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: SeptemberJune 30, 20172023
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 OctoberJuly 31, 2017,2023, there were 316,641,799229,117,430 shares of common stock outstanding, par value $0.01 per share.




1

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
6549
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
10282
ITEM 4 — CONTROLS AND PROCEDURES
10484
10585
ITEM 1 — LEGAL PROCEEDINGS
10585
ITEM 1A — RISK FACTORS
10585
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
10585
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES
10585
ITEM 4 — MINE SAFETY DISCLOSURES
10585
ITEM 5 — OTHER INFORMATION
10585
ITEM 6 — EXHIBITS
10686
SIGNATURES
10787






2

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This Quarterly Report on Form 10-Q of NRG Energy, Inc., or NRG or the Company, includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. The words "believes," "projects," "anticipates," "plans," "expects," "intends," "estimates""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 Smart Home 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.

3

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.



4

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 EBITDAAdjusted earnings before interest, taxes, depreciation and amortization
ASCAESOAlberta Electric System Operator
AROAsset 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 June 30, 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

5

IFRSICEInternational Financial Reporting StandardsIntercontinental Exchange
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)
PeakingUnits expected to satisfy demand requirements during the periods of greatest or peak load on the system
PERPG&EPeak Energy Rent
Petition DateJune 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 $1.4 billion accounts receivables securitization facility due 2024, which go to market as Reliant, NRG and other brands owned by NRG, as well as Business Solutionswas last amended on June 22, 2023
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 2024, which was last amended on June 22, 2023

6

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 SeptemberJune 30, 2017, the Company’s $5.42023, 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 June 30, 2023, NRG’s $3.2 billion outstanding Senior Secured First Lien Notes consists of $600 million of the 3.75% Senior Secured First Lien Notes due 2024, $500 million of the 2.0% Senior Secured First Lien Notes due 2025, $900 million of the 2.45% Senior Secured First Lien Notes due 2027, $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, Inc.
TWhTerawatt Hour
U.S.United States of America
U.S. DOEU.S. Department of Energy
VaRValue at Risk
VIEVariable Interest Entity
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




7

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 June 30,Six months ended June 30,
(In millions, except for per share amounts)2023202220232022
Revenue
Revenue$6,348 $7,282 $14,070 $15,178 
Operating Costs and Expenses
Cost of operations (excluding depreciation and amortization shown below)4,962 5,887 13,740 10,817 
Depreciation and amortization315 157 505 340 
Impairment losses— 155 — 155 
Selling, general and administrative costs522 351 948 698 
Acquisition-related transaction and integration costs22 10 93 18 
Total operating costs and expenses5,821 6,560 15,286 12,028 
Gain on sale of assets3 32 202 29 
Operating Income/(Loss)530 754 (1,014)3,179 
Other Income/(Expense)
Equity in earnings/(losses) of unconsolidated affiliates5 4 10 (11)
Other income, net13 12 29 12 
Interest expense(151)(105)(299)(208)
Total other expense(133)(89)(260)(207)
Income/(Loss) Before Income Taxes397 665 (1,274)2,972 
Income tax expense/(benefit)89 152 (247)723 
Net Income/(Loss)$308 $513 $(1,027)$2,249 
Less: Cumulative dividends attributable to Series A Preferred Stock17 — 21 — 
Net Income/(Loss) Available for Common Stockholders$291 $513 $(1,048)$2,249 
Income/(Loss) per Share
Weighted average number of common shares outstanding — basic231 237 230 240 
Income/(Loss) per Weighted Average Common Share — Basic$1.26 $2.16 $(4.56)$9.37 
Weighted average number of common shares outstanding — diluted232 237 230 240 
Income/(Loss) per Weighted Average Common Share —Diluted$1.25 $2.16 $(4.56)$9.37 
See accompanying notes to condensed consolidated financial statements.



8


NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)
(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 June 30,Six months ended June 30,
(In millions)2023202220232022
Net Income/(Loss)$308 $513 $(1,027)$2,249 
Other Comprehensive Income/(Loss)
Foreign currency translation adjustments6 (22)8 (13)
Defined benefit plans— 20 (1)19 
Other comprehensive income/(loss)6 (2)7 6 
Comprehensive Income/(Loss)$314 $511 $(1,020)$2,255 
See accompanying notes to condensed consolidated financial statements.



