Company no longer records the conversion feature of its convertible senior notes in equity. Instead, the Company combined the previously separated equity component with the liability component, which together is now classified as debt, thereby eliminating the subsequent amortization of the debt discount as interest expense. As a result of the provisions of the amended guidance, the Company recorded a $100 million decrease to additional paid-in capital, a $57 million decrease to debt discount, a $57 million increase to retained earnings and a $14 million decrease to long-term deferred tax liabilities. For more information on the adoption of ASU 2020-06, refer to Note 2, ~~Summary of Significant Accounting Policies~~.

~~Modification to Convertible Senior Notes~~ ~~— On February 22, 2022, the Company irrevocably elected to eliminate the right to settle conversions only in shares of the Company's common stock,~~ ~~such that any~~ conversion after such date, the Company will pay cash per $1,000 principal amount and will settle in cash or a combination of cash and the Company's common stock for the remainder, if any, of the Company’s conversion obligation in excess of the aggregate principal amount.

~~Convertible Senior Notes Features~~ — As of September 30, ~~2022,~~2023, the Convertible Senior Notes were convertible, under certain circumstances, into cash or a combination of cash and the Company’s common stock at a price of ~~$43.77~~$42.17 per common share, which is equivalent to a conversion rate of approximately ~~22.8467~~23.7112 shares of common stock per $1,000 principal amount of Convertible Senior Notes. The net carrying amounts of the Convertible Senior Notes as of September 30, 2023 and December 31, 2022 were $571 million and $570 million, respectively. The Convertible Senior Notes mature on June 1, 2048, unless earlier repurchased, redeemed or converted in accordance with their terms. The Convertible Senior notes are convertible at the option of the holders under certain circumstances. Prior to the close of business on the business day immediately preceding December 1, 2024, the Convertible

Senior Notes will be convertible only upon the occurrence of certain events and during certain periods, and thereafter during specified periods as follows:

•from December 1, 2024 until the close of business on the second scheduled trading day immediately before June 1, 2025; and

•from December 1, 2047 until the close of business on the second scheduled trading day immediately before the maturity date

The following table details the interest expense recorded in connection with the Convertible Senior Notes, due 2048:


		Three months ended September 30,						Nine months ended September 30,							Three months ended September 30,						Nine months ended September 30,
($ In millions)	($ In millions)	2022			2021			2022			2021			($ In millions)	2023			2022			2023			2022
Contractual interest expense	Contractual interest expense	$	4		$	4		$	12		$	12		Contractual interest expense	$	4		$	4		$	12		$	12
Amortization of discount and deferred finance costs		—			4			1			12
Amortization of deferred finance costs														Amortization of deferred finance costs	—			—			1			1
Total	Total	$	4		$	8		$	13		$	24		Total	$	4		$	4		$	13		$	13

Effective Interest Rate	Effective Interest Rate	0.76		%	1.34		%	2.28		%	3.99		%	Effective Interest Rate	0.76		%	0.76		%	2.28		%	2.28		%

~~Receivables Securitization Facilities~~Revolving Credit Facility

On February ~~9, 2022,~~14, 2023, the Company ~~entered into amendments to~~amended its ~~existing Repurchase~~Revolving Credit Facility ~~to, among other things,~~to: (i) increase the ~~size of the facility from $75~~existing revolving commitments thereunder by $600 million, ~~to $150 million and~~ (ii) replace LIBOR with term SOFR as the benchmark for the pricing rate. The Repurchase Facility has no commitment fee and borrowings will be drawn at SOFR + 1.30%. On July 26, 2022, the Company renewed its existing Repurchase Facility to, among other things, extend the maturity date of a portion of the revolving commitments thereunder to ~~July 26, 2023.~~February 14, 2028, (iii) transition the benchmark rate applicable to revolving loans from LIBOR to SOFR and (iv) make certain other amendments to the terms of the Revolving Credit Facility for purposes of, among other things, providing additional flexibility. For further discussion, see Note 13, Long-term Debt and Finance Leases, ofthe Company’s 2022 Form 10-K.

On March 13, 2023, the Company further amended its Revolving Credit Facility to increase the existing revolving commitments by an additional $45 million. As of September 30, ~~2022,~~2023, there were no outstanding ~~borrowings.~~

~~On July 26, 2022, NRG Receivables LLC, a wholly-owned indirect subsidiary~~borrowings of the Company, entered into an amendment to its Receivables Facility dated September 22, 2020 with a group of conduit lenders and banks and Royal Bank of Canada, as Administrative Agent to, among other things, (i) extend the scheduled termination date by one year, (ii) increase the aggregate commitments from $800$300 million to $1.0 billion, (iii) increase the letter of credit sublimit to equal the aggregate commitments, (iv) replace LIBOR with Term SOFR as the benchmark for borrowings and (v) add new originators. The weighted average interest rate related to usage under the ~~Receivables Facility as of September 30, 2022 was 0.836%.~~Revolving Credit Facility. As of ~~September 30, 2022,~~October 31, 2023, there were no outstanding borrowings ~~and there were $884~~of $100 million ~~in letters of credit issued~~ under the ~~Receivables~~Revolving Credit Facility.

Bilateral Letter of Credit Facilities

On ~~April 29, 2022,~~ May ~~27, 2022~~19, 2023, May 30, 2023 and October ~~13, 2022,~~17, 2023 the Company increased the size of ~~the~~its bilateral letter of credit facilities by ~~$100~~$25 million, ~~$50~~$100 million and $50 million, respectively, to provide additional liquidity ~~allowing~~and to allow for the issuance of up to ~~$675~~$850 million of letters of credit. These facilities are uncommitted.

Receivables Securitization Facilities

On June 22, 2023, NRG Receivables LLC (“NRG Receivables”), an indirect wholly-owned subsidiary of the Company, amended its existing Receivables Facility to, among other things, (i) extend the scheduled termination date to June 21, 2024, (ii) increase the aggregate commitments from $1.0 billion to $1.4 billion (adjusted seasonally) and (iii) add a new originator. On October 6, 2023, the Receivables Facility was further amended to replace the benchmark interest rate of the Receivable Facility's subordinated note from LIBOR to SOFR. As of September 30, 2023, there were no outstanding borrowings.

In addition, in connection with the amendments to the Receivables Facility, on June 22, 2023, the Company and the originators thereunder renewed the existing uncommitted Repurchase Facility. Such renewal, among other things, extended the maturity date to June 21, 2024 and joined an additional originator to the Repurchase Facility. On October 6, 2023, the Repurchase Facility was further amended to reflect the concurrent amendment to the Receivables Facility's subordinated note. As of September 30, 2023, there were no outstanding borrowings.

For further information on the above facilities, see Note 13, Long-term Debt and Finance Leases, of the Company's 2022 ~~$592~~Form 10-K.

Dunkirk Bonds

On April 3, 2023, NRG remarketed $59 million in aggregate principal amount of 4.25% tax-exempt refinancing bonds of the Chautauqua County Capital Resource Corporation (the "Dunkirk Bonds"). The Dunkirk Bonds are guaranteed on a first-priority basis by each of NRG's current and future subsidiaries that guarantee indebtedness under the Revolving Credit Facility. The Dunkirk Bonds are secured by a first priority security interest in the same collateral that is pledged for the benefit of the lenders under the Revolving Credit Facility, which consists of a substantial portion of the property and assets owned by NRG and the guarantors. The collateral securing the Dunkirk 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 Dunkirk Bonds or any of NRG's senior, unsecured debt securities or downgrade such ratings below investment grade. The Dunkirk Bonds are subject to mandatory tender and purchase on April 3, 2028 and have a final maturity date of April 1, 2042.

Pre-Capitalized Trust Securities Facility

On August 29, 2023, the Company entered into a Facility Agreement (as defined below) with Alexander Funding Trust II, a newly-formed Delaware statutory trust (the “Trust”), in connection with the sale by the Trust of $500 million pre-capitalized trust securities redeemable July 31, 2028 (the “P-Caps”). The Trust invested the proceeds from the sale of the P-Caps in a portfolio of principal and interest strips of U.S. Treasury securities (the “Eligible Treasury Assets”). The P-Caps will replace the Company’s existing pre-capitalized trust securities redeemable 2023 issued by Alexander Funding Trust, which mature on November 15, 2023.

In connection with the sale of the P-Caps, the Company and the guarantors named therein entered into a facility agreement, dated August 29, 2023 (the “Facility Agreement”), with the Trust and Deutsche Bank Trust Company Americas, as notes trustee (the “Notes Trustee”). Under the Facility Agreement, the Company has the right, from time to time, to issue to the Trust, and to require the Trust to purchase from the Company, on one or more occasions (the “Issuance Right”), up to $500 million aggregate principal amount of the Company’s 7.467% Senior Secured First Lien Notes due 2028 (the “P-Caps Secured Notes”) in exchange for all or a portion of the Eligible Treasury Assets corresponding to the portion of the Issuance Right under the Facility Agreement being exercised at such time. The Company pays to the Trust a facility fee equal to 3.13427% applied to the unexercised portion of the Issuance Right on a semi-annual basis.

The P-Caps are to be redeemed by the Trust on July 31, 2028 or earlier upon an early redemption of the P-Caps Secured Notes. Following any distribution of P-Caps Secured Notes to the holders of the P-Caps, the Company may similarly redeem such P-Caps Secured Notes, in whole or in part, at the redemption price described in the Indenture (as defined below), plus accrued but unpaid interest to, but excluding, the date of redemption. Any P-Caps Secured Notes outstanding and held by the Trust as a result of the exercise of the Issuance Right that remain outstanding will also mature on July 31, 2028.

The Issuance Right will be exercised automatically in full if (i) the Company fails to pay the facility fee when due or any amount due and owing under the trust expense reimbursement agreement or fails to purchase and pay for any Eligible Treasury Assets that are due and not paid on their payment date and such failure is not cured within 30 days or (ii) upon certain bankruptcy events of the Company. The Company will be required to mandatorily exercise the Issuance Right if certain mandatory exercise events occur upon the terms and conditions set forth in the Facility Agreement.

The P-Caps Secured Notes that may be sold to the Trust from time to time will be governed by the base indenture, dated August 29, 2023 (the “Base Indenture”), between the Company and the Notes Trustee, as supplemented by the supplemental indenture, dated August 29, 2023 (the “Supplemental Indenture” and, together with the Base Indenture, the “Indenture”), among the Company, the guarantors named therein and the Notes Trustee.

The P-Caps Secured Notes will, if sold to the Trust, be guaranteed on a first-priority basis by each of the Company’s subsidiaries that guarantee indebtedness under the Revolving Credit Facility. The P-Caps Secured Notes will, if sold to the Trust, be secured by a first priority security interest in the same collateral that is pledged for the benefit of the lenders under the Revolving Credit Facility, which consists of a substantial portion of the property and assets owned by the Company and the guarantors. The collateral securing the P-Caps Secured Notes will be released at the Company’s request if the senior unsecured long-term debt securities of the Company are rated investment grade by any two of the three rating agencies, subject to reversion if such rating agencies downgrade such rating below investment grade or withdraw such investment grade rating.

In connection with the issuance of the P-Caps, on August 29, 2023, the Company entered into a letter of credit facility agreement (the “LC Agreement”) with Deutsche Bank Trust Company Americas, as collateral agent (the “Collateral Agent”) and administrative agent, and certain financial institutions (the “LC Issuers”) for the issuance of letters of credit in an aggregate amount not to exceed $485 million. The LC Agreement replaces the Company’s existing letter of credit facility agreement, effective August 29, 2023. In addition, on August 29, 2023, the Trust entered into a pledge and control agreement (the “Pledge Agreement”), among the Company, the Trust and the Collateral Agent, under which the Trust agreed to grant a security interest over the Eligible Treasury Assets in favor of the Collateral Agent for the benefit of the LC Issuers. Pursuant to the LC

Agreement and the Pledge Agreement, the Collateral Agent is entitled to withdraw Eligible Treasury Assets from the Trust’s pledged account, following notice to the Company, in the event the Company has failed to reimburse amounts drawn under any letter of credit issued pursuant to the LC Agreement, and the LC Issuers have the right to instruct the Collateral Agent to enforce the pledge over the Eligible Treasury Assets upon the occurrence of any event of default under the LC Agreement.

Non-recourse Debt

The following are descriptions of certain indebtedness of NRG's subsidiaries. All of NRG's non-recourse debt is secured by the assets in the subsidiaries as further described below.

Acquired Vivint Smart Home Debt

On March 10, 2023, in connection with the Vivint Smart Home acquisition, Vivint Smart Home's indirect wholly owned subsidiary, APX Group, Inc. ("APX"), retained its 6.750% senior secured notes due 2027, 5.750% senior notes due 2029, senior secured term loan credit agreement and senior secured revolving credit facility.

Vivint Smart Home 2027 Senior Secured Notes

Vivint Smart Home has outstanding $600 million aggregate principal amount of 6.750% senior secured notes due 2027 (the "Vivint Smart Home 2027 Senior Secured Notes"). The Vivint Smart Home 2027 Senior Secured Notes are senior secured obligations of APX and are guaranteed by APX Group Holdings, Inc., each of APX's existing and future wholly owned U.S. restricted subsidiaries (subject to customary exclusions and qualifications) and Vivint Smart Home. Interest on the Vivint Smart Home 2027 Senior Secured Notes is paid semi-annually in arrears on February 15 and August 15 until the maturity date of February 15, 2027.

Vivint Smart Home 2029 Senior Notes

Vivint Smart Home has outstanding $800 million aggregate principal amount of 5.750% senior notes due 2029 (the "Vivint Smart Home 2029 Senior Notes"). The Vivint Smart Home 2029 Senior Notes are senior unsecured obligations of APX and are guaranteed by APX Group Holdings, Inc., each of APX's existing and future wholly owned U.S. restricted subsidiaries (subject to customary exclusions and qualifications) and Vivint Smart Home. Interest on the Vivint Smart Home 2029 Senior Notes is paid semi-annually in arrears on January 15 and July 15 until the maturity date of July 15, 2029.

Vivint Smart Home Senior Secured Credit Facilities

The Vivint Smart Home senior secured credit agreement (the “Vivint Smart Home Credit Agreement”) provides for (i) a term loan facility in an aggregate principal amount of $1.4 billion (the “Vivint Smart Home Term Loan Facility”, and the loans thereunder, the “Vivint Smart Home Term Loans”) and (ii) a revolving credit facility in an aggregate principal amount of $370 million (the “Vivint Smart Home Revolving Credit Facility,” and the loans thereunder, the “Vivint Smart Home Revolving Loans”).

All of APX’s obligations under the Vivint Smart Home Credit Agreement are guaranteed by APX Group Holdings, Inc. and each of APX’s existing and future wholly-owned U.S. restricted subsidiaries (subject to customary exclusions and qualifications). The obligations under the Vivint Smart Home Credit Agreement are secured by a first priority perfected security interest in (i) substantially all of the present and future tangible and intangible assets of APX, and the guarantors, including without limitation equipment, subscriber contracts and communication paths, intellectual property, general intangibles, investment property, material intercompany notes and proceeds of the foregoing, subject to permitted liens and other customary exceptions, (ii) substantially all personal property of APX and the guarantors consisting of accounts receivable arising from the sale of inventory and other goods and services (including related contracts and contract rights, inventory, cash, deposit accounts, other bank accounts and securities accounts), inventory and intangible assets to the extent attached to the foregoing books and records of APX and the guarantors, and the proceeds thereof, subject to permitted liens and other customary exceptions, in each case held by APX and the guarantors and (iii) a pledge of all of the capital stock of APX, each of its subsidiary guarantors and each restricted subsidiary of APX and its subsidiary guarantors, in each case other than certain excluded assets and subject to the limitations and exclusions provided in the applicable collateral documents.

The Vivint Smart Home Credit Agreement contains customary covenants, which, among other things, require APX to maintain a maximum first lien net leverage ratio when amounts outstanding under the Vivint Smart Home Revolving Facility exceed a certain threshold and restrict, subject to certain exceptions, APX and its restricted subsidiaries’ ability to:

•incur or guarantee additional debt or issue disqualified stock or preferred stock;

•pay dividends and make other distributions on, or redeem or repurchase, capital stock;

•make certain investments;

•incur certain liens;

•enter into transactions with affiliates;

•merge or consolidate;

•materially change the nature of their business;

•enter into agreements that restrict the ability of restricted subsidiaries to make dividends or other payments to APX or grant liens on their assets;

•designate restricted subsidiaries as unrestricted subsidiaries;

•amend, prepay, redeem or purchase certain material contractually subordinated debt; and

•transfer or sell certain assets.

On June 9, 2023, Vivint Smart Home entered into an amendment to the Vivint Smart Home Credit Agreement which transitioned the benchmark rate applicable to the Vivint Smart Home Term Loans and the Vivint Smart Home Revolving Loans from LIBOR to SOFR. As of September 30, 2023, the aggregate outstanding principal amount of the Vivint Term Loans was ~~issued~~$1.3 billion. As of September 30, 2023, Vivint Smart Home had no outstanding borrowings under ~~these facilities.~~the Vivint Smart Home Revolving Credit Facility.

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. ~~On June 1,~~During 2022, the ~~Company sold its 49% ownership in~~equity method of accounting for Ivanpah was suspended based on losses generated by the ~~Watson natural gas generating facility for $59 million as further described in Note 4,Acquisitions~~project, including the impact of debt service and ~~Dispositions~~.depreciation.

Variable Interest Entities that are Consolidated

The Company has a controlling financial interest that has been identified as a VIE under ASC 810 in NRG Receivables LLC, which has entered into financing transactions related to the Receivables Facility as further described in Note 13, Long-term Debt and Finance Leases, to the Company’s ~~2021~~2022 Form 10-K.

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


(In millions)	(In millions)	September 30, 2022		December 31, 2021		(In millions)	September 30, 2023		December 31, 2022
Accounts receivable and Other current assets	Accounts receivable and Other current assets	$	1,269	$	939	Accounts receivable and Other current assets	$	1,796	$	2,108

Current liabilities	Current liabilities	153		78		Current liabilities	153		152

Net assets	Net assets	$	1,116	$	861	Net assets	$	1,643	$	1,956

3041

Note 11 — Changes in Capital Structure

As of September 30, ~~2022~~2023 and December 31, ~~2021,~~2022, the Company had 10,000,000 shares of preferred stock authorized and 500,000,000 shares of common stock authorized. The following table reflects the changes in NRG's preferred and common stock issued and outstanding:


		Issued	Treasury	Outstanding		Preferred	Common
Balance as of December 31, 2021		423,547,174	(179,793,275)	243,753,899
						Issued and Outstanding	Issued	Treasury	Outstanding
Balance as of December 31, 2022					Balance as of December 31, 2022	—	423,897,001	(194,335,971)	229,561,030
Shares issued under LTIPs					Shares issued under LTIPs	—	1,011,448	—	1,011,448
Shares issued under ESPP					Shares issued under ESPP	—	—	86,516	86,516
Issuance of Series A Preferred Stock					Issuance of Series A Preferred Stock	650,000	—	—	—
Shares repurchased					Shares repurchased	—	—	(1,322,141)	(1,322,141)
Balance as of September 30, 2023					Balance as of September 30, 2023	650,000	424,908,449	(195,571,596)	229,336,853
Shares issued under LTIPs	Shares issued under LTIPs	347,365	—	347,365	Shares issued under LTIPs	—	55,507	—	55,507
Shares issued under ESPP	Shares issued under ESPP	—	68,941	68,941	Shares issued under ESPP	—	—	104,733	104,733
Shares repurchased	Shares repurchased	—	(12,045,068)	(12,045,068)	Shares repurchased	—	—	(3,732,657)	(3,732,657)
Balance as of September 30, 2022		423,894,539	(191,769,402)	232,125,137
Shares issued under LTIPs		2,462	—	2,462
Shares issued under ESPP		—	73,884	73,884
Shares repurchased		—	(1,817,278)	(1,817,278)
Balance as of October 31, 2022		423,897,001	(193,512,796)	230,384,205
Balance as of October 31, 2023					Balance as of October 31, 2023	650,000	424,963,956	(199,199,520)	225,764,436

Common Stock

Share Repurchases

~~On December 6, 2021~~In June 2023, NRG revised its long-term capital allocation policy to target allocating approximately 80% of cash available for allocation, after debt reduction, to be returned to shareholders. As part of the revised capital allocation framework, the Company announced ~~that the Board of Directors has authorized $1~~an increase to its share repurchase authorization to $2.7 billion, ~~for share repurchases, as part of NRG’s capital allocation program. During 2021, $44 million of share repurchases were completed under this authorization.~~to be executed through 2025. During the ~~nine~~three months ended September 30, ~~2022,~~2023, the Company completed ~~additional $483~~$50 million of share repurchases at an average price of ~~$40.04.~~$37.82 under the $2.7 billion authorization. Through October 31, ~~2022,~~2023, an additional ~~$76~~$150 million of share repurchases were executed at an average price of ~~$41.71~~$40.17 per share. ~~In October 2022, the Board of Directors approved an additional $600 million in share repurchases.~~

~~The following repurchases have been made during the nine months ended September 30, 2022, and through October 31, 2022:~~
Total number of shares and share equivalents purchased Average price paid per share and share equivalent Amounts paid for shares and share equivalents purchased (in millions)
2022 repurchases
Repurchases(a)
12,045,068 $ 483
Equivalent shares purchased in lieu of tax withholdings on equity compensation issuances(b)
150,448 6
Total Share Repurchases during the nine months ended September 30, 2022
12,195,516 $40.07 489
Repurchases made during October(a)
1,817,278 $ 76
Equivalent shares purchased in October in lieu of tax withholdings on equity compensation issuances(b)
793 —
Total Share Repurchases January 1, 2022 through October 31, 2022 14,013,587 $40.28 $ 565

~~(a)Includes $10 million and $6 million accrued as of September 30, 2022 and October 31, 2022, respectively~~

~~(b)~~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 $42.75 and $41.04 for the nine months ended September 30, 2022 and for October 2022, respectively

Employee Stock Purchase Plan

The Company offers 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%~~90% of its market value on the offering date or ~~95%~~90% of the fair market value on the exercise date. An offering date occurs each April 1 and October 1. An exercise date occurs each September 30 and March 31. On April 27, 2023, NRG stockholders approved the adoption of the Amended and Restated Employee Stock Purchase Plan, effective April 1, 2023, which included a reduction in the price at which eligible employees may purchase shares of NRG common stock from 95% to 90% of the fair market value of the shares on the applicable date. NRG stockholders also approved an increase of 4,400,000 shares available for the issuance under the ESPP.

NRG Common Stock Dividends

During the first quarter of ~~2022,~~2023, NRG increased the annual dividend to ~~$1.40~~$1.51 from ~~$1.30~~$1.40 per share and expects to target an annual dividend growth rate of 7%-9% per share in subsequent years. A quarterly dividend of ~~$0.35~~$0.3775 per share was paid on the Company's common stock during the three months ended September 30, ~~2022.~~2023. On October ~~21, 2022,~~19, 2023, NRG declared a quarterly dividend on the Company's common stock of ~~$0.35~~$0.3775 per share, payable on November 15, ~~2022~~2023 to stockholders of record as of November 1, ~~2022.~~2023. Beginning in the first quarter of ~~2023,~~2024, NRG will increase the annual dividend by 8% to ~~$1.51~~$1.63 per share.

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

Preferred Stock

Series A Preferred Stock

On March 9, 2023 ("Series A Issuance Date"), the Company issued 650,000 shares of 10.25% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock ("Series A Preferred Stock"). The net proceeds of $635 million, net of issuance costs, were used to partially fund the Vivint Smart Home acquisition.

The Series A Preferred Stock is not convertible into or exchangeable for any other securities or property and has limited voting rights. The Series A Preferred Stock may be redeemed, in whole or in part, on one or more occasions, at the option of the

Company at any time after March 15, 2028 ("Series A First Reset Date") and in certain other circumstances prior to the Series A First Reset Date. The Series A Preferred Stock has a liquidation preference of $1,000 per share, plus accumulated but unpaid dividends.

Series A Preferred Stock Dividends

The annual dividend rate on each share of Series A Preferred Stock is 10.25% from the Series A Issuance Date to, but excluding the Series A First Reset Date. On and after the Series A First Reset Date, the dividend rate on each share of Series A Preferred Stock shall equal the five-year U.S. Treasury rate as of the most recent reset dividend determination date (subject to a floor of 1.00%), plus a spread of 5.92% per annum. Cumulative cash dividends on the Series A Preferred Stock are payable semiannually, in arrears, on each March 15 and September 15, when, as and if declared by the board of directors. In September 2023, the Company paid a semi-annual dividend of $52.96 per share on its outstanding Series A Preferred Stock, totaling $34 million.

Note 12 — ~~Income~~Income/(Loss) Per Share

Basic ~~income~~income/(loss) per common share is computed by dividing net ~~income~~income/(loss) less cumulative dividends attributable to preferred stock by the weighted average number of common shares outstanding. Shares issued and treasury shares repurchased during the ~~year~~period are weighted for the portion of the ~~year~~period that they were outstanding. Diluted ~~income~~income/(loss) per share is computed in a manner consistent with that of basic ~~income~~income/(loss) per share while giving effect to all potentially dilutive common shares that were outstanding during the ~~period.~~period when there is net income. The ~~outstanding~~ relative performance stock units, non-vested restricted ~~stock units, market~~ stock units, and non-qualified stock options are not considered outstanding for purposes of computing basic ~~income~~income/(loss) per share. However, these instruments are included in the denominator for purposes of computing diluted income per share under the treasury stock method for periods when ~~we have~~there is net income. The Convertible Senior Notes are convertible, under certain circumstances, into cash or combination of cash and Company’s common stock. Prior to adoption of ASU 2020-06, there was no dilutive effect for the Convertible Senior Notes due to the Company’s expectation to settle the liability in cash. Upon adoption of ASU 2020-06, on January 1, 2022, theThe Company is including the potential share settlements, if any, in the denominator for purposes of computing diluted income per share under the if converted method for periods when ~~we have~~there is net income. The potential shares settlements are calculated as the excess of the Company's conversion obligation over the aggregate principal amount (which will be settled in cash), divided by the average share price for the period. For each of the ~~periods~~three and nine months ended September 30, 2023 and 2022, there was no dilutive effect for the Convertible Senior Notes since there were no potential share settlements for ~~these~~the periods.

NRG's basic and diluted ~~income~~income/(loss) per share is shown in the following table:

Three months ended September 30, Nine months ended September 30,
(In millions, except per share data) 2022 2021 2022 2021
Basic and diluted income per share:
Net income $ 67 $ 1,618 $ 2,316 $ 2,614
Weighted average number of common shares outstanding - basic and diluted 235 245 238 245
Income per weighted average common share — basic and diluted $ 0.29 $ 6.60 $ 9.73 $ 10.67


	Three months ended September 30,				Nine months ended September 30,
(In millions, except per share data)	2023		2022		2023		2022
Basic income/(loss) per share:
Net income/(loss)	$	343	$	67	$	(684)	$	2,316
Less: Cumulative dividends attributable to Series A Preferred Stock	17		—		38		—
Net income/(loss) available for common stockholders	$	326	$	67	$	(722)	$	2,316
Weighted average number of common shares outstanding - basic	230		235		230		238
Income/(loss) per weighted average common share — basic	$	1.42	$	0.29	$	(3.14)	$	9.73

Diluted income/(loss) per share:
Net income/(loss)	$	343	$	67	$	(684)	$	2,316
Less: Cumulative dividends attributable to Series A Preferred Stock	17		—		38		—
Net income/(loss) available for common stockholders	$	326	$	67	$	(722)	$	2,316
Weighted average number of common shares outstanding - basic	230		235		230		238
Incremental shares attributable to the issuance of equity compensation (treasury stock method)	2		—		—		—
Weighted average number of common shares outstanding - dilutive	232		235		230		238
Income/(loss) per weighted average common share — diluted	$	1.41	$	0.29	$	(3.14)	$	9.73

~~As of~~For the nine months ended September 30, ~~2022,~~2023, the Company had 6 million of outstanding equity instruments that are anti-dilutive and ~~2021,~~were not included in the computation of the Company's diluted loss per share. For all other periods presented, 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~~Company's diluted income per share.

Note 13 — Segment Reporting

The Company’s segment structure reflects how management currently makes financial decisions and allocates resources. The Company manages its operations based on the combined results of the retail and wholesale generation businesses with a geographical focus. The acquired operations from the Vivint Smart Home acquisition are reported within the Vivint Smart Home segment.

NRG’s chief operating decision maker, its chief executive officer, evaluates the performance of ~~its~~the Company's 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). The accounting policies of the segments are the same as those applied in the consolidated financial statements as disclosed in Note 2, Summary of Significant Accounting Policies, to the Company’s 2022 Form 10-K.

Three months ended September 30, 2022
(In millions) Texas East West/Services/Other Corporate Eliminations Total
Revenue $ 3,149 $ 4,180 $ 1,169 $ — $ 12 $ 8,510
Depreciation and amortization 77 39 22 7 — 145
Impairment losses — 43 — — — 43
Gain on sale of assets 22 — — — — 22
Equity in (losses)/earnings of unconsolidated affiliates (1) — 12 — — 11
(Loss)/Income before income taxes (475) 555 106 (103) — 83
Net (loss)/income $ (475) $ 555 $ 88 $ (101) $ — $ 67


	Three months ended September 30, 2023
(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate		Eliminations		Total
Revenue	$	3,686	$	2,809	$	978	$	478	$	—	$	(5)	$	7,946
Depreciation and amortization	71		27		23		178		9		—		308


Equity in earnings of unconsolidated affiliates	—		—		6		—		—		—		6

Income/(loss) before income taxes	463		314		(205)		(24)		(140)		—		408



Net income/(loss)	$	463	$	316	$	(168)	$	(4)	$	(264)	$	—	$	343


	Three months ended September 30, 2022
(In millions)	Texas		East		West/Services/Other		Corporate		Eliminations		Total
Revenue	$	3,145	$	4,178	$	1,175	$	—	$	12	$	8,510
Depreciation and amortization	79		37		22		7		—		145
Impairment losses	—		43		—		—		—		43
Gain on sale of assets	22		—		—		—		—		22
Equity in (losses)/earnings of unconsolidated affiliates	(1)		—		12		—		—		11

(Loss)/income before income taxes	(481)		557		110		(103)		—		83



Net (loss)/income	$	(481)	$	557	$	92	$	(101)	$	—	$	67



	Nine months ended September 30, 2023
(In millions)	Texas		East		West/Services/Other		Vivint Smart Home(a)		Corporate		Eliminations		Total
Revenue	$	8,235	$	9,488	$	3,244	$	1,070	$	—	$	(21)	$	22,016
Depreciation and amortization	219		87		70		410		27		—		813


Gain on sale of assets	—		202		—		—		—		—		202
Equity in earnings of unconsolidated affiliates	—		—		16		—		—		—		16


Income/(loss) before income taxes	1,532		(1,188)		(684)		(86)		(440)		—		(866)




Net income/(loss)	$	1,532	$	(1,187)	$	(601)	$	(66)	$	(362)	$	—	$	(684)

(a)Includes results of operations following the acquisition date of March 10, 2023



	Nine months ended September 30, 2022
(In millions)	Texas		East		West/Services/Other		Corporate		Eliminations		Total
Revenue	$	7,857	$	12,407	$	3,395	$	—	$	29	$	23,688
Depreciation and amortization	233		164		65		23		—		485
Impairment losses	—		198		—		—		—		198

Gain/(loss) on sale of assets	10		—		43		(2)		—		51
Equity in (losses)/earnings of unconsolidated affiliates	(2)		—		2		—		—		—

Income/(loss) before income taxes	1,052		2,082		274		(353)		—		3,055



Net income/(loss)	$	1,052	$	2,083	$	246	$	(1,065)	$	—	$	2,316

3244

Three months ended September 30, 2021
(In millions) Texas East West/Services/Other Corporate Eliminations Total
Revenue $ 2,635 $ 3,077 $ 883 $ — $ 14 $ 6,609
Depreciation and amortization 84 87 21 7 — 199
Equity in (losses)/earnings of unconsolidated affiliates (2) — 17 — — 15
Income/(loss) before income taxes 251 1,980 140 (208) — 2,163
Net income/(loss) $ 251 $ 1,980 $ 126 $ (739) $ — $ 1,618

Nine months ended September 30, 2022
(In millions) Texas East West/Services/Other Corporate Eliminations Total
Revenue $ 7,868 $ 12,414 $ 3,377 $ — $ 29 $ 23,688
Depreciation and amortization 230 167 65 23 — 485
Impairment losses — 198 — — — 198
Gain/(loss) on sale of assets 10 — 43 (2) — 51
Equity in (losses)/earnings of unconsolidated affiliates (2) — 2 — — —
Income/(loss) before income taxes 1,064 2,085 259 (353) — 3,055
Net income/(loss) $ 1,064 $ 2,086 $ 231 $ (1,065) $ — $ 2,316

Nine months ended September 30, 2021
(In millions) Texas East West/Services/Other Corporate Eliminations Total
Revenue $ 8,362 $ 9,002 $ 2,564 $ — $ 15 $ 19,943
Depreciation and amortization 245 237 66 21 — 569
Impairment losses — 306 — — — 306
Gain on sale of assets — — 17 — — 17
Equity in (losses)/earnings of unconsolidated affiliates (3) — 26 — — 23
Income/(loss) before income taxes 600 3,119 271 (536) — 3,454
Net income/(loss) $ 600 $ 3,119 $ 239 $ (1,344) $ — $ 2,614

Note 14 — Income Taxes

Effective Income Tax Rate

The income tax provision consisted of the following:


		Three months ended September 30,						Nine months ended September 30,							Three months ended September 30,						Nine months ended September 30,
(In millions, except rates)	(In millions, except rates)	2022			2021			2022			2021			(In millions, except rates)	2023			2022			2023			2022
Income before income taxes		$	83		$	2,163		$	3,055		$	3,454
Income tax expense		16			545			739			840
Income/(Loss) before income taxes														Income/(Loss) before income taxes	$	408		$	83		$	(866)		$	3,055
Income tax expense/(benefit)														Income tax expense/(benefit)	65			16			(182)			739

Effective income tax rate	Effective income tax rate	19.3		%	25.2		%	24.2		%	24.3		%	Effective income tax rate	15.9		%	19.3		%	21.0		%	24.2		%

For the nine months ended September 30, 2023, the effective tax rate approximated the statutory rate of 21%, which includes the impact of state and foreign taxes. For the three months ended September 30, 2023, the effective tax rate was lower than the statutory rate of 21%, primarily due to a decrease in state tax expense resulting from a decrease in year-to-date financial statement losses. For the three months ended September 30, 2022, the effective tax rate was lower than the statutory rate of 21% primarily due to the benefit resulting from carbon capture tax credits and the reduction in statutory state tax rates. For the nine months ended September 30, 2022, the effective tax rate was higher than the statutory rate of 21% primarily due to state tax expense, partially offset by tax benefit resulting from the release of valuation allowance on state net operating losses and carbon capture tax credits. For the three months ended September 30, 2021, the effective tax rate was higher than the statutory rate of 21% primarily due to state tax expense. For the nine months ended September 30, 2021 the effective tax rate was higher than the statutory rate of 21% primarily due to state tax expense partially offset by one-time tax benefits, as a result of the acquisition of Direct Energy, on the revaluation of state deferred tax assets, NOLs and valuation allowance.

