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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
x☒Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the Quarterly Period Ended: September 30, 2017March 31, 2023
o☐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)
41-1724239
(I.R.S. Employer

Identification No.)
910 Louisiana StreetHoustonTexas77002
804 Carnegie Center, Princeton, New Jersey
(Address of principal executive offices)
08540
(Zip Code)
(609) 524-4500(713) 537-3000
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each ClassTrading Symbol(s)Name of Exchange on Which Registered
Common Stock, par value $0.01NRGNew 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.
Yesx☒Noo☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files).
Yesx☒Noo☐
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☐
Large accelerated filer x
Accelerated filer o
Non-accelerated filer o
Smaller reporting company o
Emerging growth company o
(Do not check if a smaller reporting 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.  o☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yeso☐Nox☒
As of October 31, 2017,April 30, 2023, there were 316,641,799230,232,374 shares of common stock outstanding, par value $0.01 per share.




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TABLE OF CONTENTS
Index
3
5
108
ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES
108
ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
6544
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
10266
ITEM 4 — CONTROLS AND PROCEDURES
10468
10569
ITEM 1 — LEGAL PROCEEDINGS
10569
ITEM 1A — RISK FACTORS
10569
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
10583
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES
10583
ITEM 4 — MINE SAFETY DISCLOSURES
10583
ITEM 5 — OTHER INFORMATION
10583
ITEM 6 — EXHIBITS
10684
SIGNATURES
10786






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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""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 Item 1A — Risk Factors Related to NRG Energy, Inc., in Part I,II, Item 1A of the Company's Annual Report onthis Form 10-K for the year ended December 31, 2016,10-Q and the following:
•Business uncertainties related to NRG's ability to achieveintegrate the expected benefitsoperations of Vivint with its Transformation Plan;own;
The potential adverse effects of the GenOn Entities' filings under Chapter 11 of the Bankruptcy Code and restructuring transactions on NRG's operations, management and employees and the risks associated with operating NRG's business during the restructuring process;
Risks and uncertainties associated with the GenOn Entities' Chapter 11 Cases including the ability to achieve anticipated benefits therefrom;
•NRG's ability to engage in successful mergersobtain and acquisitions activity;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;power and gas;
•Changes in law, including judicial and regulatory decisions;
•Hazards customary to the power production industry and power generation operations, such as fuel and electricity price volatility, unusual weather conditions, (including wind and solar 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;
NRG's ability to enter into contracts to sell power and procure fuel on acceptable terms and prices;
•The liquidity and competitiveness of wholesale markets for energy commodities;
•Government regulation, including compliance with regulatory requirements and changes in market rules, rates, tariffs and environmental laws;
Changes in law, including judicial decisions;•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 for units subject to capacity performance requirements in PJM, performance incentives in ISO-NE, and scarcity pricing in ERCOT;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 going forward;in the future;
•Operating and financial restrictions placed on NRG and its subsidiaries that are contained in the indentures governing NRG's outstanding notes, in NRG's Senior Credit Facility,corporate credit agreements, and in debt and other agreements of certain of NRG subsidiaries and project affiliates generally;
Cyber terrorism•The ability of NRG and inadequate cybersecurity, or the occurrence of a catastrophic loss and the possibility that NRG may not have adequate insurance to cover losses resulting from such hazards or the inability of NRG's insurers to provide coverage;
NRG's abilityits counterparties to develop and build new power generation facilities;
NRG's ability to develop and innovate new products as retail and wholesale markets continue to change and evolve;
•NRG's ability to implement its strategy of finding ways to meet the challenges of climate change, clean air and protecting natural resources, while taking advantage of business opportunities;
•NRG's ability to increase cash from operations through operational and commercialmarket initiatives, corporate efficiencies, asset strategy, and a range of other programs throughout NRG to reduce costs or generate revenues;


NRG's ability to sell assets to NRG Yield, Inc. and to close drop-down transactions;
NRG's ability to achieve its strategy of regularly returning capital to stockholders;
NRG's ability to obtain and maintain retail market share;
•NRG's ability to successfully evaluate investments and achieve intended financial results in new business and growth initiatives; and
NRG's ability to successfully integrate, realize cost savings and manage any acquired businesses; and
•NRG's ability to develop and maintain successful partnering relationships.relationships as needed.


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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.otherwise except as otherwise required by applicable laws. The foregoing review of 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.



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GLOSSARY OF TERMS
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:
20162022 Form 10-KNRG’s Annual Report on Form 10-K for the year ended December 31, 20162022
2023 Term Loan FacilityACEThe Company's $1.9 billion term loan facility due 2023, a component of the Senior Credit FacilityAffordable Clean Energy
Adjusted EBITDAAESOAdjusted earnings before interest, taxes, depreciation and amortizationAlberta Electric System Operator
ASCAROAsset Retirement Obligation
ASCThe FASB Accounting Standards Codification, which the FASB established as the source of authoritative GAAP
ASUAccounting Standards Updates which reflect- updates to the ASC
Average realized pricesBTUVolume-weighted average power prices, net of average fuel costs and reflecting the impact of settled hedges
BACTBest Available Control Technology
Bankruptcy CodeChapter 11 of Title 11 of the U.S. Bankruptcy Code
Bankruptcy CourtUnited States Bankruptcy Court for the Southern District of Texas, Houston Division
BETMBoston Energy Trading and Marketing LLC
BTUBritish Thermal Unit
CAABusinessNRG Business, which serves business customers
CAAClean Air Act
CAIRCAISOClean Air Interstate Rule
CAISOCalifornia Independent System Operator
CDDCooling Degree Day
CDWRCFTCCalifornia Department of Water Resources
CECCalifornia Energy Commission
CenterPointCenterPoint Energy, Inc. and its subsidiaries, on and after August 31, 2002, and Reliant Energy, Incorporated and its subsidiaries prior to August 31, 2002
CFTCU.S. Commodity Futures Trading Commission
Chapter 11 CasesVoluntary cases commenced by the GenOn Entities under the Bankruptcy Code in the Bankruptcy Court
COD
CO2
Commercial Operation DateCarbon Dioxide
ComEdCompanyCommonwealth Edison
CompanyNRG Energy, Inc.
CPPConvertible Senior NotesAs of March 31, 2023, consists of NRG’s $575 million unsecured 2.75% Convertible Senior Notes due 2048
CottonwoodCottonwood Generating Station, a natural gas-fueled plant located in Deweyville, Texas in which NRG is leasing back through May 2025
CPPClean Power Plan
CPUCCalifornia Public Utilities Commission
CSAPRCWACross-State Air Pollution RuleClean Water Act
CVSRCalifornia Valley Solar Ranch
D.C. CircuitU.S. Court of Appeals for the District of Columbia Circuit
DGPV Holdco 1DthNRG DGPV Holdco 1 LLCDekatherms
DGPV Holdco 2NRG DGPV Holdco 2 LLC
Distributed SolarSolar power projects that primarily sell power to customers for usage on site, or are interconnected to sell power into a local distribution grid
DSIDry Sorbent Injection
Economic gross marginSum of retail revenue, energy revenue, capacity revenue, retail revenue and other revenue, less cost of fuels and purchased energy and other cost of sales
ELGEGUEffluent Limitations GuidelinesElectric Generating Unit
El Segundo Energy CenterEPANRG West Holdings LLC, the subsidiary of Natural Gas Repowering LLC, which owns the El Segundo Energy Center project
EMEEdison Mission Energy
Energy Plus HoldingsEnergy Plus Holdings LLC
EPAU.S. Environmental Protection Agency


ERCOT
EPCEngineering, Procurement and Construction
ERCOTElectric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas
ESCOESPPEnergy Service Company
ESPElectrostatic Precipitator
ESPPNRG Energy, Inc. Amended and Restated Employee Stock Purchase Plan
ESPSExisting Source Performance Standards
Exchange ActThe Securities Exchange Act of 1934, as amended
FASBFinancial Accounting Standards Board
FERCFederal Energy Regulatory Commission
FGDFlue gas desulfurization
FTRsFinancial Transmission Rights
GAAPAccountingGenerally accepted accounting principles generally accepted in the U.S.
GenConnGHGGenConn Energy LLCGreenhouse Gas
GenOnGreen Mountain EnergyGenOnGreen Mountain Energy Inc.Company
GenOn Americas GenerationGWGenOn Americas Generation, LLCGigawatts
GenOn Americas Generation Senior NotesGWhGenOn Americas Generation's $695 million outstanding unsecured senior notes consisting of $366 million of 8.5% senior notes due 2021 and $329 million of 9.125% senior notes due 2031Gigawatt Hour
GenOn EntitiesHDDGenOn and certain of its wholly owned subsidiaries, including GenOn Americas Generation. that filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court on June 14, 2017
GenOn Senior NotesGenOn's $1.8 billion outstanding unsecured senior notes consisting of $691 million of 7.875% senior notes due 2017, $649 million of 9.5% senior notes due 2018, and $489 million of 9.875% senior notes due 2020
GHGGreenhouse Gas
GWGigawatt
GWhGigawatt Hour
HAPHazardous Air Pollutant
HDDHeating Degree Day
Heat RateA 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 and isgeneration. Heat rates are generally expressed as BTU per net kWh
HLBVHomeHypothetical Liquidation at Book ValueNRG Home, which serves residential customers
IASBHLWIndependent Accounting Standards BoardHigh-level radioactive waste
IFRSICEInternational Financial Reporting StandardsIntercontinental Exchange

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ILUIESOIllinois Union Insurance CompanyIndependent Electricity System Operator
ISOIndependent System Operator, also referred to as RTOs
ISO-NEISO New England Inc.
ITCIvanpahInvestment Tax CreditIvanpah Solar Electric Generation Station, a solar thermal power plant located in California's Mojave Desert in which NRG owns 54.5% interest
LaGenkWhKilowatt-hour
LaGenLouisiana Generating, L.L.C.LLC
LIBORLondon Inter-Bank Offered Rate
LTIPsLSEsLoad Serving Entities
LTIPsCollectively, the NRG Long-Term Incentive Plan, as amended,long-term incentive plan ("LTIP") and the NRG GenOn Long-Term Incentive PlanVivint LTIP
Marsh LandingMDthNRG Marsh Landing, LLC (formerly known as GenOn Marsh Landing, LLC)Thousand Dekatherms
Mass MarketResidential and small commercial customers
MATSMercury and Air Toxics Standards promulgated by the EPA
MDthThousand Dekatherms
Midwest GenerationMidwest Generation, LLC
MISOMidcontinent Independent System Operator, Inc.


MMBtu
MMBtuMillion British Thermal Units
MWMegawatts
MWhSaleable megawatt hour net of internal/parasitic load megawatt-hour
MWtNAAQSMegawatts Thermal Equivalent
NAAQSNational Ambient Air Quality Standards
NEPOOLNew England Power Pool
NERCNorth American Electric Reliability Corporation
Net ExposureCounterparty credit exposure to NRG, net of collateral
Net GenerationRevenue RateThe net amountSum of electricity produced, expressed in kWhs or MWhs, that is the total amount of electricity generated (gross) minus the amount of electricity used during generationretail revenues less TDSP transportation charges
NOLNodalNodal Exchange is a derivatives exchange
NOLNet Operating Loss
NOx
NOx		Nitrogen Oxides
NPDESNPNSNational Pollutant Discharge Elimination System
NPNSNormal Purchase Normal Sale
NRCU.S. Nuclear Regulatory Commission
NRGNRG Energy, Inc.
NRG YieldReporting segment including the projects owned by NRG Yield, Inc.
NRG Yield 2019 Convertible Notes$345 million aggregate principal amount of 3.50% Convertible Senior Notes due 2019 issued by NRG Yield, Inc.
NRG Yield 2020 Convertible Notes$287.5 million aggregate principal amount of 3.25% Convertible Notes due 2020 issued by NRG Yield, Inc.
NRG Yield, Inc.NRG Yield, Inc., the owner of 53.7% of the economic interests of NRG Yield LLC with a controlling interest, and issuer of publicly held shares of Class A and Class C common stock
NSRNew Source Review
Nuclear Decommissioning Trust FundNRG's nuclear decommissioning trust fund assets, which are for the Company's portion of the decommissioning of the STP, unitsUnits 1 & 2
NYAGNuclear Waste Policy ActStateU.S. Nuclear Waste Policy Act of New York Office of Attorney General1982
NYISONew York Independent System Operator
NYSPSCNYMEXNew York State Public Service CommissionMercantile Exchange
OCI/OCLOther Comprehensive Income/(Loss)
PeakingORDCUnits expected to satisfy demand requirements during the periods of greatest or peak load on the systemOperating Reserve Demand Curve
PERPeak Energy Rent
Petition DatePG&EJune 14, 2017
PG&EPacific Gas and Electric Company
PJMPJM Interconnection, LLC
PMPM2.5Particulate Matter that has a diameter of less than 2.5 micrometers
PPAPower Purchase Agreement
PSDPUCTPrevention of Significant Deterioration
PTCProduction Tax Credit
PUCTPublic Utility Commission of Texas
RAPARCRAResource Adequacy Purchase Agreement
RCRAResource Conservation and Recovery Act of 1976
REMANRG REMA LLC, which leases a 100% interest in the Shawville generating facility and 16.7% and 16.5% interests in the Keystone and Conemaugh generating facilities, respectively
RepoweringTechnologies utilized to replace, rebuild, or redevelop major portions of an existing electrical generating facility to achieve a substantial emissions reduction, increase facility capacity and improve system efficiency
Restructuring Support AgreementRestructuring Support and Lock-Up Agreement, dated as of June 12, 2017 and as amended on October 2, 2017, by and among GenOn Energy, Inc., GenOn Americas Generation, LLC, the subsidiaries signatory thereto, NRG Energy, Inc. and the noteholders signatory thereto


RetailReceivables FacilityReporting segment that includes NRG's residential and small commercial businessesNRG Receivables LLC, a bankruptcy remote, special purpose, wholly-owned indirect subsidiary of the Company's $1.0 billion accounts receivables securitization facility due 2023, which go to market as Reliant, NRG and other brands owned by NRG, as well as Business Solutionswas last amended on July 26, 2022
Receivables Securitization FacilitiesCollectively, the Receivables Facility and the Repurchase Facility
Renewable PPAA 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
REPRetail electric provider
Repurchase FacilityNRG's $150 million uncommitted repurchase facility related to the Receivables Facility due 2023, which was last amended on July 26, 2022

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Revolving Credit Facility
The Company’s $2.5 billion revolving credit facility, a component of the Senior Credit Facility. The revolving credit facility consists of $289 million of Tranche A Revolving Credit Facility, due 2018, and $2.2 billion of Tranche B Revolving Credit Facility, due 2021

Prior to June 30, 2016, the Company's $2.5$4.3 billion revolving credit facility due 2018, a component of the Senior Credit Facility. On June 30, 2016, the Company replaced the Senior Credit Facility, including the Revolving Credit Facility
2028, was last amended on March 13, 2023
RGGIRegional Greenhouse Gas Initiative
RMRRTOReliability Must-Run
ROFO AgreementSecond Amended and Restated Right of First Offer Agreement between the Company and NRG Yield, Inc.
RPV HoldcoNRG RPV Holdco 1 LLC
RTORegional Transmission Organization, also referred to as ISOs
SCESECSouthern California Edison
SDG&ESan Diego Gas & Electric Company
SECU.S. Securities and Exchange Commission
Securities ActThe Securities Act of 1933, as amended
Senior Credit Facility
NRG's senior secured credit facility, compromised of the Revolving Credit Facility and the 2023 Term Loan Facility

Prior to June 30, 2016, the Company's senior secured facility, comprised of the Term Loan Facility and the Revolving Credit Facility. On June 30, 2016, the Company replaced the Senior Credit Facility
Senior NotesAs of September 30, 2017, the Company’s $5.4March 31, 2023, NRG's $4.6 billion outstanding unsecured senior notes consisting of $398$375 million of 7.625% senior notes due 2018, $207 million of 7.875% senior notes due 2021, $992 million of 6.25% senior notes due 2022, $869 million ofthe 6.625% senior notes due 2023,2027, $821 million of 5.75% senior notes due 2028, $733 million of 6.25%the 5.25% senior notes due 2024,2029, $500 million of the 3.375% senior notes due 2029, $1.0 billion of 7.25%the 3.625% senior notes due 20262031 and $1.25$1.1 billion of 6.625%the 3.875% senior notes due 20272032
Senior Secured First Lien NotesAs of March 31, 2023, NRG’s $3.4 billion outstanding Senior Secured First Lien Notes consists of $600 million of the 3.75% Senior Secured First Lien Notes due 2024, $500 million of the 2.0% Senior Secured First Lien Notes due 2025, $900 million of the 2.45% Senior Secured First Lien Notes due 2027, $500 million of the 4.45% Senior Secured First Lien Notes due 2029 and $740 million of the 7.000% Senior Secured First Lien Notes due 2033
ServicesNRG Services, AgreementNRG provides GenOn with various management, personnel and otherwhich primarily includes the services which include human resources, regulatory and public affairs, accounting, tax, legal, information systems, treasury, risk management, commercial operations, and asset management, as set forthbusinesses acquired in the services agreement with GenOnDirect Energy acquisition and the Goal Zero business
Settlement AgreementA settlement agreement and any other documents necessary to effectuate the settlement among NRG, GenOn, and certain holders of senior unsecured notes of GenOn Americas Generation and GenOn, and certain of GenOn's direct and indirect subsidiaries
SewardSNFThe Seward Power Generating Station, a 525 MW coal-fired facility in Pennsylvania
ShelbyThe Shelby County Generating Station, a 352 MW natural gas-fired facility in IllinoisSpent Nuclear Fuel
SO2
Sulfur Dioxide
SPPSOFRSolar Power PartnersSecured overnight financing rate
STPSouth Central PortfolioNRG's South Central Portfolio, which owned and operated a portfolio of generation assets consisting of Bayou Cove, Big Cajun-I, Big Cajun-II, Cottonwood and Sterlington, was sold on February 4, 2019. NRG is leasing back the Cottonwood facility through May 2025
STPSouth Texas Project — nuclear generating facility located near Bay City, Texas in which NRG owns a 44% interest
S&PSTPNOCStandard & Poor's
TCPATelephone Consumer Protection Act
Term Loan FacilityPrior to June 30, 2016, the Company's $2.0 billion term loan facility due 2018, a component of the Senior Credit Facility.
TSATransportation Services Agreement
TWCCSouth Texas Westmoreland Coal Co.
U.S.United States of America
U.S. DOEU.S. Department of Energy
Utility Scale SolarSolar power projects, typically 20 MW or greater in size (on an alternating current basis), that are interconnected into the transmission or distribution grid to sell power at a wholesale level
VaRValue at Risk
VIEVariable Interest Entity


Project Nuclear Operating Company
Walnut CreekTDSPNRG Walnut Creek, LLC, the operating subsidiary of WCEP Holdings, LLC, which owns the Walnut Creek projectTransmission/distribution service provider
WSTWashington-St. Tammany Electric Cooperative,
U.S.United States of America
U.S. DOEU.S. Department of Energy
VaRValue at Risk
VIEVariable Interest Entity
VivintVivint Smart Home, Inc.
Winter Storm ElliottA major winter storm that had impacts across the majority of the United States and parts of Canada occurring in December 2022
Winter Storm UriA major winter and ice storm that had widespread impacts across North America occurring in February 2021




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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)2017 2016 2017 2016
Operating Revenues
 
    
Total operating revenues$3,049

$3,421

$8,132

$8,328
Operating Costs and Expenses






Cost of operations2,156

2,440

5,852

5,711
Depreciation and amortization272

298

789

826
Impairment losses14

9

77

65
Selling, general and administrative213

277

697

801
Reorganization18

—

18

—
Development activity expenses14

21

49

65
Total operating costs and expenses2,687

3,045

7,482

7,468
   Other income - affiliate14

48

104

144
   Gain/(loss) on sale of assets—

4

4

(79)
Operating Income376

428

758

925
Other Income/(Expense)






Equity in earnings of unconsolidated affiliates27

16

29

13
Impairment loss on investment—

(8)
—

(147)
Other income, net15

7

33

29
Loss on debt extinguishment, net(1)
(50)
(3)
(119)
Interest expense(221)
(237)
(692)
(718)
Total other expense(180)
(272)
(633)
(942)
Income/(Loss) from Continuing Operations Before Income Taxes196

156

125

(17)
Income tax expense6

28

5

75
Income/(Loss) from Continuing Operations190

128

120

(92)
(Loss)/Income from discontinued operations, net of income tax(27)
265

(802)
256
Net Income/(Loss)163

393

(682)
164
Less: Net loss attributable to noncontrolling interest and redeemable noncontrolling interests(8)
(9)
(63)
(49)
Net Income/(Loss) Attributable to NRG Energy, Inc.171

402

(619)
213
Dividends for preferred shares—

—

—

5
Gain on redemption of preferred shares—

—

—

(78)
Net Income/(Loss) Available for Common Stockholders$171

$402

$(619)
$286
Income/(Loss) per Share Attributable to NRG Energy, Inc. Common Stockholders






Weighted average number of common shares outstanding — basic317

316

317

315
Income from continuing operations per weighted average common share — basic$0.63

$0.43

$0.58

$0.10
(Loss)/Income from discontinued operations per weighted average common share — basic$(0.09)
$0.84

$(2.53)
$0.81
Income/(Loss) per Weighted Average Common Share — Basic$0.54

$1.27

$(1.95)
$0.91
Weighted average number of common shares outstanding — diluted322

317

317

316
Income from continuing operations per weighted average common share — diluted$0.61

$0.43

$0.58

$0.10
(Loss)/Income from discontinued operations per weighted average common share — diluted$(0.08)
$0.84

$(2.53)
$0.81
Income/(Loss) per Weighted Average Common Share — Diluted$0.53

$1.27

$(1.95)
$0.91
Dividends Per Common Share$0.03

$0.03

$0.09

$0.21
Three months ended March 31,
(In millions, except for per share amounts)20232022
Revenue
Revenue$7,722 $7,896 
Operating Costs and Expenses
Cost of operations (excluding depreciation and amortization shown below)8,778 4,930 
Depreciation and amortization190 183 
Selling, general and administrative costs426 347 
Acquisition-related transaction and integration costs71 8 
Total operating costs and expenses9,465 5,468 
Gain/(loss) on sale of assets199 (3)
Operating (Loss)/Income(1,544)2,425 
Other Income/(Expense)
Equity in earnings/(losses) of unconsolidated affiliates5 (15)
Other income, net16 — 
Interest expense(148)(103)
Total other expense(127)(118)
(Loss)/Income Before Income Taxes(1,671)2,307 
Income tax (benefit)/expense(336)571 
Net (Loss)/Income$(1,335)$1,736 
Less: Cumulative dividends attributable to Series A Preferred Stock4 — 
Net (Loss)/Income Available for Common Stockholders$(1,339)$1,736 
(Loss)/Income per Share
Weighted average number of common shares outstanding — basic and diluted230 242 
(Loss)/Income per Weighted Average Common Share —Basic and Diluted$(5.82)$7.17 
See accompanying notes to condensed consolidated financial statements.



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NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)/INCOME
(Unaudited)
 Three months ended September 30, Nine months ended September 30,
 2017 2016 2017 2016
 (In millions)
Net income/(loss)$163
 $393
 $(682)
$164
Other comprehensive income/(loss), net of tax
 
 


Unrealized gain/(loss) on derivatives, net of income tax (benefit)/expense of $0, $(1), $1, and $17

27

6

(8)
Foreign currency translation adjustments, net of income tax expense of $0, $0, $0, and $02

3

10

6
Available-for-sale securities, net of income tax expense of $0, $0, $0, and $01

—

2

1
Defined benefit plans, net of income tax expense of $0, $0, $0, and $0(1)
31

26

32
Other comprehensive income9

61

44

31
Comprehensive income/(loss)172

454

(638)
195
Less: Comprehensive loss attributable to noncontrolling interest and redeemable noncontrolling interests(5)
(2)
(61)
(70)
Comprehensive income/(loss) attributable to NRG Energy, Inc.177

456

(577)
265
Dividends for preferred shares—

—

—

5
Gain on redemption of preferred shares—
 —
 —

(78)
Comprehensive income/(loss) available for common stockholders$177

$456

$(577)
$338
Three months ended March 31,
(In millions)20232022
Net (Loss)/Income$(1,335)$1,736 
Other Comprehensive Income
Foreign currency translation adjustments1 9 
Defined benefit plans— (1)
Other comprehensive income1 8 
Comprehensive (Loss)/Income$(1,334)$1,744 
See accompanying notes to condensed consolidated financial statements.



9

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NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, 2023December 31, 2022
(In millions, except share data and liquidation preference on preferred stock)(Unaudited)(Audited)
ASSETS
Current Assets
Cash and cash equivalents$407 $430 
Funds deposited by counterparties330 1,708 
Restricted cash32 40 
Accounts receivable, net3,519 4,773 
Inventory722 751 
Derivative instruments4,400 7,886 
Cash collateral paid in support of energy risk management activities293 260 
Prepayments and other current assets505 383 
Total current assets10,208 16,231 
Property, plant and equipment, net1,835 1,692 
Other Assets
Equity investments in affiliates136 133 
Operating lease right-of-use assets, net247 225 
Goodwill5,343 1,650 
Intangible assets, net4,419 2,132 
Nuclear decommissioning trust fund879 838 
Derivative instruments3,350 4,108 
Deferred income taxes2,925 1,881 
Other non-current assets354 256 
Total other assets17,653 11,223 
Total Assets$29,696 $29,146 

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Draft 4                                                04/21/2023    

 September 30, 2017 December 31, 2016
(In millions, except shares)   
ASSETS   
Current Assets   
Cash and cash equivalents$1,223

$938
Funds deposited by counterparties31

2
Restricted cash537

446
Accounts receivable, net1,274

1,058
Inventory630

721
Derivative instruments475

1,067
Cash collateral posted in support of energy risk management activities203

150
Current assets - held for sale33

9
Prepayments and other current assets354

404
Current assets - discontinued operations—

1,919
Total current assets4,760

6,714
Property, plant and equipment, net15,332

15,369
Other Assets 
 
Equity investments in affiliates1,138

1,120
Notes receivable, less current portion5

16
Goodwill662

662
 Intangible assets, net1,838

1,973
Nuclear decommissioning trust fund670

610
Derivative instruments206

181
Deferred income taxes205

225
Non-current assets held-for-sale10

10
Other non-current assets644

841
Non-current assets - discontinued operations—

2,961
Total other assets5,378

8,599
Total Assets$25,470

$30,682
LIABILITIES AND STOCKHOLDERS’ EQUITY 
 
Current Liabilities 
 
Current portion of long-term debt and capital leases$1,247

$516
Accounts payable911

813
Derivative instruments522

1,092
Cash collateral received in support of energy risk management activities31

81
Accrued expenses and other current liabilities830

990
Accrued expenses and other current liabilities - affiliate164

—
Current liabilities - discontinued operations—

1,210
Total current liabilities3,705

4,702
Other Liabilities 
 
Long-term debt and capital leases15,658

15,957
Nuclear decommissioning reserve265

287
Nuclear decommissioning trust liability397

339
Deferred income taxes21

20
Derivative instruments307

284
Out-of-market contracts, net213

230
Non-current liabilities held-for-sale13

11
Other non-current liabilities1,116

1,176
Non-current liabilities - discontinued operations—

3,184
Total non-current liabilities17,990

21,488
Total Liabilities21,695

26,190
Redeemable noncontrolling interest in subsidiaries85

46
Commitments and Contingencies




Stockholders’ Equity


Common stock4

4
Additional paid-in capital8,369

8,358
Retained deficit(4,713)
(3,787)
Less treasury stock, at cost — 101,580,045 and 102,140,814 shares, respectively(2,386)
(2,399)
Accumulated other comprehensive loss(91)
(135)
Noncontrolling interest2,507

2,405
Total Stockholders’ Equity3,690

4,446
Total Liabilities and Stockholders’ Equity$25,470

$30,682
March 31, 2023December 31, 2022
(In millions, except share data and liquidation preference on preferred stock)(Unaudited)(Audited)
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Current portion of long-term debt and finance leases$971 $63 
Current portion of operating lease liabilities94 83 
Accounts payable2,330 3,643 
Derivative instruments4,350 6,195 
Cash collateral received in support of energy risk management activities330 1,708 
Deferred revenue current688176
Accrued expenses and other current liabilities1,563 1,114 
Total current liabilities10,326 12,982 
Other Liabilities
Long-term debt and finance leases11,332 7,976 
Non-current operating lease liabilities196 180 
Nuclear decommissioning reserve344 340 
Nuclear decommissioning trust liability514 477 
Derivative instruments1,893 2,246 
Deferred income taxes133 134 
Deferred revenue non-current84810
Other non-current liabilities1,030 973 
Total other liabilities16,290 12,336 
Total Liabilities26,616 25,318 
Commitments and Contingencies
Stockholders' Equity
Preferred stock; 10,000,000 shares authorized; 650,000 Series A shares issued and outstanding at March 31, 2023 (liquidation preference $1,000); 0 shares issued and outstanding at December 31, 2022650 —
Common stock; $0.01 par value; 500,000,000 shares authorized; 424,292,409 and 423,897,001 shares issued and 229,956,438 and 229,561,030 shares outstanding at March 31, 2023 and December 31, 2022, respectively4 4 
Additional paid-in-capital8,481 8,457 
(Accumulated deficit)/Retained earnings(15)1,408 
Treasury stock, at cost 194,335,971 shares at March 31, 2023 and December 31, 2022(5,864)(5,864)
Accumulated other comprehensive loss(176)(177)
Total Stockholders' Equity3,080 3,828 
Total Liabilities and Stockholders' Equity$29,696 $29,146 

See accompanying notes to condensed consolidated financial statements.



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NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 Nine months ended September 30,
(In millions)2017 2016
Cash Flows from Operating Activities   
Net (loss)/income$(682)
$164
(Loss)/Income from discontinued operations, net of income tax(802)
256
Income/(loss) from continuing operations120

(92)
Adjustments to reconcile net (loss)/income to net cash provided by operating activities:


Distributions and equity in earnings of unconsolidated affiliates24

44
Depreciation and amortization789

826
Provision for bad debts57

36
Amortization of nuclear fuel37

39
Amortization of financing costs and debt discount/premiums44

42
Adjustment for debt extinguishment3

119
Amortization of intangibles and out-of-market contracts79

131
Amortization of unearned equity compensation27

23
Impairment losses77

211
Changes in deferred income taxes and liability for uncertain tax benefits26

29
Changes in nuclear decommissioning trust liability20

24
Changes in derivative instruments25

30
Changes in collateral posted in support of risk management activities(103)
261
Proceeds from sale of emission allowances21

11
(Gain)/loss on sale of assets(22)
70
Changes in other working capital(380)
(130)
Cash provided by continuing operations844

1,674
Cash (used)/provided by discontinued operations(38)
67
Net Cash Provided by Operating Activities806

1,741
Cash Flows from Investing Activities 
 
Acquisitions of businesses, net of cash acquired(36)
(18)
Capital expenditures(760)
(659)
Decrease in notes receivable11

2
Purchases of emission allowances(47)
(32)
Proceeds from sale of emission allowances105

47
Investments in nuclear decommissioning trust fund securities(402)
(378)
Proceeds from the sale of nuclear decommissioning trust fund securities382

354
Proceeds from renewable energy grants and state rebates8

11
Proceeds from sale of assets, net of cash disposed of36

84
Investments in unconsolidated affiliates(31)
(23)
Other22

31
Cash used by continuing operations(712)
(581)
Cash (used)/provided by discontinued operations(53)
326
Net Cash Used by Investing Activities(765)
(255)
Cash Flows from Financing Activities 
 
Payment of dividends to common and preferred stockholders(28)
(66)
Payment for preferred shares—

(226)
Net receipts from settlement of acquired derivatives that include financing elements2

6
Proceeds from issuance of long-term debt1,134

5,237
Payments for short and long-term debt(712)
(5,353)
Receivable from affiliate(125)
—
Payments for debt extinguishment costs—

(98)
Contributions from, net of distributions to, noncontrolling interest in subsidiaries65

(127)
Proceeds from issuance of stock—

1
Payment of debt issuance costs(43)
(70)
Other - contingent consideration(10)
(10)
Cash provided/(used) by continuing operations283

(706)
Cash (used)/provided by discontinued operations(224)
119
Net Cash provided/(used) by Financing Activities59

(587)
Effect of exchange rate changes on cash and cash equivalents(10)
(6)
Change in Cash from discontinued operations(315)
512
Net Increase in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash405

381
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period1,386

1,322
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period$1,791

$1,703
Three months ended March 31,
(In millions)20232022
Cash Flows from Operating Activities
Net (Loss)/Income$(1,335)$1,736 
Adjustments to reconcile net (loss)/income to cash (used)/provided by operating activities:
Distributions from and equity in (earnings)/losses of unconsolidated affiliates(5)18 
Depreciation and amortization190 183 
Accretion of asset retirement obligations6 7 
Provision for credit losses35 25 
Amortization of nuclear fuel13 14 
Amortization of financing costs and debt discounts20 6 
Amortization of in-the-money contracts and emissions allowances119 147 
Amortization of unearned equity compensation30 6 
Net gain on sale of assets and disposal of assets(187)(6)
Changes in derivative instruments1,599 (2,816)
Changes in current and deferred income taxes and liability for uncertain tax benefits(338)575 
Changes in collateral deposits in support of risk management activities(1,412)2,007 
Changes in nuclear decommissioning trust liability(16)(7)
Changes in other working capital(317)(219)
Cash (used)/provided by operating activities(1,598)1,676 
Cash Flows from Investing Activities
Payments for acquisitions of businesses and assets, net of cash acquired(2,492)(26)
Capital expenditures(142)(60)
Net purchases of emission allowances(18)(18)
Investments in nuclear decommissioning trust fund securities(87)(151)
Proceeds from the sale of nuclear decommissioning trust fund securities99 161 
Proceeds from sales of assets, net of cash disposed219 14 
Proceeds from insurance recoveries for property, plant and equipment, net71 — 
Cash used by investing activities(2,350)(80)
Cash Flows from Financing Activities
Proceeds from issuance of preferred stock, net of fees636 — 
Payments of dividends to common stockholders(87)(85)
Payments for share repurchase activity(8)(188)
Net receipts from settlement of acquired derivatives that include financing elements336 561 
Net proceeds of Revolving Credit Facility and Receivables Securitization Facilities950 — 
Proceeds from issuance of long-term debt731 — 
Payments of debt issuance costs(18)— 
Repayments of long-term debt and finance leases(4)(1)
Cash provided by financing activities2,536 287 
Effect of exchange rate changes on cash and cash equivalents3 3 
Net (Decrease)/Increase in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash(1,409)1,886 
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period2,178 1,110 
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period$769 $2,996 
See accompanying notes to condensed consolidated financial statements.



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NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(Unaudited)
(In millions)Preferred StockCommon
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 Stock650 (14)636 
Other comprehensive income1 1 
Equity-based awards activity, net(a)
38 38 
Common stock dividends and dividend equivalents declared(b)
(88)(88)
Balance at March 31, 2023$650 $4 $8,481 $(15)$(5,864)$(176)$3,080 

(In millions)Common
Stock		Additional
Paid-In
Capital		Retained EarningsTreasury
Stock		Accumulated
Other
Comprehensive
Loss		Total
Stock-holders'
Equity
Balance at December 31, 2021$4 $8,531 $464 $(5,273)$(126)$3,600 
Net income1,736 1,736 
Other comprehensive income8 8 
Share repurchases(187)(187)
Equity-based awards activity, net(a)
2 2 
Common stock dividends and dividend equivalents declared(b)
(86)(86)
Adoption of ASU 2020-06(100)57 (43)
Balance at March 31, 2022$4 $8,433 $2,171 $(5,460)$(118)$5,030 
(a)Includes $(8) million and $(6) million of equivalent shares purchased in lieu of tax withholding on equity compensation issuances for the quarters ended March 31, 2023 and 2022, respectively.
(b)Dividends per common share were $0.3775 and $0.35 for the quarters ended March 31, 2023 and 2022.
See accompanying notes to condensed consolidated financial statements.

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NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 1 — Nature of Business and Basis of Presentation
General
NRG Energy, Inc., or NRG or the Company, is a leading integratedenergy, smart home and services company fueled by market-leading brands, proprietary technologies, and complementary sales channels. NRG brings the power company built onof energy to customers by producing and selling energy and related products and services. Across the strengthUnited States and Canada, NRG develops innovative, sustainable solutions, predominately under brand names such as NRG, Reliant, Direct Energy, Green Mountain Energy and Vivint. The Company has a customer base that includes approximately 7.5 million residential consumers in addition to commercial, industrial, and wholesale customers, supported by approximately 16 GW of a diverse competitive electric generation portfolio.
The Company's business is segmented as follows:
•Texas, which includes all activity related to customer, plant and leading retail electricity platform. NRG is continuously focused on excellencemarket operations in operating performance of its existingTexas, 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 optimal hedging of generation assetsactivities: (i) all activity related to customer, plant and retail loadmarket operations as well as serving the energy needs of end-use residential, commercial and industrial customers in competitive markets through multiple brands and channels. The Company owns and operates approximately 30,000 MW of generation; engages in the trading of wholesale energy, capacityWest and Canada, (ii) the Services businesses (iii) activity related products; transactsto the Cottonwood facility, (iv) the remaining renewables activity, including the Company’s equity method investment in Ivanpah Master Holdings, LLC, and trades fuel(v) activity related to the Company’s equity method investment for the Gladstone power plant in Australia;
•Vivint smart home; and transportation services; and directly sells energy, services, and innovative, sustainable products and services to retail customers under the names “NRG”, "Reliant" and other retail brand names owned by NRG.
•Corporate activities.
The accompanying unaudited interim condensed consolidated financial statements have been prepared in accordance with the SEC's regulations for interim financial information and with the instructions to Form 10-Q. Accordingly, they do not include all of the information and notes required by generally accepted accounting principles 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 20162022 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, 2017,March 31, 2023, and the results of operations, comprehensive income/(loss)income, cash flows and cash flowsstatements of stockholders' equity for the three and nine months ended September 30, 2017March 31, 2023 and 2016.2022.
GenOn Chapter 11 Cases
On June 14, 2017, or the Petition Date, GenOn, along with GenOn Americas Generation and certain of their directly and indirectly-owned subsidiaries, or collectively the GenOn Entities, filed voluntary petitions for relief under Chapter 11, or the Chapter 11 Cases, of the U.S. Bankruptcy Code, or the Bankruptcy Code, in the U.S. Bankruptcy Court for the Southern District of Texas, Houston Division, or the Bankruptcy Court. GenOn Mid-Atlantic, as well as its consolidated subsidiaries, REMA and certain other subsidiaries, did not file for relief under Chapter 11.

As a result of the bankruptcy filings and beginning on June 14, 2017, GenOn and its subsidiaries were deconsolidated from NRG’s consolidated financial statements. NRG recorded its investment in GenOn under the cost method with an estimated fair value of zero. NRG determined that this disposal of GenOn and its subsidiaries is a discontinued operation; and, accordingly, the financial information for all historical periods have been recast to reflect GenOn as a discontinued operation. In connection with the disposal, NRG recorded a loss on deconsolidation of $208 million during the quarter ended June 30, 2017. See Note 3, Discontinued Operations, Dispositions and Acquisitions, for more information.

Prior to the GenOn Entities' filing the Chapter 11 Cases, on June 12, 2017, NRG entered into a restructuring support and lock-up agreement, or the Restructuring Support Agreement, with the GenOn Entities and certain holders of the GenOn and GenOn Americas Generation Senior Notes, that provides for a restructuring and recapitalization of the GenOn Entities through a prearranged plan of reorganization. The RSA was amended on October 2, 2017 to remove the requirement to conduct a rights offering in connection with the exit financing. There is no assurance that the GenOn Entities' plan will be approved by the requisite stakeholders, confirmed by the Bankruptcy Court, or successfully implemented thereafter. The principal terms of the Restructuring Support Agreement are described further in Note 3, Discontinued Operations, Dispositions and Acquisitions.

As announced on October 31, 2017, NRG and GenOn engaged in arms-length discussions to settle certain items related to the pre-petition Restructuring Support Agreement, including key topics such as: (i) timeline and transition; (ii) cooperation and co-development matters; (iii) post-employment and retiree health and welfare benefits and pension benefits; (iv) tax matters; and (v) intercompany balances. The agreements reached on these topics are expected to be incorporated into definitive documents for GenOn’s emergence from Chapter 11.



Forms of definitive documents were filed with the Bankruptcy Court by the GenOn Entities; however, such definitive documents are subject to ongoing review, revision, and further negotiation by the parties to the Restructuring Support Agreement, including NRG, who have various consent rights over the final form of the plan supplement documents, and may be amended, modified, supplemented, and revised in accordance with those ongoing negotiations.

Transformation Plan
On July 12, 2017, NRG announced its Transformation Plan designed to significantly strengthen earnings and cost competitiveness, lower risk and volatility, and create significant shareholder value. The three-part, three-year plan is comprised of the following targets:
Operations and cost excellence — Cost savings and margin enhancement of $1,065 million recurring, which consists of $590 million of annual cost savings, a $215 million net margin enhancement program, $50 million annual reduction in maintenance capital expenditures, and $210 million in permanent selling, general and administrative expense reduction associated with asset sales.
Portfolio optimization — Targeting up to $4.0 billion of asset sale net cash proceeds, including divestitures of 6 GWs of conventional generation and businesses (excluding GenOn) and the expected monetization of 100% of its interest in NRG Yield, Inc. and its renewables platform.

Capital structure and allocation enhancements — A prioritized capital allocation strategy that targets a reduction in consolidated debt from approximately $19.5 billion ($18 billion net debt) to approximately $6.5 billion ($6 billion net debt). Following the completion of the contemplated asset sales, the Company expects $4.8-$6.3 billion in excess cash to be available for allocation through 2020, after achieving its targeted 3.0x net debt / Adjusted EBITDA corporate credit ratio.

The Company expects to fully implement the Transformation Plan by the end of 2020 with significant completion by the end of 2018. The Company expects to realize (i) $370 million of non-recurring working capital improvements through 2020 and (ii) approximately $290 million, one-time costs to achieve.

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

Note 2 — Summary of Significant Accounting Policies
Vivint Flex Pay
Under the Vivint Flex Pay plan (“Vivint Flex Pay”), customers pay separately for smart home products and smart home and security services. The customer has the ability to pay for Vivint products in the following three ways: (i) qualified customers may finance the purchase through third-party financing providers ("Consumer Financing Program" or “CFP”), (ii) Vivint generally offers a limited number of customers not eligible for the CFP, but who qualify under Vivint’s underwriting criteria, the option to enter into a retail installment contract directly with Vivint or (iii) customers may conduct purchases by check, automatic clearing house payments, credit or debit card or by obtaining short term financing (generally no more than six-month installment terms) through Vivint.

14
Draft 4                                                04/21/2023    

Although customers pay separately for products and services under Vivint Flex Pay, the Company has determined that the sale of products and services are one single performance obligation resulting in deferred revenue for the gross amount of products sold. For products financed through the CFP, gross deferred revenues are reduced by (i) any fees the third-party financing provider (“Financing Provider”) is contractually entitled to receive at the time of loan origination, and (ii) the present value of expected future payments due to the Financing Providers. Loans are issued on either an installment or revolving basis with repayment terms ranging from 6 to 60 months.
For certain Financing Provider loans:
•Vivint pays a monthly fee based on either the average daily outstanding balance of the installment loans, or the number of outstanding loans.
•Vivint incurs fees at the time of the loan origination and receives proceeds that are net of these fees.
•Vivint also shares liability for credit losses, with Vivint being responsible for between 2.6% and 100% of lost principal balances.
Due to the nature of these provisions, the Company records a derivative liability at its fair value when the Financing Provider originates loans to customers, which reduces the amount of estimated revenue recognized on the provision of the services. The derivative liability is reduced as payments are made by Vivint to the Financing Provider. Subsequent changes to the fair value of the derivative liability are realized through other income, net in the consolidated statements of operations. For further discussion, see Note 7, Accounting for Derivative Instruments and Hedging Activities.
Capitalized Contract Costs
Capitalized contract costs represent the costs directly related and incremental to the origination of new contracts, modification of existing contracts or to the fulfillment of the related subscriber contracts. These costs include installed products, commissions, other compensation and 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 period of benefit periodically and whenever events or circumstances indicate that the 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 cost of operations and selling, general and administrative costs on the consolidated statements of operations. Contract costs not directly related and incremental to the origination of new contracts, modification of existing contracts or to the fulfillment of the related subscriber contracts are expensed as incurred.
Other Balance Sheet Information
The following table presents the allowance for doubtful accounts included in accounts receivable, net; accumulated depreciation included in property, plant and equipment, net;net and accumulated amortization included in intangible assets, net and accumulated amortization included in out-of-market contracts, net:
(In millions)March 31, 2023December 31, 2022
Property, plant and equipment accumulated depreciation$1,518 $1,478 
Intangible assets accumulated amortization2,290 2,112 
Credit Losses
Retail trade receivables are reported on the balance sheet net of the allowance for credit losses. 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.

15
Draft 4                                                04/21/2023    

 September 30, 2017 December 31, 2016
 (In millions)
Accounts receivable allowance for doubtful accounts$61
 $29
Property, plant and equipment accumulated depreciation6,437
 5,711
Intangible assets accumulated amortization1,750
 1,687
Out-of-market contracts accumulated amortization352
 457
The following table represents the activity in the allowance for credit losses for the three months ended March 31, 2023 and 2022:

Three months ended March 31,
(In millions)20232022
Beginning balance$133 $683 
Acquired balance from Vivint16 — 
Provision for credit losses35 25 
Write-offs(78)(50)
Recoveries collected9 8 
Ending balance$115 $666 

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 sheetsheets that sum to the total of the same such amounts shown in the statementstatements of cash flows.flows:
September 30, 2017 December 31, 2016 September 30, 2016 December 31, 2015
(In millions)
(In millions)(In millions)March 31, 2023December 31, 2022
Cash and cash equivalents$1,223
 $938
 $1,217
 $853
Cash and cash equivalents$407 $430 
Funds deposited by counterparties31
 2
 6
 55
Funds deposited by counterparties330 1,708 
Restricted cash537
 446
 480
 414
Restricted cash32 40 
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows$1,791
 $1,386
 $1,703
 $1,322
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows$769 $2,178 
Funds deposited by counterparties consist of cash held by the Company as a result of collateral posting obligations from its counterparties. Somecounterparties related to NRG's hedging program. The decrease in funds deposited by counterparties is driven by the significant decrease in forward positions as a result of decreases in natural gas and power prices compared to December 31, 2022. Though some amounts are segregated into separate accounts, thatnot all funds are not contractually restricted but, basedrestricted. Based on the Company's intention, these funds are not available for the payment of general corporate obligations.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 hedge counterparties pursuant to the terms and conditions of the underlying trades. Since collateral requirements fluctuate daily and the Company cannot predict if any collateral will be held for more than twelve months, the funds deposited by counterparties are classified as a current asset on the Company's balance sheet, with an offsetting liability for this cash collateral received within current liabilities. As of December 31, 2016, $79 million of the cash collateral received was from GenOn, previously a consolidated subsidiary, and is included in cash collateral received in current liabilities as a result of deconsolidating GenOn, with the offset included in cash and cash equivalents.
Restricted cash consists primarily of funds held to satisfy the requirements of certain debtfinancing agreements and funds held within the Company's projects that are restricted in their use.uses.
Noncontrolling InterestGoodwill
The following table reflectsrepresents the changes in NRG's noncontrolling interest balance:goodwill during the three months ended March 31, 2023:
 (In millions)
Balance as of December 31, 2016$2,405
Contributions from noncontrolling interest116
Non-cash adjustments to noncontrolling interest98
Sale of assets to NRG Yield, Inc.24
Comprehensive loss attributable to noncontrolling interest(8)
Dividends paid to NRG Yield, Inc. public shareholders(80)
Distributions to noncontrolling interest(48)
Balance as of September 30, 2017$2,507

Redeemable Noncontrolling Interest
The following table reflects the changes in the Company's redeemable noncontrolling interest balance:
 (In millions)
Balance as of December 31, 2016$46
Contributions from redeemable noncontrolling interest73
Non-cash adjustments to noncontrolling interest21
Comprehensive loss attributable to redeemable noncontrolling interest(53)
Distributions to redeemable noncontrolling interest(2)
Balance as of September 30, 2017$85



(In millions)TexasEastWest/Services/OtherVivintTotal
Balance as of December 31, 2022$710 $723 $217 $— $1,650 
Goodwill resulting from the acquisition of Vivint— — — 3,692 3,692 
Foreign currency translation adjustments— — 1 — 1 
Balance as of March 31, 2023$710 $723 $218 $3,692 $5,343 
Recent Accounting Developments - Guidance Adopted in 20172023
ASU 2016-182021-08 — In November 2016,October 2021, the FASB issued ASU No. 2016-18, Statement of Cash Flows2021-08, Business Combinations (Topic 230)805): Accounting for Contract Assets and Contract Liabilities from Contracts with Customers, Restricted Cash, or ASU No. 2016-18. The amendments of ASU No. 2016-18 require2021-08, which requires that an entity to include amounts generally described as restricted cashrecognize and restricted cash equivalents, including funds deposited by counterparties with cashmeasure contract assets and cash equivalents when reconciling the beginning of period and end of period total amounts on the statement of cash flows. The amendments of ASU No. 2016-18 are effective for annual reporting periods beginning after December 15, 2017, and interim periods within those annual periods. Early adoption is permitted and the adoption of ASU No. 2016-18 will be applied retrospectively. The Company adopted the guidancecontract liabilities acquired in ASU No. 2016-18 during the second quarter of 2017. In connection with the adoption of the standard, the Company has applied the guidance retrospectively which resulted in a decrease in cash flows from operations of $49 million and an increase in cash flows from investing of $66 million on the statement of cash flows for the nine months ended September 30, 2016.
ASU 2016-16 — In October 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740), Intra-Entity Transfers of Assets Other Than Inventory, or ASU No. 2016-16.  Current GAAP prohibits the recognition of current and deferred income taxes for an intra-entity asset transfer until the asset has been sold to an outside party which has resulted in diversity in practice and increased complexity within financial reporting.  The amendments of ASU No. 2016-16 would require an entity to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs.  The Company adopted the guidance in ASU No. 2016-16 effective January 1, 2017. In connection with the adoption of the standard, the Company recorded a reduction to non-current assets of $267 million with a corresponding reduction to cumulative retained deficit. 
ASU 2016-15 — In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments, or ASU No. 2016-15. The amendments of ASU No. 2016-15 were issued to address eight specific cash flow issues for which stakeholders have indicated to the FASB that a diversity in practice existed in how entities were presenting and classifying these items in the statement of cash flows. The issues addressed by ASU No. 2016-15 include but are not limited to the classification of debt prepayment and debt extinguishment costs, payments made for contingent consideration for a business combination proceeds fromas if it had originated the settlement of insurance proceeds, distributions received from equity method investees and separately identifiable cash flows and the application of the predominance principle. The Company adopted the guidancecontracts in ASU No. 2016-15 effective January 1, 2017. In connectionaccordance with the adoption of the standard, the Company has applied the guidance retrospectively which resulted in an increase in cash flows from operations of $98 million and a decrease in cash flows from financing of $98 million on the statement of cash flows for the nine months ended September 30, 2016.
ASU 2016-09 — In March 2016, the FASB issued ASU No. 2016-09, Compensation - Stock Compensation (Topic 718), or ASU No. 2016-09. The amendments focused on simplification specifically with regard to share-based payment transactions, including income tax consequences, classification of awards as equity or liabilities and classification on the statement of cash flows. The Company adopted the guidance in ASU No. 2016-09 effective January 1, 2017 with no material adjustments recorded to the consolidated balance sheet.
Recent Accounting Developments - Guidance Not Yet Adopted
ASU 2017-12 — In August 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815), Targeted Improvements to Accounting for Hedging Activities, or ASU No. 2017-12. The amendments of ASU No. 2017-12 were issued to simplify the application of hedge accounting guidance and more closely align financial reporting for hedging relationships with economic results of an entity's risk management activities. The issues addressed by ASU No. 2017-12 include but are not limited to alignment of risk management activities and financial reporting, risk component hedging, accounting for the hedged item in fair value hedges of interest rate risk, recognition and presentation of the effects of hedging instruments, amounts excluded from the assessment of hedge effectiveness, and other simplifications of hedge accounting guidance. The amendments of ASU No. 2017-12 are effective for fiscal years beginning after December 15, 2018, and interim periods therein.  Early adoption is permitted in any interim period and the effect of the adoption should be reflected as of the beginning of the fiscal year of adoption. The Company does not expect the adoption of ASU No. 2017-12 will have a material impact on its consolidated results of operations, cash flows, and statement of financial position.


ASU 2017-07 — In March 2017, the FASB issued ASU No. 2017-07, Compensation - Retirement Benefits (Topic 715), Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, or ASU No. 2017-07.   Current GAAP does not indicate where the amount of net benefit cost should be presented in an entity’s income statement and does not require entities to disclose the amount of net benefit cost that is included in the income statement.  The amendments of ASU No. 2017-07 require an entity to report the service cost component of net benefit costs in the same line item as other compensation costs arising from services rendered by the related employees during the applicable service period.  The other components of net benefit cost are required to be presented separately from the service cost component and outside the subtotal of income from operations. Further, ASU No. 2017-07 prescribes that only the service cost component of net benefit costs is eligible for capitalization. The amendments of ASU No. 2017-07 are effective for fiscal years beginning after December 15, 2017, including interim periods therein.  Early adoption is permitted and must be applied on a retrospective basis, except for the amendments regarding the capitalization of the service cost component, which must be applied prospectively. The Company is currently assessing the impact that the adoption of ASU No. 2017-07 will have on its results of operations, cash flows, and statement of financial position.
ASU 2016-02 — In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), or Topic 842, with the objective to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and to improve financial reporting by expanding the related disclosures. The guidance in Topic 842 provides that a lessee that may have previously accounted for a lease as an operating lease under current GAAP should recognize the assets and liabilities that arise from a lease on the balance sheet. In addition, Topic 842 expands the required quantitative and qualitative disclosures with regards to lease arrangements. The Company expects to adopt the standard effective January 1, 2019 utilizing the required modified retrospective approach for the earliest period presented. The Company expects to elect certain of the practical expedients permitted, including the expedient that permits the Company to retain its existing lease assessment and classification. The Company is currently working through an adoption plan which includes the evaluation of lease contracts compared to the new standard. While the Company is currently evaluating the impact the new guidance will have on its financial position and results of operations, the Company expects to recognize lease liabilities and right of use assets. The extent of the increase to assets and liabilities associated with these amounts remains to be determined pending the Company’s review of its existing lease contracts and service contracts which may contain embedded leases. While this review is still in process, NRG believes the adoption of Topic 842 will have a material impact on its financial statements.
ASU 2014-09 — In May 2014, the FASB issued ASU No. 2014-09, ASC 606, Revenue from Contracts with Customers (Topic 606), orCustomers. As a result, an acquirer should recognize and measure the acquired contract assets and contract liabilities consistently with how they were recognized and measured in the acquiree’s financial statements. The amendments per ASU 2021-08 apply only to contract assets and contract liabilities from contracts with customers, as defined in Topic 606, which was further amended through various updates issued bysuch as refund liabilities and upfront payments to customers. Assets and liabilities under related Topics, such as deferred costs under Subtopic 340-40, Other Assets and Deferred Costs — Contracts

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with Customers, are not within the FASB thereafter. Thescope of amendments of Topic 606 completed the joint effort between the FASB and the IASB, to develop a common revenue standard for GAAP and IFRS, and to improve financial reporting. The guidance under Topic 606 provides that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for the goods or services provided and establishes a five step model to be applied by an entity in evaluating its contracts with customers.per ASU 2021-08. The Company expects to adopt the standardadopted ASU 2021-08 prospectively effective January 1, 20182023 and applyapplied the guidance retrospectivelyamended requirements to the acquisition of Vivint.