9



NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, 2023December 31, 2022
(In millions, except share data and liquidation preference on preferred stock)(Unaudited)(Audited)
ASSETS
Current Assets
Cash and cash equivalents$422 $430 
Funds deposited by counterparties365 1,708 
Restricted cash26 40 
Accounts receivable, net3,274 4,773 
Inventory686 751 
Derivative instruments4,423 7,886 
Cash collateral paid in support of energy risk management activities270 260 
Prepayments and other current assets580 383 
Current assets - held-for-sale75 — 
Total current assets10,121 16,231 
Property, plant and equipment, net1,706 1,692 
Other Assets
Equity investments in affiliates139 133 
Operating lease right-of-use assets, net221 225 
Goodwill5,143 1,650 
Customer relationships, net2,446943
Other intangible assets, net1,897 1,189 
Nuclear decommissioning trust fund— 838 
Derivative instruments2,910 4,108 
Deferred income taxes2,711 1,881 
Other non-current assets536 251 
Non-current assets - held-for-sale1,161 5 
Total other assets17,164 11,223 
Total Assets$28,991 $29,146 

10

 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
June 30, 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$1,319 $63 
Current portion of operating lease liabilities91 83 
Accounts payable2,107 3,643 
Derivative instruments3,832 6,195 
Cash collateral received in support of energy risk management activities365 1,708 
Deferred revenue current731176
Accrued expenses and other current liabilities1,395 1,110 
Current liabilities - held-for-sale36 4 
Total current liabilities9,876 12,982 
Other Liabilities
Long-term debt and finance leases10,737 7,976 
Non-current operating lease liabilities165 180 
Nuclear decommissioning reserve— 340 
Nuclear decommissioning trust liability— 477 
Derivative instruments1,889 2,246 
Deferred income taxes130 134 
Deferred revenue non-current92710
Other non-current liabilities988 942 
Non-current liabilities - held-for-sale947 31 
Total other liabilities15,783 12,336 
Total Liabilities25,659 25,318 
Commitments and Contingencies
Stockholders' Equity
Preferred stock; 10,000,000 shares authorized; 650,000 Series A shares issued and outstanding at June 30, 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; 424,675,214 and 423,897,001 shares issued and 230,425,759 and 229,561,030 shares outstanding at June 30, 2023 and December 31, 2022, respectively4 4 
Additional paid-in-capital8,504 8,457 
Retained earnings205 1,408 
Treasury stock, at cost 194,249,455 and 194,335,971 shares at June 30, 2023 and December 31, 2022, respectively(5,861)(5,864)
Accumulated other comprehensive loss(170)(177)
Total Stockholders' Equity3,332 3,828 
Total Liabilities and Stockholders' Equity$28,991 $29,146 

See accompanying notes to condensed consolidated financial statements.



11

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six months ended June 30,
(In millions)20232022
Cash Flows from Operating Activities
Net (Loss)/Income$(1,027)$2,249 
Adjustments to reconcile net (loss)/income to cash (used)/provided by operating activities:
Distributions from and equity in (earnings)/losses of unconsolidated affiliates(9)16 
Depreciation and amortization505 340 
Accretion of asset retirement obligations5 16 
Provision for credit losses80 51 
Amortization of nuclear fuel26 28 
Amortization of financing costs and debt discounts31 11 
Amortization of in-the-money contracts and emissions allowances112 128 
Amortization of unearned equity compensation61 14 
Net gain on sale of assets and disposal of assets(187)(46)
Impairment losses— 155 
Changes in derivative instruments1,515 (3,918)
Changes in current and deferred income taxes and liability for uncertain tax benefits(282)672 
Changes in collateral deposits in support of risk management activities(1,355)3,121 
Changes in nuclear decommissioning trust liability2 (5)
Uplift securitization proceeds received from ERCOT— 689 
Changes in other working capital(505)(332)
Cash (used)/provided by operating activities(1,028)3,189 
Cash Flows from Investing Activities
Payments for acquisitions of businesses and assets, net of cash acquired(2,498)(53)
Capital expenditures(324)(150)
Net purchases of emission allowances(25)(19)
Investments in nuclear decommissioning trust fund securities(185)(271)
Proceeds from the sale of nuclear decommissioning trust fund securities180 278 
Proceeds from sales of assets, net of cash disposed229 96 
Proceeds from insurance recoveries for property, plant and equipment, net121 — 
Cash used by investing activities(2,502)(119)
Cash Flows from Financing Activities
Proceeds from issuance of preferred stock, net of fees635 — 
Payments of dividends to common stockholders(174)(168)
Payments for share repurchase activity(a)
(16)(366)
Net receipts from settlement of acquired derivatives that include financing elements318 950 
Net proceeds of Revolving Credit Facility700 — 
Proceeds from issuance of long-term debt731 — 
Payments of debt issuance costs(22)— 
Repayments of long-term debt and finance leases(10)(2)
Cash provided by financing activities2,162 414 
Effect of exchange rate changes on cash and cash equivalents3 — 
Net (Decrease)/Increase in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash(1,365)3,484 
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$813 $4,594 
 Nine months ended September 30,
(In millions)2017 2016
Cash Flows from Operating Activities   
Net (loss)/income$(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
(a)Includes $(16) million and $(6) million of equivalent shares purchased in lieu of tax withholdings on equity compensation issuances during the six months ended June 30, 2023 and June 30, 2022, respectively
See accompanying notes to condensed consolidated financial statements.