The Inflation Reduction Act ("IRA") enacted on August 16, 2022, introduced new provisions including a 15% corporate book minimum tax and a 1% excise tax on net share repurchases with both taxes effective beginning in fiscal year 2023 for NRG. ~~Additionally,~~The Company will continue to evaluate the ~~IRA establishes a~~impact of the corporate book minimum tax ~~credit associated with existing nuclear facilities which begins in 2024 and terminates at~~when the ~~end of 2031. The tax credit will fully apply when gross revenues are at or below $25 per MWh and phases out completely at $43.75 per MWh. The~~ U.S. Treasury ~~is now taking comments on what should be included in~~and the ~~definition of gross revenues.~~IRS release further guidance.

Uncertain Tax Benefits

As of September 30, ~~2022,~~2023, NRG had a non-current tax liability of ~~$23~~$48 million for uncertain tax benefits from positions taken on various federal, state, and ~~state~~foreign income tax returns inclusive of accrued interest. For the nine months ended September 30, ~~2022,~~2023, NRG accrued ~~an immaterial amount~~$1 million of interest relating to the uncertain tax benefits. As of September 30, ~~2022,~~2023, NRG had cumulative interest and penalties related to these uncertain tax benefits of $1$3 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 2019. With few exceptions, state and ~~local~~Canadian income tax examinations are no longer open for years prior to ~~2013.~~2014.

Note 15 — Related Party Transactions

NRG provides services to some of its related parties, who are accounted for as 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~~third-party affiliates:


		Three months ended September 30,				Nine months ended September 30,					Three months ended September 30,				Nine months ended September 30,
(In millions)	(In millions)	2022		2021		2022		2021		(In millions)	2023		2022		2023		2022
Revenues from Related Parties Included in Revenue	Revenues from Related Parties Included in Revenue									Revenues from Related Parties Included in Revenue
Gladstone	Gladstone	$	1	$	1	$	2	$	2	Gladstone	$	1	$	1	$	2	$	2

Ivanpah(a)	Ivanpah(a)	10		9		32		30		Ivanpah(a)	15		10		70		32
Midway-Sunset	Midway-Sunset	2		1		5		4		Midway-Sunset	—		2		2		5

Total	Total	$	13	$	11	$	39	$	36	Total	$	16	$	13	$	74	$	39

(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 hedges. 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. As of September 30, ~~2022,~~2023, hedges under the first lien program were out-of-the-money for NRG on a counterparty aggregate basis.

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 ~~differences~~difference could be material.

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

Environmental Lawsuits

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 in an interim order 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~~During the second quarter of 2023, the IPCB ~~will hold~~held hearings ~~to determine~~regarding the appropriate relief. Midwest Generation has been working with the Illinois EPA to address the groundwater issues since 2010.

Consumer Lawsuits

Similar to other energy service companies (“ESCOs”) operating in the industry, from time-to-time, the Company and/or its subsidiaries may be subject to consumer lawsuits in various jurisdictions where they sell natural gas and electricity.

Variable Price Cases — In the cases set forth below, referred to as the Variable Price Cases, such actions involve consumers alleging that one of the Company’s ESCOs promised that consumers would pay the same or less than they would have paid if they stayed with their default utility or previous energy supplier. The underlying claims of each case are similar and the Company continues to deny the allegations and is vigorously defending these matters. These matters were known and accrued for at the time of each acquisition.

XOOM Energy

Mirkin v. XOOM Energy (E.D.N.Y. Aug. 2019) is a defendant in a putative class action lawsuit pending in New York. ~~This case~~The Court denied XOOM's motion for summary judgment and granted class certification. XOOM is incurrently petitioning to appeal the ~~discovery phase.~~class certification grants and seeking a stay at the trial court.

Direct Energy

There are ~~four~~two putative class actions pending against Direct Energy: (1) Linda Stanley v. Direct Energy (S.D.N.Y Apr. 2019) - The parties mediated in June 2021 and agreed on a settlement. In April 2022, the Court granted final approval of the settlement, which was primarily paid during the second quarter of 2022; (2) Martin Forte v. Direct Energy (N.D.N.Y. Mar. 2017) - In December 2021, the Court granted Direct Energy's Motion for summary judgment effectively ending the matter at the district court level. In January 2022, Forte appealed. The briefing is complete. Oral arguments are anticipated for late 2022 or early 2023; (3) Richard Schafer v. Direct Energy (W.D.N.Y. Dec. 2019; on appeal ~~2nd~~2nd Cir. N.Y.) - The 2ndSecond Circuit sent the matter back to the trial court in December 2021. After discovery, Direct Energy filed summary ~~judgment;~~judgment. Direct Energy won summary judgment and ~~(4)~~Schafer appealed. The appeal is fully briefed. Oral argument occurred on October 25, 2023. Given the result of Martin Forte v. Direct Energy (N.D.N.Y. Mar. 2017), it is expected that the trial court's summary judgment will be upheld and Direct Energy will prevail; and (2) Andrew Gant v.

Direct Energy and NRG (D.N.J. Aug. 2022) - The Court granted Direct Energy and ~~NRG filed a~~NRG's Motion to Dismiss on ~~October 18, 2022.~~July 21, 2023, but allowed for the Plaintiff to amend his Complaint. The case was dismissed on September 29, 2023. The parties reached a settlement for the Plaintiff's individual claim.

Telephone Consumer Protection Act ("TCPA") Cases — In the cases set forth below, referred to as the TCPA Cases, such actions involve consumers alleging violations of the Telephone Consumer Protection Act of 1991, as amended, by receiving calls, texts or voicemails without consent in violation of the federal Telemarketing Sales Rule, and/or state counterpart legislation. The underlying claims of each case are similar. The Company denies the allegations asserted by plaintiffs and intends to vigorously defend these matters. These matters were known and accrued for at the time of the acquisition.

There are two putative class actions pending against Direct Energy: (1) Holly Newman v. Direct Energy, LP (D. Md Sept 2021) - Direct Energy filed its Motion to Dismiss asserting the ruling in the Brittany Burk v. Direct Energy (S.D. Tex. Feb 2019) preempts the Plaintiff's ability to file suit based on the same facts. The Court denied Direct Energy's motion stating the Court does not have the benefit of all of the facts that were in front of the Burk court to issue a similar ruling. On October 19, 2022, Direct Energy filed a Motion to Transfer Venue asking the Court to transfer the case to the Southern District where the ~~Buck~~Burk case was filed. On April 12, 2023, the Court granted Direct ~~Energy will await~~Energy’s Motion to Transfer Venue, moving to the ~~court's ruling before moving forward with written discovery;~~case to the Southern District of Texas; and (2) Matthew Dickson v. Direct Energy (N.D. Ohio Jan. 2018) - The case was stayed pending the outcome of an appeal to the Sixth Circuit based on the unconstitutionality of the TCPA during the period from 2015-2020. The Sixth Circuit found the TCPA was in effect during that period and remanded the case back to the trial court. Direct Energy refiled its motions along with supplements. On March 25, 2022, the Court granted summary judgment in favor of Direct Energy and dismissed the case. Dickson ~~appealed,~~appealed. The Sixth Circuit found that Dickson has standing and reversed the trial court's dismissal of the case. The matter is back at the trial court. The parties will conduct further fact discovery and expert discovery and are likely to resubmit motions for further review by the Court.

Sales Practice Lawsuits

There are three litigation matters relating to claims made by Vivint Smart Home competitors against Vivint Smart Home alleging, among other things, that Vivint Smart Home's sales representatives used deceptive sales practices. These matters were known and accrued for at the time of the acquisition. The three matters are: (1) CPI Security Systems, Inc. ("CPI") v. Vivint Smart Home, Inc. (W.D.N.C. Sept. 2020). The CPI matter that was filed in 2020 went to trial, and in February 2023, the jury issued a verdict against Vivint Smart Home, in favor of CPI for $50 million of compensatory damages and an additional $140 million of punitive damages. Vivint Smart Home filed its post-trial motion in March 2023 and continues to evaluate its post-trial and appeal options. While Vivint Smart Home believes the CPI jury verdict is not legally or factually supported and intends to pursue post judgment remedies and file an appeal, there can be no assurance that such defense efforts will be successful; (2) ADT LLC, et al. ("ADT") v. Vivint Smart Home, Inc. f/k/a Mosaic Acquisition Corporation, et al.(S.D.Fl. Aug. 2020). The parties mediated in May 2023 and agreed on a settlement. In June 2023, the Court granted final approval of the settlement, which was paid in June 2023; and (3) Alert 360 Opco, Inc, et al. ("Alert 360") v. Vivint Smart Home, Inc., et al (N.D.Ok. March 2023). On March 1, 2023, Alert 360 filed a complaint against Vivint Smart Home alleging, among other things, deceptive sales practices. The parties mediated in August 2023 and agreed to a settlement, which is expected to be finalized during the fourth quarter of 2023.

Patent Infringement Lawsuits

SB IP Holdings LLC (“Skybell”) v. Vivint Smart Home, Inc. — On October 23, 2023, a jury in the U.S. District Court, Eastern District of Texas, Sherman Division, issued a verdict against the Company in favor of Skybell for $45 million in damages for patent infringement. The patents that were the basis for the claims made by Skybell were ruled invalid by the U.S. International Trade Commission in November 2021. In accordance with advice by legal counsel, the Company does not believe the verdict is legally supported and will pursue post-judgment and appellate remedies along with any other legal options available.

Contract Disputes

Alarm.com — In September 2022, Vivint Smart Home sent Alarm.com a notice asserting that it was no longer obligated to pay certain license fees under the Patent Cross License Agreement between the parties on the basis that Vivint Smart Home no longer practices any claim under any valid Alarm.com patent and, therefore, no license fees are due. Alarm.com filed an arbitration demand against Vivint Smart Home alleging, among other things, breach of the agreement due to continued use of the patents in question. The arbitration panel recently determined that Vivint Smart Home's challenge to the validity of certain Alarm.com patents will be considered as part of the arbitration proceeding.

STP — In July 2023, the partners in STP, CPS and Austin Energy, initiated a lawsuit and filed to intervene in the license transfer application with the NRC, claiming a right of first refusal exists in relation to the proposed sale of NRG South Texas' 44% interest in STP to Constellation. NRG believes the claims set forth by CPS and Austin Energy in the lawsuit and the ~~parties~~NRC

proceedings are inwithout merit and intends to vigorously defend against them. For further discussion of the ~~briefing process.~~transaction, see Note 4, Acquisitions and Dispositions.

Winter Storm Uri Lawsuits

The Company has been named in certain property damage and wrongful death claims that have been filed in connection with Winter Storm Uri in its capacity as a generator and a ~~retail electric provider.~~REP. Most of the lawsuits related to Winter Storm Uri are consolidated into a single multi-district litigation matter in Harris County District Court. NRG's REPs have since been severed from the multi-district litigation and will be seeking dismissal in any remaining cases. As a power generator, the Company is named in ~~161~~various cases with claims ranging from: wrongful death; personal injury only; property damage and personal injury; property damage only; and subrogation. ~~As a retail electric provider, the Company~~The case is named in 27 lawsuits with similar claims: wrongful death; property damage only; personal injury only; and both personal injury and property damage. The power generators and retail electric providers filed five motions to dismiss that represent the breadth of the claims filed against them. Briefing is

~~complete and oral arguments occurred~~currently stayed pending appeal by other parties on ~~October 11-12, 2022. All of the lawsuits related to Winter Storm Uri are consolidated into a single multi-district litigation matter in Harris County District Court.~~other issues. The Company intends to vigorously defend these matters.

Indemnifications and Other Contractual Arrangements

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. On February 4, 2019, NRG sold the South Central Portfolio, including the entities subject to this litigation. However, NRG had agreed to indemnify the purchaser for certain losses suffered in connection with this litigation. In February 2020, the federal court dismissed this lawsuit without prejudice for lack of subject matter jurisdiction. 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~~matters, which was dismissed on October 2, 2023 pursuant to ~~this litigation. However, NRG has agreed to indemnify the purchaser for certain losses suffered in connection therewith.~~a settlement agreement.

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

In addition to the regulatory proceeding 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.

Note 18 — Environmental Matters

NRG is subject to a wide range of 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 maintained during operation of power plants. The electric generation industry has been facing increasingly stringent requirements regarding air quality, GHG emissions, combustion byproducts, water ~~discharge~~use and ~~use,~~discharge, and threatened and endangered species. In general, future laws are expected to require the addition of emissions controls or other environmental controls or to impose additional 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. The Company has elected to use a $1 million disclosure threshold, as permitted, for environmental proceedings to which the government is a party.

Air

CPP/ACE Rules — On July 8, 2019, the EPA promulgated the ACE rule, which rescinded the CPP, which had sought to broadly regulate CO2 emissions from the power sector. The ACE rule required states that have coal-fired EGUs to develop plans to seek heat rate improvements from coal-fired EGUs. On January 19, 2021, the D.C. Circuit vacated the ACE rule (but on February 22, 2021, at the EPA's request, stayed the issuance of the portion of the mandate that would ~~have vacated~~vacate the repeal of the CPP). On June 30, 2022, the U.S. Supreme Court held that the "generation shifting" approach in the CPP exceeded the powers granted to the EPA by Congress. The Court did not address the related issues of whether the EPA may adopt only measures applied at each source. On May 23, 2023, the EPA proposed significantly revising the manner in which new and existing EGU's GHG emissions should be regulated including using hydrogen as a fuel, capturing and storing/sequestering CO2 and requiring new units to be more efficient. The EPA has stated that it intends to finalize these revisions in 2024. The Company ~~anticipates~~expects that ~~there~~the final rule will be ~~additional proceedings at~~challenged in the ~~D.C. Circuit~~courts and ~~additional rulemaking by the EPA over the next~~accordingly uncertain for several years.

Cross-State Air Pollution Rule ("CSAPR") — ~~In April 2022,~~On March 15, 2023, the EPA ~~proposed revising~~signed and released a prepublication of a final rule that sought to significantly revise the CSAPR to address the good-neighbor ~~provisions~~obligations of the 2015 ozone ~~NAAQS.~~NAAQS for 23 states after earlier having disapproved numerous state plans to address the issue. Several states, including Texas, challenged the EPA's disapproval of their state plans. On May 1, 2023, the United States Court of Appeals for the Fifth Circuit stayed the EPA's disapproval of Texas' and Louisiana's state plans, which disapprovals are a condition precedent to the EPA imposing its plan on Texas and Louisiana. Several other states are also similarly situated because of similar stays. Nonetheless, on June 5, 2023, the EPA published this rule in the Federal Register. On July 31, 2023, the EPA promulgated an interim final rule that addresses the various judicial orders that have stayed several State-Implementation-Plan disapprovals by limiting the effectiveness of certain requirements of the final rule promulgated on June 5, 2023 in Texas and five other states. The final rule decreases, over time, the ozone-season NOx allowances allocated to generators in the states not affected by the judicial stays beginning this summer by assuming that participants in this cap-and-trade program had or would optimize existing NOx controls and later install additional NOx controls. The Company cannot predict the outcome of the legal challenges to the: (i) various state disapprovals; (ii) the final rule promulgated on June 5, 2023; and (iii) the interim final rule promulgated on July 31, 2023 that seeks to address the judicial orders.

Regional Haze Proposal — On May 2023, the EPA proposed to withdraw the existing Texas Sulfur Dioxide Trading Program and replace it with unit-specific SO2 limits for 12 units in Texas to address requirements to improve visibility at National Parks and Wilderness areas. If ~~the rule were~~ finalized as proposed, it would ~~apply to 25 states (including Texas) beginning~~result in ~~2023. In 2023,~~more stringent SO2 limits for two of the ~~revised Group 3 trading program (previously established~~Company's coal-fired units in the Revised CSAPR Update Rule) would have emission budgets based on NOx emission rates that the EPA says are achievable by existing controls at power plants. Starting in 2026, the NOx budgets would be reduced significantly based on levels achievable if selective catalytic reduction ("SCR") controls were installed at coal-fueled power plants that do not currently have such controls. Starting in 2025, the budgets would be updated annually to account for retirements, changes to operations and new units. The proposal also contemplates heightened surrender requirements for units that exceed certain NOx emission rate thresholds. Comments on the proposed rule were due in June 2022 and numerous detailed comments were submitted.Texas. The Company cannot predict the outcome of this ~~proposed revision and anticipates that this rulemaking will be subject to legal challenges after it is finalized.~~proposal.

Water

Effluent Limitations Guidelines — In November 2015, the EPA revised the Effluent Limitations Guidelines ("ELG") for Steam Electric Generating Facilities, which 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, postponed 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 amended the rule. On October 13, 2020, the EPA amended the 2015 ELG rule by: (i) altering the stringency of certain limits for FGD wastewater; (ii) relaxing the zero-discharge requirement for bottom ash transport water; and (iii) changing several deadlines. ~~On July 26,~~In 2021, the EPA announced that it iswas initiating a new rulemaking to evaluate revising the ELG ~~rule. While the EPA is developing the new~~ rule but keeping the existing rule (as amended in 2020) ~~will stay~~ in ~~place, and~~place. On March 29, 2023, the EPA ~~expects permitting authorities~~proposed revisions to ~~continue to implement~~ the ~~current regulation. The Company anticipates that~~ELG and sought comments on the proposal, which the EPA ~~will release a proposed rule in the first quarter of 2023.~~is currently analyzing. In October 2021, NRG informed its regulators that the Company intends to comply with the ELG by ceasing combustion of coal by the end of 2028 at its domestic coal units outside of Texas, and installing appropriate controls by the end of 2025 at its two plants that have coal-fired units in Texas.

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 amended 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. In 2019 and 2020, the EPA proposed several changes to this rule.~~surface impoundments. On August 28, 2020, the EPA finalized "A Holistic Approach to Close Part A: Deadline to Initiate Closure," which amended the April 2015 Rule to address the August 2018 D.C. Circuit decision and extend some of the deadlines. On November 12, 2020, the EPA finalized "A Holistic Approach to Closure Part B," which further amended the April 2015 Rule to, among other things, provide procedures for requesting approval to operate existing impoundments with an alternative liner. On May 23, 2023, the EPA proposed establishing requirements for: (i) inactive (or legacy) surface impoundments at inactive facilities and (ii) all coal combustion residual ("CCR") management units (regardless of how or when the CCR was placed) at regulated facilities. The EPA also solicited comments on this proposal. NRG anticipates further rulemaking related to the Federal Permit Program and legacy surface impoundments.

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

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~~Liquidity and capital resources including liquidity position, financial condition addressing ~~liquidity position, sources~~credit ratings, material cash requirements and ~~uses of liquidity, capital resources and requirements,~~

commitments, and ~~off-balance sheet arrangements;~~other obligations; and

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

As you read this discussion and analysis, refer to NRG's ~~Condensed Consolidated Statements~~condensed consolidated statements of ~~Operations~~operations to this Form 10-Q, which present the results of operations for the three and nine months ended September 30, ~~2022~~2023 and ~~2021.~~2022. Also refer to NRG's ~~2021~~2022 Form 10-K, which includes detailed discussions of various items impacting the Company's business, results of operations and financial condition, including: General section; Strategy section; Business Overview section, including how regulation, weather, and other factors affect NRG's business; and Critical Accounting Estimates section.

Executive Summary

Introduction and Overview

NRG Energy, Inc., or NRG or the Company, is a ~~consumer~~leading energy, smart home and services company ~~built on dynamic retail brands. NRG brings~~fueled by market-leading brands, proprietary technologies, and complementary sales channels. Across the ~~power of energy to customers by producing and selling energy and related products and services, nation-wide in the U.S.~~United States and Canada, ~~in a manner that~~NRG delivers ~~value to all of NRG's stakeholders. The Company sells power, natural gas, home and power services, and develops~~ innovative, sustainable solutions, predominately under ~~the~~ brand names such as NRG, Reliant, Direct Energy, Green Mountain Energy ~~Stream,~~ and ~~XOOM Energy.~~Vivint, while also advocating for competitive energy markets and customer choice. The Company has a customer base that includes approximately ~~5.5~~7.5 million ~~Home customers as well as~~residential consumers in addition to commercial, industrial, and wholesale customers, supported by approximately 1615 GW of generation as of September 30, ~~2022.~~

2023
.

Strategy

NRG's strategy is to maximize stockholder value through the safe production and sale of reliable electricity and natural gas to its customers in the markets it serves, while ~~positioning the Company to provide~~also providing innovative home solutions to the end-use energy or service consumer. This strategy is intended to enable the Company to optimize the integrated model to generate stable and predictable cash flow, significantly strengthen earnings and cost competitiveness, and lower risk and volatility. Sustainability is a philosophy that underpins and facilitates value creation across ~~our~~NRG's business for ~~our~~its stakeholders. It is an integral piece of NRG's strategy and ties directly to the Company's business success, reduced risks and enhanced reputation.

To effectuate the Company’s strategy, NRG is focused on: (i) serving the energy needs of end-use residential, commercial and industrial, and wholesale ~~customers~~counterparties in competitive markets and optimizing on cross selling opportunities through its multiple brands and channels; (ii) offering a variety of energy products and services, including renewable energy solutions and smart home products and services that are differentiated by innovative features, premium service, integrated platforms, sustainability, and loyalty/affinity programs; (iii) excellence in operating performance of its assets; (iv) optimal hedging of its portfolio; and (v) engaging in disciplined and transparent capital allocation.

~~The Company implemented~~ a four-year plan that began in 2022 to spend $2 billion in order to achieve growth through optimization of the Company’s core power and natural gas sales, as well as integrated solution sales within our core network in both power and home services.

Energy Regulatory Matters

The Company’s regulatory matters are described in the Company’s ~~2021~~2022 Form 10-K in Item 1, Business — Regulatory Matters. These matters have been updated below and in Note 17, Regulatory Matters.

As participants in wholesale and retail energy markets and owners and operators 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 generation 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 and provinces 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~~

~~Inflation Reduction Act~~ — The IRA allocates $369 billion in spending for energy security and addressing climate change. Much of these investments come through the tax code in the form of clean energy tax credits. In the past, investment tax credits and production tax credits have played a vital role in the growth of wind and solar projects around the U.S., but they have had short lifespans, phaseouts and uncertainty of extensions. The IRA provides 10-year extensions on these tax credits, which will provide more certainty needed for investment decisions to build out these projects in the long-term. With new renewable generation coming online, renewable energy supply costs will likely become cheaper and more plentiful. NRG Home can also benefit from increased residential usage to charge electric vehicles ("EV") and special EV products. The IRA also introduced new tax provisions including a corporate book minimum tax and an excise tax on net stock repurchases with both taxes effective beginning in fiscal year 2023 for NRG. Additionally, the IRA establishes a tax credit associated with existing nuclear facilities which begins in 2024 and terminates at the end of 2031. The tax credit will fully apply when gross revenues are at or below $25 per MWh and phases out completely at $43.75 per MWh. The U.S. Treasury is now taking comments on what should be included in the definition of gross revenues.

~~State and Provincial Energy Regulation~~50

~~Illinois Legislation~~ — Illinois enacted the Climate and Equitable Jobs Act ("CEJA") on September 15, 2021, which targets 100% clean energy by 2050. CEJA focuses on (i) decarbonization, (ii) incentives to transition coal plants into clean energy facilities and (iii) nuclear subsidies. A component of CEJA is the Coal-to-Solar Energy Storage Grant Program. On June 1, 2022, the Illinois Department of Commerce and Economic Opportunity announced that NRG is eligible to receive almost $160 million over 10 years to develop battery storage at both the Waukegan and Will County power plant sites.

Regional Regulatory Developments

NRG is affected by rule/tariff changes that occur in the ISO regions. For further discussion on regulatory developments, see Note 17, Regulatory Matters.

Texas

Public Utility Commission of Texas’ Actions with Respect to Wholesale Pricing and Market Design — ~~In September 2021, the~~The PUCT ~~opened a rulemaking project~~continues to ~~evaluate whether it should amend its rules to modify the High System Wide Offer cap ("HCAP")~~analyze and ~~the ORDC, which is intended to ensure prices~~implement multiple options for promoting increased reliability in the ~~competitive~~wholesale electric market, ~~appropriately reflect~~including the value of operating reserves as the system approaches scarcity conditions. This rulemaking project concluded in December 2021, resulting in a rule amendment that lowered the HCAP to $5,000 per MWh and which expanded the minimum contingency level to 3,000 MW in Phase I. These two changes are broadly offsetting in their effect on overall average energy prices. In 2022, the PUCT has focused on the developmentadoption of a ~~winter firm fuel product. The PUCT directed ERCOT~~reliability standard for resource adequacy and market-based mechanisms to ~~issue a Request~~achieve this standard. During the 88th Regular Session, the Texas Legislature authorized deployment of the Performance Credit Mechanism ("PCM"), which will measure real-time contribution to system reliability and provide compensation for ~~Proposal~~resources to ~~procure dual fuel capability with on-site fuel storage~~be available, subject to certain "guardrails" such as an annual net cost cap, as part of ~~the initial firm fuel procurement for the winter~~its adoption of ~~2022 and 2023. The procurement amount will be 3,000MW to 4,000MW and capped at a cost of $54 million. For Phase II,~~ the PUCT Chair endorsed a version of NRG's Load-Serving Entity Reliability Obligation ("LSERO") idea; that retailers and other LSEs should be obliged to purchase an amount of physical reliability resources at critical hours commensurate with the state's newly cautious view of planning for tail events.Sunset Bill (House Bill 1500). The ~~PUCT is~~Texas Legislature also considering the development of a Backstop Reserve Service prior to implementation of an LSERO. ERCOT resource constraints will delay implementation, including Phase II items, by 12 to 24 months. Recently, the South Texas Electric Cooperative ("STEC") has filed a proposal to create a net-load based capacity market that allocates costs to loads, renewables and thermal resources with forced outages. A broad group of stakeholders, including NRG, have expressed support fordirected the PUCT to ~~include~~implement additional market design changes such as the ~~STEC proposal in the blueprint~~creation of a new ancillary service called Dispatchable Reliability Reserve Service ("DRRS") to further increase ERCOT's capability to manage net load variability and firming requirements for ~~further review alongside the LSERO even though there~~new generation resources which penalize poor performance during periods of low grid reserves. DRRS is ~~opposition for the specific cost allocation mechanism. The PUCT contracted with consulting firm E3~~expected to ~~develop design details and implementation specifics for the Phase II proposals due~~be implemented in the fourth quarter of ~~2022.~~2024. Additionally, through Senate Bill 2627, the Texas Legislature created the Texas Energy Fund, subject to voter approval in November 2023, which will provide grants and low-interest loans to incentivize the development of more dispatchable generation and smaller backup generation in ERCOT.

~~Activity~~Operating Reserve Demand Curve ("ORDC") — On August 3, 2023, the PUCT approved implementation of an enhancement to the ORDC as a bridge solution that was recommended by the ERCOT Technical Advisory Committee and the ERCOT board of directors. The ORDC enhancement will install price floors of $10 and $20 at reserve levels of 7,000 MW and 6,500 MW or below, respectively. ERCOT is expected to complete implementation in the fourth quarter of 2023.

Ruling on ~~Securitization and ERCOT~~ Pricing during Winter Storm Uri — On March 17, 2023, the Third Court of Appeals issued a ruling in Luminant Energy Co. v. PUCT, which is an appeal relating to the validity of two orders issued by the PUCT on February 15 and 16, 2021, respectively, governing scarcity pricing in the ERCOT wholesale electricity market during Winter Storm Uri. The Third Court found that the PUCT exceeded its statutory authority by ordering the market price of energy to be set at the high system wide offer cap due to scarcity conditions as a result of firm load shed occurring in ERCOT. The Third Court reversed the PUCT's orders and remanded the case. On March 23, 2023, the PUCT filed a petition for review to the Supreme Court of Texas seeking reversal of the Third Court's decision, which was granted on September 29, 2023. The Court has requested briefing on the merits and has set oral arguments for this case on January 30, 2024. The outcome of this appeal could potentially require a repricing of the market prices during the subject time period.

Voluntary Mitigation Plan ("VMP") Changes — On March 13, 2023, the PUCT Staff determined that a portion of NRG's VMP should be terminated due to the increase in procurement of ancillary services by ERCOT, specifically non-spin reserve services, following Winter Storm Uri. As such, PUCT Staff terminated part of the VMP for NRG which provides protection from wholesale market power abuse accusations related to offers for ancillary services. NRG agreed with these changes to the VMP. At the March 23, 2023 open meeting, the PUCT approved the amended VMP. Pursuant to amendments to Public Utility Regulation Act § 15.023 adopted during the 88th Legislative Session, NRG's VMP will be reviewed by the PUCT within two years or, in the event a wholesale market design change is made, not later than the 90th day after the implementation date of such change.

ERCOT Request for Proposals for Winter Capacity — On October 2, 2023, ERCOT issued a Request for Proposals for Capacity for Winter 2023-2024. Proposals are due in early November, and ERCOT will issue awards later in November. The ~~Texas Legislature acted~~contracts, if awarded, will start between December 1, 2023 and January 9, 2024 and will run until February 29, 2024. The costs of procurement of winter capacity, if any, will be charged to ~~pass~~Qualified Scheduling Entities on an hourly load-ratio share basis. Increases in costs assessed to LSEs are expected to be included in customer pricing.

PJM

Revisions to PJM Local Deliverability Area Reliability Requirement — The Base Residual Auction for the 2024/2025 delivery year commenced on December 7, 2022 and closed on December 13, 2022. On December 19, 2022, PJM announced that it would delay the publication of the auction results. On December 23, 2022, PJM made a ~~variety~~filing at FERC to revise the definition of ~~securitization vehicles~~Locational Deliverability Area Reliability Requirement in the Tariff. This would allow PJM to ~~finance exceptionally high power~~exclude certain resources from the calculation of the Local Deliverability Area Reliability Requirement. On February 21, 2023, FERC accepted PJM's filing. Multiple parties, including NRG, filed for rehearing. Rehearing was denied by operation of law, and ~~gas costs~~multiple parties, including the Company, filed appeals to the Third Circuit Court of Appeals. The price of the auction cleared significantly lower as a result of the PJM Tariff change.

Capacity Performance Penalties and Bonuses from Winter Storm ~~Uri, including HB 4492. ERCOT subsequently filed two applications requesting the PUCT~~Elliott — PJM experienced approximately 23 hours of Capacity Performance events from December 23-24, 2022 across PJM's entire footprint. The Company is subject to ~~issue Debt Obligation Orders ("DOOs") based on the legislation. On October 13, 2021, the PUCT issued DOOs authorizing ERCOT's securitization of $800 million to cover short payments~~penalty and reimburse congestion revenue right account holders for amount related to the default of market participants other than electric cooperatives Brazos Electric Cooperative Inc. ("Brazos") and Rayburn Country Electric Cooperative, Inc. ("Rayburn"), which are discussed below (the "Default Securitization") and $2.1 billion related to highly priced ancillary service and ORPDA during Winter Storm Uri (the "Uplift Securitization").

3951

The DOOs required ERCOT to issue loans or securitized bonds through a bankruptcy remote special purpose entity as the borrower and distribute the proceeds to affected market participants for default-related shortbonus payments and to LSEs for certain ancillary-service and ORDPA costs using an allocation of proceeds based on an LSE's exposure to relevant costs as calculated by the LSE's prevailing load-ratio share during the period of Winter Storm Uri, and a further redistribution of proceeds initially allocated to other LSEs and customers who opt-out of securitization. In turn, ERCOT charges non-bypassable fees related to the ~~Default Securitization and Uplift Securitization~~events. On April 3, 2023, FERC approved PJM's request to all qualified scheduling entities and to all LSEs (other than those that have opted-out), respectively. The Uplift Securitization provided for a one-time opt-out for certain LSEs or individual transmission-level customers who in exchange for foregoing any securitization-related proceeds likewise avoid future fees assessed by ERCOT for the use of repaying ERCOT's debt obligations. However, nearly all competitive REPs were required by the law to participate, ensuring the charge established by the law is competitively neutral. The $2.1 billion Uplift Securitization was disbursed by ERCOT in June 2022, with NRG's LSEs collectively receiving $689 million. NRG LSEs that assessed customers certain ancillary-service and ORDPA costs during the period ofallow Winter Storm ~~Uri provided~~Elliott penalty payments to be spread over 9 months (with interest) and allow future penalties to have a ~~refund or credit~~9 month window to ~~those customers proportionate to~~be satisfied without interest. Multiple generators filed various complaints against PJM at FERC alleging that PJM violated its Tariff in, among other things, the ~~LSE's total recovery. The $800 million Default Securitization was disbursed by ERCOT~~manner in ~~November 2021, with NRG receiving $12 million.~~

~~Electric Cooperative Bankruptcy~~which it operated the system during Winter Storm Elliott and ~~Securitization~~ ~~— Of~~ the ~~defaults in the ERCOT market, the majority is attributable to Brazos. Brazos currently is in bankruptcy. NRG and ERCOT have both filed a proof~~resulting assessment of claim in the bankruptcy proceeding of Brazos, and Brazos has challenged ERCOT's claim in a manner that may prejudice NRG's claims against Brazos. During the fourth quarter of 2021, ERCOT filed a motion to dismiss Brazos' complaint relating to ERCOT's proof of claim, which NRG joined in support, but this motion was denied by the Bankruptcy Court, and ERCOT, NRG and certain other parties appealed.capacity performance penalties. On ~~January 11, 2022, the United States District Court for the Southern District of Texas entered~~June 5, 2023, FERC issued an order setting the various complaints for settlement. A settlement in principle has been reached and was filed with FERC on September 29, 2023. FERC also granted a waiver allowing ~~the appellants~~PJM to ~~seek direct review from the Fifth Circuit Court of Appeals~~defer collection of the ~~Bankruptcy Court's decision on the motion to dismiss. On January 18, 2022, ERCOT, NRG~~remaining unbilled non-performance charges and certain other parties filed a petition for direct review by the United States Court of Appeals for the Fifth Circuit. The Court of Appeals granted the petition on February 4, 2022, and such appeal remains pending. On February 7, 2022, the Bankruptcy Court entered an order granting summary judgment in favor of Brazos on whether ERCOT's sales to Brazos were in the ordinary course of Brazos' business. The Bankruptcy Court ruled that the portion of ERCOT's claims for charges incurred by Brazos after the intervention of the PUCT and ERCOT were not in the ordinary course and thus are not entitled to administrative expense status under the Bankruptcy Code. The amount and priority of ERCOT's claim for amounts incurred prior to such intervention or after such intervention ceased are issues to be determined at trial. The Bankruptcy Court's summary judgment ruling may also apply to NRG's claims against Brazos. To the extent the Bankruptcy Court reduces or disallows claims against Brazos, this presents risk for NRG.

~~Trial~~suspended remaining bonus payments associated with Winter Storm Elliott until FERC decides on the merits of the ~~ERCOT proof of claim and Brazos' complaint commenced before~~settlement. The settling parties requested that FERC approve the Bankruptcy Court on February 22, 2022. On the eighth day of trial, the parties agreed to suspend the trial and pursue mediation. On March 25, 2022, the Bankruptcy Court entered an order that appointed a mediator and abated the trial for the duration of the mediation. NRG thereafter participated in the mediation process with ERCOT, Brazos and various other parties in interest which culminated in the negotiation of a settlement between Brazos and ERCOT to be implemented under a chapter 11 plan and a related ERCOT market settlement process. On September 1, 2022, Brazos filed such chapter 11 plan, and on September 20, 2022, Brazos amended the plan and distributed it to certain creditors to solicit their acceptance. A hearing with the Bankruptcy Court regarding the potential confirmation of the plan is currently set for November 14, 2022. With respect to the pending appeal of the Bankruptcy Court's ruling on the motion to dismiss, on September 19, 2022, the Fifth Circuit Court of Appeals entered an order abating all deadlines pending confirmation of Brazos' chapter 11 plan.