Note 3 — Revenue Recognition
Vivint Retail Revenue
Vivint offers its customers combinations of smart home products and services, which together create an integrated smart home system that allows the Company's customers to monitor, control and protect their home. As the products and services included in the customer's contract are integrated and highly interdependent, and because the products (including installation) and services must work together to deliver the monitoring, controlling and protection of their home, the Company has concluded that the products and services contracted for by the customer are generally not distinct within the context of the contract and, therefore, constitute a single, combined performance obligation. Revenues for this single, combined performance obligation are recognized on a straight-line basis over the customer's contract term, which is the period in which the parties to the contract have enforceable rights and obligations. The Company has determined that certain contracts that do not require a long-term commitment for monitoring services by the customer contain a material right to renew the contract, because the customer does not have to purchase the products upon renewal. Proceeds allocated to the material right are recognized over the period of the benefit. The majority of Vivint's subscription contracts are five years and are generally non-cancelable. These contracts generally convert into month-to-month agreements at the dateend of adoption. The Company will recognize the cumulative effectinitial term, while some customers are month-to-month from inception. Payment for Vivint services is generally due in advance on a monthly basis. Product sales and other one-time fees are invoiced to customers at time of applying Topic 606 at the date of initial application, as prescribed under the modified retrospective transition method. The Company also expects to elect the practical expedient available under Topic 606sale. Revenues for measuring progress toward complete satisfaction of a performance obligation and for disclosure requirements of remaining performance obligations. The practical expedient allows an entity to recognize revenue in the amount to which the entity has the right to invoice suchany products or services that the entity has a right to the consideration in an amount that corresponds directly with the value to the customer for performance completed to date by the entity. The Company continues to assess the new standard with a focus on identifying theare considered separate performance obligations included within its revenue arrangements with customersare recognized upon delivery. Payments received or billed in advance are reported as deferred revenues.
Performance Obligations
As of March 31, 2023, estimated future fixed fee performance obligations are $1.0 billion for the remaining nine months of fiscal year 2023, and evaluating$1.1 billion, $828 million, $510 million, $227 million and $4 million for the Company’s methods of estimating the amountfiscal years 2024, 2025, 2026, 2027 and timing of variable consideration. While the impact remains subject to continued review, the Company does not believe the adoption of Topic 606 will have a material impact on its financial statements.


Note 3 — Discontinued Operations, Dispositions2028, respectively. These performance obligations include Vivint products and Acquisitions
Discontinued Operations
As described in Note 1, Basis of Presentation, on the Petition Date, the GenOn Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. As a result of the bankruptcy filings, NRG concluded that it no longer controls GenOnservices as it is subject to the control of the Bankruptcy Court; and, accordingly, NRG no longer consolidates GenOn for financial reporting purposes.
By eliminating a large portion of its operationswell as cleared auction MWs in the PJM, marketISO-NE, NYISO and MISO capacity auctions and are subject to penalties for non-performance.

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Disaggregated Revenues
The following tables represent the Company’s disaggregation of revenue from contracts with customers for the deconsolidation of GenOn, NRG concluded that GenOn meets the criteria for discontinued operations, as this represents a strategic shift in the markets in which NRG operates. As such, all prior period results for GenOn have been reclassified as discontinued operations while NRG will record all ongoing results of GenOn as a cost method investment, which was valued at zero at the date of deconsolidation.three months ended March 31, 2023 and 2022:
Summarized results of discontinued operations were as follows:
Three months ended March 31, 2023
(In millions)TexasEastWest/Services/Other
Vivint(a)
Corporate/EliminationsTotal
Retail revenue:
Home(b)
$1,236 $651 $625 $148 $— $2,660 
Business722 3,365 616 — — 4,703 
Total retail revenue(c)
1,958 4,016 1,241 148 — 7,363 
Energy revenue(c)
4 74 48 — 2 128 
Capacity revenue(c)
— 41 1 — — 42 
Mark-to-market for economic hedging activities(d)
— 35 67 — (11)91 
Contract amortization— (11)— — — (11)
Other revenue(c)
72 21 17 — (1)109 
Total revenue2,034 4,176 1,374 148 (10)7,722 
Less: Revenues accounted for under topics other than ASC 606 and ASC 815— (1)9 — — 8 
Less: Realized and unrealized ASC 815 revenue(2)113 97 — (9)199 
Total revenue from contracts with customers$2,036 $4,064 $1,268 $148 $(1)$7,515 
(a) Vivint includes results of operations following the acquisition date of March 10, 2023
(b) Home includes Services and Vivint
(c) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 and included in the amounts above:
(In millions)TexasEastWest/Services/OtherVivintCorporate/EliminationsTotal
Retail revenue$— $27 $— $— $— $27 
Energy revenue— 47 17 — 2 66 
Capacity revenue— 6 — — — 6 
Other revenue(2)(2)13 — — 9 
(d) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815

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Three months ended September 30, 2017 (a)
 Three months ended September 30, 2016 
Nine months ended September 30, 2017 (a)
 Nine months ended September 30, 2016
(In millions)   
Operating revenues$—
 $532
 $646
 $1,509
Operating costs and expenses—
 (468) (700) (1,409)
Gain on sale of assets—
 262
 —
 294
Other expenses—
 (43) (98) (127)
(Loss)/Income from operations of discontinued components, before tax—
 283
 (152) 267
Income tax expense—
 21
 9
 20
(Loss)/Incomes from operations of discontinued components—
 262
 (161) 247
Interest income - affiliate—
 3
 6
 9
(Loss)/Income from operations of discontinued components, net of tax—
 265
 (155) 256
Pre-tax loss on deconsolidation—
 —
 (208) —
Settlement consideration and services credit—
 —
 (289) —
Pension and post-retirement liability assumption(b)
(25) —
 (144) —
Other(2) —
 (6) —
Loss on disposal of discontinued components, net of tax(27) —
 (647) —
(Loss)/Income from discontinued operations, net of tax$(27) $265
 $(802) $256
Three months ended March 31, 2022
(In millions)TexasEastWest/Services/OtherCorporate/EliminationsTotal
Retail revenue:
Home(a)
$1,283 $579 $703 $— $2,565 
Business663 3,942 400 — 5,005 
Total retail revenue1,946 4,521 1,103 — 7,570 
Energy revenue(b)
15 204 54 5 278 
Capacity revenue(b)
— 115 1 — 116 
Mark-to-market for economic hedging activities(c)
(2)(130)(18)17 (133)
Contract amortization— (9)— — (9)
Other revenue(b)
61 14 4 (5)74 
Total revenue2,020 4,715 1,144 17 7,896 
Less: Revenues accounted for under topics other than ASC 606 and ASC 815— (9)11 — 2 
Less: Realized and unrealized ASC 815 revenue(7)(66)(42)20 (95)
Total revenue from contracts with customers$2,027 $4,790 $1,175 $(3)$7,989 
(a) Home includes Services
(b) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 and included in the amounts above:
(In millions)TexasEastWest/Services/OtherCorporate/EliminationsTotal
Energy revenue$— $45 $(20)$4 $29 
Capacity revenue— 13 — — 13 
Other revenue(5)6 (4)(1)(4)
(c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815
(a) As of June 14, 2017, NRG no longer consolidates GenOn for financial reporting purposes.
(b) See Note 1, Basis of Presentation, for further discussion regarding the October 30, 2017 proposed changes to the Restructuring Support Agreement. As part of this, NRG recorded the liability for GenOn’s post-employment and retiree health and welfare benefits, in an amount up to $25 million with a corresponding loss on discontinued operations during the third quarter of 2017.


Contract Balances
The following table summarizesreflects the major classes ofcontract assets and liabilities classifiedincluded in the Company’s balance sheet as discontinued operationsof March 31, 2023 and December 31, 2022:
(In millions)March 31, 2023December 31, 2022
Deferred customer acquisition costs$188 $126 
Accounts receivable, net - Contracts with customers3,416 4,704 
Accounts receivable, net - Accounted for under topics other than ASC 60687 64 
Accounts receivable, net - Affiliate16 5 
Total accounts receivable, net$3,519 $4,773 
Unbilled revenues (included within Accounts receivable, net - Contracts with customers)$1,290 $1,952 
Deferred revenues(a)
1,536 186 
(a) Deferred revenues from contracts with customers for the three months ended March 31, 2023 and the year ended December 31, 2022 were approximately $1.5 billion and $175 million, respectively. The increase in deferred revenues is primarily due to acquisition of Vivint
The revenue recognized from contracts with customers during the three months ended March 31, 2023 and 2022 relating to the deferred revenue balance at the beginning of each period was $168 million and $117 million, respectively. The change in deferred revenue balances recognized during the three months ended March 31, 2023 and 2022 was primarily due to the timing difference of when consideration was received and when the performance obligation was transferred.

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Note 4 — Acquisitions and Dispositions
Acquisitions
Vivint Smart Home Acquisition
On March 10, 2023 (the "Acquisition Closing Date"), 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 and Jetson Merger Sub, Inc., a wholly-owned subsidiary of the Company (“Merger Sub”) pursuant to which Merger Sub merged with and into Vivint, with Vivint surviving the merger as a wholly-owned subsidiary of the Company. Dedicated to redefining the home experience with intelligent products and services, Vivint brings nearly two million customers to NRG. Vivint'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, support and professional monitoring, enabling superior customer experiences and a complete end-to-end smart home experience. The acquisition accelerates the realization of NRG's consumer-focused growth strategy and creates a leading essential home services platform fueled by market-leading brands, unparalleled insights, proprietary technologies and complementary sales channels.
NRG paid $12 per share, or $2.609 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 $636 million from newly issued $650 million 10.25% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock, net of issuance costs;
•proceeds of approximately $900 million drawn from its Revolving Credit Facility and Receivables Securitization Facilities; and
•cash on hand.
In February 2023, the Company increased its Revolving Credit Facility by $600 million to meet the additional liquidity requirements related to the acquisition. For further discussion see Note 8, Long-term Debt and Finance Leases.
Acquisition costs of $36 million for the three months ended March 31, 2016. As2023 are included in acquisition-related transaction and integration costs in the Company's consolidated statement of June 14, 2017, NRG no longer consolidates GenOnoperations.
The acquisition has been recorded as a business combination under ASC 805, with identifiable assets and liabilities acquired provisionally recorded at their estimated fair values on the Acquisition Closing Date. The initial accounting for financial reporting purposes.
(In millions) December 31, 2016
Cash and cash equivalents $1,034
Other current assets 885
Current assets - discontinued operations 1,919
Property, plant and equipment, net 2,543
Other non-current assets 418
Non-current assets - discontinued operations 2,961
Current portion of long term debt and capital leases 704
Other current liabilities 506
Current liabilities - discontinued operations 1,210
Long-term debt and capital leases 2,050
Out-of-market contracts 811
Other non-current liabilities 323
Non-current liabilities - discontinued operations $3,184
Restructuring Support Agreement
As described in Note 1, Basisthe business combination is not complete because the evaluation necessary to assess the fair value of Presentation, NRG, GenOncertain net assets acquired and certain holders representing greater than 93% in aggregate principalthe amount of GenOn’s Senior Notesgoodwill to be recognized is still in process. The provisional amounts are subject to revision until the evaluations are completed to the extent that additional information is obtained about the facts and certain holders representing greater than 93% in aggregate principal amount of GenOn Americas Generation’s Senior Notes entered into a Restructuring Support Agreementcircumstances that provides for a restructuring and recapitalizationexisted as of the GenOn Entities through a prearranged planAcquisition Closing Date.
The total consideration of reorganization. Completion of the agreed upon terms$2.623 billion includes:
(In millions)
Vivint common shares outstanding as of March 10, 2023 of 216,901,639 at $12.00 per share$2,603 
Other Vivint equity instruments (Cash out RSUs and PSUs, Stock Appreciation Rights, Private Placement Warrants)6 
Total Cash Consideration$2,609 
Fair value of acquired Vivint equity awards attributable to pre-combination service14 
Total Consideration$2,623 

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The purchase price is contingent upon certain milestones in the Restructuring Support Agreement. Certain principal terms of the Restructuring Support Agreement are detailed below:provisionally allocated as follows:
(In millions)
Current Assets
Cash and cash equivalents$120 
Accounts receivable, net60 
Inventory113 
Prepayments and other current assets37 
Total current assets330 
Property, plant and equipment, net49 
Other Assets
Operating lease right-of-use assets, net35 
Goodwill(a)
3,692 
1)Full releases from GenOn and GenOn Americas Generation in favor of NRG, including either a full release or indemnification in favor of NRG for any claims relating to GenOn Mid-Atlantic or REMA and the dismissal of all litigation against NRG.
2)
NRG will provide settlement cash consideration to GenOn of $261.3 million, which will be paid in cash less any amounts owed to NRG under the intercompany secured revolving credit facility. As of September 30, 2017, GenOn owed NRG approximately $125 million under the intercompany secured revolving credit facility. See Note 14, Related Party Transactions, for further discussion of the intercompany secured revolving credit facility.
3)Intangibles assets, netNRG will consent to the cancellation of its interests in the equity of GenOn. The equity interests in the reorganized GenOn will be issued to the holders of the GenOn Senior Notes.2,500 
 Deferred income taxes451 
Other non-current assets14 
Total other assets6,692 
Total Assets$7,071 
4)Current LiabilitiesNRG will retain the pension liability, including payment
Current portion of approximately $13 millionlong-term debt and finance leases$14 
Current portion of 2017 pension contributions, for GenOn employees for service provided prior to the completion of the reorganization, which was paid in September 2017. GenOn’s pension liability as of September 30, 2017 was approximately $106 million.operating lease liabilities13 
Accounts payable109 
Derivatives instruments80 
Deferred revenue current517 
Accrued expenses and other current liabilities207 
Total current liabilities940 
Other Liabilities
Long-term debt and finance leases2,572 
Non-current operating lease liabilities28 
Derivatives instruments32 
Deferred income taxes18 
Deferred revenue non-current835 
Other non-current liabilities23 
Total other liabilities3,508 
Total Liabilities$4,448 
5)Vivint Purchase Price
The shared services agreement between NRG and GenOn will be amended such that (i) NRG will provide shared services to GenOn at an annualized rate of $84 million during the pendency of the Chapter 11 Cases, (ii) if the settlement is approved by the bankruptcy court, NRG will provide shared services to GenOn at no charge for two months, and (iii) NRG will then provide an option for up to two, one-month extensions for shared services at an annualized rate of $84 million. See Note 14, Related Party Transactions, for further discussion of the shared services agreement.
$
2,623 
6)NRG will provide a credit of $28 million to GenOn to apply against amounts owed under the shared services agreement upon emergence from bankruptcy. Any unused amount can be paid in cash at GenOn’s request. The credit was intended to reimburse GenOn for its payment of financing costs.
7)
NRG agreed to provide GenOn with a letter of credit facility during the pendency of the Chapter 11 Cases, which could be utilized for required letters of credit in lieu of the intercompany secured revolving credit facility. GenOn can no longer utilize the intercompany secured revolving credit facility and, on July 27, 2017, the letter of credit facility was terminated, as GenOn had obtained a separate letter of credit facility with a third party financial institution. See Note 14, Related Party Transactions, for further discussion of the intercompany secured revolver credit facility and the letter of credit facility obtained in July 2017.
8)NRG and GenOn have agreed to cooperate in good faith to maximize the value of certain development projects.


In addition(a) Goodwill arising from the acquisition is attributed to the Restructuring Support Agreement, additional support and other agreements are being negotiated, including a transition services agreement. See Note 1, Basis of Presentation, for further discussion regarding the October 30, 2017 proposed changes to the Restructuring Support Agreement.
Settlement Consideration
NRG has determined that the paymentvalue of the settlement considerationplatform acquired, cross-selling opportunities, customer growth and the synergies expected from combining the operations of Vivint with NRG's existing businesses. None of the goodwill recorded is probableexpected to be deductible for tax purposes.
Fair Value Measurement of Intangible Assets
The fair values of intangible assets as of the Acquisition Closing Date were measured primarily based on significant inputs that are observable and has recordedunobservable in the market and thus represent Level 2 and Level 3 measurements, respectively. Significant inputs were as follows:
Customer relationships — Customer relationships, reflective of Vivint’s customer base, were valued using an excess earning method of the income approach, and is classified as level 3. Under this approach, the Company estimated the present

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value of expected future cash flows resulting from existing customer relationships, considering attrition and charges for contributory assets (such as net working capital, fixed assets, workforce, trade name and technology) utilized in the business, discounted using a liability forweighted average cost of capital of comparable companies. The customer relationships are amortized to depreciation and amortization, ratably based on discounted future cash flows.
Technology – Developed technology was valued using a "relief from royalty" method of the income approach, and is classified as Level 3. Under this approach, the fair value was estimated to be the present value of royalties saved which assumed the value of the asset based on discounted cash flows of the amount duethat would be paid by a hypothetical market participant had they not owned the asset and instead licensed the asset from another company. The estimated cash flows from the developed technology considered the obsolescence factor and was discounted using a weighted average cost of $261.3 millioncapital of comparable companies. The developed technology is amortized to depreciation and amortization, ratably based on discounted future cash flows.
Trade name — Trade name was valued using a "relief from royalty" method of the income approach, and is classified as level 3. Under this approach, the fair value is estimated to be the present value of royalties saved which assumed the value of the asset based on discounted cash flows of the amount that would be paid by a hypothetical market participant had they not owned the asset and instead licensed the asset from another company. The estimated cash flows from the trade name considered the expected probable use of the asset and was discounted using a weighted average cost of capital of comparable companies. The trade name is amortized to depreciation and amortization, on a straight line basis, over the expected life of the asset.
Fair Value Measurement of Acquired Vivint’s Debt
The Company acquired $2.7 billion in accrued expensesaggregate principal of Vivint’s 2027 Senior Secured Notes, 2029 Senior notes and other current liabilities - affiliate with a corresponding loss from discontinued operations. NRG expects to pay this amount net of amounts due from GenOn under2028 Senior Secured Term Loan (together, the intercompany secured revolving credit facility,Acquired Vivint’s Debt) which is further described in Note 14, Related Party Transactions.
Pension Liability
NRG will retain the pension liability, including payment of approximately $13 million of 2017 pension contributions, which was paid in September 2017, for the GenOn employees for service provided prior to emergence from bankruptcy. NRG determined that the retention of this liability is probable and haswere recorded the estimated accumulated pension benefit obligationat fair value as of September 30, 2017 of $106 million in other non-current liabilities with a corresponding loss from discontinued operations. NRG's obligation for this liability will be revalued throughthe Acquisition Closing Date. The difference between the fair value at the Acquisition Closing Date and at GenOn's emergence from bankruptcy.
Services Agreement
NRG will continue to provide shared services to GenOn under the Services Agreement at an annualized rate of $84 million during the pendencyprincipal outstanding of the Chapter 11 CasesAcquired Vivint’s Debt, of $152 million, is being amortized through interest expense over the remaining term of the debt. The Acquired Vivint’s Debt are classified as level 2 and were measured at fair value using observable market inputs based on interest rates at the Acquisition Closing Date. For additional discussion seeNote 8, Long-term Debt and Finance Leases.
Fair Value Measurement of Derivatives Liabilities
The derivative liabilities are recorded in connection with the contractual future payment obligations with the financing providers under Vivint’s Consumer Financing Program. The fair values of the derivatives liabilities as of the Acquisition Closing Date were valued using a discounted cash flow model, with inputs consisting of available market data, such as market yield discount rates, as well as unobservable internally derived assumptions, such as collateral prepayment rates, collateral default rates and loss severity rates. These derivatives are priced using a credit valuation adjustment methodology, and are classified as level 3. Changes to the fair value are recorded through other income, net in the Consolidated Statement of Operations. For additional discussion see Note 7, Accounting for two months post-emergence at no charge. NRG then will provide an option for up to two, one-month extensions for shared services at an annualized rate of $84 million. Beginning on June 14, 2017, NRG records operating incomeDerivative Instruments and Hedging Activities.
Supplemental Pro Forma Financial Information for the amounts earned for shared servicesthree months ended March 31, 2023 and 2022
The following table provides pro forma combined financial information of approximately $5 million per month. NRG has also agreed to provide GenOn with a credit of $28 million against amounts owed under the Services Agreement. Any unused amount can be paid in cash at GenOn’s request. As a result, NRG has concluded that the liability for this credit is probable and has recorded a payable to GenOn for $28 million in accrued expenses and other current liabilities - affiliate with a corresponding loss from discontinued operations. See Note 1, Basis of Presentation, for further discussion regarding the October 30, 2017 proposed changesVivint, after giving effect to the Restructuring Support AgreementVivint acquisition and Services Agreement.related financing transactions as if they had occurred on January 1, 2022. The pro forma financial information has been prepared for illustrative and informational purposes only, and is not intended to project future operating results or be indicative of what the Company's financial performance would have been had the transactions occurred on the date acquired. No effect has been given to operating synergies.
Commercial Operations
(In millions)Three months ended March 31, 2023Three months ended March 31, 2022
Total operating revenues$8,008 $8,288 
Net (loss)/ income(1,329)1,558 
For pre-disposal periods, NRG provided GenOn with services as described in Note 14, Related Party Transactions. Under intercompany agreements, NRG Power Marketing LLC has entered into physicalAmounts above reflect certain pro forma adjustments that were directly attributable to the Vivint acquisition. These adjustments include the following:
(i)Income statement effects of fair value adjustments based on the preliminary purchase price allocation including amortization of intangible assets, reversal of historical Vivint amortization of capitalized contract costs and financial intercompany commodity and hedging transactions with GenOn and certainreversal of its subsidiaries. Subject to applicable collateral thresholds, these arrangements may providehistorical Vivint other income recorded for the bilateral exchangechange in fair value of credit support basedwarrant derivative liabilities, as the warrants are assumed to be cashed out upon market exposure and potential market movements. The terms and conditionsthe close of the agreements are generally consistent with industry practicesAcquisition.
(ii)Adjustments to record additional stock-based compensation expense related to acquired Vivint equity awards in the 2022 period. Additionally, one-time stock-based compensation expense related primarily to the acceleration of Vivint equity awards is removed from the three months ended March 31, 2023 and other third party arrangements. For currentreflected in the 2022 period.

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(iii)Adjustments to reflect all acquisition and pre-disposal periods, revenue andrelated transactions costs occurring during the three months ended March 31, 2022.
(iv)Interest expense associated with theseassumes the financing transactions is recordeddirectly attributable to the Vivint acquisition occurred on January 1, 2022.
(v)Adjustments related to recording Vivint's historical debt at Acquisition Closing Date fair value.
(vi)Adjustments to reflect the write-off of short-term deferred financing costs related to the bridge facility put in continuing operations.
GenOn Debt
As of June 14, 2017,place for the GenOn Senior Notes and GenOn Americas Generation Senior Notes, which totaled approximately $2.5 billion, were deconsolidated from NRG's consolidated financial statements. The filingacquisition prior to securing permanent financing during the 2022 period instead of the Chapter 11 Cases constitutes an event2023 period.
(vii)Tax effects of default underpro forma adjustments on both periods and the following debt instrumentsshifting of GenOn:
1)The intercompany secured revolving credit facility with NRG;
2)The indenture governing the GenOn 7.875% Senior Notes due 2017 (as amended or supplemented from time to time);
3)The indenture governing the GenOn 9.500% Notes due 2018 (as amended or supplemented from time to time);
4)The indenture governing the GenOn 9.875% Notes due 2020 (as amended or supplemented from time to time);
5)The indenture governing the GenOn Americas Generation 8.50% Senior Notes due 2021 (as amended or supplemented from time to time); and
6)The indenture governing the GenOn Americas Generation 9.125% Senior Notes due 2031 (as amended or supplemented from time to time).
Transferthe recognition of Assets Under Common Controlone-time tax benefits resulting from the acquisition from the three months ended March 31, 2023 to the 2022 period.
Dispositions
Sale of Astoria
On November 1, 2017, NRG completedJanuary 6, 2023, the sale of a 38 MW solar portfolio primarily comprised of assets from SPP funds, in addition to other projects developed by NRG, to NRG Yield, Inc. for cash consideration of $71 million, plus $3 million in working capital adjustments.
On August 1, 2017, NRGCompany closed on the sale of its remaining 25% interest in NRG Wind TE Holdco, a portfolioland and related generation assets from the Astoria site, within the East region of 12 wind projects,operations, for initial proceeds of $212 million, subject to NRG Yield, Inc. for total cash consideration of $44 million, including working capital adjustmenttransaction fees of $3 million. The transaction also includes potential additional payments to NRG dependent upon actual energy prices for merchant periods beginning in 2027.


On March 27, 2017, the Company sold to NRG Yield, Inc.: (i) a 16% interest in the Agua Caliente solar project, representing ownership of approximately 46 net MW of capacitymillion and (ii) NRG's interests in seven utility-scale solar projects located in Utah representing 265 net MW of capacity, which have reached commercial operations. NRG Yield, Inc. paid cash consideration of $130 million, plus $1 million in working capital adjustments, and assumed non-recourse debt of approximately $328 million.
On September 1, 2016, the Company completed the sale of its remaining 51.05% interest in the CVSR project to NRG Yield, Inc. for total cash consideration of $78.5 million, plus an immaterial working capital adjustment. In addition, NRG Yield, Inc. assumed non-recourse project level debt of $496 million.
Acquisitions
SunEdison Utility-Scale Solar and Wind Acquisition
On November 2, 2016, the Company acquired equity interestscertain indemnifications, resulting in a tax equity portfolio from SunEdison, located in Utah, comprised of 530 MW of mechanically-complete solar assets, of which NRG’s net interest based on cash to be distributed is 265 MW, for upfront cash consideration of $111 million. In connection with the acquisition, the Company assumed non-recourse debt of $222 million. The Company also borrowed additional amounts of $65$199 million during the fourth quarter of 2016, which effectively reduced the Company's use of liquidity related to the acquisition. The Company does not have a controlling interest in the tax equity portfolio and, accordingly, its interest is recorded as an equity method investment. The purchase price was preliminarily allocated to the equity method investment balance of approximately $328 million, current assets of $5 million and the assumed non-recourse debt of $222 million. The assets reached commercial operations during the fourth quarter of 2016 and have 20-year PPAs with PacificCorp.
The Company acquired a 110 MW portfolio of construction-ready and 71 MW of development solar assets in Hawaii from SunEdison for upfront cash consideration of $2 million on October 3, 2016 and a 154 MW construction-ready solar project in Texas for upfront cash consideration of $11 million on November 9, 2016.
In addition to the total $124 million in upfront cash consideration paid for the above acquisitions, the Company expects to make an estimated $59 million in additional payments contingent upon future development milestones, of which $15 million was paid as of September 30, 2017.
SunEdison Solar Distributed Generation Acquisition
On October 3, 2016, the Company acquired a 29 MW portfolio of mechanically-complete and construction-ready distributed generation solar assets from SunEdison for cash consideration of approximately $67 million excluding post-closing adjustments which reduced the purchase price by $5 million. Subsequent to the acquisition, the Company sold the majority of these assets into a tax-equity financed portfolio within the DGPV Holdco partnership between NRG and NRG Yield, Inc., and expects to sell the remaining assets into a similar portfolio in 2017. The purchase price was allocated to $47 million in construction in progress and $15 million in intangible assets.
Dispositions
Disposition of Majority Interest in EVgo
On June 17, 2016, the Company completed the sale of a majority interest in its EVgo business to Vision Ridge Partners for total consideration of approximately $39 million, including $17 million in cash received, which is net of $2.5 million in working capital adjustments, $15 million contributed as capital to the EVgo business and $7 million of future contributions by Vision Ridge Partners, all of which were determined based on forecasted cash requirements to operate the business in future periods. In addition, the Company has future earnout potential of up to $70 million based on future profitability targets. NRG will retain its original financial obligation of $102.5 million under its agreement with the CPUC whereby EVgo will build at least 200 public fast charging Freedom Station sites and perform the associated work to prepare 10,000 commercial and multi-family parking spaces for electric vehicle charging in California.gain. As part of the sale,transaction, NRG has contracted with EVgo to continue to build the remaining required Freedom Stations and commercial and multi-family parking spaces for electric vehicle charging required under this obligation and will be directly reimbursed by NRG for the costs. As a result of the sale, the Company recorded a loss on sale of $83 million during the second quarter of 2016, which reflects the loss on the sale of the equity interest of $27 million and the accrual of NRG's remaining obligation under its agreement with the CPUC of $56 million. On February 22, 2017, the Company and CPUC entered into a second amendment to the agreement which extended the operating period commitment for the Freedom Stations to December 5, 2020. At September 30, 2017, the Company's remaining 35% interest in EVgo of $2 million was accounted for as an equity-method investment.


Rockford Disposition
On May 12, 2016, the Company entered into an agreement with RA Generation, LLC to sell 100%lease the land back for the purpose of its interests inoperating the Rockford I and Rockford II generating stations, or Rockford, for cash consideration of $55 million, subjectAstoria gas turbines. The lease agreement is expected to adjustments for working capital andterminate by the resultsend of the PJM 2019/2020 base residual auction. Rockford is a 450 MW natural gas facility located in Rockford, Illinois. The transaction triggered an indicator of impairment as the sales price was less than the carrying amount of the assets, and, as a result the assets were considered to be impaired. The Company measured the impairment loss as the difference between the carrying amount of the assets and the agreed-upon sales price. The Company recorded an impairment loss of $17 million during the quarter ended June 30, 2016 to reduce the carrying amount of the assets held for sale to the fair market value. At June 30, 2016, the Company had $2 million of current assets and $54 million of non-current assets classified as held for sale for Rockford on its balance sheet. On July 12, 2016, the Company completed the sale of Rockford for cash proceeds of $56 million, including $1 million in adjustments for the PJM base residual auction results. For further discussion on this impairment, refer to year.

Note 7, Impairments, to this Form 10-Q.
Note 45 — Fair Value of Financial Instruments
This footnote should be read in conjunction with the complete description under Note 4, Fair Value of Financial Instruments, to the Company's 2016 Form 10-K.
For cash and cash equivalents, funds deposited by counterparties, restricted cash, accounts and other receivables, accounts payable, restricted cash, and cash collateral paid and received in support of energy risk management activities, the carrying amount approximatesamounts approximate fair valuevalues because of the short-term maturity of those instruments and are classified as Level 1 within the fair value hierarchy.
The estimated carrying amountsvalue and fair valuesvalue of NRG's recorded financial instruments not carried at fair market value arethe Company's long-term debt, including current portion, is as follows:
March 31, 2023December 31, 2022
(In millions)Carrying AmountFair ValueCarrying AmountFair Value
Convertible Senior Notes$575 $595 $575 $576 
Other long-term debt, including current portion11,784 11,012 7,523 6,432 
Total long-term debt, including current portion(a)
$12,359 $11,607 $8,098 $7,008 
 As of September 30, 2017 As of December 31, 2016
 Carrying Amount Fair Value Carrying Amount Fair Value
 (In millions)
Assets:       
Notes receivable (a)
$22
 $21
 $34
 $34
Liabilities:       
Long-term debt, including current portion (b)
17,097
 17,423
 16,655
 16,620
(a) Includes the current portion of notes receivable which is recorded in prepayments and other current assets on the Company's consolidated balance sheets.
(b) Excludes deferred financing costs, which are recorded as a reduction to long-term debt onin the Company's consolidated balance sheets.sheets
The fair value of the Company's publicly-traded long-term debt isand the Vivint Senior Secured Term Loan are based on quoted market prices and isare classified as Level 2 within the fair value hierarchy. The estimated fair value of debt securities, non-publicly traded long-term debtthe borrowing under the Revolving Credit Facility and certain notes receivable ofReceivable Securitization Facilities approximates the Company are based on expected future cash flows discounted atcarrying value because the interest rates vary with market interest rates, or current interest rates for similar instruments with equivalent credit quality and areis classified as Level 3 within the fair value hierarchy. The following table presents the level within the fair value hierarchy for long-term debt, including current portion, as of September 30, 2017March 31, 2023 and December 31, 2016:2022:
 As of September 30, 2017 As of December 31, 2016
 Level 2 Level 3 Level 2 Level 3
 (In millions)
Long-term debt, including current portion$9,571
 $7,852
 $9,205
 $7,415



March 31, 2023December 31, 2022
(In millions)Level 2Level 3Level 2Level 3
Convertible Senior Notes$595 $— $576 $— 
Other long-term debt, including current portion10,062 950 6,432 — 
Total long-term debt, including current portion$10,657 $950 $7,008 $— 
Recurring Fair Value Measurements
Debt securities, equity securities, and trust fund investments, which are comprised of various U.S. debt and equity securities, and derivative assets and liabilities, are carried at fair market value.

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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:
March 31, 2023
Fair Value
(In millions)TotalLevel 1Level 2Level 3
Investments in securities (classified within other current and non-current assets)$19 $— $19 $— 
Nuclear trust fund investments: 
Cash and cash equivalents13 13 — — 
U.S. government and federal agency obligations98 96 2 — 
Federal agency mortgage-backed securities101 — 101 — 
Commercial mortgage-backed securities34 — 34 — 
Corporate debt securities113 — 113 — 
Equity securities430 430 — — 
Foreign government fixed income securities1 1 — — 
Other trust fund investments (classified within other non-current assets):
U.S. government and federal agency obligations
1 1 — — 
Derivative assets: 
Foreign exchange contracts15 — 15 — 
Commodity contracts7,725 1,331 5,360 1,034 
Interest rate contracts10 — 10 — 
Measured using net asset value practical expedient:
Equity securities — nuclear trust fund investments89 
       Equity securities (classified within other non-current assets)6 
Total assets$8,655 $1,872 $5,654 $1,034 
Derivative liabilities: 
Foreign exchange contracts$1 $— $1 $— 
Commodity contracts6,116 1,422 4,131 563 
Interest rate contracts15 — 15 — 
Consumer Financing Program111 — — 111 
Total liabilities$6,243 $1,422 $4,147 $674 

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As of September 30, 2017December 31, 2022
Fair Value
(In millions)Level 1 Level 2 Level 3 Total(In millions)TotalLevel 1Level 2Level 3
Investment in available-for-sale securities (classified within other
non-current assets):
       
Debt securities$—
 $—
 $19
 $19
Available-for-sale securities5
 —
 —
 5
Investments in securities (classified within other current and non-current assets)Investments in securities (classified within other current and non-current assets)$19 $— $19 $— 
Nuclear trust fund investments:       Nuclear trust fund investments:
Cash and cash equivalents31
 —
 —
 31
Cash and cash equivalents15 15 — — 
U.S. government and federal agency obligations43
 1
 —
 44
U.S. government and federal agency obligations86 84 2 — 
Federal agency mortgage-backed securities—
 74
 —
 74
Federal agency mortgage-backed securities101 — 101 — 
Commercial mortgage-backed securities—
 11
 —
 11
Commercial mortgage-backed securities35 — 35 — 
Corporate debt securities—
 108
 —
 108
Corporate debt securities114 — 114 — 
Equity securities333
 —
 65
 398
Equity securities403 403 — — 
Foreign government fixed income securities—
 4
 —
 4
Foreign government fixed income securities1 — 1 — 
Other trust fund investments:       
Other trust fund investments (classified within other non-current assets):Other trust fund investments (classified within other non-current assets):
U.S. government and federal agency obligations1
 —
 —
 1
U.S. government and federal agency obligations
1 1 — — 
Derivative assets:       Derivative assets: 
Foreign exchange contractsForeign exchange contracts18 — 18 — 
Commodity contracts132
 409
 98
 639
Commodity contracts11,976 1,929 8,796 1,251 
Interest rate contracts—
 42
 —
 42
Measured using net asset value practical expedient:Measured using net asset value practical expedient:
Equity securities — nuclear trust fund investmentsEquity securities — nuclear trust fund investments83 
Equity securities (classified within other non-current assets) Equity securities (classified within other non-current assets)6 
Total assets$545
 $649
 $182
 $1,376
Total assets$12,858 $2,432 $9,086 $1,251 
Derivative liabilities:       Derivative liabilities: 
Foreign exchange contractsForeign exchange contracts$2 $— $2 $— 
Commodity contracts201
 404
 146
 751
Commodity contracts8,439 1,244 6,449 746 
Interest rate contracts—
 78
 —
 78
Total liabilities$201
 $482
 $146
 $829
Total liabilities$8,441 $1,244 $6,451 $746 
.


 As of December 31, 2016
 Fair Value
(In millions)Level 1 Level 2 Level 3 Total
Investment in available-for-sale securities (classified within other
non-current assets):
       
Debt securities$—
 $—
 $17
 $17
Available-for-sale securities10
 —
 —
 10
Nuclear trust fund investments:       
Cash and cash equivalents25
 —
 —
 25
U.S. government and federal agency obligations72
 1
 —
 73
Federal agency mortgage-backed securities—
 62
 —
 62
Commercial mortgage-backed securities—
 17
 —
 17
Corporate debt securities—
 84
 —
 84
Equity securities292
 —
 54
 346
Foreign government fixed income securities—
 3
 —
 3
Other trust fund investments:       
U.S. government and federal agency obligations1
 —
 —
 1
Derivative assets:       
Commodity contracts560
 549
 90
 1,199
Interest rate contracts—
 49
 —
 49
Total assets$960
 $765
 $161
 $1,886
Derivative liabilities:       
Commodity contracts494
 636
 158
 1,288
Interest rate contracts—
 88
 —
 88
Total liabilities$494
 $724
 $158
 $1,376

There were no transfers during the three and nine months ended September 30, 2017 and 2016 between Levels 1 and 2. The following tables reconcile,table reconciles, for the three and nine months ended September 30, 2017March 31, 2023 and 2016,2022, the beginning and ending balances for financial instruments that are recognized at fair value in the condensed consolidated financial statements, using significant unobservable inputs, for commodity derivatives:
Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
Commodity Derivatives(a)
(In millions)Three months ended March 31, 2023Three months ended March 31, 2022
Beginning balance$505 $293 
    Total (losses)/gains realized/unrealized included in earnings(91)166 
Purchases41 23 
Transfers into Level 3(b)
24 53 
Transfers out of Level 3(b)
(8)(7)
Ending balance$471 $528 
(Losses)/Gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of period end$(55)$237 
(a)Consists of derivative assets and liabilities, net, excluding derivatives liabilities from Consumer Financing Program, which are presented in a separate table below.
(b)Transfers into/out of Level 3 are related to the availability of external broker quotes and are valued as of the end of the reporting period. All transfers in/out are with Level 2

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


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The following table reconciles, for the three months ended March 31, 2023 the beginning and ending balances of the contractual obligations from the Consumer Financing Program that are recognized at least annually,fair value in the condensed consolidated financial statements, using significant unobservable inputs:
 Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
 Three months ended September 30, 2017 Nine months ended September 30, 2017
(In millions)Debt Securities Trust Fund Investments 
Derivatives(a)
 Total Debt Securities Trust Fund Investments 
Derivatives(a)
 Total
Beginning balance$18
 $61
 $(11) $68
 $17
 $54
 $(68) $3
Total gains/(losses) — realized/unrealized:      

       

Included in earnings1
 —
 (28) (27) 2
 —
 18
 20
Included in nuclear decommissioning obligation—
 3
 —
 3
 —
 10
 —
 10
Purchases—
 1
 (9) (8) —
 1
 —
 1
Transfers into Level 3 (b)
—
 —
 (6) (6) —
 —
 (11) (11)
Transfers out of Level 3 (b)
—
 —
 6
 6
 —
 —
 13
 13
Ending balance as of September 30, 2017$19
 $65
 $(48) $36
 $19
 $65
 $(48) $36
Losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of September 30, 2017$—
 $���
 $(13) $(13) $—
 $—
 $(6) $(6)
(a)Consists of derivative assets and liabilities, net.Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
(b)Transfers into/out of Level 3 are related to the availability of external broker quotes and are valued as of the end of the reporting period. All transfers in/out are with Level 2.Consumer Financing Program


 Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
 Three months ended September 30, 2016 Nine months ended September 30, 2016
(In millions)Debt Securities Trust Fund Investments 
Derivatives(a)
 Total Debt Securities Trust Fund Investments 
Derivatives(a)
 Total
Beginning balance$16
 $51
 $18
 $85
 $17
 $54
 $(22) $49
Total (losses)/gains — realized/unrealized:               
Included in earnings—
 —
 (5) (5) —
 —
 4
 4
Included in OCI1
 —
 —
 1
 —
 —
 —
 —
Included in nuclear decommissioning obligations—
 3
 —
 3
 —
 (1) —
 (1)
Purchases—
 —
 (25) (25) —
 1
 2
 3
Transfers into Level 3 (b)
—
 —
 (13) (13) —
 —
 (6) (6)
Transfers out of Level 3 (b)
—
 —
 3
 3
 —
 —
 —
 —
Ending balance as of September 30, 2016$17
 $54
 $(22) $49
 $17
 $54
 $(22) $49
Losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of September 30, 2016$—
 $—
 $(4) $(4) $—
 $—
 $(11) $(11)
(a)(In millions)Consists of derivative assets and liabilities, net.Three months ended March 31, 2023
(b)Transfers into/out
Beginning balance$— 
Contractual obligations added from the acquisition of Level 3 are related to the availability of external broker quotes and are valued as of the end of the reporting period. All transfers in/out are with Level 2.Vivint112 
New contractual obligations2 
Settlements(3)
Ending balance$111 

Gains and losses, when they occur, are recorded in other income, net.
Derivative Fair Value Measurements
A portion of NRG's contracts are exchange-traded contracts with readily available quoted market prices. A majority of NRG's contracts are non-exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter and on-line exchanges. The remainder of the assets and liabilities represent contracts for which external sources or observable market quotes are not available for the whole term or for certain delivery months or the contracts are retail and load following power contracts.available. These contracts are valued usingbased on various valuation techniques including, but not limited to, internal models that applybased on a fundamental analysis of the market and corroborationextrapolation of the observable market data with similar markets.characteristics. As of September 30, 2017,March 31, 2023, contracts valued with prices provided by models and other valuation techniques make up 14%13% of the total derivative assets and 18%11% of the total derivative liabilities.
NRG's significant positions classified as Level 3 include physical and financial natural gas and power contracts executed in illiquid markets, as well as financial transmission rights, or FTRs. The significant unobservable inputs used in developing fair value include illiquid natural gas and power location pricing, which is derived as a basis to liquid locations. The basis spread is based on observable market data when available or derived from historic prices and forward market prices from similar observable markets when not available. For FTRs, NRG uses the most recent auction prices to derive the fair value.












The Consumer Financing Program derivatives are valued using a discounted cash flow model, with inputs consisting of available market data, such as market yield discount rates, as well as unobservable internally derived assumptions, such as collateral prepayment rates, collateral default rates and loss severity rates. These derivatives are priced quarterly using a credit valuation adjustment methodology.
The following tables quantify the significant, unobservable inputs used in developing the fair value of the Company's Level 3 positions as of September 30, 2017March 31, 2023 and December 31, 2016:2022:
March 31, 2023
Fair ValueInput/Range
(In millions)AssetsLiabilitiesValuation TechniqueSignificant Unobservable InputLowHighWeighted Average
Natural Gas Contracts$152 $196 Discounted Cash FlowForward Market Price (per MMBtu)$1 $17 $4 
Power Contracts827 292 Discounted Cash FlowForward Market Price (per MWh)2 326 45 
FTRs55 75 Discounted Cash FlowAuction Prices (per MWh)(30)145 0
Consumer Financing Program— 111 Discounted Cash FlowCollateral Default Rate1.80 %52.50 %6.16 %
Discounted Cash FlowCollateral Prepayment Rate2.00 %3.00 %2.87 %
Discounted Cash FlowLoss Severity Rates6.00 %36.00 %10.88 %
$1,034 $674 

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Significant Unobservable InputsDecember 31, 2022
September 30, 2017Fair ValueInput/Range
Fair Value Input/Range
Assets Liabilities Valuation Technique Significant Unobservable Input Low High Weighted Average
(In millions)      
(In millions)(In millions)AssetsLiabilitiesValuation TechniqueSignificant Unobservable InputLowHighWeighted Average
Natural Gas ContractsNatural Gas Contracts$340 $448 Discounted Cash FlowForward Market Price (per MMBtu)$2 $48 $6 
Power Contracts$47
 $101
 Discounted Cash Flow Forward Market Price (per MWh) $10
 $88
 $24
Power Contracts843 216 Discounted Cash FlowForward Market Price (per MWh)3 431 48 
FTRs51
 45
 Discounted Cash Flow Auction Prices (per MWh) (31) 36
 —
FTRs68 82 Discounted Cash FlowAuction Prices (per MWh)(32)610 0
$98
 $146
      $1,251 $746 
 Significant Unobservable Inputs
 December 31, 2016
 Fair Value   Input/Range
 Assets Liabilities Valuation Technique Significant Unobservable Input Low High Weighted Average
 (In millions)          
Power Contracts$39
 $108
 Discounted Cash Flow Forward Market Price (per MWh) $11
 $104
 $31
FTRs51
 50
 Discounted Cash Flow Auction Prices (per MWh) (22) 17
 —
 $90
 $158
          
The following table provides sensitivity of fair value measurements to increases/(decreases) in significant, unobservable inputs as of September 30, 2017March 31, 2023 and December 31, 2016:
2022:
Significant Unobservable InputPositionChange In InputImpact on Fair Value Measurement
Forward Market Price Natural Gas/PowerBuyIncrease/(Decrease)Higher/(Lower)
Forward Market Price Natural Gas/PowerSellIncrease/(Decrease)Lower/(Higher)
FTR PricesBuyIncrease/(Decrease)Higher/(Lower)
FTR PricesSellIncrease/(Decrease)Lower/(Higher)
Collateral Default Ratesn/aIncrease/(Decrease)Higher/(Lower)
Collateral Prepayment Ratesn/aIncrease/(Decrease)Lower/(Higher)
 Loss Severity Ratesn/aIncrease/(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, 2017, the credit reserve resulted in a $1 million increase in fair value in operating revenue and cost of operations. As of DecemberMarch 31, 2016,2023, the credit reserve resulted in a $10 million decrease in fair value in operating revenue andprimarily within cost of operations. As of December 31, 2022, the credit reserve resulted in a $9 million decrease primarily within cost of operations.
Concentration of Credit Risk
In addition to the credit risk discussion as disclosed in Note 2,, Summary of Significant Accounting Policies, to the Company's 20162022 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, andas well as retail customer credit risk through its retail load activities.



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Counterparty Credit Risk
The Company's counterparty credit risk policies are disclosed in its 20162022 Form 10-K. As of September 30, 2017, the Company'sMarch 31, 2023, counterparty credit exposure, excluding credit risk exposure underfrom RTOs, ISOs, registered commodity exchanges and certain long termlong-term agreements, was $134 million with net exposure of $129 million.$1.7 billion and NRG held collateral (cash and letters of credit) against those positions of $14$554 million,. resulting in a net exposure of $1.1 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 74%52% of the Company's exposure before collateral is expected to roll off by the end of 2018.2024. Counterparty credit exposure is valued through observable market quotes and discounted at a risk free interest rate. The following tables highlight net counterparty credit exposure by industry sector and by counterparty credit quality. Net counterparty credit exposure is defined as the aggregate net asset position for NRG with counterparties where netting is permitted under the enabling agreement and includes all cash flow, mark-to-market and NPNS, and non-derivative transactions. The exposure is shown net of collateral held and includes amounts net of receivables or payables.
Net Exposure(a)(b)
Category by Industry Sector(% of Total)
Utilities, energy merchants, marketers and other9171 %
Financial institutions929 
Total as of September 30, 2017March 31, 2023100%
Net Exposure (a)(b)
Category by Counterparty Credit Quality(% of Total)
Investment grade7955 %
Non-InvestmentNon-investment grade/Non-Ratednon-rated2145 
Total as of September 30, 2017March 31, 2023100%
(a)Counterparty credit exposure excludes uranium and coal transportation contracts because of the unavailability of market prices.
(b)
(a)Counterparty credit exposure excludes uranium and coal transportation contracts because of the unavailability of market prices
(b)The figures in the tables above exclude potential counterparty credit exposure related to RTOs, ISOs, registered commodity exchanges and certain long term contracts.
NRG has counterparty credit riskexposure related to RTOs, ISOs, registered commodity exchanges and certain long-term contracts
The Company currently has exposure to certaintwo wholesale counterparties eachin excess of which represent more than 10% of total net exposure discussed above. The aggregate of such counterparties' exposure was $50 millionas of September 30, 2017.March 31, 2023. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration. Given the credit quality, diversification and term of the exposure in the portfolio, NRG does not anticipate a material impact on the Company's financial position or results of operations from nonperformance by any of NRG's counterparties.
RTOs and ISOs
The Company participates in the organized markets of CAISO, ERCOT, AESO, IESO, ISO-NE, MISO, NYISO and PJM, known as RTOs or ISOs. Trading in the majority of these markets is approved by FERC, orwhereas in the case of ERCOT, it is approved by the PUCT, and includeswhereas 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 NYMEX.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 TermLong-Term Contracts
Counterparty credit exposure described above excludes credit risk exposure under certain long term agreements, including California tolling agreements, Gulf Coast load obligations, and wind and solarlong-term contracts, primarily Renewable PPAs. As external sources or observable market quotes are not always available to estimate such exposure, the Company estimates its credit exposure forvalues 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, 2017,March 31, 2023, aggregate credit risk exposure managed by NRG to these counterparties was approximately $4.3$1.1 billion including $2.8 billion related to assets of NRG Yield, Inc., for the next five years. This amount excludes potential credit exposures for projects with long-term PPAs that have not reached commercial operations. The majority of these power contracts are with utilities or public power entities with strong credit quality and public utility commission or other regulatory support. However, such regulated utility counterparties can be impacted by changes in government regulations or treatment by regulatory agencies which NRG is unable to predict.



Retail Customer Credit Risk
NRGThe Company is exposed to retail credit risk through the Company's retail electricity and gas providers as well as through Vivint, which serve commercial, industrialboth Home and governmental/institutional customers and the Mass market.Business customers. Retail credit risk results in losses when a customer fails to pay for products or services rendered. The losses may result from both nonpaymentnon-payment of customer accounts receivable and the loss of in-the-money

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forward value. NRGThe Company manages retail credit risk through the use of established credit policies, thatwhich include monitoring of the portfolio and the use of credit mitigation measures such as deposits or prepayment arrangements.
As of September 30, 2017,March 31, 2023, the Company believes itsCompany's retail customer credit exposure to Home and Business customers was diversified across many customers and various industries, as well as government entities. Current economic conditions may affect the Company’s customers’ ability to pay bills in a timely manner, which could increase customer delinquencies and may lead to an increase in credit losses.

Note 56 — Nuclear Decommissioning Trust Fund
This footnote should be read in conjunction with the complete description under Note 6, Nuclear Decommissioning Trust Fund, to the Company's 2016 Form 10-K.
NRG's Nuclear Decommissioning Trust Fund assets, which are for the decommissioning of its 44% interest in STP, are comprised of securities classified as available-for-sale and recorded at fair value based on actively quoted market prices. NRG accounts for the Nuclear Decommissioning Trust Fund in accordance with ASC 980, Regulated Operations, because the Company's nuclear decommissioning activities are subject to approval by the PUCT with regulated rates that are designed to recover all decommissioning costs and that can be charged to and collected from the ratepayers per PUCT mandate. Since the Company is in compliance with PUCT rules and regulations regarding decommissioning trusts and the cost of decommissioning is the responsibility of the Texas ratepayers, not NRG, all realized and unrealized gains or losses (including other-than-temporary impairments) related to the Nuclear Decommissioning Trust Fund are recorded to nuclear decommissioning trustthe Nuclear Decommissioning Trust liability and are not included in net income or accumulated OCI, consistent with regulatory treatment.
The following table summarizes the aggregate fair values and unrealized gains and losses (including other-than-temporary impairments) for the securities held in the trust funds, as well as information about the contractual maturities of those securities.
As of March 31, 2023As of December 31, 2022
As of September 30, 2017 As of December 31, 2016
(In millions, except otherwise noted)Fair Value Unrealized Gains Unrealized Losses Weighted-average Maturities (In years) Fair Value Unrealized Gains Unrealized Losses Weighted-average Maturities (In years)
(In millions, except maturities)(In millions, except maturities)Fair ValueUnrealized GainsUnrealized LossesWeighted-average Maturities (In years)Fair ValueUnrealized GainsUnrealized LossesWeighted-average Maturities (In years)
Cash and cash equivalents$31
 $—
 $—
 —
 $25
 $—
 $—
 —
Cash and cash equivalents$13 $— $— — $15 $— $— — 
U.S. government and federal agency obligations44
 2
 —
 10
 73
 1
 —
 11
U.S. government and federal agency obligations98 1 4 1186 — 5 11
Federal agency mortgage-backed securities74
 1
 1
 24
 62
 1
 1
 25
Federal agency mortgage-backed securities101 — 8 26101 — 11 26
Commercial mortgage-backed securities11
 —
 —
 23
 17
 —
 1
 26
Commercial mortgage-backed securities34 — 3 2935 — 4 30
Corporate debt securities108
 2
 1
 11
 84
 1
 2
 11
Corporate debt securities113 1 9 11114 — 13 12
Equity securities398
 260
 —
 —
 346
 214
 —
 —
Equity securities519 374 — — 486 346 3 — 
Foreign government fixed income securities4
 —
 —
 9
 3
 —
 —
 9
Foreign government fixed income securities1 — — 201 — — 17
Total$670
 $265
 $2
   $610
 $217
 $4
  Total$879 $376 $24 $838 $346 $36 
The following table summarizes proceeds from sales of available-for-sale securities held in the trust funds and the related realized gains and losses from these sales. The cost of securities sold is determined on the specific identification method.
 Three months ended March 31,
(In millions)20232022
Realized gains$2 $1 
Realized losses(5)(4)
Proceeds from sale of securities99 161 

 Nine months ended September 30,
 2017 2016
 (In millions)
Realized gains$8
 $7
Realized losses6
 3
Proceeds from sale of securities382

354


Note 67 — Accounting for Derivative Instruments and Hedging Activities
This footnote should be read in conjunction with the complete description under Note 5, Accounting for Derivative Instruments and Hedging Activities, to the Company's 2016 Form 10-K.
Energy-Related Commodities
As of September 30, 2017,March 31, 2023, NRG had energy-related derivative instruments extending through 2031.2036. The Company marks these derivatives to market through the statement of operations. NRG has executed energy-related contracts extending through 2038 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 ratesrate through the Company's issuance of variable rate debt. In order to manage the Company's interest rate risk, NRG enters into interest rate swap agreements. In the first quarter of 2023, the Company entered into $1.0 billion of interest rate swaps through 2027 to hedge the floating rate on the Term Loan acquired with the Vivint

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acquisition. Additionally, in the first quarter of 2023, the Company entered into a $720 million interest rate swap to hedge the floating rate on the Revolving Credit Facility extending through 2024.
Foreign Exchange Contracts
NRG is exposed to changes in foreign currency primarily associated with the purchase of USD denominated natural gas for its Canadian business. In order to manage the Company's foreign exchange risk, NRG entered into foreign exchange contracts. As of September 30, 2017,March 31, 2023, NRG had foreign exchange contracts extending through 2026. The Company marks these derivatives to market through the statement of operations.
Consumer Financing Program
Under the Consumer Financing Program, Vivint 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 incurs fees at the time of the loan origination and receives proceeds that are net of these fees. Vivint also shares the liability for credit losses, depending on the credit quality of the customer. Due to the nature of certain provisions under the Consumer Financing Program, the Company had interest raterecords a derivative instruments on recourse debt extending through 2021, which areliability 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 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 shares the liability for credit losses depending on the credit quality of the customer; and
•    Vivint pays transactional fees associated with customer payment processing.
The derivative is classified as a Level 3 instrument. The derivative positions are valued using a discounted cash flow hedges. The Company had interest rate swaps on non-recourse debt extending through 2041, mostmodel, with inputs consisting of whichavailable market data, such as market yield discount rates, as well as unobservable internally derived assumptions, such as collateral prepayment rates, collateral default rates and loss severity rates. These derivatives are designated aspriced quarterly using a credit valuation adjustment methodology. In summary, the fair value represents an estimate of the present value of the cash flow hedges.flows Vivint will be obligated to pay to the Financing Provider for each component of the derivative.
Volumetric Underlying Derivative Transactions
The following table summarizes the net notional volume buy/(sell) of NRG's open derivative transactions broken out by category, excluding those derivatives that qualified for the NPNS exception, as of September 30, 2017March 31, 2023 and December 31, 2016.2022. Option contracts are reflected using delta volume. Delta volume equals the notional volume of an option adjusted for the probability that the option will be in-the-money at its expiration date.
  Total Volume (In millions)
CategoryUnitsMarch 31, 2023December 31, 2022
EmissionsShort Ton— 1 
Renewable Energy CertificatesCertificates13 15 
CoalShort Ton14 11 
Natural GasMMBtu667 422 
OilBarrels— 1 
PowerMWh198 192 
Consumer Financing ProgramDollars863 — 
Foreign ExchangeDollars594 569 
InterestDollars1,720 — 

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  Total Volume
  September 30, 2017 December 31, 2016
CategoryUnits(In millions)
EmissionsShort Ton(1) —
CoalShort Ton15
 35
Natural GasMMBtu(62) (53)
OilBarrel—
 1
PowerMWh19
 7
CapacityMW/Day(1) (1)
InterestDollars$3,806
 $3,429
EquityShares1
 1
The decrease in the coal position was primarily the result of the settlement of hedge positions, and the increase in the power position was primarily the result of additional retail hedge positions.


