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, 2024

☐

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, 2024, there were 202,566,373 shares of common stock outstanding, par value $0.01 per share.

TABLE OF CONTENTS

Index


CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION			3
GLOSSARY OF TERMS			5
PART I — FINANCIAL INFORMATION			8
ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES			8
ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			48
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			84
ITEM 4 — CONTROLS AND PROCEDURES			86
PART II — OTHER INFORMATION			87
ITEM 1 — LEGAL PROCEEDINGS			87
ITEM 1A — RISK FACTORS			87
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			87
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES			87
ITEM 4 — MINE SAFETY DISCLOSURES			87
ITEM 5 — OTHER INFORMATION			88
ITEM 6 — EXHIBITS			89
SIGNATURES			90

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," "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 II, Item 1A of this Form 10-Q and the following:

•Business uncertainties related to NRG's ability to integrate the operations of Vivint Smart Home;

•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, including the impacts of weather;

•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 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;

•Changes in law, including judicial and regulatory decisions;

•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:


2023 Form 10-K						NRG’s Annual Report on Form 10-K for the year ended December 31, 2023
ACE						Affordable Clean Energy
Adjusted EBITDA						Adjusted earnings before interest, taxes, depreciation and amortization
AESO						Alberta Electric System Operator

ASC						The FASB Accounting Standards Codification, which the FASB established as the source of authoritative GAAP
ASR						Accelerated Share Repurchase
ASU						Accounting Standards Updates - updates to the ASC
BTU						British Thermal Unit
Business						NRG Business, which serves business customers
CAA						Clean Air Act
CAISO						California Independent System Operator
CAMT						15% Corporate Alternative Minimum Tax enacted by the IRA on August 16, 2022
CDD						Cooling Degree Day

CFTC						U.S. Commodity Futures Trading Commission

CO2						Carbon Dioxide
Company						NRG Energy, Inc.
Convertible Senior Notes						As of September 30, 2024, consists of NRG’s $232 million unsecured 2.75% Convertible Senior Notes due 2048
Constellation						Constellation Energy Generation
Cottonwood						Cottonwood Generating Station, a natural gas-fueled plant located in Deweyville, Texas, which NRG is leasing through May 2025
CPP						Clean Power Plan

CWA						Clean Water Act
D.C. Circuit						U.S. Court of Appeals for the District of Columbia Circuit
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
ELG						Effluent Limitations Guidelines
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
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 solar thermal power plant located in California's Mojave Desert in which NRG owns 54.5% interest
kWh						Kilowatt-hour

LTIPs						Collectively, the NRG long-term incentive plan ("LTIP") and the 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 Rates						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						Prior to the sale of STP on November 1, 2023, nuclear decommissioning trust fund assets, for NRG's portion of the decommissioning of the STP units 1 & 2
NYISO						New York Independent System Operator
NYMEX						New York Mercantile Exchange


OECD						Organization for Economic Cooperation and Development
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 $2.3 billion accounts receivables securitization facility due 2025, which was last amended on June 21, 2024
Receivables Securitization Facilities						Collectively, the Receivables Facility and the Repurchase Facility
RECs						Renewable Energy Certificates
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 2024, which was terminated on June 21, 2024
Revolving Credit Facility						The Company's $4.2 billion revolving credit facility due 2029, which was last amended on October 30, 2024
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 Credit Facility						NRG's senior secured credit facility, comprised of the Revolving Credit Facility and the Term Loan B Facility
Senior Notes						As of September 30, 2024, NRG's $3.9 billion outstanding unsecured senior notes consisting of $375 million of the 6.625% senior notes due 2027, $821 million of 5.750% senior notes due 2028, $733 million of the 5.250% 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 $480 million of the 3.875% senior notes due 2032
Senior Secured First Lien Notes						As of September 30, 2024, NRG’s $2.6 billion outstanding Senior Secured First Lien Notes consists of $500 million of the 2.000% Senior Secured First Lien Notes due 2025, $900 million of the 2.450% Senior Secured First Lien Notes due 2027, $500 million of the 4.450% Senior Secured First Lien Notes due 2029 and $740 million of the 7.000% Senior Secured First Lien Notes due 2033
Series A Preferred Stock						As of September 30, 2024, NRG's Series A Preferred Stock consists of 650,000 outstanding shares of the 10.25% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock, with a $1,000 liquidation preference per share
Services						NRG Services, which primarily includes the services businesses acquired in the Direct Energy acquisition and the Goal Zero business

SO2						Sulfur Dioxide
SOFR						Secured overnight financing rate
STP						South Texas Project — a nuclear generating facility located near Bay City, Texas in which NRG owned a 44% interest. NRG closed on the sale of its interest in STP on November 1, 2023

TDSP						Transmission/distribution service provider

TWh						Terawatt Hour
U.S.						United States of America
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,
(In millions, except for per share amounts)	2024		2023		2024		2023
Revenue
Revenue	$	7,223	$	7,946	$	21,311	$	22,016
Operating Costs and Expenses
Cost of operations (excluding depreciation and amortization shown below)	7,239		6,406		17,229		20,137
Depreciation and amortization	352		359		1,045		921
Impairment losses	—		—		15		—
Selling, general and administrative costs (excluding amortization of customer acquisition costs of $55, $36, $144 and $84, respectively, which are included in depreciation and amortization shown separately above)	645		602		1,739		1,502

Acquisition-related transaction and integration costs	7		18		22		111
Total operating costs and expenses	8,243		7,385		20,050		22,671

Gain on sale of assets	208		—		209		202
Operating (Loss)/Income	(812)		561		1,470		(453)
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates	6		6		13		16

Other income, net	5		14		38		43
Loss on debt extinguishment	—		—		(260)		—
Interest expense	(213)		(173)		(528)		(472)
Total other expense	(202)		(153)		(737)		(413)
(Loss)/Income Before Income Taxes	(1,014)		408		733		(866)
Income tax (benefit)/expense	(247)		65		251		(182)


Net (Loss)/Income	$	(767)	$	343	$	482	$	(684)
Less: Cumulative dividends attributable to Series A Preferred Stock	17		17		51		38
Net (Loss)/Income Available for Common Stockholders	$	(784)	$	326	$	431	$	(722)
(Loss)/Income per Share
Weighted average number of common shares outstanding — basic	207		230		207		230


(Loss)/Income per Weighted Average Common Share — Basic	$	(3.79)	$	1.42	$	2.08	$	(3.14)
Weighted average number of common shares outstanding — diluted	207		232		213		230


(Loss)/Income per Weighted Average Common Share —Diluted	$	(3.79)	$	1.41	$	2.02	$	(3.14)

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS)/INCOME

(Unaudited)


	Three months ended September 30,				Nine months ended September 30,
(In millions)	2024		2023		2024		2023
Net (Loss)/Income	$	(767)	$	343	$	482	$	(684)
Other Comprehensive (Loss)/Income

Foreign currency translation adjustments	6		(8)		(4)		—

Defined benefit plans	(8)		1		(10)		—
Other comprehensive (loss)/income	(2)		(7)		(14)		—
Comprehensive (Loss)/Income	$	(769)	$	336	$	468	$	(684)

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS


	September 30, 2024		December 31, 2023
(In millions, except share data)	(Unaudited)		(Audited)
ASSETS
Current Assets
Cash and cash equivalents	$	1,104	$	541
Funds deposited by counterparties	12		84
Restricted cash	10		24
Accounts receivable, net	3,258		3,542

Inventory	540		607
Derivative instruments	2,456		3,862
Cash collateral paid in support of energy risk management activities	449		441

Prepayments and other current assets	782		626


Total current assets	8,611		9,727
Property, plant and equipment, net	1,818		1,763
Other Assets
Equity investments in affiliates	49		42

Operating lease right-of-use assets, net	172		179
Goodwill	5,018		5,079
Customer relationships, net	1,648		2,164
Other intangible assets, net	1,439		1,763

Derivative instruments	1,747		2,293
Deferred income taxes	2,098		2,251
Other non-current assets	1,124		777


Total other assets	13,295		14,548
Total Assets	$	23,724	$	26,038


	September 30, 2024		December 31, 2023
(In millions, except share data)	(Unaudited)		(Audited)
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities

Current portion of long-term debt and finance leases	$	258	$	620

Current portion of operating lease liabilities	77		90
Accounts payable	1,994		2,325

Derivative instruments	2,351		4,019
Cash collateral received in support of energy risk management activities	12		84
Deferred revenue current	761		720
Accrued expenses and other current liabilities	1,895		1,642



Total current liabilities	7,348		9,500
Other Liabilities
Long-term debt and finance leases	10,422		10,133
Non-current operating lease liabilities	125		128



Derivative instruments	1,469		1,488
Deferred income taxes	8		22
Deferred revenue non-current	919		914
Other non-current liabilities	913		947


Total other liabilities	13,856		13,632
Total Liabilities	21,204		23,132

Commitments and Contingencies
Stockholders' Equity
Preferred stock; 10,000,000 shares authorized; 650,000 Series A shares issued and outstanding at September 30, 2024 and December 31, 2023, aggregate liquidation preference of $650 at September 30, 2024 and December 31, 2023	650		650
Common stock; $0.01 par value; 500,000,000 shares authorized; 264,056,285 and 267,330,470 shares issued and 204,929,327 and 208,130,950 shares outstanding at September 30, 2024 and December 31, 2023, respectively	3		3
Additional paid-in-capital	3,145		3,416
Retained earnings	977		820
Treasury stock, at cost; 59,126,958 shares and 59,199,520 shares at September 30, 2024 and December 31, 2023, respectively	(2,150)		(1,892)
Accumulated other comprehensive loss	(105)		(91)

Total Stockholders' Equity	2,520		2,906
Total Liabilities and Stockholders' Equity	$	23,724	$	26,038

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Nine months ended September 30,
(In millions)	2024		2023
Cash Flows from Operating Activities
Net Income/(Loss)	$	482	$	(684)


Adjustments to reconcile net income/(loss) to cash provided/(used) by operating activities:
Equity in and distributions from earnings of unconsolidated affiliates	(6)		(16)
Depreciation of property, plant and equipment and amortization of customer relationships and other intangible assets	814		813
Amortization of capitalized contract costs	231		108
Accretion of asset retirement obligations	29		14
Provision for credit losses	228		165
Amortization of nuclear fuel	—		42
Amortization of financing costs and debt discounts	32		42
Loss on debt extinguishment	260		—
Amortization of in-the-money contracts and emissions allowances	83		111
Amortization of unearned equity compensation	82		87
Net gain on sale of assets and disposal of assets	(197)		(187)

Impairment losses	15		—
Changes in derivative instruments	268		1,553
Changes in current and deferred income taxes and liability for uncertain tax benefits	134		(225)
Changes in collateral deposits in support of risk management activities	(80)		(1,188)
Changes in nuclear decommissioning trust liability	—		(4)


Changes in other working capital	(1,021)		(1,093)
Cash provided/(used) by operating activities	$	1,354	$	(462)


Cash Flows from Investing Activities
Payments for acquisitions of businesses and assets, net of cash acquired	$	(33)	$	(2,502)
Capital expenditures	(286)		(493)

Net purchases of emissions allowances	(16)		(25)
Investments in nuclear decommissioning trust fund securities	—		(293)
Proceeds from the sale of nuclear decommissioning trust fund securities	—		280
Proceeds from sales of assets, net of cash disposed	495		229
Proceeds from insurance recoveries for property, plant and equipment, net	3		173



Cash provided/(used) by investing activities	$	163	$	(2,631)


	Nine months ended September 30,
(In millions)	2024		2023
Cash Flows from Financing Activities
Proceeds from issuance of preferred stock, net of fees	$	—	$	635
Payments of dividends to preferred and common stockholders	(322)		(295)
Equivalent shares purchased in lieu of tax withholdings	(45)		(19)
Payments for share repurchase activity	(316)		(50)
Net (payments)/receipts from settlement of acquired derivatives that include financing elements	(2)		332
Net proceeds of Revolving Credit Facility and Receivable Securitization Facilities	—		300
Proceeds from issuance of long-term debt	875		731
Payments of debt issuance costs	(13)		(29)
Repayments of long-term debt and finance leases	(960)		(15)
Payments for debt extinguishment costs	(258)		—



Proceeds from credit facilities	1,050		3,020
Repayments to credit facilities	(1,050)		(3,020)
Cash (used)/provided by financing activities	$	(1,041)	$	1,590


Effect of exchange rate changes on cash and cash equivalents	1		—

Net Increase/(Decrease) in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash	477		(1,503)
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period	649		2,178
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	$	1,126	$	675

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(Unaudited)


(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, 2023	$	650	$	3	$	3,416	$	820	$	(1,892)	$	(91)	$	2,906
Net income							511						511

Other comprehensive loss											(9)		(9)


Share repurchases(a)					117				(117)				—
Retirement of treasury stock(b)					(38)				38				—
Equity-based awards activity, net(c)					8								8

Common stock dividends and dividend equivalents declared(d)							(86)						(86)


Series A Preferred Stock dividends(e)							(33)						(33)


Balance at March 31, 2024	$	650	$	3	$	3,503	$	1,212	$	(1,971)	$	(100)	$	3,297
Net income							738						738
Other comprehensive loss											(3)		(3)
Shares reissuance for ESPP					1				5				6
Share repurchases(f)									(91)				(91)
Retirement of treasury stock(b)					(38)				38				—
Equity-based awards activity, net(c)					16								16

Common stock dividends and dividend equivalents declared(d)							(87)						(87)
Capped Call Options(g)					(253)								(253)
Balance at June 30, 2024	$	650	$	3	$	3,229	$	1,863	$	(2,019)	$	(103)	$	3,623
Net loss							(767)						(767)
Other comprehensive loss											(2)		(2)
Share repurchases(f)									(231)				(231)
Retirement of treasury stock(b)					(100)				100				—
Equity-based awards activity, net(c)					16								16

Common stock dividends and dividend equivalents declared(d)							(86)						(86)
Series A Preferred Stock dividends(e)							(33)						(33)
Balance at September 30, 2024	$	650	$	3	$	3,145	$	977	$	(2,150)	$	(105)	$	2,520

(a)Represents the final settlements of the November 6, 2023 ASR agreements. See Note 9, Changes in Capital Structure for additional information

(b)For further discussion of the treasury stock retirements, see Note 9, Changes in Capital Structure

(c)Includes $(10) million, $(12) million and $(23) million of equivalent shares purchased in lieu of tax withholding on equity compensation issuances for the quarters ended September 30, June 30 and March 31, 2024, respectively

(d)Dividends per common share were $0.4075 for each of the quarters ended September 30, June 30 and March 31, 2024

(e)Dividends per share of Series A Preferred Stock were $51.25 for each of the periods ended September 15 and March 15, 2024

(f)Includes excise tax accrued of $2 million and $1 million for the quarters ended September 30 and June 30, 2024, respectively

(g)For further discussion of the Capped Call Options, see Note 9, Changes in Capital Structure


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


Equity-based awards activity, net(h)					38								38

Common stock dividends and dividend equivalents declared(i)							(88)						(88)

Balance at March 31, 2023	$	650	$	4	$	8,481	$	(15)	$	(5,864)	$	(176)	$	3,080
Net income							308						308
Issuance of Series A Preferred Stock					(1)								(1)
Other comprehensive income											6		6
Shares reissuance for ESPP					1				3				4

Equity-based awards activity, net(h)					23								23

Common stock dividends and dividend equivalents declared(i)							(88)						(88)






Balance at June 30, 2023	$	650	$	4	$	8,504	$	205	$	(5,861)	$	(170)	$	3,332
Net income							343						343
Other comprehensive loss											(7)		(7)

Share repurchases									(50)				(50)
Equity-based awards activity, net(h)					23								23

Common stock dividends and dividend equivalents declared(i)							(89)						(89)



Series A Preferred Stock dividends(j)							(34)						(34)

Balance at September 30, 2023	$	650	$	4	$	8,527	$	425	$	(5,911)	$	(177)	$	3,518

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

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

(j)Dividend per share of Series A Preferred Stock was $52.96

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 — Nature of Business and Basis of Presentation

General

NRG Energy, Inc., or NRG or the Company, sits at the intersection of energy and home services. NRG is a leading energy and home services company fueled by market-leading brands, proprietary technologies, and complementary sales channels. Across the United States and Canada, NRG delivers innovative, sustainable solutions, predominately under brand names such as NRG, Reliant, Direct Energy, Green Mountain Energy and Vivint, while also advocating for competitive energy markets and customer choice. The Company has a customer base that includes approximately 8 million residential consumers in addition to commercial, industrial, and wholesale customers, supported by approximately 13 GW of generation as of September 30, 2024.

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 and (iii) activity related to the Cottonwood facility and other investments;

•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 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 2023 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, 2024, and the results of operations, comprehensive (loss)/income, cash flows and stockholders' equity for the three and nine months ended September 30, 2024 and 2023.

The Company identified an error in the previously issued condensed consolidated financial statements for the period ended September 30, 2023 related to the presentation of cash flows associated with certain borrowings and repayments related to certain credit facilities. The statement of cash flows for the period ended September 30, 2023 has been adjusted to present on a gross basis the certain borrowings from credit facilities of $3.0 billion and the related repayments of $3.0 billion. The change had no impact to the total cash used by financing activities for the period ended September 30, 2023. The Company evaluated the materiality of this error both qualitatively and quantitatively and has concluded it is immaterial to the impacted period.

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 of operations, net assets or consolidated cash flows.

Presentation Adjustments

As of September 30, 2024, the Company is recording the amortization of capitalized contracts costs within depreciation and amortization. This change, along with additional financial statement disclosures, is meant to address investor inquiries by enhancing transparency to easier match expenses with revenues. NRG previously recorded amortization of capitalized contract costs related to fulfillment in cost of operations and amortization of capitalized contract costs related to customer acquisition primarily in selling, general and administrative costs in the consolidated statements of operations.

The following table presents adjustments within the condensed consolidated statement of operations for the three and nine months ended September 30, 2023 related to capitalized contract costs:


(In millions)	As Previously Presented		Presentation Adjustments		As Adjusted
Three months ended September 30, 2023
Cost of operations (excluding depreciation and amortization shown below)	$	6,421	$	(15)	$	6,406
Depreciation and amortization	308		51		359
Selling, general and administrative costs	638		(36)		602
Nine months ended September 30, 2023
Cost of operations (excluding depreciation and amortization shown below)	$	20,161	$	(24)	$	20,137
Depreciation and amortization	813		108		921
Selling, general and administrative costs	1,586		(84)		1,502

The following table presents adjustments within the condensed consolidated statement of cash flows for the nine months ended September 30, 2023 related to capitalized contract costs:


(In millions)	As Previously Presented		Presentation Adjustments		As Adjusted
Nine months ended September 30, 2023
Cash flows from operating activities:
Amortization of capitalized contract costs	$	—	$	108	$	108
Changes in other working capital	(985)		(108)		(1,093)

Note 2 — Summary of Significant Accounting Policies

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 are included in depreciation and amortization in the condensed 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.