If the Brazos' chapter 11 plan is confirmed and becomes effective, it and the related ERCOT settlement would provide market participants a recovery of funds that were short-paid in relation to Brazos. In October 2022, NRG elected the accelerated cash recovery option and will recover 65% of the $68 million, 43% of which was short-paid will be recovered onwithout modification or ~~around the effective date of the bankruptcy plan and another 22% will be recovered over the following 12-year period. The plan and ERCOT settlement also contemplate and would provide that there be~~condition no ~~default uplift under the current ERCOT protocols in relation to the Brazos short payments. NRG's discounted market share of the default uplift is $9 million and is recorded as an other liability.~~

~~In February 2022, Rayburn successfully completed a securitization transaction and fully paid its outstanding obligations to ERCOT.~~later than December 29, 2023.

~~Reliability and Plant Operations Standards~~ — The PUCT created a rulemaking to establish weatherization standards and issued a notice for comments in response to provisions of Texas Senate Bill 3 ("SB3") that require mandatory standards for power generators and others within the electric-power sector. On October 21, 2021, Commissioners of the PUCT voted to adopt Phase 1 of the rule without substantial modifications from the proposal, and those rules are now in effect. On May 26, 2022, the PUCT issued a proposal for publication to repeal Phase I rules and implement Phase 2 rules. The new rules entail conducting a weather study by ERCOT and the State Climatologist to create a percentile-based standard of weatherization and implementing

weatherization plan audits based on weather related outages that occur during weather emergencies. NRG filed comments to the rulemaking on June 23, 2022. On September 29, 2022, the PUCT adopted the Phase II Weatherization Standards.

FERC Delays PJM

~~Indian River RMR Proceeding~~ Base Residual Auctions — On ~~June 29, 2021, Indian River notified~~April 11, 2023, PJM ~~that it intended~~filed to ~~retire Unit 4, effective May 31, 2022, due~~delay the Base Residual Auctions for the 2025/2026 to ~~expected uneconomic operations.~~2028/2029 delivery years. On ~~July 30, 2021,~~October 13, 2023, PJM ~~responded~~made two filings proposing to develop market reforms to improve the operation of the capacity market through changes to the ~~deactivation notice~~Market Seller Offer Cap rules, changes to PJM's resource adequacy risk modeling and ~~stated~~capacity accreditation processes, and changes to capacity performance enhancements. PJM proposes to restart the auctions after FERC's ruling on these market changes. On June 9, 2023, FERC issued an order approving the delay in the Base Residual Auctions and required PJM to make a compliance filing that will specify future auction dates. On June 26, 2023, PJM ~~had identified reliability violations resulting from~~made its compliance filing setting the ~~proposed deactivation of Unit 4. NRG filed a cost based RMR rate schedule at FERC on April 1, 2022. FERC accepted~~auction for June 2024 for the ~~rate schedule with a June 1, 2022 effective date, subject to refund and established hearing and settlement procedures. Multiple parties protested. Parties are currently in settlement negotiations.~~2025/2026 delivery year through the 2028/2029 delivery year.

PJM ~~Revisions~~Files to ~~Minimum Offer Price Rule —~~ On July 30, 2021, PJM filed a proposed tariff change at FERC to largely eliminate the current minimum offer price rules ("MOPR") except in very narrow cases. The proposal would eliminate: (i) the current MOPR for new entrant natural gas resources effective with the 2023/2024 delivery year and (ii) the expanded MOPR established in FERC's December 2019 Order to address out-of-market subsidies. On September 30, 2021, PJM's proposal went into effect by operation of law because the FERC Commissioners were split 2-2 asMake Changes to the lawfulness of the change. Multiple parties filed motions for rehearing and ultimately appealed to the federal court of appeals. On December 21, 2021 and December 30, 2021, respectively, the Third Circuit Court of Appeals and the Seventh Circuit Court of Appeals issued an order holding the appeals in abeyance. The Seventh Court appeal is being held in abeyance while the appeal in the Third Court is moving forward with briefing. Any changes to the PJM capacity market construct may impact the outcome of future Base Residual Auctions.

~~PJM's ORDC Filing and Compliance Directives~~Performance Assessment Interval Trigger — On May ~~21, 2020,~~30, 2023, PJM filed proposed ~~energy~~tariff revisions at FERC that narrow the definition of Emergency Actions used to determine Performance Assessment Intervals ("PAIs"). On July 28, 2023, FERC accepted the tariff revisions, and ~~reserve market reforms to enhance price formation in reserve markets, which includes modifying~~PJM made its ORDC and aligning market-based reserve products in Day-Ahead and Real-Time markets. In addition to approving PJM's proposal, FERC also directed PJM to implement a forward-looking Energy and Ancillary Services Offset to be used in PJM's capacity markets. After multiple compliance ~~filings, parties filed appeals at the Court of Appeals for the D.C. Circuit of FERC’s orders, and~~filing on August ~~13, 2021, FERC filed a motion~~28, 2023. The new definition would decrease the instances of when PAIs would occur and ~~was granted a voluntary remand~~therefore decrease the case back to the agency. On December 22, 2021, FERC issued its order on voluntary remand affirming in part and reversing in part FERC's determination. Specifically, FERC reversed itself and ordered PJM to: (i) eliminate the more robust ORDC curves and reserve penalty adders and maintain the existing (lower) curves and (lower) penalty adders and (ii) restore its tariff provisions related to its prior backward-looking Energy and Ancillary Services Offset. In response to requests for rehearinginstances of the December 2021 order, FERC issued a notice denying the rehearings by operation of law and providing for further consideration on February 22, 2022. Multiple parties filed appeals in various appellate courts andwhen capacity performance penalties are ~~now all before the Sixth Circuit Court of Appeals for consideration.~~assessed.

Independent Market Monitor Market Seller Offer Cap Complaint — On March 18, 2021, finding that the calculation of the default Market Seller Offer Cap was unjust and unreasonable, ~~the~~FERC issued an Order, which permitted the ~~current~~ PJM May 2021 capacity auction for the 2022/2023 delivery ~~rule~~year to continue under the existing rules and set a procedural schedule for parties to file briefs with possible solutions. On September 2, 2021, FERC issued an order in response to a complaint filed by the PJM Independent Market Monitor's proposal, which ~~eliminates~~eliminated the Cost of New Entry-based Market Seller Offer Cap, ~~and implements~~implemented a limited default cap for certain asset classes based on going-forward costs and ~~provides~~provided for unit specific cost review by the Independent Market Monitor for all other non-zero offers into the auctions. AsOn October 4, 2021, as required by the Order, PJM submitted its compliance tariff ~~on October 4, 2021. On October 4, 2021,~~and certain parties filed a motion for rehearing, which was denied by operation of law. On February 18, 2022, FERC addressed the arguments raised on rehearing and rejected the rehearing requests. Multiple parties filed appeals at the Court of Appeals for the D.C. ~~Circuit. Briefing is underway.~~

~~Generator Interconnection Process Reform~~ ~~— On June 14, 2022, PJM filed proposed tariff revisions at FERC regarding its interconnection process to provide~~Circuit, and on August 15, 2023, the Court denied the petitions for a more efficient process and address the backlog in interconnection service requests. The filing would transition the interconnect process from a "first-come, first-served" queue approach to a "first-ready, first-served" cluster/cycle approach. Additionally, project developers would be required to provide more significant financial deposits and meet other thresholds in order to move forward in the process. The filing is pending at FERC.review.

~~On June 16, 2022, FERC issued a Notice of Proposed Rulemaking to reform the generator interconnection procedures across the ISOs/RTOs. The matter is pending at FERC.~~

~~New York~~

~~NYISO's Revisions to the Buyer-Side Mitigation Rules —~~ On January 5, 2022, the NYISO filed its Comprehensive Mitigation Review proposing changes to the buyer-side mitigation rules. The proposal would remove certain facilities to be reviewed under the buyer-side mitigation rules to serve the goals of New York's Climate Leadership and Community Protection Act, adopt a marginal capacity accreditation market design and adjust the rules surrounding installed and unforced capacity. On February 9, 2022, FERC issued a deficiency notice, focusing on capacity accreditation issues, which NYISO responded. On

~~May 10, 2022, FERC issued an order accepting the NYISO's Comprehensive Mitigation Review. Changes to NYISO's Buyer Side Mitigation rules may impact the outcome of future capacity auctions.~~

California

California Resource Adequacy Proceedings — As part of the Integrated Resource Procurement docket, the CPUC ~~approved a decision on June 24, 2021~~is requiring that ~~requires~~ all LSEs to procure a pro rata share of ~~11.5~~15.5 GW of new non-fossil resource adequacy from 2023 to 2026. ~~In that same~~A June 2023 decision in the resource adequacy ("RA") docket keeps the reserve margin at 17 percent in 2024 and 2025, but extends the CPUC ~~ordered~~orders for the state's major investor-owned utilities to procure additional summer reliability resources through ~~2023. On June 23, 2022, the CPUC approved a decision that raises the~~2025, creating an "effective" reserve margin ~~from 15 percent~~of 21 to ~~16 percent in 2023 and at least 17 percent in 2024. Finally,~~23.5 percent. SB846 establishes a pathway for PG&E's Diablo Canyon Nuclear power plant, which units are scheduled to close in 2024 and 2025, to remain open for at least five additional years. A CPUC decision expected by the end of 2023 will determine how the RA from the extension will be treated. Finally, the CPUC jurisdictional retail providers will be required to procure RA that meets their hourly load shape beginning in 2025. The result of these changes will likely keep ~~Resource Adequacy ("RA")~~RA prices elevated ~~in the near term~~through 2024, and if LSEs cannot meet their RA obligations, penalties and restrictions on serving new customers may be issued.

~~Midway-Sunset Reliability Must Run Proceeding —~~ San Joaquin Energy, LLC, a subsidiary of NRG, owns a 50%, non-controlling interest in the Midway-Sunset Cogeneration Company ("MSCC"). MSCC owns a cogeneration facility near Fellows, California and submitted mothball notices for the cogeneration facility to the CAISO in the latter half of 2020. On December 17, 2020, the CAISO Board effectively rejected the mothball notices by authorizing its staff to designate the MSCC facility as a RMR resource conditioned on execution of a RMR contract. On January 29, 2021, MSCC made its RMR filing at FERC. Multiple parties filed protests and on March 16, 2021, MSCC filed a response to those protests. On April 2, 2021, FERC accepted the RMR filing, suspended it to become effective February 1, 2021 subject to refund and established hearing and settlement judge proceedings. On September 27, 2021, the CAISO gave notice to MSCC extending the term of the reliability designation through December 31, 2022. On April 29, 2022, the participants in the settlement proceeding filed a Joint Offer of Settlement with the FERC, which was approved by FERC on July 28, 2022.

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 maintained 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. 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 affect the Company have been revised recently and continue to be revised by the EPA, including ash storage and disposal requirements, NAAQS revisions and implementation and effluent limitation guidelines. ~~Some of these recent revisions may, in turn, be revised by the current U.S. presidential administration.~~

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 ~~2021~~2022 Form 10-K in Item 1, Business - Environmental Matters and Item 1A, Risk ~~Factors.~~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~~related 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 may become more stringent. In January 2023, the EPA proposed increasing the stringency of the PM2.5 NAAQS. 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.

CPP/ACE Rules — The attention in recent years on GHG emissions has resulted in federal and state regulations. In October 2015, the EPA promulgated 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. On January 19, 2021, the D.C. Circuit vacated the ACE rule (but on February 22, 2021, at the EPA's request, stayed the issuance of the portion of the mandate that would ~~have vacated~~vacate the repeal of the CPP). On June 30, 2022, the U.S. Supreme Court held that the "generation shifting" approach in the CPP exceeded the powers granted to the EPA by Congress. The Court did not address the related issues of whether the EPA may adopt only

measures applied at each source. On May 23, 2023, the EPA proposed significantly revising the manner in which new and existing EGU's GHG emissions should be regulated including using hydrogen as a fuel, capturing and storing/sequestering CO2 and requiring new units to be more efficient. The EPA has stated that it intends to finalize these revisions in 2024. The Company ~~anticipates~~expects that ~~there~~the final rule will be ~~additional proceedings at~~challenged in the ~~D.C. Circuit~~courts and ~~additional rulemaking by the EPA over the next~~accordingly uncertain for several years.

Regional Haze Proposal — On May 2023, the EPA proposed to withdraw the existing Texas Sulfur Dioxide Trading Program and replace it with unit-specific SO2 limits for 12 units in Texas to address requirements to improve visibility at National Parks and Wilderness areas. If ~~the rule were~~ finalized as proposed, itthe rule would ~~apply to 25 states (including Texas) beginning~~result in ~~2023. In 2023,~~more stringent SO2 limits for two of the ~~revised Group 3 trading program (previously established~~Company's coal-fired units in the Revised CSAPR Update Rule) would have emission budgets based on NOx emission rates that the EPA says are achievable by existing controls at power plants. Starting in 2026, the NOx budgets would be reduced significantly based on levels achievable if SCR controls were installed at coal-fueled power plants that do not currently have such controls. Starting in 2025, the budgets would be updated annually to account for retirements, changes to operations, and new units. The proposal also contemplates heightened surrender requirements for units that exceed certain NOx emission rate thresholds. Comments on the proposed rule were due in June 2022 and numerous detailed comments were submitted.Texas. The Company cannot predict the outcome of this ~~proposed revision and anticipates that this rulemaking will be subject to legal challenges after it is finalized.~~proposal.

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 amended the ~~2015~~ 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. In 2019 and 2020, the EPA proposed several changes to this rule.~~surface impoundments. On August 28, 2020, the EPA finalized "A Holistic Approach to Closure Part A: Deadline to Initiate Closure," which amended the April 2015 Rule to address the August 2018 D.C. Circuit decision and extend some of the deadlines. On November 12, 2020, the EPA finalized "A Holistic Approach to Closure Part B: Alternative Demonstration for Unlined Surface Impoundments," which further amended the April 2015 Rule to, among other things, provide procedures for requesting approval to operate existing ash impoundments with an alternate liner. On May 23, 2023, the EPA proposed establishing requirements for: (i) inactive (or legacy) surface impoundments at inactive facilities and (ii) all CCR management units (regardless of how or when the CCR was placed) at regulated facilities. NRG anticipates further rulemaking related to the Federal Permit Program and legacy surface impoundments.

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 ~~three~~four times through addendums to cover payments through December 31, ~~2022.~~2025. 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 ELG for Steam Electric Generating Facilities, which 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, postponed 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 amended the rule. On October 13, 2020, the EPA amended the 2015 ELG rule by: (i) altering the stringency of certain limits for FGD wastewater; (ii) relaxing the zero-discharge requirement for bottom ash transport water; and (iii) changing several deadlines. ~~On July 26,~~In 2021, the EPA announced that it iswas initiating a new rulemaking to evaluate revising the ELG ~~rule. While the EPA is developing the new~~ rule but keeping the existing rule (as amended in 2020) ~~will stay~~ in ~~place, and~~place. On March 29, 2023, the EPA ~~expects permitting authorities~~proposed revisions to ~~continue to implement~~ the ~~current regulation. The Company anticipates that~~ELG and sought comments, which the EPA ~~will release a proposed rule in the first quarter of 2023.~~is currently analyzing. In October 2021, NRG informed its regulators that the Company intends to comply with the ELG by ceasing combustion of coal by the end of 2028 at its domestic coal units outside of Texas, and installing appropriate controls by the end of 2025 at its two plants that have coal-fired units in Texas.

Regional Environmental Developments

Ash Regulation in Illinois — On July 30, 2019, Illinois enacted legislation that ~~requires~~required the state to promulgate regulations regarding coal ash at surface impoundments. On April 15, 2021, the state promulgated the implementing regulation, which became effective on April 21, 2021. NRG has applied for initial operating permits and has begun to apply for construction permits (for closure) as required by the regulation.

Houston Nonattainment for 2008 Ozone Standard — During the fourth quarter of 2022, the EPA changed the Houston area's classification from Serious to Severe nonattainment for the 2008 Ozone Standard. Accordingly, Texas is required to develop a new control strategy and submit it to the EPA.

Significant Events

The following significant events have occurred during ~~2022~~2023 as further described within this Management's Discussion and Analysis and the condensed consolidated financial statements:

~~Astoria~~Sale of the 44% equity interest in STP

On ~~September 9,~~November 1, 2023, the Company closed on the previously announced sale of its 44% equity interest in STP to Constellation. Proceeds of $1.75 billion were reduced by preliminary working capital and other adjustments of $96 million, resulting in net proceeds of $1.654 billion. For further discussion, see Note 4, Acquisitions and Dispositions.

Vivint Smart Home Acquisition

On March 10, 2023, the Company completed the acquisition of Vivint Smart Home. The Company paid $12 per share, or $2.6 billion in cash. For further discussion, see Note 4, Acquisitions and Dispositions.

Retirement of Joliet

During the second quarter of 2022, the Company ~~entered into a definitive purchase agreement~~announced the planned retirement of the Joliet generating facility in 2023. On September 1, 2023, the Joliet generating facility fully retired.

Sale of Gregory

On October 2, 2023, the Company closed on the sale of its 100% ownership in the Gregory natural gas generating facility in Texas for $102 million.

Series A Preferred Stock

On March 9, 2023, the Company issued 650,000 shares of 10.25% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock. The proceeds, net of issuance costs, of $635 million were used to ~~sell~~partially fund the Vivint Smart Home acquisition. For further discussion, see Note 11, Changes in Capital Structure.

Issuance of 2033 Senior Secured First Lien Notes

On March 9, 2023, the Company issued $740 million of aggregate principal amount of 7.000% senior secured first lien notes due 2033. The net proceeds of $724 million, net of issuance costs, were used to partially fund the Vivint Smart Home acquisition. For further discussion, see Note 9, Long-term Debt and Finance Leases.

Sale of Astoria

On January 6, 2023, NRG closed on the sale of land and related assets from the Astoria site, within the East region of operations, for initial proceeds of $212 million, subject to ~~purchase price adjustments~~transaction fees of $3 million and certain ~~other~~ indemnifications. NRG recognized a gain on the sale of $199 million. As part of the transaction, NRG ~~will enter~~entered into an agreement to lease the land back for the purpose of operating the Astoria ~~facility through the planned April 30, 2023 retirement date.~~gas turbines. The ~~operating~~ lease agreement is expected to terminate by the end ~~six months~~of the year after ~~the facility's actual retirement date. The transaction~~decommissioning is ~~expected to close in the fourth quarter of 2022 and is subject to various closing conditions.~~complete.

W.A. Parish ~~Extended Outage~~Return to Service

In May 2022, W.A. Parish Unit 8 came offline as a result of damage to ~~certain components of~~ the steam turbine/generator. ~~Based on management's current assessment of necessary restoration efforts, the Company is targeting to return~~The extended forced outage ended in September 2023 and the unit has returned to ~~service by the end of the second quarter of 2023.~~

~~Retirement of Joliet~~

During the second quarter of 2022, the results of the PJM Base Residual Auction for the 2023/2024 delivery year were released leading the Company to revise its long-term view of certain facilities and announce the planned retirement of the Joliet generating facility in May 2023. Impairment losses of $20 million and $130 million were recorded on the PJM generating assets and Midwest Generation goodwill, respectively.

~~ERCOT Securitization Proceeds~~

During 2021, the Texas Legislature passed HB 4492 for ERCOT to mitigate exceptionally high price adders and ancillary service costs incurred by LSEs during Winter Storm Uri. HB 4492 authorized ERCOT to obtain $2.1 billion of financing to distribute to LSEs that were charged and paid to ERCOT those highly priced ancillary service and ORDPA during Winter Storm Uri. In December 2021, the Company accounted for the proceeds as a reduction to cost of operations within its consolidated statements of operations in the 2021 annual period for which the proceeds were intended to compensate. The Company received proceeds of $689 million from ERCOT in June 2022.

~~Sale of Watson~~

~~On June 1, 2022, the Company closed on the sale of its 49% ownership in the Watson natural gas generating facility for $59 million. NRG recognized a gain on the sale of $46 million.~~service.

Share Repurchases

In ~~December 2021,~~June 2023, NRG revised its long-term capital allocation policy to target allocating approximately 80% of cash available for allocation after debt reduction to be returned to shareholders. As part of the ~~Company's board of directors authorized~~revised capital allocation framework, the Company announced an increase to its share repurchase ~~$1.0~~authorization to $2.7 billion, ~~of its common stock, of which $44 million was completed in 2021.~~to be executed through 2025. During the ~~nine~~three months ended September 30, ~~2022,~~2023, the Company completed ~~$489~~$50 million of share repurchases at an average price of ~~$40.07 per share, including $6 million of equivalent shares purchased in lieu of tax withholdings on equity compensation issuances.Through~~$37.82 under the $2.7 billion authorization. Through October 31, ~~2022,~~2023, an additional ~~$76~~$150 million of share repurchases were executed at an average price of ~~$41.71~~$40.17 per share. ~~In October 2022,~~Following the ~~Board~~closing of ~~Directors approved an additional $600~~the STP sale on November 1, 2023, the Company intends to execute a $950 million inaccelerated share ~~repurchases.~~

repurchase program.

Dividend Increase

In the first quarter of ~~2022,~~2023, NRG increased the annual common stock dividend to ~~$1.40~~$1.51 from ~~$1.30~~$1.40 per share, representing an 8% increase from ~~2021.~~2022. Beginning in the first quarter of ~~2023,~~2024, NRG will increase the annual dividend by 8% to ~~$1.51~~$1.63 per share. The Company expects to target an annual dividend growth rate of 7-9% per share in subsequent years.

Renewable Power Purchase Agreements

The Company's strategy is to procure mid to long-term generation through power purchase agreements. As of September 30, ~~2022,~~2023, NRG has entered into Renewable PPAs totaling approximately ~~2.4~~1.9 GW with third-party project developers and other counterparties, of which approximately ~~45%~~1.1 GW are operational. The average ~~tenor~~tenure of these agreements is ~~twelve~~eleven years. The Company expects to continue evaluating and executing similar agreements that support the needs of the business. The total GW procured through Renewable PPAs may be impacted by contract terminations when they occur.

~~Limestone Unit 1 Return to Service~~

In early July 2021, Limestone Unit 1 came offline as a result of damage to the duct work associated with the FGD system. The extended forced outage ended in April of 2022 and the unit has returned to service.

~~COVID-19~~

~~While the pandemic presents risks to the Company's business, as further described in the Company’s 2021 Form 10-K in Part II, Item 1A —~~ ~~Risk Factors, there was not a material adverse impact on the Company’s results of operations for the nine months ended September 30, 2022 and 2021.~~

Trends Affecting Results of Operations and Future Business Performance

The Company’s trends are described in the Company’s ~~2021~~2022 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.

4556

Consolidated Results of Operations

The following table provides selected financial information for the Company:


		Three months ended September 30,							Nine months ended September 30,								Three months ended September 30,						Nine months ended September 30,
(In millions, except as otherwise noted)		2022		2021		Change			2022		2021		Change
(In millions)																(In millions)	2023		2022		Change		2023		2022		Change
Revenue	Revenue															Revenue
Retail revenue	Retail revenue	$	7,858	$	5,951	$	1,907		$	22,379	$	16,929	$	5,450		Retail revenue	$	7,521	$	7,858	$	(337)	$	20,911	$	22,379	$	(1,468)
Energy revenue(a)	Energy revenue(a)	450		336		114			1,034		989		45			Energy revenue(a)	261		450		(189)		472		1,034		(562)
Capacity revenue(a)	Capacity revenue(a)	38		189		(151)			244		615		(371)			Capacity revenue(a)	59		38		21		150		244		(94)
Mark-to-market for economic hedging activities	Mark-to-market for economic hedging activities	33		3		30			(248)		(99)		(149)			Mark-to-market for economic hedging activities	(70)		33		(103)		96		(248)		344
Contract amortization	Contract amortization	(6)		(3)		(3)			(28)		(19)		(9)			Contract amortization	(5)		(6)		1		(24)		(28)		4
Other revenues(a)(b)	Other revenues(a)(b)	137		133		4			307		1,528		(1,221)			Other revenues(a)(b)	180		137		43		411		307		104
Total revenue	Total revenue	8,510		6,609		1,901			23,688		19,943		3,745			Total revenue	7,946		8,510		(564)		22,016		23,688		(1,672)
Operating Costs and Expenses	Operating Costs and Expenses															Operating Costs and Expenses
Cost of fuel	Cost of fuel	742		466		(276)			1,603		1,530		(73)			Cost of fuel	400		742		342		790		1,603		813
Purchased energy and other cost of sales(c)	Purchased energy and other cost of sales(c)	6,494		4,641		(1,853)			18,757		14,774		(3,983)			Purchased energy and other cost of sales(c)	5,599		6,494		895		15,883		18,757		2,874

Mark-to-market for economic hedging activities	Mark-to-market for economic hedging activities	122		(1,782)		(1,904)			(3,155)		(4,122)		(967)			Mark-to-market for economic hedging activities	(17)		122		139		2,029		(3,155)		(5,184)
Contract and emissions credit amortization(c)	Contract and emissions credit amortization(c)	(16)		(45)		(29)			87		19		(68)			Contract and emissions credit amortization(c)	(12)		(16)		(4)		78		87		9
Operations and maintenance	Operations and maintenance	359		332		(27)			1,049		1,036		(13)			Operations and maintenance	336		359		23		1,080		1,049		(31)
Other cost of operations	Other cost of operations	101		80		(21)			278		259		(19)			Other cost of operations	115		101		(14)		301		278		(23)
Cost of operations (excluding depreciation and amortization shown below)	Cost of operations (excluding depreciation and amortization shown below)	7,802		3,692		(4,110)			18,619		13,496		(5,123)			Cost of operations (excluding depreciation and amortization shown below)	6,421		7,802		1,381		20,161		18,619		(1,542)
Depreciation and amortization	Depreciation and amortization	145		199		54			485		569		84			Depreciation and amortization	308		145		(163)		813		485		(328)
Impairment losses	Impairment losses	43		—		(43)			198		306		108			Impairment losses	—		43		43		—		198		198
Selling, general and administrative costs	Selling, general and administrative costs	326		318		(8)			973		973		—			Selling, general and administrative costs	638		378		(260)		1,586		1,076		(510)
Provision for credit losses		52		64		12			103		715		612

Acquisition-related transaction and integration costs	Acquisition-related transaction and integration costs	8		17		9			26		81		55			Acquisition-related transaction and integration costs	18		8		(10)		111		26		(85)
Total operating costs and expenses	Total operating costs and expenses	8,376		4,290		(4,086)			20,404		16,140		(4,264)			Total operating costs and expenses	7,385		8,376		991		22,671		20,404		(2,267)

Gain on sale of assets	Gain on sale of assets	22		—		22			51		17		34			Gain on sale of assets	—		22		(22)		202		51		151
Operating Income		156		2,319		(2,163)			3,335		3,820		(485)
Operating Income/(Loss)																Operating Income/(Loss)	561		156		405		(453)		3,335		(3,788)
Other Income/(Expense)	Other Income/(Expense)															Other Income/(Expense)
Equity in earnings of unconsolidated affiliates	Equity in earnings of unconsolidated affiliates	11		15		(4)			—		23		(23)			Equity in earnings of unconsolidated affiliates	6		11		(5)		16		—		16

Other income, net	Other income, net	21		8		13			33		42		(9)			Other income, net	14		21		(7)		43		33		10
Loss on debt extinguishment		—		(57)		57			—		(57)		57

Interest expense	Interest expense	(105)		(122)		17			(313)		(374)		61			Interest expense	(173)		(105)		(68)		(472)		(313)		(159)
Total other expense	Total other expense	(73)		(156)		83			(280)		(366)		86			Total other expense	(153)		(73)		(80)		(413)		(280)		(133)
Income Before Income Taxes		83		2,163		(2,080)			3,055		3,454		(399)
Income tax expense		16		545		529			739		840		101
Income/(Loss) Before Income Taxes																Income/(Loss) Before Income Taxes	408		83		325		(866)		3,055		(3,921)
Income tax expense/(benefit)																Income tax expense/(benefit)	65		16		(49)		(182)		739		921

Net Income		$	67	$	1,618	$	(1,551)		$	2,316	$	2,614	$	(298)
Net Income/(Loss)																Net Income/(Loss)	$	343	$	67	$	276	$	(684)	$	2,316	$	(3,000)

Business Metrics
Average natural gas price — Henry Hub ($/MMBtu)		$	8.20	$	4.01	104		%	$	6.77	$	3.18	113		%

(a)Includes gains and losses from financially settled transactions

(b)Includes trading gains and losses and ancillary revenues

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

4657

Management’s discussion of the results of operations for the three months ended September 30, ~~2022~~2023 and ~~2021~~2022

Electricity Prices

The following table summarizes average on peak power prices for each of the major markets in which NRG operates for the three months ended September 30, ~~2022~~2023 and ~~2021.~~2022. The average on-peak power prices increased in Texas due to record loads, which were impacted by weather. East and West average on-peak power prices ~~increased~~decreased for the three months ended September 30, ~~2022~~2023 as compared to the same period in ~~2021~~2022 as a result of ~~higher~~lower natural gas prices.


		Average on Peak Power Price ($/MWh)							Average on Peak Power Price ($/MWh)
		Three months ended September 30,							Three months ended September 30,
Region	Region	2022		2021		Change %		Region	2023		2022		Change %
Texas	Texas							Texas
ERCOT - Houston(a)	ERCOT - Houston(a)	$	128.61	$	47.11	173	%	ERCOT - Houston(a)	$	183.49	$	128.61	43	%
ERCOT - North(a)	ERCOT - North(a)	131.62		46.16		185	%	ERCOT - North(a)	181.72		131.62		38	%

East	East							East
NY J/NYC(b)	NY J/NYC(b)	$	109.43	$	54.75	100	%	NY J/NYC(b)	$	40.86	$	109.43	(63)	%
NEPOOL(b)	NEPOOL(b)	99.14		52.57		89	%	NEPOOL(b)	40.41		99.14		(59)	%
COMED (PJM)(b)	COMED (PJM)(b)	101.00		48.36		109	%	COMED (PJM)(b)	39.38		101.00		(61)	%
PJM West Hub(b)	PJM West Hub(b)	110.99		51.32		116	%	PJM West Hub(b)	43.27		110.99		(61)	%

West	West							West
MISO - Louisiana Hub(b)	MISO - Louisiana Hub(b)	$	90.32	$	44.95	101	%	MISO - Louisiana Hub(b)	$	38.53	$	90.32	(57)	%
CAISO - SP15(b)	CAISO - SP15(b)	110.03		72.02		53	%	CAISO - SP15(b)	67.59		110.03		(39)	%

(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

Natural Gas Prices

The following table summarizes the average ~~realized power prices for NRG, including the impact of settled hedges,~~Henry Hub natural gas price for the three months ended September 30, ~~2022~~2023 and ~~2021:~~2022:

Average Realized Power Price ($/MWh)
Three months ended September 30,
Segment 2022 2021 Change %
East(a)
$ 58.95 $ 37.26 58 %
West/Services/Other 96.93 50.31 93 %


	Three months ended September 30,
	2023		2022		Change %
($/MMBtu)	$	2.55	$	8.20	(69)	%

~~(a)~~Average Realized Power Price reflects energy sales from the generation fleet, including sales to the retail component of the East Segment. Intercompany financial transactions hedging generation with the retail business make up ~~($5.47)/MWh~~ ~~in the three months ended September 30, 2022 and ($9.84)/MWh in the three months ended September 30, 2021~~

The average realized power prices increased in the East and West/Services/Other segments for the three months ended September 30, 2022 as compared to the same period in 2021, as a result of higher natural gas prices. Average power prices increased less than average on peak power prices due to the impact of the Company's multi-year hedging program.

Gross Margin

The Company calculates gross margin in order to evaluate operating performance as revenues less cost of fuel, purchased energy and other costs of sales, mark-to-market for economic hedging activities, contract and ~~emission~~emissions credit amortization and depreciation and amortization.

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 retail revenue, energy revenue, capacity revenue and other revenue, less cost of fuel, purchased energy and other cost of sales. Economic gross margin does not include mark-to-market gains or losses on economic hedging activities, contract amortization, emissions credit amortization, depreciation and amortization, operations and maintenance, or other cost of operations.