Fair Value of Derivative Instruments
The following table summarizes the fair value within the derivative instrument valuation on the balance sheets:
 Fair Value
 Derivative Assets Derivative Liabilities
 September 30, 2017 December 31, 2016 September 30, 2017 December 31, 2016
 (In millions)
Derivatives designated as cash flow hedges:
   

 
Interest rate contracts current$—
 $—
 $8

$28
Interest rate contracts long-term10
 12
 15

41
Total derivatives designated as cash flow hedges10
 12
 23

69
Derivatives not designated as cash flow hedges:
    
 
Interest rate contracts current5
 —
 19

7
Interest rate contracts long-term27
 37
 36

12
Commodity contracts current470
 1,067
 495

1,057
Commodity contracts long-term169
 132
 256

231
Total derivatives not designated as cash flow hedges671
 1,236
 806

1,307
Total derivatives$681

$1,248
 $829

$1,376




 Fair Value
 Derivative AssetsDerivative Liabilities
(In millions)March 31, 2023December 31, 2022March 31, 2023December 31, 2022
Derivatives Not Designated as Cash Flow or Fair Value Hedges:   
Interest rate contracts - current$10 $— $— $— 
Interest rate contracts - long-term— — 15 — 
Foreign exchange contracts - current9 11 — 1 
Foreign exchange contracts - long-term6 7 1 1 
Consumer Financing Program - short-term— — 80 — 
Consumer Financing Program - long-term— — 31 — 
Commodity contracts - current4,381 7,875 4,270 6,194 
Commodity contracts - long-term3,344 4,101 1,846 2,245 
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges$7,750 $11,994 $6,243 $8,441 
The Company has elected to present derivative assets and liabilities on the balance sheet on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. In addition, collateral received or paid on the Company's derivative assets or liabilities are recorded on a separate line item on the balance sheet. The following table summarizes the offsetting of derivatives by counterparty master agreement level and collateral received or paid:
Gross Amounts Not Offset in the Statement of Financial Position
(In millions)Gross Amounts of Recognized Assets / LiabilitiesDerivative InstrumentsCash Collateral (Held) /PostedNet Amount
As of March 31, 2023
Foreign exchange contracts:
Derivative assets$15 $(1)$— $14 
Derivative liabilities(1)1 — — 
Total foreign exchange contracts$14 $— $— $14 
Commodity contracts:
Derivative assets$7,725 $(5,750)$(307)$1,668 
Derivative liabilities(6,116)5,750 8 (358)
Total commodity contracts$1,609 $— $(299)$1,310 
Consumer Financing Program:
Derivative liabilities$(111)$— $— $(111)
Interest rate contracts:
Derivative assets$10 $(8)$— $2 
Derivative liabilities(15)8 — (7)
Total interest rate contracts(5)— — (5)
Total derivative instruments$1,507 $— $(299)$1,208 

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  Gross Amounts Not Offset in the Statement of Financial Position
  Gross Amounts of Recognized Assets / Liabilities Derivative Instruments Cash Collateral (Held) / Posted Net Amount
As of September 30, 2017 (In millions)
Commodity contracts:        
Derivative assets $639
 $(546) $(5) $88
Derivative liabilities (751) 546
 83
 (122)
Total commodity contracts (112) —
 78
 (34)
Interest rate contracts:        
Derivative assets 42
 (2) —
 40
Derivative liabilities (78) 2
 —
 (76)
Total interest rate contracts (36) —
 —
 (36)
Total derivative instruments $(148) $—
 $78
 $(70)
  Gross Amounts Not Offset in the Statement of Financial Position
  Gross Amounts of Recognized Assets / Liabilities Derivative Instruments Cash Collateral (Held) / Posted Net Amount
As of December 31, 2016 (In millions)
Commodity contracts:       
Derivative assets $1,199
 $(1,021) $(13) $165
Derivative liabilities (1,288) 1,021
 13
 (254)
Total commodity contracts (89) —
 —
 (89)
Interest rate contracts:       
Derivative assets 49
 (4) —
 45
Derivative liabilities (88) 4
 —
 (84)
Total interest rate contracts (39) —
 —
 (39)
Total derivative instruments $(128) $—
 $—

$(128)
Accumulated Other Comprehensive Loss
The following table summarizes the effects of ASC 815 on the Company's accumulated OCI balance attributable to cash flow hedge derivatives, net of tax:
 Interest Rate Contracts
 Three months ended September 30, Nine months ended September 30,
 2017 2016 2017 2016
 (In millions)
Accumulated OCI beginning balance$(67) $(165) $(66) $(101)
Reclassified from accumulated OCI to income:       
Due to realization of previously deferred amounts4
 2
 10
 12
Mark-to-market of cash flow hedge accounting contracts4
 32
 (3) (42)
Accumulated OCI ending balance, net of $15, and $28 tax$(59) $(131)
$(59)
$(131)
Losses expected to be realized from OCI during the next 12 months, net of $4 tax$14
 
 $14
 

Amounts reclassified from accumulated OCI into income and amounts recognized in income from the ineffective portion of cash flow hedges are recorded to interest expense for interest rate contracts. There was no ineffectiveness for the three and nine months ended September 30, 2017 and 2016.


Accounting guidelines require a high degree of correlation between the derivative and the hedged item throughout the period in order to qualify as a cash flow hedge. As of December 31, 2016, the Company's regression analysis for Viento Funding II interest rate swaps, while positively correlated, did not meet the required threshold for cash flow hedge accounting. As a result, the Company de-designated the Viento Funding II cash flow hedges as of December 31, 2016, and will prospectively mark these derivatives to market through the income statement.
The Company's regression analysis for Marsh Landing, Walnut Creek, and Avra Valley interest rate swaps, while positively correlated, no longer contain match terms for cash flow hedge accounting. As a result, the Company voluntarily de-designated the Marsh Landing, Walnut Creek, and Avra Valley cash flow hedges as of April 28, 2017, and will prospectively mark these derivatives to market through the income statement.
Gross Amounts Not Offset in the Statement of Financial Position
(In millions)Gross Amounts of Recognized Assets / LiabilitiesDerivative InstrumentsCash Collateral (Held) /PostedNet Amount
As of December 31, 2022
Foreign exchange contracts:
Derivative assets$18 $(2)$— $16 
Derivative liabilities(2)2 — — 
Total foreign exchange contracts$16 $— $— $16 
Commodity contracts:
Derivative assets$11,976 $(7,897)$(1,659)$2,420 
Derivative liabilities(8,439)7,897 20 (522)
Total commodity contracts$3,537 $— $(1,639)$1,898 
Total derivative instruments$3,553 $— $(1,639)$1,914 
Impact of Derivative Instruments on the Statements of Operations
Unrealized gains and losses associated with changes in the fair value of derivative instruments not accounted for as cash flow hedges and ineffectiveness of hedge derivativesfair value hedges are reflected in current period consolidated results of operations.
The following table summarizes the pre-tax effects of economic hedges that have not been designated as cash flow hedges ineffectiveness on cash flowor fair value hedges and trading activity on the Company's statement of operations.
(In millions)Three months ended March 31,
Unrealized mark-to-market results20232022
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges$(846)$(408)
Reversal of acquired (gain) positions related to economic hedges(25)(60)
Net unrealized (losses)/gains on open positions related to economic hedges(1,073)2,745 
Total unrealized mark-to-market (losses)/gains for economic hedging activities(1,944)2,277 
Reversal of previously recognized unrealized losses on settled positions related to trading activity1 1 
Net unrealized gains/(losses) on open positions related to trading activity11 (15)
Total unrealized mark-to-market gains/(losses) for trading activity12 (14)
Total unrealized (losses)/gains - commodities and foreign exchange$(1,932)$2,263 

Three months ended March 31,
(In millions)20232022
Unrealized gains/(losses) included in revenues - commodities$103 $(147)
Unrealized (losses)/gains included in cost of operations - commodities(2,037)2,414 
Unrealized gains/(losses) included in cost of operations - foreign exchange2 (4)
Total impact to statement of operations - commodities and foreign exchange$(1,932)$2,263 
Total impact to statement of operations - interest rate contracts$(5)$— 
The effect of energyforeign exchange and commodity contracts ishedges are included within operating revenues and cost of operations and theoperations. The effect of the interest rate contracts isare included inwithin interest expense.
 Three months ended September 30, Nine months ended September 30,
 2017 2016 2017 2016
Unrealized mark-to-market results(In millions)
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges$(6) $(30) $19
 $(75)
Reversal of acquired gain positions related to economic hedges(2) (7) (1) (11)
Net unrealized (losses)/gains on open positions related to economic hedges(16) (50) (1) 27
Total unrealized mark-to-market (losses)/gains for economic hedging activities(24) (87) 17
 (59)
Reversal of previously recognized unrealized (gains)/losses on settled positions related to trading activity(5) 3
 (24) 13
Net unrealized (losses)/gains on open positions related to trading activity—
 (8) 17
 14
Total unrealized mark-to-market (losses)/gains for trading activity(5) (5) (7) 27
Total unrealized (losses)/gains$(29) $(92) $10
 $(32)
 Three months ended September 30, Nine months ended September 30,
 2017 2016 2017 2016
 (In millions)
Unrealized gains/(losses) included in operating revenues$21
 $57
 $178
 $(333)
Unrealized (losses)/gains included in cost of operations(50) (149) (168) 301
Total impact to statement of operations — energy commodities$(29) $(92) $10
 $(32)
Total impact to statement of operations — interest rate contracts$11
 $9
 $(8) $(9)
The reversals of acquired gain or loss positions were valued based upon the forward prices on the acquisition date. The roll-off amounts were offset by realized gains or losses at the settled prices and are reflected in operating revenue or cost of operations during the same period.
For the ninethree months ended September 30, 2017,March 31, 2023, the $1 million$1.1 billion unrealized losslosses from open economic hedge positions was primarily the result of a decrease in value of forward purchasespositions as a result of coal,decreases in natural gas and ERCOT power due to decreases in coal, natural gas, and ERCOT electricity prices, which was largely offset by an increase in value of forward sales of PJM power and New York capacity due to decreases in PJM electricity and New York capacity prices.

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For the ninethree months ended September 30, 2016,March 31, 2022, the $27 million$2.7 billion unrealized gain from open economic hedge positions was primarily the result of an increase in value of forward purchasespositions as a result of natural gas due to increases in natural gas and power prices.


Credit Risk Related Contingent Features
Certain of the Company's hedgingtrading agreements contain provisions that requireentitle the counterparty to demand that the Company to 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 requiresrequire the Company to post additional collateral if there were a one notch 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, 2017,March 31, 2023 was $27 million. The collateral required for contracts with credit rating contingent features as of September 30, 2017, was $34$612 million. The Company is also a party to certain marginable agreements where NRGunder which it has a net liability position, but the counterparty has not called for the collateral due, which was approximately $17$124 million as of September 30, 2017.March 31, 2023. In the event of a downgrade in the Company's credit rating and if called for by the counterparty, $33 million of additional collateral would be required for all contracts with credit rating contingent features as of March 31, 2023.
See Note 4, 5, Fair Value of Financial Instruments, to this Form 10-Q for discussion regarding concentration of credit risk.

Note 7 — Impairments

2017 Impairment Losses
Bacliff Project — On June 16, 2017, NRG Texas Power LLC provided notice to BTEC New Albany, LLC that it was exercising its right to terminate the Amended and Restated Membership Interest Purchase Agreement, or MIPA, due to the Bacliff Project, a new peaking facility at the former P.H. Robinson Electric Generating Station, not achieving commercial completion by the contractual expiration date of May 31, 2017. As a result of the MIPA termination, the Company recorded an impairment loss of $41 million to reduce the carrying amount of the related construction in progress to $0 during the second quarter of 2017. On July 14, 2017, the Company gave notice to BTEC New Albany, LLC that it owes NRG Texas Power LLC approximately $48 million under the terminated MIPA, consisting of $38 million in purchaser incurred costs and $10 million in liquidated damages.
Other Impairments — During the second quarter of 2017, the Company recorded impairment losses of approximately $22 million in connection with the Company's Renewables business. During the third quarter of 2017, the Company recorded an additional $14 million in impairment losses, in connection with the Company's Renewable business.
2016 Impairment Losses
Rockford — On May 12, 2016, the Company entered into an agreement with RA Generation, LLC to sell 100% of its interests in the Rockford generating stations for cash consideration of $55 million. The transaction triggered an indicator of impairment as the sale price was less than the carrying amount of the assets, and, as a result, the assets were considered to be impaired. The Company measured the impairment loss as the difference between the carrying amount of the assets and the agreed-upon sale price. The Company recorded an impairment loss of $17 million during the quarter ended June 30, 2016, to reduce the carrying amount of the assets held for sale to the fair market value.
Other Impairments — During the second quarter of 2016, the Company recorded impairment losses for intangible assets of $8 million in connection with the Company's strategic change in its residential solar business as well as $10 million of deferred marketing expenses. In addition, the Company also recorded an impairment loss of $17 million to record certain previously purchased solar panels at fair market value. During the third quarter of 2016, the Company recorded an additional $9 million in impairment losses related to investments and $8 million in other impairments.
Petra Nova Parish Holdings —During the first quarter of 2016, management changed its plans with respect to its future capital commitments driven in part by the continued decline in oil prices. As a result, the Company reviewed its 50% interest in Petra Nova Parish Holdings for impairment utilizing the other-than-temporary impairment model. In determining fair value, the Company utilized an income approach and considered project specific assumptions for the future project cash flows. The carrying amount of the Company's equity method investment exceeded the fair value of the investment and the Company concluded that the decline is considered to be other than temporary. As a result, the Company measured the impairment loss as the difference between the carrying amount and the fair value of the investment and recorded an impairment loss of $140 million.




Note 8 — Long-term Debt and CapitalFinance Leases
This footnote should be read in conjunction with the complete description under Note 12, Debt and Capital Leases, to the Company's 2016 Form 10-K. Long-term debt and capitalfinance leases consisted of the following:
(In millions, except rates)March 31, 2023December 31, 2022Interest rate %
Recourse debt:
Senior Notes, due 2027$375 $375 6.625
Senior Notes, due 2028821 821 5.750
Senior Notes, due 2029733 733 5.250
Senior Notes, due 2029500 500 3.375
Senior Notes, due 20311,030 1,030 3.625
Senior Notes, due 20321,100 1,100 3.875
Convertible Senior Notes, due 2048(a)
575 575 2.750
Senior Secured First Lien Notes, due 2024600 600 3.750
Senior Secured First Lien Notes, due 2025500 500 2.000
Senior Secured First Lien Notes, due 2027900 900 2.450
Senior Secured First Lien Notes, due 2029500 500 4.450
Senior Secured First Lien Notes, due 2033740 — 7.000
Revolving Credit Facility725 — SOFR + 1.720
Receivables Facility150 — various
Repurchase Facility75 — SOFR + 1.300
Tax-exempt bonds466 466 1.250 - 4.750
Subtotal recourse debt9,790 8,100 
Non-recourse debt:
Vivint Senior Secured Notes, due 2027600 — 6.750
Vivint Senior Notes, due 2029800 — 5.750
Vivint Senior Secured Term Loan, due 20281,330 — various
Subtotal all Vivint non-recourse debt2,730 — 
Subtotal long-term debt (including current maturities)12,520 8,100 
Finance leases19 11 various
Subtotal long-term debt and finance leases (including current maturities)12,539 8,111 
Less current maturities(971)(63)
Less debt issuance costs(75)(70)
Discounts(161)(2)
Total long-term debt and finance leases$11,332 $7,976 
(In millions, except rates)September 30, 2017 December 31, 2016 
September 30, 2017 interest rate % (a)
   
Recourse debt:     
Senior notes, due 2018$398
 $398
 7.625
Senior notes, due 2021207
 207
 7.875
Senior notes, due 2022992
 992
 6.250
Senior notes, due 2023869
 869
 6.625
Senior notes, due 2024733
 733
 6.250
Senior notes, due 20261,000
 1,000
 7.250
Senior notes, due 20271,250
 1,250
 6.625
Term loan facility, due 20231,876
 1,891
 L+2.25
Tax-exempt bonds465
 455
 4.125 - 6.00
Subtotal NRG recourse debt7,790
 7,795
 
Non-recourse debt:     
NRG Yield Operating LLC Senior Notes, due 2024500
 500
 5.375
NRG Yield Operating LLC Senior Notes, due 2026350
 350
 5.000
NRG Yield, Inc. Convertible Senior Notes, due 2019345
 345
 3.500
NRG Yield, Inc. Convertible Senior Notes, due 2020288
 288
 3.250
El Segundo Energy Center, due 2023400
 443
 L+1.75 - L+2.375
Marsh Landing, due 2017 and 2023334
 370
 L+1.750 - L+1.875
Alta Wind I - V lease financing arrangements, due 2034 and 2035940
 965
 5.696 - 7.015
Walnut Creek, term loans due 2023279
 310
 L+1.625
Utah Portfolio, due 2022284
 287
 L+2.625
Tapestry, due 2021165
 172
 L+1.625
CVSR, due 2037746
 771
 2.339 - 3.775
CVSR HoldCo, due 2037194
 199
 4.680
Alpine, due 2022138
 145
 L+1.750
Energy Center Minneapolis, due 2017 and 202582
 96
 5.95 - 7.25
Energy Center Minneapolis, due 2031125
 125
 3.55
Viento, due 2023169
 178
 L+3.00
NRG Yield - other562
 540
 various
Subtotal NRG Yield debt (non-recourse to NRG)5,901
 6,084
  
Ivanpah, due 2033 and 20381,097
 1,113
 2.285 - 4.256
Carlsbad Energy Project407
 —
 4.120
Agua Caliente, due 2037833
 849
 2.395 - 3.633
Agua Caliente Borrower 1, due 203889
 —
 5.430
Cedro Hill, due 2025153
 163
 L+1.75
Midwest Generation, due 2019173
 231
 4.390
NRG Other689
 468
 various
Subtotal other NRG non-recourse debt3,441
 2,824
  
Subtotal all non-recourse debt9,342
 8,908
  
Subtotal long-term debt (including current maturities)17,132

16,703
  
Capital leases6
 6
 various
Subtotal long-term debt and capital leases (including current maturities)17,138

16,709
  
Less current maturities(1,247)
(516)  
Less debt issuance costs(198) (188)  
Discounts(35) (48)  
Total long-term debt and capital leases$15,658

$15,957
  
(a)As of September 30, 2017, L+ equals 3 month LIBOR plus x%, with the exceptionex-dividend date of April 28, 2023, the Utah Portfolio term loans.Convertible Senior Notes were convertible at a price of $42.57, which is equivalent to a conversion rate of approximately 23.4925 shares of common stock per $1,000 principal amount



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Recourse Debt
2023 Term Loan Facility
On January 24, 2017, NRG repriced the 2023 Term Loan Facility, reducing the interest rate margin by 50 basis points to LIBOR plus 2.25%. The LIBOR floor remains 0.75%.
Revolving Credit Facility
On June 12, 2017, NRG repaid $125 million on the Revolving Credit Facility. As of September 30, 2017, no cash borrowings were outstanding on the revolver.
Senior Notes
2017 Senior Note Redemptions
On October 16, 2017, the Company redeemed $398 million of its 7.625% Senior Notes due 2018 and $206 million of its 7.875% Senior Notes due 2021 for $630 million, which included $14 million in accrued interest.
2016 Senior Note Repurchases
During the nine months ended September 30, 2016, the Company repurchased $2.6 billion in aggregate principal of its Senior Notes in the open market for $2.7 billion, which included accrued interest of $67 million. In connection with the repurchases, a $94 million loss on debt extinguishment was recorded, which included the write-off of previously deferred financing costs of $15 million.
Issuance of 20262033 Senior Secured First Lien Notes
On May 23, 2016, NRGMarch 9, 2023, the Company issued $1.0 billion in$740 million of aggregate principal amount at par of 7.25%7.000% senior secured first lien notes due 2026, or the 20262033 (the "2033 Senior Notes.Secured First Lien Notes"). The 20262033 Senior Secured First Lien Notes are senior unsecuredsecured obligations of NRG and are guaranteed by certain of its subsidiaries. The 2033 Senior Secured First Lien Notes are secured by a first priority security interest in the same collateral that is pledged for the benefit of the lenders under the Revolving Credit Facility and existing senior secured notes, which collateral consists of a substantial portion of the property and assets owned by the Company and the guarantors. The collateral securing the 2033 Senior Secured First Lien Notes will be released at the Company’s request if the senior unsecured long-term debt securities of the Company are rated investment grade by any two of the three rating agencies, subject to reversion if such rating agencies withdraw such investment grade rating or downgrade such rating below investment grade. Interest is paid semi-annually beginning on NovemberSeptember 15, 2016,2023 until the maturity date of MayMarch 15, 2026.2033. The proceeds of the 2033 Senior Secured First Lien Notes, along with cash on hand and other proceeds, were used to fund the acquisition of Vivint.
Issuance of 20272048 Convertible Senior Notes
As of March 31, 2023, the Convertible Senior Notes were convertible, under certain circumstances, into cash or a combination of cash and the Company’s common stock at a price of $43.01 per common share, which is equivalent to a conversion rate of approximately 23.2527 shares of common stock per $1,000 principal amount of Convertible Senior Notes. The net carrying amounts of the Convertible Senior Notes as of March 31, 2023 and December 31, 2022 were $571 million and $570 million, respectively. The Convertible Senior Notes mature on June 1, 2048, unless earlier repurchased, redeemed or converted in accordance with their terms. The Convertible Senior notes are convertible at the option of the holders under certain circumstances. Prior to the close of business on the business day immediately preceding December 1, 2024, the Convertible Senior Notes will be convertible only upon the occurrence of certain events and during certain periods, and thereafter during specified periods as follows:
•from December 1, 2024 until the close of business on the second scheduled trading day immediately before June 1, 2025; and
•from December 1, 2047 until the close of business on the second scheduled trading day immediately before the maturity date
The following table details the interest expense recorded in connection with the Convertible Senior Notes, due 2048:
Three months ended March 31,
($ In millions)20232022
Contractual interest expense$4 $4 
Amortization of discount and deferred finance costs1 — 
Total$5 $4 
Effective Interest Rate0.77 %0.76 %
Revolving Credit Facility
On August 2, 2016,February 14, 2023, the Company amended its Revolving Credit Facility to: (i) increase the existing revolving commitments thereunder by $600 million, (ii) extend the maturity date of a portion of the revolving commitments thereunder to February 14, 2028, (iii) transition the benchmark rate applicable to revolving loans from LIBOR to SOFR and (iv) make certain other amendments to the terms of the Revolving Credit Facility for purposes of, among other things, providing additional flexibility. For further discussion, see Note 13, Long-term Debt and Finance Leases, ofthe Company’s 2022 Form 10-K.
On March 13, 2023, the Company amended its Revolving Credit Facility to, among other things, increase the existing revolving commitments by $45 million. As of March 31, 2023, there were outstanding borrowings of $725 million and there were $1.1 billion in letters of credit issued under the Revolving Credit Facility. As of April 30, 2023, there were outstanding borrowings of $650 million and $994 million in letters of credit issued under the Revolving Credit Facility.
Dunkirk Bonds
On April 3, 2023, NRG issued $1.25 billionremarketed $59 million in aggregate principal amount of 4.25% tax-exempt refinancing bonds of the Chautauqua County Capital Resource Corporation (the "Dunkirk Bonds"). The Dunkirk Bonds are guaranteed on a first-priority basis by each of NRG's current and future subsidiaries that guarantee indebtedness under the Revolving Credit Facility. The Dunkirk Bonds are secured by a first priority security interest in the same collateral that is pledged for the benefit of the lenders under the Revolving Credit Facility, which consists of a substantial portion of the property and assets owned by NRG

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and the guarantors. The collateral securing the Dunkirk Bonds will, at parthe request of 6.625% senior notes due 2027, or the 2027 Senior Notes. The 2027 Senior Notes areNRG, be released if NRG satisfies certain conditions, including receipt of an investment grade rating on its senior, unsecured obligationsdebt securities from two out of NRGthe three rating agencies, subject to reversion if those rating agencies withdraw their investment grade rating of the Dunkirk Bonds or any of NRG's senior, unsecured debt securities or downgrade such ratings below investment grade. The Dunkirk Bonds are subject to mandatory tender and are guaranteed by certain of its subsidiaries. Interest is paid semi-annually beginningpurchase on January 15, 2017, until theApril 3, 2028 and have a final maturity date of January 15, 2027. The proceeds from the issuance of the 2027 Senior Notes were utilized to retire the Company's 8.250% senior notes due 2020 and reduce the balance of the Company's 7.875% senior notes due 2021.April 1, 2042.
Non-recourse Debt
NRG Yield LLC and NRG Yield Operating LLC Revolving Credit FacilityThe following are descriptions of certain indebtedness of NRG's subsidiaries. All of NRG's non-recourse debt is secured by the assets in the subsidiaries as further described below.
NRG Yield LLC and its directVivint Acquired Debt
On March 10, 2023, in connection with the Vivint acquisition, Vivint's wholly owned indirect subsidiary, NRG Yield Operating LLC, entered into aAPX Group, Inc. ("APX"), retained its 6.750% senior secured notes due 2027, 5.750% senior notes due 2029, senior secured term loan credit agreement and senior secured revolving credit facility.
Vivint 2027 Senior Secured Notes
As of March 31, 2023, Vivint had outstanding $600 million aggregate principal amount of 6.750% senior secured notes due 2027 (the "Vivint 2027 Senior Secured Notes"). The Vivint 2027 Senior Secured Notes are senior secured obligations of APX and are guaranteed by APX Group Holdings, Inc., each of APX's existing and future wholly owned U.S. restricted subsidiaries (subject to customary exclusions and qualifications) and Vivint. Interest on the Vivint 2027 Senior Secured Notes is paid semi-annually in arrears on February 15 and August 15 until the maturity date of February 15, 2027.
Vivint 2029 Senior Notes
As of March 31, 2023, Vivint had outstanding $800 million aggregate principal amount of 5.750% senior notes due 2029 (the "Vivint 2029 Senior Notes"). The Vivint 2029 Senior Notes are senior unsecured obligations of APX and are guaranteed by APX Group Holdings, Inc., each of APX's existing and future wholly owned U.S. restricted subsidiaries (subject to customary exclusions and qualifications) and Vivint. Interest on the Vivint 2029 Senior Notes is paid semi-annually in arrears on January 15 and July 15 until the maturity date of July 15, 2029.
Vivint Senior Secured Credit Facilities
The Vivint senior secured credit agreement (the “Vivint Credit Agreement”) provides for (i) a term loan facility in an aggregate principal amount of $1.4 billion (the “Vivint Term Loan Facility”, and the loans thereunder, the “Vivint Term Loans”) and (ii) a revolving credit facility in an aggregate principal amount of $370 million (the “Vivint Revolving Credit Facility,” and the loans thereunder, the “Vivint Revolving Loans”).
All of APX’s obligations under the Vivint Credit Agreement are guaranteed by APX Group Holdings, Inc. and each of APX’s existing and future wholly-owned U.S. restricted subsidiaries (subject to customary exclusions and qualifications). The obligations under the Vivint Credit Agreement are secured by a first priority perfected security interest in (1) substantially all of the present and future tangible and intangible assets of APX, and the guarantors, including without limitation equipment, subscriber contracts and communication paths, intellectual property, general intangibles, investment property, material intercompany notes and proceeds of the foregoing, subject to permitted liens and other customary exceptions, (2) substantially all personal property of APX and the guarantors consisting of accounts receivable arising from the sale of inventory and other goods and services (including related contracts and contract rights, inventory, cash, deposit accounts, other bank accounts and securities accounts), inventory and intangible assets to the extent attached to the foregoing books and records of APX and the guarantors, and the proceeds thereof, subject to permitted liens and other customary exceptions, in each case held by APX and the guarantors and (3) a pledge of all of the capital stock of APX, each of its subsidiary guarantors and each restricted subsidiary of APX and its subsidiary guarantors, in each case other than excluded assets and subject to the limitations and exclusions provided in the applicable collateral documents.
The Vivint Credit Agreement contains customary covenants, which, can be used for cashamong other things, require APX to maintain a maximum first lien net leverage ratio when amounts outstanding under the Vivint Revolving Facility exceed a certain threshold and forrestrict, subject to certain exceptions, APX and its restricted subsidiaries’ ability to:
•incur or guarantee additional debt or issue disqualified stock or preferred stock;
•pay dividends and make other distributions on, or redeem or repurchase, capital stock;
•make certain investments;
•incur certain liens;
•enter into transactions with affiliates;
•merge or consolidate;

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•materially change the issuancenature of letterstheir business;
•enter into agreements that restrict the ability of credit. At September 30, 2017, thererestricted subsidiaries to make dividends or other payments to APX or grant liens on their assets;
•designate restricted subsidiaries as unrestricted subsidiaries;
•amend, prepay, redeem or purchase certain material contractually subordinated debt; and
•transfer or sell certain assets.
As of March 31, 2023, the aggregate outstanding principal amount of the Vivint Term Loans was $68$1.3 billion. As of March 31, 2023, Vivint had $11 million ofin letters of credit issued under the revolvingVivint Revolving Credit Facility and there were no Vivint Revolving Loans outstanding. As of May 4, 2023, there were $10 million in letters of credit facility and no borrowing outstanding on the revolver.
Project Financings
Agua Caliente Project Financing
On February 17, 2017, Agua Caliente Borrower 1 LLC and Agua Caliente Borrower 2 LLC, or Agua Caliente Holdco, the indirect owners of 51% of the Agua Caliente solar facility, issued $130 million of senior secured notes under the Agua Caliente Holdco Financing Agreement, or 2038 Agua Caliente Holdco Notes, that bear interest at 5.43%Vivint Revolving Credit Facility.

Note 9 — Investments Accounted for Using the Equity Method and mature on December 31, 2038. As described in Note 3, Discontinued Operations, Dispositions and Acquisitions, on March 27, 2017, NRG Yield, Inc. acquired Agua Caliente Borrower 2 LLC from NRG. The debt is joint and several with respect to Agua Caliente Borrower 1 LLC and Agua Caliente Borrower 2 LLC and is secured by the equity interests of each borrower in the Agua Caliente solar facility.


Carlsbad Project Financing
On May 26, 2017, Carlsbad Energy Holdings, LLC entered into a note payable agreement with financial institutions for the issuance of up to $407 million of senior secured notes that bear interest at a rate of 4.12%, and mature on October 31, 2038. As of September 30, 2017, all $407 million of these notes were outstanding.
Also on May 26, 2017, Carlsbad Energy Holdings, LLC entered into a credit agreement, or the Carlsbad Financing Agreement, with the issuing banks, for a $194 million construction loan, that will convert to a term loan upon completion of the project. The Carlsbad Financing Agreement also includes a letter of credit facility with an aggregate principle amount not to exceed $83 million, and a working capital loan facility with an aggregate principle amount not to exceed $4 million.
Note 9 — Variable Interest Entities, or VIEs
Entities that are not Consolidated
NRG has interests in entities that are considered VIEs under ASC 810, Consolidation, but NRG is not considered the primary beneficiary.  NRG accounts for its interests in these entities underthe 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.
GenConn Energy LLC— Through its consolidated subsidiary, NRG Yield Operating LLC, the Company owns a 50% interest in GCE Holding LLC, the owner of GenConn, which owns and operates two190 MW peaking generation facilities in Connecticut at NRG's Devon and Middletown sites. NRG's maximum exposure to loss is limited to its equity investment, which was $102 million as of September 30, 2017.
Variable Interest Entities that are Consolidated
The Company has a controlling financial interest in certain entities which havethat has been identified as VIEsa VIE under ASC 810. These arrangements are primarily810 in NRG Receivables LLC, which has entered into financing transactions related to tax equity arrangements entered into with third-parties in order to finance the cost of solar energy systems under operating leases and wind facilities eligible for certain tax creditsReceivables Facility as further described in Note 2, Summary of Significant Accounting Policies13, Long-term Debt and Finance Leases, to the Company's 2016Company’s 2022 Form 10-K. For one of the tax equity arrangements, the Company has a deficit restoration obligation equal to $100 million as of September 30, 2017, which would be required to be funded if the arrangement were to be dissolved.
The summarized financial information for the Company's consolidated VIEsVIE consisted of the following:
(In millions)March 31, 2023December 31, 2022
Accounts receivable and Other current assets$730 $2,108 
Current liabilities303 152 
Net assets$427 $1,956 

(In millions)September 30, 2017 December 31, 2016
Current assets$74
 $87
Net property, plant and equipment1,466
 1,534
Other long-term assets1,026
 954
Total assets2,566
 2,575
Current liabilities69
 59
Long-term debt420
 442
Other long-term liabilities187
 183
Total liabilities676
 684
Noncontrolling interests578
 529
Net assets less noncontrolling interests$1,312
 $1,362



Note 10 — Changes in Capital Structure
As of September 30, 2017March 31, 2023 and December 31, 2016,2022, the Company had 10,000,000 shares of preferred stock authorized and 500,000,000 shares of common stock authorized. The following table reflects the changes in NRG's preferred and common stock issued and outstanding:
PreferredCommon
Issued and OutstandingIssuedTreasuryOutstanding
Balance as of December 31, 2022— 423,897,001 (194,335,971)229,561,030 
Shares issued under LTIPs— 395,408 — 395,408 
Issuance of Series A Preferred Stock650,000 — — — 
Balance as of March 31, 2023650,000 424,292,409 (194,335,971)229,956,438 
 Issued Treasury Outstanding
Balance as of December 31, 2016417,583,825
 (102,140,814) 315,443,011
Shares issued under LTIPs634,738
 —
 634,738
Shares issued under ESPP—
 560,769
 560,769
Balance as of September 30, 2017418,218,563
 (101,580,045) 316,638,518
PreferredCommon Stock
On May 24, 2016, NRG enteredShare Repurchases
In December 2021, the Company announced that the Board of Directors authorized $1 billion for share repurchases as part of NRG’s Capital Allocation policy. The program began with $44 million of share repurchases in December 2021, and an agreement with Credit Suisse Groupincremental $601 million was repurchased in 2022. During the first quarter of 2023, the Company purchased $8 million in equivalent shares in lieu of tax withholdings on equity compensation issuances. The balance of $347 million under the current program is expected to repurchase 100%be repurchased in 2023, subject to the availability of excess cash and full visibility of the outstandingachievement of the Company's 2023 targeted credit metrics.

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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 its $344.5 million 2.822% preferred stock. On June 13, 2016, the Company completed the repurchase from Credit Suisse of 100% of the outstanding shares at a price of $226 million. The transaction resulted in a gain on redemption of $78 million, measured as the difference between the fair value of the cash consideration paid upon redemption of $226 million and the carrying value of the preferredNRG common stock at the timelesser of 95% of its market value on the offering date or 95% of the redemptionfair market value on the exercise date. On April 27, 2023, NRG stockholders approved the adoption of $304 million. This amount is reflected in net income/(loss) available to NRG common stockholders in the calculation of earnings per share.
Amended and Restated Employee Stock Purchase Plan,
On effective April 27, 2017,1, 2023, which includes a reduction in the price at which eligible employees may purchase shares of NRG common stock from 95% to 90% of the fair market value of the shares on the applicable date. NRG stockholders also approved an increase of 3,000,0004,400,000 shares available for issuance under the ESPP. As ofAn offering date occurs each April 1 and October 1. An exercise date occurs each September 30 2017, there were 3,107,050 shares of treasury stock available for issuance under the ESPP.
Amended and Restated Long-term Incentive PlanMarch 31.
On April 27, 2017, NRG stockholders approved an increase of 3,000,000 shares available for issuance under the NRG Energy, Inc. Amended and Restated Long-term Incentive Plan.
NRG Common Stock Dividends
The following table listsDuring the dividendsfirst quarter of 2023, NRG increased the annual dividend to $1.51 from $1.40 per share and expects to target an annual dividend growth rate of 7%-9% per share in subsequent years. A quarterly dividend of $0.3775 per share was paid on the Company's common stock during the ninethree months ended September 30, 2017:
 Third Quarter 2017 Second Quarter 2017
First Quarter 2017
Dividends per Common Share$0.03
 $0.03

$0.03
March 31, 2023. On October 18, 2017,April 19, 2023, NRG declared a quarterly dividend on the Company's common stock of $0.03$0.3775 per share, payable Novemberon May 15, 2017,2023 to stockholders of record as of NovemberMay 1, 2017, representing $0.12 per share on an annualized basis.2023.
The Company's common stock dividends are subject to available capital, market conditions, and compliance with associated laws, regulations and other contractual obligations.

Preferred Stock

Series A Preferred Stock
On March 9, 2023, the Company issued 650,000 shares of 10.25% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock ("Series A Preferred Stock"). The net proceeds of $636 million, net of issuance costs, were used to fund the Vivint acquisition.
The Series A Preferred Stock is not convertible into or exchangeable for any other securities or property and has limited voting rights. The Series A Preferred Stock may be redeemed, in whole or in part, on one or more occasions, at the option of the Company at any time after March 15, 2028 ("Series A First Reset Date") and in certain other circumstances prior to the Series A First Reset Date.
The annual dividend rate on each share of Series A Preferred Stock is 10.25% from the Series A Issuance Date to, but excluding the Series A First Reset Date. On and after the Series A First Reset Date, the dividend rate on each share of Series A Preferred Stock shall equal the five-year U.S. Treasury rate as of the most recent reset dividend determination date (subject to a floor of 1.00%), plus a spread of 5.92% per annum. The Series A Preferred Stock has a liquidation preference of $1,000 per share, plus accumulated but unpaid dividends. Cumulative cash dividends on the Series A Preferred Stock are payable semiannually, in arrears, on each March 15 and September 15, commencing on September 15, 2023, when, as and if declared by the board of directors.
Note 11 — Earnings/(Loss)/Income Per Share
Basic earnings/(loss)/income per common share is computed by dividing net income/(loss)/income less accumulatedcumulative dividends attributable to preferred stock dividends by the weighted average number of common shares outstanding. Shares issued and treasury shares repurchased during the yearperiod are weighted for the portion of the yearperiod that they were outstanding. Diluted earnings/(loss)/income per share is computed in a manner consistent with that of basic income/(loss)/income per share while giving effect to all potentially dilutive common shares that were outstanding during the period. Duringperiod when there is net income. The relative performance stock units, non-vested restricted stock units, and non-qualified stock options are not considered outstanding for purposes of computing basic (loss)/income per share. However, these instruments are included in the second quarterdenominator for purposes of 2016,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 combination of cash and Company’s common stock. The Company repurchased 100%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 outstanding shares of its 2.822% preferred stock. The reconciliation of Company's conversion obligation over the aggregate principal amount (which will be settled in cash), divided by the average share price for the period. For the period ended March 31, 2023, there was no dilutive effect for the Convertible Senior Notes since there was a net loss. For the period ending March 31, 2022, there was no dilutive effect for the Convertible Senior Notes since there were no potential share settlements for the period.

37
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NRG's basic and diluted earnings/(loss)/income per share is shown in the following table:
Three months ended March 31,
(In millions, except per share data)20232022
Basic and diluted (loss)/income per share:
Net (loss)/income$(1,335)$1,736 
Less: Cumulative dividends attributable to Series A Preferred Stock4 — 
Net (loss)/income available for common stockholders(1,339)1,736 
Weighted average number of common shares outstanding - basic and diluted230 242 
(Loss)/Income per weighted average common share — basic and diluted$(5.82)$7.17 
 Three months ended September 30, Nine months ended September 30,
(In millions, except per share data)2017 2016 2017 2016
Basic and diluted income/(loss) per share attributable to NRG Energy, Inc. common stockholders
Net income/(loss) attributable to NRG Energy, Inc.$171
 $402
 $(619) $213
Dividends for preferred shares—
 —
 —
 5
Gain on redemption of 2.822% redeemable perpetual preferred stock—
 —
 —
 (78)
Income/(loss) available for common stockholders$171

$402

$(619)
$286
Weighted average number of common shares outstanding - basic317
 316

317
 315
Income/(loss) per weighted average common share — basic$0.54
 $1.27
 $(1.95) $0.91
Diluted income/(loss) per share attributable to NRG Energy, Inc. common stockholders    
Weighted average number of common shares outstanding - diluted317
 316
 317
 315
Incremental shares attributable to the issuance of equity compensation (treasury stock method)5
 1
 —
 1
Total dilutive shares322
 317
 317
 316
Income/(loss) per weighted average common share — diluted$0.53
 $1.27
 $(1.95) $0.91
The following table summarizes NRG’sAs of March 31, 2023, the Company had 7 million outstanding equity instruments that are anti-dilutive and were not included in the computation of the Company’sCompany's diluted earnings/(loss)loss per share:share. As of March 31, 2022, the Company had 1 million outstanding equity instruments that are anti-dilutive and were not included in the computation of the Company's diluted income per share.

 Three months ended September 30, Nine months ended September 30,
(In millions of shares)2017 2016 2017 2016
Equity compensation plans1
 2
 6
 3
Total1
 2
 6
 3


Note 12 — Segment Reporting
The Company'sCompany’s segment structure reflects how management currently makes financial decisions and allocates resources. The Company's businesses are segregated as follows: Generation, which includes generation, international and BETM; Retail, which includes Mass customers and Business Solutions, which includes C&I customers and other distributed and reliability products; Renewables, which includes solar and wind assets, excluding those in NRG Yield; NRG Yield; and corporate activities. The financial information forCompany manages its operations based on the three and nine months ended September 30, 2016 has been recast to reflect the current segment structure.
On September 1, 2016, NRG Yield acquired the remaining 51.05% interest in CVSR Holdco LLC, which indirectly owns the CVSR solar facility, from the Company. On March 27, 2017, NRG Yield acquired from NRG a 16% interest in the Agua Caliente solar project, and NRG's interests in seven utility-scale solar projects located in Utah. On August 1, 2017, NRG Yield acquired the remaining 25% interest in NRG Wind TE Holdco from the Company. All three acquisitions were treated as a transfer of entities under common control and accordingly, all historical periods have been recast to reflect the acquisition as if they had occurred at the beginningcombined results of the financial statement period.
On June 14, 2017, as described in Note 3, Discontinued Operations, Dispositionsretail and Acquisitions, NRG deconsolidated GenOn for financial reporting purposes. The financial information for all historical periods have been recast to reflect the deconsolidation of GenOn and to present discontinued operations within the corporate segment.wholesale generation businesses with a geographical focus.
NRG’s chief operating decision maker, its chief executive officer, evaluates the performance of its segments based on operational measures including adjusted earnings before interest, taxes, depreciation and amortization, or Adjusted EBITDA, free cash flow and allocation of capital, for allocation, as well as net income/(loss).
 
Generation(a)
 
Retail (a)
 
Renewables(a)
 NRG Yield 
Corporate(a)
 Eliminations Total
Three months ended September 30, 2017(In millions)
Operating revenues(a)
$1,224
 $1,937
 $144
 $265
 $2
 $(523) $3,049
Depreciation and amortization96
 29
 51
 88
 8
 —
 272
Impairment losses1
 —
 13
 —
 —
 —
 14
Equity in (losses)/earnings of unconsolidated affiliates12
 —
 (3) 28
 —
 (10) 27
Loss on debt extinguishment, net—
 —
 —
 —
 (1) —
 (1)
Income/(loss) from continuing operations before income taxes258
 69
 (7) 49
 (161) (12) 196
Income/(loss) from continuing operations258
 69
 (4) 41
 (162) (12) 190
Loss from discontinued operations, net of tax—
 —
 —
 —
 (27) —
 (27)
Net Income/(loss)258
 69

(4) 41
 (189) (12) 163
Net Income/(loss) attributable to NRG Energy, Inc.$258
—
$69
 $9
 $35

$(220) $20
 $171
Total assets as of September 30, 2017$8,585
 $2,445
 $5,357
 $8,442
 $11,090
 $(10,449) $25,470
The acquired operations from the Vivint acquisition are reported within the Vivint segment.
(a) Operating revenues include inter-segment sales and net derivative gains and losses of:$491
 $(8) $19
 $—
 $21
 $—
 $523
Three months ended March 31, 2023
(In millions)TexasEastWest/Services/Other
Vivint(a)
CorporateEliminationsTotal
Revenue$2,034 $4,176 $1,374 $148 $— $(10)$7,722 
Depreciation and amortization75 30 24 52 9 — 190 
Gain on sale of assets— 199 — — — — 199 
Equity in earnings of unconsolidated affiliates— — 5 — — — 5 
Income/(loss) before income taxes284 (1,402)(351)(39)(163)— (1,671)
Net income/(loss)$284 $(1,402)$(304)$(39)$126 $— $(1,335)
 
Generation(a)
 
Retail(a)
 
Renewables(a)
 NRG Yield 
Corporate(a)
 Eliminations Total
Three months ended September 30, 2016(In millions)
Operating revenues(a)
$1,536
 $2,012
 $139
 $272
 $24
 $(562) $3,421
Depreciation and amortization134
 26
 48
 75
 15
 —
 298
Impairment losses9
 —
 —
 —
 —
 —
 9
Equity in earnings/(losses) of unconsolidated affiliates6
 —
 (10) 16
 5
 (1) 16
Gain on sale of assets

 —
 —
 —
 4
 —
 4
Loss on debt extinguishment, net—
 —
 —
 —
 (50) —
 (50)
Income/(loss) from continuing operations before income taxes370
 (78) (1) 63
 (202) 4
 156
Income/(loss) from continuing operations372
 (78) 2
 50
 (222) 4
 128
Income from discontinued operations, net of tax—
 —
 —
 —
 265
 —
 265
Net Income/(Loss)372
 (78) 2
 50
 43
 4
 393
Net Income/(Loss) attributable to NRG Energy, Inc.$372
 $(78) $(9) $55
 $19
 $43
 $402
(a)Vivint includes results of operations following the acquisition date of March 10, 2023
(a) Operating revenues include inter-segment sales and net derivative gains and losses of:$506
 $(2) $8
 $—
 $50
$52
$—
 $562
Three months ended March 31, 2022
(In millions)TexasEastWest/Services/OtherCorporateEliminationsTotal
Revenue$2,020 $4,715 $1,144 $— $17 $7,896 
Depreciation and amortization77 77 21 8 — 183 
(Loss) on sale of assets— — (1)(2)— (3)
Equity in (losses) of unconsolidated affiliates(1)— (14)— — (15)
Income/(loss) before income taxes771 1,538 129 (131)— 2,307 
Net income/(loss)$771 $1,538 $130 $(703)$— $1,736 


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Generation(a)
 
Retail (a)
 
Renewables(a)
 NRG Yield 
Corporate(a)
 Eliminations Total
Nine months ended September 30, 2017(In millions)
Operating revenues(a)
$3,072
 $4,875
 $364
 $767
 $13
 $(959) $8,132
Depreciation and amortization287
 87
 150
 241
 24
 —
 789
Impairment losses42
 —
 35
 —
 —
 —
 77
Equity in (losses)/earnings of unconsolidated affiliates(16) —
 (6) 63
 7
 (19) 29
Gain on sale of assets4
 —
 —
 —
 —
 —
 4
Loss on debt extinguishment, net—
 —
 (3) —
 —
 —
 (3)
Income/(loss) from continuing operations before income taxes202
 371
 (97) 100
 (430) (21) 125
Income/(loss) from continuing operations200
 380
 (84) 85
 (440) (21) 120
Loss from discontinued operations, net of tax—
 —
 —
 —
 (802) —
 (802)
Net Income/(Loss)200
 380
 (84) 85
 (1,242) (21) (682)
Net Income/(Loss) attributable to NRG Energy, Inc.$200
 $380
 $(18) $87
 $(1,306) $38
 $(619)
(a) Operating revenues include inter-segment sales and net derivative gains and losses of:$897
 $3
 $23
 $—
 $36
 $—
 $959
 
Generation(a)
 
Retail(a)
 
Renewables(a)
 
NRG Yield(a)
 
Corporate(a)
 Eliminations Total
Nine months ended September 30, 2016(In millions)
Operating revenues(a)
$3,173
 $4,918
 $336
 $789
 $54
 $(942) $8,328
Depreciation and amortization331
 83
 143
 224
 45
 —
 826
Impairment losses26
 —
 27
 —
 12
 —
 65
Equity in earnings/(losses) of unconsolidated affiliates1
 —
 (16) 34
 11
 (17) 13
Loss on sale of assets—
 —
 —
 —
 (79) —
 (79)
Impairment loss on investment(142) —
 1
 —
 (6) —
 (147)
Loss on debt extinguishment, net—
 —
 —
 —
 (119) —
 (119)
(Loss)/income from continuing operations before income taxes(51) 735
 (121) 141
 (706) (15) (17)
(Loss)/income from continuing operations(49) 734
 (107) 116
 (771) (15) (92)
Income from discontinued operations, net of tax—
 —
 —
 —
 256
 —
 256
Net (Loss)/Income(49) 734
 (107) 116
 (515) (15) 164
Net (Loss)/Income attributable to NRG Energy, Inc.$(49) $734
 $(103) $113
 $(547) $65
 $213
(a) Operating revenues include inter-segment sales and net derivative gains and losses of:$836
 $3
 $16
 $6
 $81
 $—
 $942






Note 13 — 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 otherwise noted)2017 2016 2017 2016
Income/(Loss) before income taxes$196
 $156
 $125
 $(17)
Income tax expense from continuing operations6
 28
 5
 75
Effective tax rate3.1% 17.9%
4.0%
(441.2)%
For the three months and nine months ended September 30, 2017, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the tax benefit for the change in valuation allowance and the generation of PTCs and ITCs from various wind and solar facilities, respectively, partially offset by the inclusion of consolidated partnerships and current state tax expense.
 Three months ended March 31,
(In millions, except rates)20232022
(Loss)/Income before income taxes$(1,671)$2,307 
Income tax (benefit)/expense(336)571 
Effective income tax rate20.1 %24.8 %
For the three months ended September 30, 2016, NRG's overallMarch 31, 2023, the effective tax rate was differentlower than the statutory rate of 35%21% primarily due to the tax benefit for the change in valuation allowance, partially offset by amortization of indefinite lived assets, inclusion of consolidated partnerships andcurrent state tax expense.
expense and permanent differences which when applied to year-to-date financial statement losses have an inverted effect and reduced the overall effective tax rate. For the ninethree months ended September 30, 2016, NRG's overallMarch 31, 2022, the effective tax rate was differenthigher than the statutory rate of 35%21% primarily due to the amortization of indefinite lived assets, the inclusion of consolidated partnerships, state tax expenseexpense.
The Inflation Reduction Act ("IRA") enacted on August 16, 2022, introduced new provisions including a 15% corporate book minimum tax and a 1% excise tax on net share repurchases with both taxes effective beginning in fiscal year 2023 for NRG. The Company will continue to evaluate the impact of the corporate book minimum tax when the U.S. Treasury and the expense forIRS release further guidance. Additionally, the changeIRA establishes a tax credit associated with existing nuclear facilities which begins in valuation allowance.2024 and terminates at the end of 2031. The production tax credit will fully apply when gross revenues are at or below $25 per MWh and phases out completely at $43.75 per MWh. The U.S. Treasury is in the process of defining the methods by which gross revenues may be calculated pursuant to the IRA.
Uncertain Tax Benefits
As of September 30, 2017,March 31, 2023, NRG has recordedhad a non-current tax liability of $40$43 million for uncertain tax benefits from positions taken on various federal and state income tax returns includinginclusive of accrued interest. For the ninethree months ended September 30, 2017,March 31, 2023, NRG accrued an immaterial amount of interest relating to the uncertain tax benefits. As of September 30, 2017,March 31, 2023, NRG had cumulative interest and penalties related to these uncertain tax benefits of $4 million.$2 million. The Company recognizes interest and penalties related to uncertain tax benefits in income tax expense.
NRG is subject to examination by taxing authorities for income tax returns filed in the U.S. federal jurisdiction and various state and foreign jurisdictions including operations located in Australia.Australia and Canada. The Company is notno longer subject to U.S. federal income tax examinations for years prior to 2015.2019. With few exceptions, state and localCanadian income tax examinations are no longer open for years before 2010. The Company's primary foreign operations are also no longer subject to examination by local jurisdictions for years prior to 2010.

2014.

Note 14 — Related Party Transactions
Services Agreement with GenOn
The CompanyNRG provides GenOn with various management, personnel and other services which include human resources, regulatory and public affairs, accounting, tax, legal, information systems, treasury, risk management, commercialto some of its related parties, who are accounted for as equity method investments, under operations and asset management, as set forth inmaintenance agreements. Fees for the services agreementunder these agreements include recovery of NRG's costs of operating the plants. Certain agreements also include fees for administrative service, a base monthly fee, profit margin and/or annual incentive bonus.
The following table summarizes NRG's material related party transactions with GenOn, or the Services Agreement. The initial term of the Services Agreement was through December 31, 2013, with an automatic renewal absent a request for termination. The fee charged was determined based on a fixed amount as described in the Services Agreement and was calculated based on historical GenOn expenses prior to the NRG Merger. The annualthird-party affiliates:
 Three months ended March 31,
(In millions)20232022
Revenues from Related Parties Included in Revenue  
Gladstone$1 $1 
Ivanpah(a)
34 13 
Midway-Sunset1 2 
Total$36 $16 
(a)Also includes fees under the Services Agreement were approximately $193 million andproject management has concluded that this method of charging overhead costs is reasonable. As described in Note 3, Discontinued Operations, Dispositions and Acquisitions, in connectionagreements with the Restructuring Support Agreement, NRG agreed to provide shared services to GenOn under the Services Agreement for an adjusted annualized fee of $84 million through the pendency of the Chapter 11 Cases. Beginning on June 14, 2017, NRG records operating income for the amounts earned for shared services of approximately $5 million per month. Subsequent to the GenOn Entities' emergence from bankruptcy, NRG will provide shared services for two months at no charge; after which GenOn has an additional two, one-month options to provide services at an annualized fee of $84 million. NRG charges these fees on a monthly basis, less amounts incurred directly by GenOn. For the three and nine months ended September 30, 2017, NRG recorded other income - affiliate related to these services of $14 million and $104 million, respectively. For the three and nine months ended September 30, 2016, NRG recorded other income - affiliate related to these services of $48 million and $144 million, respectively.each project company
In addition, as described in Note 3, Discontinued Operations, Dispositions and Acquisitions, under the Restructuring Support Agreement, NRG has agreed to provide GenOn with a $28 million credit against amounts owed to NRG prior to the Petition Date under the current Services Agreement. The credit was intended to reimburse GenOn for its payment of financing costs. In addition, the Restructuring Support Agreement provides that to the extent GenOn has paid for services during the bankruptcy proceedings and the aforementioned credit has not been applied in full, NRG shall, upon request by GenOn, reimburse such payments in cash up to the amount of any unused portion of the credit.
See Note 1, Basis of Presentation, for further discussion regarding the October 30, 2017 proposed changes to the Restructuring Support Agreement and Services Agreement, based on which NRG recorded a reserve of $15 million against affiliate receivable balances as of September 30, 2017.