12

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(Unaudited)
(In millions)Preferred StockCommon
Stock		Additional
Paid-In
Capital		Retained EarningsTreasury
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 
Net income308 308 
Issuance of Series A Preferred Stock(1)(1)
Other comprehensive income6 6 
Shares reissuance for ESPP1 3 4 
Equity-based awards activity, net(a)
23 23 
Common stock dividends and dividend equivalents declared(b)
(88)(88)
Balance at June 30, 2023$650 $4 $8,504 $205 $(5,861)$(170)$3,332 

(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 
Net income513 513 
Other comprehensive loss(2)(2)
Shares reissuance for ESPP12 3 
Share repurchases(168)(168)
Equity-based awards activity, net8 8 
Common stock dividends and dividend equivalents declared(b)
(84)(84)
Balance at June 30, 2022$4 $8,442 $2,600 $(5,626)$(120)$5,300 
(a)Includes $(8) million, $(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, June 30, 2023 and March 31, 2022, respectively
(b)Dividends per common share were $0.3775 for the quarters ended June 30 and March 31, 2023 and $0.35 for the quarters ended June 30 and March 31, 2022
See accompanying notes to condensed consolidated financial statements.

13

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

Note 1 — Nature of Business and Basis of Presentation
General
NRG Energy, Inc., or NRG or the Company, is a leading integrated powerenergy, smart home and services company built onfueled by market-leading brands, proprietary technologies, and complementary sales channels. Across the strengthUnited States and Canada, NRG delivers innovative, sustainable solutions, predominately under brand names such as NRG, Reliant, Direct Energy, Green Mountain Energy and Vivint, while also advocating for competitive energy markets and customer choice. The Company has a customer base that includes approximately 7.5 million residential consumers in addition to commercial, industrial, and wholesale customers, supported by approximately 16 GW of a diverse competitive electric generation portfoliogeneration.
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 SeptemberJune 30, 2017,2023, and the results of operations, comprehensive income/(loss)income, cash flows and cash flowsstatements of stockholders' equity for the three and ninesix months ended September 30, 2017 and 2016.
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, Dispositions2023 and Acquisitions, for more information.2022.

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

14

Although subscribers pay separately for products and services under Flex Pay, the Company has determined that the sale of products and services are one single performance obligation resulting in deferred revenue for the gross amount of products sold. For products financed through the CFP, gross deferred revenues are reduced by (i) any fees the third-party financing provider (“Financing Provider”) is contractually entitled to receive at the time of loan origination, and (ii) the present value of expected future payments due to the Financing Providers. Loans are issued on either an installment or revolving basis with repayment terms ranging from 6 to 60 months.
For certain Financing Provider loans:
•Vivint Smart Home pays a monthly fee based on either the average daily outstanding balance of the installment loans, or the number of outstanding loans.
•Vivint Smart Home incurs fees at the time of the loan origination and receives proceeds that are net of these fees.
•Vivint Smart Home also shares liability for credit losses, with Vivint Smart Home being responsible for between 2.6% and 100% of lost principal balances.
Due to the nature of these provisions, the Company records a derivative liability at its fair value when the Financing Provider originates loans to subscribers, which reduces the amount of estimated revenue recognized on the provision of the services. The derivative liability is reduced as payments are made by Vivint Smart Home to the Financing Provider. Subsequent changes to the fair value of the derivative liability are realized through other income, net in the consolidated statements of operations. For further discussion, see Note 7, Accounting for Derivative Instruments and Hedging Activities.
Capitalized Contract Costs
Capitalized contract costs represent the costs directly related and incremental to the origination of new contracts, modification of existing contracts or to the fulfillment of the related subscriber contracts. These costs include installed products, commissions, other compensation and 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; accumulated amortization included in intangible assets, net and accumulated amortization included in out-of-market contracts,customer relationships, net and other intangible assets, net:
(In millions)June 30, 2023December 31, 2022
Property, plant and equipment accumulated depreciation$1,351 $1,478 
Customer relationships and other intangible assets accumulated amortization2,394 2,112 
Credit Losses
Retail trade receivables are reported on the balance sheet net of the allowance for credit losses within accounts receivables, net. Long-term receivables are recorded net in other non-current assets in the consolidated balance sheets. 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