4758

The ~~below~~following tables present the composition and reconciliation of gross margin and economic gross margin for the three months ended September 30, ~~2022~~2023 and ~~2021:~~2022:


		Three months ended September 30, 2022								Three months ended September 30, 2023
($ In millions)	($ In millions)	Texas		East		West/Services/Other		Corporate/Eliminations			Total		($ In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue	Retail revenue	$	3,005	$	3,863	$	990	$	—		$	7,858	Retail revenue	$	3,489	$	2,633	$	922	$	478	$	(1)	$	7,521
Energy revenue	Energy revenue	48		212		180		10			450		Energy revenue	51		152		59		—		(1)		261
Capacity revenue	Capacity revenue	—		38		—		—			38		Capacity revenue	—		64		(4)		—		(1)		59
Mark-to-market for economic hedging activities	Mark-to-market for economic hedging activities	4		32		(7)		4			33		Mark-to-market for economic hedging activities	—		(60)		(10)		—		—		(70)
Contract amortization	Contract amortization	—		(10)		4		—			(6)		Contract amortization	—		(6)		1		—		—		(5)
Other revenue(a)	Other revenue(a)	92		45		2		(2)			137		Other revenue(a)	146		26		10		—		(2)		180
Total revenue	Total revenue	3,149		4,180		1,169		12			8,510		Total revenue	3,686		2,809		978		478		(5)		7,946
Cost of fuel	Cost of fuel	(489)		(140)		(113)		—			(742)		Cost of fuel	(300)		(64)		(36)		—		—		(400)
Purchased energy and other cost of sales(b)(c)(d)	Purchased energy and other cost of sales(b)(c)(d)	(2,012)		(3,609)		(865)		(8)			(6,494)		Purchased energy and other cost of sales(b)(c)(d)	(2,359)		(2,385)		(808)		(50)		3		(5,599)
Mark-to-market for economic hedging activities	Mark-to-market for economic hedging activities	(600)		423		59		(4)			(122)		Mark-to-market for economic hedging activities	(42)		244		(185)		—		—		17
Contract and emission credit amortization		(4)		29		(9)		—			16
Contract and emissions credit amortization													Contract and emissions credit amortization	(5)		22		(5)		—		—		12
Depreciation and amortization	Depreciation and amortization	(77)		(39)		(22)		(7)			(145)		Depreciation and amortization	(71)		(27)		(23)		(178)		(9)		(308)
Gross margin	Gross margin	$	(33)	$	844	$	219	$	(7)		$	1,023	Gross margin	$	909	$	599	$	(79)	$	250	$	(11)	$	1,668
Less: Mark-to-market for economic hedging activities, net	Less: Mark-to-market for economic hedging activities, net	(596)		455		52		—			(89)		Less: Mark-to-market for economic hedging activities, net	(42)		184		(195)		—		—		(53)
Less: Contract and emission credit amortization, net		(4)		19		(5)		—			10
Less: Contract and emissions credit amortization, net													Less: Contract and emissions credit amortization, net	(5)		16		(4)		—		—		7
Less: Depreciation and amortization	Less: Depreciation and amortization	(77)		(39)		(22)		(7)			(145)		Less: Depreciation and amortization	(71)		(27)		(23)		(178)		(9)		(308)
Economic gross margin	Economic gross margin	$	644	$	409	$	194	$	—		$	1,247	Economic gross margin	$	1,027	$	426	$	143	$	428	$	(2)	$	2,022
(a) Includes trading gains and losses and ancillary revenues	(a) Includes trading gains and losses and ancillary revenues												(a) Includes trading gains and losses and ancillary revenues
(b) Includes capacity and emissions credits
(c) Includes $846 million and $184 million of TDSP expense in Texas and West/Services/Other, respectively. TDSP expense in the East was immaterial due to the impact of certain provisions of the CEJA in Illinois, which took effect in June 2022
(c) Includes $1.0 billion, $69 million and $207 million of TDSP expense in Texas, East and West/Services/Other, respectively													(c) Includes $1.0 billion, $69 million and $207 million of TDSP expense in Texas, East and West/Services/Other, respectively
(d) Excludes depreciation and amortization shown separately	(d) Excludes depreciation and amortization shown separately												(d) Excludes depreciation and amortization shown separately
Business Metrics	Business Metrics	Texas		East		West/Services/Other		Corporate/Eliminations			Total		Business Metrics	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail sales	Retail sales												Retail sales
Home power sales volume (GWh)	Home power sales volume (GWh)	14,053		3,838		533		—			18,424		Home power sales volume (GWh)	15,034		3,799		531		—		—		19,364
Business power sales volume (GWh)	Business power sales volume (GWh)	11,006		12,753		3,194		—			26,953		Business power sales volume (GWh)	12,116		13,296		2,889		—		—		28,301
Home natural gas sales volume (MDth)	Home natural gas sales volume (MDth)	—		6,070		5,345		—			11,415		Home natural gas sales volume (MDth)	—		3,438		5,064		—		—		8,502
Business natural gas sales volume (MDth)	Business natural gas sales volume (MDth)	—		314,094		30,602		—			344,696		Business natural gas sales volume (MDth)	—		351,154		39,953		—		—		391,107
Average retail Home customer count (in thousands) ~~(b)~~(a)	Average retail Home customer count (in thousands) ~~(b)~~(a)	2,977		1,794		786		—			5,557		Average retail Home customer count (in thousands) ~~(b)~~(a)	2,879		1,880		769		—		—		5,528
Ending retail Home customer count (in thousands) ~~(b)~~(a)	Ending retail Home customer count (in thousands) ~~(b)~~(a)	2,903		1,788		784		—			5,475		Ending retail Home customer count (in thousands) ~~(b)~~(a)	2,871		1,889		765		—		—		5,525
Average Vivint Smart Home subscriber count (in thousands)(b)													Average Vivint Smart Home subscriber count (in thousands)(b)	—		—		—		2,035		—		2,035
Ending Vivint Smart Home subscriber count (in thousands) (b)													Ending Vivint Smart Home subscriber count (in thousands) (b)	—		—		—		2,051		—		2,051
Power generation	Power generation												Power generation
GWh sold	GWh sold	11,921		3,291		1,858		—			17,070		GWh sold	11,918		2,837		1,726		—		—		16,481
GWh generated(c)	GWh generated(c)												GWh generated(c)
Coal	Coal	5,448		1,532		—		—			6,980		Coal	5,459		873		—		—		—		6,332
Gas	Gas	3,960		323		1,860		—			6,143		Gas	3,964		600		1,725		—		—		6,289
Nuclear	Nuclear	2,513		—		—		—			2,513		Nuclear	2,495		—		—		—		—		2,495

Oil	Oil	—		3		—					3		Oil	—		5		—		—		—		5
Renewables	Renewables	—		—		2		—			2		Renewables	—		—		1		—		—		1
Total	Total	11,921		1,858		1,862		—			15,641		Total	11,918		1,478		1,726		—		—		15,122
(a) Home customer count includes recurring residential customers, services customers and municipal aggregations
(b) The whole home warranty business was sold in January 2022
(b) Vivint Smart Home subscribers includes customers that also purchase other NRG products													(b) Vivint Smart Home subscribers includes customers that also purchase other NRG products
(c) Includes owned and leased generation, excludes tolled generation and equity investments

4859


		Three months ended September 30, 2021									Three months ended September 30, 2022
($ In millions)	($ In millions)	Texas		East		West/Services/Other		Corporate/Eliminations				Total		($ In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Retail revenue	Retail revenue	$	2,503	$	2,698	$	749	$	1			$	5,951	Retail revenue	$	2,999	$	3,863	$	996	$	—	$	7,858
Energy revenue	Energy revenue	18		201		113		4				336		Energy revenue	48		212		180		10		450
Capacity revenue	Capacity revenue	—		172		17		—				189		Capacity revenue	—		38		—		—		38
Mark-to-market for economic hedging activities	Mark-to-market for economic hedging activities	(1)		(3)		(6)		13				3		Mark-to-market for economic hedging activities	4		32		(7)		4		33
Contract amortization	Contract amortization	—		(7)		4		—				(3)		Contract amortization	—		(10)		4		—		(6)
Other revenue(a)	Other revenue(a)	115		16		6		(4)				133		Other revenue(a)	94		43		2		(2)		137
Total revenue	Total revenue	2,635		3,077		883		14				6,609		Total revenue	3,145		4,178		1,175		12		8,510
Cost of fuel	Cost of fuel	(305)		(93)		(68)		—				(466)		Cost of fuel	(489)		(140)		(113)		—		(742)
Purchased energy and other cost of sales(b)(c)(d)	Purchased energy and other cost of sales(b)(c)(d)	(1,492)		(2,500)		(647)		(2)				(4,641)		Purchased energy and other cost of sales(b)(c)(d)	(2,012)		(3,609)		(865)		(8)		(6,494)
Mark-to-market for economic hedging activities	Mark-to-market for economic hedging activities	(81)		1,786		90		(13)				1,782		Mark-to-market for economic hedging activities	(600)		423		59		(4)		(122)
Contract and emission credit amortization		(7)		61		(9)		—				45
Contract and emissions credit amortization														Contract and emissions credit amortization	(4)		29		(9)		—		16
Depreciation and amortization	Depreciation and amortization	(84)		(87)		(21)		(7)				(199)		Depreciation and amortization	(79)		(37)		(22)		(7)		(145)
Gross margin	Gross margin	$	666	$	2,244	$	228	$	(8)			$	3,130	Gross margin	$	(39)	$	844	$	225	$	(7)	$	1,023
Less: Mark-to-market for economic hedging activities, net	Less: Mark-to-market for economic hedging activities, net	(82)		1,783		84		—				1,785		Less: Mark-to-market for economic hedging activities, net	(596)		455		52		—		(89)
Less: Contract and emission credit amortization, net		(7)		54		(5)		—				42
Less: Contract and emissions credit amortization, net														Less: Contract and emissions credit amortization, net	(4)		19		(5)		—		10
Less: Depreciation and amortization	Less: Depreciation and amortization	(84)		(87)		(21)		(7)				(199)		Less: Depreciation and amortization	(79)		(37)		(22)		(7)		(145)
Economic gross margin	Economic gross margin	$	839	$	494	$	170	$	(1)			$	1,502	Economic gross margin	$	640	$	407	$	200	$	—	$	1,247
(a) Includes trading gains and losses and ancillary revenues	(a) Includes trading gains and losses and ancillary revenues									(a) Includes trading gains and losses and ancillary revenues
(b) Includes capacity and emissions credits	(b) Includes capacity and emissions credits													(b) Includes capacity and emissions credits
(c) Includes $802 million, $38 million and $197 million of TDSP expense in Texas, East, and West/Services/Other, respectively
(c) Includes $846 million and $184 million of TDSP expense in Texas and West/Services/Other, respectively. TDSP expense in the East was immaterial due to the impact of certain provisions of the CEJA in Illinois, which took effect in June 2022														(c) Includes $846 million and $184 million of TDSP expense in Texas and West/Services/Other, respectively. TDSP expense in the East was immaterial due to the impact of certain provisions of the CEJA in Illinois, which took effect in June 2022
(d) Excludes depreciation and amortization shown separately	(d) Excludes depreciation and amortization shown separately													(d) Excludes depreciation and amortization shown separately
Business Metrics	Business Metrics	Texas		East		West/Services/Other		Corporate/Eliminations				Total		Business Metrics	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Retail sales	Retail sales													Retail sales
Home power sales volume (GWh)	Home power sales volume (GWh)	13,486		4,032		512		—				18,030		Home power sales volume (GWh)	14,053		3,838		533		—		18,424
Business power sales volume (GWh)	Business power sales volume (GWh)	10,583		14,794		2,672		—				28,049		Business power sales volume (GWh)	11,006		12,753		3,194		—		26,953
Home natural gas sales volume (MDth)	Home natural gas sales volume (MDth)	—		5,148		6,580		—				11,728		Home natural gas sales volume (MDth)	—		4,212		5,345		—		9,557
Business natural gas sales volume (MDth)	Business natural gas sales volume (MDth)	—		334,503		20,666		—				355,169		Business natural gas sales volume (MDth)	—		315,952		30,602		—		346,554
Average retail Home customer count (in thousands)~~(b)~~(a)	Average retail Home customer count (in thousands)~~(b)~~(a)	3,030		1,819		960		—				5,809		Average retail Home customer count (in thousands)~~(b)~~(a)	2,963		1,794		800		—		5,557
Ending retail Home customer count (in thousands)~~(b)~~(a)	Ending retail Home customer count (in thousands)~~(b)~~(a)	3,043		1,784		954		—				5,781		Ending retail Home customer count (in thousands)~~(b)~~(a)	2,890		1,788		797		—		5,475
Power generation	Power generation													Power generation
GWh sold	GWh sold	11,841		4,267		2,246		—				18,354		GWh sold	11,921		3,291		1,858		—		17,070
GWh generated~~(c)~~(b)	GWh generated~~(c)~~(b)													GWh generated~~(c)~~(b)
Coal	Coal	5,558		2,375		—		—				7,933		Coal	5,448		1,532		—		—		6,980
Gas~~(d)~~	Gas~~(d)~~	3,756		750		1,970		—				6,476		Gas~~(d)~~	3,960		323		1,860		—		6,143
Nuclear	Nuclear	2,527		—		—		—				2,527		Nuclear	2,513		—		—		—		2,513
Oil~~(e)~~	Oil~~(e)~~	—		106		—		—				106		Oil~~(e)~~	—		3		—		—		3

Renewables														Renewables	—		—		2				2
Total	Total	11,841		3,231		1,970		—				17,042		Total	11,921		1,858		1,862		—		15,641
(a) Home customer count includes recurring residential customers, services customers and municipal aggregations	(a) Home customer count includes recurring residential customers, services customers and municipal aggregations													(a) Home customer count includes recurring residential customers, services customers and municipal aggregations
(b) Includes 143 thousand whole home warranty customers in West/Services/Other. The whole home warranty business was sold in January 2022
(c) Includes owned and leased generation, excludes tolled generation and equity investments
(d) Includes 410 GWh and 947 GWh in East and West/Services/Other, respectively, that was sold to Generation Bridge in December 2021
(e) Includes 103 GWh in East that was sold to Generation Bridge in December 2021
(b) Includes owned and leased generation, excludes tolled generation and equity investments														(b) Includes owned and leased generation, excludes tolled generation and equity investments

4960

The following table ~~below~~ represents the weather metrics for the three months ended September 30, ~~2022~~2023 and ~~2021:~~2022:


		Three months ended September 30,			Three months ended September 30,
Weather Metrics	Weather Metrics	Texas	East	West/Services/Other (b)		Weather Metrics	Texas	East	West/Services/Other(b)
2022
2023						2023
CDDs (a)	CDDs (a)	1,789	874	1,268		CDDs(a)	2,039	817	1,291
HDDs (a)	HDDs (a)	—	54	3		HDDs(a)	—	48	4
2021
2022						2022
CDDs	CDDs	1,589	784	1,134		CDDs	1,789	874	1,268
HDDs	HDDs	—	38	5		HDDs	—	54	3
10-year average	10-year average					10-year average
CDDs	CDDs	1,659	819	1,159		CDDs	1,673	824	1,173
HDDs	HDDs	6	53	11		HDDs	5	52	9

(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/Services/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 ~~decreased $2.1 billion~~increased $645 million and economic gross margin ~~decreased $255~~increased $775 million during the three months ended September 30, ~~2022,~~2023, compared to the same period in ~~2021.~~2022.

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

Texas


	(In millions)
~~Lower~~ Higher gross margin due to ~~Winter Storm Uri~~the net effect of: •increased net revenue rates of $4.15 per MWh, or $118 million, primarily driven by changes in ~~2021,~~customer term, product and mix; and •a $225 million decrease in cost to serve the retail load, primarily ~~due to ERCOT 180 day settlements~~driven by lower supply costs which were a result of lower realized power pricing, the diversified supply strategy and improved plant performance coupled with the 2022 impact of the W.A. Parish Unit 8 extended outage that began in ~~the third quarter of 2021~~May 2022	$	~~(13)~~
~~The following explanations exclude the impact of Winter Storm Uri:~~343
Higher gross margin due to an increase in load of ~~1.4~~1.3 TWhs, or $42 million, ~~MWhs due to~~from weather,	46
~~Lower gross margin due to the net effect of:~~ •~~a 58%, or $527 million,~~ and an increase in ~~overall average costs to serve the retail~~ load ~~driven by increases in power, ancillary, and fuel costs and the extended outage at W.A. Parish Unit 8 that began in the second quarter~~ of ~~2022; and~~ •~~increased net revenue rates of $14.85 per MWh,~~750 GWhs, or ~~$323~~$7 million, ~~primarily~~ driven by changes in customer mix	~~(204)~~49
~~Lower~~Higher gross margin ~~from~~due to market optimization activities	~~(28)~~5




Other	4 (10)
~~Decrease~~Increase in economic gross margin	$	~~(195)~~387
~~Decrease~~Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	~~(514)~~554
~~Decrease~~Increase in contract and ~~emission~~emissions credit amortization	3 (1)
Decrease in depreciation and amortization	78
~~Decrease~~Increase in gross margin	$	~~(699)~~948

5061

East


	(In millions)
Lower gross margin due to ~~the sale of fossil generating assets to Generation Bridge in December 2021~~	$	~~(61)~~
~~Lower gross margin due to~~ a decrease in generation and capacity as a result of ~~Midwest Generation~~ asset retirements ~~in the second quarter of 2022~~	~~(47)~~$	(14)
~~Lower gross margin primarily due to a 65% decrease in PJM capacity prices~~	~~(34)~~
~~Lower~~Higher electric gross margin due to ~~attrition and decreased load due to changes~~lower supply costs of $8.00 per MWh, or $134 million, driven primarily by decreases in ~~customer mix and attrition~~	~~(27)~~
~~Lower gross margin at Midwest Generation (excluding the impact of asset retirements) due to higher supply costs~~power prices, partially offset by ~~a 36% increase in average realized pricing and an increase in generation volumes due to dark spread expansion~~	~~(21)~~
~~Higher retail electric gross margin due to higher~~lower net revenue rates as a result of changes in customer term, product and mix of ~~$12.25~~$6.75 per MWh, or ~~$203~~$97 million	37

Lower electric gross margin from decreased volume due to changes in customer mix and weather	(7)
Lower natural gas gross margin, including the impact of transportation and storage contract optimization, resulting in lower net revenue rates from changes in customer term, product, and mix of $4.25 per Dth, or $1.50 billion, partially offset by ~~higher~~lower supply costs of ~~$8.25~~$4.00 per ~~MWh, driven primarily by increases in power prices, totaling $134 million~~Dth, or $1.43 billion	69 (74)
Higher natural gas gross margin from increased volume due to ~~higher net revenue rates as a result of changes~~an increase in customer ~~term, product~~count and change in customer mix ~~of $3.69 per Dth, totaling $1.2 billion,~~	19

Higher gross margin due to a reduction in capacity performance penalties resulting from Winter Storm Elliot in December 2022 and a 200% increase in NYISO capacity pricing, partially offset by ~~higher supply costs of $3.62 per Dth, or $1.2 billion~~a 36% decrease in PJM capacity prices and a 7% decrease in PJM capacity volumes	2321
Higher gross margin due to a decrease in supply costs at Midwest Generation, partially offset by a 43% decrease in generation volumes due to dark spread contractions	49
Lower gross margin from sales of NOx ~~emission~~emissions credits	12 (13)

Other	1
~~Decrease~~Increase in economic gross margin	$	~~(85)~~19
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	~~(1,328)~~(271)
Increase in contract amortization	~~(35)~~(3)
Decrease in depreciation and amortization	4810
Decrease in gross margin	$	~~(1,400)~~(245)

West/Services/Other


	(In millions)

Lower gross margin primarily due to lower Services sales	$	(21)
Lower electric gross margin due to ~~the sale~~higher supply costs of ~~fossil generating assets~~$13.50 per MWh, or $46 million, partially offset by higher revenue rates of $8.50 per MWh, or $30 million	(16)
Higher natural gas gross margin due to ~~Generation Bridge~~lower supply costs of $2.35 per Dth, or $106 million, and changes in customer mix of $5 million, partially offset by lower revenue rates of $2.25 per Dth, or $101 million	10

Lower gross margin at Cottonwood driven by lower average realized prices and a reduction in capacity performance bonus payments resulting from PJM Winter Storm Elliott in December ~~2021~~2022	$(31)
Other	~~(24)~~1


~~Lower gross margin due to the sale of the whole home warranty business in the first quarter of 2022~~	~~(7)~~
~~Higher gross margin at Cottonwood due to a 129% increase in average realized power prices partially offset by increased commodity costs~~	34
~~Higher gross margin primarily due to increased revenue at Airtron~~	14
~~Higher gross margin from market optimization activities~~	7


~~Increase~~Decrease in economic gross margin	$	24 (57)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	~~(32)~~(247)
Decrease in contract amortization	1
Increase in depreciation and amortization	(1)
Decrease in gross margin	$	~~(9)~~(304)

Vivint Smart Home


	(In millions)
Increase due to the acquisition of Vivint Smart Home	$	428

Increase in economic gross margin	$	428


Increase in depreciation and amortization	(178)
Increase in gross margin	$	250

5162

Mark-to-Market for Economic Hedging Activities

Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges. Total net mark-to-market results ~~decreased~~increased by ~~$1.9 billion~~$36 million during the three months ended September 30, ~~2022,~~2023, compared to the same period in ~~2021.~~2022.

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


		Three months ended September 30, 2022								Three months ended September 30, 2023
(In millions)	(In millions)	Texas		East		West/Services/Other		Eliminations			Total		(In millions)	Texas		East		West/Services/Other		Eliminations		Total
Mark-to-market results in revenue	Mark-to-market results in revenue												Mark-to-market results in revenue
Reversal of previously recognized unrealized losses on settled positions related to economic hedges		$	1	$	12	$	2	$	(2)		$	13
Reversal of acquired (gain) positions related to economic hedges		—		(2)		—		—			(2)
Net unrealized gains/(losses) on open positions related to economic hedges		3		22		(9)		6			22
Total mark-to-market gains/(losses) in revenue		$	4	$	32	$	(7)	$	4		$	33
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges													Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	—	$	(8)	$	20	$	(2)	$	10
Net unrealized (losses) on open positions related to economic hedges													Net unrealized (losses) on open positions related to economic hedges	—		(52)		(30)		2		(80)
Total mark-to-market (losses) in revenue													Total mark-to-market (losses) in revenue	$	—	$	(60)	$	(10)	$	—	$	(70)
Mark-to-market results in operating costs and expenses	Mark-to-market results in operating costs and expenses												Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges	Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges	$	(191)	$	(151)	$	(60)	$	2		$	(400)	Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges	$	(298)	$	(142)	$	(94)	$	2	$	(532)
Reversal of acquired (gain)/loss positions related to economic hedges	Reversal of acquired (gain)/loss positions related to economic hedges	(16)		18		(15)		—			(13)		Reversal of acquired (gain)/loss positions related to economic hedges	(11)		11		(6)		—		(6)
Net unrealized (losses)/gains on open positions related to economic hedges		(393)		556		134		(6)			291
Net unrealized gains/(losses) on open positions related to economic hedges													Net unrealized gains/(losses) on open positions related to economic hedges	267		375		(85)		(2)		555
Total mark-to-market (losses)/gains in operating costs and expenses	Total mark-to-market (losses)/gains in operating costs and expenses	$	(600)	$	423	$	59	$	(4)		$	(122)	Total mark-to-market (losses)/gains in operating costs and expenses	$	(42)	$	244	$	(185)	$	—	$	17


		Three months ended September 30, 2021								Three months ended September 30, 2022
(In millions)	(In millions)	Texas		East		West/Services/Other		Eliminations			Total		(In millions)	Texas		East		West/Services/Other		Eliminations		Total
Mark-to-market results in revenue	Mark-to-market results in revenue												Mark-to-market results in revenue
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges		$	1	$	(1)	$	2	$	(1)		$	1
Reversal of previously recognized unrealized losses on settled positions related to economic hedges													Reversal of previously recognized unrealized losses on settled positions related to economic hedges	$	1	$	12	$	2	$	(2)	$	13
Reversal of acquired (gain) positions related to economic hedges	Reversal of acquired (gain) positions related to economic hedges	—		(2)		—		—			(2)		Reversal of acquired (gain) positions related to economic hedges	—		(2)		—		—		(2)
Net unrealized gains/(losses) on open positions related to economic hedges													Net unrealized gains/(losses) on open positions related to economic hedges	3		22		(9)		6		22
Total mark-to-market gains/(losses) in revenue													Total mark-to-market gains/(losses) in revenue	$	4	$	32	$	(7)	$	4	$	33
Mark-to-market results in operating costs and expenses													Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges													Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges	$	(191)	$	(151)	$	(60)	$	2	$	(400)
Reversal of acquired (gain)/loss positions related to economic hedges													Reversal of acquired (gain)/loss positions related to economic hedges	(16)		18		(15)		—		(13)
Net unrealized (losses)/gains on open positions related to economic hedges	Net unrealized (losses)/gains on open positions related to economic hedges	(2)		—		(8)		14			4		Net unrealized (losses)/gains on open positions related to economic hedges	(393)		556		134		(6)		291
Total mark-to-market (losses) in revenue		$	(1)	$	(3)	$	(6)	$	13		$	3
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges		$	(99)	$	(2)	$	2	$	1		$	(98)
Reversal of acquired (gain)/loss positions related to economic hedges		(47)		31		(24)		—			(40)
Net unrealized gains on open positions related to economic hedges		65		1,757		112		(14)			1,920
Total mark-to-market gains in operating costs and expenses		$	(81)	$	1,786	$	90	$	(13)		$	1,782
Total mark-to-market (losses)/gains in operating costs and expenses													Total mark-to-market (losses)/gains in operating costs and expenses	$	(600)	$	423	$	59	$	(4)	$	(122)

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

For the three months ended September 30, 2023, the $70 million loss in revenues from economic hedge positions was driven primarily by a decrease in the value of open positions as a result of increases in PJM power prices. The $17 million gain in operating costs and expenses from economic hedge positions was driven primarily by an increase in the value of Texas and East open positions as a result of increases in ERCOT and PJM power prices, partially offset by the reversal of previously recognized unrealized gains on contracts that settled during the period.

For the three months ended September 30, 2022, the $33 million gain in revenues from economic hedge positions was driven primarily by an increase in the value of open positions due to newly executed transactions during the quarter and the reversal of previously recognized unrealized losses on contracts that settled during the period. The $122 million loss in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period, partially offset by an increase in the value of open positions as a result of increases in natural gas and power prices.

For the three months ended September 30, 2021, the $3 million gain in revenues from economic hedge positions was driven primarily by an increase in the value of open positions. The $1.8 billion 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 natural gas and Northeast power prices, partially offset by the reversal of previously recognized unrealized gains on contracts that settled during the period and acquired contracts that settled during the period.

5263

In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the three months ended September 30, ~~2022~~2023 and ~~2021.~~2022. The realized and unrealized financial and physical trading results are included in revenue. The Company's trading activities are subject to limits based on the Company's Risk Management Policy.


		Three months ended September 30,					Three months ended September 30,
(In millions)	(In millions)	2022		2021		(In millions)	2023		2022
Trading gains
Trading gains/(losses)						Trading gains/(losses)
Realized	Realized	$	1	$	31	Realized	$	7	$	1
Unrealized	Unrealized	9		8		Unrealized	(1)		9
Total trading gains	Total trading gains	$	10	$	39	Total trading gains	$	6	$	10

Operations and Maintenance Expense

Operations and maintenance expense ~~are~~is comprised of the following:


(In millions)	(In millions)	Texas		East		West/Services/Other		Eliminations		Total		(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Eliminations		Total

Three months ended September 30, 2023												Three months ended September 30, 2023	$	132	$	93	$	55	$	57	$	(1)	$	336
Three months ended September 30, 2022	Three months ended September 30, 2022	$	213	$	91	$	55	$	—	$	359	Three months ended September 30, 2022	214		90		55		—		—		359
Three months ended September 30, 2021		160		121		52		(1)		332

Operations and maintenance expense ~~increased~~decreased by ~~$27~~$23 million for the three months ended September 30, ~~2022,~~2023, compared to the same period in ~~2021,~~2022, due to the following:


	(In millions)
~~Decrease~~Increase due to the ~~sale~~acquisition of ~~fossil generating assets to Generation Bridge in December 2021~~Vivint Smart Home	$	~~(21)~~57
Decrease due to ~~Midwest Generation asset retirements~~partial property insurance claims in 2023 for the ~~second quarter of~~extended outage at W.A. Parish, as well as restoration expenses incurred in 2022	~~(10)~~(76)
~~Increase due to the W.A. Parish restoration efforts~~Decrease in major maintenance expenditures primarily associated with the ~~May 2022 extended outage~~timing of planned outages at STP	25
~~Increase due to the duration and scope of outages at the Texas nuclear, coal and gas facilities in 2022~~	17
~~Increase driven by higher retail operations costs~~	8 (11)
Increase in ~~the estimate of environmental remediation~~retail operation costs ~~at a deactivated site in the East~~driven by higher personnel costs	7
~~Increase in variable operation and maintenance expense at the PJM coal facilities associated with increased generation in 2022 as compared to 2021~~	5
~~Other~~	~~(4)~~
~~Increase~~Decrease in operations and maintenance expense	$	27 (23)

Other Cost of Operations

Other cost of operations ~~are~~is comprised of the following:


(In millions)	(In millions)	Texas		East		West/Services/Other		Total		(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Total

Three months ended September 30, 2023										Three months ended September 30, 2023	$	78	$	33	$	3	$	1	$	115
Three months ended September 30, 2022	Three months ended September 30, 2022	$	60	$	38	$	3	$	101	Three months ended September 30, 2022	59		38		4		—		101
Three months ended September 30, 2021		47		31		2		80

Other ~~costs~~cost of operations ~~increased by $21 million~~ for the three months ended September 30, ~~2022,~~2023 increased by $14 million, when compared to the same period in ~~2021,~~2022, due to the following:


	(In millions)
~~Decrease due to the sale of fossil generating assets to Generation Bridge in December 2021~~	$	~~(8)~~
Increase in retail gross receipt taxes due to higher revenues in Texas partially offset by lower revenues in the East	21 $






6
Increase primarily due to ~~higher~~changes in ARO cost estimates at Midwest Generation	5
Increase in property insurance premiums and property taxes	72
Other	1
Increase in other cost of operations	$	2114

5364

Depreciation and Amortization

Depreciation and amortization are comprised of the following:


(In millions)	(In millions)	Texas		East		West/Services/Other		Corporate		Total		(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate		Total
Three months ended September 30, 2023												Three months ended September 30, 2023	$	71	$	27	$	23	$	178	$	9	$	308
Three months ended September 30, 2022	Three months ended September 30, 2022	$	77	$	39	$	22	$	7	$	145	Three months ended September 30, 2022	79		37		22		—		7		145
Three months ended September 30, 2021		84		87		21		7		199

Depreciation and amortization ~~decreased~~increased by ~~$54~~$163 million for the three months ended September 30, ~~2022,~~2023, compared to the same period in ~~2021,~~2022, primarily due to ~~lower depreciation at Midwest Generation as a result~~higher amortization of ~~asset impairments and retirements.~~intangible assets due to the acquisition of Vivint Smart Home in March 2023.

Impairment Losses

Impairment losses of $43 million were recorded during the three months ended September 30, 2022 primarily related to the purchase and sale agreement for the sale of the land and related assets at the Astoria generating site and ~~the~~ planned withdrawal and cancellation of its proposed Astoria redevelopment project. ~~Refer to~~For further discussion, see Note 8, Impairments~~for further discussion.~~.

Selling, General and Administrative Costs

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


(In millions)	(In millions)	Texas		East		West/Services/Other		Corporate		Total		(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/ Eliminations		Total
Three months ended September 30, 2023												Three months ended September 30, 2023	$	237	$	156	$	66	$	172	$	7	$	638
Three months ended September 30, 2022	Three months ended September 30, 2022	$	150	$	108	$	60	$	8	$	326	Three months ended September 30, 2022	190		115		65		—		8		378
Three months ended September 30, 2021		148		109		45		16		318

Selling, general and administrative costs increased by $8$260 million for the three months ended September 30, ~~2022,~~2023, compared to the same period in ~~2021,~~2022, due to the following:


	(In millions)
Increase due to the ~~favorable resolution~~acquisition of ~~a legal matter in 2021~~Vivint Smart Home	$	15172
Increase in personnel costs	33
Increase in provision for credit losses	24
Increase in marketing and media expenses	22
Increase in broker fee ~~expenses, partially offset by lower commissions~~and commission expenses	4
~~Decrease due to lower marketing and media spend~~	~~(15)~~18

~~Decrease due to Winter Storm Uri, primarily due to legal expenses in 2021~~	~~(2)~~
Other	6 (9)
Increase in selling, general and administrative costs	$	8

~~Provision for Credit Losses~~

~~Provision for credit losses are comprised of the following:~~

(In millions) Texas East West/Services/Other Total
Three months ended September 30, 2022 $ 41 $ 7 $ 4 $ 52
Three months ended September 30, 2021 58 3 3 64

~~Provision for credit losses decreased by $12 million for the three months ended September 30, 2022, compared to the same period in 2021, due to the following:~~


	~~(In millions)~~
~~Decrease due to Winter Storm Uri, related to counterparty credit risk in 2021~~	$	~~(32)~~
~~Increase due to higher revenues and deteriorated customer payment behavior~~	20
~~Decrease in provision for credit losses~~	$	~~(12)~~260

Acquisition-Related Transaction and Integration Costs

Acquisition-related transaction and integration costs of $8$18 million were incurred during the three months ended September 30, 2023, which consisted of $16 million of integration costs primarily related to Direct Energy and ~~$17~~$2 million of integration costs related to Vivint Smart Home .

Acquisition-related transaction and integration costs of $8 million were incurred during the three months ended September 30, 2022, ~~and 2021,~~ which are comprised primarily of integration costs related to Direct Energy.

Gain on Sale of Assets

The gain on sale of assets of $22 million for the three months ended September 30, 2022 was due to the sale of the Company's 50% ownership interest in Petra Nova.

~~Loss on debt extinguishment, Net~~

~~Loss on debt extinguishment of $57 million was recorded for the~~ ~~three months ended September 30, 2021 in connection with the redemption of the 2026 Senior Notes and the partial redemption of the 2027 Senior Notes in the third quarter of 2021.~~

Interest Expense

Interest expense ~~decreased~~increased by ~~$17~~$68 million for the three months ended September 30, ~~2022,~~2023, compared to the same period in ~~2021,~~2022, primarily due to the Vivint Smart Home acquisition including the impact of newly issued Senior Secured First Lien Notes, acquired debt ~~reduction~~of Vivint Smart Home and borrowings on the ~~refinancing of debt to lower interest rates in the second half of 2021.~~Revolving Credit Facility.

~~Income Tax Expense~~Gross Margin

The Company calculates gross margin in order to evaluate operating performance as revenues less cost of fuel, purchased energy and other costs of sales, mark-to-market for economic hedging activities, contract and emissions credit amortization and depreciation and amortization.

Economic Gross Margin

The following tables present the composition and reconciliation of gross margin and economic gross margin for the three months ended September 30, 2023 and 2022:


	Three months ended September 30, 2023
($ In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue	$	3,489	$	2,633	$	922	$	478	$	(1)	$	7,521
Energy revenue	51		152		59		—		(1)		261
Capacity revenue	—		64		(4)		—		(1)		59
Mark-to-market for economic hedging activities	—		(60)		(10)		—		—		(70)
Contract amortization	—		(6)		1		—		—		(5)
Other revenue(a)	146		26		10		—		(2)		180
Total revenue	3,686		2,809		978		478		(5)		7,946
Cost of fuel	(300)		(64)		(36)		—		—		(400)
Purchased energy and other cost of sales(b)(c)(d)	(2,359)		(2,385)		(808)		(50)		3		(5,599)
Mark-to-market for economic hedging activities	(42)		244		(185)		—		—		17
Contract and emissions credit amortization	(5)		22		(5)		—		—		12
Depreciation and amortization	(71)		(27)		(23)		(178)		(9)		(308)
Gross margin	$	909	$	599	$	(79)	$	250	$	(11)	$	1,668
Less: Mark-to-market for economic hedging activities, net	(42)		184		(195)		—		—		(53)
Less: Contract and emissions credit amortization, net	(5)		16		(4)		—		—		7
Less: Depreciation and amortization	(71)		(27)		(23)		(178)		(9)		(308)
Economic gross margin	$	1,027	$	426	$	143	$	428	$	(2)	$	2,022
(a) Includes trading gains and losses and ancillary revenues
(b) Includes capacity and emissions credits
(c) Includes $1.0 billion, $69 million and $207 million of TDSP expense in Texas, East and West/Services/Other, respectively
(d) Excludes depreciation and amortization shown separately
Business Metrics	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail sales
Home power sales volume (GWh)	15,034		3,799		531		—		—		19,364
Business power sales volume (GWh)	12,116		13,296		2,889		—		—		28,301
Home natural gas sales volume (MDth)	—		3,438		5,064		—		—		8,502
Business natural gas sales volume (MDth)	—		351,154		39,953		—		—		391,107
Average retail Home customer count (in thousands)(a)	2,879		1,880		769		—		—		5,528
Ending retail Home customer count (in thousands)(a)	2,871		1,889		765		—		—		5,525
Average Vivint Smart Home subscriber count (in thousands)(b)	—		—		—		2,035		—		2,035
Ending Vivint Smart Home subscriber count (in thousands) (b)	—		—		—		2,051		—		2,051
Power generation
GWh sold	11,918		2,837		1,726		—		—		16,481
GWh generated(c)
Coal	5,459		873		—		—		—		6,332
Gas	3,964		600		1,725		—		—		6,289
Nuclear	2,495		—		—		—		—		2,495

Oil	—		5		—		—		—		5
Renewables	—		—		1		—		—		1
Total	11,918		1,478		1,726		—		—		15,122
(a) Home customer count includes recurring residential customers, services customers and municipal aggregations
(b) Vivint Smart Home subscribers includes customers that also purchase other NRG products
(c) Includes owned and leased generation, excludes tolled generation and equity investments


	Three months ended September 30, 2022
($ In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Retail revenue	$	2,999	$	3,863	$	996	$	—	$	7,858
Energy revenue	48		212		180		10		450
Capacity revenue	—		38		—		—		38
Mark-to-market for economic hedging activities	4		32		(7)		4		33
Contract amortization	—		(10)		4		—		(6)
Other revenue(a)	94		43		2		(2)		137
Total revenue	3,145		4,178		1,175		12		8,510
Cost of fuel	(489)		(140)		(113)		—		(742)
Purchased energy and other cost of sales(b)(c)(d)	(2,012)		(3,609)		(865)		(8)		(6,494)
Mark-to-market for economic hedging activities	(600)		423		59		(4)		(122)
Contract and emissions credit amortization	(4)		29		(9)		—		16
Depreciation and amortization	(79)		(37)		(22)		(7)		(145)
Gross margin	$	(39)	$	844	$	225	$	(7)	$	1,023
Less: Mark-to-market for economic hedging activities, net	(596)		455		52		—		(89)
Less: Contract and emissions credit amortization, net	(4)		19		(5)		—		10
Less: Depreciation and amortization	(79)		(37)		(22)		(7)		(145)
Economic gross margin	$	640	$	407	$	200	$	—	$	1,247
(a) Includes trading gains and losses and ancillary revenues
(b) Includes capacity and emissions credits
(c) Includes $846 million and $184 million of TDSP expense in Texas and West/Services/Other, respectively. TDSP expense in the East was immaterial due to the impact of certain provisions of the CEJA in Illinois, which took effect in June 2022
(d) Excludes depreciation and amortization shown separately
Business Metrics	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Retail sales
Home power sales volume (GWh)	14,053		3,838		533		—		18,424
Business power sales volume (GWh)	11,006		12,753		3,194		—		26,953
Home natural gas sales volume (MDth)	—		4,212		5,345		—		9,557
Business natural gas sales volume (MDth)	—		315,952		30,602		—		346,554
Average retail Home customer count (in thousands)(a)	2,963		1,794		800		—		5,557
Ending retail Home customer count (in thousands)(a)	2,890		1,788		797		—		5,475
Power generation
GWh sold	11,921		3,291		1,858		—		17,070
GWh generated(b)
Coal	5,448		1,532		—		—		6,980
Gas	3,960		323		1,860		—		6,143
Nuclear	2,513		—		—		—		2,513
Oil	—		3		—		—		3
Renewables	—		—		2				2
Total	11,921		1,858		1,862		—		15,641
(a) Home customer count includes recurring residential customers, services customers and municipal aggregations
(b) Includes owned and leased generation, excludes tolled generation and equity investments

The following table represents the weather metrics for the three months ended September 30, 2023 and 2022:


	Three months ended September 30,
Weather Metrics	Texas	East	West/Services/Other(b)
2023
CDDs(a)	2,039	817	1,291
HDDs(a)	—	48	4
2022
CDDs	1,789	874	1,268
HDDs	—	54	3
10-year average
CDDs	1,673	824	1,173
HDDs	5	52	9

(b) The West/Services/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 $645 million and economic gross margin increased $775 million during the three months ended September 30, 2023, compared to the same period in 2022.