Credit Agreement with GenOn39
NRG and GenOn are party to a secured intercompany revolving credit agreement.  The intercompany revolving credit agreement provided for a $500 million revolving credit facility, all of which was available for revolving loans and letters of credit. At September 30, 2017 and December 31, 2016, $103 million and $272 million, respectively, of letters of credit were issued and outstanding under the NRG credit agreement for GenOn. Additionally, as of September 30, 2017, there were $125 million of loans outstanding under the intercompany secured revolving credit facility. As of December 31, 2016, no loans were outstanding under this intercompany secured revolving credit facility. In addition, the intercompany secured revolving credit facility contains customary covenants and events of default. As of September 30, 2017, GenOn was in default under the secured intercompany revolving credit agreement due to the filing of the Chapter 11 Cases.
Draft 4                                                04/21/2023    
As a result of the Chapter 11 Cases, no additional revolving loans or letters of credit are available to GenOn. In addition, NRG agreed to provide GenOn with a letter of credit facility during the pendency of the Chapter 11 Cases, which could be utilized for required letters of credit in lieu of the intercompany secured revolving credit facility. The letter of credit facility provided availability of up to $330 million less amounts borrowed and letters of credit provided are required to be cash collateralized at 103% of the letter of credit amount. On July 27, 2017, this letter of credit facility was terminated as GenOn has obtained a separate letter of credit facility with a third party financial institution. Effective with completion of the reorganization, GenOn must repay NRG for all revolving loans outstanding, with such amount to be netted against the settlement payment owed from NRG to GenOn. Accordingly, the affiliate receivable is recorded net within accrued expenses and other current liabilities - affiliate on the consolidated balance sheet as of September 30, 2017. Interest continues to accrue during the pendency of the Chapter 11 Cases and borrowings remain secured obligations.



Commercial Operations Agreement
NRG Power Marketing LLC has entered into physical and financial intercompany commodity and hedging transactions with GenOn and certain of its subsidiaries. Subject to applicable collateral thresholds, these arrangements may provide for the bilateral exchange of credit support based upon market exposure and potential market movements. The terms and conditions of the agreements are generally consistent with industry practices and other third party arrangements. As of September 30, 2017, derivative assets and liabilities associated with these transactions are recorded within NRG's derivative instruments balances on the consolidated balance sheet, with related revenues and costs within operating revenues and cost of operations, respectively.

Note 15 — Commitments and Contingencies
This footnote should be read in conjunction with the complete description under Note 22, Commitments and Contingencies, to the Company's 2016 Form 10-K.
Commitments
First Lien Structure—
NRG has granted first liens to certain counterparties on a substantial portion of the Company'sproperty and assets excluding assets acquired in the EME (including Midwest Generation) acquisitions, assets heldowned by NRG Yield, Inc. and NRG's assets that have project-level financing,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 agreementspositions for forward sales of power or MWh equivalents. The Company's lien counterparties maya counterparty are out-of-the-money to NRG, the counterparty would have a claim on NRG's assets tounder the extent market prices exceed the hedged price.first lien program. As of September 30, 2017,March 31, 2023, hedges under the first lienslien program were out-of-the-money for NRG on a counterparty aggregate basis.
Lignite Contract with Texas Westmoreland Coal Co. — The Company has a contract with TWCC for reclamation activities associated with closure of the Jewett mine.  NRG is responsible for reclamation costs and has recorded an adequate ARO liability. The Railroad Commission of Texas has imposed a bond obligation of $95.5 million on TWCC for the reclamation of the mine. Pursuant to the contract with TWCC, NRG supports this obligation through surety bonds. Additionally, NRG is obligated to provide additional performance assurance if required by the Railroad Commission of Texas.
Contingencies
The Company's material legal proceedings are described below. The Company believes that it has valid defenses to these legal proceedings and intends to defend them vigorously. NRG records reservesaccruals 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 reserveaccrual for the applicable legal matters, including regulatory and environmental matters as further discussed below.in Note 16, Regulatory Matters, and Note 17, 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 reservesaccruals 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 Asbestos LiabilitiesLLC— The Company, through its subsidiary,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. During the second quarter of 2023, the IPCB will hold 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 potential asbestos liabilitiesconsumer lawsuits in various jurisdictions where they sell natural gas and electricity.
Variable Price Cases — In the cases set forth below, referred to as the Variable Price Cases, such actions involve consumers alleging that one of the Company’s ESCOs promised that consumers would pay the same or less than they would have paid if they stayed with their default utility or previous energy supplier. The underlying claims of each case are similar and the Company continues to deny the allegations and is vigorously defending these matters. These matters were known and accrued for at the time of each acquisition.
XOOM Energy
Mirkin v. XOOM Energy (E.D.N.Y. Aug. 2019) is a defendant in a putative class action lawsuit pending in New York. This case is in the summary judgment phase.
Direct Energy
There are two putative class actions pending against Direct Energy: (1) Richard Schafer v. Direct Energy (W.D.N.Y. Dec. 2019; on appeal 2nd Cir. N.Y.) - The Second Circuit sent the matter back to the trial court in December 2021. After discovery, Direct Energy filed summary judgment. Direct Energy won summary judgment and Schafer appealed. The parties are now briefing the appeal. Given the result of its acquisitionMartin Forte v. Direct Energy (N.D.N.Y. Mar. 2017), the trial court's summary

40
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judgment will be upheld and Direct Energy is expected to prevail; and (2) Andrew Gant v. Direct Energy and NRG (D.N.J. Aug. 2022) - Direct Energy and NRG filed a Motion to Dismiss on October 18, 2022.
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 EME.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 is currently analyzingdenies the scopeallegations asserted by plaintiffs and intends to vigorously defend these matters. These matters were known and accrued for at the time of potential liability as it maythe acquisition.
There are two putative class actions pending against Direct Energy: (1) Holly Newman v. Direct Energy, LP (D. Md Sept 2021) - Direct Energy filed its Motion to Dismiss asserting the ruling in the Brittany Burk v. Direct Energy (S.D. Tex. Feb 2019) preempts the Plaintiff's ability to file suit based on the same facts. The Court denied Direct Energy's motion stating the Court does not have the benefit of all of the facts that were in front of the Burk court to issue a similar ruling. On October 19, 2022, Direct Energy filed a Motion to Transfer Venue asking the Court to transfer the case to the Southern District where the Burk case was filed. On April 12, 2023, the Court granted Direct Energy’s Motion to Transfer Venue, moving to the case to the Southern District of Texas; and (2) Matthew Dickson v. Direct Energy (N.D. Ohio Jan. 2018) - The case was stayed pending the outcome of an appeal to the Sixth Circuit based on the unconstitutionality of the TCPA during the period from 2015-2020. The Sixth Circuit found the TCPA was in effect during that period and remanded the case back to the trial court. Direct Energy refiled its motions along with supplements. On March 25, 2022, the Court granted summary judgment in favor of Direct Energy and dismissed the case. Dickson appealed. The Court held oral arguments on January 17, 2023. The Company anticipates a ruling with the next six months.
Sales Practice Lawsuits
There are three ongoing litigation matters relating to claims made by Vivint competitors against Vivint alleging, among other things, that Vivint's sales representatives used deceptive sales practices: (1) CPI Security Systems, Inc. ("CPI") v. Vivint (W.D.N.C. Sept. 2020); (2) ADT LLC, et al. ("ADT") v. Vivint Smart Home, Inc. f/k/a Mosaic Acquisition Corporation, et al.(S.D.Fl. Aug. 2020); and (3) Alert 360 Opco, Inc, et al. ("Alert 360") v. Vivint Smart Home, Inc., et al (N.D.Ok. March 2023). The CPI and ADT matters were filed in 2020 and relate to, Midwest Generation.among other things, alleged deceptive sales practices by Vivint sales representatives. The CompanyCPI matter went to trial, and in February 2023, the jury issued a verdict against Vivint, in favor of CPI for $50 million of compensatory damages and an additional $140 million of punitive damages. Vivint filed its post-trial motion in March 2023 and continues to evaluate its post-trial and appeal options. While Vivint believes the CPI jury verdict is not legally or factually supported and intends to pursue post judgment remedies and file an appeal, there can be no assurance that it has established an adequate reserve for these cases.
Energy Plus Holdings—such defense efforts will be successful. Trial in the ADT matter is scheduled to commence in August 2023. On August 7, 2012, Energy Plus Holdings received a subpoena from the NYAG which generally sought information and business records related to Energy Plus Holdings' sales, marketing and business practices. Energy Plus Holdings provided documents and information to the NYAG. On June 22, 2015, the NYAG issued another subpoena seeking additional information. Energy Plus Holdings provided responsive documents to this second subpoena. On August 28, 2017, the parties entered into an Assurance of Discontinuance resolving this matter.



Midwest Generation New Source Review Litigation— In August 2009, the EPA and the Illinois Attorney General, or the Government Plaintiffs,March 1, 2023, Alert 360 filed a complaint oragainst Vivint alleging, among other things, deceptive sales practices. These matters were known and accrued for, as necessary, at the Governments’ Complaint, in the U.S. District Court for the Northern District of Illinois alleging violations of CAA PSD requirements by Midwest Generation arising from maintenance, repair or replacement projects at six Illinois coal-fired electric generating stations performed by Midwest Generation or ComEd, a prior ownertime of the stations, including alleged failuresacquisition. Vivint intends to obtain PSD construction permits and to comply with BACT requirements. The Government Plaintiffs also alleged violationsvigorously defend these matters. In management's opinion, the disposition of opacity and PM standards at the Midwest Generation plants. Finally, the Government Plaintiffs alleged that Midwest Generation violated certain operating permit requirements under Title V of the CAA allegedly arising from such claimed PSD, opacity and PM emission violations. In addition to seeking penalties of up to $37,500 per violation, per day, the complaint seeks an injunction ordering Midwest Generation to install controls sufficient to meet BACT emission rates at the units subject to the complaint and other remedies, which could go well beyond the requirements of the CPS. Several environmental groups intervened as plaintiffs in this litigation and filed a complaint, or the Intervenors’ Complaint, which alleged opacity, PM and related Title V violations. Midwest Generation filed a motion to dismiss nine of the ten PSD counts in the Governments’ Complaint, and to dismiss the tenth PSD count to the extent the Governments’ Complaint sought civil penalties for that count. The trial court granted the motion in March 2010.
In June 2010, the Government Plaintiffs and Intervenors each filed an amended complaint. The Governments’ Amended Complaint again alleged that Midwest Generation violated PSD (based upon the same projects as alleged in their original complaint, but adding allegations that the Company was liable as the “successor” to ComEd), Title V and opacity and PM standards. It named EME and ComEd as additional defendants and alleged PSD violations (again, premised on the same projects) against them. The Intervenors’ Amended Complaint named only Midwest Generation as a defendant and alleged Title V and opacity/PM violations, as well as one of the ten PSD violations alleged in the Governments’ Amended Complaint. Midwest Generation again moved to dismiss all but one of the Government Plaintiffs’ PSD claims and the related Title V claims. Midwest Generation also filed a motion to dismiss the PSD claim in the Intervenors’ Amended Complaint and the related Title V claims. In March 2011, the trial court granted Midwest Generation’s partial motion to dismiss the Government Plaintiffs’ PSD claims. The trial court denied Midwest Generation’s motion to dismiss the PSD claim asserted in the Intervenors’ Amended Complaint, but noted that the plaintiffs would be required to convince the court that the statute of limitations should be equitably tolled. The trial court didthese matters will not address other counts in the amended complaints that allege violations of opacity and PM emission limitations under the Illinois State Implementation Plan and related Title V claims. The trial court also granted the motions to dismiss the PSD claims asserted against EME and ComEd.
Following the trial court ruling, the Government Plaintiffs appealed the trial court’s dismissals of their PSD claims, including the dismissal of nine of the ten PSD claims against Midwest Generation and of the PSD claims against the other defendants. Those PSD claim dismissals were affirmed by the U.S. Court of Appeals for the Seventh Circuit in July 2013. In addition, in 2012, all but one of the environmental groups that had intervened in the case dismissed their claims without prejudice. As a result, only one environmental group remains a plaintiff intervenor in the case. The Company does not expect the resolution of this matter to have a material impact on the Company’smaterially adversely affect NRG's consolidated financial position, results of operations or cash flows.
Telephone Consumer Protection Act Purported Class Actions —Three purported class action lawsuitsContract Disputes
In September 2022, Vivint sent Alarm.com a notice asserting that it was no longer obligated to pay certain license fees under the Patent Cross License Agreement between the parties on the basis that Vivint no longer practices any claim under any valid Alarm.com patent and, therefore, no license fees are due. Alarm.com filed an arbitration demand against Vivint alleging, among other things, breach of the agreement due to continued use of the patents in question. The arbitration panel recently determined that Vivint's challenge to the validity of certain Alarm.com patents will be considered as part of the arbitration proceeding.
Winter Storm Uri Lawsuits
The Company has been named in certain property damage and wrongful death claims that have been filed against NRG Residential Solar Solutions, LLC — one in Californiaconnection with Winter Storm Uri in its capacity as a generator and two in New Jersey.  The plaintiffs generally allege misrepresentation by the call agents and violationsa REP. Most of the TCPA, claiming thatlawsuits related to Winter Storm Uri are consolidated into a single multi-district litigation matter in Harris County District Court. NRG's REPs have since been severed from the defendants engagedmulti-district litigation and will be seeking dismissal in any remaining cases. As a telemarketing campaign placing unsolicited calls to individuals onpower generator, the “Do Not Call List.”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 plaintiffs seek statutory damages of up to $1,500 per plaintiff, actual damages and equitable relief. On June 22, 2017, plaintiffs in the California case filed a motion for leave to file a second amended complaint to substitute new plaintiffs. Defendants’ filed an opposition to this motion on June 26, 2017. The court granted plaintiffs' motion to substitute new plaintiffs and on August 1, 2017, Defendants filed an answer to the second amended complaint. On August 31, 2017, the court in the California case agreed that the litigation should beis currently stayed pending the New Jersey settlement. On July 12, 2017, the parties in the New Jersey action reached an agreement in principle to resolve the class allegations which was confirmedappeal by a term sheet signed by theother parties on July 28, 2017. On September 27, 2017, plaintiffs in the New Jersey case filed their motion for preliminary approval of the class settlement.other issues. The Company intends to vigorously defend these matters.

Indemnifications and Other Contractual Arrangements


California Department of Water Resources and San Diego Gas & Electric Company v. Sunrise Power Company LLC — On January 29, 2016, CDWR and SDG&E filed a lawsuit against Sunrise Power Company, along with NRG and Chevron Power Corporation.  In June 2001, CDWR and Sunrise entered into a 10-year PPA under which Sunrise would construct and operate a generating facility and provide power to CDWR.  At the time the PPA was entered into, Sunrise had a transportation services agreement, or TSA, to purchase natural gas from Kern River through April 30, 2018.  In August 2003, CDWR entered into an agreement with Sunrise and Kern River in which CDWR accepted assignment of the TSA through the term of the PPA.  After the PPA expired, Kern River demanded that any reassignment be to a party which met certain creditworthiness standards which Sunrise did not.  As such, the plaintiffs brought this lawsuit against the defendants alleging breach of contract, breach of covenant of good faith and fair dealing and improper distributions.  Plaintiffs generally claim damages of $1.2 million per month for the remaining 70 months of the TSA. On April 20, 2016, the defendants filed demurrers in response to the plaintiffs' complaint. The demurrers were granted on June 14, 2016; however, the plaintiffs were allowed to file amended complaints on July 1, 2016. On July 27, 2016, defendants filed demurrers to the amended complaints. On November 18, 2016, the court sustained the demurrers and allowed plaintiffs another opportunity to file a second amended lawsuit which they did on January 13, 2017. On April 21, 2017, the court issued an order sustaining the demurrers without leave to amend. On July 14, 2017, CDWR filed a notice of appeal.

Braun v. NRG Yield, Inc. — On April 19, 2016, plaintiffs filed a putative class action lawsuit against NRG Yield, Inc., the current and former members of its board of directors individually, and other parties in California Superior Court in Kern County, CA.  Plaintiffs allege various violations of the Securities Act due to the defendants’ alleged failure to disclose material facts related to low wind production prior to the NRG Yield, Inc.'s June 22, 2015 Class C common stock offering.  Plaintiffs seek compensatory damages, rescission, attorney’s fees and costs. The Defendants filed demurrers and a motion challenging jurisdiction on October 18, 2016. On October 26, 2017, the court approved the parties' stipulation which provides the plaintiffs' opposition is due on December 6, 2017 and defendants' reply is due on February 8, 2018.

Ahmed v. NRG Energy, Inc. and the NRG Yield Board of Directors — On September 15, 2016, plaintiffs filed a putative class action lawsuit against NRG Energy, Inc., the directors of NRG Yield, Inc., and other parties in the Delaware Chancery Court. The complaint alleges that the defendants breached their respective fiduciary duties with regard to the recapitalization of NRG Yield, Inc. common stock in 2015. The plaintiffs generally seek economic damages, attorney’s fees and injunctive relief. The defendants filed a motion to dismiss the lawsuit on December 21, 2016. Plaintiffs filed their objection to the motion to dismiss on February 15, 2017. The defendants' reply was filed on March 24, 2017. The court heard oral argument on defendants' motion to dismiss on June 20, 2017. On September 7, 2017, the court requested additional briefing which the parties provided on September 21, 2017.

Griffoul v. NRG Residential Solar Solutions — On February 28, 2017, plaintiffs, consisting of New Jersey residential solar customers, filed a purported class action lawsuit in New Jersey state court.  Plaintiffs allege violations of the New Jersey Consumer Fraud Action and Truth-in-Consumer Contracts, Warranty and Notice Act with regard to certain provisions of their residential solar contracts.  The plaintiffs seek damages and injunctive relief as to the proper allocation of the solar renewable energy credits. On June 6, 2017, the defendants filed a motion to compel arbitration or dismiss the lawsuit. Plaintiffs filed their opposition on June 29, 2017. On July 14, 2017, the court denied NRG's motion to compel arbitration or dismiss the case. On July 25, 2017, NRG filed a motion for reconsideration of the appeal, which the court denied. On August 22, 2017, NRG filed a notice of appeal. NRG’s appellate brief was filed on October 25, 2017. Plaintiffs’ opposition is due on November 16, 2017.
Rice v. NRG — On April 14, 2017, plaintiffs filed a purported class action lawsuit in the U.S. District Court for the Western District of Pennsylvania against NRG, First Energy Corporation and Matt Canastrale Contracting, Inc.  Plaintiffs generally claim personal injury, trespass, nuisance and property damage related to the disposal of coal ash from GenOn's Elrama Power Plant and First Energy’s Mitchell and Hatfield Power Plants. Plaintiffs generally seek monetary damages, medical monitoring and remediation of their property. Plaintiffs filed an amended complaint on August 14, 2017. On October 20, 2017, NRG filed its answer and affirmative defenses.

Washington-St. Tammany and Claiborne Electric Cooperative v. LaGen — On June 28, 2017, plaintiffs Washington-St. Tammany Electric Cooperative, Inc. and Claiborne Electric Cooperative, Inc. filed a lawsuit against Louisiana Generating, L.L.C., or LaGen in the United States District Court for the Middle District of Louisiana. The plaintiffs claimclaimed breach of contract against LaGen for allegedly improperly charging the plaintiffs for costs related to the installation and maintenance of certain pollution control technology.

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Plaintiffs seeksought damages for the alleged improper charges and a declaration as to which charges arewere proper under the contract. In February 2020, the federal court dismissed this lawsuit without prejudice for lack of subject matter jurisdiction. On September 14, 2017, the court issued a scheduling order setting this case for trial on October 21, 2019. LaGen filed a motion for a more definite statement on September 18, 2017.



GenOn Chapter 11 Cases — On the Petition Date, the GenOn Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. Under the Restructuring Support Agreement to which the GenOn Entities, NRG and certain of GenOn's and GenOn Americas Generation's senior unsecured noteholders are parties, each of them has agreed to support Bankruptcy Court approval of the plan of reorganization. GenOn has a customary "fiduciary out" under the Restructuring Support Agreement. Moreover, the Bankruptcy Court may not approve the plan of reorganization. If the plan of reorganization is not approved, NRG may not be entitled to the benefits of the Settlement Agreement provided under the Restructuring Support Agreement and it will remain subject to any claims of GenOn and the noteholders, including claims relating to or arising out of any shared services and any other relationships or transactions between the companies. See Note 3, Discontinued Operations, Dispositions and Acquisitions, for additional information related to the Chapter 11 Cases.
GenOn Noteholders' Lawsuit —On December 13, 2016, certain indenture trustees for an ad hoc group of holders, or the Noteholders, of the GenOn Energy, Inc. 7.875% Senior Notes due 2017, 9.500% Notes due 2018, and 9.875% Notes dueMarch 17, 2020, and the GenOn Americas Generation, LLC 8.50% Senior Notes due 2021 and 9.125% Senior Notes due 2031, along with certain of the Noteholders, filed a complaint in the Superior Court of the State of Delaware against NRG and GenOn alleging certain claims related to the Services Agreement between NRG and GenOn. Plaintiffs generally seek return of all monies paid under the Services Agreement and any other damages that the court deems appropriate. On February 3, 2017, the court entered an order approving a Standstill Agreement whereby the parties agreed to suspend all deadlines in the case until March 1, 2017.  The Standstill Agreement terminated on March 1, 2017. On April 30, 2017, the Noteholders filed an amended complaint that asserts (i) additional fraudulent transfer claims in relation to GenOn’s sale of the Marsh Landing project to NRG Yield LLC, (ii) alleged breaches of fiduciary duty by certain current and former officers and directors of GenOn in relation to the Services Agreement and the alleged usurpation of corporate opportunities concerning the Mandalay and Canal projects and (iii) claims against NRG for allegedly aiding and abetting such claimed breaches of fiduciary duties. In addition to NRG and GenOn, the amended complaint names NRG Yield LLC and certain current and former officers and directors of GenOn as defendants. The plaintiffs among other things, generally seek return of all monies paid under the services agreement and any other damages that the court deems appropriate. Pursuant to the terms of the Restructuring Support Agreement, this matter should ultimately be resolved if the GenOn Entities' plan of reorganization is approved by the Bankruptcy Court.

Morgantown v. GenOn Mid-Atlantic — On June 8, 2017, Morgantown and Dickerson Owner Lessors filed a lawsuit against GenOn Mid-Atlantic, LLC, NRG North America LLC, GenOn Americas Generation, LLC, NRG Americas, Inc., GenOn Energy Holdings, Inc., GenOn Energy, Inc., and NRG Energy, Inc. in New York State Supreme Court. The plaintiffs allege that they were overcharged by defendants for certain services outlined in a Services Agreement and that defendants caused a Qualified Credit Support portion of a Participation Agreement, or QCS Agreement, to be violated by causing the transfer of certain money outside the allowable confines set forth in the QCS Agreement. In addition, plaintiffs claim that the transfers were unfairly executed and done so in an effort to defraud plaintiffs and hinder their ability to continue to do business. As such, plaintiffs seek, among other things, the return of certain transferred funds and service charges paid and to bar defendants from executing additional transfers on plaintiffs’ behalf. A claims estimation ruling on this matter by the Bankruptcy Court could occur as early as November 7, 2017.

BTEC v. NRG Texas Power — On July 18, 2017, BTEC New Albany LLC, or BTEC, filed a lawsuit against NRG Texas Power LLC, or NRG Texas Power, in the Harris County District Court in Texas.  On January 15, 2013, the parties entered into a Membership  Interest and Purchase Agreement, or MIPA, whereby BTEC agreed to dismantle, transport and rebuild an electric power generation facility at the former P.H. Robinson Electric Generating Station in Bacliff, Texas.  The MIPA required BTEC to meet a Guaranteed Commercial Completion Date of May 31, 2016.  But even a year later, BTEC had not satisfied all of the contractually-required acceptance criteria.  As a result and given that the MIPA expiration date passed on May 31, 2017, NRG elected to terminate the contract in June 2017. BTEC claims that NRG Texas Power breached the MIPA by improperly terminating it, and seeks a declaratory judgment as to the rights and obligations of the parties.  In addition, BTEC seeks damages, interest and attorney’s fees. On August 14, 2017, NRG Texas Power served its answer to the lawsuit. On September 7, 2017, NRG Texas Power filed a counterclaim seeking damages in excess of $48 million.



GenOn Related Contingencies

Actions Pursued by MC Asset Recovery—With Mirant Corporation's emergence from bankruptcy protection in 2006, certain actions filed by GenOn Energy Holdings and some of its subsidiaries against third parties were transferred to MC Asset Recovery, a wholly owned subsidiary of GenOn Energy Holdings.  MC Asset Recovery is governed by a manager who is independent of NRG and GenOn.  MC Asset Recovery is a disregarded entity for income tax purposes. Under the remaining action transferred to MC Asset Recovery, MC Asset Recovery seeks to recover damages from Commerzbank AG and various other banks, or the Commerzbank Defendants, for alleged fraudulent transfers that occurred prior to Mirant's bankruptcy proceedings.  In December 2010, the U.S.Nineteenth Judicial District Court for the Northern DistrictParish of Texas dismissed MC Asset Recovery's complaint againstEast Baton Rouge in Louisiana alleging substantially the Commerzbank Defendants.  In January 2011, MC Asset Recovery appealedsame matters. On February 4, 2019, NRG sold the District Court's dismissal of its complaint againstSouth Central Portfolio, including the Commerzbank Defendantsentities subject to the U.S. Court of Appeals for the Fifth Circuit, or the Fifth Circuit.  In March 2012, the Fifth Circuit reversed the District Court's dismissal and reinstated MC Asset Recovery's amended complaint against the Commerzbank Defendants.  On December 10, 2015, the District Court granted summary judgment in favor of the Commerzbank Defendants. On December 29, 2015, MC Asset Recovery filed a notice to appeal this judgment with the Fifth Circuit. On June 1, 2017, the Fifth Circuit affirmed the District Court's judgment. On June 12, 2017, MC Asset Recovery petitioned the Fifth Circuit for rehearing. The petition for rehearing was denied and a court order and judgment affirming the District Court's judgments was entered on July 17, 2017. On January 17, 2018, the bankruptcy court will hear a Motion for a Final Decree in the Mirant bankruptcy.
Natural Gas Litigation—GenOn is party to several lawsuits, certain of which are class action lawsuits, in state and federal courts in Kansas, Missouri, Nevada and Wisconsin. These lawsuits were filed in the aftermath of the California energy crisis in 2000 and 2001 and the resulting FERC investigations and relate to alleged conduct to increase natural gas prices in violation of state antitrust law and similar laws. The lawsuits seek treble or punitive damages, restitution and/or expenses. The lawsuits also name as parties a number of energy companies unaffiliated with NRG. In July 2011, the U.S. District Court for the District of Nevada, which was handling four of the five cases, granted the defendants' motion for summary judgment and dismissed all claims against GenOn in those cases. The plaintiffs appealed to the U.S. Court of Appeals for the Ninth Circuit, or the Ninth Circuit, which reversed the decision of the District Court. GenOn along with the other defendants in the lawsuit filed a petition for a writ of certiorari to the U.S. Supreme Court challenging the Ninth Circuit's decision and the U.S. Supreme Court granted the petition. On April 21, 2015, the U.S. Supreme Court affirmed the Ninth Circuit’s holding that plaintiffs’ state antitrust law claims are not field-preempted by the federal Natural Gas Act and the Supremacy Clause of the U.S. Constitution.  The U.S. Supreme Court left open whether the claims were preempted on the basis of conflict preemption. The U.S. Supreme Court directed that the case be remanded to the U.S. District Court for the District of Nevada for further proceedings. On March 7, 2016, class plaintiffs filed their motions for class certification. Defendants filed their briefs in opposition to class plaintiffs' motions for class certification on June 24, 2016. On March 30, 2017, the court denied the plaintiffs' motions for class certification. On April 13, 2017, the plaintiffs petitioned the Ninth Circuit for interlocutory review of the court’s order denying class certification. On June 13, 2017, the Ninth Circuit granted plaintiffs' petition for interlocutory review.
In May 2016 in one of the Kansas cases, the U.S. District Court for the District of Nevada granted the defendants' motion for summary judgment. Subsequently in December 2016, the plaintiffs filed a notice of appeal with the Ninth Circuit. The appeal has been fully briefed by the parties. GenOnlitigation. However, NRG has agreed to indemnify CenterPoint againstthe purchaser for certain losses relating to these lawsuits.
In September 2012, the State of Nevada Supreme Court, which was handling the remaining case, affirmed dismissal by the Eighth Judicial District Court for Clark County, Nevada of all plaintiffs' claims against GenOn. In February 2013, the plaintiffssuffered in the Nevada case filed a petition for a writ of certiorari to the U.S. Supreme Court. In June 2013, the U.S. Supreme Court denied the petition for a writ of certiorari, thereby ending one of the five lawsuits.
Potomac River Environmental Investigation—In March 2013, NRG Potomac River LLC, a subsidiary of GenOn, received notice that the District of Columbia Department of Environment (now renamed the Department of Energy and Environment, or DOEE) was investigating potential discharges to the Potomac River originating from the Potomac River Generating facility site, a site where the generation facility is no longer in operation. In connection with that investigation, DOEE served a civil subpoena on NRG Potomac River LLC requesting information related to the site and potential discharges occurring from the site.  NRG Potomac River LLC provided various responsive materials.  In January 2016, DOEE advised NRG Potomac River LLC that DOEE believed various environmental violations had occurred as a result of discharges DOEE believes occurred to the Potomac River from the Potomac River Generating facility site and as a result of associated failures to accurately or sufficiently report such discharges.  DOEE has indicated it believes that penaltiesthis litigation.

Note 16 — Regulatory Matters
Environmental regulatory matters are appropriate in light of the violations.  NRG Potomac River LLC is currently reviewing the information provided by DOEE.


discussed within Note 16 — Regulatory Matters
This footnote should be read in conjunction with the complete description under Note 23, Regulatory Matters, to the Company's 2016 Form 10-K.17, Environmental Matters.
NRG operates in a highly regulated industry and is subject to regulation by various federal, state and stateprovincial agencies. As such, NRG is affected by regulatory developments at both the federal, state and stateprovincial levels and in the regions in which NRG operates. In addition, NRG is subject to the market rules, procedures, and protocols of the various ISO and RTO markets in which NRG participates. These power markets are subject to ongoing legislative and regulatory changes that may impact NRG's wholesale and retail businesses.operations.
In addition to the regulatory proceedingsproceeding 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.
National
Zero-Emission Credits for Nuclear Plants in Illinois California Station Power— In 2016, Illinois enactedAs the result of unfavorable final and non-appealable litigation, the Company accrued a Zero Emission Credit, or ZEC, program for selected nuclear units in Illinois. In total, the program directs over $2.5 billion over ten years to nuclear plants in Illinois that would otherwise retire. Pursuant to the legislation, the Illinois Power Agency, or IPA, conducts a competitive solicitation to procure ZECs, although both the Governorliability associated with consumption of Illinois and Exelon have already announced that the ZECs will be awarded to two Exelon-owned nuclearstation power plants in Illinois.  These ZECs are out-of-market subsidies that threaten to artificially suppress market prices and interfere with the wholesale power market. On February 14, 2017, NRG, along with other companies, filed a complaint in the U.S. District Court for the Northern District of Illinois alleging that the state program is preempted by federal law and in violation of the dormant commerce clause. Another plaintiff group filed a similar complaint on the same day.Subsequently, on March 31, 2017, NRG, along with other companies, filed a motion for preliminary injunction. On April 10, 2017, Exelon, as an intervenor defendant, and State defendants filed motions to dismiss. On July 14, 2017, Defendants' motions to dismiss were granted. On July 17, 2017, NRG, along with other companies, filed a notice of appeal to the U.S. Court of Appeals for the Seventh Circuit. On July 18, 2017, the Court of Appeals issued an order setting an expedited briefing schedule for the matter. Briefing is underway.

Zero-Emission Credits for Nuclear Plants in New York — On August 1, 2016, the NYSPSC issued its Clean Energy Standard, or CES, which provided for ZECs which would provide more than $7.6 billion over 12 years in out-of-market subsidy payments to certain selected nuclear generating units in the state. These ZECs are out-of-market subsidies that threaten to artificially suppress market prices and interfere with the wholesale power market. On October 19, 2016, NRG, along with other companies, filed a complaint in the U.S. District Court for the Southern District of New York, challenging the validity of the NYSPSC action and the ZEC program. On March 29, 2017, the U.S. District Court heard oral arguments on a motion to dismiss filed by defendants. On July 25, 2017, the defendants' motions to dismiss were granted. On August 24, 2017, NRG, along with other companies, filed a notice of appeal to the U.S. Court of Appeals for the Second Circuit. On September 9, 2017, the Court of Appeals issued a briefing schedule. Briefing is underway.

Department of Energy's Proposed Grid Resiliency Pricing Rule — On September 29, 2017, the Department of Energy issued a proposed rulemaking titled the "Grid Resiliency Pricing Rule." The rulemaking directs FERC to take action to reform the ISO/RTO markets to value certain reliability and resiliency attributes of electric generation resources. On October 2, 2017, FERC issued a notice inviting comments. On October 4, 2017, FERC staff issued a series of questions requesting commenters to address. On October 23, 2017, NRG filed comments encouraging FERC to act expeditiously to modernize energy and capacity markets in a manner compatible with robust competitive markets.



Note 17 — Environmental Matters
This footnote should be read in conjunction with the complete description under Note 24, Environmental Matters, toat the Company's 2016 Form 10-K.Encina power plant facility in California after August 30, 2010. The Company has established an appropriate accrual pending potential regulatory action by San Diego Gas & Electric regarding the Company's Encina facility.

Note 17 — Environmental Matters
NRG is subject to a wide range of environmental laws in the development, construction, ownership and operation of projects.power plants. These laws generally require that governmental permits and approvals be obtained before construction and maintained during operation of power plants. NRG is also subject to laws regarding the protection of wildlife, including migratory birds, eagles and threatened and endangered species. The electric generation industry has been facing increasingly stringent requirements regarding GHGs,air quality, GHG emissions, combustion byproducts, water discharge and use, and threatened and endangered species that have been put in place in recent years. However, under the current U.S. presidential administration, some of these rules are being reconsidered and reviewed.species. In general, future laws are expected to require the addition of emissions controls or other environmental controls or to impose certainadditional restrictions on the operations of the Company's facilities, which could have a material effect on the Company's consolidated financial position, results of operations, or cash flows. Federal and stateThe Company has elected to use a $1 million disclosure threshold, as permitted, for environmental laws generallyproceedings to which the government is a party.
Air
CPP/ACE Rules — On July 8, 2019, the EPA promulgated the ACE rule, which rescinded the CPP, which had sought to broadly regulate CO2 emissions from the power sector. The ACE rule required states that have become more stringent over time, although this trend could slow or pause in the near term with respectcoal-fired EGUs to federal laws under the current U.S. presidential administration.
The EPA finalized CSAPR in 2011, which was intendeddevelop plans to replace CAIR inseek heat rate improvements from coal-fired EGUs. On January 2012, to address certain states' obligations to reduce emissions so that downwind states can achieve federal air quality standards. In December 2011,19, 2021, the D.C. Circuit vacated the ACE rule (but on February 22, 2021, at the EPA's request, stayed the implementationissuance of CSAPR and then vacated CSAPR in August 2012 but kept CAIR in place until the EPA could replace it. In April 2014,portion of the mandate that would vacate the repeal of the CPP). On June 30, 2022, the U.S. Supreme Court reversed and remanded the D.C. Circuit's decision. In October 2014, the D.C. Circuit lifted the stay of CSAPR. In response, the EPA in November 2014 amended the CSAPR compliance dates. Accordingly, CSAPR replaced CAIR on January 1, 2015. On July 28, 2015, the D.C. Circuit held that the EPA had"generation shifting" approach in the CPP exceeded its authority by requiring certain reductions that were not necessary for downwind statesthe powers granted to achieve federal standards. Although the D.C. Circuit kept the rule in place, the court ordered the EPA to revise the Phase 2 (or 2017) (i) SO2 budgets for four states including Texas and (ii) ozone-season NOx budgets for 11 states including Maryland, New Jersey, New York, Ohio, Pennsylvania and Texas. On October 26, 2016, the EPA finalized the CSAPR Update Rule, which reduces future NOx allocations and discounts the current banked allowances to account for the more stringent 2008 Ozone NAAQS and to address the D.C. Circuit's July 2015 decision. This rule has been challenged in the D.C. Circuit.by Congress. The Company believes its investment in pollution controls and cleaner technologies leave the fleet well-positioned for compliance.
In February 2012, the EPA promulgated standards (the MATS rule) to control emissions of HAPs from coal and oil-fired electric generating units. The rule established limits for mercury, non-mercury metals, certain organics and acid gases, which had to be met beginning in April 2015 (with some units getting a 1-year extension). In June 2015, the U.S. Supreme Court issued a decision in the case of Michigan v. EPA, and held that the EPA unreasonably refused to consider costs when it determined that it was "appropriate and necessary" to regulate HAPs emitted by electric generating units. The U.S. Supreme Court did not vacateaddress the MATS rule but rather remanded it to the D.C. Circuit for further proceedings. In December 2015, the D.C. Circuit remanded the MATS rule torelated issues of whether the EPA without vacatur. On April 25, 2016,may adopt only measures applied at each source. The Company anticipates that there will be additional rulemaking by the EPA released a supplemental finding that the benefits of this regulation outweigh the costs to address the U.S. Supreme Court's ruling that the EPA had not properly considered costs. This finding has been challenged in the D.C. Circuit. On April 18, 2017, the EPA asked the D.C. Circuit to postpone oral argument that had been scheduled for May 18, 2017 because the EPA is closely reviewing the supplemental finding to determine whether it should reconsider all or part of the rule. On April 27, 2017, the D.C. Circuit granted EPA's request to postpone the oral argument and hold the case in abeyance. While NRG cannot predict the final outcome of this rulemaking, NRG believes that because it has already invested in pollution controls and cleaner technologies, the fleet is well-positioned to comply with the MATS rule.
Water
In August 2014, the EPA finalized the regulation regarding the use of water for once through cooling at existing facilities to address impingement and entrainment concerns. NRG anticipates that more stringent requirements will be incorporated into some of its water discharge permits over the next several years as NPDES permitsyears.
Cross-State Air Pollution Rule ("CSAPR") — On March 15, 2023, the EPA signed and released a prepublication of a final rule that if and when published in the Federal Register would have significantly revised 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 renewed.a condition precedent to the EPA imposing its plan on Texas and Louisiana. Accordingly, the EPA may not publish this rule in the Federal Register or if it does publish the rule, it would be ineffective in Texas and Louisiana while the stay is pending. The rule would have decreased over time the ozone-season NOx allowances allocated to generators in the 23 states beginning this summer by assuming that participants in this cap-and-trade program had or would optimize existing NOx controls and later install additional NOx controls. The Company cannot predict the outcome of: (i) the legal challenges to the various state disapprovals; (ii) whether the EPA will proceeds with publication in the Federal Register; and (iii) legal challenges to the final rule if it is published in the Federal Register.

42
Draft 4                                                04/21/2023    

Water
Effluent Limitations Guidelines — In November 2015, the EPA revised the Effluent Limitations Guidelines ("ELG") for Steam Electric Generating Facilities, which would have imposed more stringent requirements (as individual permits were renewed) for wastewater streams from flue gas desulfurization, or FGD, fly ash, bottom ash and flue gas mercury control.  In April 2017, the EPA granted two petitions to reconsider the rule and also administratively stayed some of the deadlines. On September 18, 2017, the EPA promulgated a final rule that, (i) postponesamong 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 completes its next rulemaking and (ii) withdrewamended the April 2017 administrative stay. The legal challenges have been suspended whilerule. On October 13, 2020, the EPA reconsidersamended 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 likely modifies(iii) changing several deadlines. On July 26, 2021, the EPA announced that it is initiating a new rulemaking to evaluate revising the ELG rule. Accordingly,While the EPA is developing the new rule, the existing rule (as amended in 2020) will stay in place, and the EPA expects permitting authorities to continue to implement the current regulation. On March 29, 2023, the EPA proposed revisions to the ELG and is accepting comments on the proposal until May 30, 2023. In October 2021, NRG informed its regulators that the Company has largely eliminated its estimate of the environmental capital expenditures that would have been requiredintends to comply with permits incorporating the revised guidelines. The Company will revisit these estimates afterELG by ceasing combustion of coal by the rule is revised.  


end of 2028 at its domestic coal units outside of Texas, and installing appropriate controls by the end of 2025 at its two plants that have coal-fired units in Texas.
Byproducts, Wastes, Hazardous Materials and Contamination
In April 2015, the EPA finalized the rule regulating byproducts of coal combustion (e.g., ash and gypsum) as solid wastes under the RCRA. On September 13, 2017,July 30, 2018, the EPA grantedpromulgated a rule that amended the petitionash rule by extending some of the deadlines and providing more flexibility for reconsiderationcompliance. On August 21, 2018, the D.C. Circuit found, among other things, that the Utility Solid Waste Activities Group filed in May 2017. The Company has evaluatedEPA had not adequately regulated unlined ponds and legacy surface impoundments. On August 28, 2020, the impactEPA 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 new rule ondeadlines. On November 12, 2020, the Company's consolidated financial position, results of operations, or cash flows and has accrued its environmental and asset retirement obligations underEPA finalized "A Holistic Approach to Closure Part B," which further amended the rule based on current estimates as of September 30, 2017.
East Region
Burton Island Old Ash Landfill — In January 2006, NRG's Indian River Power LLC was notified that it may be a potentially responsible partyApril 2015 Rule to, among other things, provide procedures for requesting approval to operate existing impoundments with respect to Burton Island Old Ash Landfill, a historic captive landfill located at the Indian River facility. On October 1, 2007,an alternative liner. NRG signed an agreement with DNREC to investigate the site through the Voluntary Clean-up Program, or the VCP. On February 4, 2008, DNREC issued findings that noanticipates further action was required in relation to surface water and that a previously planned shoreline stabilization project would satisfactorily address shoreline erosion. The landfill itself required a Remedial Investigation and Feasibility Study to determine the type and scope of any additional required work. DNREC approved the Feasibility Study in December 2012. In January 2013, DNREC proposed a remediation plan based on the Feasibility Study. The remediation plan was approved in October 2013. In December 2015, DNREC approved the Company's remediation design and the Company's Long Term Stewardship Plan. In the second quarter of 2017, the Company completed the remediation requirements in the remediation plan. The cost of completing the work required by the remediation plan was within amounts budgeted in early 2016. The estimated cost to comply with the Long-Term Stewardship Plan was addedrulemaking related to the liability in December 2016.
In addition to the VCP, on May 29, 2008, DNREC requested that NRG's Indian River Power LLC participate in the developmentFederal Permit Program and performance of a Natural Resource Damage Assessment at the Burton Island Old Ash Landfill. NRG is working with DNREC and other trustees to close out the assessment process.


Note 18 — Condensed Consolidating Financial Information
As of September 30, 2017, the Company had outstanding $5.4 billion of Senior Notes due from 2018 to 2027, as shown in Note 8, Debt and Capital Leases. These Senior Notes are guaranteed by certain of NRG's current and future 100% owned domestic subsidiaries, or guarantor subsidiaries. These guarantees are both joint and several. The non-guarantor subsidiaries include all of NRG's foreign subsidiaries and certain domestic subsidiaries, and NRG Yield, Inc. and its subsidiaries.
Unless otherwise noted below, each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of September 30, 2017:legacy surface impoundments.

43
Ace Energy, Inc.New Genco GP, LLCNRG Norwalk Harbor Operations Inc.
Allied Home Warranty GP LLCNorwalk Power LLCNRG Operating Services, Inc.
Allied Warranty LLCNRG Advisory Services LLCNRG Oswego Harbor Power Operations Inc.
Arthur Kill Power LLCNRG Affiliate Services Inc.NRG PacGen Inc.
Astoria Gas Turbine Power LLCNRG Arthur Kill Operations Inc.NRG Portable Power LLC
Bayou Cove Peaking Power, LLCNRG Astoria Gas Turbine Operations Inc.NRG Power Marketing LLC
BidURenergy, Inc.NRG Bayou Cove LLCNRG Reliability Solutions LLC
Cabrillo Power I LLCNRG Business Services LLCNRG Renter's Protection LLC
Cabrillo Power II LLCNRG Cabrillo Power Operations Inc.NRG Retail LLC
Carbon Management Solutions LLCNRG California Peaker Operations LLCNRG Retail Northeast LLC
Cirro Group, Inc.NRG Cedar Bayou Development Company, LLCNRG Rockford Acquisition LLC
Cirro Energy Services, Inc.NRG Connected Home LLCNRG Saguaro Operations Inc.
Conemaugh Power LLCNRG Connecticut Affiliate Services Inc.NRG Security LLC
Connecticut Jet Power LLCNRG Construction LLCNRG Services Corporation
Cottonwood Development LLCNRG Curtailment Solutions, IncNRG SimplySmart Solutions LLC
Cottonwood Energy Company LPNRG Development Company Inc.NRG South Central Affiliate Services Inc.
Cottonwood Generating Partners I LLCNRG Devon Operations Inc.NRG South Central Generating LLC
Cottonwood Generating Partners II LLCNRG Dispatch Services LLCNRG South Central Operations Inc.
Cottonwood Generating Partners III LLCNRG Distributed Energy Resources Holdings LLCNRG South Texas LP
Cottonwood Technology Partners LPNRG Distributed Generation PR LLCNRG SPV #1 LLC
Devon Power��LLCNRG Dunkirk Operations Inc.NRG Texas C&I Supply LLC
Dunkirk Power LLCNRG El Segundo Operations Inc.NRG Texas Gregory LLC
Eastern Sierra Energy Company LLCNRG Energy Efficiency-L LLCNRG Texas Holding Inc.
El Segundo Power, LLCNRG Energy Labor Services LLCNRG Texas LLC
El Segundo Power II LLCNRG ECOKAP Holdings LLCNRG Texas Power LLC
Energy Alternatives Wholesale, LLCNRG Energy Services Group LLCNRG Warranty Services LLC
Energy Choice Solutions LLCNRG Energy Services International Inc.NRG West Coast LLC
Energy Plus Holdings LLCNRG Energy Services LLCNRG Western Affiliate Services Inc.
Energy Plus Natural Gas LLCNRG Generation Holdings, Inc.O'Brien Cogeneration, Inc. II
Energy Protection Insurance CompanyNRG Greenco LLCONSITE Energy, Inc.
Everything Energy LLCNRG Home & Business Solutions LLCOswego Harbor Power LLC
Forward Home Security, LLCNRG Home Services LLCReliant Energy Northeast LLC
GCP Funding Company, LLCNRG Home Solutions LLCReliant Energy Power Supply, LLC
Green Mountain Energy CompanyNRG Home Solutions Product LLCReliant Energy Retail Holdings, LLC
Gregory Partners, LLCNRG Homer City Services LLCReliant Energy Retail Services, LLC
Gregory Power Partners LLCNRG Huntley Operations Inc.RERH Holdings, LLC
Huntley Power LLCNRG HQ DG LLCSaguaro Power LLC
Independence Energy Alliance LLCNRG Identity Protect LLCSomerset Operations Inc.
Independence Energy Group LLCNRG Ilion Limited PartnershipSomerset Power LLC
Independence Energy Natural Gas LLCNRG Ilion LP LLCTexas Genco GP, LLC
Indian River Operations Inc.NRG International LLCTexas Genco Holdings, Inc.
Indian River Power LLCNRG Maintenance Services LLCTexas Genco LP, LLC
Keystone Power LLCNRG Mextrans Inc.Texas Genco Services, LP
Langford Wind Power, LLCNRG MidAtlantic Affiliate Services Inc.US Retailers LLC
Louisiana Generating LLCNRG Middletown Operations Inc.Vienna Operations Inc.
Meriden Gas Turbines LLCNRG Montville Operations Inc.Vienna Power LLC
Middletown Power LLCNRG New Roads Holdings LLCWCP (Generation) Holdings LLC
Montville Power LLCNRG North Central Operations Inc.West Coast Power LLC
NEO CorporationNRG Northeast Affiliate Services Inc.
Draft 4                                                04/21/2023    



NRG conducts much of its business through and derives much of its income from its subsidiaries. Therefore, the Company's ability to make required payments with respect to its indebtedness and other obligations depends on the financial results and condition of its subsidiaries and NRG's ability to receive funds from its subsidiaries. There are no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to NRG. However, there may be restrictions for certain non-guarantor subsidiaries.
The following condensed consolidating financial information presents the financial information of NRG Energy, Inc., the guarantor subsidiaries and the non-guarantor subsidiaries in accordance with Rule 3-10 under the SEC Regulation S-X. The financial information may not necessarily be indicative of results of operations or financial position had the guarantor subsidiaries or non-guarantor subsidiaries operated as independent entities.
In this presentation, NRG Energy, Inc. consists of parent company operations. Guarantor subsidiaries and non-guarantor subsidiaries of NRG are reported on an equity basis. For companies acquired, the fair values of the assets and liabilities acquired have been presented on a push-down accounting basis.


NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the three months ended September 30, 2017
(Unaudited)
 Guarantor Subsidiaries Non-Guarantor Subsidiaries 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 Consolidated
 (In millions)
Operating Revenues         
Total operating revenues$2,160
 $1,021
 $—
 $(132) $3,049
Operating Costs and Expenses         
Cost of operations1,588
 682
 15
 (129) 2,156
Depreciation and amortization104
 160
 8
 —
 272
Impairment losses—
 14
 —
 —
 14
Selling, general and administrative97
 29
 88
 (1) 213
Reorganization—
 —
 18
 —
 18
Development activity expenses—
 9
 5
 
 14
Total operating costs and expenses1,789
 894
 134
 (130) 2,687
     Other income - affiliate—
 —
 14
 —
 14
Operating Income/(Loss)371
 127
 (120) (2) 376
Other Income/(Expense)         
Equity in losses of consolidated subsidiaries(41) (9) (134) 184
 —
Equity in (losses)/earnings of unconsolidated affiliates—
 (606) 666
 (33) 27
Other income7
 3
 5
 —
 15
Loss on debt extinguishment—
 (1) —
 —
 (1)
Interest expense(4) (103) (114) —
 (221)
Total other (expense)/income(38) (716) 423
 151
 (180)
Income/(Loss) from Continuing Operations Before Income Taxes333
 (589) 303
 149
 196
Income tax expense/(benefit)113
 (209) 102
 —
 6
Income/(Loss) from Continuing Operations220
 (380) 201
 149
 190
Loss from Discontinued Operations, net of income tax—
 (27) —
 —
 (27)
Net Income/(Loss)220
 (407) 201
 149
 163
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interests—
 (3) 30
 (35) (8)
Net Income/(Loss) Attributable to
NRG Energy, Inc.
$220
 $(404) $171
 $184
 $171
(a)All significant intercompany transactions have been eliminated in consolidation.











NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the nine months ended September 30, 2017
(Unaudited)
 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc.
(Note Issuer)		 
Eliminations(a)
 Consolidated
 (In millions)
Operating Revenues         
Total operating revenues$5,517

$2,872

$—

$(257)
$8,132
Operating Costs and Expenses         
Cost of operations4,156
 1,904
 46
 (254) 5,852
Depreciation and amortization307
 458
 24
 —
 789
Impairment losses42
 35
 —
 —
 77
Selling, general and administrative281
 115
 304
 (3) 697
Reorganization—
 —
 18
 —
 18
Development activity expenses—
 34
 15
 —
 49
Total operating costs and expenses4,786
 2,546
 407
 (257) 7,482
     Other income - affiliate—
 —
 104
 —
 104
Gain on sale of assets4
 —
 —
 —
 4
Operating Income/(Loss)735
 326
 (303) —
 758
Other Income/(Expense)         
Equity in losses of consolidated subsidiaries(61) (66) (182) 309
 —
Equity in earnings/(losses) of unconsolidated affiliates—
 101
 (3) (69) 29
Other income8
 15
 10
 —
 33
Loss on debt extinguishment—
 (3) —
 —
 (3)
Interest expense(11) (328) (353) —
 (692)
Total other expense(64) (281) (528) 240
 (633)
Income/(Loss) from Continuing Operations Before Income Taxes671
 45
 (831) 240
 125
Income tax expense/(benefit)244
 28
 (267) —
 5
Income/(Loss) from Continuing Operations427
 17
 (564) 240
 120
Loss from Discontinued Operations, net of income tax—
 (802) —
 —
 (802)
Net Income/(Loss)427
 (785) (564) 240
 (682)
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interests—
 (49) 55
 (69) (63)
Net Income/(Loss) Attributable to
NRG Energy, Inc.		$427
 $(736) $(619) $309
 $(619)
(a)All significant intercompany transactions have been eliminated in consolidation.



NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)
For the three months ended September 30, 2017
(Unaudited)
 Guarantor Subsidiaries Non-Guarantor Subsidiaries 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 Consolidated
 (In millions)
Net Income/(Loss)$220
 $(407) $201
 $149
 $163
Other Comprehensive Income/(Loss), net of tax         
Unrealized gain on derivatives, net—
 7
 7
 (7) 7
Foreign currency translation adjustments, net2
 2
 2
 (4) 2
Available-for-sale securities, net—
 —
 1
 —
 1
Defined benefit plans, net—
 —
 (2) 1
 (1)
Other comprehensive income2
 9
 8
 (10) 9
Comprehensive Income/(Loss)222
 (398) 209
 139
 172
Less: Comprehensive income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interest—
 —
 30
 (35) (5)
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.$222
 $(398) $179
 $174
 $177
(a)All significant intercompany transactions have been eliminated in consolidation.























NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)
For the nine months ended September 30, 2017
(Unaudited)
 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc.
(Note Issuer)		 
Eliminations(a)
 Consolidated
 (In millions)
Net Income/(Loss)$427
 $(785) $(564) $240
 $(682)
Other Comprehensive Income/(Loss), net of tax         
Unrealized gain on derivatives, net—
 6
 7
 (7) 6
Foreign currency translation adjustments, net7
 7
 9
 (13) 10
Available-for-sale securities, net—
 —
 2
 —
 2
Defined benefit plans, net—
 29
 25
 (28) 26
Other comprehensive income7
 42
 43
 (48) 44
Comprehensive Income/(Loss)434
 (743) (521) 192
 (638)
Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest—
 (47) 55
 (69) (61)
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.$434
 $(696) $(576) $261
 $(577)
(a)All significant intercompany transactions have been eliminated in consolidation.






NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
September 30, 2017
(Unaudited)
 Guarantor Subsidiaries Non-Guarantor Subsidiaries 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 Consolidated
ASSETS(In millions)
Current Assets         
Cash and cash equivalents$(20) $350
 $893
 $—
 $1,223
Funds deposited by counterparties29
 2
 —
 —
 31
Restricted cash14
 523
 —
 —
 537
Accounts receivable - trade, net876
 395
 3
 —
 1,274
Accounts receivable - affiliate222
 191
 (22) (337) 54
Inventory406
 224
 —
 —
 630
Derivative instruments438
 106
 5
 (74) 475
Cash collateral posted in support of energy risk management activities190
 13
 —
 —
 203
Prepayments and other current assets108
 147
 45
 —
 300
Current assets - held for sale—
 33
 —
 —
 33
Total current assets2,263
 1,984
 924

(411) 4,760
Net property, plant and equipment3,980
 11,142
 236
 (26) 15,332
Other Assets         
Investment in subsidiaries1,098
 1,004
 9,409
 (11,511) —
Equity investments in affiliates—
 1,135
 3
 —
 1,138
Notes receivable, less current portion—
 5
 —
 —
 5
Goodwill359
 303
 —
 —
 662
Intangible assets, net520
 1,321
 —
 (3) 1,838
Nuclear decommissioning trust fund670
 —
 —
 —
 670
Derivative instruments187
 38
 27
 (46) 206
Deferred income tax(5) (148) 358
 —
 205
Non-current assets held-for-sale—
 10
 —
 —
 10
Other non-current assets63
 520
 61
 —
 644
Total other assets2,892
 4,188
 9,858
 (11,560) 5,378
Total Assets$9,135
 $17,314
 $11,018
 $(11,997) $25,470
LIABILITIES AND STOCKHOLDERS’ EQUITY         
Current Liabilities         
Current portion of long-term debt and capital leases$—
 $623
 $624
 $—
 $1,247
Accounts payable599
 285
 31
 —
 915
Accounts payable — affiliate528
 (340) 146
 (338) (4)
Derivative instruments418
 178
 —
 (74) 522
Cash collateral received in support of energy risk management activities29
 2
 —
 —
 31
Accrued expenses and other current liabilities301
 57
 472
 —
 830
Accrued expenses and other current liabilities-affiliate—
 164
 —
 —
 164
Total current liabilities1,875
 969
 1,273
 (412) 3,705
Other Liabilities         
Long-term debt and capital leases244
 8,644
 6,770
 —
 15,658
Nuclear decommissioning reserve265
 —
 —
 —
 265
Nuclear decommissioning trust liability397
 —
 —
 —
 397
Deferred income taxes428
 —
 (407) —
 21
Derivative instruments194
 159
 —
 (46) 307
Out-of-market contracts, net69
 144
 —
 —
 213
Non-current liabilities held-for-sale—
 13
 —
 —
 13
Other non-current liabilities377
 315
 424
 —
 1,116
Total non-current liabilities1,974
 9,275
 6,787
 (46) 17,990
Total liabilities3,849
 10,244
 8,060
 (458) 21,695
Redeemable noncontrolling interest in subsidiaries—
 85
 —
 —
 85
Stockholders’ Equity5,286
 6,985
 2,958
 (11,539) 3,690
Total Liabilities and Stockholders’ Equity$9,135
 $17,314
 $11,018
 $(11,997) $25,470
(a)All significant intercompany transactions have been eliminated in consolidation.


NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the nine months ended September 30, 2017 (Unaudited)
 Guarantor Subsidiaries Non-Guarantor Subsidiaries 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 Consolidated
 (In millions)
Cash Flows from Operating Activities         
Net income/(loss)$427
 $(785) $(564) $240
 $(682)
Loss from discontinued operations—
 (802) —
 —
 (802)
Net income/(loss) from continuing operations427
 17
 (564) 240
 120
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:        
Distributions from unconsolidated affiliates—
 60
 —
 (7) 53
Equity in losses/(earnings) of unconsolidated affiliates—
 (101) 3
 69
 (29)
Depreciation and amortization307
 458
 24
 —
 789
Provision for bad debts40
 2
 15
 —
 57
Amortization of nuclear fuel37
 —
 —
 —
 37
Amortization of financing costs and debt discount/premiums—
 31
 13
 —
 44
Adjustment for debt extinguishment—
 3
 —
 —
 3
Amortization of intangibles and out-of-market contracts20
 59
 —
 —
 79
Amortization of unearned equity compensation—
 —
 27
 —
 27
Impairment losses42
 35
 —
 —
 77
Changes in deferred income taxes and liability for uncertain tax benefits244
 28
 (246) —
 26
Changes in nuclear decommissioning trust liability20
 —
 —

—
 20
Changes in derivative instruments(11) 32
 12
 (8) 25
Changes in collateral deposits supporting energy risk management activities(126) 23
 —
 —
 (103)
Proceeds from sale of emission allowances21
 —
 —
 —
 21
Gain on sale of assets(22) —
 —
 —
 (22)
Cash (used)/provided by changes in other working capital(958) (523) 1,395
 (294) (380)
Cash provided by continuing operations41
 124
 679
 —
 844
Cash used by discontinued operations—
 (38) —
 —
 (38)
Net Cash Provided by Operating Activities41
 86
 679
 —
 806
Cash Flows from Investing Activities         
Dividends from NRG Yield, Inc.—
 —
 69
 (69) —
Acquisition of Drop Down Assets, net of cash acquired—
 (176) —
 176
 —
Intercompany dividends—
 —
 129
 (129) —
Acquisition of business, net of cash acquired—
 (36) —
 —
 (36)
Capital expenditures(135) (606) (19) —
 (760)
Decrease in notes receivable—
 11
 —
 —
 11
Purchases of emission allowances(47) —
 —
 —
 (47)
Proceeds from sale of emission allowances105
 —
 —
 —
 105
Investments in nuclear decommissioning trust fund securities(402) —
 —
 —
 (402)
Proceeds from sales of nuclear decommissioning trust fund securities382
 —
 —
 —
 382
Proceeds from renewable energy grants and state rebates8
 —

—
 —
 8
Proceeds from sale of assets, net of cash disposed of36
 —
 —
 —
 36
Investments in unconsolidated affiliates—
 (31) —
 —
 (31)
Other22
 —
 —
 —
 22
Cash (used)/provided by continuing operations(31) (838) 179
 (22) (712)
Cash used by discontinued operations—
 (53) —
 —
 (53)
Net Cash (Used)/Provided by Investing Activities(31) (891) 179
 (22) (765)
Cash Flows from Financing Activities

  
  
    
Dividends from NRG Yield, Inc.—
 (69) —
 69
 —
Payments from/(for) intercompany loans9
 417
 (426) —
 —
Acquisition of Drop Down Assets, net of cash acquired—
 —
 176
 (176) —
Intercompany dividends—
 (129) —
 129
 —
Payment of dividends to common and preferred stockholders—
 —
 (28) —
 (28)
Net receipts from settlement of acquired derivatives that include financing elements—
 2
 —
 —
 2
Proceeds from issuance of long-term debt—
 920
 214
 —
 1,134
Payments for short and long-term debt—
 (493) (219) —
 (712)
Receivable from affiliate—
 (125) —
 —
 (125)
Contributions from, net of distributions to, noncontrolling interest in subsidiaries—
 65
 —
 —
 65
Payment of debt issuance costs—
 (38) (5) —
 (43)
Other - contingent consideration—
 (10) —
 —
 (10)
Cash provided/(used) by continuing operations9
 540
 (288) 22
 283
Cash used by discontinued operations—
 (224) —
 —
 (224)
Net Cash Provided/(Used) by Financing Activities9
 316
 (288) 22
 59
Change in cash from discontinued operations—
 (315) —
 —
 (315)
Effect of exchange rate changes on cash and cash equivalents—
 (10) —
 —
 (10)
Net Increase/(Decrease) in Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties19
 (184) 570
 —
 405
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at Beginning of Period4
 1,059
 323
 —
 1,386
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at End of Period$23

$875

$893

$—
 $1,791
(a) All significant intercompany transactions have been eliminated in consolidation.


NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the three months ended September 30, 2016
(Unaudited)
 Guarantor Subsidiaries Non-Guarantor Subsidiaries 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 Consolidated
 (In millions)
Operating Revenues         
Total operating revenues$2,424
 $1,090
 $—
 $(93) $3,421
Operating Costs and Expenses         
Cost of operations1,719
 804
 10
 (93) 2,440
Depreciation and amortization147
 144
 7
 —
 298
Impairment losses8
 1
 —
 —
 9
Selling, general and administrative115
 50
 112
 —
 277
Development activity expenses—
 10
 11
 —
 21
Total operating costs and expenses1,989
 1,009
 140
 (93) 3,045
     Other income - affiliate—
 —
 48
 —
 48
Gain on sale of assets—
 —
 4
 —
 4
Operating Income/(Loss)435
 81
 (88) —
 428
Other Income/(Expense)     
    
Equity in (losses)/earnings of consolidated subsidiaries(114) (10) 562
 (438) —
Equity in earnings/(losses) of unconsolidated affiliates2
 75
 (12) (49) 16
Loss on investment—
 (8) —
 —
 (8)
Other income/(loss), net1
 6
 ��
 —
 7
Loss on debt extinguishment—
 —
 (50) —
 (50)
Interest expense(4) (104) (129) —
 (237)
Total other expense(115) (41) 371
 (487) (272)
Income from Continuing Operations Before Income Taxes320
 40
 283
 (487) 156
Income tax expense/(benefit)134
 45
 (151) —
 28
Income from Continuing Operations186
 (5) 434
 (487) 128
Income from Discontinued Operations, net of income tax—
 263
 2
 —
 265
Net Income186
 258
 436
 (487) 393
Less: Net income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interest—
 6
 34
 (49) (9)
Net Income Attributable to NRG Energy, Inc.$186
 $252
 $402
 $(438) $402
(a)All significant intercompany transactions have been eliminated in consolidation.


NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the nine months ended September 30, 2016
(Unaudited)
 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc.
(Note Issuer)		 
Eliminations(a)
 Consolidated
 (In millions)
Operating Revenues         
Total operating revenues$6,079
 $2,400
 $—
 $(151) $8,328
Operating Costs and Expenses         
Cost of operations4,278
 1,558
 29
 (154) 5,711
Depreciation and amortization372
 435
 19
 —
 826
Impairment losses8
 57
 —
 —
 65
Selling, general and administrative306
 144
 351
 —
 801
Development activity expenses—
 42
 23
 —
 65
Total operating costs and expenses4,964
 2,236
 422
 (154) 7,468
     Other income - affiliate—
 —
 144
 —
 144
Loss on sale of assets—
 —
 (79) —
 (79)
Operating Income/(Loss)1,115
 164
 (357) 3
 925
Other Income/(Expense)     
    
Equity in (losses)/earnings of consolidated subsidiaries(195) (80) 904
 (629) —
Equity in earnings/(losses) of unconsolidated affiliates5
 114
 (2) (104) 13
Impairment loss on investment—
 (147) —
 —
 (147)
Other income, net3
 25
 2
 (1) 29
Loss on debt extinguishment—
 (4) (115) —
 (119)
Interest expense(11) (312) (395) 

 (718)
Total other (expense)/income(198) (404) 394
 (734) (942)
Income/(Loss) Before Income Taxes917
 (240) 37
 (731) (17)
Income tax expense/(benefit)362
 (49) (238) —
 75
Income/(Loss) from Continuing Operations555
 (191) 275
 (731) (92)
Income from Discontinued Operations, net of income tax—
 248
 8
 —
 256
Net Income555
 57
 283
 (731) 164
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest—
 (17) 70
 (102) (49)
Net Income Attributable to NRG Energy, Inc.$555
 $74
 $213
 $(629) $213
(a)All significant intercompany transactions have been eliminated in consolidation.



NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)
For the three months ended September 30, 2016
(Unaudited)
 Guarantor Subsidiaries Non-Guarantor Subsidiaries 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 Consolidated
 (In millions)
Net Income$186
 $258
 $436
 $(487) $393
Other Comprehensive Income/(Loss), net of tax         
Unrealized income on derivatives, net—
 40
 26
 (39) 27
Foreign currency translation adjustments, net2
 2
 4
 (5) 3
Defined benefit plans, net54
 —
 (43) 20
 31
Other comprehensive loss56
 42
 (13) (24) 61
Comprehensive Income242
 300
 423
 (511) 454
Less: Comprehensive income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interest—
 13
 34
 (49) (2)
Comprehensive Income Attributable to NRG Energy, Inc.$242
 $287
 $389
 $(462) $456
(a)All significant intercompany transactions have been eliminated in consolidation.









NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)
For the nine months ended September 30, 2016
(Unaudited)
 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc.
(Note Issuer)		 
Eliminations(a)
 Consolidated
 (In millions)
Net Income$555
 $57
 $283
 $(731) $164
Other Comprehensive Income/(Loss), net of tax        
Unrealized (loss)/gain on derivatives, net—
 (15) 46
 (39) (8)
Foreign currency translation adjustments, net4
 4
 6
 (8) 6
Available-for-sale securities, net—
 —
 1
 —
 1
Defined benefit plans, net55
 —
 (43) 20
 32
Other comprehensive income/(loss)59
 (11) 10
 (27) 31
Comprehensive Income614
 46
 293
 (758) 195
Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest—
 (38) 70
 (102) (70)
Comprehensive Income Attributable to NRG Energy, Inc.614
 84
 223
 (656) 265
Dividends for preferred shares—
 —
 5
 —
 5
Gain on redemption of preferred shares—
 —
 (78) —
 (78)
Comprehensive Income Available for Common Stockholders$614
 $84
 $296
 $(656) $338
(a)All significant intercompany transactions have been eliminated in consolidation.

















NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2016
 Guarantor Subsidiaries Non-Guarantor Subsidiaries 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations (a)
 Consolidated
ASSETS(In millions)
Current Assets         
Cash and cash equivalents$(9) $624
 $323
 $—
 $938
Funds deposited by counterparties2
 —
 —
 —
 2
Restricted cash11
 435
 —
 —
 446
Accounts receivable - trade, net734
 321
 3
 —
 1,058
Accounts receivable - affiliate307
 (254) 200
 (139) 114
Inventory482
 239
 —
 —
 721
Derivative instruments962
 196
 1
 (92) 1,067
Cash collateral posted in support of energy risk management activities116
 34
 —
 —
 150
Current assets held-for-sale—
 9
 —
 —
 9
Prepayments and other current assets76
 152
 62
 —
 290
Current assets - discontinued operations—
 1,919
 —
 —
 1,919
Total current assets2,681
 3,675
 589
 (231) 6,714
Net Property, Plant and Equipment4,219
 10,926
 251
 (27) 15,369
Other Assets         
Investment in subsidiaries1,090
 1,054
 10,128
 (12,272) —
Equity investments in affiliates(13) 1,128
 5
 —
 1,120
Notes receivable, less current portion—
 16
 —
 —
 16
Goodwill359
 303
 —
 —
 662
Intangible assets, net592
 1,384
 —
 (3) 1,973
Nuclear decommissioning trust fund610
 —
 —
 —
 610
Derivative instruments144
 44
 36
 (43) 181
Deferred income taxes3
 —
 222
 —
 225
Non-current assets held for sale—
 10
 —
 —
 10
Other non-current assets67
 446
 328
 —
 841
Non-current assets - discontinued operations—
 2,961
 —
 —
 2,961
Total other assets2,852
 7,346
 10,719
 (12,318) 8,599
Total Assets$9,752
 $21,947
 $11,559
 $(12,576) $30,682
LIABILITIES AND STOCKHOLDERS’ EQUITY         
Current Liabilities         
Current portion of long-term debt and capital leases$—
 $498
 $18
 $—
 $516
Accounts payable501
 247
 34
 —
 782
Accounts payable — affiliate744
 (452) (122) (139) 31
Derivative instruments947
 237
 —
 (92) 1,092
Cash collateral received in support of energy risk management activities81
 —
 —
 —
 81
Accrued expenses and other current liabilities316
 209
 465
 —
 990
Current liabilities - discontinued operations—
 1,210
 —
 —
 1,210
Total current liabilities2,589
 1,949
 395
 (231) 4,702
Other Liabilities         
Long-term debt and capital leases244
 8,252
 7,461
 —
 15,957
Nuclear decommissioning reserve287
 —
 —
 —
 287
Nuclear decommissioning trust liability339
 —
 —
 —
 339
Deferred income taxes186
 125
 (291) —
 20
Derivative instruments157
 170
 —
 (43) 284
Out-of-market contracts, net80
 150
 —
 —
 230
Non-current liabilities held-for-sale—
 11
 —
 —
 11
Other non-current liabilities396
 456
 324
 —
 1,176
Non-current liabilities - discontinued operations—
 3,184
 —
 —
 3,184
Total non-current liabilities1,689
 12,348
 7,494
 (43) 21,488
Total Liabilities4,278
 14,297
 7,889
 (274) 26,190
Redeemable noncontrolling interest in subsidiaries—
 46
 —
 —
 46
Stockholders’ Equity5,474
 7,604
 3,670
 (12,302) 4,446
Total Liabilities and Stockholders’ Equity$9,752
 $21,947
 $11,559

$(12,576) $30,682
(a)All significant intercompany transactions have been eliminated in consolidation.


NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the nine months ended September 30, 2016 (Unaudited)
 Guarantor Subsidiaries Non-Guarantor Subsidiaries 
NRG Energy, Inc.
(Note Issuer)
 
Eliminations(a)
 Consolidated
 (In millions)
Cash Flows from Operating Activities         
Net Income$555
 $57
 $283
 $(731) $164
Less: Income from discontinued operations—
 248
 8
 —
 256
Net income/(loss) from continuing operations555
 (191) 275
 (731) (92)
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:         
Distributions from unconsolidated affiliates—
 65
 —
 (8) 57
Equity in (earnings)/losses of unconsolidated affiliates(5) (20) 2
 10
 (13)
Depreciation and amortization372
 435
 19
 —
 826
Provision for bad debts31
 5
 —
 —
 36
Amortization of nuclear fuel39
 —
 —
 —
 39
Amortization of financing costs and debt discount/premiums—
 25
 17
 —
 42
Adjustment for debt extinguishment—
 102
 17
 —
 119
Amortization of intangibles and out-of-market contracts32
 99
 —
 —
 131
Amortization of unearned equity compensation—
 —
 23
 —
 23
Impairment losses8
 203
 —
 —
 211
Changes in deferred income taxes and liability for uncertain tax benefits(134) (90) 253
 —
 29
Changes in nuclear decommissioning trust liability24
 —
 —
 —
 24
Changes in derivative instruments(173) 206
 (3) —
 30
Changes in collateral posted supporting energy risk management activities268
 (7) —
 —
 261
Proceeds from sale of emission allowances11
 —
 —
 —
 11
Loss on sale of assets—
 —
 70
 —
 70
Cash (used)/provided by changes in other working capital(827) 168
 (200) 729
 (130)
Net cash provided by continuing operations201
 1,000

473

—
 1,674
Cash provided by discontinued operations—
 67
 —
 —
 67
Net Cash Provided by Operating Activities201
 1,067
 473
 —
 1,741
Cash Flows from Investing Activities         
Dividends from NRG Yield, Inc.—
 —
 59
 (59) —
Acquisition of September 2016 Drop Down assets, net of cash acquired—
 (77) —
 77
 —
Intercompany dividends—
 —
 12
 (12) —
Acquisition of businesses, net of cash acquired—
 (18) —
 —
 (18)
Capital expenditures(145) (474) (40) —
 (659)
Increase in notes receivable—
 2
 —
 —
 2
Purchases of emission allowances(32) —
 —
 —
 (32)
Proceeds from sale of emission allowances47
 —
 —
 —
 47
Investments in nuclear decommissioning trust fund securities(378) —
 —
 —
 (378)
Proceeds from sales of nuclear decommissioning trust fund securities354
 —
 —
 —
 354
Proceeds from renewable energy grants and state rebates—
 11
 —
 —
 11
Proceeds from sale of assets, net of cash disposed of—
 67
 17
 —
 84
Investments in unconsolidated affiliates2
 (25) —
 —
 (23)
Other27
 (4) 8
 —
 31
Net cash (used)/provided by continuing operations(125) (518) 56

6
 (581)
Cash provided by discontinued operations—
 326
 —
 —
 326
Net Cash (Used)/Provided by Investing Activities(125) (192) 56
 6
 (255)
Cash Flows from Financing Activities         
Dividends from NRG Yield, Inc.—
 (59) —
 59
 —
Payments (for)/from intercompany loans(2) (134) 136
 —
 —
Acquisition of September 2016 Drop Down assets, net of cash acquired—
 —
 77
 (77) —
Intercompany dividends(52) 40
 —
 12
 —
Payment of dividends to common and preferred stockholders—
 —
 (66) —
 (66)
Payment for preferred shares—
 —
 (226) —
 (226)
Net receipts for settlement of acquired derivatives that include financing elements—
 6
 —
 —
 6
Proceeds from issuance of long-term debt—
 1,097
 4,140
 —
 5,237
Payments for short and long-term debt(2) (811) (4,540) —
 (5,353)
Payments for debt extinguishment costs—
 (98) —
 —
 (98)
Distributions from, net of contributions to, noncontrolling interest in subsidiaries—
 (127) —
 —
 (127)
Proceeds from issuance of common stock—
 —
 1
 —
 1
Payment of debt issuance costs—
 (17) (53) —
 (70)
Other(3) (7) —
 —
 (10)
Net cash used by continuing operations(59) (110) (531) (6) (706)
Cash provided by discontinued operations—
 119
 —
 —
 119
Net Cash (Used)/Provided by Financing Activities(59) 9
 (531) (6) (587)
Change in cash from discontinued operations—
 512
 —
 —
 512
Effect of exchange rate changes on cash and cash equivalents—
 (6) —
 —
 (6)
Net Increase/(Decrease) in Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties17
 366
 (2) —
 381
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at Beginning of Period—
 629
 693
 —
 1,322
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at End of Period$17
 $995
 $691
 $—
 $1,703
(a)All significant intercompany transactions have been eliminated in consolidation.


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, 2017March 31, 2023 and 2016.2022. Also refer to NRG's 20162022 Form 10-K, which includes detailed discussions of various items impacting the Company's business, results of operations and financial condition, including: Introduction and OverviewGeneral section; NRG's Business Strategy section; Business Overview section, including how regulation, weather, and other factors affect NRG's business; and Critical Accounting Policies and Estimates section.
The discussion and analysis below has been organized as follows:
Executive summary, including introduction and overview, business strategy, and changes to the business environment during the period, including environmental and regulatory matters;
Results of operations;
Financial condition, addressing liquidity position, sources and uses of liquidity, capital resources and requirements, commitments, and off-balance sheet arrangements; and
Known trends that may affect NRG's results of operations and financial condition in the future.


Executive Summary
Introduction and Overview
NRG Energy, Inc., or NRG or the Company, is a leading energy, smart home and services company fueled by market-leading brands, proprietary technologies, and complementary sales channels. NRG brings the power of energy to customers by producing and selling energy and related products and services. Across the United States and Canada, NRG develops innovative, sustainable solutions, predominately under brand names such as NRG, Reliant, Direct Energy, Green Mountain Energy and Vivint. The Company has a customer base that includes approximately 7.5 million residential consumers in addition to commercial, industrial, and wholesale customers, supported by approximately 16 GW of generation.
Strategy
NRG's strategy is to maximize stockholder value through the safe production and sale of reliable electricity and natural gas to its customers in the markets it serves, while also providing innovative solutions to the end-use energy or service consumer. This strategy is intended to enable the Company to optimize the integrated power company built onmodel to generate stable and predictable cash flow, significantly strengthen earnings and cost competitiveness, and lower risk and volatility. Sustainability is a philosophy that underpins and facilitates value creation across NRG's business for its stakeholders. It is an integral piece of NRG's strategy and ties directly to business success, reduced risks and enhanced reputation.
To effectuate the strength of a diverse competitive electric generation portfolio and leading retail electricity platform.Company’s strategy, NRG is continuously focused on excellence in operating performance of its existing assets and optimal hedging of generation assets and retail load operations, as well ason: (i) serving the energy needs of end-use residential, commercial and industrial, customersand wholesale counterparties in competitive markets and optimizing on cross selling opportunities through its multiple brands and channels. The Company owns and operates approximately 30,000 MWchannels; (ii) offering a variety of generation; engages in the trading of wholesale energy capacity and related products; transacts in and trades fuel and transportation services; and directly sells energy, services, and innovative, sustainable products and services, to retail customers under the names “NRG”, "Reliant"including renewable energy solutions and other retail brand names ownedsmart home products and services that are differentiated by NRG. NRG was incorporated as a Delaware corporation on May 29, 1992.
The following table summarizes NRG's global generation portfolio as of September 30, 2017, byinnovative features, premium service, integrated platforms, sustainability, and loyalty/affinity programs; (iii) excellence in operating segment:

  
Global Generation Portfolio(a)(b)
  (In MW)
  Generation        
Generation Type Gulf Coast 
East/West (c)
 
Renewables(d) 
 
NRG Yield(e) 
 
Other(f) 
 Total Global
Natural gas(g)
 7,464
 4,939
 —
 1,878
 —
 14,281
Coal 5,114
 3,869
 —
 —
 —
 8,983
Oil —
 3,642
 —
 190
 —
 3,832
Nuclear 1,136
 —
 —
 —
 —
 1,136
Wind —
 —
 743
 2,206
 —
 2,949
Utility Scale Solar —
 —
 742
 921
 —
 1,663
Distributed Solar —
 —
 175
 14
 114
 303
Total generation capacity(g)
 13,714
 12,450
 1,660
 5,209
 114
 33,147
Capacity attributable to noncontrolling interest(h)
 —
 —
 (684) (2,342) —
 (3,026)
Total net generation capacity 13,714
 12,450
 976
 2,867
 114
 30,121
(a) All Utility Scale Solar and Distributed Solar facilities are described in MW on an alternating current basis. MW figures provided represent nominal summer net MW capacity of power generated as adjusted for the Company's owned or leased interest excluding capacity from inactive/mothballed units.
(b)GenOn, which represented 16,423 MW of global generation at December 31, 2016, was deconsolidated from NRG on June 14, 2017.
(c) Includes International and BETM.
(d) Includes Distributed Solar capacity from assets held by DGPV Holdco 1 and DGPV Holdco 2.
(e) Does not include NRG Yield, Inc.'s thermal converted (MWt) capacity, which is part of the NRG Yield operating segment.
(f) The Distributed Solar figure within "Other" includes the aggregate production capacity of installed and activated residential solar energy systems. Also includes capacity from operating portfolios of residential solar assets held by RPV Holdco.
(g) Natural gas generation does not include 51 MW related to the Miramar and El Cajon sites which were part of the San Diego Combustion Turbines and retired on January 1, 2017, and 106 MW related to Encina Unit 1 which was deactivated on March 31, 2017.
(h)NRG Yield's total generation capacity includes 6 MWs for noncontrolling interest for Spring Canyon II and III. NRG Yield's total generation capacity net of this noncontrolling interest was 5,203 MWs.

GenOn
On June 14, 2017, GenOn, GenOn Americas Generation and certain of their directly and indirectly-owned subsidiaries, all of which are subsidiaries of NRG, filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas, Houston Division. As a result of the bankruptcy filings and beginning on June 14, 2017, GenOn and its subsidiaries, representing approximately 15,000 MW, were deconsolidated from NRG’s consolidated financial statements.



Transformation Plan
On July 12, 2017, NRG announced its Transformation Plan designed to significantly strengthen earnings and cost competitiveness, lower risk and volatility, and create significant shareholder value. The three-part, three-year plan is comprised of the following targets:
Operations and cost excellence — Cost savings and margin enhancement of $1,065 million recurring, which consists of $590 million of annual cost savings, a $215 million net margin enhancement program, $50 million annual reduction in maintenance capital expenditures, and $210 million in permanent selling, general and administrative expense reduction associated with asset sales.

Portfolio optimization — Targeting up to $4.0 billion of asset sale net cash proceeds, including divestitures of 6 GWs of conventional generation and businesses (excluding GenOn) and the expected monetization of 100%performance of its interestassets; (iv) optimal hedging of its portfolio; and (v) engaging in NRG Yield, Inc.disciplined and its renewables platform.transparent capital allocation.

Capital structure and allocation enhancements — A prioritized capital allocation strategy that targets a reduction in consolidated debt from approximately $19.5 billion ($18 billion net debt) to approximately $6.5 billion ($6 billion net debt). Following the completion of the contemplated asset sales, the Company expects $4.8-$6.3 billion in excess cash to be available for allocation through 2020, after achieving its targeted 3.0x net debt / Adjusted EBITDA corporate credit ratio.

The Company expects to fully implement the Transformation Plan by the end of 2020 with significant completion by the end of 2018. The Company expects to realize (i) $370 million of non-recurring working capital improvements through 2020 and (ii) approximately $290 million, one-time costs to achieve.

Energy Regulatory Matters
The Company’s regulatory matters are described in the Company’s 20162022 Form 10-K in Item 1, Business — Regulatory Matters. These matters have been updated below and in Note 16, Regulatory Matters, to the Condensed Consolidated Financial Statements of this Form 10-Q as found in Item 1.Matters.
As owners of power plants and 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 generating, thermal,generation or distributed generation assets are located. In addition, NRG is subject to the market rules, procedures and protocols of the various ISO and RTO markets in which it participates. Likewise, certain NRG entities participating in the retail markets are subject to rules and regulations established by the states and provinces in which NRG entities are licensed to sell at retail. NRG must also comply with the mandatory reliability requirements imposed by NERC and the regional reliability entities in the regions where NRG operates.
NRG's operations within the ERCOT footprint are not subject to rate regulation by FERC, as they are deemed to operate solely within the ERCOT market and not in interstate commerce. These operations are subject to regulation by the PUCT, as well as to regulation by the NRC with respect to NRG's ownership interest in STP.



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East Region
PJM
MinimumRegional Regulatory Developments
NRG is affected by rule/tariff changes that occur in the ISO regions. For further discussion on regulatory developments see Note 16, Regulatory Matters.
Texas
Public Utility Commission of Texas’ Actions with Respect to Wholesale Pricing and Market Design — In September 2021, the PUCT opened a rulemaking project to evaluate whether it should amend its rules to modify the High System Wide Offer Price Rule Exemption Appeal —cap ("HCAP") and the ORDC, which is intended to ensure prices in the competitive market appropriately reflect the value of operating reserves as the system approaches scarcity conditions. This rulemaking project concluded in December 2021, resulting in a rule amendment that lowered the HCAP to $5,000 per MWh and which expands the minimum contingency level to 3,000 MW in Phase I. These two changes are broadly offsetting in their effect on overall average energy prices. In 2022, the PUCT has focused on the development of a winter firm fuel product. The PUCT directed ERCOT to issue a Request for Proposal to procure dual fuel capability with on-site fuel storage as part of the initial firm fuel procurement for the winter of 2022 and 2023. The procurement amount was 2,940MW with a total cost of $53 million.
The PUCT engaged an independent consultant, E3, to evaluate various resource adequacy proposals and recommend a policy direction to increase incentives for investment in dispatchable generation in ERCOT. On July 7, 2017,November 10, 2022, the D.C. Circuit vacatedindependent consultant provided a FERCreport including various market design options such as a Forward Reliability Market, Load Servicing Entity Reliability Obligation and a new concept called a Performance Credit Mechanism ("PCM"). The PCM measures real-time contribution to system reliability and provides compensation for resources to be available. The PUCT staff filed a summary of comments and their recommendations, which support PCM. On January 19, 2023, the Commission approved an order from 2013 related toadopting the PCM as their policy direction for resource adequacy in ERCOT, however, implementation is delayed until the legislature reviews.
Ruling on Pricing during Winter Storm Uri — On March 17, 2023, the Third Court of Appeals issued a ruling in Luminant Energy Co. v. PUCT, which is an exemptionappeal relating to the Minimum Offer Price Rule, or MOPR,validity of two orders issued by the PUCT on February 15 and 16, 2021, respectively, governing scarcity pricing in the ERCOT wholesale electricity market during Winter Storm Uri. The Third Court found that the PUCT exceeded its statutory authority by ordering the market price of energy to be set at the high system wide offer cap due to scarcity conditions as a result of firm load shed occurring in ERCOT. The Third Court reversed the PUCT's orders and remanded the issue backcase. At the March 23, 2023 open meeting, the PUCT voted to FERC. On October 23, 2017, PJM re-filed its initial 2012 MOPR. FERC'sappeal the Third Court's ruling on PJM's renewed proposal could affect how generators participate in the PJM Base Residual Auction.
2020/2021 PJM Auction Results — On May 23, 2017, PJM announced the results of its 2020/2021 base residual auction. NRG, excluding GenOn, cleared approximately 3,992 MW of Capacity Performance product. NRG’s expected capacity revenues, excluding GenOn, from the base residual auction for the 2020/2021 delivery year are approximately $268 million. For results of the 2019/2020 PJM base residual auction, refer to Item 1 - Business of the 2016 Form 10-K.
The table below provides a detailed description of NRG’s 2020/2021 base residual auction result:
 Capacity Performance Product
Zone
Cleared Capacity (MW)(a)
 Price ($/MW-day)
COMED3,315 $188.12
EMAAC519 $187.87
MAAC158 $86.04
Total3,992  
(a) Includes imports. Does not include capacity sold by NRG Curtailment Specialists.
New England
2020/2021 ISO-NE Auction Results — On February 6, 2017, ISO-NE announced the results of its 2020/2021 forward capacity auction. NRG cleared 2,641 MW at $5.297 KW per month providing expected annual capacity revenues of $167.9 million. The 333 MWs at Canal Unit 3, which previously cleared the tenth forward capacity auction with a seven year price lock at a price of $7.03 KW per month for the 2020/2021 deliverability year, are excluded from these results.

Peak Energy Rent Adjustment Complaint — On September 30, 2016, the New England Power Generators Association, or NEPGA, filed a complaint against ISO-NE asking FERC to find the Peak Energy Rent, or PER, unjust and unreasonable. The PER adjustment reduces capacity payments on days where energy prices exceed a pre-defined level, known as the "PER strike price." On January 9, 2017, FERC granted NEPGA’s complaint requiring a change to the methodology used to calculate the PER strike price. FERC also directed the parties to determine any refunds for PER paid between September 30, 2016 and May 31, 2018. On July 26, 2017, NEPGA filed settlement documents at FERC, which NRG supported. The settlement is pending at FERC.Supreme Court of Texas. The outcome of this matter will determinecase could require a repricing of the amountmarket prices during that time.
Voluntary Mitigation ("VMP") Changes — On March 13, 2023, the PUCT Staff determined that a portion of refundsNRG'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.
PJM
PJM Delays Base Residual Auction Results and Files to Update Tariff — The Base Residual Auction for the 2024/2025 delivery year commenced on December 7, 2022 and closed on December 13, 2022. On December 19, 2022, PJM announced that it would delay the publication of the auction results. On December 23, 2022, PJM made a filing at FERC to revise the definition of Locational Deliverability Area 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, fleet may receivehave filed for rehearing. The price of the auction cleared was significantly lower as a result of negotiating the PER strike price methodology.PJM Tariff change.
New York
New York Public Service Commission Retail Energy Market Proceedings Capacity Performance Penalties and Bonuses from Winter Storm Elliott — PJM experienced approximately 23 hours of Capacity Performance events from December 23-24, 2022 across PJM's entire footprint. The Company will be subject to penalty or bonus payments related to the events with settlements to occur in 2023. PJM anticipates that certain market participants who incurred penalties may encounter challenges in paying penalties levied upon them. This may result in bonus payments being prorated. On February 23, 2016,2, 2023, PJM made a filing at FERC that, if approved, would give PJM the NYSPSC issued what it refersability to asextend the payment period for PJM members who incurred penalties for an additional 9 months. On April 3, 2023, FERC approved PJM's request to allow Winter Storm Elliott penalty payments to be spread over 9 months (with interest) and allow future penalties to have a 9 month window to be satisfied without interest. In addition, multiple generators filed various complaints against PJM at FERC alleging that PJM violated its “Retail Reset” order, or Reset Order,Tariff in, docket 12-M-0476 et al.  Amongamong other things, the Reset Order placedmanner in which it operated the system during Winter Storm Elliott and the resulting assessment of capacity performance penalties.

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PJM Files at FERC to Delay the Upcoming Base Residual Auctions — On April 11, 2023, PJM filed to delay the Base Residual Auctions for the 2025/2026 to 2028/2029 delivery years. PJM proposes to develop market reforms to improve the operation of the capacity market, and plans to make a price capfiling regarding those reforms by October 1, 2023. PJM proposes to restart the auctions after FERC's ruling on energy supply offersthese market changes.
California
California Resource Adequacy Proceedings — As part of the Integrated Resource Procurement docket, the CPUC approved a decision on June 24, 2021 that requires all LSEs to procure a pro rata share of 11.5 GW of new non-fossil resource adequacy from 2023 to 2026. In that same docket, the CPUC ordered the state's major investor-owned utilities to procure additional summer reliability resources through 2023, with recent staff proposals recommending an extension of these order through 2025. Further procurement order in this docket issued in February 2023 directed LSEs to procure an additional four GW of clean resources in the 2026 to 2028 timeframe. Reserve margin increased from 15 percent to 16 percent in 2023 and required many retail providers to seek affirmative consent from certain retail customers. Various parties have challenged the NYPSC’s ability to regulate rates charged by competitive suppliersat least 17 percent in New York state court.  In conjunction with the court challenges, the NYPSC is2024. SB846 establishes a pathway for PG&E's Diablo Canyon Nuclear power plant, which units are scheduled to commence an evidentiary proceeding on the functioning of the competitive retail markets on November 29, 2017.  The outcome of this evidentiaryclose in 2024 and collaborative process, combined with the outcome of the appeal of the Appellate Division order, could affect the viability of the New York retail energy market.
General
State Out-Of-Market Subsidy Proposals — Certain states including Connecticut, New Jersey, Ohio and Pennsylvania have considered but have not enacted proposals2025, to provide out-of-market subsidy payments to potentially uneconomic nuclear and fossil generating units.  NRG has opposed those efforts to provide out of market subsidies, and intends to continue opposing them in the future.   



West Region
CAISO
Puente Power Project — On October 5, 2017, the California Energy Commission, or CEC, the agency responsible for permitting the Puente Power Project, issued a statement on behalf of the committee of two Commissioners overseeing the permitting process stating their intention to issue a proposed decision that would deny a permit for the Puente Power Project. On October 16, 2017, NRG filed a motion to suspend the permitting proceedingremain open for at least six months. A hearing onfive additional years. Recently opened rulemaking will determine how the motion was held on October 31, 2017, afterresource adequacy from the extension will be treated. Finally, the CPUC released a proposed order in March 2023 regarding details for implementation of a new Resource Adequacy ("RA") program beginning in 2025 which the CEC took the matter under submission subjectwill require procurement to a written decision to be issued at an unspecified later date. If the CEC Commissioners accept the recommendation, and formally deny a permit for the Puente Power Project, then the project will not move forward.
Nuclear Operations
Decommissioning Trusts — Upon expirationmeet needs during every hour of the operating licenses forday. The result of these changes will likely keep RA prices elevated in the two generating units at STP, recently extended until 2047near term and 2048, respectively, the co-owners of STP are required under federal law to decontaminate and decommission the STP facility. Under NRC regulations, a power reactor licensee generally must pre-fund the full amount of its estimated NRC decommissioningif LSEs cannot meet their RA obligations, unless it is a rate-regulated utility, or a state or municipal entity that sets its own rates, or has the benefit of a state-mandated non-bypassable charge available to periodically fund the decommissioning trust such that the trust, plus allowable earnings, will equal the estimated decommissioning obligations by the time the decommissioning is expected to begin.penalties may be issued.

Environmental Regulatory Matters
NRG is subject to a wide range ofnumerous environmental laws in the development, construction, ownership and operation of projects.power plants. These laws generally require that governmental permits and approvals be obtained before construction and maintained during operation of power plants. NRG is also subject toFederal and state environmental laws regarding the protection of wildlife, including migratory birds, eagles and threatened and endangered species. Requirements regarding GHGs, combustion byproducts, water discharge and use, and threatened and endangered specieshistorically have been put in place in recent years. However, under the current U.S. presidential administration, some of these rules are being reconsidered and reviewed.become more stringent over time. Future laws may require the addition of emissions controls or other environmental controls or impose restrictions on the operations of the Company's facilities, which could have a material effect on the Company's operations. Complying with environmental laws often involves specialized human resources and significant capital and operating expenses.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 with the potential tothat affect the Company and its facilities have been revised recently promulgatedand continue to be revised by the EPA, but are being reconsidered, including ESPS/NSPS for GHGs,ash storage and disposal requirements, NAAQS revisions and implementation and effluent limitation guidelines. NRG is evaluatingwill evaluate the potential outcomes and any resulting impactsimpact of recently promulgatedthese regulations that the EPA is now reconsidering andas they are revised but cannot fully predict such impactsthe impact of each until administrative reconsiderationsanticipated revisions and legal challenges are resolved. Federal and state environmental laws generally have become more stringent over time, although this trend could slow or pause in the near term with respect to federal laws under the current U.S. presidential administration. The Company’s environmental matters are described in the Company’s 20162022 Form 10-K in Item 1, Business - Environmental Matters and Item 1A, Risk Factors. These matters have been updated in Item 1 — Note 17,Environmental Matters, to the Condensed Consolidated Financial Statementscondensed consolidated financial statements of this Form 10-Q and as follows.
NationalAir
Air
The CAA and the resultingrelated 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.PM2.5. Many of the Company's facilities are located in or near areas that are classified by the EPA as not achieving certain NAAQS (non-attainment areas). The relevant NAAQS have historicallymay become more stringent. In January 2023, the EPA proposed increasing the stringency of the PM2.5 NAAQS. The Company maintains a comprehensive compliance strategy to address continuing and new requirements. Complying with increasingly stringent NAAQSair regulations could require the installation of additional emissions control equipment at some NRG facilities or retiring of units if installing such controls is not economical.economic. Significant changes to air regulatory programs affecting the Company are described below.
Ozone NAAQS — On October 26, 2015, the EPA promulgated a rule that reduces the ozone NAAQS to 0.070 ppm. Challenges to this rule have been stayed at the request of the EPA so that it can evaluate the rule. If the rule is not altered by the EPA and survives legal challenges, this more stringent NAAQS will obligate the states to develop plans to reduce NOx (an ozone precursor), which could affect some of the Company's units.


Clean Power Plan CPP/ACE Rules — The attention in recent years on GHG emissions has resulted in federal regulations and state legislative and regulatory action.regulations. In October 2015, the EPA finalizedpromulgated the Clean Power Plan, or CPP, addressing GHG emissions from existing EGUs. On February 9, 2016, the U.S. Supreme Court stayed the CPP. TheIn July 2019, EPA promulgated the ACE rule, which rescinded the CPP, which had sought to broadly regulate CO2 emissions from the power sector. On January 19, 2021, the D.C. Circuit heard oral argumentvacated 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. The Company anticipates that there will be additional rulemaking by the EPA over the next several years.
Cross-State Air Pollution Rule ("CSAPR") — On March 15, 2023, the EPA signed and released a prepublication of a final rule that if and when published in the Federal Register would have significantly revised the CSAPR to address the good-

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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. Accordingly, the EPA may not publish this rule in the Federal Register or if it does publish the rule, it would be ineffective in Texas and Louisiana while the stay is pending. The rule would have decreased over time the ozone-season NOx allowances allocated to generators in the 23 states beginning this summer by assuming that participants in this cap-and-trade program had or would optimize existing NOx controls and later install additional NOx controls. The Company cannot predict the outcome of: (i) the legal challenges to the CPP in September 2016. At the EPA's request, the D.C. Circuit agreed on April 28, 2017 to hold the case in abeyance. On October 16, 2017,various state disapprovals; (ii) whether the EPA proposed awill proceeds with publication in the Federal Register; and (iii) legal challenges to the final rule to repealif it is published in the CPP. Accordingly, the Company believes the CPP is not likely to survive.Federal Register.
Byproducts, Wastes, Hazardous Materials and Contamination
In April 2015, the EPA finalized the rule regulating byproducts of coal combustion (e.g., ash and gypsum) as solid wastes under the RCRA. On September 13, 2017,July 30, 2018, the EPA grantedpromulgated a rule that amended the petitionash rule by extending some of the deadlines and providing more flexibility for reconsiderationcompliance. On August 21, 2018, the D.C. Circuit found, among other things, that the Utility Solid Waste Activities Group filed in May 2017. The Company has evaluatedEPA had not adequately regulated unlined ponds and legacy surface impoundments. On August 28, 2020, the impactEPA 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 new rule ondeadlines. On November 12, 2020, the Company's consolidated financial position, resultsEPA 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. NRG anticipates further rulemaking related to the Federal Permit Program and legacy surface impoundments.
Domestic Site Remediation Matters
Under certain federal, state and local environmental laws, a current or previous owner or operator of operations,a facility, including an electric generating facility, may be required to investigate and remediate releases or cash flowsthreatened releases of hazardous or toxic substances or petroleum products. NRG may be responsible for property damage, personal injury and has accruedinvestigation 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 environmental and asset retirement obligations under the rule based on current estimates as of September 30, 2017.operations.
Nuclear Waste — The federal government's program to construct a nuclear waste repository at Yucca Mountain, Nevada was discontinued in 2010. Since 1998, the U.S. DOE has been in default of the federal government's obligations to begin accepting spent nuclear fuel, or SNF, and high-level radioactive waste, or HLW, under the U.S. Nuclear Waste Policy Act of 1982, or the Nuclear Waste Policy Act. Owners of nuclear plants, including the owners of STP, had been required to enter into contracts setting out the obligations of the owners and the U.S. DOE, including the fees to be paid by the owners for the U.S. DOE's services to license a spent fuel repository. Effective May 16, 2014, the U.S. DOE stopped collecting the fees.
On February 5, 2013, STPNOC entered into a settlement agreement with the U.S. DOE for payment of damages relating to the U.S. DOE's failure to accept SNF and HLW under the Nuclear Waste Policy Act through December 31, 2013, which washas been extended four times through an addendum dated January 24, 2014,addendums to cover payments through December 31, 2016. On December 12, 2016, STPNOC received the federal government's offer of another three-year extension of payment for continued failure to accept SNF and HLW. The proposal has been reviewed for adequacy and, with advice of counsel, was accepted.2025. There are no facilities for the reprocessing or permanent disposal of SNF currently in operation in the U.S., nor has the NRC licensed any such facilities. STPNOC currently stores all SNF generated by its nuclear generating facilities in on-site storage pools.  Since STPNOC's SNF storage pools do not have sufficient storage capacity for the life of the units, STPNOC is proceeding to construct dry cask storage capability on-site. STPNOC plans to continue to assert claims against the U.S. DOE for damages relating to the U.S. DOE's failure to accept SNF and HLW.
Under the federal Low-Level Radioactive Waste Policy Act of 1980, as amended in 1985, the state of Texas is required to provide, either on its own or jointly with other states in a compact, for the disposal of all low-level radioactive waste generated within the state. STP's warehouse capacityTexas is adequate for on-site storage untilcurrently in a sitecompact with the state of Vermont, and the compact low-level waste facility located in Andrews County in Texas becomes fully operational.has been operational since 2012.
Water
The Company is required under the CWA to comply with intake and discharge requirements, requirements for technological controls and operating practices. As with air quality regulations, federal and state water regulations have become more stringent and imposed new requirements.
Effluent Limitations Guidelines — In November 2015, the EPA revised the ELG for Steam Electric Generating Facilities, which imposed more stringent requirements (as individual permits were renewed) for wastewater streams from FGD, fly ash, bottom ash and flue gas mercury control. On September 18, 2017, the EPA promulgated a final rule that, among other things, postponed the compliance dates to preserve the status quo for FGD wastewater and bottom ash transport water by two years to November 2020 until the EPA amended the rule. On October 13, 2020, the EPA amended the 2015 ELG rule by: (i) altering the stringency of certain limits for FGD wastewater; (ii) relaxing the zero-discharge requirement for bottom ash transport water;

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and (iii) changing several deadlines. On July 26, 2021, the EPA announced that it is initiating a new rulemaking to evaluate revising the ELG rule. While the EPA is developing the new rule, the existing rule (as amended in 2020) will stay in place, and the EPA expects permitting authorities to continue to implement the current regulation. On March 29, 2023, the EPA proposed revisions to the ELG and is accepting comments on the proposal until May 30, 2023. In October 2021, NRG informed its regulators that the Company intends to comply with the ELG by ceasing combustion of coal by the end of 2028 at its domestic coal units outside of Texas, and installing appropriate controls by the end of 2025 at its two plants that have coal-fired units in Texas.
Regional Environmental Developments
Gulf Coast Region
Texas Regional Haze Ash Regulation in Illinois— On October 17, 2017,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 has begun to apply for construction permits (for closure) as required by the regulation.
Houston Nonattainment for 2008 Ozone Standard — During the fourth quarter of 2022, the EPA promulgated a final rule creating a Texas-only SO2 cap-and-trade programchanged the Houston area's classification from Serious to address regional haze. The program is scheduled to begin on January 1, 2019. Several of the Company's units in Texas will be affected by this rule.

East Region
Massachusetts Global Warming Solutions Act Proposed Regulation - In May 2016, the Massachusetts Supreme Judicial Court held that the Massachusetts DEP had not complied withSevere nonattainment for the 2008 Global Warming Solutions Act, which requires establishing limits for sources of GHGs. The Court held that participation in RGGI was not sufficient.  In August 2017,Ozone Standard. Accordingly, Texas is required to develop a new control strategy and submit it to the Massachusetts DEP finalized  a regulation that, if it survives legal challenges, would limit GHG emissions, and may limit operations, from electric generating facilities located in Massachusetts.  The final regulation has been challenged in The Commonwealth of Massachusetts Superior Court of Suffolk County.EPA.





Significant Events
The following significant events have occurred during 2017,2023 as further described within this Management's Discussion and Analysis and the Condensed Consolidated Financial Statements:condensed consolidated financial statements:
NRG Transformation PlanVivint Acquisition
On March 10, 2023, the Company completed the acquisition of Vivint. The Company paid $12 per share, or $2.6 billion in cash. For further discussion, see Note 4, Acquisitions and Dispositions.
Series A Preferred Stock
On March 9, 2023, the Company issued 650,000 shares of 10.25% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock. The proceeds, net of issuance costs, of $636 million were used to fund the Vivint acquisition. For further discussion, see Note 10, Changes in Capital Structure.
Issuance of 2033 Senior Secured First Lien Notes
On March 9, 2023, the Company issued $740 million of aggregate principal amount of 7.000% senior secured first lien notes due 2023. The net proceeds of $724 million, net of issuance costs, were used to fund the Vivint acquisition. For further discussion, see Note 8, Long-term Debt and Finance Leases.
Astoria
On July 12, 2017, NRG announced its Transformation Plan. The three-part, three-year plan is comprised of targets in the areas of operational and cost excellence, portfolio optimization, and capital structure and allocation enhancement.
GenOn Chapter 11 Bankruptcy Filing
On the Petition Date, the GenOn Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. As a result of the bankruptcy filings and beginning on the Petition Date, NRG no longer consolidates GenOn for financial reporting purposes, as discussed in more detail in Note 1, Basis of Presentation, Note 3, Discontinued Operations, Dispositions and Acquisitions and Note 14, Related Party Transactionsof this Form 10-Q.
Transfers of Assets Under Common Control
On March 27, 2017, NRG completed the sale of the following projects to NRG Yield, Inc.: (i) a 16% interest in the Agua Caliente solar project, and (ii) NRG's interests in seven utility-scale solar projects located in Utah, which have reached commercial operations, for $130 million cash consideration, as discussed in more detail in Note 3, Discontinued Operations, Dispositions and Acquisitions of this Form 10-Q.
On August 1, 2017,January 6, 2023, NRG closed on the sale of its remaining 25% interest inland and related assets from the Astoria site, within the East region of operations, for initial proceeds of $212 million, subject to transaction fees of $3 million and certain indemnifications. NRG Wind TE Holdco,recognized a portfolio of 12 wind projects, to NRG Yield, Inc. for total cash consideration of $44 million, including working capital adjustments. The transaction also includes potential additional payments to NRG dependent upon actual energy prices for merchant periods beginning in 2027.
On October 17, 2017, the Company offered NRG Yield, Inc. the opportunity to purchase 100% of its ownership interest in Buckthorn Solar pursuant to the ROFO Agreement.
On November 1, 2017, NRG completedgain on the sale of a 38 MW solar portfolio primarily comprised$199 million. As part of assets from SPP funds in addition to other projects developed bythe transaction, NRG to NRG Yield, Inc. for cash consideration of $71 million, plus $3 million in working capital adjustments.
Financing Activities
On May 26, 2017, Carlsbad Energy Holdings, LLC entered into a note payablean agreement with financial institutionsto lease the land back for the issuancepurpose of upoperating the Astoria gas turbines. The lease agreement is expected to $407 million of senior secured notes that bear interest at a rate of 4.12%, and mature on October 31, 2038, as discussed in more detail in Note 8, Debt and Capital Leases.
On June 12, 2017, NRG repaid $125 million onterminate by the Revolving Credit Facility. As of September 30, 2017, there were no cash borrowings outstanding on the revolver.
On October 16, 2017, NRG redeemed all of its outstanding 7.625% Senior Notes due 2018 and all of its outstanding 7.875% Senior Notes due 2021 for $630 million, which included $14 million in accrued interest.
Operational Matters
Extreme Weather Events
In late August 2017, Hurricane Harvey made landfall on the Texas coast.  During the third quarter of 2017, the Company’s Retail business was impacted by Hurricane Harvey by approximately $20 million.

In addition, during August 2017, NRG's Cottonwood generating station was damaged when the Sabine River Authority opened the floodgatesend of the Toledo Bend reservoir, which resulted in downstream flooding of the Sabine River. The generating station was returned to service during the fourth quarter of 2017. NRG is continuing to work with insurers on potential property insurance recovery and does not anticipate recovery from business interruption insurance due to the short period of the outage. The Company estimates the impact of the Cottonwood damage and Hurricane Harvey on Gulf Coast Generation to be approximately $20 million.year.


Carlsbad Energy Center Power Purchase Tolling Agreement
As of May 1, 2017, NRG’s subsidiary, Carlsbad Energy Center LLC, achieved the Conditions Precedent, or CP, Satisfaction Date under its power purchase tolling agreement with San Diego Gas & Electric Company for the Carlsbad Energy Center.  The CP Satisfaction Date is the date on which specified conditions precedent under the power purchase tolling agreement have either been satisfied or waived. 
Bacliff Project
On June 16, 2017, the Company provided notice to BTEC New Albany, LLC that NRG Texas Power LLC was exercising its right to terminate the Amended and Restated Membership Interest Purchase Agreement, or MIPA, due to the Bacliff Project, a new peaking facility at the former P.H. Robinson Electric Generating Station, not achieving commercial completion by the contractual expiration date of May 31, 2017. On July 14, 2017, the Company gave notice to BTEC New Albany, LLC that it owes NRG Texas Power LLC approximately $48 million under the terminated MIPA, consisting of $38 million in purchaser incurred costs and $10 million in liquidated damages.
Will County Unit 4W.A. Parish Extended Outage
In May 2017, NRG's Will County2022, W.A. Parish Unit 4 suffered an equipment failure that is projected8 came offline as a result of damage to result in an extended outage. At this time,the steam turbine/generator. Based on work completed to date, the Company expectsis targeting to complete repairs and return the unit to service by the end of the second quarter of 2023.
Dividend Increase
In the first quarter of 2023, NRG increased the annual dividend to $1.51 from $1.40 per share, representing an 8% increase from 2022. The Company expects to target an annual dividend growth rate of 7-9% per share in subsequent years.
Renewable Power Purchase Agreements
The Company's strategy is to procure mid to long-term generation through power purchase agreements. NRG has entered into Renewable PPAs totaling approximately 1.9 GW with third-party project developers and other counterparties, of which approximately 1.1 GW are operational as of April 30, 2023. 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 early 2018.contract terminations when they occur.

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Trends Affecting Results of Operations and Future Business Performance
In addition to below, theThe Company’s trends are described in the Company’s 20162022 Form 10-K in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations - Trends Affecting Results of Operations and Future Business Performance.

ERCOT Retirements — A number of announced retirement notices of coal generating facilities in Texas could lower reserve margins in ERCOT. This trend of retirement notices could have an effect on the Company’s results of operations and future business performance, particularly in the ERCOT market.

Environment.
Changes in Accounting Standards
See Note 2,, Summary of Significant Accounting Policies, to the Condensed Consolidated Financial Statements of this Form 10-Q, for a discussion of recent accounting developments.