Depreciation and Amortization

The Company's depreciation and amortization included in the condensed consolidated statement of operations consisted of the following:


	Three months ended September 30,				Nine months ended September 30,
(In millions)	2024		2023		2024		2023
Amortization of capitalized contract costs related to fulfillment	$	34	$	14	$	82	$	20
Amortization of capitalized contract costs related to customer acquisition	57		37		149		88
Amortization of customer relationships and other intangible assets	192		244		610		623
Depreciation of property, plant and equipment	69		64		204		190
Total depreciation and amortization	$	352	$	359	$	1,045	$	921

Credit Losses

Retail trade receivables are reported on the consolidated balance sheet net of the allowance for credit losses within accounts receivables, net. Long-term receivables are recorded net of allowance for credit losses 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, 2024 and 2023:


	Three months ended September 30,				Nine months ended September 30,
(In millions)	2024		2023		2024		2023
Beginning balance	$	127	$	120	$	145	$	133
Acquired balance from Vivint Smart Home	—		—		—		22
Provision for credit losses	95		85		228		165
Write-offs	(74)		(59)		(252)		(203)
Recoveries collected	9		9		28		30
Other	7		3		15		11
Ending balance	$	164	$	158	$	164	$	158

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)	September 30, 2024		December 31, 2023
Property, plant and equipment accumulated depreciation	$	1,470	$	1,295
Customer relationships and other intangible assets accumulated amortization	3,435		2,994

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)	September 30, 2024		December 31, 2023
Cash and cash equivalents	$	1,104	$	541
Funds deposited by counterparties	12		84
Restricted cash	10		24
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows	$	1,126	$	649

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. 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 agreements and funds held within the Company's projects that are restricted in their uses.

Goodwill

The following table represents the changes in goodwill during the nine months ended September 30, 2024:


(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Total
Balance as of December 31, 2023	$	643	$	721	$	221	$	3,494	$	5,079

Impairment	—		—		(15)		—		(15)
Sale of Airtron	—		—		(44)		—		(44)
Foreign currency translation adjustments	—		—		(2)		—		(2)
Balance as of September 30, 2024	$	643	$	721	$	160	$	3,494	$	5,018

Recent Accounting Developments — Guidance Not Yet Adopted

ASU 2023-07 – In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280) – Improvements to Reportable Segment Disclosures, or ASU 2023-07. The guidance in ASU 2023-07 enhances reportable segment disclosure requirements by requiring disclosure of significant segment expenses that are regularly provided to the chief operating decision maker and included within each reported measure of segment profit and loss, an amount and description of its composition for other segment items and interim disclosures of a reportable segment’s profit or loss and assets. The Company plans to adopt the new guidance for the annual period ending December 31, 2024 and subsequent interim periods thereafter. The guidance will be applied retrospectively for all prior periods presented in the financial statements.

ASU 2023-09 – In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740) – Improvements to Income Tax Disclosures, or ASU 2023-09. The guidance in ASU 2023-09 enhances income tax disclosures by requiring disclosure of specific categories in the effective tax rate reconciliation and additional information for reconciling items that meet a quantitative threshold. Further the amendments of ASU 2023-09 require certain disclosures on income tax expense and income taxes paid. ASU 2023-09 is effective for annual periods beginning after December 15, 2024, with early adoption permitted. The amendments of ASU 2023-09 may be applied on a prospective or retrospective basis. The Company is currently evaluating the impact of adopting ASU 2023-09 on its disclosures.

ASU 2024-03 – In November 2024, the FASB issued ASU No. 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40) – Disaggregation of Income Statement Expenses, or ASU 2024-03. The guidance in ASU 2024-03 requires more detailed information about specified categories of expenses included in certain captions presented on the face of the income statement. This ASU is effective for annual periods beginning after December 15, 2026, and interim periods beginning after December 15, 2027. Early adoption is permitted. The amendments may be applied either (1) prospectively to financial statements issued for reporting periods after the effective date of this ASU or (2) retrospectively to all prior periods presented in the financial statements. The Company is currently evaluating the impact of adopting ASU 2024-03 on its disclosures.

Note 3 — Revenue Recognition

Performance Obligations

As of September 30, 2024, estimated future fixed fee performance obligations are $421 million for the remaining three months of fiscal year 2024, and $1.4 billion, $1.1 billion, $757 million, $459 million and $190 million for the fiscal years 2025, 2026, 2027, 2028 and 2029, respectively. These performance obligations include Vivint Smart Home products and services, as well as cleared auction MWs in the PJM, ISO-NE, NYISO and MISO capacity auctions. The cleared auction MWs are subject to penalties for non-performance.

Disaggregated Revenues

The following tables represent the Company’s disaggregation of revenue from contracts with customers for the three and nine months ended September 30, 2024 and 2023:


	Three months ended September 30, 2024
(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue:
Home(a)	$	2,235	$	616	$	349	$	499	$	(4)	$	3,695
Business	996		1,852		411		—		—		3,259
Total retail revenue(b)	3,231		2,468		760		499		(4)		6,954
Energy revenue(b)	12		67		52		—		(3)		128
Capacity revenue(b)	—		40		8		—		(1)		47
Mark-to-market for economic hedging activities(c)	—		1		6		—		1		8
Contract amortization	—		(7)		(1)		—		—		(8)
Other revenue(b)	58		31		8		—		(3)		94
Total revenue	3,301		2,600		833		499		(10)		7,223
Less: Revenues accounted for under topics other than ASC 606 and ASC 815	—		14		13		—		—		27
Less: Realized and unrealized ASC 815 revenue	19		33		18		—		(1)		69
Total revenue from contracts with customers	$	3,282	$	2,553	$	802	$	499	$	(9)	$	7,127
(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)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue	$	—	$	6	$	—	$	—	$	—	$	6
Energy revenue	—		9		12		—		(3)		18
Capacity revenue	—		17		—		—		—		17
Other revenue	19		—		—		—		1		20
(c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815


	Three months ended September 30, 2023
(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue:
Home(a)	$	2,397	$	544	$	390	$	478	$	(1)	$	3,808
Business	1,092		2,089		532		—		—		3,713
Total retail revenue(b)	3,489		2,633		922		478		(1)		7,521
Energy revenue(b)	51		152		59		—		(1)		261
Capacity revenue(b)	—		64		(4)		—		(1)		59
Mark-to-market for economic hedging activities(c)	—		(60)		(10)		—		—		(70)
Contract amortization	—		(6)		1		—		—		(5)
Other revenue(b)	146		26		10		—		(2)		180
Total revenue	3,686		2,809		978		478		(5)		7,946
Less: Revenues accounted for under topics other than ASC 606 and ASC 815	—		8		10		—		—		18
Less: Realized and unrealized ASC 815 revenue	16		58		(7)		—		—		67
Total revenue from contracts with customers	$	3,670	$	2,743	$	975	$	478	$	(5)	$	7,861
(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)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue	$	—	$	14	$	—	$	—	$	—	$	14
Energy revenue	—		77		—		—		—		77
Capacity revenue	—		27		—		—		—		27
Other revenue	16		—		3		—		—		19
(c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815


	Nine months ended September 30, 2024
(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue:
Home(a)	$	5,361	$	1,855	$	1,362	$	1,434	$	(12)	$	10,000
Business	2,740		6,402		1,385		—		—		10,527
Total retail revenue(b)	8,101		8,257		2,747		1,434		(12)		20,527
Energy revenue(b)	35		194		170		—		(9)		390
Capacity revenue(b)	—		120		16		—		(3)		133
Mark-to-market for economic hedging activities(c)	—		15		14		—		3		32
Contract amortization	—		(23)		(2)		—		—		(25)
Other revenue(b)	161		84		17		—		(8)		254
Total revenue	8,297		8,647		2,962		1,434		(29)		21,311
Less: Revenues accounted for under topics other than ASC 606 and ASC 815	—		36		38		—		—		74
Less: Realized and unrealized ASC 815 revenue	29		165		60		—		(4)		250
Total revenue from contracts with customers	$	8,268	$	8,446	$	2,864	$	1,434	$	(25)	$	20,987
(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)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue	$	—	$	25	$	—	$	—	$	—	$	25
Energy revenue	—		67		50		—		(8)		109
Capacity revenue	—		58		—		—		—		58
Other revenue	29		—		(4)		—		1		26
(c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815


	Nine months ended September 30, 2023
(In millions)	Texas		East		West/Services/Other		Vivint Smart Home(a)		Corporate/Eliminations		Total
Retail revenue:
Home(b)	$	5,196	$	1,641	$	1,421	$	1,070	$	(1)	$	9,327
Business	2,646		7,366		1,572		—		—		11,584
Total retail revenue(c)	7,842		9,007		2,993		1,070		(1)		20,911
Energy revenue(c)	71		254		147		—		—		472
Capacity revenue(c)	—		154		(3)		—		(1)		150
Mark-to-market for economic hedging activities(d)	—		27		80		—		(11)		96
Contract amortization	—		(24)		—		—		—		(24)
Other revenue(c)	322		70		27		—		(8)		411
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	—		13		26		—		—		39
Less: Realized and unrealized ASC 815 revenue	28		270		97		—		(10)		385
Total revenue from contracts with customers	$	8,207	$	9,205	$	3,121	$	1,070	$	(11)	$	21,592
(a) Includes results of operations following the acquisition date of March 10, 2023
(b) Home includes Services
(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)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue	$	—	$	57	$	—	$	—	$	—	$	57
Energy revenue	—		137		10		—		1		148
Capacity revenue	—		50		—		—		—		50
Other revenue	28		(1)		7		—		—		34
(d) 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, 2024 and December 31, 2023:


(In millions)	September 30, 2024		December 31, 2023
Capitalized contract costs (included in Prepayments and other current assets and Other non-current assets)	$	1,173	$	706

Accounts receivable, net - Contracts with customers	3,181		3,395
Accounts receivable, net - Accounted for under topics other than ASC 606	74		136
Accounts receivable, net - Affiliate	3		11
Total accounts receivable, net	$	3,258	$	3,542

Unbilled revenues (included within Accounts receivable, net - Contracts with customers)	$	1,318	$	1,493
Deferred revenues(a)	1,680		1,634

(a)Deferred revenues from contracts with customers were approximately $1.6 billion as of both September 30, 2024 and December 31, 2023

The revenue recognized from contracts with customers during the three months ended September 30, 2024 and 2023 relating to the deferred revenue balance at the beginning of each period was $290 million and $310 million, respectively, which decreased 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 nine months ended September 30, 2024 and 2023 relating to the deferred revenue balance at the beginning of each period was $511 million and $168 million, respectively, which increased primarily due to the acquisition of Vivint Smart Home.

Note 4 — Acquisitions and Dispositions

Acquisitions

Acquisition of Vivint Smart Home

On March 10, 2023, the Company 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 Company (“Merger Sub”) pursuant to which Merger Sub merged with and into Vivint Smart Home, Inc., with Vivint Smart Home, Inc. surviving the merger as a wholly-owned subsidiary of the Company. Dedicated to redefining the home experience with intelligent products and services, Vivint Smart Home brought approximately two million subscribers to NRG. Vivint Smart Home's single, expandable platform incorporates artificial intelligence and machine learning into its operating system and its vertically integrated business model includes hardware, software, sales, installation, customer service and technical support and professional monitoring, enabling superior subscriber experiences and a complete end-to-end smart home experience. The acquisition accelerated the realization of NRG's consumer-focused growth strategy and created 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 approximately $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.

The acquisition has been recorded as a business combination under ASC 805, with identifiable assets and liabilities acquired recorded at their estimated Acquisition Closing Date fair value. 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

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 consolidated statement of operations.

For additional information, refer to Note 4, Acquisitions and Dispositions, to the Company's 2023 Form 10-K.

Dispositions

Sale of Airtron

On September 16, 2024, the Company closed on the sale of its 100% ownership in the Airtron business unit. Proceeds of $500 million were reduced by working capital and other adjustments of $16 million, resulting in net proceeds of $484 million. The Company recorded a gain on the sale of $208 million within the West/Services/Other region of operations.

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 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 proceeds of $212 million, subject to transaction fees of $3 million and certain indemnifications, resulting in a $199 million gain.

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 long-term debt, including current portion, is as follows:


	September 30, 2024				December 31, 2023
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value




Convertible Senior Notes	$	232	$	515	$	575	$	739

Other long-term debt, including current portion	10,497		10,412		10,219		9,835
Total long-term debt, including current portion(a)	$	10,729	$	10,927	$	10,794	$	10,574

(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, the Term Loans and Vivint Senior Secured Term Loan (as defined in Note 7, Long-term Debt and Finance Leases) are based on quoted market prices and are classified as Level 2 within the fair value hierarchy.

Recurring Fair Value Measurements

Debt securities, 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, 2024
	Fair Value
(In millions)	Total		Level 1		Level 2		Level 3
Investments in securities (classified within other current and non-current assets)	$	26	$	—	$	26	$	—



Derivative assets:
Interest rate contracts	2		—		2		—
Foreign exchange contracts	5		—		5		—
Commodity contracts	4,196		626		3,384		186


Equity securities measured using net asset value practical expedient (classified within other non-current assets)	6
Total assets	$	4,235	$	626	$	3,417	$	186
Derivative liabilities:
Interest rate contracts	$	30	$	—	$	30	$	—
Foreign exchange contracts	2		—		2		—
Commodity contracts	3,588		654		2,722		212
Consumer Financing Program	200		—		—		200
Total liabilities	$	3,820	$	654	$	2,754	$	412


	December 31, 2023
	Fair Value
(In millions)	Total		Level 1		Level 2		Level 3
Investments in securities (classified within other current and non-current assets)	$	21	$	—	$	21	$	—


Derivative assets:
Interest rate contracts	12		—		12		—
Foreign exchange contracts	5		—		5		—
Commodity contracts	6,138		1,334		4,470		334



Equity securities measured using net asset value practical expedient (classified within other non-current assets)	6
Total assets	$	6,182	$	1,334	$	4,508	$	334
Derivative liabilities:
Interest rate contracts	$	8	$	—	$	8	$	—
Foreign exchange contracts	9		—		9		—
Commodity contracts	5,356		1,413		3,728		215
Consumer Financing Program	134		—		—		134
Total liabilities	$	5,507	$	1,413	$	3,745	$	349

The following table reconciles, for the three and nine months ended September 30, 2024 and 2023, the beginning and ending balances for financial instruments that are recognized at fair value in the condensed consolidated financial statements, using significant unobservable inputs, for commodity derivatives:


	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Commodity Derivatives(a)
(In millions)	Three months ended September 30, 2024		Three months ended September 30, 2023		Nine months ended September 30, 2024		Nine months ended September 30, 2023
Beginning balance	$	121	$	905	$	119	$	505

Total (losses)/gains realized/unrealized included in earnings	(83)		5		(120)		(172)
Purchases	(38)		(115)		(7)		25
Transfers into Level 3(b)	(19)		(374)		(2)		64
Transfers out of Level 3(b)	(7)		—		(16)		(1)
Ending balance	$	(26)	$	421	$	(26)	$	421
(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	$	(41)	$	75	$	(70)	$	(56)

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

(b)Transfers into/out of Level 3 within the fair value hierarchy are related to the availability of consensus pricing and external broker quotes and are valued as of the end of the reporting period. All transfers in/out of Level 3 are from/to Level 2

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

The following table reconciles, for the three and nine months ended September 30, 2024 and 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, 2024		Three months ended September 30, 2023		Nine months ended September 30, 2024		Nine months ended September 30, 2023
Beginning balance	$	(151)	$	(115)	$	(134)	$	—
Contractual obligations added from the acquisition of Vivint Smart Home	—		—		—		(112)
New contractual obligations	(63)		(33)		(121)		(55)
Settlements	21		21		64		43
Total losses included in earnings	(7)		(1)		(9)		(4)
Ending balance	$	(200)	$	(128)	$	(200)	$	(128)

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

Derivative Fair Value Measurements

The Company's contracts consist of non-exchange traded contracts valued using prices provided by external sources and exchange-traded contracts with readily available quoted market prices. Beginning in the fourth quarter of 2023 and as of September 30, 2024, the fair value of non-exchange traded contracts were primarily based on consensus pricing provided by independent pricing services. The pricing data was compiled from market makers with longer dated tenors as compared to broker quotes, enhancing reliability and increasing transparency. Prior to the fourth quarter of 2023, the Company valued derivatives based on price quotes from brokers in active markets who regularly facilitate those transactions. 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, 2024, contracts valued with prices provided by models and other valuation techniques made up 4% of derivative assets and 11% of derivative liabilities.

NRG's significant positions classified as Level 3 include physical and financial natural gas, power, capacity contracts and RECs executed in illiquid markets, FTRs and the Consumer Financing Program. 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. Forward capacity prices are based on market information, forecasted future electricity demand and supply, past auctions and internally developed pricing models. REC prices are based on market information and internally developed pricing models. 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.

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, 2024 and December 31, 2023:



	September 30, 2024
	Fair Value						Input/Range
(In millions, except as noted)	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low			High			Weighted Average
Natural Gas Contracts	$	38	$	27	Discounted Cash Flow	Forward Market Price ($ per MMBtu)	$	1		$	13		$	4
Power Contracts	75		138		Discounted Cash Flow	Forward Market Price ($ per MWh)	0			131			41
Capacity Contracts	27		12		Discounted Cash Flow	Forward Market Price ($ per MW/Day)	20			649			207
RECs	31		9		Discounted Cash Flow	Forward Market Price ($ per Certificate)	2			245			16
FTRs	15		26		Discounted Cash Flow	Auction Prices ($ per MWh)	(38)			8,434			0
Consumer Financing Program	—		200		Discounted Cash Flow	Collateral Default Rates	0.25		%	100.00		%	10.90		%
					Discounted Cash Flow	Collateral Prepayment Rates	2.00		%	3.00		%	2.86		%
					Discounted Cash Flow	Credit Loss Rates	4.70		%	60.00		%	13.88		%
	$	186	$	412



	December 31, 2023
	Fair Value						Input/Range
(In millions, except as noted)	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low			High			Weighted Average
Natural Gas Contracts	$	39	$	65	Discounted Cash Flow	Forward Market Price ($ per MMBtu)	$	1		$	15		$	3
Power Contracts	197		66		Discounted Cash Flow	Forward Market Price ($ per MWh)	1			210			47
Capacity Contracts	21		33		Discounted Cash Flow	Forward Market Price ($ per MW/Day)	49			658			285
RECs	58		14		Discounted Cash Flow	Forward Market Price ($ per Certificate)	2			320			15
FTRs	19		37		Discounted Cash Flow	Auction Prices ($ per MWh)	(58)			252			0
Consumer Financing Program	—		134		Discounted Cash Flow	Collateral Default Rates	0.43		%	93.30		%	8.12		%
					Discounted Cash Flow	Collateral Prepayment Rates	2.00		%	3.00		%	2.95		%
					Discounted Cash Flow	Credit Loss Rates	6.00		%	60.00		%	12.57		%
	$	334	$	349

The following table provides sensitivity of fair value measurements to increases/(decreases) in significant, unobservable inputs as of September 30, 2024 and December 31, 2023:

Significant Unobservable Input

Position

Change In Input

Impact on Fair Value Measurement

Forward Market Price Natural Gas/Power/Capacity/RECs

Buy

Increase/(Decrease)

Higher/(Lower)

Forward Market Price Natural Gas/Power/Capacity/RECs

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, 2024, the credit reserve resulted in a $2 million decrease primarily within cost of operations. As of December 31, 2023, the credit reserve resulted in a $18 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 2023 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 2023 Form 10-K. As of September 30, 2024, counterparty credit exposure, excluding credit exposure from RTOs, ISOs, registered commodity exchanges and certain long-term agreements, was $1.3 billion and NRG held collateral (cash and letters of credit) against those positions of $128 million, resulting in a net exposure of $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 30% of the Company's exposure before collateral is expected to roll off by the end of 2025. 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	75	%
Financial institutions	25

Total as of September 30, 2024	100	%


	Net Exposure (a)(b)
Category by Counterparty Credit Quality	(% of Total)
Investment grade	59	%
Non-investment grade/Non-Rated	41
Total as of September 30, 2024	100	%

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

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

The Company currently has no exposure to wholesale counterparties in excess of 10% of total net exposure as of September 30, 2024. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration.

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 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, 2024, aggregate credit risk exposure managed by NRG to these counterparties was approximately $890 million 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 forward value. The Company manages retail credit risk by using established credit policies, which include monitoring of the portfolio and the use of credit mitigation measures such as deposits or prepayment arrangements.

As of September 30, 2024, 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 their bills in a timely manner or at all, which could increase customer delinquencies and may lead to an increase in credit losses.