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

Texas


	(In millions)
Higher gross margin due to the net effect of: •increased net revenue rates of $4.15 per MWh, or $118 million, primarily driven by changes in customer term, product and mix; and •a $225 million decrease in cost to serve the retail load, primarily driven by lower supply costs which were a result of lower realized power pricing, the diversified supply strategy and improved plant performance coupled with the 2022 impact of the W.A. Parish Unit 8 extended outage that began in May 2022	$	343
Higher gross margin due to an increase in load of 1.3 TWhs, or $42 million, from weather, and an increase in load of 750 GWhs, or $7 million, driven by changes in customer mix	49
Higher gross margin due to market optimization activities	5




Other	(10)
Increase in economic gross margin	$	387
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	554
Increase in contract and emissions credit amortization	(1)
Decrease in depreciation and amortization	8
Increase in gross margin	$	948

East


	(In millions)
Lower gross margin due to a decrease in generation and capacity as a result of asset retirements	$	(14)
Higher electric gross margin due to lower supply costs of $8.00 per MWh, or $134 million, driven primarily by decreases in power prices, partially offset by lower net revenue rates as a result of changes in customer term, product and mix of $6.75 per MWh, or $97 million	37

Lower electric gross margin from decreased volume due to changes in customer mix and weather	(7)
Lower natural gas gross margin, including the impact of transportation and storage contract optimization, resulting in lower net revenue rates from changes in customer term, product, and mix of $4.25 per Dth, or $1.50 billion, partially offset by lower supply costs of $4.00 per Dth, or $1.43 billion	(74)
Higher natural gas gross margin from increased volume due to an increase in customer count and change in customer mix	19

Higher gross margin due to a reduction in capacity performance penalties resulting from Winter Storm Elliot in December 2022 and a 200% increase in NYISO capacity pricing, partially offset by a 36% decrease in PJM capacity prices and a 7% decrease in PJM capacity volumes	21
Higher gross margin due to a decrease in supply costs at Midwest Generation, partially offset by a 43% decrease in generation volumes due to dark spread contractions	49
Lower gross margin from sales of NOx emissions credits	(13)
Other	1
Increase in economic gross margin	$	19
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(271)
Increase in contract amortization	(3)
Decrease in depreciation and amortization	10
Decrease in gross margin	$	(245)

West/Services/Other


	(In millions)

Lower gross margin primarily due to lower Services sales	$	(21)
Lower electric gross margin due to higher supply costs of $13.50 per MWh, or $46 million, partially offset by higher revenue rates of $8.50 per MWh, or $30 million	(16)
Higher natural gas gross margin due to lower supply costs of $2.35 per Dth, or $106 million, and changes in customer mix of $5 million, partially offset by lower revenue rates of $2.25 per Dth, or $101 million	10

Lower gross margin at Cottonwood driven by lower average realized prices and a reduction in capacity performance bonus payments resulting from PJM Winter Storm Elliott in December 2022	(31)
Other	1


Decrease in economic gross margin	$	(57)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(247)
Decrease in contract amortization	1
Increase in depreciation and amortization	(1)
Decrease in gross margin	$	(304)

Vivint Smart Home


	(In millions)
Increase due to the acquisition of Vivint Smart Home	$	428

Increase in economic gross margin	$	428


Increase in depreciation and amortization	(178)
Increase in gross margin	$	250

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 $36 million during the three months ended September 30, 2023, compared to the same period in 2022.

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


	Three months ended September 30, 2023
(In millions)	Texas		East		West/Services/Other		Eliminations		Total
Mark-to-market results in revenue
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	—	$	(8)	$	20	$	(2)	$	10
Net unrealized (losses) on open positions related to economic hedges	—		(52)		(30)		2		(80)
Total mark-to-market (losses) in revenue	$	—	$	(60)	$	(10)	$	—	$	(70)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges	$	(298)	$	(142)	$	(94)	$	2	$	(532)
Reversal of acquired (gain)/loss positions related to economic hedges	(11)		11		(6)		—		(6)
Net unrealized gains/(losses) on open positions related to economic hedges	267		375		(85)		(2)		555
Total mark-to-market (losses)/gains in operating costs and expenses	$	(42)	$	244	$	(185)	$	—	$	17


	Three months ended September 30, 2022
(In millions)	Texas		East		West/Services/Other		Eliminations		Total
Mark-to-market results in revenue
Reversal of previously recognized unrealized losses on settled positions related to economic hedges	$	1	$	12	$	2	$	(2)	$	13
Reversal of acquired (gain) positions related to economic hedges	—		(2)		—		—		(2)
Net unrealized gains/(losses) on open positions related to economic hedges	3		22		(9)		6		22
Total mark-to-market gains/(losses) in revenue	$	4	$	32	$	(7)	$	4	$	33
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges	$	(191)	$	(151)	$	(60)	$	2	$	(400)
Reversal of acquired (gain)/loss positions related to economic hedges	(16)		18		(15)		—		(13)
Net unrealized (losses)/gains on open positions related to economic hedges	(393)		556		134		(6)		291
Total mark-to-market (losses)/gains in operating costs and expenses	$	(600)	$	423	$	59	$	(4)	$	(122)

For the three months ended September 30, ~~2022, income tax expense~~2023, the $70 million loss in revenues from economic hedge positions was driven primarily by a decrease in the value of ~~$16~~open positions as a result of increases in PJM power prices. The $17 million gain in operating costs and expenses from economic hedge positions was ~~recorded~~driven primarily by an increase in the value of Texas and East open positions as a result of increases in ERCOT and PJM power prices, partially offset by the reversal of previously recognized unrealized gains on ~~pre-tax income of $83 million. For~~contracts that settled during the same period in 2021, income tax expense of $545 million was recorded on pre-tax income of $2.2 billion. The effective tax rates were 19.3% and 25.2% for the three months ended September 30, 2022 and 2021, respectively.period.

For the three months ended September 30, 2022, the ~~effective tax rate~~$33 million gain in revenues from economic hedge positions was ~~lower than~~driven primarily by an increase in the ~~statutory rate~~value of ~~21% primarily~~open positions due to newly executed transactions during the ~~benefit resulting from carbon capture tax credits~~quarter and the ~~reduction~~reversal of previously recognized unrealized losses on contracts that settled during the period. The $122 million loss in ~~statutory state tax rates. For~~operating costs and expenses from economic hedge positions was driven primarily by the ~~same~~reversal of previously recognized unrealized gains on contracts that settled during the period, partially offset by an increase in ~~2021,~~ the ~~effective tax rate was higher than the statutory rate~~value of ~~21% primarily due to state tax expense.~~open positions as a result of increases in natural gas and power prices.

5563

~~Management’s discussion of~~In accordance with ASC 815, the following table represents the results of ~~operations~~the Company's financial and physical trading of energy commodities for the ~~nine~~three months ended September 30, ~~2022~~2023 and ~~2021~~2022. The realized and unrealized financial and physical trading results are included in revenue. The Company's trading activities are subject to limits based on the Company's Risk Management Policy.

~~Electricity Prices~~


	Three months ended September 30,
(In millions)	2023		2022
Trading gains/(losses)
Realized	$	7	$	1
Unrealized	(1)		9
Total trading gains	$	6	$	10

~~The following table summarizes average on peak power prices for each~~

Operations and Maintenance Expense

Operations and maintenance expense is comprised of the ~~major markets in which NRG operates~~following:


(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Eliminations		Total

Three months ended September 30, 2023	$	132	$	93	$	55	$	57	$	(1)	$	336
Three months ended September 30, 2022	214		90		55		—		—		359

Operations and maintenance expense decreased by $23 million for the ~~nine~~three months ended September 30, 2022 and 2021. The average on-peak power prices decreased significantly in Texas due to Winter Storm Uri's impact on 2021 pricing. East and West average on-peak power prices increased for the nine months ended September 30, 2022 as2023, compared to the same period in ~~2021 as a result~~2022, due to the following:


	(In millions)
Increase due to the acquisition of Vivint Smart Home	$	57
Decrease due to partial property insurance claims in 2023 for the extended outage at W.A. Parish, as well as restoration expenses incurred in 2022	(76)
Decrease in major maintenance expenditures primarily associated with the timing of planned outages at STP	(11)
Increase in retail operation costs driven by higher personnel costs	7
Decrease in operations and maintenance expense	$	(23)

Other Cost of ~~higher natural gas prices.~~Operations

Average on Peak Power Price ($/MWh)
Nine months ended September 30,
Region 2022 2021 Change %
Texas
ERCOT - Houston (a)
$ 101.20 $ 240.14 (58) %
ERCOT - North(a)
85.68 236.75 (64) %
East
    NY J/NYC(b)
$ 98.34 $ 45.04 118 %
    NEPOOL(b)
96.30 47.17 104 %
    COMED (PJM)(b)
76.82 38.00 102 %
    PJM West Hub(b)
87.44 40.04 118 %
West
MISO - Louisiana Hub(b)
$ 75.26 $ 40.11 88 %
CAISO - SP15(b)
71.86 51.22 40 %
Other cost of operations is comprised of the following:

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


(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Total

Three months ended September 30, 2023	$	78	$	33	$	3	$	1	$	115
Three months ended September 30, 2022	59		38		4		—		101

~~(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~~Other cost of ~~settled hedges,~~operations for the ~~nine~~three months ended September 30, ~~2022 and 2021:~~
Average Realized Power Price ($/MWh)
Nine months ended September 30,
Segment 2022 2021 Change %
East(a)
$ 53.96 $ 37.70 43 %
West/Services/Other
69.79 39.97 75 %

~~(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 ($5.70)/MWh in the nine months ended September 30, 2022 and ($5.10)/MWh in the nine months ended September 30, 2021

~~The average realized power prices~~2023 increased ~~in the East and West/Services/Other segments for the nine months ended September 30, 2022, as~~by $14 million, when compared to the same period in ~~2021, as a result of higher natural gas prices. Average power prices increase less than average on peak power prices~~2022, due to ~~impact~~the following:


	(In millions)
Increase in retail gross receipt taxes due to higher revenues in Texas partially offset by lower revenues in the East	$	6
Increase primarily due to changes in ARO cost estimates at Midwest Generation	5
Increase in property insurance premiums and property taxes	2
Other	1
Increase in other cost of operations	$	14

Depreciation and Amortization

Depreciation and amortization are comprised of the following:


(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate		Total
Three months ended September 30, 2023	$	71	$	27	$	23	$	178	$	9	$	308
Three months ended September 30, 2022	79		37		22		—		7		145

Depreciation and amortization increased by $163 million for the three months ended September 30, 2023, compared to the same period in 2022, primarily due to higher amortization of intangible assets due to the acquisition of Vivint Smart Home in March 2023.

Impairment Losses

Impairment losses of $43 million were recorded during the three months ended September 30, 2022 primarily related to the purchase and sale agreement for the sale of the land and related assets at the Astoria generating site and planned withdrawal and cancellation of its proposed Astoria redevelopment project. For further discussion, see Note 8, Impairments.

Selling, General and Administrative Costs

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


(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/ Eliminations		Total
Three months ended September 30, 2023	$	237	$	156	$	66	$	172	$	7	$	638
Three months ended September 30, 2022	190		115		65		—		8		378

Selling, general and administrative costs increased by $260 million for the three months ended September 30, 2023, compared to the same period in 2022, due to the following:


	(In millions)
Increase due to the acquisition of Vivint Smart Home	$	172
Increase in personnel costs	33
Increase in provision for credit losses	24
Increase in marketing and media expenses	22
Increase in broker fee and commission expenses	18


Other	(9)
Increase in selling, general and administrative costs	$	260

Acquisition-Related Transaction and Integration Costs

Acquisition-related transaction and integration costs of $18 million were incurred during the three months ended September 30, 2023, which consisted of $16 million of integration costs primarily related to Direct Energy and $2 million of integration costs related to Vivint Smart Home .

Acquisition-related transaction and integration costs of $8 million were incurred during the three months ended September 30, 2022, which are comprised primarily of integration costs related to Direct Energy.

Gain on Sale of Assets

The gain on sale of assets of $22 million for the three months ended September 30, 2022 was due to the sale of the Company's ~~multi-year hedging program.~~50% ownership interest in Petra Nova.

Interest Expense

Interest expense increased by $68 million for the three months ended September 30, 2023, compared to the same period in 2022, primarily due to the Vivint Smart Home acquisition including the impact of newly issued Senior Secured First Lien Notes, acquired debt of Vivint Smart Home and borrowings on the Revolving Credit Facility.

Gross Margin

Economic Gross Margin

The following tables present the composition and reconciliation of gross margin and economic gross margin for the three months ended September 30, 2023 and 2022:


	Three months ended September 30, 2023
($ In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue	$	3,489	$	2,633	$	922	$	478	$	(1)	$	7,521
Energy revenue	51		152		59		—		(1)		261
Capacity revenue	—		64		(4)		—		(1)		59
Mark-to-market for economic hedging activities	—		(60)		(10)		—		—		(70)
Contract amortization	—		(6)		1		—		—		(5)
Other revenue(a)	146		26		10		—		(2)		180
Total revenue	3,686		2,809		978		478		(5)		7,946
Cost of fuel	(300)		(64)		(36)		—		—		(400)
Purchased energy and other cost of sales(b)(c)(d)	(2,359)		(2,385)		(808)		(50)		3		(5,599)
Mark-to-market for economic hedging activities	(42)		244		(185)		—		—		17
Contract and emissions credit amortization	(5)		22		(5)		—		—		12
Depreciation and amortization	(71)		(27)		(23)		(178)		(9)		(308)
Gross margin	$	909	$	599	$	(79)	$	250	$	(11)	$	1,668
Less: Mark-to-market for economic hedging activities, net	(42)		184		(195)		—		—		(53)
Less: Contract and emissions credit amortization, net	(5)		16		(4)		—		—		7
Less: Depreciation and amortization	(71)		(27)		(23)		(178)		(9)		(308)
Economic gross margin	$	1,027	$	426	$	143	$	428	$	(2)	$	2,022
(a) Includes trading gains and losses and ancillary revenues
(b) Includes capacity and emissions credits
(c) Includes $1.0 billion, $69 million and $207 million of TDSP expense in Texas, East and West/Services/Other, respectively
(d) Excludes depreciation and amortization shown separately
Business Metrics	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail sales
Home power sales volume (GWh)	15,034		3,799		531		—		—		19,364
Business power sales volume (GWh)	12,116		13,296		2,889		—		—		28,301
Home natural gas sales volume (MDth)	—		3,438		5,064		—		—		8,502
Business natural gas sales volume (MDth)	—		351,154		39,953		—		—		391,107
Average retail Home customer count (in thousands)(a)	2,879		1,880		769		—		—		5,528
Ending retail Home customer count (in thousands)(a)	2,871		1,889		765		—		—		5,525
Average Vivint Smart Home subscriber count (in thousands)(b)	—		—		—		2,035		—		2,035
Ending Vivint Smart Home subscriber count (in thousands) (b)	—		—		—		2,051		—		2,051
Power generation
GWh sold	11,918		2,837		1,726		—		—		16,481
GWh generated(c)
Coal	5,459		873		—		—		—		6,332
Gas	3,964		600		1,725		—		—		6,289
Nuclear	2,495		—		—		—		—		2,495

Oil	—		5		—		—		—		5
Renewables	—		—		1		—		—		1
Total	11,918		1,478		1,726		—		—		15,122
(a) Home customer count includes recurring residential customers, services customers and municipal aggregations
(b) Vivint Smart Home subscribers includes customers that also purchase other NRG products
(c) Includes owned and leased generation, excludes tolled generation and equity investments


	Three months ended September 30, 2022
($ In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Retail revenue	$	2,999	$	3,863	$	996	$	—	$	7,858
Energy revenue	48		212		180		10		450
Capacity revenue	—		38		—		—		38
Mark-to-market for economic hedging activities	4		32		(7)		4		33
Contract amortization	—		(10)		4		—		(6)
Other revenue(a)	94		43		2		(2)		137
Total revenue	3,145		4,178		1,175		12		8,510
Cost of fuel	(489)		(140)		(113)		—		(742)
Purchased energy and other cost of sales(b)(c)(d)	(2,012)		(3,609)		(865)		(8)		(6,494)
Mark-to-market for economic hedging activities	(600)		423		59		(4)		(122)
Contract and emissions credit amortization	(4)		29		(9)		—		16
Depreciation and amortization	(79)		(37)		(22)		(7)		(145)
Gross margin	$	(39)	$	844	$	225	$	(7)	$	1,023
Less: Mark-to-market for economic hedging activities, net	(596)		455		52		—		(89)
Less: Contract and emissions credit amortization, net	(4)		19		(5)		—		10
Less: Depreciation and amortization	(79)		(37)		(22)		(7)		(145)
Economic gross margin	$	640	$	407	$	200	$	—	$	1,247
(a) Includes trading gains and losses and ancillary revenues
(b) Includes capacity and emissions credits
(c) Includes $846 million and $184 million of TDSP expense in Texas and West/Services/Other, respectively. TDSP expense in the East was immaterial due to the impact of certain provisions of the CEJA in Illinois, which took effect in June 2022
(d) Excludes depreciation and amortization shown separately
Business Metrics	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Retail sales
Home power sales volume (GWh)	14,053		3,838		533		—		18,424
Business power sales volume (GWh)	11,006		12,753		3,194		—		26,953
Home natural gas sales volume (MDth)	—		4,212		5,345		—		9,557
Business natural gas sales volume (MDth)	—		315,952		30,602		—		346,554
Average retail Home customer count (in thousands)(a)	2,963		1,794		800		—		5,557
Ending retail Home customer count (in thousands)(a)	2,890		1,788		797		—		5,475
Power generation
GWh sold	11,921		3,291		1,858		—		17,070
GWh generated(b)
Coal	5,448		1,532		—		—		6,980
Gas	3,960		323		1,860		—		6,143
Nuclear	2,513		—		—		—		2,513
Oil	—		3		—		—		3
Renewables	—		—		2				2
Total	11,921		1,858		1,862		—		15,641
(a) Home customer count includes recurring residential customers, services customers and municipal aggregations
(b) Includes owned and leased generation, excludes tolled generation and equity investments

The following table represents the weather metrics for the three months ended September 30, 2023 and 2022:


	Three months ended September 30,
Weather Metrics	Texas	East	West/Services/Other(b)
2023
CDDs(a)	2,039	817	1,291
HDDs(a)	—	48	4
2022
CDDs	1,789	874	1,268
HDDs	—	54	3
10-year average
CDDs	1,673	824	1,173
HDDs	5	52	9

(b) The West/Services/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 $645 million and economic gross margin increased $775 million during the three months ended September 30, 2023, compared to the same period in 2022.

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

Texas


	(In millions)
Higher gross margin due to the net effect of: •increased net revenue rates of $4.15 per MWh, or $118 million, primarily driven by changes in customer term, product and mix; and •a $225 million decrease in cost to serve the retail load, primarily driven by lower supply costs which were a result of lower realized power pricing, the diversified supply strategy and improved plant performance coupled with the 2022 impact of the W.A. Parish Unit 8 extended outage that began in May 2022	$	343
Higher gross margin due to an increase in load of 1.3 TWhs, or $42 million, from weather, and an increase in load of 750 GWhs, or $7 million, driven by changes in customer mix	49
Higher gross margin due to market optimization activities	5




Other	(10)
Increase in economic gross margin	$	387
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	554
Increase in contract and emissions credit amortization	(1)
Decrease in depreciation and amortization	8
Increase in gross margin	$	948

East


	(In millions)
Lower gross margin due to a decrease in generation and capacity as a result of asset retirements	$	(14)
Higher electric gross margin due to lower supply costs of $8.00 per MWh, or $134 million, driven primarily by decreases in power prices, partially offset by lower net revenue rates as a result of changes in customer term, product and mix of $6.75 per MWh, or $97 million	37

Lower electric gross margin from decreased volume due to changes in customer mix and weather	(7)
Lower natural gas gross margin, including the impact of transportation and storage contract optimization, resulting in lower net revenue rates from changes in customer term, product, and mix of $4.25 per Dth, or $1.50 billion, partially offset by lower supply costs of $4.00 per Dth, or $1.43 billion	(74)
Higher natural gas gross margin from increased volume due to an increase in customer count and change in customer mix	19

Higher gross margin due to a reduction in capacity performance penalties resulting from Winter Storm Elliot in December 2022 and a 200% increase in NYISO capacity pricing, partially offset by a 36% decrease in PJM capacity prices and a 7% decrease in PJM capacity volumes	21
Higher gross margin due to a decrease in supply costs at Midwest Generation, partially offset by a 43% decrease in generation volumes due to dark spread contractions	49
Lower gross margin from sales of NOx emissions credits	(13)
Other	1
Increase in economic gross margin	$	19
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(271)
Increase in contract amortization	(3)
Decrease in depreciation and amortization	10
Decrease in gross margin	$	(245)

West/Services/Other


	(In millions)

Lower gross margin primarily due to lower Services sales	$	(21)
Lower electric gross margin due to higher supply costs of $13.50 per MWh, or $46 million, partially offset by higher revenue rates of $8.50 per MWh, or $30 million	(16)
Higher natural gas gross margin due to lower supply costs of $2.35 per Dth, or $106 million, and changes in customer mix of $5 million, partially offset by lower revenue rates of $2.25 per Dth, or $101 million	10

Lower gross margin at Cottonwood driven by lower average realized prices and a reduction in capacity performance bonus payments resulting from PJM Winter Storm Elliott in December 2022	(31)
Other	1


Decrease in economic gross margin	$	(57)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(247)
Decrease in contract amortization	1
Increase in depreciation and amortization	(1)
Decrease in gross margin	$	(304)

Vivint Smart Home


	(In millions)
Increase due to the acquisition of Vivint Smart Home	$	428

Increase in economic gross margin	$	428


Increase in depreciation and amortization	(178)
Increase in gross margin	$	250

Mark-to-Market for Economic Hedging Activities

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


	Three months ended September 30, 2023
(In millions)	Texas		East		West/Services/Other		Eliminations		Total
Mark-to-market results in revenue
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	—	$	(8)	$	20	$	(2)	$	10
Net unrealized (losses) on open positions related to economic hedges	—		(52)		(30)		2		(80)
Total mark-to-market (losses) in revenue	$	—	$	(60)	$	(10)	$	—	$	(70)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges	$	(298)	$	(142)	$	(94)	$	2	$	(532)
Reversal of acquired (gain)/loss positions related to economic hedges	(11)		11		(6)		—		(6)
Net unrealized gains/(losses) on open positions related to economic hedges	267		375		(85)		(2)		555
Total mark-to-market (losses)/gains in operating costs and expenses	$	(42)	$	244	$	(185)	$	—	$	17


	Three months ended September 30, 2022
(In millions)	Texas		East		West/Services/Other		Eliminations		Total
Mark-to-market results in revenue
Reversal of previously recognized unrealized losses on settled positions related to economic hedges	$	1	$	12	$	2	$	(2)	$	13
Reversal of acquired (gain) positions related to economic hedges	—		(2)		—		—		(2)
Net unrealized gains/(losses) on open positions related to economic hedges	3		22		(9)		6		22
Total mark-to-market gains/(losses) in revenue	$	4	$	32	$	(7)	$	4	$	33
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges	$	(191)	$	(151)	$	(60)	$	2	$	(400)
Reversal of acquired (gain)/loss positions related to economic hedges	(16)		18		(15)		—		(13)
Net unrealized (losses)/gains on open positions related to economic hedges	(393)		556		134		(6)		291
Total mark-to-market (losses)/gains in operating costs and expenses	$	(600)	$	423	$	59	$	(4)	$	(122)

In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the three months ended September 30, 2023 and 2022. The realized and unrealized financial and physical trading results are included in revenue. The Company's trading activities are subject to limits based on the Company's Risk Management Policy.


	Three months ended September 30,
(In millions)	2023		2022
Trading gains/(losses)
Realized	$	7	$	1
Unrealized	(1)		9
Total trading gains	$	6	$	10

Operations and Maintenance Expense

Operations and maintenance expense is comprised of the following:


(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Eliminations		Total

Three months ended September 30, 2023	$	132	$	93	$	55	$	57	$	(1)	$	336
Three months ended September 30, 2022	214		90		55		—		—		359

Operations and maintenance expense decreased by $23 million for the three months ended September 30, 2023, compared to the same period in 2022, due to the following:


	(In millions)
Increase due to the acquisition of Vivint Smart Home	$	57
Decrease due to partial property insurance claims in 2023 for the extended outage at W.A. Parish, as well as restoration expenses incurred in 2022	(76)
Decrease in major maintenance expenditures primarily associated with the timing of planned outages at STP	(11)
Increase in retail operation costs driven by higher personnel costs	7
Decrease in operations and maintenance expense	$	(23)

Other Cost of Operations

Other cost of operations is comprised of the following:


(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Total

Three months ended September 30, 2023	$	78	$	33	$	3	$	1	$	115
Three months ended September 30, 2022	59		38		4		—		101

Other cost of operations for the three months ended September 30, 2023 increased by $14 million, when compared to the same period in 2022, due to the following:


	(In millions)
Increase in retail gross receipt taxes due to higher revenues in Texas partially offset by lower revenues in the East	$	6
Increase primarily due to changes in ARO cost estimates at Midwest Generation	5
Increase in property insurance premiums and property taxes	2
Other	1
Increase in other cost of operations	$	14

Depreciation and Amortization

Depreciation and amortization are comprised of the following:


(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate		Total
Three months ended September 30, 2023	$	71	$	27	$	23	$	178	$	9	$	308
Three months ended September 30, 2022	79		37		22		—		7		145

Impairment Losses

Impairment losses of $43 million were recorded during the three months ended September 30, 2022 primarily related to the purchase and sale agreement for the sale of the land and related assets at the Astoria generating site and planned withdrawal and cancellation of its proposed Astoria redevelopment project. For further discussion, see Note 8, Impairments.

Selling, General and Administrative Costs

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


(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/ Eliminations		Total
Three months ended September 30, 2023	$	237	$	156	$	66	$	172	$	7	$	638
Three months ended September 30, 2022	190		115		65		—		8		378

Selling, general and administrative costs increased by $260 million for the three months ended September 30, 2023, compared to the same period in 2022, due to the following:


	(In millions)
Increase due to the acquisition of Vivint Smart Home	$	172
Increase in personnel costs	33
Increase in provision for credit losses	24
Increase in marketing and media expenses	22
Increase in broker fee and commission expenses	18


Other	(9)
Increase in selling, general and administrative costs	$	260

Acquisition-Related Transaction and Integration Costs

Gain on Sale of Assets

The gain on sale of assets of $22 million for the three months ended September 30, 2022 was due to the sale of the Company's 50% ownership interest in Petra Nova.

Interest Expense

Income Tax Expense

For the three months ended September 30, 2023, income tax expense of $65 million was recorded on pre-tax income of $408 million. For the same period in 2022, income tax expense of $16 million was recorded on pre-tax income of $83 million. The effective tax rates were 15.9% and 19.3% for the three months ended September 30, 2023 and 2022, respectively.

For the three months ended September 30, 2023, the effective tax rate was lower than the statutory rate of 21% primarily due to a decrease in state tax expense resulting from a decrease in year-to-date financial statement losses. For the same period in 2022, the effective tax rate was lower than the statutory rate of 21% primarily due to the benefit resulting from carbon capture tax credits and the reduction in statutory state tax rates.

Management’s discussion of the results of operations for the nine months ended September 30, 2023 and 2022

Electricity Prices

The following table summarizes average on peak power prices for each of the major markets in which NRG operates for the nine months ended September 30, 2023 and 2022. Texas - Houston, East and West average on-peak power prices decreased for the nine months ended September 30, 2023 as compared to the same period in 2022 as a result of lower natural gas prices.


	Average on Peak Power Price ($/MWh)
	Nine months ended September 30,
Region	2023		2022		Change %
Texas
ERCOT - Houston (a)	$	89.00	$	101.20	(12)	%
ERCOT - North(a)	87.49		85.68		2	%

East
NY J/NYC(b)	$	39.43	$	98.34	(60)	%
NEPOOL(b)	41.87		96.30		(57)	%
COMED (PJM)(b)	33.05		76.82		(57)	%
PJM West Hub(b)	38.39		87.44		(56)	%

West
MISO - Louisiana Hub(b)	$	34.54	$	75.26	(54)	%
CAISO - SP15(b)	63.38		71.86		(12)	%

(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

Natural Gas Prices

The following table summarizes the average Henry Hub natural gas price for the nine months ended September 30, 2023 and 2022:


	Nine months ended September 30,
	2023		2022		Change %
($/MMBtu)	$	2.69	$	6.77	(60)	%

Gross Margin

The Company calculates gross margin in order to evaluate operating performance as revenues less cost of fuel, purchased energy and other costs of sales, mark-to-market for economic hedging activities, contract and emissions credit amortization and depreciation and amortization.

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 fuel, purchased energy and other cost of sales. Economic gross margin does not include mark-to-market gains or losses on economic hedging

activities, contract and emissions credit amortization, depreciation and amortization, operations and maintenance, or other cost of operations.