 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 and six months ended June 30, 2023 and 2022:

Three months ended June 30,Six months ended June 30,
(In millions)2023202220232022
Beginning balance$121 $666 $133 $683 
Acquired balance from Vivint Smart Home— — 22 — 
Provision for credit losses45 26 80 51 
Write-offs(66)(71)(144)(121)
Recoveries collected12 6 21 14 
Other8 — 8 — 
Ending balance$120 $627 $120 $627 

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)June 30, 2023December 31, 2022
Cash and cash equivalents$1,223
 $938
 $1,217
 $853
Cash and cash equivalents$422 $430 
Funds deposited by counterparties31
 2
 6
 55
Funds deposited by counterparties365 1,708 
Restricted cash537
 446
 480
 414
Restricted cash26 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$813 $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 six months ended June 30, 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/OtherVivint Smart HomeTotal
Balance as of December 31, 2022$710 $723 $217 $— $1,650 
Goodwill resulting from the acquisition of Vivint Smart Home— — — 3,492 3,492 
Sale of business— (2)— — (2)
Foreign currency translation adjustments— — 3 — 3 
Balance as of June 30, 2023$710 $721 $220 $3,492 $5,143 
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

16

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 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 Smart Home.

Note 3 — Revenue Recognition
Vivint Smart Home Retail Revenue
Vivint Smart Home offers its subscribers combinations of smart home products and services, which together create an integrated smart home system that allows the Company's subscribers to monitor, control and protect their homes. As the products and services included in the subscriber's contract are integrated and highly interdependent, and because the products (including installation) and services must work together to deliver the monitoring, controlling and protection of their home, the Company has concluded that the products and services contracted for by the subscriber are generally not distinct within the context of the contract and, therefore, constitute a single, combined performance obligation. Revenues for this single, combined performance obligation are recognized on a straight-line basis over the subscriber's contract term, which is the period in which the parties to the contract have enforceable rights and obligations. The Company has determined that certain contracts that do not require a long-term commitment for monitoring services by the subscriber contain a material right to renew the contract, because the subscriber does not have to purchase the products upon renewal. Proceeds allocated to the material right are recognized over the period of the benefit. The majority of Vivint Smart Home's subscription contracts are five years and are generally non-cancelable. These contracts generally convert into month-to-month agreements at the dateend of adoption. The Company will recognize the cumulative effectinitial term, while some subscribers are month-to-month from inception. Payment for Vivint Smart Home services is generally due in advance on a monthly basis. Product sales and other one-time fees are invoiced to subscribers at time of 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 June 30, 2023, estimated future fixed fee performance obligations are $742 million for the remaining six months of fiscal year 2023, and evaluating$1.3 billion, $949 million, $622 million, $336 million and $42 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 Smart Home 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. The cleared auction MWs are subject to penalties for non-performance.


17

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 and six months ended June 30, 2023 and 2022:
Summarized results of discontinued operations were as follows:
Three months ended June 30, 2023
(In millions)TexasEastWest/Services/OtherVivint Smart HomeCorporate/EliminationsTotal
Retail revenue:
Home(a)
$1,563 $446 $406 $444 $— $2,859 
Business832 1,912 424 — — 3,168 
Total retail revenue(b)
2,395 2,358 830 444 — 6,027 
Energy revenue(b)
16 28 40 — (1)83 
Capacity revenue(b)
— 49 — — — 49 
Mark-to-market for economic hedging activities(c)
— 52 23 — — 75 
Contract amortization— (7)(1)— — (8)
Other revenue(b)
104 23 — — (5)122 
Total revenue2,515 2,503 892 444 (6)6,348 
Less: Revenues accounted for under topics other than ASC 606 and ASC 815— 6 7 — — 13 
Less: Realized and unrealized ASC 815 revenue14 99 7 — (1)119 
Total revenue from contracts with customers$2,501 $2,398 $878 $444 $(5)$6,216 
(a) Home includes Services and Vivint Smart Home
(b) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 and included in the amounts above:
(In millions)TexasEastWest/Services/OtherVivint Smart HomeCorporate/EliminationsTotal
Retail revenue$— $16 $— $— $— $16 
Energy revenue— 13 (7)— (1)5 
Capacity revenue— 17 — — — 17 
Other revenue14 1 (9)— — 6 
(c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815