Note 6 — Accounting for Derivative Instruments and Hedging Activities

Energy-Related Commodities

As of September 30, 2024, 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 2037 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 2024, the Company entered into interest rate swaps with a total nominal value of $700 million extending through 2029 to hedge the floating rate of the Term Loans. Additionally, as of September 30, 2024, the Company had $1.0 billion of interest rate swaps extending through 2027 to hedge the floating rate of the Vivint Term Loans (as defined in Note 7, Long-term Debt and Finance Leases). In November 2024, in connection with the repayment of the Vivint Term Loans and the increase of the Term Loans, the Company decreased its interest rate swap notional value from $1.7 billion to $700 million.

Foreign Exchange Contracts

NRG is exposed to changes in foreign currency primarily associated with the purchase of U.S. dollar denominated natural gas for its Canadian business. To manage the Company's foreign exchange risk, NRG entered into foreign exchange contracts. As of September 30, 2024, NRG had foreign exchange contracts extending through 2028. 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. 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 Providers 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, 2024 and December 31, 2023. 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, 2024	December 31, 2023
Emissions	Short Ton	1	—
RECs	Certificates	12	12
Coal	Short Ton	11	9
Natural Gas	MMBtu	759	838
Oil	Barrels	1	—
Power	MWh	206	201
Interest	Dollars	1,700	1,000
Foreign Exchange	Dollars	433	548
Consumer Financing Program	Dollars	1,275	1,116

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, 2024		December 31, 2023		September 30, 2024		December 31, 2023




Derivatives Not Designated as Cash Flow or Fair Value Hedges:
Interest rate contracts - current	$	2	$	12	$	1	$	—
Interest rate contracts - long-term	—		—		29		8
Foreign exchange contracts - current	4		3		1		4
Foreign exchange contracts - long-term	1		2		1		5
Commodity contracts - current	2,450		3,847		2,234		3,922
Commodity contracts - long-term	1,746		2,291		1,354		1,434
Consumer Financing Program - short-term	—		—		115		93
Consumer Financing Program - long-term	—		—		85		41
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges	$	4,203	$	6,155	$	3,820	$	5,507

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, 2024
Interest rate contracts:
Derivative assets	$	2	$	(2)	$	—	$	—
Derivative liabilities	(30)		2		—		(28)
Total interest rate contracts	$	(28)	$	—	$	—	$	(28)
Foreign exchange contracts:
Derivative assets	$	5	$	(1)	$	—	$	4
Derivative liabilities	(2)		1		—		(1)
Total foreign exchange contracts	$	3	$	—	$	—	$	3
Commodity contracts:
Derivative assets	$	4,196	$	(3,224)	$	(6)	$	966
Derivative liabilities	(3,588)		3,224		166		(198)
Total commodity contracts	$	608	$	—	$	160	$	768
Consumer Financing Program:
Derivative liabilities	$	(200)	$	—	$	—	$	(200)
Total derivative instruments	$	383	$	—	$	160	$	543


	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, 2023
Interest rate contracts:
Derivative assets	$	12	$	(8)	$	—	$	4
Derivative liabilities	(8)		8		—		—
Total interest rate contracts	$	4	$	—	$	—	$	4
Foreign exchange contracts:
Derivative assets	$	5	$	(5)	$	—	$	—
Derivative liabilities	(9)		5		—		(4)
Total foreign exchange contracts	$	(4)	$	—	$	—	$	(4)
Commodity contracts:
Derivative assets	$	6,138	$	(4,926)	$	(74)	$	1,138
Derivative liabilities	(5,356)		4,926		145		(285)
Total commodity contracts	$	782	$	—	$	71	$	853
Consumer Financing Program:
Derivative liabilities	$	(134)	$	—	$	—	$	(134)


Total derivative instruments	$	648	$	—	$	71	$	719

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. 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.


(In millions)	Three months ended September 30,				Nine months ended September 30,
Unrealized mark-to-market results	2024		2023		2024		2023
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(414)	$	(522)	$	39	$	(1,519)
Reversal of acquired (gain)/loss positions related to economic hedges	(8)		(6)		(3)		4
Net unrealized (losses)/gains on open positions related to economic hedges	(1,208)		475		(319)		(418)
Total unrealized mark-to-market (losses) for economic hedging activities	(1,630)		(53)		(283)		(1,933)
Reversal of previously recognized unrealized (gains)/losses on settled positions related to trading activity	(1)		—		(1)		11

Net unrealized (losses)/gains on open positions related to trading activity	(4)		(1)		1		13
Total unrealized mark-to-market (losses)/gains for trading activity	(5)		(1)		—		24
Total unrealized (losses) - commodities and foreign exchange	$	(1,635)	$	(54)	$	(283)	$	(1,909)


	Three months ended September 30,				Nine months ended September 30,
(In millions)	2024		2023		2024		2023
Total impact to statement of operations - interest rate contracts	$	(49)	$	8	$	(31)	$	32
Unrealized gains/(losses) included in revenues - commodities	$	3	$	(71)	$	32	$	120
Unrealized (losses)/gains included in cost of operations - commodities	(1,633)		8		(321)		(2,024)
Unrealized (losses)/gains included in cost of operations - foreign exchange	(5)		9		6		(5)
Total impact to statement of operations - commodities and foreign exchange	$	(1,635)	$	(54)	$	(283)	$	(1,909)
Total impact to statement of operations - Consumer Financing Program	$	(7)	$	(1)	$	(9)	$	(4)

The reversals of acquired 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, 2024, the $319 million unrealized 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 power prices.

For the nine months ended September 30, 2023, the $418 million unrealized 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.

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, 2024 was $444 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 $31 million as of September 30, 2024. In the event of a downgrade in the Company's credit rating and if called for by the counterparty, $27 million of additional collateral would be required for all contracts with credit rating contingent features as of September 30, 2024.

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

Note 7 — Long-term Debt and Finance Leases

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


(In millions, except rates)	September 30, 2024		December 31, 2023		Interest rate %
Recourse debt:
Senior Notes, due 2027	$	375	$	375	6.625
Senior Notes, due 2028	821		821		5.750
Senior Notes, due 2029	733		733		5.250
Senior Notes, due 2029	500		500		3.375
Senior Notes, due 2031	1,030		1,030		3.625
Senior Notes, due 2032	480		480		3.875
Convertible Senior Notes, due 2048(a)	232		575		2.750
Senior Secured First Lien Notes, due 2024	—		600		3.750
Senior Secured First Lien Notes, due 2025	500		500		2.000
Senior Secured First Lien Notes, due 2027	900		900		2.450
Senior Secured First Lien Notes, due 2029	500		500		4.450
Senior Secured First Lien Notes, due 2033	740		740		7.000

Term Loan, due 2031	871		—		SOFR + 2.000


Tax-exempt bonds	466		466		1.250 - 4.750
Subtotal recourse debt	8,148		8,220
Non-recourse debt:
Vivint Senior Notes, due 2029	800		800		5.750
Vivint Senior Secured Notes, due 2027	600		600		6.750
Vivint Senior Secured Term Loan, due 2028	1,310		1,320		SOFR + 2.750
Subtotal all Vivint non-recourse debt	2,710		2,720
Subtotal long-term debt (including current maturities)	10,858		10,940
Finance leases	11		19		various
Subtotal long-term debt and finance leases (including current maturities)	10,869		10,959
Less current maturities	(258)		(620)
Less debt issuance costs	(60)		(60)
Discounts	(129)		(146)
Total long-term debt and finance leases	$	10,422	$	10,133

(a)As of the ex-dividend date of November 1, 2024, the Convertible Senior Notes were convertible at a price of $40.94, which is equivalent to a conversion rate of approximately 24.4241 shares of common stock per $1,000 principal amount

Recourse Debt

Issuance of 2029 Senior Notes, 2033 Senior Notes and 2034 Senior Notes

On October 30, 2024, the Company issued $1.9 billion in aggregate principal amount of senior unsecured notes, consisting of (i) $925 million aggregate principal amount of 6.000% senior unsecured notes due 2033 (the “2033 Notes”) and (ii) $950 million aggregate principal amount of 6.250% senior notes due 2034 (the “2034 Notes” and, together with the 2033 Notes, the “Notes”). In addition, on October 30, 2024, the Company issued $798 million aggregate principal amount of 5.750% senior unsecured notes due 2029 (the “New NRG 5.750% Senior Notes due 2029”) in connection with the Company’s previously announced offer to exchange. The Notes and the New NRG 5.750% Senior Notes due 2029 are senior unsecured obligations of the Company and are guaranteed by certain of its subsidiaries that guarantee indebtedness under the Senior Credit Facility. Interest on the New NRG 5.750% Senior Notes due 2029 is paid semi-annually beginning on January 15, 2025 until the maturity date of July 15, 2029. Interest on the 2033 Notes is paid semi-annually beginning on February 1, 2025 until the maturity date of February 1, 2033. Interest on the 2034 Notes is paid semi-annually beginning on May 1, 2025 until the maturity date of November 1, 2034.

On October 30, 2024, the Company used the net proceeds from the offering of the Notes, together with the net proceeds of its new incremental term loan B in an aggregate principal amount of $450 million, and cash on hand, to pay the cash tender price for any and all of APX Group, Inc.’s 6.750% Senior Secured Notes due 2027 and to repay the APX Group, Inc.'s secured

term loans in an outstanding aggregate principal amount of approximately $1.3 billion under its senior secured credit agreement. In addition, on October 31, 2024, the Company used the net proceeds from the offering of the Notes to redeem all of its outstanding 6.625% Senior Notes due 2027, of which $375 million aggregate principal amount was outstanding. Any remaining net proceeds from the offering will be used to pay the transaction fees, expenses and premiums, to refinance outstanding debt and for general corporate purposes.

Senior Credit Facility

Term Loan B Incurrence

On April 16, 2024, the Company, as borrower, and certain of its subsidiaries, as guarantors, entered into the Eighth Amendment to the Second Amended and Restated Credit Agreement (the “Eighth Amendment”) with, among others, Citicorp North America, Inc., as administrative agent (the “Agent”) and as collateral agent, and certain financial institutions, as lenders, which amended the Company’s Second Amended and Restated Credit Agreement, dated as of June 30, 2016 (as amended, restated, supplemented and/or otherwise modified from time to time, the “Credit Agreement”), in order to (i) establish a new term loan B facility with borrowings of $875 million in aggregate principal amount (the “Existing Term Loan B Facility” and the loans thereunder, the “Term Loans”) and (ii) make certain other modifications to the Credit Agreement as set forth therein. The proceeds from the Term Loans were used to repay a portion of the Company’s Convertible Senior Notes, all of the Company’s 3.750% senior secured first lien notes due 2024 and for general corporate purposes.

At the Company’s election, the Term Loans bear interest at a rate per annum equal to either (1) a fluctuating rate equal to the highest of (A) the rate published by the Federal Reserve Bank of New York in effect on such day, plus 0.50%, (B) the rate of interest per annum publicly announced from time to time by The Wall Street Journal as the “Prime Rate” in the United States, and (C) a rate of one-month Term SOFR (as defined in the Credit Agreement) (after giving effect to any floor applicable to Term SOFR) plus 1.00%, in each case, plus a margin of 1.00% or (2) Term SOFR (as defined in the Credit Agreement) (which shall not be less than 0.00%) for a one-, three- or six-month interest period (or such other period as agreed to by the Agent and the lenders, as selected by the Company), plus a margin of 2.00%.

On October 30, 2024, the Company, as borrower, and certain subsidiaries of the Company, as guarantors, entered into the Eleventh Amendment to the Second Amended and Restated Credit Agreement (the “Eleventh Amendment”) with, among others, the Agent and certain financial institutions, as lenders, which amended the Credit Agreement in order to include a new incremental term loan B in an aggregate principal amount of $450 million (the “Incremental Term Loan B Facility” and the loans thereunder, the “Incremental Term Loans”) which Incremental Term Loan B Facility is fungible for U.S. federal tax purposes with the Existing Term Loan B Facility. The proceeds from the Incremental Term Loans, together with the proceeds of the Notes, were used to repay all loans and other amounts outstanding under APX’s senior secured credit agreement and to fund the working capital needs and other general corporate purposes of the Company and its subsidiaries.

The terms of the Incremental Term Loan B Facility (including pricing) are identical to those applicable to, and the Incremental Term Loans constitute the same class of term loans as, the Company’s Existing Term Loan B Facility. At the Company’s election, the Incremental Term Loans bear interest at a rate per annum equal to either (1) a fluctuating rate equal to the highest of (A) the rate published by the Federal Reserve Bank of New York in effect on such day, plus 0.50%, (B) the rate of interest per annum publicly announced from time to time by The Wall Street Journal as the “Prime Rate” in the United States, and (C) a rate of one-month Term SOFR (as defined in the Credit Agreement), plus 1.00%, in each case, plus a margin of 1.00%, or (2) Term SOFR (as defined in the Credit Agreement) (which will not be less than 0.00%) for a one-, three- or six-month interest period (or such other period as agreed to by the Agent and the lenders, as selected by the Company), plus a margin of 2.00%.

The Existing Term Loan B Facility and the Incremental Term Loan B Facility are guaranteed by each of the Company’s subsidiaries that guarantee the Company’s Revolving Credit Facility and are secured on a first lien basis by substantially all of the Company’s and such subsidiaries’ assets, in each case, subject to certain customary exceptions and limitations set forth in the Credit Agreement.

The Existing Term Loan B Facility and Incremental Term Loan B Facility have a final maturity date of April 16, 2031 and amortize at a rate of 1% per annum in equal quarterly installments (subject to any adjustments to such amortization payments to ensure that such Incremental Term Loan B Facility is fungible for U.S. federal tax purposes with the Company’s Existing Term Loan B Facility). If an event of default occurs under the Existing Term Loan B Facility or the Incremental Term Loan B Facility, the entire principal amount outstanding thereunder, together with all accrued unpaid interest and other amounts owing in respect thereof, may be declared immediately due and payable, subject, in certain instances, to the expiration of applicable cure periods. The Term Loan Facility and the Incremental Term Loan B Facility also provide for customary asset sale mandatory prepayments, reporting covenants and negative covenants governing dividends, investments, indebtedness, and other matters that are customary for similar term loan B facilities.

Revolving Credit Facility

On April 22, 2024, the Company, as borrower, and certain of its subsidiaries, as guarantors, entered into the Ninth Amendment to the Second Amended and Restated Credit Agreement (the “Ninth Amendment”) to extend the maturity date of a portion of the revolving commitments thereunder to February 14, 2028.

On October 30, 2024, the Company, as borrower, and certain subsidiaries of the Company, as guarantors, entered into the Tenth Amendment to the Second Amended and Restated Credit Agreement (the "Tenth Amendment") with, among others, Citicorp North America, Inc., as administrative agent and as collateral agent (the “Agent”), and certain financial institutions, as lenders, which amended the Company’s Second Amended and Restated Credit Agreement, dated as of June 30, 2016 (the “Credit Agreement”), in order to (i) extend the maturity date of its revolving credit facility to October 30, 2029 and (ii) make certain other amendments to the Credit Agreement.

2048 Convertible Senior Notes

As of October 1, 2024, the Company's Convertible Senior Notes are convertible during the quarterly period ending December 31, 2024 due to the satisfaction of the Common Stock Sale Price Condition (as defined below). As of September 30, 2024, the Convertible Senior Notes are convertible into cash or a combination of cash and the Company’s common stock at a price of $41.11 per common share, which is the equivalent to a conversion rate of approximately 24.3220 shares of common stock per $1,000 principal amount of Convertible Senior Notes. The settlement method is at the Company's election. The net carrying amounts of the Convertible Senior Notes as of September 30, 2024 and December 31, 2023 were $231 million and $572 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, including, among others, during any calendar quarter (and only during such calendar quarter) if the last reported sales price per share of the Company's common stock exceeds 130% of the conversion price for each of at least 20 trading days, whether or not consecutive, during the 30 consecutive trading days ending on, and including, the last trading day of the immediately preceding calendar quarter (the "Common Stock Sale Price Condition"). 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.

All conversions with a conversion date that occurs within the specific periods above will be settled after such period pursuant to the terms of the Convertible Senior Notes indenture.

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


	Three months ended September 30,						Nine months ended September 30,
(In millions, except percentages)	2024			2023			2024			2023
Contractual interest expense	$	1		$	4		$	7		$	12
Amortization of deferred finance costs	—			—			1			1
Total	$	1		$	4		$	8		$	13

Effective Interest Rate	0.76		%	0.76		%	2.31		%	2.28		%

Repurchases

During the nine months ended September 30, 2024, the Company completed repurchases of a portion of the Convertible Senior Notes using cash on hand and a portion of the proceeds from the Term Loans, as detailed in the table below. For the nine months ended September 30, 2024, a $260 million loss on debt extinguishment was recorded.


(In millions, except percentages)
Settlement Period	Principal Repurchased		Cash Paid(a)		Average Repurchase Percentage
March 2024	$	92	$	151	162.356%
April 2024	251		452		179.454%
Total Repurchases	$	343	$	603

(a)Includes accrued interest of $1 million and $2 million for the March and April repurchases, respectively

Capped Call Options

During the second quarter of 2024, the Company entered into privately negotiated capped call transactions with certain counterparties (the "Capped Calls") to effectively lock in a conversion premium of $257 million on the remaining $232 million of the Convertible Senior Notes. The option price of $257 million was incurred when the Company entered into the Capped Calls, which will be payable upon the earlier of settlement and expiration of the applicable Capped Calls. For further discussion see Note 9, Changes in Capital Structure.

Receivables Securitization Facilities

On June 21, 2024, 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 20, 2025, (ii) increase the aggregate commitments from $1.4 billion to $2.3 billion (adjusted seasonally) and (iii) add a new originator. As of September 30, 2024, there were no outstanding borrowings and there were $1.5 billion in letters of credit issued.

Also on June 21, 2024, Direct Energy Services, LLC (in its capacity as additional originator, the “Additional Originator”) entered into a Joinder Agreement (the “Joinder Agreement”) to join as Additional Originator to the Receivables Sale Agreement, dated as of September 22, 2020, among Direct Energy, LP, Direct Energy Business, LLC, Green Mountain Energy Company, NRG Business Marketing, LLC, Reliant Energy Northeast LLC, Reliant Energy Retail Services, LLC, Stream SPE, Ltd., US Retailers LLC and XOOM Energy Texas, LLC, as originators, NRG Retail, as the servicer, and NRG Receivables (the “Receivables Sale Agreement”). Pursuant to the Joinder Agreement, the Additional Originator agrees to be bound by the terms of the Receivables Sale Agreement, will sell to NRG Receivables substantially all of its receivables for the sale of electricity, natural gas and/or related services and certain related rights (collectively, the “Receivables”) and in connection therewith have transferred to NRG Receivables the deposit accounts into which the proceeds of such Receivables are paid.

Concurrently with the amendments to the Receivables Facility, the Company and the originators thereunder terminated the existing uncommitted Repurchase Facility.

3.750% Senior Secured First Lien Note due 2024 Repayment

On June 17, 2024, the Company repaid $600 million in aggregate principal amount of its 3.750% Senior Secured First Lien Notes due 2024.

6.625% Senior Notes due 2027 Repayment

On October 31, 2024, the Company used the net proceeds from the offering of the Notes to redeem all of its outstanding 6.625% Senior Notes due 2027, of which $375 million aggregate principal amount was outstanding.