Consolidated Results of Operations
The following table provides selected financial information for the Company:
 Three months ended March 31,
(In millions, except as otherwise noted)20232022Change
Revenue
Retail revenue$7,363 $7,570 $(207)
Energy revenue(a)
128 278 (150)
Capacity revenue(a)
42 116 (74)
Mark-to-market for economic hedging activities91 (133)224 
Contract amortization(11)(9)(2)
Other revenues(a)(b)
109 74 35 
Total revenue7,722 7,896 (174)
Operating Costs and Expenses
Cost of fuel163 329 166 
Purchased energy and other cost of sales(c)
6,002 6,452 450 
Mark-to-market for economic hedging activities2,035 (2,410)(4,445)
Contract and emissions credit amortization(c)
108 138 30 
Operations and maintenance385 336 (49)
Other cost of operations85 85 — 
Cost of operations (excluding depreciation and amortization shown below)8,778 4,930 (3,848)
Depreciation and amortization190 183 (7)
Selling, general and administrative costs426 347 (79)
Acquisition-related transaction and integration costs71 8 (63)
Total operating costs and expenses9,465 5,468 (3,997)
Gain/(loss) on sale of assets199 (3)202 
Operating (Loss)/Income(1,544)2,425 (3,969)
Other Income/(Expense)
Equity in earnings/(losses) of unconsolidated affiliates5 (15)20 
Other income, net16 — 16 
Interest expense(148)(103)(45)
Total other expense(127)(118)(9)
(Loss)/Income Before Income Taxes(1,671)2,307 (3,978)
Income tax (benefit)/expense(336)571 907 
Net (Loss)/Income$(1,335)$1,736 $(3,071)
Business Metrics
Average natural gas price — Henry Hub ($/MMBtu)$3.42 $4.95 (31)%
 Three months ended September 30, Nine months ended September 30,
(In millions except otherwise noted)2017 2016 Change 2017 2016 Change
Operating Revenues           
Energy revenue (a)
$665
 $933
 $(268) $1,908
 $2,478
 $(570)
Capacity revenue (a)
335
 303
 32
 894
 937
 (43)
Retail revenue1,934

2,015
 (81) 4,880
 4,931
 (51)
Mark-to-market for economic hedging activities26

62
 (36) 185
 (360) 545
Contract amortization(12) (12) —
 (41) (41) —
Other revenues (b)
101
 120
 (19) 306
 383
 (77)
Total operating revenues3,049
 3,421
 (372) 8,132
 8,328
 (196)
Operating Costs and Expenses           
Cost of sales (c)
1,679
 1,847
 168
 4,362
 4,526
 164
Mark-to-market for economic hedging activities50
 149
 99
 168
 (301) (469)
Contract and emissions credit amortization (c)
8
 11
 3
 24
 34
 10
Operations and maintenance326
 354
 28
 1,038
 1,196
 158
Other cost of operations93
 79
 (14) 260
 256
 (4)
Total cost of operations2,156
 2,440
 284
 5,852
 5,711
 141
Depreciation and amortization272
 298
 26
 789
 826
 37
Impairment losses14
 9
 (5) 77
 65
 (12)
Selling, general and administrative213
 277
 64
 697
 801
 104
Reorganization18
 —
 (18) 18
 —
 (18)
Development costs14
 21
 7
 49
 65
 16
Total operating costs and expenses2,687
 3,045
 358
 7,482

7,468
 (14)
   Other income - affiliate14
 48
 (34) 104
 144
 (40)
  Gain/(loss) on sale of assets—
 4
 (4) 4
 (79) 83
Operating Income376
 428
 (52) 758
 925
 (167)
Other Income/(Expense)           
Equity in earnings of unconsolidated affiliates27
 16
 11
 29
 13
 16
Impairment loss on investment—
 (8) 8
 —
 (147) 147
Other income, net15
 7
 8
 33
 29
 4
Loss on debt extinguishment, net(1) (50) 49
 (3) (119) 116
Interest expense(221) (237) 16
 (692) (718) 26
Total other expense(180) (272) 92
 (633) (942) 309
Income/(Loss) from Continuing Operations before Income Taxes196
 156
 40
 125

(17) 142
Income tax expense6
 28
 (22) 5
 75
 (70)
Income/(Loss) from Continuing Operations190
 128
 62
 120
 (92) 212
(Loss)/Income from discontinued operations, net of income tax(27) 265
 (292) (802) 256
 (1,058)
Net Income/(Loss)163
 393
 (230) (682) 164
 (846)
Less: Net loss attributable to noncontrolling interest and redeemable noncontrolling interest(8) (9) 1
 (63) (49) (14)
Net Income/(Loss) Attributable to NRG Energy, Inc.$171
 $402
 $(231) $(619) $213
 $(832)
Business Metrics    

      
Average natural gas price — Henry Hub ($/MMBtu)$3.00
 $2.81
 7% $3.17
 $2.29
 38%
(a)Includes realized gains and losses from financially settled transactions.transactions
(b)Includes unrealized trading gains and losses.losses and ancillary revenues
(c)Includes amortization of SO2 and NOx credits and excludes amortization of RGGI credits.    

credits     


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Management’s discussion of the results of operations for the three months ended September 30, 2017March 31, 2023 and 20162022
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, 2017March 31, 2023 and 2016. The2022. Texas, East and West average on-peak power prices have generally decreased primarily due to the increase in natural gas prices for the three months ended September 30, 2017March 31, 2023 as compared to the same period in 2016.2022 as a result of lower natural gas prices, while average CAISO on-peak power prices increased primarily driven by colder winter weather in California in 2023.
 Average on Peak Power Price ($/MWh)
Three months ended March 31,
Region20232022Change %
Texas
ERCOT - Houston(a)
$26.98 $48.69 (45)%
ERCOT - North(a)
26.72 46.27 (42)%
East
    NY J/NYC(b)
$45.40 $104.26 (56)%
    NEPOOL(b)
52.63 116.48 (55)%
    COMED (PJM)(b)
29.78 44.69 (33)%
    PJM West Hub(b)
36.49 58.33 (37)%
West
MISO - Louisiana Hub(b)
$29.78 $43.49 (32)%
CAISO - SP15(b)
92.54 45.20 105 %
 Average on Peak Power Price ($/MWh)
 Three months ended September 30,
Region2017 2016 Change %
Gulf Coast (a)
     
ERCOT - Houston (b)
$33.09
 $33.12
 — %
ERCOT - North(b)
29.35
 30.47
 (4)%
MISO - Louisiana Hub(c)
39.56
 39.83
 (1)%
East/West    
    NY J/NYC(c)
37.42
 42.50
 (12)%
    NEPOOL(c)
31.94
 42.33
 (25)%
    PEPCO (PJM)(c)
38.81
 42.57
 (9)%
    PJM West Hub(c)
35.10
 38.84
 (10)%
CAISO - NP15(c)
46.69
 38.13
 22 %
CAISO - SP15(c)
46.54
 40.24
 16 %
(a) Gulf Coast region also transacts in PJM - West Hub.
(b) Average on peak power prices based on real time settlement prices as published by the respective ISOs.ISOs
(c) (b)Average on peak power prices based on day ahead settlement prices as published by the respective ISOs.ISOs

The following table summarizes average realized power prices for each region in which NRG operates for the three months ended September 30, 2017 and 2016, which reflects the impact of settled hedges.
 Average Realized Power Price ($/MWh)
 Three months ended September 30,
Region2017 2016 Change %
Gulf Coast$34.69
 $39.68
 (13)%
East/West38.19
 40.44
 (6)%
Though the average on peak power prices have decreased on average by 5%, average realized prices by region for the Company have generally fluctuated at a slower rate year-over-year due to the Company's multi-year hedging program.


Gross Margin
The Company calculates gross margin in order to evaluate operating performance as operating revenues less cost of sales, which includes cost of fuel, purchased energy and other costs of sales, mark-to-market for economic hedging activities, contract and emission credit amortization and mark-to-market for economic hedging activities.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, retail revenue and other revenue, less cost of fuelsfuel, 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, emissionemissions credit amortization, depreciation and amortization, operations and maintenance, or other operating costs.cost of operations.



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The below tables present the composition and reconciliation of gross margin and economic gross margin for the three months ended September 30, 2017March 31, 2023 and 2016:2022:
Three months ended March 31, 2023
($ In millions)TexasEastWest/Services/Other
Vivint(a)
Corporate/EliminationsTotal
Retail revenue$1,958 $4,016 $1,241 $148 $— $7,363 
Energy revenue4 74 48 — 2 128 
Capacity revenue— 41 1 — — 42 
Mark-to-market for economic hedging activities— 35 67 — (11)91 
Contract amortization— (11)— — — (11)
Other revenue(b)
72 21 17 — (1)109 
Total revenue2,034 4,176 1,374 148 (10)7,722 
Cost of fuel(112)(23)(28)— — (163)
Purchased energy and other cost of sales(c)(d)(e)
(1,255)(3,577)(1,157)(11)(2)(6,002)
Mark-to-market for economic hedging activities129 (1,790)(385)— 11 (2,035)
Contract and emission credit amortization(1)(104)(3)— — (108)
Depreciation and amortization(75)(30)(24)(52)(9)(190)
Gross margin$720 $(1,348)$(223)$85 $(10)$(776)
Less: Mark-to-market for economic hedging activities, net129 (1,755)(318)— — (1,944)
Less: Contract and emission credit amortization, net(1)(115)(3)— — (119)
Less: Depreciation and amortization(75)(30)(24)(52)(9)(190)
Economic gross margin$667 $552 $122 $137 $(1)$1,477 
(a) Vivint 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 $647 million, $49 million and $357 million of TDSP expense in Texas, East and West/Services/Other, respectively.
(e) Excludes depreciation and amortization shown separately
Business MetricsTexasEastWest/Services/OtherVivintCorporate/EliminationsTotal
Retail sales
Home power sales volume (GWh)7,614 3,079 636 — — 11,329 
Business power sales volume (GWh)8,568 10,451 2,393 — — 21,412 
Home natural gas sales volume (MDth)— 22,395 36,733 — — 59,128 
Business natural gas sales volume (MDth)— 471,121 50,879 — — 522,000 
Average retail Home customer count (in thousands)(a)
2,871 1,770 778 — — 5,419 
Ending retail Home customer count (in thousands)(a)
2,869 1,801 784 — — 5,454 
Ending Vivint smart home customer count(b)
— — — 1,938 — 1,938 
Power generation
GWh sold5,186 1,258 1,303 — — 7,747 
GWh generated(c)
   Coal2,081 218 — — — 2,299 
   Gas785 39 1,302 — — 2,126 
   Nuclear2,320 — — — — 2,320 
Renewables— — 1 — — 1 
Total5,186 257 1,303 — — 6,746 
(a) Home customer count includes recurring residential customers, services customers and municipal aggregations
(b) Vivint customer count includes customers that also purchase other NRG products
(c) Includes owned and leased generation, excludes tolled generation and equity investments


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Three months ended March 31, 2022
Three months ended September 30, 2017
Generation          
(In millions)Gulf Coast 
East/West(a)
 Subtotal Retail Renewables NRG Yield Corporate/Eliminations Total
($ In millions)($ In millions)TexasEast West/Services/OtherCorporate/EliminationsTotal
Retail revenueRetail revenue$1,946 $4,521 $1,103 $— $7,570 
Energy revenue$540
 $243
 $783
 $—
 $119
 $146
 $(383) $665
Energy revenue15 204 54 5 278 
Capacity revenue74
 172
 246
 —
 1
 92
 (4) 335
Capacity revenue— 115 1 — 116 
Retail revenue—
 —
 —
 1,936
 —
 —
 (2) 1,934
Mark-to-market for economic hedging activities133
 —
 133
 —
 5
 —
 (112) 26
Mark-to-market for economic hedging activities(2)(130)(18)17 (133)
Contract amortization5
 —
 5
 1
 (1) (18) 1
 (12)Contract amortization— (9)— — (9)
Other revenue (b)
41
 16
 57
 —
 20
 44
 (20) 101
Operating revenue793
 431
 1,224
 1,937
 144
 264
 (520) 3,049
Other revenue(a)
Other revenue(a)
61 14 4 (5)74 
Total revenueTotal revenue2,020 4,715 1,144 17 7,896 
Cost of fuel(292) (123) (415) (1) (1) (6) 17
 (406)Cost of fuel(175)(103)(51)— (329)
Other cost of sales(c)
(102) (79) (181) (1,457) (3) (9) 377
 (1,273)
Purchased energy and other cost of sales(b)(c)(d)
Purchased energy and other cost of sales(b)(c)(d)
(1,282)(4,164)(1,005)(1)(6,452)
Mark-to-market for economic hedging activities2
 10
 12
 (174) —
 —
 112
 (50)Mark-to-market for economic hedging activities655 1,576 196 (17)2,410 
Contract and emission credit amortization(7) (1) (8) —
 —
 —
 —
 (8)Contract and emission credit amortization2 (138)(2)— (138)
Depreciation and amortizationDepreciation and amortization(77)(77)(21)(8)(183)
Gross margin$394
 $238
 $632
 $305
 $140
 $249
 $(14) $1,312
Gross margin$1,143 $1,809 $261 $(9)$3,204 
Less: Mark-to-market for economic hedging activities, net135

10

145
 (174)
5

—

—
 (24)Less: Mark-to-market for economic hedging activities, net653 1,446 178 — 2,277 
Less: Contract and emission credit amortization, net(2)
(1)
(3) 1

(1)
(18)
1
 (20)Less: Contract and emission credit amortization, net2 (147)(2)— (147)
Less: Depreciation and amortizationLess: Depreciation and amortization(77)(77)(21)(8)(183)
Economic gross margin$261
 $229

$490

$478

$136

$267

$(15)
$1,356
Economic gross margin$565 $587 $106 $(1)$1,257 
(a) Includes trading gains and losses and ancillary revenues(a) Includes trading gains and losses and ancillary revenues
(b) Includes capacity and emissions credits(b) Includes capacity and emissions credits
(c) Includes $672 million, $61 million and $389 million of TDSP expense in Texas, East, and West/Services/Other, respectively(c) Includes $672 million, $61 million and $389 million of TDSP expense in Texas, East, and West/Services/Other, respectively
(d) Excludes depreciation and amortization shown separately(d) Excludes depreciation and amortization shown separately
Business Metrics               Business MetricsTexasEastWest/Services/OtherCorporate/EliminationsTotal
MWh sold (thousands)(d)(e)
15,568
 6,363
     928
 1,544
    
MWh generated (thousands) (f)
14,185
 4,106
     928
 2,261
    
(a) Includes International, BETM and Generation eliminations
(b) Renewables other revenue includes $7 million of intercompany revenue to NRG Yield.
(c) Includes purchased energy, capacity and emissions credits
(d) MWh sold excludes generation at facilities in East/West and NRG Yield that generate revenue under capacity agreements.
(e) Does not include thermal MWh of 9 thousand or MWt of 463 thousand for thermal sold by NRG Yield.
(f) Does not include thermal MWh of 44 thousand or MWt of 463 thousand for thermal generated by NRG Yield.
Retail salesRetail sales
Home power sales volume (GWh)Home power sales volume (GWh)9,239 3,438 609—13,286 
Business power sales volume (GWh)Business power sales volume (GWh)8,691 12,148 2,117—22,956 
Home natural gas sales volume (MDth)Home natural gas sales volume (MDth)— 24,115 39,285—63,400 
Business natural gas sales volume (MDth)Business natural gas sales volume (MDth)— 545,940 41,965—587,905 
Average retail Home customer count (in thousands)(a)
Average retail Home customer count (in thousands)(a)
2,996 1,773 807—5,576 
Ending retail Home customer count (in thousands)(a)
Ending retail Home customer count (in thousands)(a)
2,972 1,773 802—5,547 
Power generationPower generation
GWh soldGWh sold8,0213,8811,498—13,400
GWh generated(b)
GWh generated(b)
Coal Coal4,465 2,466——6,931 
Gas Gas1,008 1141,500—2,622 
Nuclear Nuclear2,548 ———2,548 
Oil Oil——1—1 
TotalTotal8,021 2,580 1,501 — 12,102 
(a) Home customer count includes recurring residential customers, services customers and municipal aggregations(a) Home customer count includes recurring residential customers, services customers and municipal aggregations
(b) Includes owned and leased generation, excludes tolled generation and equity investments(b) Includes owned and leased generation, excludes tolled generation and equity investments

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 Three months ended September 30, 2016
 Generation          
(In millions)Gulf Coast 
East/West(a)
 Subtotal Retail Renewables NRG Yield Corporate/Eliminations Total
Energy revenue$650
 $362
 $1,012
 $—
 $127
 $158

$(364) $933
Capacity revenue72
 148
 220
 —
 —
 86
 (3) 303
Retail revenue—
 —
 —
 2,009
 —
 —
 6
 2,015
Mark-to-market for economic hedging activities179
 57
 236
 2
 1
 —
 (177) 62
Contract amortization4
 —
 4
 1
 (1) (17) 1
 (12)
Other revenue (b)
51
 13
 64
 —
 12
 45
 (1) 120
Operating revenue956
 580
 1,536
 2,012
 139
 272
 (538) 3,421
Cost of fuel(317) (190) (507) (1) (2) (7) 18
 (499)
Other cost of sales(c)
(114) (83) (197) (1,484) (1) (11) 345
 (1,348)
Mark-to-market for economic hedging activities27
 7
 34
 (360) —
 —
 177
 (149)
Contract and emission credit amortization(9) —
 (9) (2) —
 —
 —
 (11)
Gross margin$543
 $314
 $857
 $165
 $136
 $254
 $2
 $1,414
Less: Mark-to-market for economic hedging activities, net206

64

270
 (358)
1

—

—
 (87)
Less: Contract and emission credit amortization, net(5)
—

(5) (1)
(1)
(17)
1
 (23)
Economic gross margin$342
 $250
 $592
 $524
 $136
 $271
 $1
 $1,524
Business Metrics               
MWh sold (thousands)(d)(e)
16,380
 8,951
     977
 1,744
    
MWh generated (thousands) (f)
14,927
 6,426
     977
 2,372
    
(a) Includes International, BETM and Generation eliminations.
(b) Renewables other revenue includes $5 million of intercompany revenue to NRG Yield.
(c) Includes purchased energy, capacity and emissions credits
(d) MWh sold excludes generation at facilities in the East, West and NRG Yield that generate revenue under capacity agreements.
(e) Does not include thermal MWh of 12 thousand or MWt of 496 thousand for thermal sold by NRG Yield.
(f) Does not include thermal MWh of 125 thousand or MWt of 496 thousand for thermal generated by NRG Yield.
The table below represents the weather metrics for the three months ended September 30, 2017March 31, 2023 and 2016:2022:
 Three months ended March 31,
Weather MetricsTexasEast
West/Services/Other (b)
2023
CDDs (a)
166 54 73 
HDDs (a)
799 2,092 1,159 
2022
CDDs68 42 31 
HDDs1,177 2,404 1,151 
10-year average
CDDs102 40 46 
HDDs978 2,525 1,093 
(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
 Three months ended September 30,       
Weather MetricsGulf Coast East/West        
2017           
CDDs (a)
1,528
 770
        
HDDs (a)
1
 34
        
2016           
CDDs1,655
 806
        
HDDs—
 23
        
10 year average           
CDDs1,617
 705
        
HDDs6
 40
        
(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.

Gross margin decreased $4.0 billion and economic gross margin increased $220 million during the three months ended March 31, 2023, compared to the same period in 2022.


GenerationThe tables below describe the changes in gross margin and economic gross margin by segment:
Generation gross margin decreased $225 million and economic gross margin decreased $102 million, both of which include intercompany sales, during the three months ended September 30, 2017, compared to the same period in 2016:

The table below describes the decrease in Generation gross margin and economic gross margin:

Gulf Coast Region
 (In millions)
Lower gross margin due to a 12% decrease in average realized prices primarily in Texas due to lower hedged power prices$(76)
Lower energy margin due to increased supply cost on load contracts(13)
Lower capacity margin on contract expirations and lower demand(9)
Higher gross margin due to increased generation primarily due to lower unplanned outages16
Other1
Decrease in economic gross margin$(81)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges(71)
Increase in contract and emission credit amortization3
Decrease in gross margin$(149)
East/West
 (In millions)
Lower gross margin due to a 37% decrease in generation driven by lower economic generation due to milder weather conditions and the Will County outage$(28)
Lower gross margin from commercial optimization activities(8)
Higher gross margin due to a 38% increase in PJM capacity volumes coupled with a 140% increase in NY/NE realized capacity prices21
Higher gross margin due to a 12% increase in average realized energy prices due to extreme heat in California and increased pricing during high demand periods in the East10
Lower gross margin by BETM due to higher gains in 2016 on over the counter strategies, offset in small part by higher gains in 2017 on congestion strategies(16)
Decrease in economic gross margin$(21)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges(54)
Decrease in contract and emission credit amortization(1)
Decrease in gross margin$(76)





Retail gross margin and economic gross margin
The following is a discussion of gross margin and economic gross margin for Retail.
 Three months ended September 30,
(In millions except otherwise noted)2017 2016
Retail revenue$1,845
 $1,911
Supply management revenue63
 53
Capacity revenue28
 45
Customer mark-to-market—
 2
Contract amortization1
 1
Operating revenue (a)
1,937
 2,012
Cost of sales (b)
(1,458) (1,485)
Mark-to-market for economic hedging activities(174) (360)
Contract amortization—
 (2)
Gross Margin$305
 $165
Less: Mark-to-market for economic hedging activities, net(174) (358)
Less: Contract and emission credit amortization, net1
 (1)
Economic Gross Margin$478
 $524
    
Business Metrics   
Mass electricity sales volume - GWh - Gulf Coast11,935
 11,996
Mass electricity sales volume - GWh - All other regions1,724
 1,986
C&I electricity sales volume — GWh - All regions5,087
 5,146
Natural gas sales volumes (MDth)241
 172
Average Retail Mass customer count (in thousands) 
2,884
 2,786
Ending Retail Mass customer count (in thousands)2,880
 2,797
Texas
(In millions)
Higher gross margin due to the net effect of:
•increased net revenue rates of $8.75 per MWh, or $160 million, primarily driven by changes in customer term, product and mix; and
•a $5 million decrease in cost to serve the retail load, which was primarily driven by an extended outage at Limestone in 2022 and the more conservative winter hedge profile in the first quarter of 2022, partially offset by higher supply costs
$165 
Lower gross margin due to a decrease in load of 920,000 MWh, or $34 million, from weather, and a decrease in load of 827,000 MWh, or $32 million, driven by attrition and changes in customer mix(66)
Higher gross margin due to market optimization activities3 
(a)Includes intercompany sales of $2 million and $1 million in 2017 and 2016, respectively, representing sales from Retail to the Gulf Coast region.
(b)Includes intercompany purchases
Increase in economic gross margin$102 
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges(524)
Increase in contract and emission credit amortization(3)
Decrease in depreciation and amortization2 
Decrease in gross margin$(423)



53
Draft 4                                                04/21/2023    

East
(In millions)
Lower gross margin due to a decrease in generation and capacity as a result of $365Midwest Generation asset retirements in the second quarter of 2022$(41)
Higher electric gross margin due to higher net revenue rates of $13.00 per MWh, or $175 million, as a result of changes in customer term, product and mix, partially offset by higher supply costs of $7.75 per MWh, or $104 million71 
Lower electric gross margin of $3 million due to a decrease in load of 218,000 MWh from weather, as well as a $3 million decrease due to a reduction in customer count and change in customer mix(6)
Higher natural gas gross margin, including the impact of transportation and storage contract optimization, resulting in lower supply costs of $0.25 per Dth, primarily driven by a decrease in gas costs, totaling $124 million, partially offset by lower net revenue rates from changes in customer term, product and mix of $0.15 per Dth, or $81 million43 
Lower natural gas gross margin from a decrease in volumes, partially offset by an increase in customer count and mix(50)
Lower gross margin primarily due to a 63% decrease in PJM capacity prices(28)
Lower gross margin primarily at Midwest Generation due to a 85% decrease in generation volumes due to dark spread contractions, partially offset by a decrease in supply costs(11)
Lower gross margin from market optimization activities(8)
Other(5)
Decrease in economic gross margin$(35)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges(3,201)
Decrease in contract amortization32 
Decrease in depreciation and amortization47 
Decrease in gross margin$(3,157)

West/Services/Other
(In millions)
Lower natural gas gross margin due to higher supply rates of $1.05 per Dth, or $95 million, partially offset by higher net revenue rates of $0.85 per Dth, or $76 million, and $340changes in customer mix of $3 million$(16)
Higher gross margin from market optimization activities20 
Higher gross margin at Cottonwood due to a reduction in 2017commodity costs16 
Other(4)
Increase in economic gross margin$16 
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges(496)
Increase in contract amortization(1)
Increase in depreciation and 2016, respectively.amortization(3)
Decrease in gross margin$(484)

Retail gross margin increased $140 million and economic gross margin decreased $46 million for
Vivint(a)
(In millions)
Increase due to the acquisition of Vivint$137 
Increase in economic gross margin$137 
Increase in depreciation and amortization(52)
Increase in gross margin$85
(a) Includes results of operations following the three months ended September 30, 2017, compared to the same period in 2016, due to:acquisition date of March 10, 2023

54
 (In millions)
Lower gross margin due to lower rates to customers driven by customer product, term, and mix of $26 million or approximately $1.25 per MWh and higher supply costs of $10 million or approximately $0.50 per MWh driven primarily by an increase in power prices at the time of procurement$(36)
Lower gross margin of $15 million due to a reduction in load of 477,000 MWh partially offset by $4 million in higher margin due to the lower unfavorable impacts of selling back excess supply due to milder weather conditions in 2017 as compared to 2016(11)
Lower gross margin of $9 million due to a reduction in load of 200,000 MWh, and the unfavorable impact of selling back excess supply along with $7 million of customer relief related to the impact of Hurricane Harvey in 2017(16)
Higher gross margin due to higher volumes driven by higher average customer usage and mix17
Decrease in economic gross margin$(46)
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges184
Increase in contract and emission credit amortization2
Increase in gross margin$140
Draft 4                                                04/21/2023    





Mark-to-marketMark-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 and ineffectiveness on cash flow hedges. Total net mark-to-market results increaseddecreased by $63 million$4.2 billion during the three months ended September 30, 2017,March 31, 2023, compared to the same period in 2016.2022.
The breakdown of gains and losses included in operating revenues and operating costs and expenses by regionsegment was as follows:
Three months ended March 31, 2023
(In millions)TexasEastWest/Services/OtherEliminationsTotal
Mark-to-market results in revenue 
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges$— $(13)$9 $(3)$(7)
Reversal of acquired (gain) positions related to economic hedges— (1)— — (1)
Net unrealized gains on open positions related to economic hedges— 49 58 (8)99 
Total mark-to-market gains in revenue$— $35 $67 $(11)$91 
Mark-to-market results in operating costs and expenses  
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges$(79)$(482)$(281)$3 $(839)
Reversal of acquired loss/(gain) positions related to economic hedges7 (28)(3)— (24)
Net unrealized gains/(losses) on open positions related to economic hedges201 (1,280)(101)8 (1,172)
Total mark-to-market gains/(losses) in operating costs and expenses$129 $(1,790)$(385)$11 $(2,035)
 Three months ended March 31, 2022
(In millions)TexasEastWest/Services/OtherEliminationsTotal
Mark-to-market results in revenue    
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges$1 $(22)$30 $(2)$7 
Reversal of acquired loss positions related to economic hedges— 2 — — 2 
Net unrealized (losses) on open positions related to economic hedges(3)(110)(48)19 (142)
Total mark-to-market (losses) in revenue$(2)$(130)$(18)$17 $(133)
Mark-to-market results in operating costs and expenses     
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges$(94)$(261)$(62)$2 $(415)
Reversal of acquired loss/(gain) positions related to economic hedges12 (68)(6)— (62)
Net unrealized gains on open positions related to economic hedges737 1,905 264 (19)2,887 
Total mark-to-market gains in operating costs and expenses$655 $1,576 $196 $(17)$2,410 
 Three months ended September 30, 2017
 Generation        
 Gulf Coast East/West Retail Renewables 
Eliminations(a)
 Total
 (In millions)
Mark-to-market results in operating revenues           
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges$121
 $5
 $—
 $1
 $(68) $59
Net unrealized gains/(losses) on open positions related to economic hedges12
 (5) —
 4
 (44) (33)
Total mark-to-market gains/(losses) in operating revenues$133
 $—
 $—
 $5
 $(112) $26
Mark-to-market results in operating costs and expenses           
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges$(5) $(1) $(127) $—
 $68
 $(65)
Reversal of acquired gain positions related to economic hedges—
 —
 (2) —
 —
 (2)
Net unrealized gains/(losses) on open positions related to economic hedges7
 11
 (45) —
 44
 17
Total mark-to-market gains/(losses) in operating costs and expenses$2
 $10
 $(174) $—
 $112
 $(50)
(a)Represents the elimination of the intercompany activity between Retail and Generation.
 Three months ended September 30, 2016
 Generation        
 Gulf Coast East/West Retail Renewables 
Eliminations(a)
 Total
 (In millions)
Mark-to-market results in operating revenues           
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges$8
 $(1) $—
 $—
 $(77) $(70)
Net unrealized gains/(losses) on open positions related to economic hedges171
 58
 2
 1
 (100) 132
Total mark-to-market gains/(losses) in operating revenues$179
 $57
 $2
 $1
 $(177) $62
Mark-to-market results in operating costs and expenses           
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges$7
 $2
 $(46) $—
 $77
 $40
Reversal of acquired gain positions related to economic hedges—
 (5) (2) —
 —
 (7)
Net unrealized gains/(losses) on open positions related to economic hedges20
 10
 (312) —
 100
 (182)
Total mark-to-market gains/(losses) in operating costs and expenses$27
 $7
 $(360) $—
 $177
 $(149)
(a)Represents the elimination of the intercompany activity between Retail and Generation.

`
Mark-to-market results consist of unrealized gains and losses on contracts that are not yet settled. The settlement of these transactions is reflected in the same revenue or cost caption as the items being hedged.
The reversals of acquired gain or loss positions were valued based upon the forward prices on the acquisition date.


For the three months ended September 30, 2017,March 31, 2023, the $26$91 million gain in operating revenues from economic hedge positions was driven primarily by an increase in the reversal of previously recognized unrealized losses on contracts that settled during the period, partially offset by a decrease in value of open positions as a result of an increasedecreases in natural gas and power prices. The $50 million$2.0 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 natural gas and power prices and the reversal of previously recognized unrealized gains on contracts that settled during the period, partially offsetperiod.
For the three months ended March 31, 2022, the $133 million loss in revenues from economic hedge positions was driven primarily by an increasea decrease in the value of open positions as a result of an increaseincreases in coalnatural gas and power prices.
For the three months ended September 30, 2016, the $62 million The $2.4 billion gain in operating revenuescosts and expenses from economic hedge positions was driven primarily by an increase in the value of open positions as a result of decreasesincreases in natural gas and electricitypower prices, partially offset by the reversal of previously recognized unrealized gains on contracts that settled during the period. The $149 million loss in operating costsperiod and expenses from economic hedge positions was driven primarily by a decrease in value of open positions as a result of decreases in natural gas and ERCOT electricity prices, partially offset by the reversal of previously recognized unrealized losses onacquired contracts that settled during the period.

55
Draft 4                                                04/21/2023    

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, 2017March 31, 2023 and 2016.2022. The realized and unrealized financial and physical trading results are included in operating revenue within the Generation segment.revenue. The Company's trading activities are subject to limits withinbased on the Company's Risk Management Policy and are primarily transacted through BETM.Policy.
 Three months ended March 31,
(In millions)20232022
Trading gains/(losses)
Realized$2 $7 
Unrealized12 (14)
Total trading gains/(losses)$14 $(7)
 Three months ended September 30,
(In millions)2017 2016
Trading (losses)/gains   
Realized$(10) $20
Unrealized(5) (5)
Total trading (losses)/gains$(15) $15




Operations and Maintenance Expense
Operations and maintenance expense is comprised of the following:
 GenerationRetail Renewables NRG Yield Corporate EliminationsTotal
 Gulf Coast 
East/West(a)
     
 (In millions)
Three months ended September 30, 2017$120
 $85
 $56
 $28
 $46
 $3
 $(12)$326
Three months ended September 30, 2016139
 97
 58
 19
 41
 7
 (7)354
(In millions)TexasEastWest/Services/Other
Vivint(a)
EliminationsTotal
Three months ended March 31, 2023$218 $79 $71 $18 $(1)$385 
Three months ended March 31, 2022189 101 47 — (1)336 
(a)Includes International, BETM and generation eliminations of $2 million in 2017 and $1 million in 2016.

(a) Vivint includes results of operations following the acquisition date of March 10, 2023
Operations and maintenance expense decreasedincreased by $28$49 million for the three months ended September 30, 2017,March 31, 2023, compared to the same period in 2016,2022, due to the following:
(In millions)
Increase due to the acquisition of Vivint$18 
Decrease primarily due to Midwest Generation asset retirements in the second quarter of 2022, partially offset by an increase in deactivation costs in the West(9)
Increase in major maintenance expenditures associated with the timing of planned outages at STP as well as the scope and duration of outages at Texas gas facilities and Cottonwood32 
Increase primarily due to higher retail operations costs10 
Decrease in variable operation and maintenance expense due to a reduction in PJM generation volumes in 2023 as compared to 2022(9)
Other7 
Increase in operations and maintenance expense$49 
Other Cost of Operations
Other cost of operations is comprised of the following:
(In millions)TexasEastWest/Services/OtherTotal
Three months ended March 31, 2023$49 $32 $4 $85 
Three months ended March 31, 202242 37 6 85 
Other cost of operations for the three months ended March 31, 2023 was flat, when compared to the same period in 2022, with fluctuations within other cost of operations shown below:
(In millions)
Increase due to higher property insurance premiums$8 
Decrease in retail gross receipt taxes due to lower revenues in the East(7)
Other(1)
Change in other cost of operations$— 


56
 (In millions)
Decrease in operation and maintenance expenses due to a reduction in normal maintenance at various gas and coal facilities in Texas$(18)
Decrease in operation and maintenance expenses primarily due to major maintenance activities and environmental work at Midwest Generation in 2016(11)
Other1
 $(28)
Draft 4                                                04/21/2023    
Selling, General
Depreciation and AdministrativeAmortization
Selling, generalDepreciation and administrative expensesamortization are comprised of the following:
(In millions)TexasEastWest/Services/Other
Vivint(a)
CorporateTotal
Three months ended March 31, 2023$75 $30 $24 $52 $9 $190 
Three months ended March 31, 202277 77 21 — 8 183 
 Generation Retail Renewables NRG Yield Corporate Total
 (In millions)
Three months ended September 30, 2017$42
 $112
 $14
 $4
 $41
 $213
Three months ended September 30, 201664
 137
 12
 4
 60
 277
(a) Vivint includes results of operations following the acquisition date of March 10, 2023
Selling, generalDepreciation and administrative expenses decreasedamortization increased by $64$7 million for the three months ended September 30, 2017,March 31, 2023, compared to the same period in 2016. The decrease2022, primarily due to higher amortization of intangible assets due to the acquisition of Vivint in year over year expenses isMarch 2023, partially offset by lower depreciation at Midwest Generation as a result of asset impairments and retirements in 2022.
Selling, General and Administrative Costs
Selling, general and administrative costs are comprised of the following:
(In millions)TexasEastWest/Services/Other
Vivint(a)
CorporateTotal
Three months ended March 31, 2023$170 $149 $51 $50 $6 $426 
Three months ended March 31, 2022146 132 57 — 12 347 
(a) Vivint includes results of operations following the acquisition date of March 10, 2023
Selling, general and administrative costs increased by $79 million for the three months ended March 31, 2023, compared to the same period in 2022, due primarily to a reduction inthe following:
(In millions)
Increase due to the acquisition of Vivint$50 
Increase due to higher personnel costs20 
Increase in broker fee and commission expenses9 
Increase due to higher provision for credit losses primarily related to deteriorated customer payment behavior7 
Decrease due to lower consulting and legal expenses(5)
Other(2)
Increase in selling, general and administrative costs$79 
Acquisition-Related Transaction and Integration Costs
Acquisition-related transaction and integration costs and selling and marketing activities as the Company continues to focus on cost management.
Reorganization
Reorganization expenses of $18$71 million were incurred during the third quarterthree months ended March 31, 2023, which consisted of 2017$36 million of acquisition costs and $30 million of integration costs related to Vivint, as well as $5 million of integration costs related to Direct Energy.
Acquisition-related transaction and integration costs of $8 million were incurred during the Transformation Plan announcedthree months ended March 31, 2022, which are comprised primarily of integration costs related to Direct Energy.
Gain/(Loss) on July 12, 2017.Sale of Assets
LossThe gain on Debt Extinguishment
A loss on debt extinguishmentsale of $50assets of $199 million was recorded for the three months ended September 30, 2016, primarily driven byMarch 31, 2023 was related to the repurchasesale of NRG Senior Notes at a price above par value, combined withland and related assets from the write-off of unamortized debt issuance costs.Astoria site.

Other Income, Net

Interest Expense
NRG's interest expense decreasedOther income, net increased by $16 million for the three months ended September 30, 2017,March 31, 2023, compared to the same period in 2016 due to the following:2022, primarily driven by higher interest income.
 (In millions)
Decrease due to the repurchase of Senior Notes in 2016 of $25 million, partly offset by Senior Notes issued in 2016 of $7 million$(18)
Decrease due to termination of swaps related to 2016 Capistrano debt refinancing(16)
Increase due to the issuance of Carlsbad Energy Project debt during 2017, and Utah Portfolio debt, due 2022, during 20168
Increase in derivative interest expense from changes in fair value of interest rate swaps4
Increase due to the issuance of Yield Operating Senior Notes, due 20263
Other3
 $(16)
Income TaxInterest Expense
For the three months ended September 30, 2017, NRG recorded income taxInterest expense of $6increased by $45 million on pre-tax income of $196 million. For the same period in 2016, NRG recorded income tax expense of $28 million on pre-tax income of $156 million. The effective tax rate was 3.1% and 17.9% for the three months ended September 30, 2017 and 2016, respectively.
For the three months ended September 30, 2017, NRG's overall effective tax rate was different then the statutory rate of 35% primarily due to the tax benefit for the change in valuation allowance and the generation of PTCs and ITCs from various wind and solar facilities, respectively, partially offset by the inclusion of consolidated partnerships and current state tax expense.
For the three months ended September 30, 2016, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the tax benefit for the change in valuation allowance, partially offset by amortization of indefinite lived assets, inclusion of consolidated partnerships and state tax expense.
(Loss)/Income from Discontinued Operations, Net of Income Tax Expense/(Benefit)
For the three months ended September 30, 2017, NRG recorded loss from discontinued operations, net of income tax expense/(benefit) of $27 million.
For the three months ended September 30, 2016, NRG recorded income from discontinued operations, net of income tax expense/(benefit) of $265 million.




Management’s discussion of the results of operations for the nine months ended September 30, 2017, and 2016
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, 2017, and 2016. Average on-peak power prices increased primarily due to the increase in natural gas prices for the nine months ended September 30, 2017 asMarch 31, 2023, compared to the same period in 2016.
 Average on Peak Power Price ($/MWh)
 Nine months ended September 30,
Region2017
2016 Change %
Gulf Coast (a)
     
ERCOT - Houston (b)
$35.61
 $25.97
 37 %
ERCOT - North(b)
26.64
 24.14
 10 %
MISO - Louisiana Hub(c)
42.33
 33.47
 26 %
East/West    
    NY J/NYC(c)
37.46
 35.04
 7 %
    NEPOOL(c)
33.11
 33.80
 (2)%
    PEPCO (PJM)(c)
35.65
 38.15
 (7)%
    PJM West Hub(c)
33.30
 33.95
 (2)%
CAISO - NP15(c)
33.82
 29.38
 15 %
CAISO - SP15(c)
33.42
 30.22
 11 %
(a) Gulf Coast region also transacts in PJM - West Hub.
(b) Average on peak power prices based on real time settlement prices as published by the respective ISOs.
(c) Average on peak power prices based on day ahead settlement prices as published by the respective ISOs.

The following table summarizes average realized power prices for each region in which NRG operates for the nine months ended September 30, 2017, and 2016, which reflects the impact of settled hedges.
 Average Realized Power Price ($/MWh)
 Nine months ended September 30,
Region2017 2016 Change %
Gulf Coast$34.42
 $39.52
 (13)%
East/West40.33
 42.38
 (5)%
Though the average on peak power prices have increased on average by 7%, average realized prices by region for the Company have generally fluctuated at a slower rate year-over-year2022, primarily due to the Company's multi-year hedging program.

Gross Margin
The Company calculates gross margin in order to evaluate operating performance as operating revenues less costVivint acquisition including newly issued Senior Secured First Lien Notes, acquired debt of sales, which includes cost of fuel, other costs of sales, contract and emission credit amortization and mark-to-market for economic hedging activities.
Economic Gross Margin
In addition to gross margin, the Company evaluates its operating performance using the measure of economic gross margin, which is not a GAAP measure and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Economic gross margin should be viewed as a supplement to and not a substitute for the Company's presentation of gross margin, which is the most directly comparable GAAP measure. Economic gross margin is not intended to represent gross margin. The Company believes that economic gross margin is useful to investors as it is a key operational measure reviewed by the Company's chief operating decision maker. Economic gross margin is defined as the sum of energy revenue, capacity revenue, retail revenue and other revenue, less cost of fuels and other cost of sales.
Economic gross margin does not include mark-to-market gains or losses on economic hedging activities, contract amortization, emission credit amortization, or other operating costs.


The below tables present the composition and reconciliation of gross margin and economic gross margin for the nine months ended September 30, 2017 and 2016:
 Nine months ended September 30, 2017
 Generation          
(In millions)Gulf Coast 
East/West(a)
 Subtotal Retail Renewables NRG Yield Corporate/Eliminations Total
Energy revenue$1,408
 $651
 $2,059
 $—
 $298
 $436
 $(885) $1,908
Capacity revenue207
 438
 645
 —
 1
 256
 (8) 894
Retail revenue—
 —
 —
 4,875
 —
 —
 5
 4,880
Mark-to-market for economic hedging activities174
 4
 178
 —
 8
 —
 (1) 185
Contract amortization11
 —
 11
 —
 (1) (52) 1
 (41)
Other revenue (b)
143
 36
 179
 —
 58
 127
 (58) 306
Operating revenue1,943
 1,129
 3,072
 4,875
 364
 767
 (946) 8,132
Cost of fuel(790) (293) (1,083) (8) (3) (24) 48
 (1,070)
Other cost of sales(c)
(259) (203) (462) (3,661) (8) (21) 860
 (3,292)
Mark-to-market for economic hedging activities(22) 7
 (15) (154) —
 

 1
 (168)
Contract and emission credit amortization(21) (3) (24) —
 —
   —
 (24)
Gross margin$851
 $637
 $1,488
 $1,052
 $353
 $722
 $(37) $3,578
Less: Mark-to-market for economic hedging activities, net152
 11
 163
 (154) 8
 —
 —
 17
Less: Contract and emission credit amortization, net(10) (3) (13) —
 (1) (52) 1
 (65)
Economic gross margin$709
 $629
 $1,338
 $1,206
 $346
 $774
 $(38) $3,626
Business Metrics               
MWh sold (thousands)(d)(e)
40,908
 16,140
     2,940
 5,295
    
MWh generated (thousands) (f)
37,975
 10,202
     2,940
 6,467
    
(a) Includes International, BETM and Generation eliminations.
(b) Renewables other revenue includes $21 million of intercompany revenue to NRG Yield.
(c) Includes purchased energy, capacity and emissions credits.
(d) MWh sold excludes generation at facilities in the East, West and NRG Yield that generate revenue under capacity agreements.
(e) Does not include thermal MWh of 27 thousand or MWt of 1,450 thousand for thermal sold by NRG Yield.
(f) Does not include thermal MWh of 80 thousand or MWt of 1,450 thousand for thermal generated by NRG Yield.


 Nine months ended September 30, 2016
 Generation          
(In millions)Gulf Coast 
East/West(a)
 Subtotal Retail Renewables NRG Yield Corporate/Eliminations Total
Energy revenue$1,598
 $896
 $2,494
 $—
 $303
 $459
 $(778) $2,478
Capacity revenue222
 468
 690
 —
 —
 256
 (9) 937
Retail revenue—
 —
 —
 4,918
 —
 —
 13
 4,931
Mark-to-market for economic hedging activities(270) (9) (279) —
 —
 —
 (81) (360)
Contract amortization11
 —
 11
 —
 (1) (51) —
 (41)
Other revenue (b)
182
 75
 257
 —
 34
 125
 (33) 383
Operating revenue1,743
 1,430
 3,173
 4,918
 336
 789
 (888) 8,328
Cost of fuel(718) (371) (1,089) (5) (3) (25) 114
 (1,008)
Other cost of sales(c)
(309) (245) (554) (3,628) (9) (23) 696
 (3,518)
Mark-to-market for economic hedging activities62
 8
 70
 150
 —
 —
 81
 301
Contract and emission credit amortization(22) (4) (26) (5) —
 (6) 3
 (34)
Gross margin$756
 $818
 $1,574
 $1,430
 $324
 $735
 $6
 $4,069
Less: Mark-to-market for economic hedging activities, net(208) (1) (209) 150
 —
 —
 —
 (59)
Less: Contract and emission credit amortization, net(11) (4) (15) (5) (1) (57) 3
 (75)
Economic gross margin$975
 $823
 $1,798
 $1,285
 $325
 $792
 $3
 $4,203
Business Metrics               
MWh sold (thousands)(d)(e)
40,433
 21,141
     2,968
 5,563
    
MWh generated (thousands) (f)
36,427
 13,732
     2,968
 6,828
    
(a) Includes International, BETM and Generation eliminations.
(b) Renewables other revenue includes $13 million of intercompany revenue to NRG Yield.
(c) Includes purchased energy, capacity and emissions credits
(d) MWh sold excludes generation at facilities in the East, West and NRG Yield that generate revenue under capacity agreements.
(e) Does not include thermal MWh of 61 thousand or MWt of 1,497 thousand for thermal sold by NRG Yield.
(f) Does not include thermal MWh of 248 thousand or MWt of 1,497 thousand for thermal generated by NRG Yield.

The table below represents the weather metrics for the nine months ended September 30, 2017 and 2016:
 Nine months ended September 30,         
Weather MetricsGulf Coast East/West          
2017             
CDDs (a)
2,653
 1,071
          
HDDs (a)
674
 2,041
          
2016             
CDDs2,605
 1,098
          
HDDs984
 2,046
          
10 year average             
CDDs2,656
 976
          
HDDs1,167
 2,277
          
(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.



Generation gross margin and economic gross margin
Generation gross margin decreased $86 million and economic gross margin decreased $460 million, both of which include intercompany sales, during the nine months ended September 30, 2017, compared to the same period in 2016:

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

Gulf Coast Region
 (In millions)
Lower gross margin due to a 12% decrease in average realized prices primarily in Texas due to lower hedged power prices$(225)
Lower energy margin due to increased supply costs on load contracts(39)
Lower capacity margin on contract expirations and lower demand(29)
Lower gross margin due to a 42% decrease in ISO capacity prices and a 58% decrease in volume(18)
Lower gross margin from a 7% decrease in nuclear generation driven by the timing of planned outages(17)
Higher gross margin primarily due to 19% higher coal generation mainly in Texas driven by timing of planned outages59
Other3
Decrease in economic gross margin$(266)
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges360
Increase in contract and emission credit amortization1
Increase in gross margin$95

East/West
 (In millions)
Lower gross margin due to a 14% decrease in generation driven by lower economic generation due to milder weather conditions and the Will County outage$(60)
Lower gross margin by BETM due to higher gains in 2016 on over the counter strategies, offset in small part by higher gains in 2017 on congestion strategies(45)
Lower gross margin from commercial optimization activities(39)
Lower gross margin due to lower load contracted prices coupled with slightly lower volumes(26)
Lower gross margin due to a 16% decrease in capacity pricing in New York of $10 million coupled with decreases in capacity pricing and volumes due to the Long Beach capacity toll expiration and unit retirements in California(23)
Other(1)
Decrease in economic gross margin$(194)
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges12
Increase in contract and emission credit amortization1
Decrease in gross margin$(181)





Retail gross margin and economic gross margin
The following is a discussion of gross margin and economic gross margin for Retail.
 Nine months ended September 30,
(In millions except otherwise noted)2017 2016
Retail revenue$4,658
 $4,727
Supply management revenue147
 117
Capacity revenue70
 74
Operating revenue (a)
4,875
 4,918
Cost of sales (b)
(3,669) (3,633)
Mark-to-market for economic hedging activities(154) 150
Contract amortization—
 (5)
Gross Margin$1,052
 $1,430
Less: Mark-to-market for economic hedging activities, net(154) 150
Less: Contract and emission credit amortization, net—
 (5)
Economic Gross Margin$1,206
 $1,285
    
Business Metrics   
Mass electricity sales volume - GWh - Gulf Coast28,153
 27,382
Mass electricity sales volume - GWh - All other regions4,722
 5,264
C&I electricity sales volume — GWh - All regions (c)
15,228
 14,357
Natural gas sales volumes (MDth)1,941
 1,423
Average Retail Mass customer count (in thousands)2,857
 2,770
Ending Retail Mass customer count (in thousands)2,880
 2,797
(a)Includes intercompany sales of $4 million and $3 million in 2017 and 2016, respectively, representing sales from Retail to the Gulf Coast region.
(b)Includes intercompany purchases of $830 million and $655 million in 2017 and 2016.
(c)Includes volumes for 2017 for one customer that self-supplied their volumes during the first six months of 2016.

Retail gross margin decreased $378 million and economic gross margin decreased $79 million for the nine months ended September 30, 2017, compared to the same period in 2016, due to:
 (In millions)
Lower gross margin due to lower rates to customers driven by customer product, term, and mix of $95 million or approximately $2 per MWh, partially offset by lower supply costs of $5 million or approximately $0.10 per MWh driven primarily by a decrease in power prices at the time of procurement$(90)
Lower gross margin of $9 million due to a reduction in load of 200,000 MWh, and the unfavorable impact of selling back excess supply along with $7 million of customer relief related to the impact of Hurricane Harvey in 2017(16)
Lower gross margin of $13 million due to a reduction in load of 420,000 MWh and $2 million in lower margin due to the unfavorable impacts of selling back excess supply due to milder weather conditions in 2017 as compared to 2016(15)
Higher gross margin due to higher volumes driven by higher average customer usage and mix42
Decrease in economic gross margin$(79)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges(304)
Increase in contract and emission credit amortization5
Decrease in gross margin$(378)




Renewables gross margin and economic gross margin
Renewables gross margin increased $29 million and economic gross margin increased $21 million for the nine months ended September 30, 2017, compared to the same period in 2016, primarily driven by new distributed generation solar projects placed in service, increased margin in operations and maintenance agreements and receipt of insurance proceeds offsetting lower volume at the Ivanpah solar plant.
NRG Yield gross margin and economic gross margin
NRG Yield gross margin decreased $13 million and economic gross margin decreased by $19 million during the nine months ended September 30, 2017, compared to the same period in 2016, due to a 4% decrease in volume generated at wind projects, primarily in connection with lower wind resources at the Alta Wind and NRG Wind TE Holdco projects, as well as 5% decrease in solar generation, primarily at CVSR in connection with lower insolation.
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 and ineffectiveness on cash flow hedges. Total net mark-to-market results increased by $76 million during the nine months ended September 30, 2017, compared to the same period in 2016.
The breakdown of gains and losses included in operating revenues and operating costs and expenses by region was as follows:
 Nine months ended September 30, 2017
 Generation        
 Gulf Coast East/West Retail Renewables 
Eliminations(a)
 Total
 (In millions)
Mark-to-market results in operating revenues           
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges$113
 $(32) $(1) $1
 $21
 $102
Net unrealized gains/(losses) on open positions related to economic hedges61
 36
 1
 7
 (22) 83
Total mark-to-market gains/(losses) in operating revenues$174
 $4
 $—
 $8
 $(1) $185
Mark-to-market results in operating costs and expenses           
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges$(12) $1
 $(51) $—
 $(21) $(83)
Reversal of acquired gain positions related to economic hedges—
 —
 (1) —
 —
 (1)
Net unrealized (losses)/gains on open positions related to economic hedges(10) 6
 (102) —
 22
 (84)
Total mark-to-market (losses)/gains in operating costs and expenses$(22) $7
 $(154) $—
 $1
 $(168)
(a)Represents the elimination of the intercompany activity between Retail and Generation.


 Nine months ended September 30, 2016
 Generation       
 Gulf Coast East/West Retail Renewables 
Eliminations(a)
 Total
 (In millions)
Mark-to-market results in operating revenues           
Reversal of previously recognized unrealized gains on settled positions related to economic hedges$(260) $(68) $(1) $—
 $—
 $(329)
Net unrealized (losses)/gains on open positions related to economic hedges(10) 59
 1
 —
 (81) (31)
Total mark-to-market losses in operating revenues$(270) $(9) $—
 $—
 $(81) $(360)
Mark-to-market results in operating costs and expenses           
Reversal of previously recognized unrealized losses on settled positions related to economic hedges$26
 $10
 $218
 $—
 $—
 $254
Reversal of acquired gain positions related to economic hedges—
 (10) (1) —
 —
 (11)
Net unrealized gains/(losses) on open positions related to economic hedges36
 8
 (67) —
 81
 58
Total mark-to-market gains in operating costs and expenses$62
 $8
 $150
 $—
 $81
 $301
(a)Represents the elimination of the intercompany activity between Retail and Generation.

Mark-to-market results consist of unrealized gains and losses on contracts that are not yet settled. The settlement of these transactions is reflected in the same revenue or cost caption as the items being hedged.
The reversals of acquired gain or loss positions were valued based upon the forward pricesVivint, borrowings on the acquisition date.
ForRevolving Credit Facility and the nine months ended September 30, 2017, the $185 million gain in operating revenues from economic hedge positions was driven primarily by the reversal of previously recognized unrealized losses on contracts that settled during the period, as well as an increase in value of open positions as a result of decreases in PJM power prices, New York capacity prices, and natural gas prices. The $168 million loss in operating costs and expenses from economic hedge positions was driven primarily by the decrease in value of open positions as a result of decreases in coal, natural gas, and ERCOT power prices,Receivables Securitization Facilities as well as the reversal of previously recognized unrealized gains on contracts that settled during the period.
For the nine months ended September 30, 2016, the $360 million loss in operating revenues from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period. The $301 million gain in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized losses on contracts that settled during the period, as well as the increase in value of open positions as a result of increases in natural gas prices.
In accordance with ASC 815, the following table represents the resultswrite-off of the Company's financial and physical tradingdeferred financing costs associated with the cancellation of energy commoditiesthe bridge facility for the nine months ended September 30, 2017, and 2016. The realized and unrealized financial and physical trading results are included in operating revenue within the Generation segment. The Company's trading activities are subject to limits within the Company's Risk Management Policy and are primarily transacted through BETM.Vivint acquisition.

57
Draft 4                                                04/21/2023    

 Nine months ended September 30,
(In millions)2017 2016
Trading gains/(losses)   
Realized$18
 $67
Unrealized(7) 27
Total trading gains$11
 $94



Operations and Maintenance Expense
 GenerationRetail Renewables NRG Yield Corporate EliminationsTotal
 Gulf Coast 
East/West(a)
     
 (In millions) 
Nine months ended September 30, 2017$370
 $284
 $170
 $91
 $143
 $12
 $(32)$1,038
Nine months ended September 30, 2016419
 374
 178
 93
 134
 19
 (21)1,196
(a)Includes International, BETM and generation eliminations of $3 million in 2017 and $4 million in 2016.