The ~~below~~following tables present the composition and reconciliation of gross margin and economic gross margin for the nine months ended September 30, ~~2022~~2023 and ~~2021:~~2022:


		Nine months ended September 30, 2022										Nine months ended September 30, 2023
($ In millions)	($ In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total			($ In millions)	Texas		East		West/Services/Other		Vivint Smart Home(a)		Corporate/Eliminations		Total
Retail revenue	Retail revenue	$	7,528	$	11,784	$	3,068	$	(1)	$	22,379		Retail revenue	$	7,842	$	9,007	$	2,993	$	1,070	$	(1)	$	20,911
Energy revenue	Energy revenue	101		544		365		24		1,034			Energy revenue	71		254		147		—		—		472
Capacity revenue	Capacity revenue	—		242		2		—		244			Capacity revenue	—		154		(3)		—		(1)		150
Mark-to-market for economic hedging activities	Mark-to-market for economic hedging activities	1		(204)		(63)		18		(248)			Mark-to-market for economic hedging activities	—		27		80		—		(11)		96
Contract amortization	Contract amortization	—		(30)		2		—		(28)			Contract amortization	—		(24)		—		—		—		(24)
Other revenue ~~(a)~~(b)	Other revenue ~~(a)~~(b)	238		78		3		(12)		307			Other revenue ~~(a)~~(b)	322		70		27		—		(8)		411
Total revenue	Total revenue	7,868		12,414		3,377		29		23,688			Total revenue	8,235		9,488		3,244		1,070		(21)		22,016
Cost of fuel	Cost of fuel	(1,018)		(315)		(270)		—		(1,603)			Cost of fuel	(596)		(102)		(92)		—		—		(790)
Purchased energy and other cost of sales~~(d)~~(e)	Purchased energy and other cost of sales~~(d)~~(e)	(4,980)		(11,040)		(2,724)		(13)		(18,757)			Purchased energy and other cost of sales~~(d)~~(e)	(5,017)		(8,091)		(2,679)		(102)		6		(15,883)
Mark-to-market for economic hedging activities	Mark-to-market for economic hedging activities	662		2,241		270		(18)		3,155			Mark-to-market for economic hedging activities	421		(1,750)		(711)		—		11		(2,029)
Contract and emission credit amortization		—		(73)		(14)		—		(87)
Contract and emissions credit amortization													Contract and emissions credit amortization	(9)		(59)		(10)		—		—		(78)
Depreciation and amortization	Depreciation and amortization	(230)		(167)		(65)		(23)		(485)			Depreciation and amortization	(219)		(87)		(70)		$	(410)	(27)		(813)
Gross margin	Gross margin	$	2,302	$	3,060	$	574	$	(25)	$	5,911		Gross margin	$	2,815	$	(601)	$	(318)	$	558	$	(31)	$	2,423
Less: Mark-to-market for economic hedging activities, net	Less: Mark-to-market for economic hedging activities, net	663		2,037		207		—		2,907			Less: Mark-to-market for economic hedging activities, net	421		(1,723)		(631)		—		—		(1,933)
Less: Contract and emission credit amortization, net		—		(103)		(12)		—		(115)
Less: Contract and emissions credit amortization, net													Less: Contract and emissions credit amortization, net	(9)		(83)		(10)		—		—		(102)
Less: Depreciation and amortization	Less: Depreciation and amortization	(230)		(167)		(65)		(23)		(485)			Less: Depreciation and amortization	(219)		(87)		(70)		(410)		(27)		(813)
Economic gross margin	Economic gross margin	$	1,869	$	1,293	$	444	$	(2)	$	3,604		Economic gross margin	$	2,622	$	1,292	$	393	$	968	$	(4)	$	5,271
(a) Includes trading gains and losses and ancillary revenues
(b) Includes capacity and emissions credits
(c) Includes $2.3 billion, $106 million and $848 million of TDSP expense in Texas, East, and West/Services/Other, respectively
(d) Excludes depreciation and amortization shown separately
(a) Includes results of operations following the acquisition date of March 10, 2023													(a) Includes results of operations following the acquisition date of March 10, 2023
(b) Includes trading gains and losses and ancillary revenues													(b) Includes trading gains and losses and ancillary revenues
(c) Includes capacity and emissions credits													(c) Includes capacity and emissions credits
(d) Includes $2.4 billion, $174 million and $806 million of TDSP expense in Texas, East, and West/Services/Other, respectively													(d) Includes $2.4 billion, $174 million and $806 million of TDSP expense in Texas, East, and West/Services/Other, respectively
(e) Excludes depreciation and amortization shown separately													(e) Excludes depreciation and amortization shown separately
Business Metrics	Business Metrics	Texas		East		West/Services/Other		Corporate/Eliminations		Total			Business Metrics	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail sales	Retail sales												Retail sales
Home electricity sales volume (GWh)	Home electricity sales volume (GWh)	34,879		10,298		1,629		—		46,806			Home electricity sales volume (GWh)	32,447		9,667		1,676		—		—		43,790
Business electricity sales volume (GWh)	Business electricity sales volume (GWh)	29,859		37,110		7,753		—		74,722			Business electricity sales volume (GWh)	30,712		35,138		7,564		—		—		73,414
Home natural gas sales volume (MDth)	Home natural gas sales volume (MDth)	—		58,909		58,963		—		117,872			Home natural gas sales volume (MDth)	—		33,549		53,379		—		—		86,928
Business natural gas sales volume (MDth)	Business natural gas sales volume (MDth)	—		1,166,896		110,396		—		1,277,292			Business natural gas sales volume (MDth)	—		1,174,282		133,011		—		—		1,307,293
Average retail Home customer count (in thousands)(a)(b)		3,006		1,785		788		—		5,579
Ending retail Home customer count (in thousands)(a)(b)		2,903		1,788		784		—		5,475
Average retail Home customer count (in thousands)(a)													Average retail Home customer count (in thousands)(a)	2,872		1,834		777		—		—		5,483
Ending retail Home customer count (in thousands)(a)													Ending retail Home customer count (in thousands)(a)	2,871		1,889		765		—		—		5,525
Average Vivint Smart Home subscriber count (in thousands)(b)													Average Vivint Smart Home subscriber count (in thousands)(b)	—		—		—		1,991		—		1,991
Ending Vivint Smart Home subscriber count (in thousands)(b)													Ending Vivint Smart Home subscriber count (in thousands)(b)	—		—		—		2,051		—		2,051
Power generation	Power generation												Power generation
GWh sold	GWh sold	29,976		9,118		5,230		—		44,324			GWh sold	24,612		4,719		4,595		—		—		33,926
GWh generated (c)	GWh generated (c)												GWh generated(c)
Coal	Coal	14,765		5,361		—		—		20,126			Coal	11,230		1,239		—		—		—		12,469
Gas	Gas	7,628		475		5,236		—		13,339			Gas	6,374		685		4,592		—		—		11,651
Nuclear	Nuclear	7,583		—		—		—		7,583			Nuclear	7,008		—		—		—		—		7,008
Oil													Oil	—		4		—		—		—		4
Renewables	Renewables	—		—		7		—		7			Renewables	—		—		3		—		—		3
Oil		—		2		—		—		2
Total	Total	29,976		5,838		5,243		—		41,057			Total	24,612		1,928		4,595		—		—		31,135
(a) Home customer count includes recurring residential customers, services customers and municipal aggregations	(a) Home customer count includes recurring residential customers, services customers and municipal aggregations									(a) Home customer count includes recurring residential customers, services customers and municipal aggregations
(b) The whole home warranty business was sold in January 2022
(b) Vivint Smart Home subscribers includes customers that also purchase other NRG products													(b) Vivint Smart Home subscribers includes customers that also purchase other NRG products
(c) Includes owned and leased generation, excludes tolled generation and equity investments	(c) Includes owned and leased generation, excludes tolled generation and equity investments									(c) Includes owned and leased generation, excludes tolled generation and equity investments

5768


		Nine months ended September 30, 2021										Nine months ended September 30, 2022
($ In millions)	($ In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total			($ In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Retail revenue	Retail revenue	$	6,575	$	8,029	$	2,326	$	(1)	$	16,929		Retail revenue	$	7,510	$	11,784	$	3,086	$	(1)	$	22,379
Energy revenue	Energy revenue	317		428		238		6		989			Energy revenue	101		544		365		24		1,034
Capacity revenue	Capacity revenue	—		568		47		—		615			Capacity revenue	—		242		2		—		244
Mark-to-market for economic hedging activities	Mark-to-market for economic hedging activities	(5)		(53)		(60)		19		(99)			Mark-to-market for economic hedging activities	1		(204)		(63)		18		(248)
Contract amortization	Contract amortization	—		(15)		(4)		—		(19)			Contract amortization	—		(30)		2		—		(28)
Other revenue(a)	Other revenue(a)	1,475		45		17		(9)		1,528			Other revenue(a)	245		71		3		(12)		307
Total revenue	Total revenue	8,362		9,002		2,564		15		19,943			Total revenue	7,857		12,407		3,395		29		23,688
Cost of fuel	Cost of fuel	(1,243)		(155)		(132)		—		(1,530)			Cost of fuel	(1,018)		(315)		(270)		—		(1,603)
Purchased energy and other cost of sales(b)(c)(d)	Purchased energy and other cost of sales(b)(c)(d)	(5,548)		(7,206)		(2,019)		(1)		(14,774)			Purchased energy and other cost of sales(b)(c)(d)	(4,979)		(11,040)		(2,725)		(13)		(18,757)
Mark-to-market for economic hedging activities	Mark-to-market for economic hedging activities	1,072		2,849		220		(19)		4,122			Mark-to-market for economic hedging activities	662		2,241		270		(18)		3,155
Contract and emission credit amortization		—		(8)		(11)		—		(19)
Contract and emissions credit amortization													Contract and emissions credit amortization	—		(73)		(14)		—		(87)
Depreciation and amortization	Depreciation and amortization	(245)		(237)		(66)		(21)		(569)			Depreciation and amortization	(233)		(164)		(65)		(23)		(485)
Gross margin	Gross margin	$	2,398	$	4,245	$	556	$	(26)	$	7,173		Gross margin	$	2,289	$	3,056	$	591	$	(25)	$	5,911
Less: Mark-to-market for economic hedging activities, net	Less: Mark-to-market for economic hedging activities, net	1,067		2,796		160		—		4,023			Less: Mark-to-market for economic hedging activities, net	663		2,037		207		—		2,907
Less: Contract and emission credit amortization, net		—		(23)		(15)		—		(38)
Less: Contract and emissions credit amortization, net													Less: Contract and emissions credit amortization, net	—		(103)		(12)		—		(115)
Less: Depreciation and amortization	Less: Depreciation and amortization	(245)		(237)		(66)		(21)		(569)			Less: Depreciation and amortization	(233)		(164)		(65)		(23)		(485)
Economic gross margin	Economic gross margin	$	1,576	$	1,709	$	477	$	(5)	$	3,757		Economic gross margin	$	1,859	$	1,286	$	461	$	(2)	$	3,604
(a) Includes trading gains and losses and ancillary revenues	(a) Includes trading gains and losses and ancillary revenues												(a) Includes trading gains and losses and ancillary revenues
(b) Includes capacity and emissions credits	(b) Includes capacity and emissions credits												(b) Includes capacity and emissions credits
(c) Includes $2.0 billion, $138 million and $731 million of TDSP expense in Texas, East and West/Services/Other, respectively
(c) Includes $2.3 billion, $106 million and $848 million of TDSP expense in Texas, East and West/Services/Other, respectively													(c) Includes $2.3 billion, $106 million and $848 million of TDSP expense in Texas, East and West/Services/Other, respectively
(d) Excludes depreciation and amortization shown separately	(d) Excludes depreciation and amortization shown separately												(d) Excludes depreciation and amortization shown separately
Business Metrics	Business Metrics	Texas		East		West/Services/Other		Corporate/Eliminations		Total			Business Metrics	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Retail sales	Retail sales												Retail sales
Home electricity sales volume (GWh)	Home electricity sales volume (GWh)	34,304		11,137		1,649		—		47,090			Home electricity sales volume (GWh)	34,879		10,298		1,629		—		46,806
Business electricity sales volume (GWh)	Business electricity sales volume (GWh)	25,180		40,373		7,321		—		72,874			Business electricity sales volume (GWh)	29,859		37,110		7,753		—		74,722
Home natural gas sales volume (MDth)	Home natural gas sales volume (MDth)	—		53,077		62,200		—		115,277			Home natural gas sales volume (MDth)	—		35,423		58,963		—		94,386
Business natural gas sales volume (MDth)	Business natural gas sales volume (MDth)	—		1,141,892		79,712		—		1,221,604			Business natural gas sales volume (MDth)	—		1,190,382		110,396		—		1,300,778
Average retail Home customer count (in thousands)(a))b)		3,059		1,871		968		—		5,898
Average retail Home customer count (in thousands)(a)													Average retail Home customer count (in thousands)(a)	2,992		1,785		802		—		5,579
Ending retail Home customer count (in thousands)~~(b)~~(a)	Ending retail Home customer count (in thousands)~~(b)~~(a)	3,043		1,784		954		—		5,781			Ending retail Home customer count (in thousands)~~(b)~~(a)	2,890		1,788		797		—		5,475
Power generation	Power generation												Power generation
GWh sold	GWh sold	29,020		10,000		5,954		—		44,974			GWh sold	29,976		9,118		5,230		—		44,324
GWh generated ~~(c)~~(b)	GWh generated ~~(c)~~(b)												GWh generated ~~(c)~~(b)
Coal	Coal	14,188		4,887		—		—		19,075			Coal	14,765		5,361		—		—		20,126
Gas~~(d)~~	Gas~~(d)~~	7,789		1,324		5,606		—		14,719			Gas~~(d)~~	7,628		475		5,236		—		13,339
Nuclear	Nuclear	7,043		—		—		—		7,043			Nuclear	7,583		—		—		—		7,583
Oil~~(e)~~	Oil~~(e)~~	—		189		—		—		189			Oil~~(e)~~	—		2		—		—		2

Renewables													Renewables	—		—		7		—		7
Total	Total	29,020		6,400		5,606		—		41,026			Total	29,976		5,838		5,243		—		41,057
(a) Home customer count includes recurring residential customers, services customers and municipal aggregations	(a) Home customer count includes recurring residential customers, services customers and municipal aggregations												(a) Home customer count includes recurring residential customers, services customers and municipal aggregations
(b) Includes 143 thousand whole home warranty customers in West/Services/Other. The whole home warranty business was sold in January 2022
(c) Includes owned and leased generation, excludes tolled generation and equity investments
(d) Includes 794 GWh and 1,867 GWh in East and West/Services/Other, respectively, that was sold to Generation Bridge in December 2021
(e) Includes 183 GWh in East that was sold to Generation Bridge in December 2021
(b) Includes owned and leased generation, excludes tolled generation and equity investments													(b) Includes owned and leased generation, excludes tolled generation and equity investments

5869

The following table ~~below~~ represents the weather metrics for the nine months ended September 30, ~~2022~~2023 and ~~2021:~~2022:


		Nine months ended September 30,			Nine months ended September 30,
Weather Metrics	Weather Metrics	Texas	East	West/Services/Other (b)		Weather Metrics	Texas	East	West/Services/Other(b)
2022
2023						2023
CDDs (a)	CDDs (a)	3,141	1,267	1,974		CDDs(a)	3,183	1,144	1,866
HDDs (a)	HDDs (a)	1,202	2,944	1,347		HDDs(a)	856	2,619	1,417
2021
2022						2022
CDDs	CDDs	2,574	1,184	1,693		CDDs	3,141	1,267	1,974
HDDs	HDDs	1,202	2,929	1,398		HDDs	1,202	2,944	1,347
10-year average	10-year average					10-year average
CDDs	CDDs	2,741	1,214	1,758		CDDs	2,761	1,220	1,776
HDDs	HDDs	1,007	2,922	1,256		HDDs	1,050	3,124	1,290

(b) The West/Services/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~~Income Tax Expense

~~Gross margin decreased $1.3 billion and economic gross margin decreased $153 million, both of which include intercompany sales, during~~For the ~~nine~~three months ended September 30, ~~2022, compared to~~2023, income tax expense of $65 million was recorded on pre-tax income of $408 million. For the same period in ~~2021.~~2022, income tax expense of $16 million was recorded on pre-tax income of $83 million. The effective tax rates were 15.9% and 19.3% for the three months ended September 30, 2023 and 2022, respectively.

~~The tables below describe~~

For the ~~changes~~three months ended September 30, 2023, the effective tax rate was lower than the statutory rate of 21% primarily due to a decrease in ~~gross margin~~state tax expense resulting from a decrease in year-to-date financial statement losses. For the same period in 2022, the effective tax rate was lower than the statutory rate of 21% primarily due to the benefit resulting from carbon capture tax credits and ~~economic gross margin by segment:~~

~~Texas~~


	~~(In millions)~~
~~Higher gross margin due to Winter Storm Uri, primarily driven by a decrease in unhedgeable ancillary and operating reserve demand curve(a)~~	$	~~560~~
~~The following explanations exclude the impact of Winter Storm Uri:~~
~~Lower gross margin due to the net effect of:~~ •a 47%, or $952 million increase in overall average costs to serve the retail load, driven by increases in power, ancillary, and fuel costs, extended outages at W.A. Parish Unit 8 and Limestone Unit 1, and the more conservative winter hedge profile in the first quarter of 2022, partially offset by the favorable impact of the early settlement of a solar PPA; and •increased net revenue rates of $9.50 per MWh, or $514 million, and higher gross margin attributable to increased load of 1.4 million MWhs, or $52 million, both primarily driven by changes in customer mix	~~(386)~~
~~Higher power gross margin due to an increase in load of 4.6 million MWhs from weather~~	~~157~~
~~Lower gross margin from market optimization activities~~	~~(42)~~


~~Other~~	4
~~Increase in economic gross margin~~	$	~~293~~
~~Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges~~	~~(404)~~

~~Decrease in depreciation and amortization~~	15
~~Decrease in gross margin~~	$	~~(96)~~

~~(a)For further discussion of ERCOT's securitization activity see~~ ~~RegionalRegulatory Developments~~ ~~section under Energy Regulatory Mattersaboveand Note 2,~~ ~~Summary of Significant Accounting Policies~~the reduction in statutory state tax rates.

~~East~~


	~~(In millions)~~
~~Lower gross margin due to the impact of Winter Storm Uri in 2021, primarily driven by natural gas optimization during volatile pricing that occurred during the weather event~~	$	~~(146)~~
~~The following explanations exclude the impact of Winter Storm Uri:~~
~~Lower gross margin due to the sale of fossil generating assets to Generation Bridge in December 2021~~	~~(178)~~
~~Lower gross margin due to a decrease in generation and capacity as a result of Midwest Generation asset retirements in the second quarter of 2022~~	~~(55)~~
Lower retail electric gross margin due to higher supply costs of $16.75 per MWh, driven primarily by increases in power prices, totaling $796 million, partially offset by higher net revenue rates as a result of changes in customer term, product and mix of $14.75 per MWh, or $704 million	~~(92)~~
~~Lower demand response gross margin primarily due to a decrease in early settlements of capacity~~	~~(86)~~
~~Lower electric gross margin from decreased load of 4.7 TWh due to attrition and change in customer mix~~	~~(43)~~
~~Lower gross margin due to a decrease of capacity prices of 23% in PJM and 44% in New York~~	~~(36)~~
Higher gross margin primarily at Midwest Generation due to a 51% increase in average realized pricing and an increase in generation volumes due to dark spread expansion, partially offset by increased supply costs	29
Higher natural gas gross margin including the impact of transportation and storage contract optimization, resulting in higher net revenue rates from changes in customer term, product and mix of $3.01 per Dth, or $3.7 billion, partially offset by higher supply costs of $2.86 per Dth or $3.5 billion	~~177~~

~~Higher gross margin from the sales of NOx emission credits~~	14




~~Decrease in economic gross margin~~	$	~~(416)~~
~~Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges~~	~~(759)~~
~~Increase in contract amortization~~	~~(80)~~
~~Decrease in depreciation and amortization~~	70
~~Decrease in gross margin~~	$	~~(1,185)~~

~~West/Services/Other~~


	~~(In millions)~~
~~Lower gross margin due to the impact of Winter Storm Uri in 2021, primarily driven by natural gas optimization during volatile pricing that occurred during the weather event~~	$	~~(13)~~
~~The following explanations exclude the impact of Winter Storm Uri:~~
~~Lower gross margin due to the sale of fossil generating assets to Generation Bridge in December 2021~~	~~(62)~~
~~Lower gross margin due to the sale of the whole home warranty business in the first quarter of 2022~~	~~(29)~~
~~Higher gross margin primarily due to increased revenue at Airtron~~	31
~~Higher gross margin at Cottonwood due to a 114% increase in average realized power prices, partially offset by increased commodity costs~~	39
Higher electric gross margin due to an increase in net revenue rates as a result of changes in customer term, product and mix of $22.13 per MWh, or $207 million, an increase in customer mix of $4 million, partially offset by higher supply costs of $19.71 per MWh, or $185 million	26
Lower natural gas gross margin due to higher supply costs of $2.08 per Dth, or $352 million, partially offset by higher net revenue rates of $1.74 per Dth, or $294 million, and an increase in load due to customer mix of $31 million	~~(27)~~


~~Other~~	2
~~Decrease in economic gross margin~~	$	~~(33)~~
~~Increase in mark-to-market for economic hedges primarily due to net unrealized gains/losses on open positions related to economic hedges~~	47
~~Decrease in contract amortization~~	3
~~Decrease in depreciation and amortization~~	1
~~Increase in gross margin~~	$	18

6066

~~Mark-to-Market for Economic Hedging Activities~~

Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges. Total net mark-to-market results decreased by $1.1 billion during the nine months ended September 30, 2022, compared to the same period in 2021.

~~The breakdown of gains and losses included in revenues and operating costs and expenses by segment was as follows:~~
Nine months ended September 30, 2022
(In millions) Texas East West/Services/Other Eliminations Total
Mark-to-market results in revenue
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges $ 2 $ (9) $ 38 $ (6) $ 25
Reversal of acquired (gain) positions related to economic hedges — (1) — — (1)
Net unrealized (losses) on open positions related to economic hedges (1) (194) (101) 24 (272)
Total mark-to-market gains/(losses) in revenue $ 1 $ (204) $ (63) $ 18 $ (248)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges $ (336) $ (547) $ (140) $ 6 $ (1,017)
Reversal of acquired loss/(gain) positions related to economic hedges 15 (25) (16) — (26)
Net unrealized gains on open positions related to economic hedges 983 2,813 426 (24) 4,198
Total mark-to-market gains in operating costs and expenses $ 662 $ 2,241 $ 270 $ (18) $ 3,155

Nine months ended September 30, 2021
(In millions) Texas East West/Services/Other Eliminations Total
Mark-to-market results in revenue
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges $ — $ (20) $ (2) $ (2) $ (24)
Reversal of acquired (gain) positions related to economic hedges — (6) — — (6)
Net unrealized (losses) on open positions related to economic hedges (5) (27) (58) 21 (69)
Total mark-to-market (losses) in revenue $ (5) $ (53) $ (60) $ 19 $ (99)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges $ (36) $ — $ — $ 2 $ (34)
Reversal of acquired loss/(gain) positions related to economic hedges 20 202 (10) — 212
Net unrealized gains on open positions related to economic hedges 1,088 2,647 230 (21) 3,944
Total mark-to-market gains in operating costs and expenses $ 1,072 $ 2,849 $ 220 $ (19) $ 4,122

For the nine months ended September 30, 2022, the $248 million loss in revenues from economic hedge positions was driven by a decrease in the value of open positions as a result of increases in power prices across all segments, partially offset by the reversal of previously recognized unrealized losses on contracts that settled during the period. The $3.2 billion 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 natural gas and power prices across all segments, partially offset by the reversal of previously recognized unrealized gains on contracts that settled during the period.

For the nine months ended September 30, 2021, the $99 million loss in revenues from economic hedge positions was driven by a decrease in the value of open positions as a result of increases in Northeast and West/Other power prices as well as the reversal of previously recognized unrealized gains on contracts that settled during the period. The $4.1 billion 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 natural gas and power prices across all segments as well as the reversal of acquired contracts that settled during the period.

~~In accordance with ASC 815, the following table represents~~Management’s discussion of the results of ~~the Company's financial and physical trading of energy commodities~~operations for the nine months ended September 30, ~~2022~~2023 and ~~2021.~~ 2022

Electricity Prices

The ~~realized and unrealized financial and physical trading results are included in revenue. The Company's trading activities are subject to limits based~~following table summarizes average on ~~the Company's Risk Management Policy.~~

Nine months ended September 30,
(In millions) 2022 2021
Trading gains/(losses)
Realized $ 3 $ 99
Unrealized (7) 2
Total trading (losses)/gains $ (4) $ 101

~~Operations and Maintenance Expense~~

~~Operations and maintenance expense are comprised~~peak power prices for each of the ~~following:~~

(In millions) Texas East West/Services/Other Corporate Eliminations Total
Nine months ended September 30, 2022 $ 598 $ 306 $ 147 $ — $ (2) $ 1,049
Nine months ended September 30, 2021 524 346 168 2 (4) 1,036

~~Operations and maintenance expense increased by $13 million~~major markets in which NRG operates for the nine months ended September 30, ~~2022, compared to the same period in 2021, due to the following:~~


	~~(In millions)~~
~~Decrease due to the sale of fossil generating assets to Generation Bridge in December 2021~~	$	~~(72)~~
~~Decrease due to Midwest Generation asset retirements in the second quarter of 2022 as well as spare parts inventory reserves in 2021~~	~~(18)~~
~~Increase in variable operation and maintenance expense at the PJM coal facilities associated with increased generation during 2022~~	30
~~Increase driven by W.A. Parish restoration efforts associated with the May 2022 extended outage~~	26
~~Increase in estimates of environmental remediation costs at deactivated sites in the East and West~~	26
~~Increase driven by higher retail operations costs~~	15
~~Increase due to scope of outages at the Texas coal and gas facilities in 2022 partially offset by a prior year planned outage at STP~~	14
~~Decrease driven by current year scrap proceeds associated with the demolition of the Encina site~~	~~(8)~~
~~Decrease driven by higher maintenance in 2021 resulting from the impacts of Winter Storm Uri~~	~~(2)~~
~~Other~~	2
~~Increase in operations and maintenance expense~~	$	13

~~Other Cost of Operations~~

~~Other Cost of operations are comprised of the following:~~
(In millions) Texas East West/Services/Other Total
Nine months ended September 30, 2022 $ 153 $ 113 $ 12 $ 278
Nine months ended September 30, 2021 144 102 13 259

~~Other cost of operations increased by $19 million~~2023 and 2022. Texas - Houston, East and West average on-peak power prices decreased for the nine months ended September 30, ~~2022,~~2023 as compared to the same period in ~~2021, due to~~2022 as a result of lower natural gas prices.


	Average on Peak Power Price ($/MWh)
	Nine months ended September 30,
Region	2023		2022		Change %
Texas
ERCOT - Houston (a)	$	89.00	$	101.20	(12)	%
ERCOT - North(a)	87.49		85.68		2	%

East
NY J/NYC(b)	$	39.43	$	98.34	(60)	%
NEPOOL(b)	41.87		96.30		(57)	%
COMED (PJM)(b)	33.05		76.82		(57)	%
PJM West Hub(b)	38.39		87.44		(56)	%

West
MISO - Louisiana Hub(b)	$	34.54	$	75.26	(54)	%
CAISO - SP15(b)	63.38		71.86		(12)	%

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


	~~(In millions)~~
~~Decrease due to the sale of fossil generating assets to Generation Bridge in December 2021~~	$	~~(24)~~
~~Increase in retail gross receipt taxes due to higher revenues~~	32
~~Increase due to higher property insurance premiums~~	9
~~Increase due to changes in current year ARO cost estimates and the timing of ARO spend~~	3
~~Other~~	~~(1)~~
~~Increase in other cost of operations~~	$	19

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

~~Depreciation and Amortization~~Natural Gas Prices

~~Depreciation and amortization expenses are comprised of~~The following table summarizes the ~~following:~~

(In millions) Texas East West/Services/Other Corporate Total
Nine months ended September 30, 2022 $ 230 $ 167 $ 65 $ 23 $ 485
Nine months ended September 30, 2021 245 237 66 21 569

~~Depreciation and amortization decreased by $84 million~~average Henry Hub natural gas price for the nine months ended September 30, ~~2022, compared~~2023 and 2022:


	Nine months ended September 30,
	2023		2022		Change %
($/MMBtu)	$	2.69	$	6.77	(60)	%

Gross Margin

The Company calculates gross margin in order to evaluate operating performance as revenues less cost of fuel, purchased energy and other costs of sales, mark-to-market for economic hedging activities, contract and emissions credit amortization and depreciation and amortization.

Economic Gross Margin

In addition to gross margin, the ~~same period~~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 ~~2021, primarily due to lower depreciation~~this report. Economic gross margin should be viewed as a ~~result of asset impairments, sales,~~supplement to and ~~retirements as well as lower amortization as~~not a ~~result of the expected roll off of acquired intangibles.~~

~~Impairment Losses~~

Impairment losses of $198 million were recorded during the nine months ended September 30, 2022 include $155 million primarily related to the decline in PJM capacity prices and the near-term retirement date of Joliet and $43 million primarily related to the purchase and sale agreementsubstitute for the ~~sale~~Company's presentation of gross margin, which is the ~~land~~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 ~~related assets at the Astoria generating site~~other revenue, less cost of fuel, purchased energy and ~~the planned withdrawal~~other cost of sales. Economic gross margin does not include mark-to-market gains or losses on economic hedging activities, contract and ~~cancellation~~emissions credit amortization, depreciation and amortization, operations and maintenance, or other cost of its proposed Astoria redevelopment project. Impairment losses of $306 million were recorded during the nine months ended September 30, 2021 related to the decline in capacity prices and the planned retirement of a significant portion of the PJM coal fleet. Refer to Note 8, ~~Impairments~~ ~~for further discussion.~~operations.

6367

~~Selling, General~~The following tables present the composition and ~~Administrative Costs~~

~~Selling, general~~reconciliation of gross margin and ~~administrative costs comprised of the following:~~

(In millions) Texas East West/Services/Other Corporate Eliminations Total
Nine months ended September 30, 2022 $ 449 $ 328 $ 162 $ 34 $ — $ 973
Nine months ended September 30, 2021 435 371 131 37 (1) 973

Total selling, general and administrative costs in the nine months ended September 30, 2022 were flat, when compared to the same period in 2021, with fluctuations within selling, general and administrative costs shown below:


	~~(In millions)~~
~~Decrease due to Winter Storm Uri, including charitable giving, legal and other costs of $17 million and ERCOT default charges of $12 million in 2021~~	$	~~(29)~~
~~Decrease in transition service agreement costs related to the Direct Energy acquisition~~	~~(16)~~
~~Increase due to the favorable resolution of a legal matter in 2021~~	15
~~Increase in broker fee expenses, partially offset by lower commissions expenses~~	14
~~Increase due to higher legal and consulting expenses including spending related to Company's growth initiatives~~	11
~~Other~~	5
~~Change in selling, general and administrative costs~~	$	—

~~Provision for Credit Losses~~

~~Provision for credit losses are comprised of the following:~~

(In millions) Texas East West/Services/Other Total
Nine months ended September 30, 2022 $ 53 $ 32 $ 18 $ 103
Nine months ended September 30, 2021 700 7 8 715

~~Provision for credit losses decreased by $612 million~~economic gross margin for the nine months ended September 30, ~~2022, compared to~~2023 and 2022:


	Nine months ended September 30, 2023
($ In millions)	Texas		East		West/Services/Other		Vivint Smart Home(a)		Corporate/Eliminations		Total
Retail revenue	$	7,842	$	9,007	$	2,993	$	1,070	$	(1)	$	20,911
Energy revenue	71		254		147		—		—		472
Capacity revenue	—		154		(3)		—		(1)		150
Mark-to-market for economic hedging activities	—		27		80		—		(11)		96
Contract amortization	—		(24)		—		—		—		(24)
Other revenue(b)	322		70		27		—		(8)		411
Total revenue	8,235		9,488		3,244		1,070		(21)		22,016
Cost of fuel	(596)		(102)		(92)		—		—		(790)
Purchased energy and other cost of sales(c)(d)(e)	(5,017)		(8,091)		(2,679)		(102)		6		(15,883)
Mark-to-market for economic hedging activities	421		(1,750)		(711)		—		11		(2,029)
Contract and emissions credit amortization	(9)		(59)		(10)		—		—		(78)
Depreciation and amortization	(219)		(87)		(70)		$	(410)	(27)		(813)
Gross margin	$	2,815	$	(601)	$	(318)	$	558	$	(31)	$	2,423
Less: Mark-to-market for economic hedging activities, net	421		(1,723)		(631)		—		—		(1,933)
Less: Contract and emissions credit amortization, net	(9)		(83)		(10)		—		—		(102)
Less: Depreciation and amortization	(219)		(87)		(70)		(410)		(27)		(813)
Economic gross margin	$	2,622	$	1,292	$	393	$	968	$	(4)	$	5,271
(a) Includes results of operations following the acquisition date of March 10, 2023
(b) Includes trading gains and losses and ancillary revenues
(c) Includes capacity and emissions credits
(d) Includes $2.4 billion, $174 million and $806 million of TDSP expense in Texas, East, and West/Services/Other, respectively
(e) Excludes depreciation and amortization shown separately
Business Metrics	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail sales
Home electricity sales volume (GWh)	32,447		9,667		1,676		—		—		43,790
Business electricity sales volume (GWh)	30,712		35,138		7,564		—		—		73,414
Home natural gas sales volume (MDth)	—		33,549		53,379		—		—		86,928
Business natural gas sales volume (MDth)	—		1,174,282		133,011		—		—		1,307,293
Average retail Home customer count (in thousands)(a)	2,872		1,834		777		—		—		5,483
Ending retail Home customer count (in thousands)(a)	2,871		1,889		765		—		—		5,525
Average Vivint Smart Home subscriber count (in thousands)(b)	—		—		—		1,991		—		1,991
Ending Vivint Smart Home subscriber count (in thousands)(b)	—		—		—		2,051		—		2,051
Power generation
GWh sold	24,612		4,719		4,595		—		—		33,926
GWh generated(c)
Coal	11,230		1,239		—		—		—		12,469
Gas	6,374		685		4,592		—		—		11,651
Nuclear	7,008		—		—		—		—		7,008
Oil	—		4		—		—		—		4
Renewables	—		—		3		—		—		3
Total	24,612		1,928		4,595		—		—		31,135
(a) Home customer count includes recurring residential customers, services customers and municipal aggregations
(b) Vivint Smart Home subscribers includes customers that also purchase other NRG products
(c) Includes owned and leased generation, excludes tolled generation and equity investments


	Nine months ended September 30, 2022
($ In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Retail revenue	$	7,510	$	11,784	$	3,086	$	(1)	$	22,379
Energy revenue	101		544		365		24		1,034
Capacity revenue	—		242		2		—		244
Mark-to-market for economic hedging activities	1		(204)		(63)		18		(248)
Contract amortization	—		(30)		2		—		(28)
Other revenue(a)	245		71		3		(12)		307
Total revenue	7,857		12,407		3,395		29		23,688
Cost of fuel	(1,018)		(315)		(270)		—		(1,603)
Purchased energy and other cost of sales(b)(c)(d)	(4,979)		(11,040)		(2,725)		(13)		(18,757)
Mark-to-market for economic hedging activities	662		2,241		270		(18)		3,155
Contract and emissions credit amortization	—		(73)		(14)		—		(87)
Depreciation and amortization	(233)		(164)		(65)		(23)		(485)
Gross margin	$	2,289	$	3,056	$	591	$	(25)	$	5,911
Less: Mark-to-market for economic hedging activities, net	663		2,037		207		—		2,907
Less: Contract and emissions credit amortization, net	—		(103)		(12)		—		(115)
Less: Depreciation and amortization	(233)		(164)		(65)		(23)		(485)
Economic gross margin	$	1,859	$	1,286	$	461	$	(2)	$	3,604
(a) Includes trading gains and losses and ancillary revenues
(b) Includes capacity and emissions credits
(c) Includes $2.3 billion, $106 million and $848 million of TDSP expense in Texas, East and West/Services/Other, respectively
(d) Excludes depreciation and amortization shown separately
Business Metrics	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Retail sales
Home electricity sales volume (GWh)	34,879		10,298		1,629		—		46,806
Business electricity sales volume (GWh)	29,859		37,110		7,753		—		74,722
Home natural gas sales volume (MDth)	—		35,423		58,963		—		94,386
Business natural gas sales volume (MDth)	—		1,190,382		110,396		—		1,300,778
Average retail Home customer count (in thousands)(a)	2,992		1,785		802		—		5,579
Ending retail Home customer count (in thousands)(a)	2,890		1,788		797		—		5,475
Power generation
GWh sold	29,976		9,118		5,230		—		44,324
GWh generated(b)
Coal	14,765		5,361		—		—		20,126
Gas	7,628		475		5,236		—		13,339
Nuclear	7,583		—		—		—		7,583
Oil	—		2		—		—		2
Renewables	—		—		7		—		7
Total	29,976		5,838		5,243		—		41,057
(a) Home customer count includes recurring residential customers, services customers and municipal aggregations
(b) Includes owned and leased generation, excludes tolled generation and equity investments

The following table represents the ~~same period in 2021, due to the following:~~


	~~(In millions)~~
~~Decrease due to Winter Storm Uri, including:~~ ~~Decrease of $403 million related to bilateral financial hedging risk~~ ~~Decrease of $152 million related to counterparty credit risk~~ ~~Decrease of $83 million related to ERCOT default shortfall payments~~	$	~~(638)~~
~~Increase due to higher revenues and deteriorated customer payment behavior~~	26


~~Decrease in provision for credit losses~~	$	~~(612)~~

~~Acquisition-Related Transaction and Integration Costs~~

~~Acquisition-related transaction and integration costs were $26 million~~weather metrics for the nine months ended September 30, ~~2022, which were primarily integration costs related to Direct Energy. Acquisition-related transaction~~2023 and ~~integration costs~~2022:


	Nine months ended September 30,
Weather Metrics	Texas	East	West/Services/Other(b)
2023
CDDs(a)	3,183	1,144	1,866
HDDs(a)	856	2,619	1,417
2022
CDDs	3,141	1,267	1,974
HDDs	1,202	2,944	1,347
10-year average
CDDs	2,761	1,220	1,776
HDDs	1,050	3,124	1,290

(a) National Oceanic and Atmospheric Administration-Climate Prediction Center - A Cooling Degree Day, or CDD, represents the number of ~~$81 million were incurred~~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 ~~nine months ended September 30, 2021, related to Direct Energy,~~period

(b) The West/Services/Other weather metrics are comprised of ~~which $24 million were acquisition-related transaction costs~~the average of the CDD and ~~$57 million were integration costs, primarily related to severance and consulting services.~~

~~Gain on Sale of Assets~~

~~The gain on sale of assets of $51 million~~HDD regional results for the ~~nine months ended September 30, 2022 includes a $46 million gain related to the sale of the Company's 49% ownership in the Watson natural gas generating facility~~West-California and a $22 million due to the sale of the Company's 50% ownership interest in Petra Nova, partially offset by a loss of $14 million on other asset sales and a $3 million adjustment to the proceeds on the sale of fossil generating assets to Generation Bridge in December of 2021. The gain on sale of assets of $17 million for the nine months ended September 30, 2021 was related to the sale of Agua Caliente in February 2021.West-South Central regions

~~Loss on debt extinguishment, net~~

~~Loss on debt extinguishment of $57 million was recorded for the~~ ~~nine months ended September 30, 2021 in connection with the redemption of the 2026 Senior Notes and the partial redemption of the 2027 Senior Notes in the third quarter of 2021.~~

~~Interest Expense~~

Interest expense decreased by $61 million for the nine months ended September 30, 2022, compared to the same period in 2021, primarily due to debt reduction and the refinancing of debt to lower interest rates in the second half of 2021.