Non-recourse Debt

Vivint Secured Notes Tender Offer

On October 30, 2024, in connection with APX Group, Inc.'s previously announced offer to purchase for cash (the "Tender Offer") any and all of APX Group, Inc.'s outstanding 6.750% senior secured notes due 2027 (the “Vivint 6.750% Senior Secured Notes due 2027”), APX Group, Inc. purchased $589 million of the Vivint 6.750% Senior Secured Notes due 2027 that had been validly tendered. On October 30, 2024, APX Group, Inc. notified the trustee for the Vivint 6.750% Senior Secured Notes due 2027 of its election to redeem the $11 million of the Vivint 6.750% Senior Secured Notes due 2027 that remained outstanding following the Tender Offer on November 8, 2024. The redemption price for such remaining Vivint 6.750% Senior Secured Notes due 2027 was equal to the total consideration paid in connection with the Tender Offer.

Vivint Unsecured Notes Exchange Offer

In connection with the Company’s previously announced offer to exchange (the "Exchange Offer") any and all outstanding 5.750% Senior Notes due 2029 (the “Vivint 5.750% Senior Notes due 2029”) issued by APX Group, Inc. for the New NRG 5.750% Senior Notes due 2029 and cash, NRG accepted tenders with respect to $798 million aggregate principal amount of the Vivint 5.750% Senior Notes due 2029 that were tendered on or prior to the early tender date.

On October 30, 2024, the Company issued the New NRG 5.750% Senior Notes due 2029 in an aggregate principal amount of $798 million. The New NRG 5.750% Senior Notes due 2029 are senior unsecured obligations of NRG and are guaranteed by certain of its subsidiaries that guarantee indebtedness under the Senior Credit Facility.

Vivint Term Loan Repricing

On April 10, 2024, the Company’s wholly-owned indirect subsidiary, Vivint, entered into Amendment No. 2 (the "Second Amendment") to the Second Amended and Restated Credit Agreement dated as of June 9, 2021 (the “Vivint Credit Agreement”) with, among others, Bank of America, N.A. as administrative agent (the “Vivint Agent”), and certain financial institutions, as lenders, which amended the Vivint Credit Agreement in order to (i) reprice its term loan B facility (the term

loans thereunder, the “Vivint Term Loans”) and (ii) make certain other modifications to the Vivint Credit Agreement as set forth therein.

At Vivint’s election, the Vivint Term Loans bear interest at a rate per annum equal to either (1) a fluctuating rate equal to the highest of (A) the rate published by the Federal Reserve Bank of New York in effect on such day, plus 0.50%, (B) the rate of interest per annum publicly announced from time to time by The Wall Street Journal as the “Prime Rate” in the United States, and (C) a rate of one-month Term SOFR (as defined in the Vivint Credit Agreement), (after giving effect to any floor applicable to Term SOFR) plus 1.00%, in each case, plus a margin of 1.75%, or (2) Term SOFR (as defined in the Vivint Credit Agreement) (which Term SOFR shall not be less than 0.50%) for a one-, three- or six-month interest period (or such other period as agreed to by the Vivint Agent and the lenders, as selected by Vivint), plus a margin of 2.75%.

On October 30, 2024, the Company repaid in full the outstanding Vivint Term Loans and terminated the revolving credit facility under the Vivint Credit Agreement.

Note 8 — 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 and movements in foreign currency exchange rates.

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 2023 Form 10-K.

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


(In millions)	September 30, 2024		December 31, 2023
Accounts receivable and Other current assets	$	2,457	$	1,541




Current liabilities	154		153







Net assets	$	2,303	$	1,388

Note 9 — Changes in Capital Structure

As of September 30, 2024 and December 31, 2023, 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:


	Preferred	Common
	Issued and Outstanding	Issued	Treasury	Outstanding
Balance as of December 31, 2023	650,000	267,330,470	(59,199,520)	208,130,950
Shares issued under LTIPs	—	1,836,827	—	1,836,827
Shares issued under ESPP	—	—	145,562	145,562

Shares repurchased	—	—	(5,181,424)	(5,181,424)
Partial settlement of Capped Call Options	—	—	(2,588)	(2,588)
Retirement of treasury stock	—	(5,111,012)	5,111,012	—
Balance as of September 30, 2024	650,000	264,056,285	(59,126,958)	204,929,327
Shares issued under LTIPs	—	64,861	—	64,861
Shares issued under ESPP	—	—	96,508	96,508
Shares repurchased	—	—	(2,524,323)	(2,524,323)

Retirement of treasury stock	—	(2,064,950)	2,064,950	—
Balance as of October 31, 2024	650,000	262,056,196	(59,489,823)	202,566,373

Common Stock

Share Repurchases

The Company's long-term capital allocation policy is to target allocating approximately 80% of cash available for allocation, after debt reduction, to be returned to shareholders. In June 2023, NRG announced an increase to its existing share repurchase authorization to $2.7 billion, to be executed through 2025. In October 2024, the Board of Directors authorized an additional $1.0 billion for share repurchases as part of the existing share repurchase authorization. As of October 31, 2024, $2.0 billion is remaining under the $3.7 billion authorization. The following table summarizes the share repurchases made under the $3.7 billion authorization through October 31, 2024:


	Total number of shares purchased	Average price paid per share		Amounts paid for shares purchased (in millions)
2023 Repurchases:
Open market repurchases	5,054,798	$	39.56	$	200
Repurchases made under the accelerated share repurchase agreements	17,676,142	(b)		950
Total Share Repurchases during 2023	22,730,940			1,150		(a)
2024 Repurchases:
Repurchases made under the accelerated share repurchase agreements	1,163,230	(b)		—
Open market repurchases(c)	4,018,194	$	79.26	319
Total Share Repurchases during the nine months ended September 30, 2024	5,181,424			$	319	(d)
Open market repurchases October 1, 2024 through October 31, 2024	2,524,323	$	89.23	225
Total Share Repurchases under the $3.7 billion authorization	30,436,687	$	55.65	$	1,694

(a)Excludes $10 million accrued for excise tax owed as of December 31, 2023

(b)Under the November 6, 2023 ASR, the Company received a total of 18,839,372 shares for an average price per share of $50.43, excluding the impact of the excise tax incurred. See discussion below for further information of the ASR agreements

(c)Includes $3 million accrued as of September 30, 2024

(d)Excludes $3 million accrued for estimated excise tax owed as of September 30, 2024

On November 6, 2023, the Company executed Accelerated Share Repurchase agreements to repurchase a total of $950 million of NRG's outstanding common stock based on volume-weighted average prices. The Company received 17,676,142 shares in the fourth quarter of 2023, which were recorded in treasury stock at fair value based on the closing prices of $833 million, with the remaining $117 million recorded in additional paid-in-capital, representing the value of the forward contracts to purchase additional shares. During the first quarter of 2024, the Company received an additional 1,163,230 shares pursuant to the ASR agreements. Upon receipt of the final shares, the Company transferred the $117 million from additional paid-in-capital to treasury stock.

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 90% of its market value on the offering date or 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.

NRG Common Stock Dividends

During the first quarter of 2024, NRG increased the annual dividend to $1.63 from $1.51 per share. A quarterly dividend of $0.4075 per share was paid on the Company's common stock during the three months ended September 30, 2024. On October 11, 2024, NRG declared a quarterly dividend on the Company's common stock of $0.4075 per share, payable on November 15, 2024 to stockholders of record as of November 1, 2024. Beginning in the first quarter of 2025, NRG will increase the annual dividend by 8% to $1.76 per share. The Company expects to target an annual dividend growth rate of 7%-9% per share in subsequent years.

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

Retirement of Treasury Stock

During the nine months ended September 30, 2024, the Company retired shares of treasury stock as detailed below. These retired shares are now included in NRG's pool of authorized but unissued shares. The Company's accounting policy upon the formal retirement of treasury stock is to deduct its par value from common stock and to reflect any excess of cost over par value as a deduction from additional paid-in-capital.


	Total number of treasury shares retired	Average price per share		Carrying value of treasury shares retired (in millions)



Shares retired during the first quarter of 2024	1,163,230	$	32.67	$	38
Shares retired during the second quarter of 2024	1,114,400	33.84		38
Shares retired during the third quarter of 2024	2,833,382	35.40		100
Total shares retired during the nine months ended September 30, 2024	5,111,012			$	176

Capped Call Options

During the second quarter of 2024, the Company entered into privately negotiated capped call transactions with certain counterparties (the "Capped Calls"). The Capped Calls each have a strike price of $41.11 per share, subject to certain adjustments, which correspond to the conversion price of the Convertible Senior Notes as of September 30, 2024. The Capped Calls have a cap price of $249.00 per share, subject to certain adjustments, and effectively lock in a conversion premium of $257 million on the remaining $232 million balance of the Convertible Senior Notes. The options will expire on June 1, 2025 if not exercised. The Capped Calls are separate transactions and not part of the terms of the Convertible Senior Notes. As these transactions meet certain accounting criteria, the Capped Calls are recorded in stockholders' equity. The option price of $257 million incurred in connection with the Capped Calls, of which $253 million was recorded as a reduction to additional paid-in capital and a $4 million loss was recorded to other income, net to account for the change in the value of the Capped Calls during the calculation period which began on May 31, 2024 and concluded on June 28, 2024. The option price will be payable upon the earlier of settlement and expiration of the applicable Capped Calls.

Preferred Stock

Series A Preferred Stock Dividends

During the quarters ended March 31, 2024 and September 30, 2024, the Company declared and paid semi-annual 10.25% dividends of $51.25 per share on its outstanding Series A Preferred Stock, each totaling $33 million.

Note 10 — (Loss)/Income Per Share

Basic (loss)/income per common share is computed by dividing net (loss)/income less cumulative dividends attributable to preferred stock by the weighted average number of common shares outstanding. Shares issued and treasury shares repurchased during the period are weighted for the portion of the period that they were outstanding. Diluted (loss)/income per share is computed in a manner consistent with that of basic (loss)/income per share while giving effect to all potentially dilutive common shares that were outstanding during the period when there is net income. The performance stock units and non-vested restricted stock units are not considered outstanding for purposes of computing basic (loss)/income 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 there is net income. The Convertible Senior Notes are convertible, under certain circumstances, into cash or a combination of cash and the Company’s common stock. The 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 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.

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


	Three months ended September 30,				Nine months ended September 30,
(In millions, except per share data)	2024		2023		2024		2023
Basic (loss)/income per share:
Net (loss)/income	$	(767)	$	343	$	482	$	(684)
Less: Cumulative dividends attributable to Series A Preferred Stock	17		17		51		38
Net (loss)/income available for common stockholders	$	(784)	$	326	$	431	$	(722)
Weighted average number of common shares outstanding - basic	207		230		207		230
(Loss)/income per weighted average common share — basic	$	(3.79)	$	1.42	$	2.08	$	(3.14)

Diluted (loss)/income per share:
Net (loss)/income	$	(767)	$	343	$	482	$	(684)
Less: Cumulative dividends attributable to Series A Preferred Stock	17		17		51		38
Net (loss)/income available for common stockholders	$	(784)	$	326	$	431	$	(722)
Weighted average number of common shares outstanding - basic	207		230		207		230
Incremental shares attributable to the issuance of equity compensation (treasury stock method)	—		2		3		—
Incremental shares attributable to the potential share settlements of the Convertible Senior Notes (if converted method)	—		—		3		—
Weighted average number of common shares outstanding - dilutive	207		232		213		230
(Loss)/income per weighted average common share — diluted	$	(3.79)	$	1.41	$	2.02	$	(3.14)

The following table summarizes the Company's outstanding equity instruments that are anti-dilutive and were not included in the computation of the Company's diluted (loss)/income per share:


	Three months ended September 30,		Nine months ended September 30,
(In millions of shares)	2024	2023	2024	2023
Equity compensation plans	5	—	—	6
Potential share settlement of the Convertible Senior Notes	3	—	—	—

Note 11 — 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. Vivint Smart Home operations are reported within the Vivint Smart Home segment.

NRG’s chief operating decision maker, its chief executive officer, evaluates the performance of 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 (loss)/income. 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 2023 Form 10-K.


	Three months ended September 30, 2024
(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate		Eliminations		Total
Revenue	$	3,301	$	2,600	$	833	$	499	$	—	$	(10)	$	7,223
Depreciation and amortization	81		39		23		198		11		—		352

Gain on sale of assets	—		—		208		—		—		—		208
Equity in earnings of unconsolidated affiliates	—		—		6		—		—		—		6

(Loss)/income before income taxes	(1,056)		89		148		(37)		(158)		—		(1,014)



Net (loss)/income	$	(1,056)	$	88	$	148	$	(29)	$	82	$	—	$	(767)


	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	84		39		24		203		9		—		359


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



	Nine months ended September 30, 2024
(In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate		Eliminations		Total
Revenue	$	8,297	$	8,647	$	2,962	$	1,434	$	—	$	(29)	$	21,311
Depreciation and amortization	240		117		96		561		31		—		1,045
Impairment losses	—		—		15		—		—		—		15

(Loss)/gain on sale of assets	(4)		—		213		—		—		—		209
Equity in earnings of unconsolidated affiliates	—		—		13		—		—		—		13

Loss on debt extinguishment	—		—		—		—		260		—		260
Income/(loss) before income taxes	259		1,116		69		(59)		(652)		—		733




Net income/(loss)	$	259	$	1,116	$	90	$	(51)	$	(932)	$	—	$	482



	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	257		122		73		442		27		—		921


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

Note 12 — Income Taxes

Effective Income Tax Rate

The income tax provision consisted of the following:


	Three months ended September 30,						Nine months ended September 30,
(In millions, except rates)	2024			2023			2024			2023
(Loss)/Income before income taxes	$	(1,014)		$	408		$	733		$	(866)
Income tax (benefit)/expense	(247)			65			251			(182)

Effective income tax rate	24.4		%	15.9		%	34.2		%	21.0		%

For the three months ended September 30, 2024, the effective tax rate was higher than the statutory rate of 21%, primarily due to the state tax expense. For the nine months ended September 30, 2024, the effective tax rate was higher than the statutory rate of 21%, primarily due to the state tax expense and permanent differences.

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 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.

On September 12, 2024, Treasury and the IRS released proposed regulations that provide guidance on the application of the CAMT. The proposed regulations allow excluding of unrealized mark-to-market gains and losses, related to qualified hedge transactions, from adjusted financial statement income. The Company will continue to evaluate the applicable corporation status and the impact of the CAMT based on the proposed guidance. As of September 30, 2024, there is no impact on the Company’s provision for income taxes from the CAMT.

Uncertain Tax Benefits

As of September 30, 2024, NRG had a non-current tax liability of $70 million for uncertain tax benefits from positions taken on various federal and state income tax returns inclusive of accrued interest. For the nine months ended September 30, 2024, NRG accrued $1 million of interest relating to the uncertain tax benefits. As of September 30, 2024, NRG had cumulative interest and penalties related to these uncertain tax benefits of $4 million. The Company recognizes interest and penalties related to uncertain tax benefits in income tax expense.

NRG is subject to examination by taxing authorities for income tax returns filed in the U.S. federal jurisdiction and various state and foreign jurisdictions including operations located in Australia and Canada. The Company is no longer subject to U.S. federal income tax examinations for years prior to 2020. With few exceptions, state and Canadian income tax examinations are no longer open for years prior to 2015.

Note 13 — Related Party Transactions

NRG provides services to some of its related parties, which 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 services, a base monthly fee, profit margin and/or annual incentive bonus.

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


	Three months ended September 30,				Nine months ended September 30,
(In millions)	2024		2023		2024		2023
Revenues from Related Parties Included in Revenue
Gladstone	$	1	$	1	$	2	$	2

Ivanpah(a)	12		15		37		70
Midway-Sunset	1		—		3		2


Total	$	14	$	16	$	42	$	74

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

Note 14 — 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, 2024, all hedges under the first liens were out-of-the-money 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 15, Regulatory Matters, and Note 16, Environmental Matters. In addition, legal costs are expensed as incurred. Management has assessed each of the following matters based on current information and

made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought, and the probability of success. Unless specified below, the Company is unable to predict the outcome of these legal proceedings or reasonably estimate the scope or amount of any associated costs and potential liabilities. As additional information becomes available, management adjusts its assessment and estimates of such contingencies accordingly. Because litigation is subject to inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate resolution of the Company's liabilities and contingencies could be at amounts that are different from its currently recorded accruals and that such difference could be material.

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

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. In 2023, the IPCB held hearings 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 Case

Mirkin v. XOOM Energy (E.D.N.Y. Aug. 2019) — XOOM Energy is a defendant in a putative class action lawsuit pending in New York, alleging that XOOM Energy 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 Court denied XOOM's motion for summary judgment and granted class certification. The Second Circuit denied XOOM's request to appeal the class certification grants. XOOM prevailed in its challenge to Mirkin's expert reports. The Court granted XOOM's motion to exclude both reports on damages. As a result, Mirkin has no method to establish damages for its class. The Court asked for further briefing on whether class certification can stand in light of the recent ruling. This matter was known and accrued for at the time of the XOOM acquisition.

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 Direct Energy 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 April 12, 2023, the Court granted Direct Energy’s Motion to Transfer Venue, moving to the case to the Southern District of Texas. The parties are proceeding with written discovery; 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. 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 conducted fact and expert discovery and Direct Energy submitted its motion for summary judgment in August 2024.

Sales Practice Lawsuit

A Vivint Smart Home competitor has made a claim against Vivint Smart Home alleging, among other things, that Vivint Smart Home's sales representatives used deceptive sales practices. This matter was known and accrued for at the time of the Vivint Smart Home acquisition. CPI Security Systems, Inc. ("CPI") v. Vivint Smart Home, Inc. (W.D.N.C. Sept. 2020) 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 has fully

briefed the appeal and oral argument is expected in early 2025. While Vivint Smart Home believes the CPI jury verdict is not legally or factually supported and is pursuing an appeal, there can be no assurance that such defense efforts will be successful.

Patent Infringement Lawsuit

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. The Company does not believe the verdict is legally supported and is pursuing appellate remedies along with any other legal options available. This matter was known and accrued for at the time of the Vivint Smart Home acquisition.

Contract Dispute

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. The parties entered into a settlement agreement in May 2024, and the litigation was dismissed. There was no incremental impact to NRG as a result of the settlement.

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 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 dismissed from the multi-district litigation. As a power generator, the Company is named in various cases with claims ranging from: wrongful death; personal injury only; property damage and personal injury; property damage only; and subrogation. The First Court of Appeals conditionally granted the generators' mandamus relief, ordering the trial court to grant the generator defendants' Motion to Dismiss. The plaintiffs challenged the ruling and the matters are stayed pending appeals by the various parties. The Company intends to vigorously defend these matters.

Note 15 — Regulatory Matters

Environmental regulatory matters are discussed within Note 16, 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 proceedings noted below, NRG and its subsidiaries are parties to other regulatory proceedings arising in the ordinary course of business or have other regulatory exposure. In management's opinion, the disposition of these ordinary course matters will not materially adversely affect NRG's consolidated financial position, results of operations, or cash flows.

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

New York State Public Service Commission ("NYSPSC") - Notice of Apparent Violation — The NYSPSC issued an order referred to as the Retail Reset Order in December 2019 that limited ESCO's offers for electric and natural gas to three compliant products: guaranteed savings from the utility default rate, a fixed rate commodity product that is priced at no more than 5% greater than the trailing 12-month average utility supply rate or New York-sourced renewable energy that is at least 50% greater than the prevailing New York Renewable Energy Standard for load serving entities. The order effectively limited ESCO offers to natural gas customers to only the guaranteed savings and capped fixed term compliant products because no equivalent renewable energy product exists for natural gas. NRG took action to comply with the order when it became effective April 16, 2021. On January 8, 2024, the NYSPSC notified eight of NRG's retail energy suppliers (serving both electricity and natural gas) of alleged non-compliance with New York regulatory requirements. Among other items, the notices allege that the NRG suppliers did not transition existing residential customers to one of the three compliant products authorized by the NYSPSC following the effective date of the order. NRG responded to the notices in February 2024. The Company believes it has complied with the Retail Reset Order and does not agree with the NYSPSC's assertions made in the notice. The outcome of this process has the potential to negatively impact the retail business in New York.