Operations and maintenance expense decreased by $158 million for the nine months ended September 30, 2017, compared to the same period in 2016, due to the following:
 (In millions)
Decrease in operation and maintenance expenses due to major maintenance activities and environmental control work at Midwest Generation in 2016$(68)
Decrease in operation and maintenance expenses due to lower expenses at Big Cajun II in 2017(26)
Decrease in operation and maintenance expenses due to the deactivation of the Huntley and Dunkirk facilities in 2016(16)
Decrease in operation and maintenance expenses due to a reduction in normal maintenance at various gas and coal facilities in Texas(15)
Decrease in Retail operation and maintenance expenses due to reduced headcount(8)
Decrease in operations and maintenance expenses related to outage work at Arthur Kill in 2016(6)
Decrease in operations and maintenance expenses due to a reduction in headcount related to the sale of the Engine Services business(4)
Other(15)
 $(158)

Selling, General and Administrative
Selling, general and administrative expenses are comprised of the following:
 Generation Retail Renewables NRG Yield Corporate Total
 (In millions)
Nine months ended September 30, 2017$155
 $337
 $43
 $16
 $146
 $697
Nine months ended September 30, 2016195
 362
 43
 10
 191
 801
Selling, general and administrative expenses decreased by $104 million for the nine months ended September 30, 2017, compared to the same period in 2016. The decrease in year over year expenses is due primarily to a reduction in personnel costs and selling and marketing activities as the Company continues to focus on cost management.
Reorganization
Reorganization expenses of $18 million were incurred during the third quarter of 2017 related to the Transformation Plan announced on July 12, 2017.
Loss on Sale of Assets
During the nine months ended September 30, 2016, the Company sold a majority interest in its EVgo business to Vision Ridge Partners, as described in Note 3, Discontinued Operations, Dispositions and Acquisitions, of this Form 10-Q, which resulted in a loss on sale of $79 million .
Impairment Losses on Investments
For the nine months ended September 30, 2016, the Company recorded other-than-temporary impairment losses of $147 million, which is primarily due to its 50% interest in Petra Nova Parish Holdings, as further described in Note 7, Impairments, of this Form 10-Q.


Loss on Debt Extinguishment
A loss on debt extinguishment of $119 million was recorded for the nine months ended September 30, 2016, primarily driven by the repurchase of NRG Senior Notes at a price above par value, combined with the write-off of unamortized debt issuance costs.
Interest Expense
NRG's interest expense decreased by $26 million for the nine months ended September 30, 2017, compared to the same period in 2016 due to the following:
 (In millions)
Decrease due to the repurchase of Senior Notes in 2016 of $127 million, partly offset by Senior Notes issued in 2016 of $78 million$(49)
Decrease due to termination of swaps related to 2016 Capistrano debt refinancing(16)
Increase due to the issuance of Utah Portfolio debt, due 2022 and CVSR Holdco Notes, due 2037 during 201616
Increase due to the issuance of Carlsbad Energy Project debt and Agua Caliente HoldCo, due 2038 during 201710
Increase in derivative interest expense from changes in fair value of interest rate swaps9
Increase due to the issuance of Yield Operating Senior Notes, due 2026, partially offset by repayment of the Yield Revolving Credit Facility, due 2019 during 20168
Other(4)
 $(26)
Income Tax Expense
For the nine months ended September 30, 2017, NRG recorded income tax expense of $5 million on a pre-tax income of $125 million. For the same period in 2016, NRG recorded income tax expense of $75 million on a pre-tax loss of $17 million. The effective tax rate was 4.0% and (441.2)% for the nine months ended September 30, 2017 and 2016, respectively.
For the nine months ended September 30, 2017, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the tax benefit for the change in valuation allowance and the generation of PTCs and ITCs from various wind and solar facilities, respectively, partially offset by the inclusion of consolidated partnerships and current state tax expense.
For the nine months ended September 30, 2016, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due the amortization of indefinite lived assets, the inclusion of consolidated partnerships, state tax expense and the expense for the change in valuation allowance.
Net loss attributable to noncontrolling interests and redeemable noncontrolling interests
For the nine months ended September 30, 2017 and 2016, net loss attributable to noncontrolling interests and redeemable noncontrolling interests primarily reflects net losses allocated to tax equity investors in tax equity arrangements using the hypothetical liquidation at book value, or HLBV, method, partially offset by NRG Yield, Inc.'s share of net income.
(Loss)/Income from Discontinued Operations, Net of Income Tax (Benefit)/Expense
For the ninethree months ended September 30, 2017, NRG recorded loss from discontinued operations, net ofMarch 31, 2023, an income tax (benefit)/benefit of $336 million was recorded on a pre-tax loss of $1.7 billion. For the same period in 2022, income tax expense of $802 million.
$571 million was recorded on pre-tax income of $2.3 billion. The effective tax rates were a benefit of 20.1% and expense of 24.8% for the three months ended March 31, 2023 and 2022, respectively.
For the ninethree months ended September 30, 2016, NRG recorded income from discontinued operations, netMarch 31, 2023, the effective tax rate was lower than the statutory rate of 21% primarily due to current state tax expense and permanent differences which when applied to year-to-date financial statement losses have an inverted effect and reduce the overall effective income tax (benefit)/expenserate. For the same period in 2022, the effective tax rate was higher than the statutory rate of $256 million.

21% primarily due to state tax expense.


Liquidity and Capital Resources
Liquidity Position
As of September 30, 2017March 31, 2023 and December 31, 2016,2022, NRG's total liquidity, excluding collateral received, wasfunds deposited by counterparties, of approximately $3.4$3.5 billion and $2.4$2.8 billion,, respectively, was comprised of the following:
(In millions)March 31, 2023December 31, 2022
Cash and cash equivalents$407 $430 
Restricted cash - operating6 5 
Restricted cash - reserves26 35 
Total439 470 
Total availability under Revolving Credit Facility and collective collateral facilities(a)
3,094 2,324 
Total liquidity, excluding funds deposited by counterparties$3,533 $2,794 
(In millions)September 30, 2017 December 31, 2016
Cash and cash equivalents:   
NRG excluding NRG Yield$1,044
 $621
NRG Yield and subsidiaries179
 317
Restricted cash - operating124
 56
Restricted cash - reserves (a)
413
 390
Total1,760
 1,384
Total credit facility availability1,604

989
Total liquidity, excluding collateral received$3,364
 $2,373
(a) Total capacity of Revolving Credit Facility and collective collateral facilities was $7.3 billion and $6.4 billion as of March 31, 2023 and December 31, 2022, respectively
(a) Includes reserves primarily for debt service, performance obligations, and capital expenditures.
For the ninethree months ended September 30, 2017,March 31, 2023, total liquidity, excluding collateral funds deposited by counterparties, increased by $1 billion.$739 million. Changes in cash and cash equivalentsequivalent balances are further discussed hereinafter under the heading CashFlow Discussion. Cash and cash equivalents at September 30, 2017March 31, 2023 were predominantly held in money market funds invested in treasury securities, treasury repurchase agreements or government agency debt.bank deposits.
Management believes that the Company's liquidity position and cash flows from operations will be adequate to finance operating and maintenance capital expenditures, to fund dividends, to NRG's common stockholders, and to fund other liquidity commitments. 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.
On July 12, 2017, NRG announced its Transformation Plan, which is described further in Management's DiscussionThe Company remains committed to maintaining a strong balance sheet and Analysiscontinues to work to achieve investment grade credit metrics over time primarily through debt reduction and the realization of Financial Condition and Results of Operations - Executive Summary.growth initiatives.
Credit Ratings
TheOn March 1, 2023, following table summarizesthe Vivint Acquisition financing launch, Standard and Poor's downgraded the Company's issuer credit to BB with a Stable outlook from BB+. There was no change to Moody's and Fitch ratings as of September 30, 2017:at the time.

S&PMoody's
NRG Energy, Inc. BB- StableBa3 Stable
7.625% Senior Notes, due 2018BB-B1
7.875% Senior Notes, due 2021BB-B1
6.25% Senior Notes, due 2022BB-B1
6.625% Senior Notes, due 2023BB-B1
6.25% Senior Notes, due 2024BB-B1
7.25% Senior Notes, due 2026BB-B1
6.625% Senior Notes, due 2027BB-B1
Term Loan Facility, due 2023BB+Baa3
NRG Yield, Inc.BBBa2
5.375% NRG Yield Operating LLC Senior Notes, due 2024BBBa2
5.00% NRG Yield Operating LLC Senior Notes, due 2026BBBa2
On October 6, 2017, Moody's upgraded the NRG rating outlook to positive from stable and affirmed NRG's Ba3 Corporate Family Rating.


Sources of Liquidity
The principal sources of liquidity for NRG's future operating and maintenance capital expenditures are expected to be derived from new and existing financing arrangements, existing cash on hand, cash flows from operations, and cash proceeds from future sales of assets, including sales to NRG Yield, Inc.financing arrangements. As described in Note 8,, Long-term Debt and CapitalFinance Leases, to this Form 10-Q, and Note 12, Debt and Capital Leases, to the Company's 2016 Form 10-K, the Company's financing arrangements consist mainly of the Senior Notes, Convertible Senior Notes, Senior Secured First Lien Notes, Revolving Credit Facility, and tax-exempt bonds. As part of the Senior Notes, theacquisition of Vivint on March 10, 2023, NRG Yield 2019 Convertible Notes, the NRG Yield 2020 Convertible Notes, the NRG Yield Operating LLC senior unsecured notes, the NRG Yield, Inc. revolving credit facility, and project-related financings.
Carlsbad Project Financing
On May 26, 2017, Carlsbad Energy Holdings, LLC entered into a note payable agreement with financial institutions for the issuance of up to $407 million ofacquired Vivint's existing debt, which includes senior secured notes, that bear interest at a rate of 4.12%, and mature on October 31, 2038. As of September 30, 2017, all $407 million of thesesenior notes were outstanding.
Also on May 26, 2017, Carlsbad Energy Holdings, LLC entered into a credit agreement, or the Carlsbad Financing Agreement, with the issuing banks, for a $194 million construction loan, that will convert to a term loan upon completion of the project. The Carlsbad Financing Agreement also includes a letters of credit facility not to exceed aggregate amount of $83 million, and a working capital loan facility with an aggregate principle amount not to exceed $4 million.senior secured term-loan.
ROFO Agreement Expansion and Offer
On February 24, 2017, the Company amended and restated the ROFO Agreement to expand the ROFO assets pipeline with the addition of 234 net MW of utility-scale solar projects. These assets include Buckthorn Solar, a 154 net MW facility located in Texas, and the Hawaii Solar projects, which have a combined capacity of 80 net MW.
On October 17, 2017, the Company offered NRG Yield, Inc. the opportunity to purchase 100% of its ownership interest in Buckthorn Solar pursuant to the ROFO Agreement.
Sale of Assets to NRG Yield, Inc.
On November 1, 2017, NRG completed the sale of a 38 MW solar portfolio primarily comprised of assets from SPP funds, in addition to other projects developed by NRG, to NRG Yield, Inc. for cash consideration of $71 million, plus $3 million in working capital adjustments.
On August 1, 2017, NRG closed on its sale of the remaining 25% interest in NRG Wind TE Holdco, a portfolio of 12 wind projects, to NRG Yield, Inc. for total cash consideration of $44 million. The transaction also includes potential additional payments to NRG dependent on actual energy prices for merchant periods beginning in 2027.
On May 23, 2017, NRG offered NRG Yield, Inc. the opportunity to form a new distributed solar investment partnership enabling up to $50 million in investment by NRG Yield, Inc. In addition, on July 31, 2017, NRG offered NRG Yield, Inc. equity interests in a 38 MW portfolio of distributed and small utility-scale solar assets primarily comprised of assets from NRG's Solar Power Partners, or SPP, funds in addition to other projects developed since the acquisition of SPP. These equity interests are not part of the ROFO Agreement. Both the distributed solar investment partnership and the distributed and small utility-scale solar acquisitions are subject to negotiation and approval by NRG Yield, Inc.'s independent directors. As of September 30, 2017, NRG Yield, Inc has invested $41 million in distributed solar investment partnerships with NRG.
On March 27, 2017, the Company sold (i) a 16% interest in the Agua Caliente solar project, representing ownership of approximately 46 net MW of capacity and (ii) NRG's interests in seven utility-scale solar projects located in Utah representing 265 net MW of capacity which have reached commercial operations to NRG Yield, Inc. NRG Yield Inc. paid cash consideration of $130 million, plus $1 million in working capital adjustments, and assumed non-recourse project debt of approximately $328 million.
2023 Term Loan Facility
On January 24, 2017, NRG repriced the 2023 Term Loan Facility, reducing the interest rate margin by 50 basis points to LIBOR plus 2.25%, the LIBOR floor remains 0.75%. As a result of the repricing, the Company expects interest savings of approximately $9 million in 2017 and approximately $60 million in interest savings over the life of the loan.


First Lien Structure
NRG has granted first liens to certain counterparties on a substantial portion of the Company's assets, excluding assets acquired through EME (including Midwest Generation), assets held by NRG Yield, Inc., and NRG's assets that have project-level financing.  NRG uses the first lien structure to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or gas used as a proxy for power.  To the extent that the underlying hedge positions for a counterparty are out-of-the-money to NRG, the counterparty would have claim under the first lien program.  The first lien program limits the volume that can be hedged, not the value of underlying out-of-the-money positions.  The first lien program does not require NRG to post collateral above any threshold amount of exposure as the lien counterparty’s exposure to NRG is positively correlated to the value of the specified generation assets.  Within the first lien structure, the Company can hedge up to 80% of its coal and nuclear capacity, and 10% of its other assets, with these counterparties for the first 60 months and then declining thereafter.  These volumetric limits, exclude Midwest Generation's coal capacity. The first lien structure is not subject to unwind or termination upon a ratings downgrade of a counterparty and has no stated maturity date.
The Company's first lien counterparties may have a claim on its assets to the extent market prices exceed the hedged prices. As of September 30, 2017, all hedges under the first liens were out-of-the-money on a counterparty aggregate basis.
The following table summarizes the amount of MW hedged against the Company's coal and nuclear assets and as a percentage relative to the Company's coal and nuclear capacity under the first lien structure as of September 30, 2017:
Equivalent Net Sales Secured by First Lien Structure (a)
2017 2018 2019 2020 2021
In MW1,458
 1,093
 —
 —
 —
As a percentage of total net coal and nuclear capacity (b)
27% 20% —% —% —%
(a)Equivalent net sales include natural gas swaps converted using a weighted average heat rate by region.
(b)Net coal and nuclear capacity represents 80% of the Company’s total coal and nuclear assets eligible under the first lien which excludes coal assets acquired in the EME (Midwest Generation) acquisition, assets in NRG Yield, Inc. and NRG's assets that have project level financing.
Uses of Liquidity
The Company's requirements for liquidity and capital resources, other than for operating its facilities, can generally be categorized by the following: (i) commercialmarket operations activities; (ii) debt service obligations;obligations, as described in Note 8, Long-term Debt and Finance Leases; (iii) capital expenditures, including maintenance, repowering, and renewable development, and environmental; and (iv) allocations in connection with acquisition opportunities, debt repayments, return of capitalshare repurchases and dividend payments to stockholders.
Senior Note Redemptions
On October 16, 2017, the Company redeemed $398 million of its 7.625% Senior Notes due 2018 and $206 million of its 7.875% Senior Notes due 2021 for $630 million, which included $14 million in accrued interest. As a result of the senior note redemptions a $12 million loss on debt extinguishment will be recorded in the fourth quarter of 2017. In addition, the Company expects to save approximately $47 million in annualized interest.
Restructuring Support Agreement
Asstockholders, as described in Note 3, Discontinued Operations, Dispositions10, Changes in Capital Structure.

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Vivint Acquisition
On March 10, 2023, the Company completed the acquisition of Vivint. The Company paid $12 per share, or $2.6 billion in cash. The Company funded the acquisition using a combination of $740 million in newly-issued secured corporate debt, $650 million in newly-issued preferred stock, $900 million drawn from its Revolving Credit Facility and Acquisitions, NRG,Receivables Facilities, and cash on hand.
Issuance of 2033 Senior Notes
On March 9, 2023, the GenOn Entities and certain holdersCompany issued $740 million of the GenOn and GenOn Americas Generationaggregate principal amount of 7.000% senior notes due 2033. The 2033 Senior Notes entered into a Restructuring Support Agreement, that provides for a restructuringare senior secured obligations of NRG and recapitalizationare guaranteed by certain of GenOn through a prearranged planits subsidiaries. Interest is paid semi-annually beginning on September 15, 2023 until the maturity date of reorganization. Certain principal terms of the Restructuring Support Agreement include that NRG will provide settlement consideration to GenOn of $261.3 million, which will be paid in cash less any amounts owed to NRG under the intercompany secured revolving credit facility. As of June 30, 2017, GenOn owed NRG approximately $125 million under the intercompany secured revolving credit facility. NRG agreed to provide GenOn with a letter of credit facility during the pendency of the Chapter 11 Cases, to be utilized for required letters of credit in lieu of the intercompany secured revolving credit facility. GenOn can no longer utilize the intercompany secured revolving credit facility and, on July 27, 2017, the letter of credit facility was terminated, as GenOn has obtained a separate letter of credit facility with a third party financial institution. In addition, NRG will retain the pension liability, including payment of approximately $13 million of 2017 pension contributions, for GenOn employees for service provided prior to the completion of the reorganization, which was paid in September 2017. GenOn’s pension liability as of September 30, 2017 was approximately $106 million.March 15, 2033. See Note 1, Basis of Presentation, 8,Long-term Debt and Finance Leases, for further discussion regardingdiscussion.
Series A Preferred Stock
On March 9, 2023, the October 30, 2017 proposed changes to the Restructuring Support Agreement, which includes the retentionCompany issued 650,000 shares of the liability 10.25% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock. See Note 10,Changes in Capital Structure,for GenOn’s post-employment and retiree health and welfare benefits, in an amount up to $25 million, recorded as a liability as of September 30, 2017.


further discussion.
Revolving Credit Facility
On February 14, 2023 (the “Revolving Credit Facility Amendment Effective Date”), the Company amended its Revolving Credit Facility to: (i) increase the existing revolving commitments thereunder by $600 million (the “Incremental Commitment”), (ii) extend the maturity date of a portion of the revolving commitments thereunder to February 14, 2028, (iii) transition the benchmark rate applicable to revolving loans from LIBOR to SOFR and (iv) make certain other amendments to the terms of the Revolving Credit Facility for purposes of, among other things, providing additional flexibility.
On March 13, 2023, the Company amended its Revolving Credit Facility to, among other things, increase the existing revolving commitments by $45 million. As of September 30, 2017,March 31, 2023, there were no cashoutstanding borrowings of $725 million and there were $1.1 billion in letters of credit issued under the Revolving Credit Facility. As of April 30, 2023, there were outstanding borrowings of $650 million and $994 million in letters of credit issued under the Revolving Credit Facility.
Sale of Astoria
On January 6, 2023, the Company closed on the revolver.sale of land and related assets from the Astoria site, within the East region of operations, for initial proceeds of $212 million, subject to transaction fees of $3 million and certain indemnifications. As part of the transaction, NRG entered into an agreement to lease the land back for the purpose of operating the Astoria gas turbines. The lease agreement is expected to terminate by the end of the year.
CommercialMarket Operations
NRG's commercialThe Company's market operations activities require a significant amount of liquidity and capital resources. These liquidity requirements are primarily driven by: (i) margin and collateral posted with counterparties; (ii) margin and collateral required to participate in physical markets and commodity exchanges; (iii) timing of disbursements and receipts (i.e.(e.g., buying fuelenergy before receiving energyretail revenues); and (iv) initial collateral for large structured transactions; and (v) collateral for project development.transactions. As of September 30, 2017, commercial operationsMarch 31, 2023, the Company had total cash collateral outstanding of $274$293 million and $606 million$4.1 billion outstanding in letters of credit to third parties primarily to support its commercial activities for both wholesale and retail transactions.market activities. As of September 30, 2017,March 31, 2023, total collateral held fromfunds deposited by counterparties was $31were $330 million in cash and $17$445 million inof letters of credit.
Future liquidity requirements may change based on the Company's hedging activities and structures, fuel purchases, and future market conditions, including forward prices for energy and fuel and market volatility. In addition, liquidity requirements are dependentdepend on NRG'sthe Company's credit ratings and general perception of its creditworthiness.

First Lien Structure

NRG has granted first liens to certain counterparties on a substantial portion of the Company's assets, subject to various exclusions including NRG's assets that have project-level financing and the assets of certain non-guarantor subsidiaries, to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements. The first lien program does not limit the volume that can be hedged, or the value of underlying out-of-the-money positions. The first lien program also does not require NRG to post collateral above any threshold amount of exposure. The first lien structure is not subject to unwind or termination upon a ratings downgrade of a counterparty and has no stated maturity date.
The Company's first lien counterparties may have a claim on its assets to the extent market prices differ from the hedged prices. As of March 31, 2023, all hedges under the first liens were out-of-the-money on a counterparty aggregate basis.

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The following table summarizes the amount of MW hedged against the Company's coal and nuclear assets and as a percentage relative to the Company's coal and nuclear capacity under the first lien structure as of March 31, 2023:
Equivalent Net Sales Secured by First Lien Structure(a)
2023
In MW460
As a percentage of total net coal and nuclear capacity(b)
11%
(a) Equivalent Net Sales include natural gas swaps converted using a weighted average heat rate by region
(b) Net coal and nuclear capacity represents 80% of the Company’s total coal and nuclear assets eligible under the first lien, which excludes coal assets acquired with Midwest Generation and NRG's assets that have project level financing

Capital Expenditures
The following tables and descriptions summarize the Company's capital expenditures for maintenance, environmental and growth investments for the ninethree months ended September 30, 2017,March 31, 2023, and the currently estimated capital expenditure and growth investmentsexpenditures forecast for the remainder of 2017. 2023.
(In millions)MaintenanceEnvironmental
Growth Investments(a)
Total
Texas$(100)$— $(20)$(120)
West/Services/Other(7)— (2)(9)
Corporate(4)— (8)(12)
Vivint(b)
(1)— — (1)
Total cash capital expenditures for the three months ended March 31, 2023(112)— (30)(142)
Investments— — (49)(49)
Total capital expenditures and investments$(112)$— $(79)$(191)
Estimated capital expenditures and investments for the remainder of 2023(c)
$(438)$(13)$(251)$(702)
 Maintenance Environmental Growth Investments Total
 (In millions)
Generation       
Gulf Coast$73
 $1
 $3
 $77
East/West17
 24
 240
 281
Retail22
 —
 33
 55
Renewables3
 —
 309
 312
NRG Yield21
 —
 2
 23
Corporate 
11
 —
 1
 12
Total cash capital expenditures for the nine months ended September 30, 2017147
 25
 588
 760
     Funding from third party equity partners, cash grants and debt financing, net of fees—
 —
 (815) (815)
     Other investments (a)
—
 —
 95
 95
Total capital expenditures and investments, net of financings147
 25
 (132) 40
        
Estimated capital expenditures for the remainder of 201776
 10
 430
 516
     Funding from third party equity partners, cash grants and debt financing, net of fees—
 —
 (211) (211)
NRG estimated capital expenditures for the remainder of 2017, net of financings$76
 $10
 $219
 $305
(a)Other investments include restricted cash activity.

(a)Includes other investments, acquisitions and integration projects
(b)Vivint includes expenditures following the acquisition date of March 10, 2023
Environmental(c)Estimated capital expenditures — For related to W.A. Parish do not reflect expected insurance recoveries
Growth investments for the ninethree months ended September 30, 2017,March 31, 2023 include expenditures for a small book acquisition, integration operating expenses, as well as the Company's environmental capital expenditures included DSI/ESP upgradesEncina site improvements classified as ARO payments. NRG has completed its demolition activities at the Powerton facilitysite and has begun marketing the Joliet gas conversion to satisfy CPS.
site.
Growth Investments capital expenditures — For the nine months ended September 30, 2017, the Company's growth investment capital expenditures included $245 million for solar projects, $241 million for repowering projects, $65 million for wind projects and $37 million for the Company's other growth projects.
Environmental Capital Expenditures
NRG estimates that environmental capital expenditures from 20172023 through 20212027 required to comply with environmental laws will be approximately $60$42 million, which includes $16 million for Midwest Generation. The increase from last quarter isprimarily driven primarily by the additioncost of the anticipated costs of adding NOx control equipmentcomplying with ELG at certain of the Company's coal units in Connecticut.Texas.
Common Stock Dividends
The following table listsDuring the dividendsfirst quarter of 2023, NRG increased the annual dividend to $1.51 from $1.40 per share and expects to target an annual dividend growth rate of 7%-9% per share in subsequent years. A quarterly dividend of $0.3775 per share was paid on the Company's common stock during the ninethree months ended September 30, 2017:
 Third Quarter 2017 Second Quarter 2017 First Quarter 2017
Dividends per Common Share$0.030
 $0.030
 $0.030
March 31, 2023. On October 18, 2017,April 19, 2023, NRG declared a quarterly dividend on the Company's common stock of $0.03$0.3775 per share, payable Novemberon May 15, 2017,2023 to stockholders of record as of NovemberMay 1, 2017 representing $0.12 on2023.
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 2022 Form 10-K.
Obligations Arising Out of a Variable Interest in an annualized basis.Unconsolidated Entity
The Company's common stockVariable 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 $475 million as of March 31, 2023. This indebtedness may restrict the ability of Ivanpah to issue dividends are subjector distributions to available capital, market conditions,NRG.

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Contractual Obligations and compliance with associated laws, regulationsMarket Commitments
NRG has a variety of contractual obligations and other contractual obligations. The Company expectsmarket commitments that based on current circumstances, comparablerepresent prospective cash dividends will continuerequirements in addition to be paidthe Company's capital expenditure programs, as disclosed in the foreseeable future.


Fuel Repowerings
The table below lists the Company's currently projected repowering2022 Form 10-K. See also Note 8, Long-term Debt and conversion projects. With respect to facilities that are currently operating, the timing of the projects listed below could adversely impact the Company's operating revenues, gross marginFinance Leases, and other operating costs during the period prior to the targeted COD.
Facility
Net Generation Capacity (MW) (b)
Project TypeFuel TypeTargeted COD
Repowerings
Carlsbad Peakers (formerly Encina) Units 1, 2, 3, 4, 5 and GT527
GrowthNatural GasQ4 2018
Puente (formerly Mandalay) Units 1 and 2(a)
262
GrowthNatural GasQ2 2020
Total Fuel Repowerings789
(a) See Regulatory Matters in the Management's DiscussionNote 15, Commitments and AnalysisContingencies, to this Form 10-Q for recent developments ina discussion of new commitments and contingencies that also include contractual obligations and market commitments that occurred during the permitting process that may impact the viability of the Puente project.three months ended March 31, 2023.
(b On June 16, 2017, NRG Texas Power LLC provided notice to BTEC New Albany, LLC that it was exercising its right to terminate the Amended and Restated Membership Interest Purchase Agreement, or MIPA, due to the Bacliff Project, a new peaking facility at the former P.H. Robinson Electric Generating Station, not achieving commercial completion by the contractual expiration date of May 31, 2017. On July 14, 2017, the Company gave notice to BTEC New Albany, LLC that it owes NRG Texas Power LLC approximately $48 million under the terminated MIPA, consisting of $38 million in purchaser incurred costs and $10 million in liquidated damages.






Cash Flow Discussion
The following table reflects the changes in cash flows for the comparative ninethree month periods:
Three months ended March 31,
(In millions)20232022Change
Cash (used)/provided by operating activities$(1,598)$1,676 $(3,274)
Cash used by investing activities(2,350)(80)(2,270)
Cash provided by financing activities2,536 287 2,249 

 Nine months ended September 30,  
 2017 2016 Change
 (In millions)
Net cash used by operating activities$806
 $1,741
 $(935)
Net cash used by investing activities(765) (255) (510)
Net cash provided by financing activities59
 (587) 646
Cash (used)/provided by operating activities
Net Cash Used By Operating Activities
Changes to net cash used(used)/provided by operating activities were driven by:
(In millions)
Changes in cash collateral in support of risk management activities due to change in commodity prices$(3,419)
Increase in operating loss/income adjusted for other non-cash items243 
Decrease in working capital primarily due to lower market pricing and volumes on gas and power(87)
Decrease in other working capital(11)
$(3,274)
 (In millions)
Changes in cash collateral in support of risk management activities due to changes in commodity prices$(364)
Decrease in operating income adjusted for non-cash items(216)
Decrease in other assets and liabilities(127)
Cash used by discontinued operations(105)
Decrease in accounts payable due to lower expenses and the timing of payments in 2017 compared to 2016.(68)
Increase in inventory due to lower generation in 2017, combined with earlier inventory purchases in the fourth quarter of 2015 for anticipated 2016 generation requirements(64)
Other(35)
Decrease in accounts receivable due to the timing of cash receipts in 2017 compared to 201644
 $(935)
Net Cash Used By Investing Activitiesused by investing activities
Changes to net cash used(used)/provided by investing activities were driven by:
(In millions)
Increase in cash paid for acquisitions primarily due to the acquisition of Vivint in March 2023$(2,466)
Increase in proceeds from sale of assets primarily due to the sale of the land and related assets from the Astoria site in January 2023205 
Increase in capital expenditures(82)
Increase from insurance proceeds for property, plant and equipment, net in 202371 
Increase in proceeds from sales of investments in nuclear decommissioning trust fund securities, net of purchases2 
$(2,270)
 (In millions)
Cash used by discontinued operations$(379)
Decrease in maintenance and environmental capital expenditures, offset by an increase in growth capital expenditures(101)
Proceeds from sale of assets in 2016 compared to 2017(48)
Increase in cash paid for acquisitions in 2017 compared to 2016(18)
Other(7)
Net increase in emissions allowances activity43
 $(510)
Net Cash Provided By Financing Activitiesprovided by financing activities
Changes to net cash providedprovided/(used) by financing activities were driven by:
(In millions)
Increase in proceeds from Revolving Credit Facility and Receivables Securitization Facilities in 2023$950 
Increase in proceeds from issuance of long-term debt in 2023731 
Increase in proceeds from issuance of preferred stock in 2023636 
Decrease in net receipts from settlement of acquired derivatives(225)
Increase due to lower payments for share repurchase activity180 
Increase in payments of deferred issuance costs(18)
Decrease due to repayments of long-term debt and finance leases(3)
Increase in payments of dividends to common stockholders(2)
$2,249 


61
 (In millions)
Increase in borrowings, primarily related to Agua Caliente Borrower 1 & 2, 2038 Senior Notes and the Carlsbad Project Financing as well as reduced payments due to repurchases of Senior Notes in 2016$538
Increase due to purchase of preferred stock in 2016226
Increase in cash contributions, net of distributions from non-controlling interest in 2017192
Decrease in debt extinguishment cost98
Decrease in payment of dividends, primarily related to reduction of NRG dividend rate in the first quarter of 201638
Decrease in deferred debt issuance cost27
Decrease in financing element related to acquired derivatives(5)
Payment for affiliate receivable(125)
Cash used by discontinued operations(343)
 $646

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NOLs, Deferred Tax Assets and Uncertain Tax Position Implications, under ASC 740
For the ninethree months ended September 30, 2017,March 31, 2023, the Company had total domestic pre-tax book incomeloss of $112 million$1.5 billion and foreign pre-tax book incomeloss of $13$168 million. As of December 31, 2016,2022, the Company had cumulative domesticU.S. Federal NOL carryforwards of $3.4$8.2 billion, of which $1.2 billion is from GenOn Energy, Inc. and subsidiaries which will begin expiring in 2026do not have an expiration date, and cumulative state NOL carryforwards of $4.9$5.3 billion for financial statement purposes. In addition, NRG also has cumulative foreign NOL carryforwards of $196$382 million, most of which do not have an expiration date. Contingent upon GenOn's emergence from bankruptcy, the Company will recognize an estimated $7.8 billion worthless stock deduction for tax purposes. The NOL balances of $1.2 billion will remain with the GenOn group of companies upon emergence from bankruptcy.
In addition to these amounts, the Companyabove NOLs, NRG has $36a $270 million indefinite carryforward for interest deductions, as well as $393 million of tax effected uncertain tax benefits.credits to be utilized in future years. As of March 31, 2023, additional federal and state NOLs of $2.1 billion and $1.8 billion, respectively, as well as federal carryforward for interest deductions of $739 million, were added with the acquisition of Vivint. As a result of the Company's tax position, including the utilization of federal and state NOLs, and based on current forecasts, NRGthe Company anticipates net income tax payments primarilydue to federal, state and localforeign jurisdictions of up to $25$66 million in 2017.2023.
TheAs of March 31, 2023, the Company has $41 million of tax-effected uncertain federal and state tax benefits, for which the Company has recorded a non-current tax liability of $40$43 million (inclusive of accrued interest) until final resolution is reached with the related taxing authority. The $40 million non-current tax liability for uncertain tax benefits is from positions taken on various state income tax returns, including accrued interest.
NRG is subject to examination by taxing authorities for income tax returns filed in the U.S. federal jurisdiction and various state and foreign jurisdictions including operations located in Australia. The Company is notno longer subject to U.S. federal income tax examinations for years prior to 2015.2019. With few exceptions, state and localCanadian income tax examinations are no longer open for years prior to 2010.2014.
Deferred tax assets and valuation allowance
Net deferred tax balance — As of March 31, 2023 and December 31, 2022, NRG recorded a net deferred tax asset, excluding valuation allowance, of $2.8 billion and $2.0 billion, respectively. The Company believes certain state net operating losses may not be realizable under the more-likely-than-not measurement and as such, a valuation allowance was recorded as of March 31, 2023 and December 31, 2022 as discussed below.
NOL Carryforwards — As of March 31, 2023, the Company had a tax-effected cumulative U.S. NOLs consisting of carryforwards for federal and state income tax purposes of $1.7 billion and $315 million, respectively. Additional federal and state NOLs of $446 million and $70 million, respectively, were added with the acquisition of Vivint. 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 $102 million.
Valuation Allowance — As of March 31, 2023 and December 31, 2022, the Company’s tax-effected valuation allowance was $231 million and $224 million, respectively, consisting of state NOL carryforwards and foreign NOL carryforwards. The valuation allowance was recorded based on the assessment of cumulative and forecasted pre-tax book earnings and the future reversal of existing taxable temporary differences.

Guarantor Financial Information
As of March 31, 2023, the Company's primary foreign operationsoutstanding registered senior notes consisted of $375 million of the 2027 Senior Notes and $821 million of the 2028 Senior Notes as shown in Note 8, Long-term Debt and Finance Leases. These Senior Notes are also no longer subject to examinationguaranteed by local jurisdictionscertain of NRG's current and future 100% owned domestic subsidiaries, or guarantor subsidiaries (the “Guarantors”). See Exhibit 22.1 for years prior to 2010.
Off-Balance Sheet Arrangements
Obligations under Certain Guarantee Contractsa listing of the Guarantors. These guarantees are both joint and several.
NRG conducts much of its business through and certainderives 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 enter intoand 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 arrangementsthe 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 tables below present summarized financial information of NRG Energy, Inc. and the Guarantors in accordance with Rule 3-10 under the normal courseSEC's Regulation S-X. The financial information may not necessarily be indicative of business to facilitate commercialresults of operations or financial position of NRG Energy, Inc. and the Guarantors in accordance with U.S. GAAP.

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The following table presents the summarized statement of operations:
(In millions)Three months ended March 31, 2023
Revenues(a)
$6,542 
Operating loss(b)
(1,467)
Total other expense(97)
Loss from continuing operations before income taxes(1,563)
Net Loss(1,275)
(a)Intercompany transactions with third parties. These arrangements include financialNon-Guarantors of $5 million during the three months ended March 31, 2023
(b)Intercompany transactions with Non-Guarantors including cost of operations of $45 million and performance guarantees, stand-by lettersselling, general and administrative of credit, debt guarantees, surety bonds and indemnifications.$35 million during the three months ended March 31, 2023
Retained or Contingent InterestsThe following table presents the summarized balance sheet information:
NRG does not have any material retained or contingent interests in assets transferred to an unconsolidated entity.
(In millions)March 31, 2023
Current assets(a)
$8,393 
Property, plant and equipment, net1,274 
Non-current assets14,276 
Current liabilities(b)
8,567 
Non-current liabilities12,332 
Obligations Arising Out(a)Includes intercompany receivables due from Non-Guarantors of a Variable Interest in an Unconsolidated Entity
Variable interest in equity investments — As of September 30, 2017, NRG has several investments with an ownership interest percentage of 50% or less in energy and energy-related entities that are accounted for under the equity method of accounting. Several of these investments are variable interest entities for which NRG is not the primary beneficiary. See also Note 9, Variable Interest Entities, or VIEs, to this Form 10-Q.
NRG's pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $616$96 million as of September 30, 2017. This indebtedness may restrict the abilityMarch 31, 2023
(b)Includes intercompany payables due to Non-Guarantors of these subsidiaries to issue dividends or distributions to NRG. See also Note 16, Investments Accounted for by the Equity Method and Variable Interest Entities, to the Company's 2016 Form 10-K.$14 million as of March 31, 2023
Contractual Obligations and Commercial Commitments
NRG has a variety of contractual obligations and other commercial commitments that represent prospective cash requirements in addition to the Company's capital expenditure programs, as disclosed in the Company's 2016 Form 10-K. See also Note 8, Debt and Capital Leases, and Note 15, Commitments and Contingencies, to this Form 10-Q for a discussion of new commitments and contingencies that also include contractual obligations and commercial commitments that occurred during the three and nine months ended September 30, 2017.


Fair Value of Derivative Instruments
NRG may enter into power purchase and sales contracts, fuel purchase contracts and other energy-related financial instruments to mitigate variability in earnings due to fluctuations in spot market prices and to hedge fuel requirements at generation facilitiespower plants or retail load obligations. In addition, in order to mitigate interest rate risk associated with the issuance of the Company's variable rate and fixed rate debt, NRG enters into interest rate swap agreements. The following disclosures aboutIn addition, in order to mitigate foreign exchange rate risk primarily associated with the purchase of USD denominated natural gas for the Company's Canadian business, NRG enters into foreign exchange contract agreements.
Under Vivint Flex Pay, customers pay for smart home products by obtaining financing from a third-party financing provider under the Consumer Financing Program. Vivint pays certain fees to the financing providers and shares in credit losses depending on the credit quality of the customer.
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 provide an update to, and should be readare recognized in conjunction with, Fair Value of Derivative Instruments in Item 7 — Management's Discussion and Analysis of Financial Condition and Results of Operations, of the Company's 2016 Form 10‑K.earnings.

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The tables below disclose the activities that include both exchange and non-exchange traded contracts accounted for at fair value in accordance with ASC 820, Fair Value Measurements and Disclosures, or ("ASC 820.820"). Specifically, these tables disaggregate realized and unrealized changes in fair value; disaggregate estimated fair values at September 30, 2017,March 31, 2023, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at September 30, 2017March 31, 2023. For a full discussion of the Company's valuation methodology of its contracts, see Derivative Fair Value Measurements in Note 5, Fair Value of Financial Instruments.
Derivative Activity Gains/(Losses)(In millions)
Fair Value of Contracts as of December 31, 2022$3,553 
Contracts realized or otherwise settled during the period(871)
Vivint contracts acquired during the period(112)
Changes in fair value(1,063)
Fair Value of Contracts as of March 31, 2023$1,507 
Derivative Activity (Losses)/Gains(In millions)
Fair Value of Contracts as of December 31, 2016$(128)
Contracts realized or otherwise settled during the period21
Changes in fair value(41)
Fair Value of Contracts as of September 30, 2017$(148)
Fair Value of Contracts as of March 31, 2023
(In millions)Maturity
Fair Value Hierarchy (Losses)/Gains1 Year or LessGreater than 1 Year to 3 YearsGreater than 3 Years to 5 YearsGreater than 5 YearsTotal Fair
Value
Level 1$(399)$293 $7 $8 $(91)
Level 2562 514 139 23 1,238 
Level 3(113)96 139 238 360 
Total$50 $903 $285 $269 $1,507 
 Fair Value of Contracts as of September 30, 2017
 Maturity
Fair value hierarchy (Losses)/Gains1 Year or Less Greater than 1 Year to 3 Years Greater than 3 Years to 5 Years Greater than 5 Years 
Total Fair
Value
 (In millions)
Level 1$(34) $(30) $(5) $—
 $(69)
Level 211
 (28) (14) —
 (31)
Level 3(24) (11) (5) (8) (48)
Total$(47) $(69) $(24) $(8) $(148)
The Company has elected to presentdisclose 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 paidposted 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, 2017,March 31, 2023, NRG's net derivative liabilityasset was $148 million,$1.5 billion, a decrease to total fair value of $20 million$2.0 billion as compared to December 31, 2016.2022. This decrease was primarily driven by losses in fair value, largely offset by the roll-off of trades that settled during the period, and Vivint contracts acquired during the period.
Based on a sensitivity analysis using simplified assumptions, the impact of a $0.50 per MMBtu increase or decrease in natural gas prices across the term of the derivative contracts would result in an increasea change of approximately $39 million$1.7 billion in the net value of derivatives as of September 30, 2017. The impact of a $0.50 per MMBtu decrease in natural gas prices across the term of derivative contracts would result in a decrease of approximately $62 million in the net value of derivatives as of September 30, 2017.March 31, 2023.



Critical Accounting Policies and Estimates
NRG's discussion and analysis of the financial condition and results of operations are based upon the condensed consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance as well as the use of estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities. The application of these policies necessarilyappropriate 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.
On an ongoing basis, 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.

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The Company identifies its most critical accounting policiesestimates as those that are the most pervasive and important to the portrayal of the Company's financial position and results of operations, and that require the most difficult, subjective and/or complex judgments by management regarding estimates about matters that are inherently uncertain. NRG's
The Company's critical accounting policies include derivative instruments, income taxesestimates are described in Part II, Item 7, Management's Discussion and valuation allowance for deferred tax assets, impairmentAnalysis of long lived assetsFinancial Condition and investments, goodwill and other intangible assets, and contingencies.
The Company performs its annual testResults of goodwill impairment during the fourth quarter.  The Company tests its long-lived assets for impairment whenever indicators of impairment exist. The Company’s annual budget is utilized to determine the cash flows associated with the Company’s long-lived assets, which incorporates various assumptions, including the Company’s long-term view of natural gas prices and its impact on merchant power prices and fuel costs. The Company’s annual budget process is finalized and approved by the Board of Directors Operations,in the fourth quarter. It is reasonably possible that the updated long term cash flows will not support the carrying value of certain assets, and the Company will be requiredCompany's 2022 Form 10-K. There have been no material changes to test such assets for impairment. This could also have a negative impact on the fair value of the reporting units that have goodwill balances.  This decrease in power prices could also result in an adverse change in the manner that long-lived assets are used, or result in the Company selling an asset before the end of its previously estimated useful life, at a price that is lower than its carrying amount. During the preparation of the budget, the Company noted that management’s view of long term merchant power prices has decreased, and accordingly, it is reasonably possible that certain of the Company's goodwill and/or long-lived assets will be significantly impaired duringcritical accounting estimates since the fourth quarter of 2017.2022 Form 10-K.



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ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
NRG is exposed to several market risks in the Company's normal business activities. Market risk is the potential loss that may result from market changes associated with the Company's retail operations, merchant power generation or with an existing or forecasted financial or commodity transaction.transactions. The types of market risks the Company is exposed to are commodity price risk, interest ratecredit risk, liquidity risk, creditinterest 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 20162022 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 and load serving obligations by entering into various derivative or non-derivative instruments to hedge the variability in future cash flows from forecasted sales and purchases of electricityenergy 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.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, including generation assets, load obligations and bilateral physical and financial transactions, calculated using the VaR model for the three months ending March 31, 2023 and nine months ended September 30, 20172022:
(In millions)20232022
VaR as of March 31,$78 $40 
Three months ended March 31,
Average$72 $37 
Maximum82 57 
Minimum61 27 
The increase in the range of the daily VaR results was primarily due to increased commodity prices and 2016:
(In millions)2017 2016
VaR as of September 30,$40
 $40
Three months ended September 30,   
Average$30
 $59
Maximum40
 72
Minimum25
 40
Nine months ended September 30,   
Average$27
 $58
Maximum40
 72
Minimum20
 40
market volatility during 2023 as compared to 2022. In order to provide additional information, for comparative purposes to NRG's peers, the Company also uses VaR to estimate the potential loss of derivative financial instruments that are subject to mark-to-market accounting. These derivative instruments include transactions that were entered into for both asset management and trading purposes. The VaR for the derivative financial instruments calculated using the diversified VaR model as of September 30, 2017, for the entire term of these instruments entered into for both asset management and trading, was $17$330 million, as of March 31, 2023, primarily driven by asset-backed and hedging transactions.
Credit Risk
Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. NRG is exposed to counterparty credit risk through various activities including wholesale sales, fuel purchases and retail supply arrangements, and retail customer credit risk through its retail load activities. Counterparty credit risk and retail customer credit risk are discussed below. See Note 7, Accounting for Derivative Instruments and Hedging Activities, to this Form 10-Q for discussion regarding credit risk contingent features.
Counterparty Credit Risk
The Company's counterparty credit risk policies are disclosed in its 2022 Form 10-K. As of March 31, 2023, counterparty credit exposure, excluding credit exposure from RTOs, ISOs, registered commodity exchanges and certain long-term agreements, was $1.7 billion and NRG held collateral (cash and letters of credit) against those positions of $554 million, resulting in a net exposure of $1.1 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 52% of the Company's exposure before collateral is expected to roll off by the end of 2024. Counterparty credit exposure is valued through observable market quotes and discounted at a risk free interest rate. The following tables highlight net counterparty credit exposure by industry sector and by counterparty credit quality. Net counterparty credit exposure is defined as the aggregate net asset position for NRG with counterparties where netting is permitted under the enabling agreement and

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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 other71 %
Financial institutions29 
Total as of March 31, 2023100 %
Net Exposure (a)(b)
Category by Counterparty Credit Quality(% of Total)
Investment grade55 %
Non-investment grade/non-rated45 
Total as of March 31, 2023100 %
(a)Counterparty credit exposure excludes uranium and coal transportation contracts because of the unavailability of market prices
(b)The figures in the tables above exclude potential counterparty credit exposure related to RTOs, ISOs, registered commodity exchanges and certain long-term contracts
The Company currently has exposure to two wholesale counterparties in excess of 10% of total net exposure discussed above as of March 31, 2023. 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 March 31, 2023, aggregate credit risk exposure managed by NRG to these counterparties was approximately $1.1 billion for the next five years.
Retail Customer Credit Risk
The Company is exposed to retail credit risk through the Company's retail electricity and gas providers as well as through Vivint, 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.
As of March 31, 2023, the Company's retail customer credit exposure to Home and Business customers was diversified across many customers and various industries, as well as government entities. Current economic conditions may affect the Company’s customers’ ability to pay bills in a timely manner, which could increase customer delinquencies and may lead to an increase in credit losses.

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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 March 31, 2023, a $0.50 per MMBtu decrease in natural gas prices across the term of the marginable contracts would cause an increase in margin collateral posted of approximately $1.15 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 $416 million. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of March 31, 2023.
Interest Rate Risk
NRG is exposed to fluctuations in interest rates through its issuance of variable rate debt. Exposures to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, caps, collars and put or call options. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt obligations when taking into account the combinationcombinations of the variable rate debt and the interest rate derivative instrument. NRG's risk management policies allow the Company to reduce interest rate exposure from variable rate debt obligations.
The Company's project subsidiaries enter In the first quarter of 2023, the Company entered into $1.0 billion of interest rate swaps intendedthrough 2027 to hedge the risks associated with interest rates on non-recourse project level debt. See Note 12, Debt and Capital Leases, of the Company's 2016 Form 10-K for more informationfloating rate on the Company'sTerm Loan acquired with the Vivint acquisition. Additionally, in the first quarter of 2023, the Company entered into a $720 million interest rate swaps.
If all ofswap to hedge the above swaps had been discontinued on September 30, 2017, the Company would have owed the counterparties $43 million. Basedfloating rate on the credit ratings of the counterparties, NRG believes its exposure to credit risk due to nonperformance by counterparties to its hedge contracts to be insignificant.Revolving Credit Facility extending through 2024.
NRG has both long and short-term debt instruments that subject the Company to the risk of loss associated with movements in market interest rates. As of September 30, 2017, a 1% change in variable interest rates would result in a $13.8 million change in interest expense on a rolling twelve month basis.


As of September 30, 2017,March 31, 2023, the fair value and related carrying value of the Company's debt was $17.4$11.6 billion and $17.1$12.4 billion, respectively. NRG estimates that a 1% decrease in market interest rates would have increased the fair value of the Company's long-term debt as of March 31, 2023 by $984$639 million.
LiquidityCurrency Exchange Risk
LiquidityNRG 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 general funding needspurchase and sale of NRG's activitiesgoods and services in the management ofcurrencies other than the Company's assets and liabilities. The Company is currently exposed to additional collateral posting if natural gas prices decline primarily due tofunctional currency or the long natural gas equivalent position at various exchanges used to hedge NRG's retail supply load obligations.
Based onfunctional currency of an applicable subsidiary. NRG hedges a sensitivity analysis for power and gas positions under marginable contracts, a $0.50 per MMBtu change in natural gas prices across the termportion of the marginable contracts would cause a change in margin collateral postedits forecasted currency transactions with foreign exchange forward contracts. As of approximately $164 million as of September 30, 2017, and a 1 MMBtu/MWh change in heat rates for heat rate positions would result in a change in margin collateral posted of approximately $149 million as of September 30, 2017. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of September 30, 2017.
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.March 31, 2023, NRG is exposed to counterparty credit risk through various activities including wholesale sales, fuel purchaseschanges in foreign currency primarily associated with the purchase of U.S. dollar denominated natural gas for its Canadian business and retail supply arrangements, and retail customer credit risk through its retail load activities. See Note 4, Fair Valueentered into foreign exchange contracts with a notional amount of Financial Instruments, to this Form 10-Q for discussions regarding counterparty credit risk and retail customer credit risk, and Note 6, Accounting for Derivative Instruments and Hedging Activities, to this Form 10-Q for discussion regarding credit risk contingent features.$594 million.
Currency Exchange Risk
NRG's foreign earnings and investments may beThe Company is subject to translation exchange rate risk related to the translation of the financial statements of its foreign currencyoperations 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 risk, which NRG generally does not hedge.rates effective during the respective period. As these earningsa result, the Company is exposed to movements in the exchange rates of various currencies against the U.S. dollar, primarily the Canadian and investments are not materialAustralian dollars. A hypothetical 10% appreciation in major currencies relative to NRG's consolidated results, the Company's foreign currency exposure is limited.

U.S. dollar as of March 31, 2023 would have resulted in an decrease of $12 million to net income within the Consolidated Statement of Operations.


ITEM 4 — CONTROLS AND PROCEDURES
Conclusion Regarding the Effectiveness of Disclosure ControlsandProcedures
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’sNRG's internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred in the third quarter of 2017ended March 31, 2023 that materially affected, or are reasonably likely to materially affect, NRG’sNRG's internal control over financial reporting.



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PART II — OTHER INFORMATION
ITEM 1 — LEGAL PROCEEDINGS
For a discussion of material legal proceedings in which NRG was involved through September 30, 2017,March 31, 2023, see Note 15,, Commitments and Contingencies, to this Form 10-Q.