Income Tax Expense

Management’s discussion of the results of operations for the nine months ended September 30, 2023 and 2022

Electricity Prices


	Average on Peak Power Price ($/MWh)
	Nine months ended September 30,
Region	2023		2022		Change %
Texas
ERCOT - Houston (a)	$	89.00	$	101.20	(12)	%
ERCOT - North(a)	87.49		85.68		2	%

East
NY J/NYC(b)	$	39.43	$	98.34	(60)	%
NEPOOL(b)	41.87		96.30		(57)	%
COMED (PJM)(b)	33.05		76.82		(57)	%
PJM West Hub(b)	38.39		87.44		(56)	%

West
MISO - Louisiana Hub(b)	$	34.54	$	75.26	(54)	%
CAISO - SP15(b)	63.38		71.86		(12)	%

(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

Natural Gas Prices

The following table summarizes the average Henry Hub natural gas price for the nine months ended September 30, 2023 and 2022:


	Nine months ended September 30,
	2023		2022		Change %
($/MMBtu)	$	2.69	$	6.77	(60)	%

Gross Margin

The Company calculates gross margin in order to evaluate operating performance as revenues less cost of fuel, purchased energy and other costs of sales, mark-to-market for economic hedging activities, contract and emissions credit amortization and depreciation and amortization.

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 fuel, purchased energy and other cost of sales. Economic gross margin does not include mark-to-market gains or losses on economic hedging activities, contract and emissions credit amortization, depreciation and amortization, operations and maintenance, or other cost of operations.

The following tables present the composition and reconciliation of gross margin and economic gross margin for the nine months ended September 30, 2023 and 2022:


	Nine months ended September 30, 2023
($ In millions)	Texas		East		West/Services/Other		Vivint Smart Home(a)		Corporate/Eliminations		Total
Retail revenue	$	7,842	$	9,007	$	2,993	$	1,070	$	(1)	$	20,911
Energy revenue	71		254		147		—		—		472
Capacity revenue	—		154		(3)		—		(1)		150
Mark-to-market for economic hedging activities	—		27		80		—		(11)		96
Contract amortization	—		(24)		—		—		—		(24)
Other revenue(b)	322		70		27		—		(8)		411
Total revenue	8,235		9,488		3,244		1,070		(21)		22,016
Cost of fuel	(596)		(102)		(92)		—		—		(790)
Purchased energy and other cost of sales(c)(d)(e)	(5,017)		(8,091)		(2,679)		(102)		6		(15,883)
Mark-to-market for economic hedging activities	421		(1,750)		(711)		—		11		(2,029)
Contract and emissions credit amortization	(9)		(59)		(10)		—		—		(78)
Depreciation and amortization	(219)		(87)		(70)		$	(410)	(27)		(813)
Gross margin	$	2,815	$	(601)	$	(318)	$	558	$	(31)	$	2,423
Less: Mark-to-market for economic hedging activities, net	421		(1,723)		(631)		—		—		(1,933)
Less: Contract and emissions credit amortization, net	(9)		(83)		(10)		—		—		(102)
Less: Depreciation and amortization	(219)		(87)		(70)		(410)		(27)		(813)
Economic gross margin	$	2,622	$	1,292	$	393	$	968	$	(4)	$	5,271
(a) Includes results of operations following the acquisition date of March 10, 2023
(b) Includes trading gains and losses and ancillary revenues
(c) Includes capacity and emissions credits
(d) Includes $2.4 billion, $174 million and $806 million of TDSP expense in Texas, East, and West/Services/Other, respectively
(e) Excludes depreciation and amortization shown separately
Business Metrics	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail sales
Home electricity sales volume (GWh)	32,447		9,667		1,676		—		—		43,790
Business electricity sales volume (GWh)	30,712		35,138		7,564		—		—		73,414
Home natural gas sales volume (MDth)	—		33,549		53,379		—		—		86,928
Business natural gas sales volume (MDth)	—		1,174,282		133,011		—		—		1,307,293
Average retail Home customer count (in thousands)(a)	2,872		1,834		777		—		—		5,483
Ending retail Home customer count (in thousands)(a)	2,871		1,889		765		—		—		5,525
Average Vivint Smart Home subscriber count (in thousands)(b)	—		—		—		1,991		—		1,991
Ending Vivint Smart Home subscriber count (in thousands)(b)	—		—		—		2,051		—		2,051
Power generation
GWh sold	24,612		4,719		4,595		—		—		33,926
GWh generated(c)
Coal	11,230		1,239		—		—		—		12,469
Gas	6,374		685		4,592		—		—		11,651
Nuclear	7,008		—		—		—		—		7,008
Oil	—		4		—		—		—		4
Renewables	—		—		3		—		—		3
Total	24,612		1,928		4,595		—		—		31,135
(a) Home customer count includes recurring residential customers, services customers and municipal aggregations
(b) Vivint Smart Home subscribers includes customers that also purchase other NRG products
(c) Includes owned and leased generation, excludes tolled generation and equity investments


	Nine months ended September 30, 2022
($ In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Retail revenue	$	7,510	$	11,784	$	3,086	$	(1)	$	22,379
Energy revenue	101		544		365		24		1,034
Capacity revenue	—		242		2		—		244
Mark-to-market for economic hedging activities	1		(204)		(63)		18		(248)
Contract amortization	—		(30)		2		—		(28)
Other revenue(a)	245		71		3		(12)		307
Total revenue	7,857		12,407		3,395		29		23,688
Cost of fuel	(1,018)		(315)		(270)		—		(1,603)
Purchased energy and other cost of sales(b)(c)(d)	(4,979)		(11,040)		(2,725)		(13)		(18,757)
Mark-to-market for economic hedging activities	662		2,241		270		(18)		3,155
Contract and emissions credit amortization	—		(73)		(14)		—		(87)
Depreciation and amortization	(233)		(164)		(65)		(23)		(485)
Gross margin	$	2,289	$	3,056	$	591	$	(25)	$	5,911
Less: Mark-to-market for economic hedging activities, net	663		2,037		207		—		2,907
Less: Contract and emissions credit amortization, net	—		(103)		(12)		—		(115)
Less: Depreciation and amortization	(233)		(164)		(65)		(23)		(485)
Economic gross margin	$	1,859	$	1,286	$	461	$	(2)	$	3,604
(a) Includes trading gains and losses and ancillary revenues
(b) Includes capacity and emissions credits
(c) Includes $2.3 billion, $106 million and $848 million of TDSP expense in Texas, East and West/Services/Other, respectively
(d) Excludes depreciation and amortization shown separately
Business Metrics	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Retail sales
Home electricity sales volume (GWh)	34,879		10,298		1,629		—		46,806
Business electricity sales volume (GWh)	29,859		37,110		7,753		—		74,722
Home natural gas sales volume (MDth)	—		35,423		58,963		—		94,386
Business natural gas sales volume (MDth)	—		1,190,382		110,396		—		1,300,778
Average retail Home customer count (in thousands)(a)	2,992		1,785		802		—		5,579
Ending retail Home customer count (in thousands)(a)	2,890		1,788		797		—		5,475
Power generation
GWh sold	29,976		9,118		5,230		—		44,324
GWh generated(b)
Coal	14,765		5,361		—		—		20,126
Gas	7,628		475		5,236		—		13,339
Nuclear	7,583		—		—		—		7,583
Oil	—		2		—		—		2
Renewables	—		—		7		—		7
Total	29,976		5,838		5,243		—		41,057
(a) Home customer count includes recurring residential customers, services customers and municipal aggregations
(b) Includes owned and leased generation, excludes tolled generation and equity investments

The following table represents the weather metrics for the nine months ended September 30, 2023 and 2022:


	Nine months ended September 30,
Weather Metrics	Texas	East	West/Services/Other(b)
2023
CDDs(a)	3,183	1,144	1,866
HDDs(a)	856	2,619	1,417
2022
CDDs	3,141	1,267	1,974
HDDs	1,202	2,944	1,347
10-year average
CDDs	2,761	1,220	1,776
HDDs	1,050	3,124	1,290

(b) The West/Services/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 decreased $3.5 billion and economic gross margin increased $1.7 billion, both of which include intercompany sales, during the nine months ended September 30, 2023, compared to the same period in 2022.

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

Texas


	(In millions)
Higher gross margin due to the net effect of: •increased net revenue rates of $6.00 per MWh, or $435 million, primarily driven by changes in customer term, product and mix; and •a $418 million decrease in cost to serve the retail load, primarily driven by lower supply costs which were a result of lower realized power pricing, the diversified supply strategy and improved plant performance coupled with the 2022 impact of the W.A. Parish Unit 8 extended outage that began in May 2022	$	853
Lower gross margin due to a decrease in load of 675 GWhs, or $74 million, driven by attrition and changes in customer mix, and a decrease in load of 905 GWhs, or $36 million, from weather	(110)
Higher gross margin due to market optimization activities	34



Other	(14)
Increase in economic gross margin	$	763
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(242)
Increase in contract and emissions credit amortization	(9)
Decrease in depreciation and amortization	14
Increase in gross margin	$	526

East


	(In millions)
Lower gross margin due to a decrease in generation and capacity as a result of asset retirements	$	(97)
Higher electric gross margin due to higher net revenue rates as a result of changes in customer term, product and mix of $3.25 per MWh, or $144 million, as well as lower supply costs of $1.25 per MWh, or $61 million, driven primarily by decreases in power prices	205
Lower electric gross margin due to attrition, changes in customer mix, and weather	(24)
Lower natural gas gross margin, including the impact of transportation and storage contract optimization, resulting in lower net revenue rates from changes in customer term, product and mix of $2.25 per Dth, or $2.69 billion, partially offset by lower supply costs of $2.20 per Dth, or $2.62 billion, driven primarily by decrease in gas costs	(74)
Lower natural gas gross margin from a decrease in volumes due to weather and changes in customer mix	(8)
Lower gross margin primarily due to a 56% decrease in PJM capacity prices and a 20% decrease in PJM capacity volumes, partially offset by a reduction in capacity performance penalties resulting from Winter Storm Elliot in December 2022, and a 94% increase in NYISO capacity pricing	(23)







Higher gross margin due to a decrease in supply costs at Midwest Generation, offset by lower gross margin as a result of a 68% decrease in generation volumes due to dark spread contractions	46
Lower gross margin from sales of NOx emissions credits	(17)
Lower gross margin from market optimization activities	(3)
Other	1
Increase in economic gross margin	$	6
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(3,760)
Decrease in contract amortization	20
Decrease in depreciation and amortization	77
Decrease in gross margin	$	(3,657)

West/Services/Other


	(In millions)
Lower gross margin primarily due to lower Services sales	$	(40)
Lower electric gross margin due to an increase in supply costs of $17.75 per MWh, or $165 million, partially offset by higher revenue rates of $13.50 per MWh, or $126 million, and changes in customer mix of $9 million	(30)

Higher natural gas gross margin due to a decrease in supply costs, of $119 million, and changes in customer mix of $7 million, partially offset by lower revenue rates, of $121 million	5






Lower gross margin at Cottonwood driven by current year planned outage and a reduction in capacity performance bonus payment resulting from PJM Winter Storm Elliott in December 2022	(16)
Higher gross margin from market optimization activities	14
Other	(1)
Decrease in economic gross margin	$	(68)
Decrease in mark-to-market for economic hedges primarily due to net unrealized gains/losses on open positions related to economic hedges	(838)
Decrease in contract amortization	2
Increase in depreciation and amortization	(5)
Decrease in gross margin	$	(909)

Vivint Smart Home(a)


	(In millions)
Increase due to the acquisition of Vivint Smart Home	$	968

Increase in economic gross margin	$	968


Increase in depreciation and amortization	(410)
Increase in gross margin	$	558

(a) Includes results of operations following the acquisition date of March 10, 2023

Mark-to-Market for Economic Hedging Activities

Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges. Total net mark-to-market results decreased by $4.8 billion during the nine months ended September 30, 2023, compared to the same period in 2022.

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


	Nine months ended September 30, 2023
(In millions)	Texas		East		West/Services/Other		Eliminations		Total
Mark-to-market results in revenue
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	—	$	(23)	$	46	$	(8)	$	15
Reversal of acquired (gain) positions related to economic hedges	—		(1)		—		—		(1)
Net unrealized gains on open positions related to economic hedges	—		51		34		(3)		82
Total mark-to-market gains in revenue	$	—	$	27	$	80	$	(11)	$	96
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges	$	(416)	$	(697)	$	(429)	$	8	$	(1,534)
Reversal of acquired loss/(gain) positions related to economic hedges	7		3		(5)		—		5
Net unrealized gains/(losses) on open positions related to economic hedges	830		(1,056)		(277)		3		(500)
Total mark-to-market gains/(losses) in operating costs and expenses	$	421	$	(1,750)	$	(711)	$	11	$	(2,029)


	Nine months ended September 30, 2022
(In millions)	Texas		East		West/Services/Other		Eliminations		Total
Mark-to-market results in revenue
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	2	$	(9)	$	38	$	(6)	$	25
Reversal of acquired (gain) positions related to economic hedges	—		(1)		—		—		(1)
Net unrealized (losses) on open positions related to economic hedges	(1)		(194)		(101)		24		(272)
Total mark-to-market gains/(losses) in revenue	$	1	$	(204)	$	(63)	$	18	$	(248)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges	$	(336)	$	(547)	$	(140)	$	6	$	(1,017)
Reversal of acquired loss/(gain) positions related to economic hedges	15		(25)		(16)		—		(26)
Net unrealized gains on open positions related to economic hedges	983		2,813		426		(24)		4,198
Total mark-to-market gains in operating costs and expenses	$	662	$	2,241	$	270	$	(18)	$	3,155

For the nine months ended September 30, 2023, the $96 million gain in revenues from economic hedge positions was driven by an increase in the value of open positions as a result of decreases in power prices. The $2.0 billion loss in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period, as well as a decrease in the value of East and West/Other open positions as a result of decreases in natural gas and power prices. This was partially offset by an increase in the value of Texas open positions as a result of increases in ERCOT power prices.

In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the nine months ended September 30, 2023 and 2022. The realized and unrealized financial and physical trading results are included in revenue. The Company's trading activities are subject to limits based on the Company's Risk Management Policy.


	Nine months ended September 30,
(In millions)	2023		2022
Trading gains/(losses)
Realized	$	4	$	3
Unrealized	24		(7)
Total trading gains/(losses)	$	28	$	(4)

Operations and Maintenance Expense

Operations and maintenance expense are comprised of the following:


(In millions)	Texas		East		West/Services/Other		Vivint Smart Home(a)		Eliminations		Total
Nine months ended September 30, 2023	$	513	$	262	$	179	$	129	$	(3)	$	1,080
Nine months ended September 30, 2022	598		304		149		—		(2)		1,049

(a) Includes results of operations following the acquisition date of March 10, 2023

Operations and maintenance expense increased by $31 million for the nine months ended September 30, 2023, compared to the same period in 2022, due to the following:


	(In millions)
Increase due to the acquisition of Vivint Smart Home	$	129
Increase in major maintenance expenditures primarily associated with the timing of planned outages at STP and the scope and duration of outages at Texas gas facilities, Midwest Generation and Cottonwood	56
Increase in retail operations costs driven by higher personnel costs	20
Decrease due to the current year partial property insurance claim for the extended outage at W.A. Parish, as well as restoration expenses incurred in 2022	(119)
Decrease due to changes in estimates of environmental remediation costs at deactivated sites in the East in 2022	(24)
Decrease in variable operation and maintenance expense due to a reduction in PJM generation volumes in 2023	(17)
Decrease driven primarily by East asset retirements partially offset by an increase in deactivation costs in the West	(15)
Other	1
Increase in operations and maintenance expense	$	31

Other Cost of Operations

Other Cost of operations are comprised of the following:


(In millions)	Texas		East		West/Services/Other		Vivint Smart Home(a)		Total
Nine months ended September 30, 2023	$	190	$	98	$	11	$	2	$	301
Nine months ended September 30, 2022	153		113		12		—		278

(a) Includes results of operations following the acquisition date of March 10, 2023

Other cost of operations increased by $23 million for the nine months ended September 30, 2023, compared to the same period in 2022, due to the following:


	(In millions)
Increase in property insurance premiums and property taxes	$	22
Increase in retail gross receipt taxes due to higher revenues in Texas offset by lower revenues in the East	1
Decrease due to changes in timing of ARO estimates	(6)
Other	6
Increase in other cost of operations	$	23

Depreciation and Amortization

Depreciation and amortization expenses are comprised of the following:


(In millions)	Texas		East		West/Services/Other		Vivint Smart Home(a)		Corporate		Total
Nine months ended September 30, 2023	$	219	$	87	$	70	$	410	$	27	$	813
Nine months ended September 30, 2022	233		164		65		—		23		485

(a) Includes results of operations following the acquisition date of March 10, 2023

Depreciation and amortization increased by $328 million for the nine months ended September 30, 2023, compared to the same period in 2022, primarily due to higher amortization of intangible assets due to the acquisition of Vivint Smart Home in March 2023, partially offset by lower depreciation at Midwest Generation as a result of asset impairments and retirements in 2022.

Impairment Losses

Impairment losses of $198 million recorded during the nine months ended September 30, 2022 include $155 million primarily related to the decline in PJM capacity prices and the near-term retirement date of Joliet and $43 million primarily related to the purchase and sale agreement for the sale of the land and related assets at the Astoria generating site and the planned withdrawal and cancellation of its proposed Astoria redevelopment project. For further discussion, see Note 8, Impairments.

Selling, General and Administrative Costs

Selling, general and administrative costs comprised of the following:


(In millions)	Texas		East		West/Services/Other		Vivint Smart Home(a)		Corporate/Eliminations		Total
Nine months ended September 30, 2023	$	580	$	441	$	171	$	375	$	19	$	1,586
Nine months ended September 30, 2022	500		362		180		—		34		1,076

(a) Includes results of operations following the acquisition date of March 10, 2023

Total selling, general and administrative costs increased by $510 million for the nine months ended September 30, 2023, compared to the same period in 2022, due to the following:


	(In millions)
Increase due to the Vivint Smart Home acquisition	$	375
Increase in personnel costs	66
Increase in higher provision for credit losses	42
Increase in broker fee and commissions expenses	36
Increase in marketing and media expenses	14
Decrease in consulting and legal expenses	(12)
Other	(11)
Increase in selling, general and administrative costs	$	510

Acquisition-Related Transaction and Integration Costs

Acquisition-related transaction and integration costs were $111 million for the nine months ended September 30, 2023, which consisted of $38 million of acquisition costs and $46 million of integration costs related to Vivint Smart Home, as well as $27 million of integration costs primarily related to Direct Energy. Acquisition-related transaction and integration costs were $26 million for the nine months ended September 30, 2022, which were primarily integration costs related to Direct Energy.

Gain on Sale of Assets

The gain on sale of assets of $202 million and $51 million for the nine months ended September 30, 2023 and 2022, respectively, included the following:


	Nine months ended September 30,
(In millions)	2023		2022
Sale of Astoria Turbines in January 2023	$	199	$	—
Sale of the Company's 49% ownership in the Watson natural gas generating facility	—		46
Sale of the Company's 50% ownership in Petra Nova	—		22
Other asset sales	3		(17)
Gain on sale of assets	$	202	$	51

Other Income, Net

Other income, net increased by $10 million in the nine months ended September 30, 2023, compared to the same period in 2022, primarily driven by higher interest income.

Interest Expense

Interest expense increased by $159 million for the nine months ended September 30, 2023, compared to the same period in 2022, primarily due to the Vivint Smart Home acquisition including the impact of newly issued Senior Secured First Lien Notes, acquired debt of Vivint Smart Home, borrowings on the Revolving Credit Facility and the Receivables Securitization Facilities, as well as the write-off of the deferred financing costs associated with the cancellation of the bridge facility for the Vivint Smart Home acquisition.

Income Tax (Benefit)/Expense

For the nine months ended September 30, 2023, an income tax benefit of $182 million was recorded on a pre-tax loss of $866 million. For the same period in 2022, income tax expense of $739 million was recorded on pre-tax income of $3.1 billion. ~~For the same period in 2021, income tax expense of $840 million was recorded on pre-tax income of $3.5 billion.~~ The effective tax rates were ~~24.2%~~21.0% and ~~24.3%~~24.2% for the nine months ended September 30, ~~2022~~2023 and ~~2021,~~2022, respectively.

For the nine months ended September 30, 2023, NRG's effective tax rate approximated the statutory rate of 21%, which includes the impact of state and foreign taxes. For the same period in 2022, NRG's overall effective tax rate was higher than the statutory rate of 21%, primarily due to state tax expense, partially offset by the tax benefit resulting from the release of the valuation allowance on state net operating losses and carbon capture tax credits. For the same period in 2021, NRG's overall effective tax rate was higher than the statutory rate of 21% primarily due to state tax expense, partially offset by one-time tax benefits, as a result of the acquisition of Direct Energy, on revaluation of state deferred tax assets, NOLs and valuation allowance.

Liquidity and Capital Resources

Liquidity Position

As of September 30, ~~2022~~2023 and December 31, ~~2021,~~2022, NRG's total liquidity, excluding funds deposited by counterparties, of approximately ~~$2.8~~$4.1 billion and ~~$2.7~~$2.8 billion, respectively, was comprised of the following:


(In millions)	(In millions)	September 30, 2022		December 31, 2021		(In millions)	September 30, 2023		December 31, 2022
Cash and cash equivalents	Cash and cash equivalents	$	333	$	250	Cash and cash equivalents	$	401	$	430
Restricted cash - operating	Restricted cash - operating	6		4		Restricted cash - operating	3		5
Restricted cash - reserves~~(a)~~	Restricted cash - reserves~~(a)~~	40		11		Restricted cash - reserves~~(a)~~	8		35
Total	Total	379		265		Total	412		470
Total availability under Revolving Credit Facility and collective collateral facilities~~(b)~~(a)	Total availability under Revolving Credit Facility and collective collateral facilities~~(b)~~(a)	2,395		2,421		Total availability under Revolving Credit Facility and collective collateral facilities~~(b)~~(a)	3,723		2,324
Total liquidity, excluding funds deposited by counterparties	Total liquidity, excluding funds deposited by counterparties	$	2,774	$	2,686	Total liquidity, excluding funds deposited by counterparties	$	4,135	$	2,794

(a) ~~Includes reserves primarily for performance obligations~~

~~(b)~~ Total capacity of Revolving Credit Facility and collective collateral facilities was ~~$6.4~~$7.5 billion and ~~$5.9~~$6.4 billion as of September 30, ~~2022~~2023 and December 31, ~~2021,~~2022, respectively

For the nine months ended September 30, ~~2022,~~2023, total liquidity, excluding funds deposited by counterparties, increased by ~~$88 million.~~$1.3 billion. Changes in cash and cash equivalent balances are further discussed hereinafter under the heading Cash Flow Discussion. Cash and cash equivalents at September 30, ~~2022~~2023 were predominantly held in bank deposits.

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.~~commitments in the short and long-term. 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.

The Company remains committed to maintaining a strong balance sheet and continues to work to achieve investment grade credit ~~metrics. The Company expects to grow into its target investment grade~~ metrics over time primarily through debt reduction and the realization of ~~Direct Energy run-rate earnings~~growth initiatives.

Credit Ratings

On March 1, 2023, following the Vivint Smart Home acquisition financing launch, Standard and ~~other growth initiatives.~~Poor's downgraded the Company's issuer credit to BB with a Stable outlook from BB+. There was no change to Moody's and Fitch ratings at the time.

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 and Finance Leases, to this Form 10-Q, the Company's financing arrangements consist mainly of the Senior Notes, Convertible Senior Notes, Senior Secured First Lien Notes, Revolving Credit Facility, the Receivables Securitization Facilities and tax-exempt bonds. The Company also issues letters of credit through bilateral letter of credit facilities and the P-Caps letter of credit facility. As part of the acquisition of Vivint Smart Home on March 10, 2023, NRG acquired Vivint Smart Home's existing debt, which includes senior secured notes, senior notes and a senior secured term-loan.

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;~~obligations, as described ~~more fully~~ in Note 9, Long-term Debt and Finance ~~Leases~~Leases; (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, as described in Note 11, Changes in Capital Structure.

Sale of Gregory

On October 2, 2023, the Company closed on the sale of its 100% ownership in the Gregory natural gas generating facility in Texas for $102 million.

Sale of the 44% equity interest in STP

On November 1, 2023, the Company closed on the previously announced sale of its 44% equity interest in STP to Constellation. Proceeds of $1.75 billion were reduced by preliminary working capital and other adjustments of $96 million, resulting in net proceeds of $1.654 billion. For further discussion, see Note 4, Acquisitions and Dispositions.

Debt Reduction

The Company plans to reduce debt by $900 million during 2023 as part of its plan to achieve target investment-grade credit metrics, and intends to fund the reduction from cash from operations. NRG plans an additional $500 million of debt reduction in the fourth quarter of 2023 following the sale of STP as the transaction is intended to be leverage neutral. As of September 30, 2023, the Company executed $600 million in debt reduction.

Vivint Smart Home Acquisition

On March 10, 2023, the Company completed the acquisition of Vivint Smart Home. The Company paid $12 per share, or $2.6 billion in cash. The Company funded the acquisition using a combination of $740 million in newly-issued secured corporate debt, $650 million in newly-issued preferred stock, $900 million drawn from its Revolving Credit Facility and Receivables Facilities, and cash on hand.

Issuance of 2033 Senior Notes

On March 9, 2023, the Company issued $740 million of aggregate principal amount of 7.000% senior notes due 2033. The 2033 Senior Notes are senior secured obligations of NRG and are guaranteed by certain of its subsidiaries. Interest is paid semi-annually beginning on September 15, 2023 until the maturity date of March 15, 2033. For further discussion, see Note 9,Long-term Debt and Finance Leases.

6576

~~ERCOT Securitization Proceeds~~Series A Preferred Stock

~~During 2021,~~On March 9, 2023, the ~~Texas Legislature passed HB 4492~~Company issued 650,000 shares of 10.25% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock. For further discussion, see Note 11,Changes in Capital Structure.

Revolving Credit Facility

On February 14, 2023, the Company amended its Revolving Credit Facility to: (i) increase the existing revolving commitments thereunder by $600 million, (ii) extend the maturity date of a portion of the revolving commitments thereunder to February 14, 2028, (iii) transition the benchmark rate applicable to revolving loans from LIBOR to SOFR and (iv) make certain other amendments to the terms of the Revolving Credit Facility for ~~ERCOT~~purposes of, among other things, providing additional flexibility.

On March 13, 2023, the Company further amended its Revolving Credit Facility to ~~mitigate exceptionally high price adders~~increase the existing revolving commitments by an additional $45 million. As of September 30, 2023, there were outstanding borrowings of $300 million and ~~ancillary service costs incurred by LSEs during Winter Storm Uri. HB 4492 authorized ERCOT to obtain $2.1~~there were $1.4 billion in letters of ~~financing to distribute to LSEs that~~credit issued under the Revolving Credit Facility. As of October 31, 2023, there were ~~charged~~outstanding borrowings of $100 million and ~~paid to ERCOT those highly priced ancillary service and ORDPA during Winter Storm Uri. The Company received proceeds~~$712 million in letters of ~~$689 million from ERCOT in June 2022.~~credit issued under the Revolving Credit Facility.

Receivables Securitization Facilities

On ~~February 9, 2022, the Company entered into amendments to~~June 22, 2023, NRG Receivables amended its existing Repurchase Facility to, among other things, (i) increase the size of the facility from $75 million to $150 million and (ii) replace LIBOR with term SOFR as the benchmark for the pricing rate. The Repurchase Facility has no commitment fee and borrowings will be drawn at SOFR + 1.30%. On July 26, 2022, the Company renewed its existing Repurchase Facility to extend the maturity date to July 26, 2023. As of September 30, 2022, there were no outstanding borrowings.

~~On July 26, 2022, NRG Receivables LLC, a wholly-owned indirect subsidiary of the Company, entered into an amendment to its~~ Receivables Facility ~~dated September 22, 2020 with a group of conduit lenders and banks and Royal Bank of Canada, as Administrative Agent~~ to, among other things, (i) extend the scheduled termination date ~~by one year,~~to June 21, 2024, (ii) increase the aggregate commitments from ~~$800 million to~~ $1.0 billion to $1.4 billion (adjusted seasonally) and (iii) ~~increase the letter of credit sublimit to equal the aggregate commitments, (iv) replace LIBOR with Term SOFR as the benchmark for borrowings and (v)~~ add a new ~~originators . The weighted average interest rate related to usage under~~originator. On October 6, 2023, the Receivables Facility aswas further amended to replace the benchmark interest rate of ~~September 30, 2022 was 0.836%.~~the Receivable Facility's subordinated note from LIBOR to SOFR. As of September 30, ~~2022,~~2023, there were no outstanding borrowings and there were ~~$884 million~~$1.2 billion in letters of credit ~~issued under~~issued.

In addition, in connection with the amendments to the Receivables Facility, on June 22, 2023, the Company and the originators thereunder renewed the existing uncommitted Repurchase Facility that provides short-term financing secured by a subordinated note issued by NRG Receivables LLC. Such renewal, among other things, extends the maturity date to June 21, 2024 and joins an additional originator to the Repurchase Facility. On October 6, 2023, the Repurchase Facility was further amended to reflect the concurrent amendment to the Receivables Facility's subordinated note. As of September 30, 2023, there were no outstanding borrowings.

Bilateral Letter of Credit Facilities

On ~~April 29, 2022,~~ May ~~27, 2022~~19, 2023, May 30, 2023 and October ~~13, 2022,~~17, 2023 the Company increased the size of ~~the~~its bilateral letter of credit facilities by ~~$100~~$25 million, ~~$50~~$100 million and $50 million, respectively, to provide additional liquidity, allowing for the issuance of up to ~~$675~~$850 million of letters of credit. These facilities are uncommitted. As of September 30, ~~2022, $592~~2023, $620 million was issued under these facilities. As of October 31, 2023, $652 million was issued under these facilities.

~~Astoria~~Pre-CapitalizedTrustSecuritiesFacility

On ~~September 9, 2022,~~August 29, 2023, the Company entered into a ~~definitive purchase agreement~~Facility Agreement with the Trust, in connection with the sale by the Trust of $500 million P-Caps. The P-Caps are to ~~sell~~be redeemed by the Trust on July 31, 2028 or earlier upon an early redemption of the P-Caps Secured Notes. The P-Caps will replace the Company’s existing pre-capitalized trust securities redeemable 2023 issued by Alexander Funding Trust, which mature on November 15, 2023.

The Facility Agreements allows for the issuance of the P-Caps Secured Notes by the Company to the Trust. In addition, the Company entered into a LC Agreement for the issuance of letters of credit in an aggregate amount not to exceed $485 million. For further discussion, see Note 9, Long-term Debt and Finance Leases.

Sale of Astoria

On January 6, 2023, the Company closed on the sale of land and related assets from the Astoria site, within the East region of operations, for initial proceeds of $212 million, subject to ~~purchase price adjustments~~transaction fees of $3 million and certain ~~other~~ indemnifications. As part of the transaction, NRG ~~will enter~~entered into an agreement to lease the land back for the purpose of operating the Astoria ~~facility through the planned April 30, 2023 retirement date.~~gas turbines. The ~~operating~~ lease agreement is expected to terminate by the end ~~six months~~of the year after decommissioning is complete.

Pension Plan Contribution

During 2023, the ~~facility's actual retirement date.~~Pension Benefit Guaranty Corporation issued a one-time waiver which provided relief for certain pension sponsors resulting in a reduction of the Company’s planned 2023 cash contribution. The ~~transaction is expected to close in the fourth quarter of 2022 and is subject to various closing conditions.~~

~~Sale of Watson~~

~~On June 1, 2022, the~~ Company ~~closed on the sale of its 49% ownership in the Watson natural gas generating facility for $59 million. NRG recognized a gain on the sale of $46 million.~~

~~CARES Act~~

~~On March 27, 2020, the U.S. government enacted the CARES Act, which provides, among other things: (i) the option~~elected to defer ~~payments of certain 2019 employer payroll taxes incurred after~~ the ~~date of enactment; and (ii) allows NOLs from tax years 2018, 2019 and 2020~~remaining 2023 cash contribution to ~~be carried back five~~future years. ~~The total benefit to the Company due to the CARES Act was $35 million. Of this amount, $13 million related to certain 2019 employer payroll taxes is payable in 2022.~~

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 (e.g., buying energy before receiving retail revenues); and (iv) initial collateral for large structured transactions. As of September 30, ~~2022,~~2023, the Company had total cash collateral outstanding of ~~$262~~$2 million and $4$3.8 billion outstanding in letters of credit to third parties primarily to support its market activities. As of September 30, ~~2022,~~2023, total funds deposited by counterparties were ~~$3.1 billion~~$263 million in cash and ~~$717~~$515 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.

First Lien Structure

NRG has granted first liens to certain counterparties on a substantial portion of the Company's assets, subject to various exclusions including 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. The first lien program does not limit the volume that can be hedged, or the value of underlying out-of-the-money positions. The first lien program also does not require NRG to post collateral above any threshold amount of exposure. 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 differ from the hedged prices. As of September 30, ~~2022,~~2023, all hedges under the first liens were out-of-the-money on a counterparty aggregate basis.

The following table summarizes the amount of MW hedged against the Company's coal and nuclear assets and as a percentage relative to the Company's coal and nuclear capacity under the first lien structure as of September 30, ~~2022:~~2023:

Equivalent Net Sales Secured by First Lien Structure(a)
2022 2023
In MW 613 713
As a percentage of total net coal and nuclear capacity(b)
18% 16%


Equivalent Net Sales Secured by First Lien Structure(a)			2023
In MW			142
As a percentage of total net coal and nuclear capacity(b)			3%

(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, Investments and Integration

The following ~~tables~~table and descriptions summarize the Company's maintenance capital expenditures, ~~for maintenance,~~ environmental capital expenditures, and ~~growth~~ investments and integration spend for the nine months ended September 30, ~~2022,~~2023, and the estimated ~~capital expenditures~~ forecast for the remainder of ~~2022.~~the year.