18

 
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 June 30, 2022
(In millions)TexasEastWest/Services/OtherCorporate/EliminationsTotal
Retail revenue:
Home(a)
$1,655 $417 $543 $(1)$2,614 
Business910 2,983 444 — 4,337 
Total retail revenue2,565 3,400 987 (1)6,951 
Energy revenue(b)
38 128 131 9 306 
Capacity revenue(b)
— 89 1 — 90 
Mark-to-market for economic hedging activities(c)
(1)(106)(38)(3)(148)
Contract amortization— (11)(2)— (13)
Other revenue(b)
90 14 (3)(5)96 
Total revenue2,692 3,514 1,076 — 7,282 
Less: Revenues accounted for under topics other than ASC 606 and ASC 815— (4)8 — 4 
Less: Realized and unrealized ASC 815 revenue(13)(123)(70)7 (199)
Total revenue from contracts with customers$2,705 $3,641 $1,138 $(7)$7,477 
(a) Home includes Services
(b) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 and included in the amounts above:
(In millions)TexasEastWest/Services/OtherCorporate/EliminationsTotal
Energy revenue$— $(19)$(20)$9 $(30)
Capacity revenue— 9 — — 9 
Other revenue(12)(7)(12)1 (30)
(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 2017.19



Six months ended June 30, 2023
(In millions)TexasEastWest/Services/Other
Vivint Smart Home(a)
Corporate/EliminationsTotal
Retail revenue:
Home(b)
$2,799 $1,097 $1,031 $592 $— $5,519 
Business1,554 5,277 1,040 — — 7,871 
Total retail revenue(c)
4,353 6,374 2,071 592 — 13,390 
Energy revenue(c)
20 102 88 — 1 211 
Capacity revenue(c)
— 90 1 — — 91 
Mark-to-market for economic hedging activities(d)
— 87 90 — (11)166 
Contract amortization— (18)(1)— — (19)
Other revenue(c)
176 44 17 — (6)231 
Total revenue4,549 6,679 2,266 592 (16)14,070 
Less: Revenues accounted for under topics other than ASC 606 and ASC 815— 5 16 — — 21 
Less: Realized and unrealized ASC 815 revenue12 212 104 — (10)318 
Total revenue from contracts with customers$4,537 $6,462 $2,146 $592 $(6)$13,731 
(a) Includes results of operations following the acquisition date of March 10, 2023
(b) Home includes Services and Vivint Smart Home
(c) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 and included in the amounts above:
(In millions)TexasEastWest/Services/OtherVivint Smart HomeCorporate/EliminationsTotal
Retail revenue$— $43 $— $— $— $43 
Energy revenue— 60 10 — 1 71 
Capacity revenue— 23 — — — 23 
Other revenue12 (1)4 — — 15 
(d) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815

20

Six months ended June 30, 2022
(In millions)TexasEastWest/Services/OtherCorporate/EliminationsTotal
Retail revenue:
Home(a)
$2,938 $996 $1,246 $(1)$5,179 
Business1,573 6,925 844 — 9,342 
Total retail revenue4,511 7,921 2,090 (1)14,521 
Energy revenue(b)
53 332 185 14 584 
Capacity revenue(b)
— 204 2 — 206 
Mark-to-market for economic hedging activities(c)
(3)(236)(56)14 (281)
Contract amortization— (20)(2)— (22)
Other revenue(b)
151 28 1 (10)170 
Total revenue4,712 8,229 2,220 17 15,178 
Less: Revenues accounted for under topics other than ASC 606 and ASC 815— (13)19 — 6 
Less: Realized and unrealized ASC 815 revenue(20)(189)(112)27 (294)
Total revenue from contracts with customers$4,732 $8,431 $2,313 $(10)$15,466 
(a) Home includes Services
(b) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 and included in the amounts above:
(In millions)TexasEastWest/Services/OtherCorporate/EliminationsTotal
Energy revenue$— $26 $(40)$13 $(1)
Capacity revenue— 22 — — 22 
Other revenue(17)(1)(16)— (34)
(c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815
Contract Balances
The following table summarizesreflects the major classes ofcontract assets and liabilities classifiedincluded in the Company’s balance sheet as discontinued operationsof June 30, 2023 and December 31, 2022:
(In millions)June 30, 2023December 31, 2022
Deferred customer acquisition costs$422 $126 
Accounts receivable, net - Contracts with customers3,049 4,704 
Accounts receivable, net - Accounted for under topics other than ASC 606194 64 
Accounts receivable, net - Affiliate31 5 
Total accounts receivable, net$3,274 $4,773 
Unbilled revenues (included within Accounts receivable, net - Contracts with customers)$1,297 $1,952 
Deferred revenues(a)
1,658 186 
(a) Deferred revenues from contracts with customers as of June 30, 2023 and December 31, 2022 were approximately $1.6 billion and $175 million, respectively. The increase in deferred revenues is primarily due to acquisition of Vivint Smart Home
The revenue recognized from contracts with customers during the six months ended June 30, 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 six months ended June 30, 2023 and 2022 was primarily due to the timing difference of when consideration was received and when the performance obligation was transferred. The revenue recognized from contracts with customers during the three months ended June 30, 2023 and 2022 relating to the deferred revenue balance at the beginning of each period was $310 million and $106 million, respectively. The change in deferred revenue balances recognized during the three months ended June 30, 2023 was primarily due to the acquisition of Vivint Smart Home.