Note 16 — 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 use and discharge, and threatened and endangered species including four rules promulgated during the second quarter of 2024. 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 — The attention in recent years on GHG emissions has resulted in federal and state regulations. In 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 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 9, 2024, the EPA promulgated a rule that repealed the ACE rule and significantly revised the manner in which new combustion-turbine and existing steam EGU's GHG emissions will be regulated including capturing and storing/sequestering CO2 in some instances. This rule has been challenged by numerous parties in the D.C. Circuit including 27 states with 22 states intervening in support of the rule. The Company anticipates that the new U.S. presidential administration will revisit this rule.

Cross-State Air Pollution Rule ("CSAPR") — On March 15, 2023, the EPA signed and released a prepublication version of a final rule that sought to significantly revise the CSAPR to address the good-neighbor obligations of the 2015 ozone 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 promulgated this rule. 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 several other states. On June 27, 2024, the U.S. Supreme Court stayed the final rule in the 11 states where the rule had not already been stayed. 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. The Company anticipates that the new U.S. presidential administration will revisit this rule.

Regional Haze Proposal — In 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 finalized as proposed, it would result in more stringent SO2 limits for two of the Company's coal-fired units in Texas. The Company cannot predict the outcome of this proposal.

Mercury and Air Toxics Standards (“MATS”) — On May 7, 2024, the EPA promulgated a final rule that amends the MATS rule by, among other things, increasing the stringency of the filterable particulate matter standard at coal-burning units. The deadline for complying with this more stringent standard is 2027. Twenty-three states have challenged this rule in the D.C. Circuit. Accordingly, the outcome of this rulemaking is uncertain. The Company anticipates that the new U.S. presidential administration will revisit this rule.

Water

ELG — In 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. In 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. On May 9, 2024, the EPA promulgated a rule that revises the ELG by, among

other things, further restricting the discharge of (i) FGD wastewater, (ii) bottom ash transport water, and (iii) combustion residual leachate. The rule was challenged in numerous courts, but the cases have been consolidated in the Eighth Circuit of the United States Court of Appeals. The outcome of the legal challenges is uncertain. The Company anticipates that the new U.S. presidential administration will revisit this rule.

Byproducts

In 2015, the EPA finalized the rule regulating byproducts of coal combustion (e.g., ash and gypsum) as solid wastes under the RCRA. On August 21, 2018, the D.C. Circuit found, among other things, that the EPA had not adequately regulated unlined ponds and legacy 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: 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 8, 2024, the EPA promulgated a rule that establishes requirements for: (i) inactive (or legacy) surface impoundments at inactive facilities and (ii) coal combustion residual ("CCR") management units (regardless of how or when the CCR was placed) at regulated facilities. The rule also creates an obligation to conduct site assessments (at all active and certain inactive facilities) to determine whether CCR management units are present. The rule has been challenged in the D.C. Circuit and the outcome of the legal challenges is uncertain. The Company anticipates that the new U.S. presidential administration will revisit this rule.

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;

•Liquidity and capital resources including liquidity position, financial condition addressing credit ratings, material cash requirements and commitments, and 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 of operations to this Form 10-Q, which present the results of operations for the three and nine months ended September 30, 2024 and 2023. Also refer to NRG's 2023 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, sits at the intersection of energy and home services. NRG is a leading energy and home services company fueled by market-leading brands, proprietary technologies, and complementary sales channels. Across the U.S. and Canada, NRG delivers innovative, sustainable solutions, predominately under brand names such as NRG, Reliant, Direct Energy, Green Mountain Energy and Vivint, while also advocating for competitive energy markets and customer choice. The Company has a customer base that includes approximately 8 million residential consumers in addition to commercial, industrial, and wholesale customers, supported by approximately 13 GW of generation as of September 30, 2024.

Strategy

NRG's strategy is to maximize stakeholder value by being a leader in the emerging convergence of energy and smart automation in the home and business. Through a diversified supply strategy, the Company sells reliable electricity and natural gas to its customers in the markets it serves, while also providing innovative home solutions to customers. NRG's unique combination of assets and capabilities enables the Company to develop and sell highly differentiated offerings that bring together every day essential services like powering and securing the home through a seamless and integrated experience. This strategy is intended to enable the Company to optimize its unique integrated platform to delight customers, generate recurring cash flow, significantly strengthen earnings and cost competitiveness, and lower risk and volatility. Sustainability is a philosophy that underpins and facilitates value creation across NRG's business for 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 counterparties in competitive markets and optimizing on additional revenue 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) achieving the optimal mix of supply to serve its customer load requirements through a diversified supply strategy; and (v) engaging in disciplined and transparent capital allocation.

Energy Regulatory Matters

The Company’s regulatory matters are described in the Company’s 2023 Form 10-K in Item 1, Business — Regulatory Matters. These matters have been updated below and in Note 15, 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.

State and Provincial Energy Regulation

Maryland Legislation — On May 9, 2024, Maryland Governor Wes Moore signed Senate Bill 1 into law, which restricts the competitive retail electric and natural-gas market in Maryland, affecting residential customers but not commercial and industrial customers. Key provisions of the law take effect January 1, 2025. The legislation imposes a price cap on residential contracts tied to a trailing 12-month historical average of utility rates, with only a limited exception for renewable power products. Renewable products must now have their price pre-approved pursuant to a process to be established and run by the Maryland Public Service Commission and source their renewable electricity certificates from within the PJM region. The law also requires that any variable-price contract not contain a change in price more than once a year, except time-of-use contracts, and limits contract terms to 12 months. It requires affirmative consent for the renewal of customer contracts for renewable power products. The law also imposes licensing requirements on energy salespersons. The law states that it does not impair existing contracts. On October 1, 2024, Green Mountain Energy Company, a subsidiary of NRG, along with a retail trade association to which NRG belongs, filed a lawsuit in federal court challenging the constitutionality of Senate Bill 1.

Regional Regulatory Developments

NRG is affected by rule/tariff changes that occur in the ISO regions. For further discussion on regulatory developments, see Note 15, Regulatory Matters.

Texas

Public Utility Commission of Texas’ Actions with Respect to Wholesale Pricing and Market Design — The PUCT continues to analyze and implement multiple options for promoting increased reliability in the wholesale electric market, including the adoption of a reliability standard for resource adequacy and market-based mechanisms to achieve this standard. The Commission adopted a reliability standard that became effective in September 2024. In 2023, the Texas Legislature authorized implementation of the Performance Credit Mechanism ("PCM"), which will measure real-time contribution to system reliability and provide compensation for resources to be available, subject to certain "guardrails" such as an absolute annual net cost cap, as part of its adoption of the PUCT Sunset Bill (House Bill 1500). The Texas Legislature also directed the PUCT to implement additional market design changes such as the 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 new generation resources which penalize poor performance during periods of low grid reserves. The PUCT directed ERCOT to implement DRRS as a standalone product which will delay implementation until 2026 or 2027.

Texas Energy Fund — Through Senate Bill 2627, the Texas Legislature created the Texas Energy Fund, which received voter approval in November 2023, and will provide grants and low-interest loans (3%) to incentivize the development of more dispatchable generation and smaller backup generation in ERCOT. The PUCT adopted a rule in March 2024, which establishes the application and participation requirements and the process by which the Texas Energy Fund loan proceeds for dispatchable generation in ERCOT will be distributed. The initial window for submitting loan applications was opened on June 1, 2024 and closed on July 27, 2024. NRG, through its subsidiaries, filed for loan proceeds for three separate projects, totaling more than 1,500 MWs of capacity. The PUCT also adopted a rule for the completion bonus grant program in April 2024, which provides for opportunities for grants of $120,000 per MW for dispatchable generation projects interconnected before June 1, 2026, or $80,000 per MW for dispatchable generation projects interconnected on or after June 1, 2026 but before June 1, 2029, subject to performance requirements. Applications for completion bonus grants can be submitted beginning in January 2025. Availability of grant funds may be impacted by the 10,000 MW collective cap on the ERCOT loan and grant program.

On August 29, 2024, the PUCT approved a portfolio of projects to move into a due diligence process with its third-party administrator. NRG THW GT LLC's 415 MW gas peakers, which is projected to become commercially operational by May 1, 2026, was among the projects selected to move into diligence, and that process is underway. Approximately 8,500 MW of projects are currently approved to undergo due diligence.

Real-time Co-optimization of Energy and Ancillary Services ("RTC") – ERCOT is progressing with a multi-year project to upgrade their systems to co-optimize the dispatch of energy and ancillary services in real-time. The RTC project will also replace the Operating Reserve Demand Curve with demand curves for each ancillary service product which will act as the primary scarcity pricing mechanism when energy or ancillary services are in shortage. ERCOT anticipates commencing market trials for testing the RTC project in Spring 2025 with production to go-live in late 2025.

Supreme Court of Texas Ruling on Pricing during Winter Storm Uri — On June 14, 2024, the Supreme Court of Texas issued an order affirming 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 Supreme Court's order reversed the judgment of the Third Court of Appeals, which held 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. In addition to holding that the PUCT's orders were consistent with the agency's statutory authority, the Supreme Court of Texas's order found that the PUCT had substantially complied with the Administrative Procedure Act's procedural rulemaking requirements.

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. In February 2024, NRG filed a notice of intent with the PUCT and terminated its existing VMP as of March 1, 2024.

Lubbock, Texas Transition to Competition — The customers of Lubbock Power and Light ("LP&L"), a municipally owned utility, entered the Texas retail competitive market in March 2024. Starting in January 2024, LP&L customers were able to shop for a REP. Customers who did not select a REP by February 15, 2024 were assigned to one of three default REPs, one of which is Reliant. LP&L customers started transitioning to their chosen REP or a default REP on March 4, 2024.

PJM

Revisions to PJM Local Deliverability Area Reliability Requirement — The Base Residual Auction ("BRA") 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 filing at FERC to revise the definition of Locational Deliverability Area ("LDA") Reliability Requirement in the Tariff. This would allow PJM to 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 multiple parties, including the Company, filed appeals to the Third Circuit Court of Appeals. On March 12, 2024, the court vacated the portion of the FERC orders that allow PJM to apply the Local Deliverability Area Reliability Requirement to the 2024/2025 capacity auction. On March 29, 2024, PJM filed a petition seeking confirmation as to the capacity commitments rules for the 2024/2025 auction. On April 22, 2024, multiple parties filed a complaint seeking to find the revised rate unjust and unreasonable and implement rates consistent with FERC's February 2023 decision, which was denied on July 9, 2024. Those parties filed an appeal to the Court of Appeals for the D.C. Circuit on November 5, 2024.

On May 6, 2024, FERC directed PJM to recalculate the 2024/2025 auction results under the Initial LDA Reliability Requirement rules, and further directed PJM to rerun the Third Incremental Auction. PJM published the revised BRA and Third Incremental Auction results on May 8, 2024 and May 23, 2024, respectively. On June 14, 2024, multiple parties filed appeals to the Third Circuit Court of Appeals seeking review of the May 6, 2024 FERC orders approving PJM's petition to restore the original capacity commitment rules for PJM to recalculate the 2024/2025 BRA and the rerun of the 2024/2025 BRA. As a result, the capacity for the 2024/2025 delivery year in the Delmarva Power and Light South zone resulted in higher prices. This outcome may change depending upon the disposition of the outstanding complaint and appeals.

PJM Base Residual Auction Revisions and Delay — On April 11, 2023, PJM filed, and FERC subsequently approved, to delay the BRAs for the 2025/2026 to 2028/2029 delivery years. PJM subsequently made a filing at FERC proposing to develop market reforms. FERC ultimately rejected some of those changes and accepted some of those changes. The approved changes were in effect for the 2025/2026 BRA that occurred in July 2024. PJM sought FERC's approval to delay the 2026/2027 BRA until June 2025. The request is pending at FERC.

Changes to RMR in PJM Capacity Auctions — On September 27, 2024, various public interest organizations filed a complaint at FERC against PJM seeking changes to the treatment of RMRs in the capacity market. Any changes approved by FERC could affect capacity prices.

Indian River RMR Proceeding — On June 29, 2021, Indian River notified PJM that it intended to retire Unit 4, effective May 31, 2022, due to expected uneconomic operations. On July 30, 2021, PJM responded to the deactivation notice and stated that PJM had identified reliability violations resulting from the proposed deactivation of Unit 4. NRG filed a cost based RMR rate schedule at FERC on April 1, 2022. FERC accepted the rate schedule with a June 1, 2022 effective date, subject to refund and established hearing and settlement procedures. The Company reached settlement with a number of the intervening parties and the settlement agreement was filed at FERC on April 2, 2024 and is pending FERC review. Delmarva Power submitted to PJM and the Maryland Public Service Commission an update on its projected completion date for the transmission upgrades that would eliminate the need for the Indian River RMR. The new anticipated date is in December 2024, which is sooner than originally estimated by PJM.

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, FERC issued an Order, which permitted the PJM May 2021 capacity auction for the 2022/2023 delivery 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 eliminated the Cost of New Entry-based Market Seller Offer Cap, implemented a limited default cap for certain asset classes based on going-forward costs and provided for unit specific cost review by the Independent Market Monitor for all other non-zero offers into the auctions. On October 4, 2021, as required by the Order, PJM submitted its compliance tariff 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, and on August 15, 2023, the Court denied the petitions for review. On January 12, 2024, the generator trade association filed a petition for review with the U.S. Supreme Court to overturn the August 15, 2023 judgment. On May 28, 2024, the U.S. Supreme Court denied the petition for review.

Final Rule on Reactive Power Payments — On October 17, 2024, FERC issued its final rule on reactive power, eliminating compensation for a generator’s reactive power within the standard power factor. ISOs must make a compliance filing, but FERC will permit ISO-NE, NYISO, and PJM to request a later effective date. This change affects the payments provided to generators providing reactive power service.

Change to Energy Efficiency in the PJM Capacity Auction — On November 5, 2024, FERC approved PJM’s proposal to terminate compensation paid through the PJM capacity market to energy efficiency resources beginning in the 2026/2027 auction year. However, energy efficiency resources will be counted as a reduction in the PJM load forecast that is the basis of the PJM capacity auction. FERC's action will eliminate wholesale market financial support for utility-run programs authorized by state utility commissions, as well as certain third-party providers of energy efficiency services. NRG's demand-side programming is not significantly affected by the modification.

Other Regulatory Matters

From time to time, NRG entities may be subject to examinations, investigations and/or enforcement actions by federal, state and provincial licensing agencies and may face the risk of penalties for violation of financial services, consumer protections and other applicable laws and regulations.

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 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 including unit retirements. 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 and continue to be revised by the EPA, including requirements regarding coal ash, GHG emissions, NAAQS revisions and implementation and effluent limitation guidelines. NRG will evaluate the impact of these regulations as they are revised but cannot fully predict the impact of each until anticipated revisions, legal challenges and reconsiderations are resolved. The Company’s environmental matters are described in the Company’s 2023 Form 10-K in Item 1, Business - Environmental Matters and Item 1A, Risk Factors. These matters have been updated in Note 16, Environmental Matters, to the condensed consolidated financial statements of this Form 10-Q and as follows.

Air

The CAA and 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 March 2024, the EPA increased 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 2019, the 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 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 9, 2024, the EPA promulgated a rule that repealed the ACE rule and significantly revised the manner in which new combustion-turbine and existing steam EGU's GHG emissions will be regulated including capturing and storing/sequestering CO2 in some instances. This rule has been challenged by numerous parties in the D.C. Circuit including 27 states with 22 states intervening in support of the rule. The Company anticipates that the new U.S. presidential administration will revisit this rule.

CSAPR — On March 15, 2023, the EPA signed and released a prepublication of a final rule that sought to significantly revise the CSAPR to address the good-neighbor obligations of the 2015 ozone 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 promulgated this rule. 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 several other states. On June 27, 2024, the United States Supreme Court stayed the final rule in the 11 states where the rule had not already been stayed. 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. The Company anticipates that the new U.S. presidential administration will revisit this rule.

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 finalized as proposed, the rule would result in more stringent SO2 limits for two of the Company's coal-fired units in Texas. The Company cannot predict the outcome of this proposal.

MATS — On May 7, 2024, the EPA promulgated a final rule that amends the MATS rule by, among other things, increasing the stringency of the filterable particulate matter standard at coal-burning units. The deadline for complying with this more stringent standard is 2027. Twenty three states have challenged this rule in the D.C. Circuit. Accordingly, the outcome of this rulemaking is uncertain. The Company anticipates that the new U.S. presidential administration will revisit this rule.

Byproducts

In April 2015, the EPA finalized the rule regulating byproducts of coal combustion (e.g., ash and gypsum) as solid wastes under the RCRA. On July 30, 2018, the EPA promulgated a rule that amended the 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 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 8, 2024, the EPA promulgated a rule that establishes requirements for: (i) inactive (or legacy) surface impoundments at inactive facilities and (ii) coal combustion residual ("CCR") management units (regardless of how or when the CCR was placed) at regulated facilities. The rule also creates an obligation to conduct site assessments (at all active and certain inactive facilities) to determine whether CCR management units are present. The rule has been challenged in the D.C. Circuit and the outcome of the legal challenges is uncertain. The Company anticipates that the new U.S. presidential administration will revisit this rule.

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.

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.

ELG — In 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. In 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. 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. On May 9, 2024, the EPA promulgated a rule that revises the ELG by, among other things, further restricting the discharge of (i) FGD wastewater, (ii) bottom ash transport water, and (iii) combustion residual leachate. The rule was challenged in numerous courts, but the cases have been consolidated in the Eighth Circuit of the United States Court of Appeals. The outcome of the legal challenges is uncertain. The Company anticipates that the new U.S. presidential administration will revisit this rule.

Regional Environmental Developments

Ash Regulation in Illinois — On July 30, 2019, Illinois enacted legislation that 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 construction permits (for closure and retrofits) as required by the regulation and is waiting for most of its permits to be issued by the Illinois EPA.

Houston Nonattainment for 2008 Ozone Standard — In 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 2024 as further described within this Management's Discussion and Analysis and the condensed consolidated financial statements:

Dispositions

Capital Allocation

During the nine months ended September 30, 2024, the Company completed $319 million of open market share repurchases at an average price of $79.26 per share. Through October 31, 2024, an additional $225 million share repurchases were executed at an average price of $89.23 per share. See Note 9, Changes in Capital Structure for additional discussion.

In October 2024, the Board of Directors authorized an additional $1.0 billion for share repurchases as part of the existing share repurchase authorization. As of October 31, 2024, $2.0 billion is remaining under the $3.7 billion authorization.

On November 6, 2023, the Company executed Accelerated Share Repurchase agreements to repurchase a total of $950 million of NRG's outstanding common stock. The Company received shares of NRG's common stock on specified settlement dates. The ASR program concluded on March 28, 2024, with total of 18,839,372 shares received at an average price of $50.43 per share.

In the first quarter of 2024, NRG increased the annual common stock dividend to $1.63 from $1.51 per share, representing an 8% increase from 2023. Beginning in the first quarter of 2025, NRG will increase the annual dividend by 8% to $1.76 per share. The Company expects to target an annual dividend growth rate of 7-9% per share in subsequent years.

On April 16, 2024, the Company, as borrower, and certain of its subsidiaries, as guarantors, entered into the Eighth Amendment with, among others, Citicorp North America, Inc., as administrative agent and as the Agent, and certain financial institutions, as lenders, which amended the Credit Agreement, in order to (i) establish a new Term Loan Facility with borrowings of $875 million in aggregate principal amount and the Term Loans and (ii) make certain other modifications to the Credit Agreement as set forth therein. The proceeds from the Term Loans were used to repay a portion of the Company’s Convertible Senior Notes, all of the Company's 3.750% senior secured first lien notes due 2024 and for general corporate purposes. For further discussion, see Note 7, Long-term Debt and Finance Leases.