(In millions)	(In millions)	Maintenance		Environmental		Growth Investments(a)		Total		(In millions)	Maintenance		Environmental		Investments and Integration(a)		Total
Texas	Texas	$	(152)	$	(1)	$	(23)	$	(176)	Texas	$	386	$	1	$	33	$	420
East	East	(3)		—		(3)		(6)		East	3		—		1		4
West/Services/Other	West/Services/Other	(17)		—		(10)		(27)		West/Services/Other	17		—		5		22
Corporate	Corporate	(2)		—		(39)		(41)		Corporate	11		—		24		35
Total cash capital expenditures for the nine months ended September 30, 2022		(174)		(1)		(75)		(250)

Vivint Smart Home(b)										Vivint Smart Home(b)	12		—		—		12
Total cash capital expenditures for the nine months ended September 30, 2023										Total cash capital expenditures for the nine months ended September 30, 2023	429		1		63		493
Integration operating expenses(c)										Integration operating expenses(c)	—		—		61		61
Investments	Investments	—		—		(105)		(105)		Investments	—		—		108		108
Total capital expenditures and investments		(174)		(1)		(180)		(355)
Total cash capital expenditures and investments for the nine months ended September 30, 2023										Total cash capital expenditures and investments for the nine months ended September 30, 2023	$	429	$	1	$	232	$	662

Estimated capital expenditures and investments for the remainder of 2022(b)		$	(110)	$	(1)	$	(90)	$	(201)
Estimated cash capital expenditures and investments for the remainder of 2023(d)										Estimated cash capital expenditures and investments for the remainder of 2023(d)	136		4		78		218
Estimated full year 2023 cash capital expenditures and investments										Estimated full year 2023 cash capital expenditures and investments	$	565	$	5	$	310	$	880

(a)Full year estimate reflects the cash expected to be available for allocation for investments and Vivint Smart Home integration in 2023

(b)Includes ~~other investments, acquisitions and~~expenditures following the acquisition date of March 10, 2023

(c)Excludes equity compensation related to integration ~~projects~~

~~(b)~~ (d)Estimated capital expenditures related to W.A. Parish do not reflect expected insurance recoveries

~~Growth investments~~Investments and Integration for the nine months ended September 30, ~~2022~~2023 include growth expenditures, ~~for Encina site improvements classified as ARO payments. NRG has completed its demolition activities at the site~~integration, small book acquisitions and ~~has begun marketing the site.~~other investments.

Environmental Capital Expenditures

NRG estimates that environmental capital expenditures from ~~2022~~2023 through ~~2026~~2027 required to comply with environmental laws will be approximately ~~$32 million. The decrease of $24~~$47 million, ~~from the previous quarter is~~ primarily ~~due to changes in assumptions regarding~~driven by the cost of complying ~~and recharacterization of~~with ELG at the ~~certain cost of complying with, water regulations~~Company's coal units in Texas.

Share Repurchases

In ~~December 2021,~~June 2023, NRG revised its long-term capital allocation policy to target allocating approximately 80% of cash available for allocation after debt reduction to be returned to shareholders. As part of the ~~Company's board of directors authorized~~revised capital allocation framework, the Company announced an increase to its share repurchase ~~$1.0~~authorization to $2.7 billion, ~~of its common stock, of which $44 million was completed in 2021.~~to be executed through 2025. During the ~~nine~~three months ended September 30, ~~2022,~~2023, the Company completed ~~$489~~$50 million of share repurchases at an average price of ~~$40.07 per share, including $6 million of equivalent shares purchased in lieu of tax withholdings on equity compensation issuances.~~$37.82 under the $2.7 billion authorization. Through October 31, ~~2022,~~2023, an additional ~~$76~~$150 million of share repurchases were executed at an average price of ~~$41.71~~$40.17 per share. ~~In October 2022,~~Following the ~~Board~~closing of ~~Directors approved an additional $600~~the STP sale on November 1, 2023, the Company intends to execute a $950 million inaccelerated share ~~repurchases.~~repurchase program.

Common Stock Dividends

Series A Preferred Stock Dividends

In September 2023, the Company paid a semi-annual dividend of $52.96 per share on its outstanding Series A Preferred Stock, totaling $34 million.

Obligations under Certain Guarantees

NRG and its subsidiaries enter into various contracts that include indemnifications and guarantee provisions as a routine part of the Company’s business activities. For further discussion, see Note 27, Guarantees, to the Company's ~~2021~~2022 Form 10-K.

Obligations Arising Out of a Variable Interest in an Unconsolidated Entity

Variable interest in equity investments — 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~~. NRG's pro-rata share of non-recourse debt was approximately ~~$492~~$467 million as of September 30, ~~2022.~~2023. This indebtedness may restrict the ability of Ivanpah to issue dividends or distributions to NRG.

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 ~~2021~~2022 Form 10-K. See also Note 9, Long-term Debt and Finance Leases, 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 nine months ended September 30, ~~2022.~~2023.

Cash Flow Discussion

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


		Nine months ended September 30,							Nine months ended September 30,
(In millions)	(In millions)	2022		2021		Change		(In millions)	2023		2022		Change
Cash provided by operating activities		$	1,758	$	1,855	$	(97)
Cash (used)/provided by operating activities								Cash (used)/provided by operating activities	$	(462)	$	1,758	$	(2,220)
Cash used by investing activities	Cash used by investing activities	(205)		(3,585)		3,380		Cash used by investing activities	(2,631)		(205)		(2,426)
Cash provided/(used) by financing activities		855		(177)		1,032
Cash provided by financing activities								Cash provided by financing activities	1,590		855		735

Cash (used)/provided by operating activities

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


	(In millions)
~~Decrease in operating income adjusted for other non-cash items~~	$	~~(1,399)~~
~~Increase due to receipt of uplift securitization proceeds from ERCOT~~	~~689~~
Increase in working capital primarily attributable to the impact of higher market prices on accounts receivable and accounts payable, partially offset by a decrease working capital related to higher priced natural gas inventory	~~323~~
Changes in cash collateral in support of risk management activities due to change in commodity prices	~~351~~ $	(3,509)
Increase in operating loss/income adjusted for other non-cash items	2,252
Decrease due to receipt of uplift securitization proceeds from ERCOT in 2022	(689)
Decrease in working capital primarily driven by Vivint Smart Home capitalized contract costs partially offset by deferred revenues	(258)
Decrease in working capital primarily due to ~~timing of prepaid broker fees~~lower gas and power market pricing coupled with lower gas volumes	~~(47)~~(16)
~~Other~~	~~(14)~~








	$	~~(97)~~(2,220)

Cash used by investing activities

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


	(In millions)
~~Decrease~~Increase in cash paid for acquisitions primarily due to the ~~Direct Energy~~ acquisition of Vivint Smart Home in ~~2021~~March 2023	$	~~3,474~~ (2,442)
~~Decrease~~Increase in capital expenditures	(243)
Increase from insurance proceeds for property, plant and equipment, net in 2023	173
Increase in proceeds from sale of assets primarily due to the sale of ~~Agua Caliente~~the land and related assets from the Astoria site in ~~2021~~January 2023	~~(91)~~122
~~Increase~~Decrease in proceeds from sales of emissions allowances, net of purchases	(21)
Decrease in proceeds from sales of investments in nuclear decommissioning trust fund securities, net of purchases	38 (15)
~~Increase in capital expenditures~~	~~(31)~~
~~Increase in purchases of emissions allowances, net of sales~~	~~(10)~~






	$	~~3,380~~ (2,426)

Cash ~~provided/(used)~~provided by financing activities

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


	(In millions)
Decrease ~~primarily in payments of long-term debt~~	$	~~1,356~~
~~Increase~~ in net receipts from settlement of acquired derivatives	~~1,200~~ $	(1,264)
~~Decrease~~Increase in proceeds from issuance of long-term debt in 2023	~~(1,100)~~731
Increase in ~~payments for share repurchase activity~~proceeds from issuance of preferred stock in 2023	~~(475)~~635
Increase due to lower payments ~~of debt extinguishment costs and deferred issuance costs~~for share repurchase activity in ~~prior year~~2023	65415
Increase in proceeds from Revolving Credit Facility in 2023	300
Increase in payments of dividends primarily due to ~~common stockholders~~preferred stock issued in 2023	~~(13)~~(43)
~~Other~~Increase in payments of deferred issuance costs	~~(1)~~(28)
Decrease due to repayments of long-term debt and finance leases






(11)
	$	~~1,032~~735

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

For the nine months ended September 30, ~~2022,~~2023, the Company had domestic pre-tax book ~~income~~loss of ~~$2.9 billion~~$553 million and foreign pre-tax book ~~income~~loss of ~~$117~~$313 million. As of December 31, ~~2021,~~2022, the Company had cumulative U.S. Federal NOL carryforwards of ~~$8.4~~$8.2 billion, of which ~~$11 million were generated prior to Tax Cuts and Jobs Act and will begin expiring in 2031,~~do not have an expiration date, and cumulative state NOL carryforwards of ~~$5.2~~$5.3 billion for financial statement purposes. NRG also has cumulative foreign NOL carryforwards of ~~$383~~$382 million, most of which do not have an expiration date. In addition to the above NOLs, NRG has a ~~$20~~$270 million indefinite carryforward for interest deductions, as well as ~~$384~~$393 million of tax credits to be utilized in future years. In connection with the Vivint Smart Home acquisition, additional federal and state NOLs of $2.1 billion and $1.8 billion, respectively, were added, as well as a federal carryforward for interest deductions of $739 million. As a result of the Company's tax position, including the utilization of federal and state NOLs, and based on current forecasts, the Company anticipates net income tax payments due to federal, state and foreign jurisdictions of up to ~~$59~~$70 million in ~~2022.~~2023. The Company does not anticipate that the corporate minimum book tax will have a material impact on the current year consolidated financial statements.

As of September 30, ~~2022,~~2023, the Company has ~~$22~~$45 million of tax-effected uncertain federal, state, and ~~state~~foreign tax benefits, for which the Company has recorded a non-current tax liability of ~~$23~~$48 million (inclusive of accrued interest) 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 2019. With few exceptions, state and Canadian income tax examinations are no longer open for years prior to ~~2013.~~2014.

Deferred tax assets and valuation allowance

Net deferred tax balance — As of September 30, ~~2022~~2023 and December 31, ~~2021,~~2022, NRG recorded a net deferred tax asset, excluding valuation allowance, of ~~$1.6~~$2.5 billion and ~~$2.3~~$2.0 billion, respectively. 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 September 30, 2023 and December 31, 2022 as discussed below.

NOL Carryforwards — As of September 30, ~~2022,~~2023, the Company had a tax-effected cumulative U.S. NOLs consisting of carryforwards for federal and state income tax purposes of ~~$1.8~~$1.7 billion and ~~$310~~$315 million, respectively. Additional federal and state NOLs of $446 million and $70 million, respectively, were added with the acquisition of Vivint Smart Home. The Company estimates it will need to generate future taxable income to fully realize the net federal deferred tax asset before the expiration of certain carryforwards commences in ~~2031.~~2030. In addition, NRG has tax-effected cumulative foreign NOL carryforwards of ~~$92 million with no expiration date.~~$99 million.

Valuation Allowance — As of September 30, ~~2022~~2023 and December 31, ~~2021,~~2022, the Company’s tax-effected valuation allowance was ~~$207~~$228 million and ~~$248~~$224 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.

Guarantor Financial Information

As of September 30, ~~2022,~~2023, the Company's outstanding registered senior notes consisted of $375 million of the 2027 Senior Notes and $821 million of the 2028 Senior Notes as shown in Note 9, Long-term Debt and Finance Leases. These Senior Notes are guaranteed by certain of NRG's current and future 100% owned domestic subsidiaries, or guarantor subsidiaries (the “Guarantors”). See Exhibit 22.1 to this Form 10-Q for a listing of the Guarantors. These guarantees are both joint and several.

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 Guarantors to transfer funds to NRG. Other subsidiaries of the Company do not guarantee the registered debt securities of either NRG Energy, Inc or the Guarantors (such subsidiaries are referred to as the “Non-Guarantors”). The Non-Guarantors include all of NRG's foreign subsidiaries and certain domestic subsidiaries.

The following tables ~~below~~ present summarized financial information of NRG Energy, Inc. and the Guarantors in accordance with Rule 3-10 under the SEC's Regulation S-X. The financial information may not necessarily be indicative of results of operations or financial position of NRG Energy, Inc. and the Guarantors in accordance with U.S. GAAP.

The following table presents the summarized statement of operations:

(In millions) Nine months ended September 30, 2022 Nine months ended September 30, 2021
Revenues(a)
$ 20,918 $ 17,675
Operating income(b)
3,450 4,144
Total other expense (252) (373)
Income from continuing operations before income taxes 3,198 3,771
Net Income 2,486 2,963


(In millions)	Nine months ended September 30, 2023
Revenue(a)	$	18,590
Operating loss(b)	(288)
Total other expense	(301)
Loss before income taxes	(589)
Net Loss	(511)

(a)Intercompany transactions with Non-Guarantors of ~~$137 million and $77~~$7 million during the nine months ended September 30, ~~2022 and 2021, respectively~~2023

(b)Intercompany transactions with Non-Guarantors including cost of operations of ~~$(319) million and $(191)~~$22 million and selling, general and administrative of ~~$142 million and $76~~$153 million during the nine months ended September 30, ~~2022 and 2021, respectively~~2023

The following table presents the summarized balance sheet information:

(In millions) September 30, 2022 December 31, 2021
Current assets(a)
$ 16,856 $ 9,399
Property, plant and equipment, net 1,326 1,324
Non-current assets 12,666 11,569
Current liabilities(b)
13,848 7,590
Non-current liabilities 12,459 11,195


(In millions)	September 30, 2023
Current assets(a)	$	6,780
Property, plant and equipment, net	1,207
Non-current assets	14,323
Current liabilities(b)	7,471
Non-current liabilities	11,385

(a)Includes intercompany receivables due from Non-Guarantors of ~~$104 million and $86~~$58 million as of September 30, ~~2022 and December 31, 2021, respectively~~2023

(b)Includes intercompany payables due ~~from~~to Non-Guarantors of ~~$47 million and $50~~$39 million as of September 30, ~~2022 and December 31, 2021, respectively~~2023

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. In order to mitigate interest rate risk associated with the issuance of the Company's variable rate debt, NRG enters into interest rate swap agreements. In addition, in order to mitigate foreign exchange rate risk primarily associated with the purchase of ~~USD~~U.S. dollar denominated natural gas for the Company's Canadian business, NRG enters into foreign exchange contract agreements.

Under Flex Pay, offered by Vivint Smart Home, subscribers pay for smart home products by obtaining financing from a third-party financing provider under the Consumer Financing Program. Vivint Smart Home pays certain fees to the financing providers and shares in credit losses depending on the credit quality of the subscriber.

NRG's trading activities are subject to limits in accordance with the Company's Risk Management Policy. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings.

7082

The following 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.~~820"). Specifically, these tables disaggregate realized and unrealized changes in fair value; disaggregate estimated fair values atas of September 30, ~~2022,~~2023, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at September 30, ~~2022.~~2023. For a full discussion of the Company's valuation methodology of its contracts, see Derivative Fair Value Measurements in Note 5, Fair Value of Financial Instruments.


Derivative Activity Gains/(Losses)	(In millions)
Fair Value of Contracts as of December 31, ~~2021~~2022	$	~~2,341~~3,553
Contracts realized or otherwise settled during the period	~~(1,014)~~(1,452)
~~Changes~~Vivint Smart Home contracts acquired during the period	(112)
Other changes in fair value	~~3,882~~ (429)
Fair Value of Contracts as of September 30, ~~2022~~2023	$	~~5,209~~1,560


		Fair Value of Contracts as of September 30, 2022											Fair Value of Contracts as of September 30, 2023
(In millions)	(In millions)	Maturity										(In millions)	Maturity
Fair Value Hierarchy Gains	Fair Value Hierarchy Gains	1 Year or Less		Greater than 1 Year to 3 Years		Greater than 3 Years to 5 Years		Greater than 5 Years		Total Fair Value		Fair Value Hierarchy 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	Level 1	$	984	$	601	$	47	$	13	$	1,645	Level 1	$	26	$	183	$	3	$	1	$	213
Level 2	Level 2	1,706		853		218		105		2,882		Level 2	553		433		63		5		1,054
Level 3	Level 3	407		128		35		112		682		Level 3	3		70		72		148		293
Total	Total	$	3,097	$	1,582	$	300	$	230	$	5,209	Total	$	582	$	686	$	138	$	154	$	1,560

The Company has elected to disclose 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 posted on the Company's derivative assets or liabilities are recorded on a separate line item on the balance sheet. Consequently, the magnitude of the changes in individual current and non-current derivative assets or liabilities is higher than the underlying credit and market risk of the Company's portfolio. As discussed in Item 3, Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk, to this Form 10-Q, NRG measures the sensitivity of the Company's portfolio to potential changes in market prices using VaR, a statistical model which attempts to predict risk of loss based on market price and volatility. NRG's risk management policy places a limit on one-day holding period VaR, which limits the Company's net open position. As the Company's trade-by-trade derivative accounting results in a gross-up of the Company's derivative assets and liabilities, the net derivative asset and liability position is a better indicator of NRG's hedging activity. As of September 30, ~~2022,~~2023, NRG's net derivative asset was ~~$5.2~~$1.6 billion, ~~an increase~~a decrease to total fair value of ~~$2.9~~$2.0 billion as compared to December 31, ~~2021.~~2022. This ~~increase~~decrease was primarily driven ~~by gains in fair value, partially offset~~ by roll-off of trades that settled during the period, losses in fair value, and Vivint Smart Home contracts acquired during the period.

Based on a sensitivity analysis using simplified assumptions, the impact of a $0.50 per MMBtu increase or decrease in natural gas prices across the term of the derivative contracts would result in ~~an increase~~a change of approximately ~~$1.3~~$1.8 billion in the net value of derivatives as of September 30, ~~2022.~~

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 $1.3 billion in the net value of derivatives as of September 30, 2022.

2023.

Critical Accounting 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 appropriate technical accounting rules and guidance involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges, and the fair value of certain assets and liabilities. These judgments, in and of themselves, could materially affect the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment may also have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies has not changed.

NRG evaluates these estimates, on an ongoing basis, utilizing historic experience, consultation with experts and other methods the Company considers reasonable. In any event, actual results may differ substantially from the Company's estimates. Any effects on the Company's business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the information that gives rise to the revision becomes known.

The Company identifies its most critical accounting estimates 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.

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 ~~2021~~2022 Form 10-K. There have been no material changes to the Company's critical accounting estimates since the ~~2021~~2022 Form 10-K.

7284

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 retail operations, merchant power generation or with existing or forecasted financial or commodity transactions. The types of market risks the Company is exposed to are commodity price risk, credit risk, liquidity 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 ~~2021~~2022 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 load serving obligations and merchant generation operations by entering into various derivative or non-derivative instruments to hedge the variability in future cash flows from forecasted sales and purchases of energy 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, gas transportation and storage assets, load obligations and bilateral physical and financial transactions, based on historical and forward values for factors such as customer demand, weather, commodity availability and commodity prices. The Company's VaR model is based on a one-day holding period at a 95% confidence interval for the forward 36 months, not including the spot month. The VaR model is not a complete picture of all risks that may affect the Company's results. Certain events such as counterparty defaults, regulatory changes, and extreme weather and prices that deviate significantly from historically observed values are not reflected in the model.

The following table summarizes average, maximum and minimum VaR for NRG's commodity portfolio, calculated using the VaR model for the three and nine months ending September 30, ~~2022~~2023 and ~~2021:~~2022:


(In millions)	(In millions)	2022		2021		(In millions)	2023		2022
VaR as of September 30,	VaR as of September 30,	$	58	$	41	VaR as of September 30,	$	63	$	58
Three months ended September 30,	Three months ended September 30,					Three months ended September 30,
Average	Average	$	44	$	43	Average	$	64	$	44
Maximum	Maximum	69		50		Maximum	75		69
Minimum	Minimum	26		38		Minimum	45		26
Nine months ended September 30,	Nine months ended September 30,					Nine months ended September 30,
Average(a)		$	45	$	36
Maximum(a)		86		50
Minimum(a)		26		25
Average						Average	$	66	$	45
Maximum						Maximum	82		86
Minimum						Minimum	45		26

~~(a)Calculation is based on NRG generation assets and load obligations excluding the acquisition of Direct Energy assets and load obligations in the first quarter of 2021~~

~~In order to provide additional information, the~~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 ~~$561~~$156 million, as of September 30, ~~2022,~~2023, primarily driven by asset-backed and hedging transactions.

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. Counterparty credit risk and retail customer credit risk are discussed below. See Note 7, Accounting for Derivative Instruments and Hedging Activities, to this Form 10-Q for discussion regarding credit risk contingent features.

Counterparty Credit Risk

~~75%~~ 36% of the Company's exposure before collateral is expected to roll off by the end of ~~2023.~~2024. Counterparty credit exposure is valued through observable market quotes and discounted at a risk free interest rate. The following tables highlight net

counterparty credit exposure by industry sector and by counterparty credit quality. Net counterparty credit exposure is defined as the aggregate net asset position for NRG with counterparties where netting is permitted under the enabling agreement and includes all cash flow, mark-to-market and NPNS, and non-derivative transactions. The exposure is shown net of collateral held and includes amounts net of receivables or payables.


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

Utilities, energy merchants, marketers and other	6168	%
Financial institutions	3932

Total as of September 30, ~~2022~~2023	100	%


	Net Exposure (a)(b)
Category by Counterparty Credit Quality	(% of Total)
Investment grade	6856	%
Non-investment grade/non-rated	3244
Total as of September 30, ~~2022~~2023	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 exposure to one wholesale counterparty in excess of 10% of total net exposure discussed above as of September 30, ~~2022.~~2023. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration.

RTOs and ISOs

Exchange Traded Transactions

Long-Term Contracts

Counterparty credit exposure described above excludes credit risk exposure under certain long-term contracts, primarily solar under Renewable PPAs. As external sources or observable market quotes are not always available to estimate such exposure, the Company values these contracts based on various techniques including, but not limited to, internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. Based on these valuation techniques, as of September 30, ~~2022,~~2023, aggregate credit risk exposure managed by NRG to these counterparties was approximately ~~$1.1~~$1.0 billion for the next five years.

Retail Customer Credit Risk

manages retail credit risk through the use of established credit policies, ~~that~~which include monitoring of the portfolio and the use of credit mitigation measures such as deposits or prepayment arrangements.

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 September 30, ~~2022,~~2023, 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 ~~$893 million~~$1.2 billion 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 ~~$392~~$296 million. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of September 30, ~~2022.~~2023.

Interest Rate Risk

NRG is 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 combinations of the variable rate debt and the interest rate derivative instrument. NRG's management policies allow the Company to reduce interest rate exposure from variable rate debt obligations. In the first quarter of 2023, the Company entered into $1.0 billion of interest rate swaps through 2027 to hedge the floating rate on the Term Loan acquired with the Vivint Smart Home acquisition. Additionally, the Company has entered into interest rate swaps to hedge the floating rate on the Revolving Credit Facility extending through 2024, with $300 million outstanding as of September 30, 2023.

As of September 30, ~~2022,~~2023, the fair value and related carrying value of the Company's debt was ~~$7.1~~$10.6 billion and ~~$8.1~~$11.7 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 September 30, ~~2022~~2023 by ~~$513~~$848 million.

Currency Exchange Risk

NRG is subject to transactional exchange rate risk from transactions with customers in countries outside of the United States, primarily within Canada, as well as from intercompany transactions between affiliates. Transactional exchange rate risk arises from the purchase and sale of goods and services in currencies other than ~~our~~the Company's functional currency or the functional currency of an applicable subsidiary. NRG hedges a portion of its forecasted currency transactions with foreign exchange forward contracts. As of September 30, ~~2022,~~2023, NRG is exposed to changes in foreign currency primarily associated with the purchase of U.S. dollar denominated natural gas for its Canadian business and entered into foreign exchange contracts with a notional amount of ~~$502~~$566 million.

The Company is subject to translation exchange rate risk related to the translation of the financial statements of its foreign operations into U.S. dollars. Costs incurred and sales recorded by subsidiaries operating outside of the United States are translated into U.S. dollars using exchange rates effective during the respective period. As a result, the Company is exposed to movements in the exchange rates of various currencies against the U.S. dollar, primarily the Canadian and Australian dollars. A hypothetical 10% appreciation in major currencies relative to the U.S. dollar as of September 30, ~~2022~~2023 would have resulted in ~~an increase~~a decrease of $9$23 million to net income within the Consolidated Statement of Operations.

ITEM 4 — CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

There were no changes in NRG's internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred in the quarter ended September 30, ~~2022~~2023 that materially affected, or are reasonably likely to materially affect, NRG's internal control over financial reporting.

7587

PART II — OTHER INFORMATION

ITEM 1 — LEGAL PROCEEDINGS

For a discussion of material legal proceedings in which NRG was involved through September 30, ~~2022,~~2023, see Note 16, Commitments and Contingencies, to this Form 10-Q.

ITEM 1A — RISK FACTORS

During the ~~nine~~three months ended September 30, ~~2022,~~2023, there were no material changes to the Risk Factors disclosed in Part I,II, Item 1A, Risk Factors~~Factors,~~ , of the Company's ~~2021~~Quarterly Report on Form ~~10-K, except~~10-Q for the ~~update below:~~

~~Negative publicity may damage NRG’s reputation or its brands.~~

~~NRG’s reputation and brands could be damaged for numerous reasons, including negative views of~~quarter ended March 31, 2023, filed with the Company’s environmental impact, sustainability goals, supply chain practices, product and service offerings, sponsorship relationships, charitable giving programs and public statements made by Company officials. The Company may also experience criticism or backlash from media, customers, employees, government entities, advocacy groups and other stakeholders that disagree with positions taken by the Company or its executives. If the Company’s brands or reputation are damaged, it could negatively impact the Company’s business, financial condition, results of operations, and ability to attract and retain highly qualified employees.SEC on May 4, 2023.

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 September 30, ~~2022.~~2023.

For the three months ended September 30, 2022 Total Number of Shares Purchased
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)(c)
Month #1
(July 1, 2022 to July 31, 2022) — $ — — $ 594,730,048
Month #2
(August 1, 2022 to August 31, 2022) 1,074,500 $ 42.21 1,074,500 $ 549,357,941
Month #3
(September 1, 2022 to September 30, 2022) 1,972,536 $ 41.63 1,972,536 $ 466,742,103
Total at September 30, 2022 3,047,036 $ 41.83 3,047,036


For the three months ended September 30, 2023	Total Number of Shares Purchased	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 (in millions) (a)(c)
Month #1
(July 1, 2023 to July 31, 2023)	1,322,141	$	37.82	1,322,141	$	2,650
Month #2
(August 1, 2023 to August 31, 2023)	—	$	—	—	$	2,650
Month #3
(September 1, 2023 to September 30, 2023)	—	$	—	—	$	2,650

Total at September 30, 2023	1,322,141	$	37.82	1,322,141

(a)~~On December 6, 2021~~In June 2023, as part of the revised capital allocation framework, the Company announced ~~that~~an increase to its share repurchase authorization to $2.7 billion to be executed through 2025. The Company began executing under the ~~Board of Directors has authorized $1~~$2.7 billion ~~for share repurchases, as part of NRG’s capital allocation program. The program began~~authorization in ~~December 2021 and continues in 2022~~July 2023

(b)The average price paid per share excludes excise taxes and commissions ~~of $0.02~~ per share paid in connection with the open market share repurchases

(c)Includes commissions of ~~$0.02~~$0.01 per share paid in connection with the open market share repurchases

ITEM 3 — DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4 — MINE SAFETY DISCLOSURES

There have been no events that are required to be reported under this Item.

ITEM 5 — OTHER INFORMATION

~~None.~~During the three months ended September 30, 2023, no director or officer of the Company adopted or terminated a 'Rule 10b5-1 trading arrangement' or 'non-Rule 10b5-1 trading arrangement,' as each term is defined in Item 408(a) of Regulation S-K.

7688

ITEM 6 — EXHIBITS

Number

Description

Method of Filing

4.1

Facility Agreement, dated August 29, 2023, among NRG Energy, Inc., the guarantors party thereto, Alexander Funding Trust II and Deutsche Bank Trust Company Americas, as the notes trustee

Incorporated herein by reference to Exhibit 4.1 to the Registrant's current report on Form 8-K filed on August 29, 2023.

4.2

Letter of Credit Facility Agreement, dated August 29, 2023, among NRG Energy, Inc., the financial institutions from time to time party thereto as letter of credit issuers, and Deutsche Bank Trust Company Americas, as administrative agent and as collateral agent

Incorporated herein by reference to Exhibit 4.2 to the Registrant's current report on Form 8-K filed on August 29, 2023.

4.3

Amended and Restated Declaration of Trust of Alexander Funding Trust II, dated August 29, 2023, among NRG Energy, Inc. as depositor and in its own capacity, Deutsche Bank Trust Company Americas, as trustee, and Deutsche Bank Trust Company Delaware, as Delaware trustee

Incorporated herein by reference to Exhibit 4.3 to the Registrant's current report on Form 8-K filed on August 29, 2023.

4.4

Indenture, dated August 29, 2023, between NRG Energy, Inc. and Deutsche Bank Trust Company Americas, as trustee, pertaining to the Notes

Incorporated herein by reference to Exhibit 4.4 to the Registrant's current report on Form 8-K filed on August 29, 2023.

4.5

Supplemental Indenture, dated August 29, 2023, among NRG Energy, Inc., the guarantors named therein and Deutsche Bank Trust Company Americas, as trustee, pertaining to the Notes

Incorporated herein by reference to Exhibit 4.5 to the Registrant's current report on Form 8-K filed on August 29, 2023.

4.6

Form of 7.467% Senior Secured First Lien Notes due 202 8

Incorporated herein by reference to Exhibit 4.6 to the Registrant's current report on Form 8-K filed on August 29, 2023.

22.1

List of Guarantor Subsidiaries

Filed herewith.

31.1

Rule 13a-14(a)/15d-14(a) certification of Mauricio Gutierrez.

Filed herewith.

31.2

Rule 13a-14(a)/15d-14(a) certification of ~~Alberto Fornaro.~~Woo-Sung Chung.

Filed herewith.

31.3

Rule 13a-14(a)/15d-14(a) certification of Emily Picarello.

Filed herewith.

Section 1350 Certification.

Furnished herewith.

101 INS

Inline XBRL Instance Document.

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

101 SCH

Inline XBRL Taxonomy Extension Schema.

Filed herewith.

101 CAL

Inline XBRL Taxonomy Extension Calculation Linkbase.

Filed herewith.

101 DEF

Inline XBRL Taxonomy Extension Definition Linkbase.

Filed herewith.

101 LAB

Inline XBRL Taxonomy Extension Label Linkbase.

Filed herewith.

101 PRE

Inline XBRL Taxonomy Extension Presentation Linkbase.

Filed herewith.

104

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

Filed herewith.

7789

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/ ~~ALBERTO FORNARO~~WOO-SUNG CHUNG

~~Alberto Fornaro~~Woo-Sung Chung

Chief Financial Officer

(Principal Financial Officer)

/s/ EMILY PICARELLO

Emily Picarello

Date: November ~~7, 2022~~2, 2023

Corporate Controller

(Principal Accounting Officer)

7890


CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION			3
GLOSSARY OF TERMS			5
PART I — FINANCIAL INFORMATION			8
ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES			8
ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			3850
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			7385
ITEM 4 — CONTROLS AND PROCEDURES			7587
PART II — OTHER INFORMATION			7688
ITEM 1 — LEGAL PROCEEDINGS			7688
ITEM 1A — RISK FACTORS			7688
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			7688
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES			7688
ITEM 4 — MINE SAFETY DISCLOSURES			7688
ITEM 5 — OTHER INFORMATION			7688
ITEM 6 — EXHIBITS			7789
SIGNATURES			7890


	September 30, 2022		December 31, 2021
(In millions, except share data)	(Unaudited)		(Audited)
ASSETS
Current Assets
Cash and cash equivalents	$	333	$	250
Funds deposited by counterparties	3,134		845
Restricted cash	46		15
Accounts receivable, net	4,061		3,245
Uplift securitization proceeds receivable from ERCOT	—		689
Inventory	772		498
Derivative instruments	9,938		4,613
Cash collateral paid in support of energy risk management activities	262		291

Prepayments and other current assets	417		395


Total current assets	18,963		10,841
Property, plant and equipment, net	1,598		1,688
Other Assets
Equity investments in affiliates	126		157

Operating lease right-of-use assets, net	236		271
Goodwill	1,650		1,795
Intangible assets, net	2,227		2,511
Nuclear decommissioning trust fund	789		1,008
Derivative instruments	4,914		2,527
Deferred income taxes	1,516		2,155
Other non-current assets	224		229


Total other assets	11,682		10,653
Total Assets	$	32,243	$	23,182

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities

Current portion of long-term debt and finance leases	$	62	$	4

Current portion of operating lease liabilities	82		81
Accounts payable	2,871		2,274

Derivative instruments	6,841		3,387
Cash collateral received in support of energy risk management activities	3,134		845
Accrued expenses and other current liabilities	1,376		1,324



Total current liabilities	14,366		7,915
Other Liabilities
Long-term debt and finance leases	7,974		7,966
Non-current operating lease liabilities	197		236
Nuclear decommissioning reserve	335		321
Nuclear decommissioning trust liability	433		666

Derivative instruments	2,802		1,412
Deferred income taxes	84		73
Other non-current liabilities	922		993


Total other liabilities	12,747		11,667
Total Liabilities	27,113		19,582

Commitments and Contingencies
Stockholders' Equity
Common stock; $0.01 par value; 500,000,000 shares authorized; 423,894,539 and 423,547,174 shares issued and 232,125,137 and 243,753,899 shares outstanding at September 30, 2022 and December 31, 2021, respectively	4		4
Additional paid-in-capital	8,450		8,531
Retained earnings	2,584		464
Treasury stock, at cost 191,769,402 and 179,793,275 shares at September 30, 2022 and December 31, 2021, respectively	(5,754)		(5,273)
Accumulated other comprehensive loss	(154)		(126)

Total Stockholders' Equity	5,130		3,600
Total Liabilities and Stockholders' Equity	$	32,243	$	23,182


	As of September 30, 2022							As of December 31, 2021
(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	$	17	$	—	$	—	—	$	33	$	—	$	—	—
U.S. government and federal agency obligations	85		—		10		11	112		5		1		10
Federal agency mortgage-backed securities	101		—		12		25	100		2		—		25
Commercial mortgage-backed securities	37		—		4		28	44		1		—		27
Corporate debt securities	104		—		15		13	122		7		1		14
Equity securities	443		301		—		—	593		456		—		—
Foreign government fixed income securities	2		—		—		18	4		—		—		13
Total	$	789	$	301	$	41		$	1,008	$	471	$	2


	Total number of shares and share equivalents purchased	Average price paid per share and share equivalent	Amounts paid for shares and share equivalents purchased (in millions)
2022 repurchases
Repurchases(a)	12,045,068		$	483
Equivalent shares purchased in lieu of tax withholdings on equity compensation issuances(b)	150,448		6

Total Share Repurchases during the nine months ended September 30, 2022	12,195,516	$40.07	489
Repurchases made during October(a)	1,817,278		$	76
Equivalent shares purchased in October in lieu of tax withholdings on equity compensation issuances(b)	793		—
Total Share Repurchases January 1, 2022 through October 31, 2022	14,013,587	$40.28	$	565


	Average Realized Power Price ($/MWh)
	Three months ended September 30,
Segment	2022		2021		Change %
East(a)	$	58.95	$	37.26	58	%
West/Services/Other	96.93		50.31		93	%