21

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 31, 2016. As6, 2022, by and among the Company, Vivint Smart Home, Inc. and Jetson Merger Sub, Inc., a wholly-owned subsidiary of the Company (“Merger Sub”) pursuant to which Merger Sub merged with and into Vivint Smart Home, Inc., with Vivint Smart Home, Inc. surviving the merger as a wholly-owned subsidiary of the Company. Dedicated to redefining the home experience with intelligent products and services, Vivint Smart Home brings approximately two million subscribers to NRG. Vivint Smart Home's single, expandable platform incorporates artificial intelligence and machine learning into its operating system and its vertically integrated business model includes hardware, software, sales, installation, support and professional monitoring, enabling superior subscriber experiences and a complete end-to-end smart home experience. The acquisition accelerates the realization of NRG's consumer-focused growth strategy and creates a leading essential home services platform fueled by market-leading brands, unparalleled insights, proprietary technologies and complementary sales channels.
NRG paid $12 per share, or $2.6 billion in cash. The Company funded the acquisition using:
•proceeds of $724 million from newly issued $740 million 7.000% Senior Secured First Lien Notes due 2033, net of issuance costs and discount;
•proceeds of $635 million from newly issued $650 million 10.25% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock, net of issuance costs;
•proceeds of approximately $900 million drawn from its Revolving Credit Facility and Receivables Securitization Facilities; and
•cash on hand.
In February 2023, the Company increased its Revolving Credit Facility by $600 million to meet the additional liquidity requirements related to the acquisition. For further discussion, see Note 9, Long-term Debt and Finance Leases.
Acquisition costs of $2 million and $38 million for the three and six months ended June 14, 2017, NRG no longer consolidates GenOn30, 2023, respectively, are included in acquisition-related transaction and integration costs in the Company's consolidated statement of operations.
The acquisition has been recorded as a business combination under ASC 805, with identifiable assets and liabilities acquired provisionally recorded at their estimated Acquisition Closing Date fair value. The initial accounting for 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 Smart Home, Inc. common shares outstanding as of March 10, 2023 of 216,901,639 at $12.00 per share$2,603 
Other Vivint Smart Home, Inc. equity instruments (Cash out RSUs and PSUs, Stock Appreciation Rights, Private Placement Warrants)6 
Total Cash Consideration$2,609 
Fair value of acquired Vivint Smart Home, Inc. equity awards attributable to pre-combination service14 
Total Consideration$2,623 

22

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)
3,492 
Intangible assets, net(b):
   Customer relationships1,740 
   Technology860 
   Trade name160 
   Sales channel contract10 
Intangible assets, net2,770 
 Deferred income taxes381 
Other non-current assets14 
Total other assets6,692 
Total Assets$7,071 
1)Current LiabilitiesFull releases from GenOn
Current portion of long-term debt and GenOn Americas Generation in favorfinance leases$14 
Current portion of NRG, including either a full release or indemnification in favor of NRG for any claims relating to GenOn Mid-Atlantic or REMAoperating lease liabilities13 
Accounts payable109 
Derivatives instruments80 
Deferred revenue current517 
Accrued expenses and the dismissal of all litigation against NRG.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 
2)Vivint Smart Home Purchase Price
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.
$		2,623 
(a)Goodwill arising from the acquisition is attributed to the value of the platform acquired, cross-selling opportunities, subscriber growth and the synergies expected from combining the operations of Vivint Smart Home with NRG's existing businesses. None of the goodwill recorded is expected to be deductible for tax purposes
(b)The weighted average amortization period for total amortizable intangible assets is approximately ten years