ITEM 1A — RISK FACTORS
Information regardingThe Company's Risk Factors are disclosed in their entirety below, including revisions as a result of the Vivint acquisition.
NRG's risk factors appears in Part I, Item 1A, RiskFactorsare grouped into the following categories: (i) Risks Related to the Acquisition of Vivint; (ii) Risks Related to the Operation of NRG's Business; (iii) Risks Related to Governmental Regulation and Laws; and (iv) Risks Related to Economic and Financial Market Conditions, and the Company's Indebtedness.
Risks Related to the Acquisition of Vivint
The acquisition of Vivint may not achieve its intended results and its integration may disrupt or have a negative impact on the Company’s business.
Achieving the anticipated cost savings and operating efficiencies from the acquisition of Vivint is subject to risks, including whether the businesses of NRG Energy, Inc.and Vivint are integrated in an efficient and effective manner. These risks include, but are not limited to:
•the difficulty of managing and integrating Vivint and its operations;
•difficulties in implementing and maintaining uniform processes, systems, standards, controls, procedures, practices, policies and compensation standards;
•unanticipated issues in integrating information technology, communications, and other systems;
•the possibility of faulty assumptions underlying expectations regarding the integration process;
•the potential impairment of relationships with, and loss of, employees;
•the potential difficulty in managing an increased number of locations and employees;
•difficulty addressing any possible differences in corporate cultures and management philosophies; and
•the effect of any government regulations which relate to the business acquired.
Many of these factors are outside of the Company’s control. Failure to address these risks effectively could result in increased costs, lower-than-expected revenues or income generated by the combined company and diversion of management's time and energy and could have an adverse effect on the Company's business, financial results and prospects.
Risks Related to the Operation of NRG's Business
NRG's financial performance may be impacted by price fluctuations in the retail and wholesale power and natural gas markets, as well as fluctuations in coal and oil markets and other market factors that are beyond the Company's control.
Market prices for power, capacity, ancillary services, natural gas, coal, oil and renewable energy credits are unpredictable and tend to fluctuate substantially. Electric power generally must be produced concurrently with its use. As a result, power prices are subject to significant volatility due to supply and demand imbalances, especially in the day-ahead and spot markets. Long and short-term power and gas prices may also fluctuate substantially due to other factors outside of the Company's control, including:
•changes in generation capacity in the Company’s markets, including the addition of new supplies of power as a result of the development of new plants, expansion of existing plants, the continued operation of uneconomic power plants due to state subsidies, retirement of existing plants or addition of new transmission capacity;
•changes in law, including judicial decisions, environmental regulations and environmental legislation;
•electric supply disruptions, including plant outages and transmission disruptions;
•changes in power and gas transmission infrastructure;
•transportation capacity constraints or inefficiencies;
•weather conditions, including extreme weather conditions and seasonal fluctuations, including the effects of climate change;
•changes in commodity prices and the supply of commodities, including but not limited to natural gas, coal and oil;
•changes in the demand for power or gas, or in patterns of power or gas usage, including the potential development of demand-side management tools and practices, distributed generation, and more efficient end-use technologies;
•development of new fuels, new technologies and new forms of competition for the production of power;
•economic and political conditions; and
•federal, state and provincial power regulations and legislation, and regulations and actions of the ISO and RTOs.
While retail rates are generally designed to allow retail sellers of electricity and natural gas to pass through price fluctuations and other changes to costs, the Company may not be able to pass through all such changes to customers. For

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example, serving retail power customers in ISOs that have a capacity market exposes the Company to the risk that capacity costs can change and may not be recoverable, or the Company may engage in sales of power at fixed prices. Additionally, increases in wholesale costs to retail customers may cause additional customer defaults or increased customer attrition, or may be impacted by regulatory rules.
Further, in low natural gas price environments, natural gas can be the more cost-competitive fuel compared to coal for generating electricity. The Company enters into guaranteed supply contracts to provide for the amount of coal needed to operate its base load coal-fired generating facilities. The Company may experience periods where it holds excess amounts of coal if fuel pricing results in the Company reducing or idling coal-fired generating facilities. In addition, the Company may incur costs to terminate supply contracts for coal in excess of its generating requirements.
Such factors and the associated fluctuations in power prices have affected the Company's wholesale and retail profitability in the past and are expected to continue to do so in the future.
Volatile power and gas supply costs and demand for power and gas could adversely affect the financial performance of NRG's retail operations.
The Company's earnings and cash flows could be adversely affected in any period in which the wholesale power or gas prices rise at a greater rate than the rates the Company can charge to customers. The price of wholesale electricity and gas supply purchases associated with the retail operations' energy commitments can be different than that reflected in the rates charged to customers due to, among other factors:
•varying supply procurement contracts used and the timing of entering into related contracts;
•subsequent changes in the overall price of natural gas;
•daily, monthly or seasonal fluctuations in the price of natural gas relative to the 12-month forward prices;
•transmission and transportation constraints and the Company's ability to move power or gas to its customers; and
•changes in market heat rate (i.e., the relationship between power and natural gas prices).
The Company's earnings and cash flows could also be adversely affected in any period in which its customers' actual usage of electricity or gas significantly varies from the forecasted usage, which could occur due to, among other factors, weather events, changes in usage patterns, competition and economic conditions.
NRG's trading operations and use of hedging agreements could result in financial losses that negatively impact its results of operations, and NRG's hedging activities may increase the volatility in the Company's 2016 Form 10-K,quarterly and Part II, Item 1Aannual financial results.
The Company typically enters into hedging agreements, including contracts to purchase or sell commodities at future dates and at fixed prices, to manage the commodity price risks inherent in its business. The Company’s risk management policies and hedging procedures may not mitigate risk as planned, and the Company may fail to fully or effectively hedge its commodity supply and price risk. In addition, these activities, although intended to mitigate price volatility, expose the Company to other risks. When the Company sells or buys power or gas forward, it gives up the opportunity to buy or sell at the future price, which not only may result in lost opportunity costs but also may require the Company to post significant amounts of cash collateral or other credit support to its counterparties. The Company also relies on counterparty performance under its hedging agreements and is exposed to the credit quality of its counterparties under those agreements. Further, if the values of the financial contracts change in a manner that the Company does not anticipate, or if a counterparty fails to perform under a contract, it could harm the Company's business, operating results or financial position.
NRG does not typically hedge the entire exposure of its operations against commodity price volatility. To the extent it does not hedge against commodity price volatility, the Company's results of operations and financial position may be improved or diminished based upon movement in commodity prices.
NRG may engage in trading activities, including the trading of power, fuel and emissions allowances that are not directly related to the operation of the Company's Form 10-Qgeneration facilities or the management of related risks. These trading activities take place in volatile markets and some of these trades could be characterized as speculative. The Company would expect to settle these trades financially rather than through the production of power or the delivery of fuel. This trading activity may expose the Company to the risk of significant financial losses which could have a material adverse effect on its business and financial condition.
NRG generally attempts to balance its fixed-price physical and financial purchases and sales commitments in terms of contract volumes and the timing of performance and delivery obligations through the use of financial and physical derivative contracts. These derivatives are accounted for in accordance with the quarter ended June 30, 2017. There have been no materialFASB ASC 815, Derivatives and Hedging ("ASC 815"), which requires the Company to record all derivatives on the balance sheet at fair value with changes in the fair value resulting from fluctuations in the underlying commodity prices immediately recognized in earnings, unless the derivative qualifies for

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cash flow hedge accounting treatment or a scope exception. As a result, the Company's quarterly and annual results are subject to significant fluctuations caused by changes in market prices.
Competition may have a material adverse effect on NRG's results of operations, cash flows and the market value of its assets.
The Company's retail operations face competition for customers. Competitors may offer different products, lower prices, and other incentives which may attract customers away from the Company. In some retail electricity markets, the principal competitor may be the incumbent utility. The incumbent utility has the advantage of long-standing relationships with its customers and strong brand recognition. Furthermore, NRG may face competition from other energy service providers, other energy industry participants, or nationally branded providers of consumer products and services, who have, and may in the future, develop businesses and offerings that compete with NRG. In the smart home market, the Company faces competition from residential security companies as well as other companies that are able to bundle their existing offerings, such as cable, telecommunications and internet service, with automation and monitored security services, and from do-it-yourself smart home systems, which customers are able to install without subscription services.
The Company’s plant operations face competition from newer or more efficient plants owned by competitors, which may put some of the Company's plants at a disadvantage to the extent these competitors are able to consume the same or less fuel as the Company's plant. Over time, the Company's plants may be unable to compete with these more efficient plants, which could result in asset retirements.
NRG’s competitors may have greater liquidity, greater access to credit and other financial resources, lower cost structures, more effective risk management policies and procedures, greater ability to incur losses, longer-standing relationships with customers, greater brand awareness, greater potential for profitability from retail sales or greater flexibility in the timing of their sale of generation capacity and ancillary services than NRG does. Competitors may also have better access to subsidies or other out-of-market payments that put NRG at a competitive disadvantage.
NRG's competitors may be able to respond more quickly to new laws or regulations or emerging technologies, or devote greater resources to marketing of retail energy and home services than NRG can. In addition, current and potential competitors may make strategic acquisitions or establish cooperative relationships among themselves or with third parties. Accordingly, it is possible that new competitors or alliances among current and new competitors may emerge and rapidly gain significant market share.
There can be no assurance that NRG will be able to compete successfully against current and future competitors, and any failure to do so would have a material adverse effect on the Company's business, financial condition, results of operations and cash flow.
NRG’s strategy relies, in part, on its ability to cross-serve and optimize its network of retail and smart home services customers, and if it is unable to retain existing customers and expand their use of the Company’s products and services, its expected growth and operating results could be adversely affected.
As part of NRG’s growth strategy, it is important for the Company to cross-sell energy sales and services to smart home services subscribers and smart home services to residential retail customers. While the Company believes there are significant cross-selling opportunities between these customers, there can be no assurances that its efforts in this regard will be successful. Additionally, for the Company to be successful in such cross-selling opportunities, it must retain its existing customers. The length of the terms for which NRG’s retail customers are contracted can be for multi-year periods, but many customers are contracted for a period of one year or less, and smart home services customers historically have entered into subscriptions that range from three to five years. These customers are not obligated to, and may not, renew their contracts or subscriptions after the expirations of their original commitments. Factors that may cause non-renewals include, but are not limited to, customer dissatisfaction with NRG’s products or services, customers’ spending levels and the preference for lower pricing of competitors’ products and services over the Company’s. If customers terminate their contracts, do not renew their contracts or do not expand their use of NRG’s products and services, the Company’s growth strategy may not be successful and its expected results of operations may be adversely affected.
NRG's costs, results of operations, financial condition and cash flows could be adversely impacted by disruption of its fuel supplies.
NRG relies on natural gas, coal and oil to fuel a majority of its power generation facilities. Grid operations depend on the continuing financial viability of contractual counterparties, as well as the infrastructure (including rail lines, rail cars, barge facilities, roadways, riverways and natural gas pipelines) available to serve generation facilities and to ensure that there is sufficient power produced to meet retail demand. As a result, the Company’s wholesale generation facilities are subject to the risks of disruptions or curtailments in the production of power at its generation facilities if no fuel is available at any price, if a counterparty fails to perform or if there is a disruption in the fuel delivery infrastructure.

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NRG routinely hedges both its wholesale sales and purchases to support its retail load obligations. In order to hedge these obligations, the Company may enter into long-term and short-term contracts for the purchase and delivery of fuel. Many of the forward power sales contracts do not allow the Company to pass through changes in fuel costs or discharge the power sale obligations in the case of a disruption in fuel supply due to force majeure events or the default of a fuel supplier or transporter. Disruptions in the Company's fuel supplies or power supply arrangements may therefore require it to supply replacement power either by running its other, higher cost power plants or by obtaining power from third-party sources at market prices that could substantially exceed the contract price, or to pay damages to counterparties for failure to deliver power or sell electricity or natural gas as contracted. Any such event could have a material adverse effect on the Company's financial performance.
NRG also buys significant quantities of energy and fuel on a short-term or spot market basis. Prices sometimes rise or fall significantly over a relatively short period of time. The price NRG can obtain for the sale of energy may not rise at the same rate, or may not rise at all, to match a rise in fuel or delivery costs. Retail rates may also not rise at the same rate or may not rise at all. This may have a material adverse effect on the Company's financial performance.
NRG's plant operating characteristics and equipment, particularly at its coal-fired plants, often dictate the specific fuel quality to be combusted. The availability and price of specific fuel qualities may vary due to supplier financial or operational disruptions, transportation disruptions and force majeure. At times, coal of specific quality may not be available at any price or the Company may not be able to transport such coal to its facilities on a timely basis. In this case, the Company may not be able to run the coal facility even if it would be profitable. Operating a coal facility with different quality coal can lead to emission or operating problems. If the Company had sold forward the power from such a coal facility, it could be required to supply or purchase power from alternate sources, perhaps at a loss. This could have a material adverse impact on the financial results of specific plants and on the Company's results of operations.
There may be periods when NRG will not be able to meet its commitments under forward sale or purchase obligations at a reasonable cost or at all.
The Company may sell fixed price gas as a proxy for power. Because the obligations under most of the Company's forward sale agreements are not contingent on a unit being available to generate power, NRG is generally required to deliver power to the buyer, even in the event of a plant outage, fuel supply disruption or a reduction in the available capacity of the unit. To the extent that the Company does not have sufficient lower-cost capacity to meet its commitments under its forward sale obligations, the Company would be required to supply replacement power either by running its other, higher cost power plants or by obtaining power from third-party sources at market prices that could substantially exceed the contract price. If NRG fails to deliver the contracted power, it would be required to pay the difference between the market price at the delivery point and the contract price, and the amount of such payments could be substantial.
NRG may not have sufficient liquidity to hedge market risks effectively.
The Company is exposed to market risks through its retail and wholesale operations, which involve the purchase of electricity and natural gas for resale, the sale of energy, capacity and related products, and the purchase and sale of fuel, transmission services and emission allowances. These market risks include, among other risks, volatility arising from location and timing differences that may be associated with buying and transporting fuel, converting fuel into energy and delivering energy to a buyer.
NRG undertakes to hedge these market activities through agreements with various counterparties. Many of the Company's agreements with counterparties include provisions that require the Company to provide guarantees, offset or netting arrangements, letters of credit, a first lien on assets and/or cash collateral to protect the counterparties against the risk of the Company's default or insolvency. The amount of such credit support that must be provided typically is based on the difference between the price of the commodity in a given contract and the market price of the commodity. Significant movements in market prices can result in the Company being required to provide cash collateral and letters of credit in very large amounts. The effectiveness of the Company's strategy may depend on the amount of collateral available to enter into or maintain these contracts, and liquidity requirements may be greater than the Company anticipates or will be able to meet. Without a sufficient amount of working capital to post as collateral in support of performance guarantees or as a cash margin, the Company may not be able to manage price volatility effectively or to implement its strategy. An increase in the amount of letters of credit or cash collateral required to be provided to the Company's counterparties may negatively affect the Company's liquidity and financial condition.
Further, if retail customers use more power or gas than expected, or if any of NRG's facilities experience unplanned outages, the Company may be required to procure additional power or gas at spot market prices to fulfill contractual commitments. Without adequate liquidity to meet margin and collateral requirements, the Company may be exposed to significant losses, may miss significant opportunities, and may have increased exposure to the volatility of spot markets.

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NRG relies on storage, transportation assets and suppliers, which it does not own or control, to deliver natural gas.
The Company depends on natural gas pipelines and other transportation and storage facilities owned and operated by third parties to deliver natural gas to wholesale and retail markets and to provide retail energy services to customers. The Company's ability to provide natural gas for its present and projected customers will depend upon its suppliers' ability to obtain and deliver supplies of natural gas, as well as NRG's ability to acquire supplies directly from new sources. Factors beyond the control of the Company and its suppliers may affect the Company's ability to deliver such supplies. These factors sinceinclude other parties' control over the drilling of new wells and the facilities to transport natural gas to the Company's receipt points, development of additional interstate pipeline infrastructure, availability of supply sources competition for the acquisition of natural gas, priority allocations, impact of severe weather disruptions to natural gas supplies and the regulatory and pricing policies of federal and state regulatory agencies, as well as the availability of Canadian reserves for export to the U.S. Energy deregulation legislation may increase competition among natural gas utilities and impact the quantities of natural gas requirements needed for sales service. If supply, transportation or storage is disrupted, including for reasons of force majeure, the ability of the Company to sell and deliver its products and services may be hindered. As a result, the Company may be responsible for damages incurred by its customers, such as the additional cost of acquiring alternative supply at then-current market rates. These conditions could have a material impact on the Company's financial condition, results of operations and cash flows.
Operation of power generation facilities involves significant risks and hazards customary to the power industry that could have a material adverse effect on NRG's revenues and results of operations, and NRG may not have adequate insurance to cover these risks and hazards.
The ongoing operation of NRG's facilities involves risks that include the breakdown or failure of equipment or processes, performance below expected levels of output or efficiency and the inability to transport the Company's products to its customers in an efficient manner due to a lack of transmission capacity. Unplanned outages of generating units, including extensions of scheduled outages due to mechanical failures or other problems occur from time to time and are an inherent risk of the Company's business. Unplanned outages typically increase the Company's operation and maintenance expenses and may reduce the Company's revenues as a result of selling fewer MWh or incurring non-performance penalties and/or require NRG to incur significant costs as a result of obtaining replacement power from third parties in the open market or running one of its higher cost units to satisfy the Company's forward power sales obligations. NRG's inability to operate the Company's plants efficiently, manage capital expenditures and costs, and generate earnings and cash flow from the Company's asset-based businesses could have a material adverse effect on the Company's results of operations, financial condition or cash flows.
In addition, NRG provides plant operations and commercial services to a variety of third parties. There is a risk that mistakes, mis-operations, or actions taken by these third parties could be attributed to NRG, including the risk of investigation or penalties being assessed to NRG in connection with the services it offers, or that regulators could question whether NRG had the appropriate safeguards in place.
Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of rotating equipment and delivering electricity to transmission and distribution systems. In addition to natural risks such as earthquake, flood, lightning, hurricane and wind, other hazards, such as fire, explosion, structural collapse and machinery failure are inherent risks in the Company's operations. These and other hazards can cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment, contamination of, or damage to, the environment and suspension of operations. The occurrence of any one of these events may result in NRG being named as a defendant in lawsuits asserting claims for substantial damages, including for environmental cleanup costs, personal injury and property damage and fines and/or penalties.
NRG maintains an amount of insurance protection that it considers adequate, obtains warranties from vendors and obligates contractors to meet certain performance levels, but the Company cannot provide any assurance that these measures will be sufficient or effective under all circumstances and against all hazards or liabilities to which it may be subject. A successful claim for which the Company is not adequately insured or protected could hurt its financial results and materially harm NRG's financial condition. NRG cannot provide any assurance that its insurance coverage will continue to be available at all or at rates or on terms similar to those reportedpresently available. Any losses not covered by insurance could have a material adverse effect on the Company's financial condition, results of operations or cash flows.
Supplier and/or customer concentration, the inability of suppliers to meet their obligations and dependence on third-party service providers may expose the Company to significant financial credit or performance risks and adversely affect NRG's results of operations, cash flows and financial condition..
NRG often relies on a single contracted supplier or a small number of suppliers for the provision and transportation of fuel, chemicals and other services required for the operation of certain of its facilities. If these suppliers cannot perform these services, the Company utilizes the marketplace. There can be no assurance that the marketplace can provide these services as, when and where required or at comparable prices. The Company also relies on a number of sole or limited source suppliers for

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critical components for its smart home products and services, and those services are dependent on third-party cellular, telecommunications and/or internet providers.
The failure of any supplier or customer to fulfill its contractual obligations to NRG, the inability of NRG to source products and services on acceptable terms, if at all, and the failure of third parties to provide services to its customers that are necessary for the Company’s smart home services could have a material adverse effect on the Company's financial results. As a result, the financial performance of the Company's facilities is dependent on the credit quality of, and continued performance by, suppliers and customers, which cannot be guaranteed.
Maintenance, expansion and refurbishment of power generation facilities involve significant risks that could result in unplanned power outages or reduced output and could have a material adverse effect on NRG's results of operations, cash flows and financial condition.
NRG's facilities require periodic maintenance and repair. Any unexpected failure, including failure associated with breakdowns, forced outages or any unanticipated capital expenditures could result in reduced profitability. NRG cannot be certain of the level of capital expenditures that will be required due to changing environmental and safety laws (including changes in the interpretation or enforcement thereof), needed facility repairs and unexpected events (such as natural disasters or terrorist attacks). The unexpected requirement of large capital expenditures could have a material adverse effect on the Company's liquidity and financial condition.
NRG relies on power transmission and distribution facilities that it does not own or control and that are subject to transmission constraints within a number of the Company's core regions.
NRG depends on transmission and distribution facilities owned and operated by others to deliver power to its customers. If transmission or distribution is disrupted, including by force majeure events, or if the transmission or distribution infrastructure is inadequate, NRG's ability to deliver power may be adversely impacted. The Company also cannot predict whether transmission or distribution facilities will be expanded in specific markets to accommodate competitive access to those markets.
In addition, in certain of the markets in which NRG operates, energy transmission congestion may occur and the Company may be deemed responsible for congestion costs associated with power sales or purchases, or retail sales, particularly where the Company’s load is not co-located with its retail sales obligations. If NRG were liable for such congestion costs, the Company's financial results could be adversely affected.
Rates and terms for service of certain residential and commercial customers in Alberta are subject to regulatory review and approval.
The Company owns Direct Energy Regulated Services, which serves as a regulated rate supplier for residential and commercial energy customers in portions of the province of Alberta. It is required to engage in regulatory approval proceedings as a part of the process of establishing the terms and rates for sales of power and natural gas. These proceedings typically involve multiple parties, including governmental bodies and officials, consumer advocacy groups and various consumers of energy, who have differing concerns but also have the common objective of limiting rate increases or even reducing rates. Decisions are subject to appeal, potentially leading to additional uncertainty associated with the approval proceedings. The potential duration of such proceedings creates a risk that rates ultimately approved by the applicable regulatory body may not be sufficient for the Company to recover its costs by the time the rates become effective. Established rates are also subject to subsequent reviews by regulators, whereby various portions of rates could be adjusted, subject to refund or disallowed. In certain instances, the Company could agree to negotiated settlements related to various rate matters and other cost recovery elements. These settlements are subject to regulatory approval. The ultimate outcome and timing of regulatory rate proceedings have a significant effect on the Company to recover its costs or earn an adequate return. In addition, subsequent legislative or regulatory action could alter the terms on which the regulated business operates and future earnings could be negatively impacted. The Company also operates a competitive energy supply business in Alberta that is not subject to rate regulation and is subject to stringent requirements to segregate operations and information relating to the competitive business from the regulated business. Failure to comply with these and other requirements on the business could subject the Company's regulated and competitive businesses in Alberta to fines, penalties, and restrictions on the ability to continue business.
Because NRG owns less than a majority of the ownership interests of some of its project investments, the Company cannot exercise complete control over their operations.
NRG has limited control over the operation of some project investments and joint ventures because the Company's investments are in projects where it beneficially owns less than a majority of the ownership interests. NRG seeks to exert a degree of influence with respect to the management and operation of projects in which it owns less than a majority of the ownership interests by negotiating to obtain positions on management committees or to receive certain limited governance rights, such as rights to veto significant actions. However, the Company may not always succeed in such negotiations. NRG

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may be dependent on its co-venturers to operate such projects. The Company's co-venturers may not have the level of experience, technical expertise, human resources management or other attributes necessary to operate these projects optimally. The approval of co-venturers also may be required for NRG to receive distributions of funds from projects or to transfer the Company's interest in projects.
Future acquisition or disposition activities could involve unknown risks and may have materially adverse effects and NRG may be subject to trailing liabilities from businesses that it disposes of or that are inactive.
NRG may in the future acquire or dispose of businesses or assets, acquire or sell books of retail customers, or pursue other business activities, directly or indirectly, through subsidiaries that involve a number of risks. The acquisition of companies and assets, and their integration, is subject to substantial risks, including the failure to identify material problems during due diligence, the risk of over-paying for assets or customers, the inability to retain customers and the inability to arrange financing for an acquisition as may be required or desired. Further, the integration and consolidation of acquisitions requires substantial human, financial and other resources and, ultimately, the Company's acquisitions may not be successfully integrated. In the case of dispositions, such risks may relate to employment matters, counterparties, regulators and other stakeholders in the disposed business, the separation of disposed assets from NRG’s business, the management of NRG’s ongoing business, and other financial, legal and operational matters related to such disposition, which may be unknown to NRG at the time. In addition, NRG may be subject to material trailing liabilities from disposed businesses. Any such risk may result in one or more costly disputes or litigation. There can be no assurances that any future acquisitions will perform as expected or that the returns from such acquisitions will support the indebtedness incurred to acquire them or the capital expenditures needed to develop them. There can also be no assurances that NRG will realize the anticipated benefits from any such dispositions. The failure to realize the anticipated returns or benefits from an acquisition or disposition could adversely affect NRG's results of operations, cash flows and financial condition.
The operation of the Company's businesses is subject to advanced persistent cyber-based security threats and integrity risk. Attacks on NRG's infrastructure that breach cyber/data security measures could expose the Company to significant liabilities, reputational damage, regulatory action, and disrupt business operations, which could have a material adverse effect.
Numerous functions affecting the efficient operation of NRG’s businesses depend on the secure and reliable storage, processing and communication of electronic data and the use of sophisticated computer hardware and software systems, much of which is connected (directly or indirectly) to the internet. As a result, NRG's information technology systems and infrastructure, and those of its vendors and suppliers, are susceptible to cyber-based security threats which could compromise confidentiality, integrity or availability. While the Company has controls in place designed to protect its infrastructure, such breaches and threats are becoming increasingly sophisticated and complex, requiring continuing evolution of its program. Any such breach, disruption or similar event that impairs NRG's information technology infrastructure could disrupt normal business operations and affect the Company's ability to control its generation assets, provide smart home services, maintain confidentiality, availability and integrity of restricted data, access retail customer information and limit communication with third parties, which could have a material adverse effect on the Company.
As part of the continuing development of new and modified reliability standards, the FERC has approved changes to its Critical Infrastructure Protection reliability standards and has established standards for assets identified as "critical cyber assets." Under the Energy Policy Act of 2005, the FERC can impose penalties (up to $1 million per day, per violation) for failure to comply with mandatory electric reliability standards, including standards to protect the power system against potential disruptions from cyber/data and physical security breaches.
Further, the Company's retail and home services businesses, including Vivint's smart home platform, require accessing, collecting, storing and transmitting sensitive customer data in the ordinary course of business. Concerns about data privacy have led to increased regulation and other actions that could impact NRG's businesses and changes in data privacy and data protection laws and regulations or any failure to comply with such laws and regulations could adversely affect the Company's business and financial results. NRG's retail and home services businesses may need to provide sensitive customer data to vendors and service providers who require access to this information in order to provide services, such as call center operations, to such businesses. The services and the networks and information systems utilized by the Company may be at risk for breaches as a result of third-party actions, employee or vendor error, malfeasance or other factors.
Although the Company takes precautions to protect its infrastructure, it has been, and will likely continue to be, subject to attempts at phishing and other cybersecurity intrusions. International conflict increases the risk of state-sponsored cyber threats and escalated use of cybercriminal and cyber-espionage activities. In particular, the current geopolitical climate has further escalated cybersecurity risk, with various government agencies, including the U.S. Cybersecurity & Infrastructure Security Agency, issuing warnings of increased cyber threats, particularly for U.S. critical infrastructure. While the Company has not experienced a cyber/data event causing any material operational, reputational or financial impact, it recognizes the growing threat within the general marketplace and the industry, and there is no assurance that NRG will be able to prevent any such

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impacts in the future. If a material breach of the Company's information technology systems were to occur, the critical operational capabilities and reputation of its business may be adversely affected, customer confidence may be diminished, and NRG may be subject to substantial legal or regulatory scrutiny and claims, any of which may contribute to potential legal or regulatory actions against the Company, loss of customers and otherwise have a material adverse effect. Any loss or disruption of critical operational capabilities to support the Company's generation, commercial or retail operations, loss of customers, or loss of confidential or proprietary data through a breach, unauthorized access, disruption, misuse or disclosure could adversely affect NRG's reputation, expose the Company to material legal or regulatory claims and impair the Company's ability to execute its business strategy, which could have a material adverse effect. In addition, NRG may experience increased capital and operating costs to implement increased security for its information technology infrastructure. NRG cannot provide any assurance that such events and impacts will not be material in the future, and the Company's efforts to deter, identify and mitigate future breaches may require additional significant capital and may not be successful.
Negative publicity may damage NRG's reputation or its brands and negatively impact its business, financial condition, results of operations and ability to attract and retain highly qualified employees.
NRG’s reputation and brands could be damaged for numerous reasons, including negative views of the Company’s environmental impact, sustainability goals, supply chain practices, product and service offerings, sponsorship relationships, charitable giving programs and public statements made by Company officials. Additionally, the Company is from time to time named in investigations, claims and lawsuits arising in the ordinary course of business, and customers have in the past communicated complaints to consumer protection organizations, regulators or the media. Negative claims or publicity regarding the Company or its operations, offerings, practices or customer service may damage its brands or reputation, even if such claims are untrue. The Company may also experience criticism or backlash from media, customers, employees, government entities, advocacy groups and other stakeholders that disagree with positions taken by the Company or its executives. If the Company’s brands or reputation are damaged, it could negatively impact the Company’s business, financial condition, results of operations, and ability to attract and retain highly qualified employees.
Risks that are beyond NRG's control, including but not limited to acts of terrorism or related acts of war, natural disaster or other catastrophic events could have a material adverse effect on NRG's financial condition, results of operations and cash flows.
NRG's generation facilities and the facilities of third parties on which they rely may be targets of terrorist activities, as well as events occurring in response to or in connection with such activities, all of which could cause environmental repercussions and/or result in full or partial disruption of the facilities ability to generate, transmit, transport or distribute electricity or natural gas. Strategic targets, such as energy-related facilities, may be at greater risk of future terrorist activities than other domestic targets. Any such environmental repercussions or disruption could result in a significant decrease in revenues or significant reconstruction or remediation costs beyond what could be recovered through insurance policies, which could have a material adverse effect on the Company's financial condition, results of operations and cash flows. In addition, significant weather events or terrorist actions could damage or shut down the power or gas transmission and distribution facilities upon which the Company is dependent, which may reduce retail volume for extended periods of time. Power or gas supply may be sold at a loss if these events cause a significant loss of retail customer demand.
The Company has made investments focused on consumer products that may not be successful, may not achieve the intended financial results or may result in product liability and reputational risk that could adversely affect the Company.
The Company may be liable to customers for any damage caused to customers’ homes, facilities, belongings or property during the installation of Company products and systems, such as smart home systems, home back-up generators and residential HVAC system repairs, installation and replacements. Where such work is performed by independent contractors, such as repairs performed under the Company's home warranty and protection plan products, the Company may nonetheless face claims and costs for damage. In addition, shortages of skilled labor for Company projects could significantly delay a project or otherwise increase its costs. The products that the Company sells or manufactures may expose the Company to product liability claims relating to personal injury, death, or environmental or property damage, and may require product recalls or other actions. Although the Company maintains liability insurance and its service contracts limit Company liability, the Company cannot be certain that its coverage will be adequate for liabilities actually incurred or that insurance will continue to be available to the Company on economically reasonable terms, or at all, or that contractual limitations will be enforced. The laws of some states limit or prohibit insurance coverage for certain liabilities and actions, and any significant uninsured damages could have a material adverse effect on the Company’s business, financial condition and cash flows. Further, any product liability claim or damage caused by the Company could significantly impair the Company’s brand and reputation, which may result in a failure to maintain customers and achieve the Company’s desired growth initiatives in these new businesses.

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Changes in technology may impair the value of, and the attractiveness of, its retail products, smart home services and NRG’s generation facilities.
Research and development activities are ongoing in the industry to provide alternative and more efficient technologies to produce power, including wind, photovoltaic (solar) cells, hydrogen, energy storage, and improvements in traditional technologies and equipment, such as more efficient gas turbines. Advances in these or other technologies could reduce the costs of power production to a level below what the Company has currently forecasted, which could adversely affect its cash flows, results of operations or competitive position. Technology, including distributed technology or changes in retail rate structures, may also have a material impact on the Company’s ability to retain retail customers. Further, technological innovation and changes could cause the Company’s smart home products and services to become obsolete, or otherwise more expensive and less effective than those of competitors, putting the Company at a competitive disadvantage.
Some emerging technologies, such as distributed renewable energy technologies, broad consumer adoption of electric vehicles and energy storage devices, could affect the price of energy. These emerging technologies may affect the financial viability of utility counterparties and could have significant impacts on wholesale market prices, which could ultimately have a material adverse effect on NRG's financial condition, results of operations and cash flows.
The Company’s smart home services rely on intellectual property and any failure to adequately protect such intellectual property, or claims that the Company has infringed on others’ intellectual property rights, could have an adverse effect on its business and operations and result in a competitive disadvantage.
The Company relies on a combination of patent, trademark, copyright and trade secret laws of the United States and other countries and a combination of confidentiality procedures, contractual provisions and other methods, to protect its intellectual property, all of which offer only limited protection. If the Company fails to acquire the necessary intellectual property rights or adequately protect or assert its intellectual property rights, competitors may manufacture and market similar products and services or convert customers, which could adversely affect market share and results of operations for smart home services. In addition, patent rights may not prevent competitors from developing, using or selling products or services that are similar to or address the same market as the Company’s smart home products and services. Certain of the Company’s smart home solutions contain software modules licensed under “open-source” licenses, which may entail greater risks than the use of third-party commercial software, as open-source licensors generally do not provide warranties or other contractual protections regarding infringement claims or the quality of the code. Further, if proprietary software is combined with open-source software, in certain cases the Company could be required to release the source code of the proprietary software to the public, allowing competitors to create similar products with lower development effort and time.
It is possible that certain of the Company’s smart home products and services or those of third parties incorporated into its offerings could infringe the intellectual property rights of others. From time to time, Vivint has been subject to claims based on allegations of infringement, misappropriation or other violations of the intellectual property rights of others. If the Company is unable to successfully defend against such claims or license necessary third-party technology or other intellectual property on acceptable terms it may be required to develop alternative, non-infringing technology, which could require significant time, effort, and expense and may ultimately not be successful.
NRG's business, financial condition and results of operations could be adversely impacted by strikes or work stoppages by its unionized employees or inability to replace employees as they retire.
As of December 31, 2022, approximately 12% of NRG's employees were covered by collective bargaining agreements. In the event that the Company's union employees strike, participate in a work stoppage or slowdown or engage in other forms of labor strife or disruption, NRG would be responsible for procuring replacement labor or the Company could experience reduced power generation or outages. Although NRG's ability to procure such labor is uncertain, contingency staffing planning is completed as part of each respective contract negotiation. Strikes, work stoppages or the inability to negotiate future collective bargaining agreements on favorable terms could have a material adverse effect on the Company's business, financial condition, results of operations and cash flows. In addition, a number of the Company's employees at NRG's plants are close to retirement. The Company's inability to replace retiring workers could create potential knowledge and expertise gaps as such workers retire.
Risks Related to Governmental Regulation and Laws
NRG's business is subject to substantial energy regulation and may be adversely affected by legislative or regulatory changes, as well as liability under, or any future inability to comply with, existing or future energy regulations or requirements.
NRG's business is subject to extensive U.S. federal, state and local laws and foreign laws. Compliance with, or changes to, the requirements under these legal regimes may cause the Company to incur significant additional costs, reduce the Company's ability to hedge exposure or to sell retail power within certain states or to certain classes of retail customers, or restrict the Company’s marketing practices, its ability to pass through costs to retail customers, or its ability to compete on favorable terms

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with competitors, including the incumbent utility. Retail competition and home warranty services are regulated on a state-by-state or at the province-by-province level and are highly dependent on state and provincial laws, regulations and policies, which could change at any moment. Failure to comply with such requirements could result in the shutdown of a non-complying facility, the imposition of liens, fines, and/or civil or criminal liability.
Public utilities under the FPA are required to obtain FERC acceptance of their rate schedules for wholesale sales of electricity. Except for ERCOT generation facilities and power marketers, all of NRG's non-qualifying facility generating companies and power marketing affiliates in the U.S. make sales of electricity in interstate commerce and are public utilities for purposes of the FPA. FERC has granted each of NRG's generating and power marketing companies that make sales of electricity outside of ERCOT the authority to sell electricity at market-based rates. FERC's orders that grant NRG's generating and power marketing companies market-based rate authority reserve the right to revoke or revise that authority if FERC subsequently determines that NRG can exercise market power in transmission or generation, create barriers to entry, or engage in abusive affiliate transactions. In addition, NRG's market-based sales are subject to certain market behavior rules, and if any of NRG's generating and power marketing companies were deemed to have violated those rules, they are subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of their market-based rate authority. If NRG's generating and power marketing companies were to lose their market-based rate authority, such companies would be required to obtain FERC's acceptance of a cost-of-service rate schedule and could become subject to the accounting, record-keeping, and reporting requirements that are imposed on utilities with cost-based rate schedules. This could have a material adverse effect on the rates NRG charges for power from its facilities.
Substantially all of the Company's generation assets are also subject to the reliability standards promulgated by the designated Electric Reliability Organization (currently NERC) and approved by FERC. If NRG fails to comply with the mandatory reliability standards, NRG could be subject to sanctions, including substantial monetary penalties and increased compliance obligations. NRG is also affected by legislative and regulatory changes, as well as changes to market design, market rules, tariffs, cost allocations, and bidding rules that occur in the existing ISOs. The ISOs that oversee most of the wholesale power markets impose, and in the future may continue to impose, mitigation, including price limitations, offer caps, non-performance penalties and other mechanisms to address some of the volatility and the potential exercise of market power in these markets. These types of price limitations and other regulatory mechanisms may have a material adverse effect on the profitability of NRG's generation facilities that sell energy and capacity into the wholesale power markets.
The regulatory environment is subject to significant changes due to state and federal policies affecting wholesale and retail competition and the creation of incentives for the addition of large amounts of new renewable generation and, in some cases, transmission. These changes are ongoing, and the Company cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on NRG's business. In addition, in some of these markets, interested parties have proposed material market design changes. If competitive restructuring of the electric power markets is reversed, discontinued, or delayed, the Company's business prospects and financial results could be negatively impacted. In addition, there have been a number of reforms to the regulation of the derivatives markets, both in the United States and internationally. These regulations, and any further changes thereto, or adoption of additional regulations, including any regulations relating to position limits on futures and other derivatives or margin for derivatives, could negatively impact NRG’s ability to hedge its portfolio in an efficient, cost-effective manner by, among other things, potentially decreasing liquidity in the forward commodity and derivatives markets or limiting NRG’s ability to utilize non-cash collateral for derivatives transactions.
NRG’s business may be affected by interference in the competitive wholesale marketplace.
NRG’s generation and competitive retail operations rely on a competitive wholesale marketplace. The competitive wholesale marketplace may be impacted by out-of-market subsidies, including bailouts of uneconomic nuclear plants, imports of power from Canada, renewable mandates or subsidies, mandates to sell power below its cost of acquisition and associated costs as well as out-of-market payments to new or existing generators. These out-of-market subsidies to existing or new generation undermine the competitive wholesale marketplace, which can lead to premature retirement of existing facilities, including those owned by the Company. If these measures continue, capacity and energy prices may be suppressed, and the Company may not be successful in its 2016efforts to insulate the competitive market from this interference. The Company's retail operations may be materially impacted by rules or regulations that allow regulated utilities to participate in competitive retail markets or own and operate facilities that could be provided by competitive market participants.
Additions or changes in tax laws and regulations could potentially affect the Company’s financial results or liquidity.
NRG is subject to various types of tax arising from normal business operations in the jurisdictions in which the Company operates. Any additions or changes to tax legislation, or their interpretation and application, including those with retroactive effect, could have a material adverse effect on NRG’s financial condition and results of operations, including income tax provision and accruals reflected in the consolidated financial statements. The Inflation Reduction Act, enacted on August 16, 2022, includes the implementation of a 15% corporate alternative minimum tax (“CAMT”) effective in 2023. The CAMT may

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lead to volatility in the Company’s cash tax payment obligations, particularly in periods of significant commodity or currency variability resulting from potential changes in the fair value of derivative instruments. There remains unanswered questions on how the operative rules for CAMT will be implemented and interpreted. The Company continuously monitors and assesses proposed tax legislation that could negatively impact its business.
The integration of the Capacity Performance product into the PJM market could lead to substantial changes in capacity income and non-performance penalties, which could have a material adverse effect on NRG’s results of operations, financial condition and cash flows.
PJM operates a pay-for-performance model where capacity payments are modified based on real-time generator performance. Capacity market prices are sensitive to design parameters, as well as additions of new capacity. NRG may experience substantial changes in capacity income and incur non-performance penalties, which could have a material adverse effect on NRG’s results of operations, financial condition and cash flows.
NRG's ownership interest in a nuclear power facility subjects the Company to regulations, costs and liabilities uniquely associated with these types of facilities.
Under the Atomic Energy Act of 1954, as amended ("AEA"), ownership and operation of STP, of which NRG indirectly owns a 44% interest, is subject to regulation by the NRC. Such regulation includes licensing, inspection, enforcement, testing, evaluation and modification of all aspects of nuclear reactor power plant design and operation, environmental and safety performance, technical and financial qualifications, decommissioning funding assurance and transfer and foreign ownership restrictions. The current facility operating licenses for STP expire on August 20, 2047 (Unit 1) and December 15, 2048 (Unit 2).
There are unique risks to owning and operating a nuclear power facility. These include liabilities related to the handling, treatment, storage, disposal, transport, release and use of radioactive materials, particularly with respect to spent nuclear fuel, and uncertainties regarding the ultimate, and potential exposure to, technical and financial risks associated with modifying or decommissioning a nuclear facility. The NRC could require the shutdown of the plant for safety reasons or refuse to permit restart of the unit after unplanned or planned outages. New or amended NRC safety and regulatory requirements may give rise to additional operation and maintenance costs and capital expenditures. Additionally, aging equipment may require more capital expenditures to keep each of these nuclear power plants operating efficiently. This equipment is also likely to require periodic upgrading and improvement. Any unexpected failure, including failure associated with breakdowns, forced outages, or any unanticipated capital expenditures, could result in reduced profitability. STP will be obligated to continue storing spent nuclear fuel if the U.S. DOE continues to fail to meet its contractual obligations to STP made pursuant to the U.S. Nuclear Waste Policy Act of 1982 to accept and dispose of STP's spent nuclear fuel. Costs associated with these risks could be substantial and could have a material adverse effect on NRG's results of operations, financial condition or cash flow to the extent not covered by the Decommissioning Trusts or recovered from ratepayers. In addition, to the extent that all or a part of STP is required by the NRC to permanently or temporarily shut down or modify its operations, or is otherwise subject to a forced outage, NRG may incur additional costs to the extent it is obligated to provide power from more expensive alternative sources — either NRG's own plants, third-party generators or the ERCOT — to cover the Company's then existing forward sale obligations. Such shutdown or modification could also lead to substantial costs related to the storage and disposal of radioactive materials and spent nuclear fuel.
While STP maintains property and liability insurance for losses related to nuclear operations, there may be limitations on the amounts and types of insurance commercially available. See also Item 15 — Note 23, Commitments and Contingencies, Nuclear Insurance, of the Company's 2022 Form 10‑K10-K. An accident at STP or another nuclear facility could have a material adverse effect on NRG's financial condition, its operational results, reputation, or liquidity as losses may exceed the insurance coverage available and/or may result in the obligation to pay retrospective premium obligations.
NRG is subject to environmental laws that impose extensive and increasingly stringent requirements on the Company's ongoing operations, as well as potentially substantial liabilities arising out of environmental contamination. These environmental requirements and liabilities could adversely impact NRG's results of operations, financial condition and cash flows.
NRG is subject to the environmental laws of foreign and U.S., federal, state and local authorities. The Company must comply with numerous environmental laws and obtain numerous governmental permits and approvals to build and operate the Company's plants. Federal and state environmental laws generally have become more stringent over time. Should NRG fail to comply with any environmental requirements that apply to its operations, the Company could be subject to administrative, civil and/or criminal liability and fines, and regulatory agencies could take other actions seeking to curtail the Company's operations. In addition, when new requirements take effect or when existing environmental requirements are revised, reinterpreted or subject to changing enforcement policies, NRG's business, results of operations, financial condition and cash flows could be adversely affected.

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NRG's businesses are subject to physical, market and economic risks relating to potential effects of climate change, and policies at the national, regional and state levels to regulate GHG emissions and mitigate climate change which could adversely impact NRG's results of operations, financial condition and cash flows.
Fluctuations in weather and other environmental conditions, including temperature and precipitation levels, may affect consumer demand for electricity or natural gas. In addition, the potential physical effects of climate change, such as increased frequency and severity of storms, floods and other climatic events, could disrupt NRG's operations and supply chain, and cause it to incur significant costs in preparing for or responding to these effects. These or other changes in climate could lead to increased operating costs or capital expenses. NRG's customers may also experience the potential physical impacts of climate change and may incur significant costs in preparing for or responding to these efforts, including changing the fuel mix and resiliency of their energy solutions and supply.
Hazards customary to the power production industry include the potential for unusual weather conditions, which could affect fuel pricing and availability, the Company's route to market or access to customers, i.e., transmission and distribution lines, transportation and delivery, or critical plant assets. The contribution of climate change to the frequency or intensity of weather-related events could affect NRG's operations and planning process.
Climate change could also affect the availability of a secure and economical supply of water in some locations, which is essential for the continued operation of NRG's generation plants. NRG monitors water supply risk carefully. If it is determined that a water supply risk exists that could impact projected generation levels at any plant, risk mitigation efforts are identified and evaluated for implementation.
Further, demand for NRG's energy-related services could be similarly impacted by consumers’ preferences or market or regulatory factors favoring energy efficiency, lower carbon energy sources or reduced electricity or natural gas usage.
NRG's GHG emissions reduction targets can be found in Item 1, Business —Environmental Regulatory Matters, of the Company's 2022 Form 10-K. The Company's ability to achieve these targets depends on many factors, including the ability to retire high emitting assets, ability to reduce emissions based on technological advances and innovation, and ability to source energy from less carbon intense resources. In addition, any future decarbonization efforts may increase costs, or NRG may otherwise be limited in its ability to apply them. The cost associated with NRG's GHG emissions reduction goals could be significant. Failure to achieve the Company's emissions targets could result in a negative impact on access to and cost of capital, changing investor sentiment regarding investment in the Company or reputation harm.
Enhanced data privacy and data protection laws and regulations or any non-compliance with such laws and regulations, could adversely affect NRG’s business and financial results.
The consumer privacy landscape continues to experience momentum for greater privacy protection and reform at the state and federal level in response to precedents set forth by the General Data Protection Regulation (the "GDPR") and the California Consumer Privacy Act (the "CCPA"). The development and evolving nature of domestic and international privacy regulation and enforcement could impact and potentially limit how NRG processes personally identifiable information. Beginning January 1, 2023, California residents have increased access rights (including the right to limit the use and disclosure of sensitive personal information), which are enforced by a new state privacy regulator, resulting in more scrutiny of business practices and disclosures. Additional states including Virginia, Utah, Connecticut, Colorado, and Nevada have similarly adopted enhanced data privacy legislation effective in 2023 and patterned after the standards set forth by CCPA, including broader data access rights, with Virginia going a step further requiring businesses to perform data protection assessments for certain processing activities. The Company is also bound by contractual requirements relating to privacy and data protection, and may agree to additional contractual requirements addressing these matters from time to time.
As new laws and regulations are created, amended or expanded, requiring businesses to implement processes to enable customers access to their data and enhanced data protection and management standards, NRG cannot forecast with any certainty the impact that they may have on the Company’s business; however, it is possible the Company may find it necessary or desirable to change certain of its business practices or to expend resources to modify its home products and services and otherwise adapt to these changes. It is possible that the Company may be unable to make such changes and modifications in a commercially reasonable manner or at all, and its Form 10-Qability to develop new home services and features could be limited. Any non-compliance with laws may result in proceedings or actions against the Company by governmental entities or individuals. Moreover, any inquiries or investigations, government penalties or sanctions, or civil actions by individuals may be costly to comply with, resulting in negative publicity, increased operating costs, significant management time and attention, and may lead to remedies that harm the business, including fines, demands or orders that existing business practices be modified or terminated.

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NRG's retail operations and smart home services are subject to changing rules and regulations that could have a material impact on the Company's profitability.
The competitiveness of NRG's retail operations partially depends on regulatory policies that establish the structure, rules, terms and conditions on which services are offered to retail customers. These policies can include, among other things, controls on the retail rates that NRG can charge, the imposition of additional costs on sales, restrictions on the Company's ability to obtain new customers through various marketing channels and disclosure requirements. The Company's retail operations may be materially impacted by rules or regulations that allow regulated utilities to participate in competitive retail markets or own and operate facilities that could be provided by competitive market participants. Additionally, state, federal or provincial imposition of net metering or RPS programs can make it more or less expensive for retail customers to supplement or replace their reliance on grid power.
The Company’s smart home services focus on transactions with residential customers, subjecting it to a variety of laws, regulations and licensing requirements governing interactions with residential consumers, including those pertaining to privacy and data security, consumer financial and credit transactions, home improvements, warranties and door-to-door solicitation. In certain jurisdictions, the Company is required to obtain licenses or permits to comply with standards governing marketing and sales efforts, installation of equipment or servicing of subscribers, and monitoring station employee selection and training. Increased regulation of matters relating to interactions with residential consumers could require modification to the Company’s home services operations and the incurrence of additional expenses. Further, any expansion of the scope of products or services into new markets may require additional licenses and expenditures to otherwise maintain compliance with additional laws, regulations or licensing requirements. These laws and regulations, as well as their interpretation, and any new laws, regulations or licensing requirements could negatively affect the Company’s ability to acquire new residential customers. Any of these measures could increase costs for providing, or reduce customer satisfaction with respect to, smart home services.
The Federal Trade Commission ("FTC") and the Federal Communications Commission have issued regulations that restrict direct-to-home marketing, telemarketing, email marketing and other sales practices, including limitations on methods of communication, requirements to maintain a “do not call” list, cancellation rights and required training for personnel to comply with these restrictions. Any noncompliance, or alleged noncompliance, of applicable regulations by the Company, third-party vendors used for marketing, telemarketing or lead generation activities or independent, third-party authorized dealers of smart home services could result in private rights of actions or enforcement actions for civil or criminal penalties. Changes in regulations or interpretations that further restrict lead generating activities also could result in a reduction in the number of new smart home services customers.
The Company’s smart home business exposes it to risks of liability for the quarter ended June 30, 2017.acts or omissions of its employees, including with respect to sales practices.
Activities in connection with sales efforts by employees, independent contractors, and other agents, including predatory door-to-door sales tactics and fraudulent misrepresentations, have in the past subjected it to, and could in the future subject the Company to, governmental investigations and class action lawsuits for, among others, false advertising and deceptive trade practice damage claims. Any litigation or regulatory proceedings resulting from such activities could adversely impact the Company’s business, financial condition, results of operations, and cash flows.
The Company is subject to various risks in connection with Vivint’s ongoing settlement administration process involving the FTC, and may be subject to FTC Actions in the future.
In 2021, Vivint entered into a settlement with the FTC where Vivint paid a total of $20 million to the United States and agreed to implement various compliance-related measures. The settlement requires a biennial assessments by an independent third-party assessor of Vivint’s compliance programs and for the assessor to provide a report to the FTC staff on ongoing compliance with the settlement. Although Vivint took action to enhance its compliance programs, these and other measures that the Company may take in the future may not be successful. If any assessments identify deficiencies in the Company’s efforts to comply, and should the FTC determine that Vivint is not in full compliance with the settlement, it could take further action, such as seeking judicial remedies for any noncompliance, and Vivint could be subject to additional sanctions and restrictions on its smart home operations. In addition, the filing of an application with the court for noncompliance with the settlement could lead to regulatory actions by other agencies or private litigation, impact Vivint’s ability to obtain regulatory approvals necessary to carry out present or future plans and operations, and result in negative publicity.
The Company's international operations are exposed to political and economic risks, commercial instability and events beyond the Company's control in the countries in which it operates, which risks may negatively impact the Company's business.
The Company's international operations depend on products manufactured, purchased and sold in the U.S. and internationally. In some cases, these countries have greater political and economic volatility and greater vulnerability to infrastructure labor, and supply chain disruptions than in NRG's other markets. Operating a business in a number of different

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regions and countries exposes the Company to a number of risks, including: imposition of burdensome tariffs or quotas, multiple and potentially conflicting laws, regulations and policies that are subject to change, imposition of currency restrictions on repatriation of earnings or other restraints, national and international conflict, including terrorist acts and political and economic instability or civil unrest that may severely disrupt economic activity in affected countries and result in increased cost.
The occurrence of one or more of these events may negatively impact the Company's business, results of operations and financial condition.
Risks Related to the Economic and Financial Market Conditions, and the Company's Indebtedness
NRG's level of indebtedness could adversely affect its ability to raise additional capital to fund its operations or return capital to stockholders. It could also expose it to the risk of increased interest rates and limit its ability to react to changes in the economy or its industry.
NRG's substantial debt could have negative consequences, including:
•increasing NRG's vulnerability to general economic and industry conditions;
•requiring a substantial portion of NRG's cash flow from operations to be dedicated to the payment of principal and interest on its indebtedness, therefore reducing NRG's ability to pay dividends or to use its cash flow to fund its operations, capital expenditures and future business opportunities;
•limiting NRG's ability to enter into long-term power sales or fuel purchases which require credit support;
•limiting NRG's ability to obtain additional financing for working capital including collateral postings, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes;
•limiting NRG's ability to adjust to changing market conditions and placing it at a competitive disadvantage compared to its competitors who have less debt; and
•exposing NRG to the risk of increased interest rates because certain of its borrowings are at variable rates of interest, primarily through its Revolving Credit Facility.
The Company’s credit documents contain financial and other restrictive covenants that may limit the Company's ability to return capital to stockholders or otherwise engage in activities that may be in its long-term best interests. NRG's failure to comply with those covenants could result in an event of default which, if not cured or waived, could result in the acceleration of all of the Company's indebtedness. The Company's corporate credit agreement includes a sustainability-linked metric and sustainability-linked bonds, which could result in increased interest expense to the Company if the sustainability metrics set forth therein are not met. Furthermore, financial and other restrictive covenants contained in any project level subsidiary debt may limit the ability of NRG to receive distributions from such subsidiary.
In addition, NRG's ability to arrange financing, either at the corporate level, a non-recourse project-level subsidiary or otherwise, and the costs of such capital, are dependent on numerous factors, including: general economic and capital market conditions; credit availability from banks and other financial institutions; investor confidence in NRG, its partners and the regional wholesale power markets; NRG's financial performance and the financial performance of its subsidiaries; NRG's level of indebtedness and compliance with covenants in debt agreements; maintenance of acceptable credit ratings; cash flow; and provisions of tax and securities laws that may impact raising capital.
NRG may not be successful in obtaining additional capital for these or other reasons. The failure to obtain additional capital from time to time may have a material adverse effect on its business and operations.
Adverse economic conditions could adversely affect NRG’s business, financial condition, results of operations and cash flows.
Adverse economic conditions, including inflation, and declines in wholesale energy prices, partially resulting from adverse economic conditions, may impact NRG's results of operations, including by reducing the demand for energy commodities. Reduced demand from negative economic conditions continues to impact the key domestic wholesale energy markets NRG serves. In general, economic and commodity market conditions will continue to impact NRG’s unhedged future energy margins, liquidity, earnings growth and overall financial condition. Macroeconomic factors may also impact consumer spending, which could adversely affect the Company’s smart home services, and increase the Company’s costs for such products and services, which it may not be able to pass on to customers. In addition, adverse economic conditions, declines in wholesale energy prices, reduced demand for energy and other factors may negatively impact the trading price of NRG’s common stock and impact forecasted cash flows, which may require NRG to evaluate its goodwill and other long-lived assets for impairment. Any such impairment could have a material impact on NRG’s financial condition.

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Goodwill and other intangible assets that NRG has recorded in connection with its acquisitions are subject to impairment evaluations and, as a result, the Company could be required to write off some or all of this goodwill and other intangible assets, which may adversely affect the Company's financial condition and results of operations.
Goodwill is not amortized but is reviewed annually or more frequently for impairment. Other intangibles are also reviewed at least annually or more frequently, if certain conditions exist, and are amortized. Any reduction in or impairment of the value of goodwill or other intangible assets will result in a charge against earnings, which could materially adversely affect NRG's reported results of operations and financial position in future periods.

ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None.During the quarter ended March 31, 2023, no purchases of NRG's common stock were made by or on behalf of NRG or any "affiliated purchaser" (as defined in Rule 10b-18(a)(3) under the Exchange Act).

ITEM 3 — DEFAULTS UPON SENIOR SECURITIES
See Note 3, Discontinued Operations, Dispositions and Acquisitions, to the Condensed Consolidated Financial Statements of this Form 10-Q, for a description of events of default by GenOn and GenOn Americas Generation under the GenOn Senior Notes and the GenOn Americas Generation Senior Notes.None.

ITEM 4 — MINE SAFETY DISCLOSURES
Not applicable.There have been no events that are required to be reported under this Item.

ITEM 5 — OTHER INFORMATION
None.



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ITEM 6 — EXHIBITS
NumberDescriptionMethod of Filing
10.12.1Incorporated herein by reference to Exhibit 2.1 to the Registrant's Current Report on Form 8-K, filed on December 6, 2022.
3.1Incorporated herein by reference to Exhibit 3.1 to the Registrant's current report on Form 8-K filed on March 10, 2023.
4.1


Incorporated herein by reference to Exhibit 10.1 to the Registrant's current report on Form 8-K filed on February 15, 2023.
4.2


Filed herewith.
4.3Incorporated herein by reference to Exhibit 4.2 to the Registrant's current report on Form 8-K filed on March 10, 2023.
4.4Incorporated herein by reference to Exhibit 4.3 to the Registrant's current report on Form 8-K filed on March 10, 2023.
4.5Incorporated herein by reference to Exhibit 10.1 to Vivint Smart Home, Inc.'s Current Report on Form 8-K filed on October 6, 2017.February 19, 2020).
10.24.6Included in Exhibit 4.5 above
4.7Incorporated herein by reference to Exhibit 4.5 to Vivint Smart Home, Inc.'s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2020
4.8Incorporated herein by reference to Exhibit 4.9 to Vivint Smart Home, Inc.'s Annual Report on Form 10-Kfiled on February 24, 2023
4.9Incorporated herein by reference to Exhibit 4.1 to Vivint Smart Home, Inc.'s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2022
4.10Incorporated herein by reference to Exhibit 10.1 to Vivint Smart Home, Inc.'s Current Report on Form 8-K filed on July 12, 2021
4.11Included in Exhibit 4.10 above
4.12Incorporated herein by reference to Exhibit 4.2 to Vivint Smart Home, Inc.'s Quarterly Report on form 10-Q for the quarterly period ended June 30, 2022
4.13Incorporated herein by reference to Exhibit 10.2 to the Registrant'sVivint Smart Home, Inc.'s Current Report on Form 8-K filed on October 6, 2017.July 12, 2021
10.310.1*Incorporated herein by reference to Exhibit 4.4 to Vivint's Post-Effective Amendment on Form S-8 to Registration Statement on Form S-4 filed with the Securities and Exchange Commission on March 24, 2020

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10.2*Filed herewith.
10.3*Filed herewith.
10.4*Incorporated herein by reference to Exhibit 10.1 to the Registrant's Current Reportcurrent report on Form 8-K filed on November 1, 2017.May 2, 2023.
31.110.5*Incorporated herein by reference to Exhibit 10.45 to Vivint Smart Home, Inc.'s Annual Report on Form 10-K for the annual period ended December 31, 2022.
10.6*Incorporated by reference to Exhibit 10.5 to Vivint Smart Home, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 2022
22.1Filed herewith.
31.1Filed herewith.
31.2Filed herewith.
31.3Filed herewith.
32Furnished herewith.
101 INSInline XBRL Instance Document.Filed herewith.The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
101 SCHInline XBRL Taxonomy Extension Schema.Filed herewith.
101 CALInline XBRL Taxonomy Extension Calculation Linkbase.Filed herewith.
101 DEFInline XBRL Taxonomy Extension Definition Linkbase.Filed herewith.
101 LABInline XBRL Taxonomy Extension Label Linkbase.Filed herewith.
101 PREInline XBRL Taxonomy Extension Presentation Linkbase.Filed herewith.
104Cover 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.




*Exhibit relates to compensation arrangements.

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

(Registrant) 
/s/ MAURICIO GUTIERREZ 
Mauricio Gutierrez
Chief Executive Officer
(Principal Executive Officer)
/s/ KIRKLAND B. ANDREWS  ALBERTO FORNARO
Kirkland B. Andrews Alberto Fornaro
Chief Financial Officer
(Principal Financial Officer)
/s/ DAVID CALLENEMILY PICARELLO
David CallenEmily Picarello
Date: November 2, 2017May 4, 2023
Chief Accounting OfficerCorporate Controller
(Principal Accounting Officer)







107

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