During the nine months ended September 30, 2024, the Company repurchased $343 million in aggregate principal amount of its Convertible Senior Notes, for $603 million, which included the payment of $3 million of accrued interest, using cash on hand and a portion of the proceeds from the Term Loans. For further discussion, see Note 7, Long-term Debt and Finance Leases.

During the second quarter of 2024, the Company entered into privately negotiated capped call transactions with certain counterparties to effectively lock in a conversion premium of $257 million on the remaining $232 million of the Convertible Senior Notes. The option price of $257 million was incurred when the Company entered into the capped call transactions, which will be payable upon the earlier of settlement and expiration of the applicable Capped Call. For further discussion see Note 9, Changes in Capital Structure.

On June 21, 2024, NRG Receivables, amended its existing Receivables Facility to, among other things, (i) extend the scheduled termination date to June 20, 2025, (ii) increase the aggregate commitments from $1.4 billion to $2.3 billion (adjusted seasonally) and (iii) add a new originator. For further discussion, see Note 7, Long-term Debt and Finance Leases.

During the second quarter of 2024, the Company repaid $600 million in aggregate principal amount of its 3.750% Senior Secured First Lien Notes due 2024.

Debt Refinancing Transactions

In the fourth quarter of 2024, the Company entered into the following debt transactions:

Sources

Uses

Issuance by NRG of 6.000% Senior Notes due 2033

$925 million

Repayment of the Vivint Senior Secured Term Loan B

$1.310 billion

Issuance by NRG of 6.250% Senior Notes due 2034

$950 million

Cash tender offer for Vivint 6.750% Senior Secured Notes due 2027(a)

$600 million

Exchange offer for New NRG 5.750% Senior Notes due 2029

$798 million

Exchange offer for Vivint 5.750% Senior Notes due 2029(b)

$798 million

Incremental Term Loan B issued by NRG

$450 million

Repayment of NRG 6.625% Senior Notes due 2027

$375 million

Cash on hand

$5 million

Estimated transactions fees, expenses and premiums

$45 million

Total

$3.128 billion

Total

$3.128 billion

(a)On October 30, 2024, APX Group, Inc. delivered a notice of redemption with respect to the Vivint 6.750% Senior Secured Notes due 2027 to redeem the $11 million of the Vivint 6.750% Senior Secured Notes due 2027 that remained outstanding following the Tender Offer on November 8, 2024

(b)On November 4, 2024, APX Group, Inc. delivered a notice of redemption with respect to the Vivint 5.750% Senior Notes due 2029 to redeem the approximate $2 million of the Vivint 5.750% Senior Notes due 2029 that remained outstanding following the Exchange Offer on November 14, 2024

As part of the above transactions, the Company entered into the Tenth Amendment and Eleventh Amendment to the Credit Agreement to (i) increase the term loan B in an aggregate principal balance of $450 million, (ii) make certain other amendments to the Credit Agreement and (iii) extend the maturity date of its revolving credit facility to October 30, 2029. For further discussion on these amendments and the debt transactions in the table above, see Note 7, Long-term Debt and Finance Leases.

Operations

NRG has entered into a definitive partnership agreement with Renew Home, a leading Virtual Power Plant platform ("VPP") formed by the combination of Google's Nest Renew and OhmConnect. This first-of-its-kind commercial partnership reinforces NRG's customer focus and brings to market unique products and services which will help customers save money while enjoying the benefits of a seamless energy and smart home experience. Leveraging Google Cloud's AI and cloud platforms, NRG and Renew Home plan to develop a VPP portfolio of up to 1 GW of load management capacity, with instantaneous dispatch value during peak events and tight supply conditions. Participating customers will enroll in an NRG branded energy plan and will be eligible for favorable rates on Vivint Smart Home services and additional products. The partnership will initially focus in Texas, with Renew Home supporting upfront customer acquisition costs and Google Nest integration.

A component of the Company's strategy is to procure mid to long-term generation through power purchase agreements. NRG has entered into Renewable PPAs totaling approximately 1.9 GW with third-party project developers and other counterparties, of which all are operational as of September 30, 2024. The average tenure of these agreements is 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.

Trends Affecting Results of Operations and Future Business Performance

The Company’s trends are described in the Company’s 2023 Form 10-K in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations - Business Environment, except for the update below:

Load Growth — The electric industry is expected to experience a surge in demand driven primarily by new manufacturing, industrial and data center facilities (inclusive of generative artificial intelligence ("gen AI")). The U.S. Energy Information Administration's 2023 Annual Energy Outlook, combined with external forecasts of gen AI, shows the potential for 500 TWh of incremental load across the U.S. through 2030, as compared to 2023. ERCOT's current long term load forecast shows peak demand increasing from 86 GW in 2024 to 137 GW in 2028. This load growth will require significant planning and construction of new generation and transmission. ERCOT has announced its New Era of Planning effort to prepare for the possibility of very large and rapid load growth.

Texas Development Priorities

In the third quarter of 2024, the PUCT selected the T.H. Wharton project to move forward in the due diligence process for the Texas Energy Fund. The Company continues to explore its options for the Cedar Bayou 5 and Greens Bayou 6 projects. NRG's shovel ready projects are as follows:

Facility

Fuel Type

Net Generation Capacity (MW)

Cedar Bayou 5

Natural Gas

689

Greens Bayou 6

Natural Gas

448

T.H. Wharton

Natural Gas

415

Total

1,552

Changes in Accounting Standards

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

Consolidated Results of Operations

The following table provides selected financial information for the Company:


	Three months ended September 30,						Nine months ended September 30,
(In millions)	2024		2023		Change		2024		2023		Change
Revenue
Retail revenue	$	6,954	$	7,521	$	(567)	$	20,527	$	20,911	$	(384)
Energy revenue(a)	128		261		(133)		390		472		(82)
Capacity revenue(a)	47		59		(12)		133		150		(17)
Mark-to-market for economic hedging activities	8		(70)		78		32		96		(64)
Contract amortization	(8)		(5)		(3)		(25)		(24)		(1)
Other revenues(a)(b)	94		180		(86)		254		411		(157)
Total revenue	7,223		7,946		(723)		21,311		22,016		(705)
Operating Costs and Expenses
Cost of fuel	296		400		104		648		790		142
Purchased energy and other cost of sales(c)	4,775		5,585		810		14,723		15,863		1,140

Mark-to-market for economic hedging activities	1,638		(17)		(1,655)		315		2,029		1,714
Contract and emissions credit amortization(c)	(3)		(12)		(9)		43		78		35
Operations and maintenance	401		335		(66)		1,192		1,076		(116)
Other cost of operations	132		115		(17)		308		301		(7)
Cost of operations (excluding depreciation and amortization shown below)	7,239		6,406		(833)		17,229		20,137		2,908
Depreciation and amortization	352		359		7		1,045		921		(124)
Impairment losses	—		—		—		15		—		(15)
Selling, general and administrative costs (excluding amortization of customer acquisition costs of $55, $36, $144 and $84, respectively, which are included in depreciation and amortization shown separately above)	645		602		(43)		1,739		1,502		(237)

Acquisition-related transaction and integration costs	7		18		11		22		111		89
Total operating costs and expenses	8,243		7,385		(858)		20,050		22,671		2,621

Gain on sale of assets	208		—		208		209		202		7
Operating (Loss)/Income	(812)		561		(1,373)		1,470		(453)		1,923
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates	6		6		—		13		16		(3)

Other income, net	5		14		(9)		38		43		(5)
Loss on debt extinguishment	—		—		—		(260)		—		(260)
Interest expense	(213)		(173)		(40)		(528)		(472)		(56)
Total other expense	(202)		(153)		(49)		(737)		(413)		(324)
(Loss)/Income Before Income Taxes	(1,014)		408		(1,422)		733		(866)		1,599
Income tax (benefit)/expense	(247)		65		312		251		(182)		(433)




Net (Loss)/Income	$	(767)	$	343	$	(1,110)	$	482	$	(684)	$	1,166

(a)Includes gains and losses from financially settled transactions

(b)Includes trading gains and losses and ancillary revenues

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

Management’s discussion of the results of operations for the three months ended September 30, 2024 and 2023

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, 2024 and 2023.


	Average on Peak Power Price ($/MWh)
	Three months ended September 30,
Region	2024		2023		Change %
Texas
ERCOT - Houston(a)	$	34.12	$	183.49	(81)	%
ERCOT - North(a)	34.21		181.72		(81)	%

East
NY J/NYC(b)	$	44.09	$	40.86	8	%
NEPOOL(b)	45.87		40.41		14	%
COMED (PJM)(b)	38.03		39.38		(3)	%
PJM West Hub(b)	49.70		43.27		15	%

West
MISO - Louisiana Hub(b)	$	30.68	$	38.53	(20)	%
CAISO - SP15(b)	43.12		67.59		(36)	%

(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 three months ended September 30, 2024 and 2023:


	Three months ended September 30,
	2024		2023		Change %
($/MMBtu)	$	2.16	$	2.55	(15)	%

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 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.

The following tables present the composition and reconciliation of gross margin and economic gross margin for the three months ended September 30, 2024 and 2023:


	Three months ended September 30, 2024
($ In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue	$	3,231	$	2,468	$	760	$	499	$	(4)	$	6,954
Energy revenue	12		67		52		—		(3)		128
Capacity revenue	—		40		8		—		(1)		47
Mark-to-market for economic hedging activities	—		1		6		—		1		8
Contract amortization	—		(7)		(1)		—		—		(8)
Other revenue(a)	58		31		8		—		(3)		94
Total revenue	3,301		2,600		833		499		(10)		7,223
Cost of fuel	(226)		(44)		(26)		—		—		(296)
Purchased energy and other cost of sales(b)(c)(d)	(1,996)		(2,122)		(625)		(37)		5		(4,775)
Mark-to-market for economic hedging activities	(1,537)		(10)		(90)		—		(1)		(1,638)
Contract and emissions credit amortization	(5)		11		(3)		—		—		3
Depreciation and amortization	(81)		(39)		(23)		(198)		(11)		(352)
Gross margin	$	(544)	$	396	$	66	$	264	$	(17)	$	165
Less: Mark-to-market for economic hedging activities, net	(1,537)		(9)		(84)		—		—		(1,630)
Less: Contract and emissions credit amortization, net	(5)		4		(4)		—		—		(5)
Less: Depreciation and amortization	(81)		(39)		(23)		(198)		(11)		(352)
Economic gross margin	$	1,079	$	440	$	177	$	462	$	(6)	$	2,152
(a) Includes trading gains and losses and ancillary revenues
(b) Includes capacity and emissions credits
(c) Includes $960 million, $61 million and $203 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 electricity sales volume (GWh)	13,126		4,357		582		—		—		18,065
Business electricity sales volume (GWh)	11,196		12,583		1,973		—		—		25,752
Home natural gas sales volume (MDth)	—		3,464		4,985		—		—		8,449
Business natural gas sales volume (MDth)	—		312,871		36,617		—		—		349,488
Average retail Home customer count (in thousands)(a)	2,946		2,157		755		—		—		5,858
Ending retail Home customer count (in thousands)(a)	2,921		2,132		718		—		—		5,771
Average Vivint Smart Home subscriber count (in thousands)(b)	—		—		—		2,137		—		2,137
Ending Vivint Smart Home subscriber count (in thousands) (b)	—		—		—		2,154		—		2,154
Power generation
GWh sold	8,598		1,521		1,468		—		—		11,587
GWh generated(c)
Coal	5,417		1,040		—		—		—		6,457
Gas	3,181		1		1,467		—		—		4,649


Oil	—		1		—		—		—		1
Renewables	—		—		1		—		—		1
Total	8,598		1,042		1,468		—		—		11,108
(a) Home customer count includes recurring residential customers, services customers and community choice
(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, 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)		(36)		3		(5,585)
Mark-to-market for economic hedging activities	(42)		244		(185)		—		—		17
Contract and emissions credit amortization	(5)		22		(5)		—		—		12
Depreciation and amortization	(84)		(39)		(24)		$	(203)	(9)		(359)
Gross margin	$	896	$	587	$	(80)	$	239	$	(11)	$	1,631
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	(84)		(39)		(24)		(203)		(9)		(359)
Economic gross margin	$	1,027	$	426	$	143	$	442	$	(2)	$	2,036
(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 electricity sales volume (GWh)	15,034		3,799		531		—		—		19,364
Business electricity 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 community choice
(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

The following table represents the weather metrics for the three months ended September 30, 2024 and 2023:


	Three months ended September 30,
Weather Metrics	Texas	East	West/Services/Other(b)
2024
CDDs(a)	1,714	814	1,194
HDDs(a)	—	28	11
2023
CDDs	2,039	817	1,291
HDDs	—	48	4
10-year average
CDDs	1,710	833	1,192
HDDs	3	49	8

(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 $1.5 billion and economic gross margin increased $116 million during the three months ended September 30, 2024, compared to the same period in 2023.

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: •a 5%, or $66 million decrease in cost to serve the retail load, driven by lower realized power prices associated with the Company's diversified supply strategy including asset sales in 2023 •an increase in net revenue of $64 million, primarily driven by changes in customer term, product and mix	$	130
Lower gross margin due to a decrease in load of 2.3 TWhs, or $74 million, due to weather and a decrease in load of 526 GWhs, or $8 million, driven by a change in customer mix	(82)

Other	4
Increase in economic gross margin	$	52
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(1,495)

Decrease in depreciation and amortization	3
Decrease in gross margin	$	(1,440)

East


	(In millions)
Lower gross margin due to a decrease in generation and capacity as a result of asset retirements	$	(3)
Lower electric gross margin due to higher supply costs of $3.50 per MWh, or $67 million, driven primarily by increases in power prices, partially offset by higher net revenue rates as a result of changes in customer term, product and mix of $3.75 per MWh, or $63 million	(4)
Higher electric gross margin due to weather	4
Lower natural gas gross margin from a decrease in load due to customer count and change in customer mix	(12)

Higher natural gas gross margin, including the impact of transportation and storage contract optimization, resulting in lower supply costs of $0.45 per Dth, or $151 million, driven primarily by decreases in gas costs, partially offset by lower net revenue rates from changes in customer term, product, and mix of $0.30 per Dth, or $100 million	51
Lower gross margin due to a reduction in realized capacity prices, as well as a prior year reduction in capacity performance penalties resulting from Winter Storm Elliott in December 2022	(30)

Other	8
Increase in economic gross margin	$	14
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(193)
Increase in contract amortization	(12)

Decrease in gross margin	$	(191)

West/Services/Other


	(In millions)
Higher electric gross margin due to lower supply costs of $33.00 per MWh, or $117 million, partially offset by lower revenue rates of $25.00 per MWh, or $88 million	$	29

Higher gross margin at Cottonwood due to a prior year reduction in capacity performance bonus payments resulting from Winter Storm Elliott in December 2022, higher capacity revenues and spark spread expansion	15
Lower gross margin at Services primarily due to the sale of Airtron	(7)

Other	(3)
Increase in economic gross margin	$	34
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	111

Decrease in depreciation and amortization	1
Increase in gross margin	$	146

Vivint Smart Home


	(In millions)
Higher gross margin driven by growth in subscribers, or $22 million and higher revenue rates of $2.04 per subscriber, or $14 million, partially offset by lower non-recurring sales revenue of $15 million	$	21

Lower gross margin due to recognition of fees associated with licensing products and services	(3)
Other	2
Increase in economic gross margin	$	20


Decrease in depreciation and amortization	5
Increase in gross margin	$	25

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 $1.6 billion during the three months ended September 30, 2024, compared to the same period in 2023.

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


	Three months ended September 30, 2024
(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	$	—	$	4	$	9	$	1	$	14
Reversal of acquired (gain) positions related to economic hedges	—		(1)		—		—		(1)
Net unrealized (losses) on open positions related to economic hedges	—		(2)		(3)		—		(5)
Total mark-to-market gains in revenue	$	—	$	1	$	6	$	1	$	8
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(498)	$	96	$	(25)	$	(1)	$	(428)
Reversal of acquired (gain)/loss positions related to economic hedges	(9)		3		(1)		—		(7)
Net unrealized (losses) on open positions related to economic hedges	(1,030)		(109)		(64)		—		(1,203)
Total mark-to-market (losses) in operating costs and expenses	$	(1,537)	$	(10)	$	(90)	$	(1)	$	(1,638)


	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

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, 2024, the $8 million gain in revenues from economic hedge positions was driven primarily by the reversal of previously recognized unrealized losses on contracts that settled during the period. The $1.6 billion loss in operating costs and expenses from economic hedge positions was driven primarily by a decrease in the value of open positions as a result of decreases in power prices, as well as the reversal of previously recognized unrealized gains on contracts that settled during the period.

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.

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, 2024 and 2023. 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)	2024		2023
Trading gains/(losses)
Realized	$	25	$	7
Unrealized	(5)		(1)
Total trading gains	$	20	$	6

Operations and Maintenance Expense

Operations and maintenance expense is comprised of the following:


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

Three months ended September 30, 2024	$	170	$	102	$	61	$	67	$	1	$	401
Three months ended September 30, 2023	131		93		55		57		(1)		335

Operations and maintenance expense increased by $66 million for the three months ended September 30, 2024, compared to the same period in 2023, due to the following:


	(In millions)
Increase primarily due to the prior year partial property insurance claim for the extended outage at W.A. Parish	$	51
Increase in planned major maintenance expenditures primarily associated with the scope of outages at the Texas coal facilities and Cottonwood	35
Increase driven by higher retail operations costs	17
Increase driven by higher Vivint Smart Home operations costs	10
Decrease primarily due to the sale of STP in November 2023	(33)
Decrease driven by a reduction in deactivation and asset retirement expenditures primarily in the East	(10)
Other	(4)
Increase in operations and maintenance expense	$	66

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, 2024	$	80	$	46	$	4	$	2	$	132
Three months ended September 30, 2023	78		33		3		1		115

Other cost of operations for the three months ended September 30, 2024 increased by $17 million, when compared to the same period in 2023, due to the following:


	(In millions)
Increase due to changes in current year ARO cost estimates at Midwest Generation and Jewett Mine	$	17
Increase primarily due to higher retail gross receipt taxes in the East	6
Decrease primarily due to the sale of STP in November 2023	(7)
Increase due to higher insurance premiums	1
Increase in other cost of operations	$	17

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, 2024	$	81	$	39	$	23	$	198	$	11	$	352
Three months ended September 30, 2023	84		39		24		203		9		359

Depreciation and amortization decreased by $7 million for the three months ended September 30, 2024, compared to the same period in 2023, due to the following:


	(In millions)
Decrease in amortization primarily driven by the expected roll off of the acquired Vivint Smart Home intangibles	$	(32)
Increase in amortization of capitalized contract costs	40
Other	(15)
Decrease in depreciation and amortization	$	(7)

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/Elimination		Total
Three months ended September 30, 2024	$	260	$	157	$	66	$	151	$	11	$	645
Three months ended September 30, 2023	225		144		65		161		7		602

Selling, general and administrative costs increased by $43 million for the three months ended September 30, 2024, compared to the same period in 2023, due to the following:


	(In millions)
Increase in personnel costs primarily driven by an increase in accruals as part of the Company's annual incentive plan reflecting financial outperformance for the year	$	54
Increase in provision for credit losses due to Hurricane Beryl related disconnect moratorium and customer payment behavior	10
Decrease in broker fee and commission expenses	(4)
Decrease in marketing and media expenses	(3)
Decrease due to the sale of STP in November 2023	(3)


Other	(11)
Increase in selling, general and administrative costs	$	43

Acquisition-Related Transaction and Integration Costs

Acquisition-related transaction and integration costs of $7 million and $18 million for the three months ended September 30, 2024 and 2023, respectively, include:


	Three months ended September 30,
(In millions)	2024		2023
Vivint Smart Home integration costs	$	4	$	2

Other integration costs, primarily related to Direct Energy	3		16
Acquisition-related transaction and integration costs	$	7	$	18

Gain on Sale of Assets

The gain on sale of assets of $208 million for the three months ended September 30, 2024 was due to the sale of the Airtron business unit.