23

Measurement Period Adjustments
The following measurement period adjustments were recognized during the quarter ended June 30, 2023:
(In millions)(Decrease)/Increase
3)NRG 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.
4)NRG will retain the pension liability, including payment of approximately $13 million of 2017 pension contributions, for GenOn employees for service provided prior to the completion of the reorganization, which was paid
Goodwill$(200)
Intangible assets, net270 
Deferred income taxes(70)
   Net change in September 2017. GenOn’s pension liability as of September 30, 2017 was approximately $106 million.assets$— 
5)
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.
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 additionThe measurement period adjustments to the Restructuring Support Agreement, additional support and other agreementsprovisional amounts are being negotiated, including a transition services agreement. See Note 1, Basis of Presentation, for further discussion regarding the October 30, 2017 proposed changesprimarily attributable to the Restructuring Support Agreement.
Settlement Consideration
NRG has determined that the paymentrefinement of the settlement considerationunderlying assumptions used to estimate the fair value of assets acquired as more information was obtained about facts and circumstances that existed as of the Acquisition Closing Date.
Fair Value Measurement of Intangible Assets
The fair values of intangible assets as of the Acquisition Closing Date were measured primarily based on significant inputs that are observable and unobservable in the market and thus represent Level 2 and Level 3 measurements, respectively. Significant inputs were as follows:
Customer relationships — Customer relationships, reflective of Vivint Smart Home’s subscriber base, were valued using an excess earning method of the income approach, and is probableclassified as Level 3. Under this approach, the Company estimated the present value of expected future cash flows resulting from existing subscriber relationships, considering attrition and has recordedcharges 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 subscriber relationships are amortized to depreciation and amortization, ratably based on discounted future cash flows. The weighted average amortization period is twelve years.
Technology – Developed technology was valued using a "relief from royalty" method of the income approach, and is classified as Level 3. Under this approach, the fair value was estimated to be the present value of royalties saved which assumed the value of the asset based on discounted cash flows of the amount 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.The weighted average amortization period is five years.
Trade name — Trade name was valued using a "relief from royalty" method of the income approach, and is classified as Level 3. Under this approach, the fair value is estimated to be the present value of royalties saved which assumed the value of the asset based on discounted cash flows of the amount that would be paid by a hypothetical market participant had they not owned the asset and instead licensed the asset from another company. The estimated cash flows from the trade name considered the expected probable use of the asset and was discounted using a weighted average cost of capital of comparable companies. The trade name is amortized to depreciation and amortization, on a straight line basis, over an amortization period of ten years.
Fair Value Measurement of Acquired Vivint Smart Home Debt
The Company acquired $2.7 billion in accrued expensesaggregate principal of Vivint Smart Home’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 Smart Home 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 Smart Home Debt, of $152 million, is being amortized through interest expense over the remaining term of the debt. The Acquired Vivint Smart Home Debt 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 9, Long-term Debt and Finance Leases.
Fair Value Measurement of Derivatives Liabilities
The derivative liabilities are recorded in connection with the contractual future payment obligations with the financing providers under Vivint Smart Home’s Consumer Financing Program. The fair values of the derivatives liabilities as of the Acquisition Closing Date were valued using a discounted cash flow model, with inputs consisting of available market data, such as market yield discount rates, as well as unobservable internally derived assumptions, such as collateral prepayment rates, collateral default rates and 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.