Interest Expense

Interest expense increased by $40 million for the three months ended September 30, 2024, compared to the same period in 2023, primarily due to unrealized losses on interest rate swaps for the 2024 period as compared to unrealized gains in the 2023 period.

Income Tax (Benefit)/Expense

For the three months ended September 30, 2024, income tax benefit of $247 million was recorded on pre-tax loss of $1.0 billion. For the same period in 2023, an income tax expense of $65 million was recorded on pre-tax income of $408 million. The effective tax rates were 24.4% and 15.9% for the three months ended September 30, 2024 and 2023, respectively.

For the three months ended September 30, 2024, the effective tax rate was higher than the statutory rate of 21% primarily due to the state tax expense. For the same period in 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.

Management’s discussion of the results of operations for the nine months ended September 30, 2024 and 2023

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, 2024 and 2023.


	Average on Peak Power Price ($/MWh)
	Nine months ended September 30,
Region	2024		2023		Change %
Texas
ERCOT - Houston (a)	$	34.09	$	89.00	(62)	%
ERCOT - North(a)	32.19		87.49		(63)	%

East
NY J/NYC(b)	$	42.79	$	39.43	9	%
NEPOOL(b)	42.62		41.87		2	%
COMED (PJM)(b)	32.50		33.05		(2)	%
PJM West Hub(b)	41.07		38.39		7	%

West
MISO - Louisiana Hub(b)	$	29.78	$	34.54	(14)	%
CAISO - SP15(b)	28.17		63.38		(56)	%

(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, 2024 and 2023:


	Nine months ended September 30,
	2024		2023		Change %
($/MMBtu)	$	2.10	$	2.69	(22)	%

Gross Margin

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, 2024 and 2023:


	Nine months ended September 30, 2024
($ In millions)	Texas		East		West/Services/Other		Vivint Smart Home		Corporate/Eliminations		Total
Retail revenue	$	8,101	$	8,257	$	2,747	$	1,434	$	(12)	$	20,527
Energy revenue	35		194		170		—		(9)		390
Capacity revenue	—		120		16		—		(3)		133
Mark-to-market for economic hedging activities	—		15		14		—		3		32
Contract amortization	—		(23)		(2)		—		—		(25)
Other revenue(a)	161		84		17		—		(8)		254
Total revenue	8,297		8,647		2,962		1,434		(29)		21,311
Cost of fuel	(471)		(98)		(79)		—		—		(648)
Purchased energy and other cost of sales(b)(c)(d)	(5,212)		(7,078)		(2,342)		(108)		17		(14,723)
Mark-to-market for economic hedging activities	(707)		595		(200)		—		(3)		(315)
Contract and emissions credit amortization	(7)		(31)		(5)		—		—		(43)
Depreciation and amortization	(240)		(117)		(96)		$	(561)	(31)		(1,045)
Gross margin	$	1,660	$	1,918	$	240	$	765	$	(46)	$	4,537
Less: Mark-to-market for economic hedging activities, net	(707)		610		(186)		—		—		(283)
Less: Contract and emissions credit amortization, net	(7)		(54)		(7)		—		—		(68)
Less: Depreciation and amortization	(240)		(117)		(96)		(561)		(31)		(1,045)
Economic gross margin	$	2,614	$	1,479	$	529	$	1,326	$	(15)	$	5,933
(a) Includes trading gains and losses and ancillary revenues
(b) Includes capacity and emissions credits
(c) Includes $2.6 billion, $197 million and $860 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 electricity sales volume (GWh)	31,540		11,803		1,722		—		—		45,065
Business electricity sales volume (GWh)	30,936		35,792		7,985		—		—		74,713
Home natural gas sales volume (MDth)	—		33,577		50,027		—		—		83,604
Business natural gas sales volume (MDth)	—		1,118,695		134,310		—		—		1,253,005
Average retail Home customer count (in thousands)(a)	2,949		2,168		761		—		—		5,878
Ending retail Home customer count (in thousands)(a)	2,921		2,132		718		—		—		5,771
Average Vivint Smart Home subscriber count (in thousands)(b)	—		—		—		2,083		—		2,083
Ending Vivint Smart Home subscriber count (in thousands)(b)	—		—		—		2,154		—		2,154
Power generation
GWh sold	16,913		3,639		4,342		—		—		24,894
GWh generated(c)
Coal	10,353		2,005		—		—		—		12,358
Gas	6,560		1		4,338		—		—		10,899

Oil	—		4		—		—		—		4
Renewables	—		—		4		—		—		4
Total	16,913		2,010		4,342		—		—		23,265
(a) Home customer count includes recurring residential customers, services customers and community choice
(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, 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)		(82)		6		(15,863)
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	(257)		(122)		(73)		$	(442)	(27)		(921)
Gross margin	$	2,777	$	(636)	$	(321)	$	546	$	(31)	$	2,335
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	(257)		(122)		(73)		(442)		(27)		(921)
Economic gross margin	$	2,622	$	1,292	$	393	$	988	$	(4)	$	5,291
(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 community choice
(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

The following table represents the weather metrics for the nine months ended September 30, 2024 and 2023:


	Nine months ended September 30,
Weather Metrics	Texas	East	West/Services/Other(b)
2024
CDDs(a)	3,003	1,277	1,881
HDDs(a)	916	2,676	1,310
2023
CDDs	3,183	1,144	1,866
HDDs	856	2,619	1,417
10-year average
CDDs	2,811	1,225	1,797
HDDs	1,040	3,089	1,306

(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 $2.2 billion and economic gross margin increased $642 million, both of which include intercompany sales, during the nine months ended September 30, 2024, compared to the same period in 2023.

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: •an increase in net revenue of $132 million primarily driven by changes in customer term, product and mix •a 4%, or $103 million increase in cost to serve the retail load driven by higher realized power prices associated with the Company's diversified supply strategy including asset sales in 2023	$	29
Lower gross margin due to a decrease in load of 1.8 TWhs, or $57 million, due to weather, partially offset by an increase in load of 1.1 TWhs, or $23 million, driven by an increase in customer counts	(34)
Other	(3)


Decrease in economic gross margin	$	(8)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(1,128)
Decrease in contract and emissions credit amortization	2
Decrease in depreciation and amortization	17
Decrease in gross margin	$	(1,117)

East


	(In millions)
Lower gross margin due to a decrease in generation and capacity as a result of the Joliet and Astoria asset retirements	$	(20)
Higher electric gross margin due to higher net revenue rates as a result of changes in customer term, product and mix of $1.75 per MWh, or $79 million as well as lower supply costs of $0.75 per MWh, or $37 million, driven primarily by decreases in power prices	116
Higher electric gross margin due to an increase in customer count and a change in customer mix	31

Higher natural gas gross margin, including the impact of transportation and storage contract optimization, resulting in lower supply costs of $0.80 per Dth, or $938 million, driven primarily by a decrease in gas costs, partially offset by lower net revenue rates of $0.75 per Dth, or $879 million, from changes in customer term, product, and mix	59
Lower natural gas gross margin from a decrease in load due to customer count and a change in customer mix	(13)
Higher gross margin due to an increase in average realized price at Midwest Generation and tolled facilities, partially offset by higher supply costs	45
Lower gross margin due to a reduction in realized capacity prices, as well as a prior year reduction in capacity performance penalties resulting from Winter Storm Elliott in December 2022	(28)
Other	(3)
Increase in economic gross margin	$	187
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	2,333
Decrease in contract amortization	29
Decrease in depreciation and amortization	5
Increase in gross margin	$	2,554

West/Services/Other


	(In millions)
Higher electric gross margin due to a decrease in supply costs of $21.00 per MWh, or $208 million, and changes in customer mix of $1 million, partially offset by lower revenue rates of $12.00 per MWh, or $118 million	$	91
Higher natural gas gross margin due to lower supply costs of $1.22 per Dth, or $224 million, partially offset by lower revenue rates of $1.15 per Dth, or $212 million, and changes in customer mix of $1 million	11
Higher gross margin at Cottonwood driven by spark spread expansion, favorable current year capacity pricing and a prior year reduction in capacity performance bonus payments resulting from Winter Storm Elliott in December 2022	53
Lower gross margin from market optimization activities	(11)
Lower gross margin at Services primarily due to higher costs primarily driven by inventory reserves, partially offset by increased sales	(9)
Other	1
Increase in economic gross margin	$	136
Increase in mark-to-market for economic hedges primarily due to net unrealized gains/losses on open positions related to economic hedges	445
Decrease in contract amortization	3
Increase in depreciation and amortization	(23)
Increase in gross margin	$	561

Vivint Smart Home(a)


	(In millions)
Increase due to the acquisition of Vivint Smart Home	$	289
Higher gross margin driven by growth in subscribers, or $53 million, higher revenue rates of $1.95 per subscriber or $29 million, partially offset by lower non-recurring sales revenue of $27 million	55
Lower gross margin due to recognition of fees associated with licensing products and services	(7)
Other	1
Increase in economic gross margin	$	338


Increase in depreciation and amortization	(119)
Increase in gross margin	$	219

(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 increased by $1.7 billion during the nine months ended September 30, 2024, compared to the same period in 2023.

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


	Nine months ended September 30, 2024
(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	$	—	$	(28)	$	—	$	3	$	(25)
Reversal of acquired (gain) positions related to economic hedges	—		(1)		—		—		(1)
Net unrealized gains on open positions related to economic hedges	—		44		14		—		58
Total mark-to-market gains in revenue	$	—	$	15	$	14	$	3	$	32
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(616)	$	628	$	55	$	(3)	$	64
Reversal of acquired loss/(gain) positions related to economic hedges	2		(5)		1		—		(2)
Net unrealized (losses) on open positions related to economic hedges	(93)		(28)		(256)		—		(377)
Total mark-to-market (losses)/gains in operating costs and expenses	$	(707)	$	595	$	(200)	$	(3)	$	(315)


	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)

For the nine months ended September 30, 2024, the $32 million gain in revenues from economic hedge positions was driven primarily by an increase in the value of open positions as a result of decreases in power prices, partially offset by the reversal of previously recognized unrealized gains on contracts that settled during the period. The $315 million loss in operating costs and expenses from economic hedge positions was driven primarily by a decrease in the value of open positions as a result of decreases in power prices, partially offset by the reversal of previously recognized unrealized losses on contracts that settled during the period.

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, 2024 and 2023. 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)	2024		2023
Trading gains
Realized	$	30	$	4
Unrealized	—		24
Total trading gains	$	30	$	28

Operations and Maintenance Expense

Operations and maintenance expense are comprised of the following:


(In millions)	Texas		East		West/Services/Other		Vivint Smart Home(a)		Corporate/Eliminations		Total
Nine months ended September 30, 2024	$	585	$	259	$	168	$	178	$	2	$	1,192
Nine months ended September 30, 2023	510		261		179		129		(3)		1,076

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

Operations and maintenance expense increased by $116 million for the nine months ended September 30, 2024, compared to the same period in 2023, due to the following:


	(In millions)
Increase in planned major maintenance expenditures associated with the scope and duration of outages at the Texas coal facilities	$	99
Increase primarily due to the prior year partial property insurance claim for the extended outage at W.A. Parish	95
Increase due to the acquisition of Vivint Smart Home in March 2023	36
Increase driven by higher retail operations costs	14
Increase driven by higher Vivint Smart Home operations costs	13
Decrease primarily due to the sale of STP in November 2023	(115)
Decrease driven by a reduction in deactivation and asset retirement expenditures primarily in the East	(29)
Other	3
Increase in operations and maintenance expense	$	116

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, 2024	$	187	$	104	$	11	$	6	$	308
Nine months ended September 30, 2023	190		98		11		2		301

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

Other cost of operations increased by $7 million for the nine months ended September 30, 2024, compared to the same period in 2023, due to the following:


	(In millions)
Increase due to changes in current year ARO cost estimates at Midwest Generation and Jewett Mine	$	14
Increase in retail gross receipt taxes due to higher revenues in Texas and the East	9
Increase due to higher insurance premiums	8
Decrease primarily due to the sale of STP in November 2023	(22)
Other	(2)
Increase in other cost of operations	$	7

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, 2024	$	240	$	117	$	96	$	561	$	31	$	1,045
Nine months ended September 30, 2023	257		122		73		442		27		921

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

Depreciation and amortization increased by $124 million for the nine months ended September 30, 2024, compared to the same period in 2023, due to the following:


	(In millions)
Increase in amortization of capitalized contract costs	$	123
Increase due to the Vivint Smart Home acquisition in March 2023	93
Decrease in amortization primarily driven by the expected roll off of the acquired Vivint Smart Home intangibles	(74)
Other	(18)
Increase in depreciation and amortization	$	124

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, 2024	$	622	$	435	$	187	$	460	$	35	$	1,739
Nine months ended September 30, 2023	545		407		168		363		19		1,502

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

Total selling, general and administrative costs increased by $237 million for the nine months ended September 30, 2024, compared to the same period in 2023, due to the following:


	(In millions)
Increase due to the Vivint Smart Home acquisition in March 2023	$	96
Increase in provision for credit losses primarily due to higher Texas Home retail revenues and customer payment behavior	54
Increase in personnel costs primarily driven by an increase in accruals as part of the Company's annual incentive plan reflecting financial outperformance for the year	52
Increase in marketing and media expenses	29
Increase in equity linked compensation primarily driven by a higher share price in 2024	24
Decrease driven by the sale of STP in November 2023	(9)
Other	(9)
Increase in selling, general and administrative costs	$	237

Acquisition-Related Transaction and Integration Costs

Acquisition-related transaction and integration costs were $22 million and $111 million for the nine months ended September 30, 2024 and 2023, respectively, include:


	Nine months ended September 30,
(In millions)	2024		2023
Vivint Smart Home integration costs	$	17	$	46
Vivint Smart Home acquisition costs	—		38
Other integration costs, primarily related to Direct Energy	5		27
Acquisition-related transaction and integration costs	$	22	$	111

Gain on Sale of Assets

The gain on sale of assets of $209 million and $202 million for the nine months ended September 30, 2024 and 2023, respectively, included the following:


	Nine months ended September 30,
(In millions)	2024		2023
Sale of the Airtron business unit	$	208	$	—
Sale of Astoria land and related assets	—		199
Other asset sales	1		3
Gain on sale of assets	$	209	$	202

Loss on Debt Extinguishment

A loss on debt extinguishment of $260 million was recorded for the nine months ended September 30, 2024, driven by the repurchase of a portion of the Convertible Senior Notes, as further discussed in Note 7, Long-term Debt and Finance Leases.

Interest Expense

Interest expense increased by $56 million for the nine months ended September 30, 2024, compared to the same period in 2023, primarily due to the acquisition of Vivint Smart Home in March 2023 and unrealized losses on interest rate swaps for the 2024 period as compared to unrealized gains in the 2023 period.

Income Tax Expense/(Benefit)

For the nine months ended September 30, 2024, an income tax expense of $251 million was recorded on a pre-tax income of $733 million. For the same period in 2023, income tax benefit of $182 million was recorded on pre-tax loss of $866 million. The effective tax rates were 34.2% and 21.0% for the nine months ended September 30, 2024 and 2023, respectively.

For the nine months ended September 30, 2024, NRG's effective tax rate was higher than the statutory rate of 21%, primarily due to the state tax expense and permanent differences. For the same period in 2023, NRG's effective tax rate approximated the statutory rate of 21%, which includes the impact of state and foreign taxes.

Liquidity and Capital Resources

Liquidity Position

As of September 30, 2024 and December 31, 2023, NRG's total liquidity, excluding funds deposited by counterparties, of approximately $6.4 billion and $4.8 billion, respectively, was comprised of the following:


(In millions)	September 30, 2024		December 31, 2023
Cash and cash equivalents	$	1,104	$	541
Restricted cash - operating	7		21
Restricted cash - reserves(a)	3		3
Total	1,114		565
Total availability under Revolving Credit Facility and collective collateral facilities(b)	5,330		4,278
Total liquidity, excluding funds deposited by counterparties	$	6,444	$	4,843

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

(b) Total capacity of Revolving Credit Facility and collective collateral facilities was $8.2 billion and $7.4 billion as of September 30, 2024 and December 31, 2023, respectively

For the nine months ended September 30, 2024, total liquidity, excluding funds deposited by counterparties, increased by $1.6 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, 2024 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, and to fund other liquidity 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 over time primarily through debt reduction and the realization of growth initiatives.

Credit Ratings

On March 18, 2024, Standard and Poor's ("S&P") affirmed the Company's issuer credit rating of BB and changed the rating outlook from Stable to Positive.

Liquidity

The principal sources of liquidity for NRG's operating and capital expenditures are expected to be derived from cash on hand, cash flows from operations and financing arrangements. As described in Note 7, 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, Term Loan 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. The Company's capital structure also included the Vivint Senior Notes, Vivint Senior Secured Notes and Vivint 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, as described in Note 7, Long-term Debt and Finance Leases; (iii) capital expenditures, including maintenance, environmental, and investments and integration; and (iv) allocations in connection with acquisition opportunities, debt repayments, share repurchases and dividend payments to stockholders, as described in Note 9, Changes in Capital Structure.

Sale of Airtron

Debt Refinancing Transactions

In the fourth quarter of 2024, the Company entered into the following debt transactions:

Sources

Uses

Issuance by NRG of 6.000% Senior Notes due 2033

$925 million

Repayment of the Vivint Senior Secured Term Loan B

$1.310 billion

Issuance by NRG of 6.250% Senior Notes due 2034

$950 million

Cash tender offer for Vivint 6.750% Senior Secured Notes due 2027(a)

$600 million

Exchange offer for New NRG 5.750% Senior Notes due 2029

$798 million

Exchange offer for Vivint 5.750% Senior Notes due 2029(b)

$798 million

Incremental Term Loan B issued by NRG

$450 million

Repayment of NRG 6.625% Senior Notes due 2027

$375 million

Cash on hand

$5 million

Estimated transactions fees, expenses and premiums

$45 million

Total

$3.128 billion

Total

$3.128 billion

Senior Credit Facility

On April 16, 2024, the Company, as borrower, and certain of its subsidiaries, as guarantors, entered into the Eighth Amendment with, among others, Citicorp North America, Inc., as the Agent and as collateral agent, and certain financial institutions, as lenders, which amended the Credit Agreement, in order to (i) establish a new Term Loan Facility with borrowings of $875 million in aggregate principal amount and the Term Loans and (ii) make certain other modifications to the Credit Agreement as set forth therein. The proceeds from the Term Loans were used to repay a portion of the Company’s Convertible Senior notes, all of the Company’s 3.750% senior secured first lien notes due 2024 and for general corporate purposes.

At the Company’s election, the Term Loans bear interest at a rate per annum equal to either (1) a fluctuating rate equal to the highest of (A) the rate published by the Federal Reserve Bank of New York in effect on such day, plus 0.50%, (B) the rate of interest per annum publicly announced from time to time by The Wall Street Journal as the “Prime Rate” in the United States, and (C) a rate of one-month Term SOFR (as defined in the Credit Agreement) (after giving effect to any floor applicable to Term SOFR) plus 1.00%, in each case, plus a margin of 1.00% or (2) Term SOFR (as defined in the Credit Agreement) (which Term SOFR shall not be less than 0.00%) for a one-, three- or six-month interest period (or such other period as agreed to by the Agent and the lenders, as selected by the Company), plus a margin of 2.00%.

On April 22, 2024, the Company, as borrower, and certain of its subsidiaries, as guarantors, entered into the Ninth Amendment to its Revolving Credit Facility to extend the maturity date of a portion of the revolving commitments thereunder to February 14, 2028. For further discussion, see Note 7, Long-term Debt and Finance Leases.

Convertible Senior Notes

As of October 1, 2024, the Company's Convertible Senior Notes are convertible during the quarterly period ending September 30, 2024 due to the satisfaction of the Common Stock Sale Price Condition. For further discussion, see Note 7, Long-term Debt and Finance Leases.


(In millions, except percentages)
Settlement Period	Principal Repurchased		Cash Paid(a)		Average Repurchase Percentage
March 2024	$	92	$	151	162.356%
April 2024	251		452		179.454%
Total Repurchases	$	343	$	603

(a)Includes accrued interest of $1 million and $2 million for the March and April repurchases, respectively

During the second quarter of 2024, the Company entered into privately negotiated capped call transactions with certain counterparties. The Capped Calls have a cap price of $249.00 per share, subject to certain adjustments, and effectively lock in a conversion premium of $257 million on the remaining $232 million balance of the Convertible Senior Notes. The option price of $257 million was incurred when the Company entered into the Capped Calls, which will be payable upon the earlier of settlement and expiration of the applicable Capped Calls. For further discussion see Note 9, Changes in Capital Structure.

Receivables Securitization Facilities

On June 21, 2024, NRG Receivables, amended its existing Receivables Facility to, among other things, (i) extend the scheduled termination date to June 20, 2025, (ii) increase the aggregate commitments from $1.4 billion to $2.3 billion (adjusted seasonally) and (iii) add a new originator. As of September 30, 2024, there were no outstanding borrowings and there were $1.5 billion in letters of credit issued.

Also on June 21, 2024, the Additional Originator entered into the Joinder Agreement to join as Additional Originator to the Receivables Sale Agreement, dated as of September 22, 2020, among Direct Energy, LP, Direct Energy Business, LLC, Green Mountain Energy Company, NRG Business Marketing, LLC, Reliant Energy Northeast LLC, Reliant Energy Retail Services, LLC, Stream SPE, Ltd., US Retailers LLC and XOOM Energy Texas, LLC, as Originators, NRG Retail, as the servicer, and the Receivables Sale Agreement. Pursuant to the Joinder Agreement, the Additional Originator agrees to be bound by the terms of the Receivables Sale Agreement, will sell to NRG Receivables substantially all of its Receivables and in connection therewith have transferred to NRG Receivables the deposit accounts into which the proceeds of such Receivables are paid.

Concurrently with the amendments to the Receivables Facility, the Company and the originators thereunder terminated the existing uncommitted Repurchase Facility.

Senior Secured First Lien Note Repayment

During the second quarter of 2024, the Company repaid $600 million in aggregate principal amount of its 3.750% Senior Secured First Lien Notes due 2024.

Vivint Term Loan Repricing

On April 10, 2024, Vivint, entered into the Second Amendment with, among others, the Vivint Agent, and certain financial institutions, as lenders, which amended the Vivint Credit Agreement, in order to (i) reprice its term loan B facility (the term loans thereunder, the “Vivint Term Loans”) and (ii) make certain other modifications to the Vivint Credit Agreement as set forth therein.

At Vivint’s election, the Vivint Term Loans will bear interest at a rate per annum equal to either (1) a fluctuating rate equal to the highest of (A) the rate published by the Federal Reserve Bank of New York in effect on such day, plus 0.50%, (B) the rate of interest per annum publicly announced from time to time by The Wall Street Journal as the “Prime Rate” in the United States, and (C) a rate of one-month Term SOFR (as defined in the Vivint Credit Agreement), (after giving effect to any floor applicable to Term SOFR) plus 1.00% in each case, plus a margin of 1.75%, or (2) Term SOFR (as defined in the Vivint Credit Agreement) (which Term SOFR shall not be less than 0.50%) for a one-, three- or six-month interest period or such other period as agreed to by the Vivint Agent and the lenders, as selected by Vivint, plus a margin of 2.75%.

Liability Management

The Company previously announced it intended to spend approximately $500 million reducing debt during 2024 to maintain its targeted credit metrics. As the Company has updated the 2024 capital allocation plan, NRG's planned spend on reducing debt has been adjusted to $335 million, as NRG believes it will maintain its targeted credit metrics.

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, 2024, the Company had total cash collateral outstanding of $449 million and $2.9 billion outstanding in letters of credit to third parties primarily to support its market activities. As of September 30, 2024, total funds deposited by counterparties were $12 million in cash and $275 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 the capacity to grant 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, 2024, all hedges under the first liens were out-of-the-money on a counterparty aggregate basis.

Capital Expenditures

The following table summarizes the Company's capital expenditures for maintenance, environmental and growth investments for the nine months ended September 30, 2024, and the estimated forecast for the remainder of the year.


(In millions)	Maintenance		Environmental		Investments and Integration		Total
Texas	$	142	$	13	$	57	$	212
East	—		2		—		2
West/Services/Other	12		—		1		13
Vivint Smart Home	14		—		4		18
Corporate	12		—		29		41
Total cash capital expenditures for the nine months ended September 30, 2024	$	180	$	15	$	91	$	286
Integration operating expenses and cost to achieve	—		—		47		47
Investments	—		—		156		156
Total cash capital expenditures and investments for the nine months ended September 30, 2024	$	180	$	15	$	294	$	489




Estimated cash capital expenditures and investments for the remainder of 2024(a)	130		10		96		236
Estimated full year 2024 cash capital expenditures and investments	$	310	$	25	$	390	$	725

(a)Excludes capital expenditures related to brownfield development projects that were submitted to the Texas Energy Fund

Investments and Integration for the nine months ended September 30, 2024 include growth expenditures, integration, small book acquisitions and other investments.

Environmental Capital Expenditures

NRG estimates that environmental capital expenditures from 2024 through 2028 required to comply with environmental laws will be approximately $93 million, primarily driven by the cost of complying with ELG at the Company's coal units in Texas.

Share Repurchases

The Company's long-term capital allocation policy is to target allocating approximately 80% of cash available for allocation after debt reduction to be returned to shareholders. In June 2023, NRG announced an increase to its share repurchase authorization to $2.7 billion, to be executed through 2025 as part of the existing share repurchase authorization. In October 2024, the Board of Directors authorized an additional $1.0 billion for share repurchases as part of the existing share repurchase authorization.

During the nine months ended September 30, 2024, the Company completed $319 million of open market share repurchases at an average price of $79.26 per share. Through October 31, 2024, an additional $225 million of share repurchases were executed at an average price of $89.23 per share. As of October 31, 2024, $2.0 billion is remaining under the $3.7 billion authorization. See Note 9, Changes in Capital Structure for additional discussion.

Common Stock Dividends

Series A Preferred Stock Dividends

During the quarters ended March 31, 2024 and September 30, 2024, the Company declared and paid a semi-annual 10.25% dividend of $51.25 per share on its outstanding Series A Preferred Stock, each totaling $33 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 2023 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. NRG's pro-rata share of non-recourse debt was approximately $461 million as of September 30, 2024. 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 2023 Form 10-K. See also Note 7, Long-term Debt and Finance Leases, and Note 14, 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, 2024.

Cash Flow Discussion

The following table reflects the changes in cash flows for the nine month ended September 30, 2024 and 2023, respectively:


	Nine months ended September 30,
(In millions)	2024		2023		Change
Cash provided/(used) by operating activities	$	1,354	$	(462)	$	1,816
Cash provided/(used) by investing activities	163		(2,631)		2,794
Cash (used)/provided by financing activities	(1,041)		1,590		(2,631)

Cash provided/(used) by operating activities

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


	(In millions)
Changes in cash collateral in support of risk management activities due to change in commodity prices	$	1,108
Increase in operating income/loss adjusted for other non-cash items	636
Increase in working capital primarily due to lower gas pricing coupled with lower gas sales volumes	396
Decrease in working capital primarily driven by capitalized contract costs and deferred revenues	(209)
Decrease in working capital primarily related to the payout of the Company's annual incentive plan in 2024 reflecting financial outperformance for 2023	(115)







	$	1,816

Cash provided/(used) by investing activities

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


	(In millions)
Decrease in cash paid for acquisitions primarily due to the acquisition of Vivint Smart Home in March 2023	$	2,469
Increase in proceeds from sale of assets primarily due to the sale of the Airtron business unit in 2024 as compared to the sale of the land and related assets from the Astoria site in 2023	266
Decrease in capital expenditures	207
Decrease in insurance proceeds for property, plant and equipment, net	(170)
Other	22





	$	2,794

Cash (used)/provided by financing activities

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


	(In millions)
Decrease due to repayments of long-term debt and finance leases	$	(945)
Decrease in proceeds due to the issuance of preferred stock in 2023	(635)
Decrease in net receipts from settlement of acquired derivatives	(334)
Decrease in proceeds from Revolving Credit Facility and Receivables Securitization Facilities in 2023	(300)
Decrease due to payments for share repurchase activity	(292)
Decrease primarily due to debt extinguishment costs in 2024	(242)
Increase in proceeds due to the issuance of long-term debt	144
Increase in payments of dividends primarily due to preferred stock	(27)





	$	(2,631)

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

For the nine months ended September 30, 2024, the Company had domestic pre-tax book income of $827 million and foreign pre-tax book loss of $94 million. As of December 31, 2023, the Company had cumulative U.S. Federal NOL carryforwards of $8.4 billion, of which $6.4 billion do not have an expiration date, and cumulative state NOL carryforwards of $6.4 billion for financial statement purposes. NRG also has cumulative foreign NOL carryforwards of $411 million, most of which do not have an expiration date. In addition to the above NOLs, NRG has a $517 million indefinite carryforward for interest deductions, as well as $317 million of tax credits to be utilized in future years. 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 $215 million in 2024, which includes the estimated impact of the sale of the Airtron business unit. As of September 30, 2024, there is no impact on the Company's provision for income taxes from the CAMT.

As of September 30, 2024, the Company has $66 million of tax-effected uncertain federal and state tax benefits, for which the Company has recorded a non-current tax liability of $70 million (inclusive of accrued interest) until final resolution is reached with the related taxing authority.

On December 31, 2021, the OECD released rules which set forth a common approach to a global minimum tax at 15% for multinational companies, which has been enacted into law by certain countries effective for 2024. The Company's preliminary analysis indicates that there is no material impact to the Company's financial statements from these rules.

The Company is no longer subject to U.S. federal income tax examinations for years prior to 2020. With few exceptions, state and Canadian income tax examinations are no longer open for years prior to 2015.

Deferred tax assets and valuation allowance

Net deferred tax balance — As of September 30, 2024 and December 31, 2023, NRG recorded a net deferred tax asset, excluding valuation allowance, of $2.4 billion and $2.5 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, 2024 and December 31, 2023 as discussed below.

NOL Carryforwards — As of September 30, 2024, the Company had a tax-effected cumulative U.S. NOLs consisting of carryforwards for federal and state income tax purposes of $1.8 billion and $367 million, respectively. 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 2030. In addition, NRG has tax-effected cumulative foreign NOL carryforwards of $110 million.

Valuation Allowance — As of September 30, 2024 and December 31, 2023, the Company’s tax-effected valuation allowance was $275 million, 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, 2024, 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 7, 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. On October 30, 2024, NRG redeemed all of its outstanding 6.625% Senior Notes due 2027, of which $375 million aggregate principal amount was outstanding.

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 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 the 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, 2024
Revenue(a)	$	17,862
Operating income(b)	1,482
Total other expense	(553)
Income before income taxes	929
Net Income	649

(a)Intercompany transactions with Non-Guarantors of $2 million during the nine months ended September 30, 2024

(b)Intercompany transactions with Non-Guarantors including cost of operations of $10 million and selling, general and administrative of $247 million during the nine months ended September 30, 2024

The following table presents the summarized balance sheet information:


(In millions)	September 30, 2024
Current assets(a)	$	5,244
Property, plant and equipment, net	1,213
Non-current assets	11,491
Current liabilities(b)	5,810
Non-current liabilities	9,873

(a)Includes intercompany receivables due from Non-Guarantors of $41 million as of September 30, 2024

(b)Includes intercompany payables due to Non-Guarantors of $31 million as of September 30, 2024

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 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.

The following tables 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 ("ASC 820"). Specifically, these tables disaggregate realized and unrealized changes in fair value; disaggregate estimated fair values as of September 30, 2024, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at September 30, 2024. 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, 2023	$	648
Contracts realized or otherwise settled during the period	62

Other changes in fair value	(327)
Fair Value of Contracts as of September 30, 2024	$	383


	Fair Value of Contracts as of September 30, 2024
(In millions)	Maturity
Fair Value Hierarchy (Losses)/Gains	1 Year or Less		Greater than 1 Year to 3 Years		Greater than 3 Years to 5 Years		Greater than 5 Years		Total Fair Value
Level 1	$	(2)	$	(15)	$	(8)	$	(3)	$	(28)
Level 2	216		210		98		113		637
Level 3	(109)		(97)		(21)		1		(226)
Total	$	105	$	98	$	69	$	111	$	383

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, 2024, NRG's net derivative asset was $383 million, a decrease to total fair value of $265 million as compared to December 31, 2023. This decrease was primarily driven by losses in fair value, partially offset by the roll-off of trades that settled 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 a change of approximately $1.8 billion in the net value of derivatives as of September 30, 2024.

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 2023 Form 10-K. There have been no material changes to the Company's critical accounting estimates since the 2023 Form 10-K.

ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

NRG is exposed to several market risks in the Company's normal business activities. Market risk is the potential loss that may result from market changes associated with the Company's 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 2023 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 ended September 30, 2024 and 2023:


(In millions)	2024		2023
VaR as of September 30,	$	67	$	63
Three months ended September 30,
Average	$	58	$	64
Maximum	67		75
Minimum	50		45
Nine months ended September 30,
Average	$	61	$	66
Maximum	75		82
Minimum	50		45

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 $149 million, as of September 30, 2024, 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 sales. Counterparty credit risk and retail customer credit risk are discussed below. See Note 6, Accounting for Derivative Instruments and Hedging Activities, to this Form 10-Q for discussion regarding credit risk contingent features.

Counterparty Credit Risk

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	75	%
Financial institutions	25

Total as of September 30, 2024	100	%


	Net Exposure (a)(b)
Category by Counterparty Credit Quality	(% of Total)
Investment grade	59	%
Non-investment grade/Non-Rated	41
Total as of September 30, 2024	100	%

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

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

The Company currently has no exposure to wholesale counterparties in excess of 10% of total net exposure discussed above as of September 30, 2024. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration.

RTOs and ISOs

Exchange Traded Transactions

Long-Term Contracts

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 forward value. The Company manages retail credit risk through the use of established credit policies, 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, 2024, 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 $1.3 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 $338 million. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of September 30, 2024.

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 2024, the Company entered into interest rate swaps with a total nominal value of $700 million extending through 2029 to hedge the floating rate of the Term Loans. Additionally, as of September 30, 2024, the Company had $1.0 billion of interest rate swaps extending through 2027 to hedge the floating rate on the Vivint Term Loans. In November 2024, in connection with the repayment of the Vivint Term Loans and the increase of the Term Loans, the Company decreased its interest rate swap notional value from $1.7 billion to $700 million.

As of September 30, 2024, the fair value and related carrying value of the Company's debt was $10.9 billion and $10.7 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, 2024 by $464 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 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, 2024, 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 $433 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, 2024 would have resulted in a decrease of $9 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, 2024 that materially affected, or are reasonably likely to materially affect, NRG's internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 1 — LEGAL PROCEEDINGS

For a discussion of material legal proceedings in which NRG was involved through September 30, 2024, see Note 14, Commitments and Contingencies, to this Form 10-Q.

ITEM 1A — RISK FACTORS

During the nine months ended September 30, 2024, there were no material changes to the Risk Factors disclosed in Part I, Item 1A, Risk Factors, of the Company's 2023 Form 10-K.

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, 2024.


For the three months ended September 30, 2024	Total Number of Shares Purchased(a)	Average Price Paid per Share(b)		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (in millions)(c)
Month #1
(July 1, 2024 to July 31, 2024)	1,128,299	$	76.28	1,127,232	$	1,374
Month #2
(August 1, 2024 to August 31, 2024)	933,540	$	78.26	932,019	$	1,301
Month #3
(September 1, 2024 to September 30, 2024)	844,543	$	82.41	844,543	$	1,231

Total at September 30, 2024	2,906,382	$	78.70	2,903,794

(a)Includes share repurchases under the June 22, 2023 $2.7 billion share repurchase authorization and partial settlement of Capped Call Options. For further discussion, see Note 9, Changes in Capital Structure

(b)The average price paid per share excludes excise tax and commissions paid in connection with the open market share repurchases

(c)Includes commissions paid in connection with the open market share repurchases and excludes the additional $1.0 billion share repurchases authorized by the Board of Directors in October 2024. For further discussion, see Note 9, Changes in Capital Structure

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

During the three months ended September 30, 2024, the following directors or officers 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, as described in the table below:

Name

Title

Date Adopted

Character of Trading Arrangement

Aggregate Number of Shares of Common Stock to be Purchased or Sold Pursuant to Trading Arrangement(a)

Duration

Date Terminated

Robert Gaudette

Executive Vice President, NRG Business

9/6/2024

Rule 10b5-1 Trading Arrangement

Up to 60,000 shares to be Sold

1/2/2025-2/28/2025

N/A

Woo-Sung Chung

Executive Vice President and Chief Financial Officer

9/13/2024

Rule 10b5-1 Trading Arrangement

Up to 20,000(b) shares to be Sold

1/13/2025-3/1/2025

N/A

(a)Potential sales may be subject to certain price limitations set forth in the 10b5-1 plans and therefore actual number of shares sold could vary if certain minimum stock prices are not met

(b)Represents approximate number of shares to be sold based on outstanding awards expected to vest during the period, where certain underlying performance share awards are being calculated at target. Actual number of shares to be sold will depend on actual vesting, the number of shares withheld by NRG to satisfy tax withholding obligations and vesting of dividend equivalent rights

ITEM 6 — EXHIBITS

Number

Description

Method of Filing

4.1

Base Indenture, dated October 30, 2024, between NRG Energy, Inc. and Deutsche Bank Trust Company Americas, as trustee, pertaining to the Notes.

Incorporated herein by reference to Exhibit 4.1 to the Registrant's current report on Form 8-K filed on November 1, 2024.

4.2

Supplemental Indenture, dated October 30, 2024, among NRG Energy, Inc., the guarantors named therein and Deutsche Bank Trust Company Americas, as trustee, containing Form 5.75% Senior Note due 2029, Form of 6.00% Senior Notes due 2033 and Form of 6.25% Senior Notes due 2034.

Incorporated herein by reference to Exhibit 4.2 to the Registrant's current report on Form 8-K filed on November 1, 2024.

10.1

Tenth Amendment to Second Amended and Restated Credit Agreement, dated as of October 30, 2024, by and among NRG Energy, Inc., Citicorp North America, Inc., as administrative agent and as collateral agent, and certain financial institutions, as lenders.

Incorporated herein by reference to Exhibit 10.1 to the Registrant's current report on Form 8-K filed on November 1, 2024.

10.2

Eleventh Amendment to Second Amended and Restated Credit Agreement, dated as of October 30, 2024, by and among NRG Energy, Inc., Citicorp North America, Inc., as administrative agent and as collateral agent, and certain financial institutions, as lenders.

Incorporated herein by reference to Exhibit 10.2 to the Registrant's current report on Form 8-K filed on November 1, 2024.

22.1

List of Guarantor Subsidiaries

Filed herewith.

31.1

Rule 13a-14(a)/15d-14(a) certification of Lawrence S. Coben.

Filed herewith.

31.2

Rule 13a-14(a)/15d-14(a) certification of Woo-Sung Chung.

Filed herewith.

31.3

Rule 13a-14(a)/15d-14(a) certification of G. Alfred Spencer.

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.