24

Supplemental Pro Forma Financial Information for the amounts earnedthree and six months ended June 30, 2023 and 2022
The following table provides pro forma combined financial information of NRG and Vivint Smart Home, after giving effect to the Vivint Smart Home acquisition and related financing transactions as if they had occurred on January 1, 2022. The pro forma financial information has been prepared for shared servicesillustrative and informational purposes only, and is not intended to project future operating results or be indicative of approximately $5 million per month. NRGwhat the Company's financial performance would have been had the transactions occurred on the date acquired. No effect has also agreedbeen given to provide GenOnprospective operating synergies.
Three months ended June 30,Six months ended June 30,
(In millions)2023202220232022
Total operating revenues$6,348 $7,690 $14,356 $15,978 
Net income/(loss)342 466 (955)2,018 
Amounts above reflect certain pro forma adjustments that were directly attributable to the Vivint Smart Home acquisition. These adjustments include the following:
(i)Income statement effects of fair value adjustments based on the preliminary purchase price allocation including amortization of intangible assets, reversal of historical Vivint Smart Home amortization of capitalized contract costs and reversal of historical Vivint Smart Home other income recorded for the change in fair value of warrant derivative liabilities, as the warrants are assumed to be cashed out upon the Acquisition Closing Date.
(ii)One time expenses directly related to the acquisition.
(iii)Adjustments to reflect all acquisition and related transactions costs in the six months ended June 30, 2022.
(iv)Interest expense assumes the financing transactions directly attributable to the Vivint Smart Home acquisition occurred on January 1, 2022.
(v)Adjustments related to recording Vivint Smart Home's historical debt at Acquisition Closing Date fair value.
(vi)Adjustments to reflect the write-off of short-term deferred financing costs related to the bridge facility put in place for the acquisition prior to securing permanent financing during the six months ended June 30, 2022 period instead of the six months ended June 30, 2023 period.
(vii)Income tax effect of the acquisition accounting adjustments and financing adjustments (adjusted for permanents book/tax differences) based on combined blended federal/state tax rate for all periods presented.
Dispositions
Planned sale of the 44% equity interest in STP
On May 31, 2023, the Company entered into a definitive equity purchase agreement with a creditConstellation Energy Generation ("Constellation") to sell its 44% equity interest in STP for $1.75 billion, subject to customary purchase price adjustments. The transaction is expected to close by the end of $28 million against amounts owed2023 and is subject to regulatory approval by the NRC. The waiting period under the Services Agreement. Any unused amount can be paidHart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, expired in cash at GenOn’s request. AsJuly 2023.
In July 2023, the City Public Service Board of San Antonio (“CPS”) filed a result, NRG has concluded thatlawsuit claiming the liability for this credit is probable and has recordedexistence of 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, Basisright of Presentation, for further discussion regarding the October 30, 2017 proposed changesfirst refusal to the Restructuring Support AgreementSTP sale transaction (the “CPS Lawsuit”). Austin Energy intervened in the CPS Lawsuit claiming a similar right of first refusal. On July 31, 2023, CPS and Services Agreement.
Commercial Operations
For pre-disposal periods,Austin Energy jointly filed a motion with the NRC seeking to dismiss the pending License Transfer Application (“LTA”) between NRG provided GenOn with services as described in Note 14, Related Party Transactions. Under intercompany agreements, NRG Power Marketing LLC has entered into physical and financial intercompany commodity and hedging transactions with GenOn and certain of its subsidiaries. SubjectConstellation, or 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 conditionshalt their review of the agreements are generally consistent with industry practices and other third party arrangements. For current and pre-disposal periods, revenue and expense associated with these transactions is recorded in continuing operations.
GenOn Debt
As of June 14, 2017, 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 filingLTA pending resolution of the Chapter 11 Cases constitutes an eventCPS lawsuit. NRG filed its answer to the CPS/Austin Energy motion on August 4, 2023.
Sale of default under the following debt instruments 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).
Transfer of Assets Under Common ControlAstoria
On November 1, 2017, NRG completedJanuary 6, 2023, the Company closed on the sale of a 38 MW solar portfolio primarily comprised ofland and related generation assets from SPP funds, in additionthe Astoria site, within the East region of operations, for initial proceeds of $212 million, subject to other projects developed by NRG, to NRG Yield, Inc. for cash considerationtransaction fees of $71 million, plus $3 million and certain indemnifications, resulting in working capital adjustments.a $199 million gain. 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 after decommissioning is complete.
Sale of Watson
On AugustJune 1, 2017, NRG2022, the Company closed on the sale of its 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, including working capital adjustment 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% interest49% ownership 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. 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.Watson natural gas generating facility 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 interests 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$59 million. The Company also borrowed additional amounts of $65 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. As part of the sale, 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 lossgain on the sale of the equity interest$46 million.

25

Held-for-sale
As 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% of its interests in the Rockford I and Rockford II generating stations, or Rockford, for cash consideration of $55 million, subject to adjustments for working capital and the results 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 reduce2023, 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 assetsfollowing is classified as held for sale for Rockford on its balance sheet. On July 12, 2016,in the Company completedCondensed Consolidated Balance Sheets, primarily related to the planned sale of Rockford for cash proceedsSTP, which is in the Texas segment:
(In millions)
   Inventory$63 
   Prepayments and other current assets12 
Current assets - held-for-sale$75 
Property, plant and equipment, net$227 
Intangible assets, net12 
       Nuclear decommissioning trust fund922 
Non-current assets - held-for-sale$1,161 
Total assets held-for-sale$1,236 
Current liabilities - held-for-sale$36 
    Nuclear decommissioning reserve$336 
    Nuclear decommissioning trust liability551 
   Other non-current liabilities60 
Non-current liabilities - held-for-sale$947 
Total liabilities held-for-sale$983 
The Company recorded income before income taxes from its 44% equity interest in STP as follows:
Three months ended June 30,Six months ended June 30,
(In millions)2023202220232022
Income before income taxes(a)
$23 $121 $7 $156 
(a)Excludes the impact of $56 million, including $1 million in adjustments for the PJM base residual auction results. For further discussion on this impairment, refer to Company's hedges at the portfolio level

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:
June 30, 2023December 31, 2022
(In millions)Carrying AmountFair ValueCarrying AmountFair Value
Convertible Senior Notes$575 $618 $575 $576 
Other long-term debt, including current portion11,535 10,563 7,523 6,432 
Total long-term debt, including current portion(a)
$12,110 $11,181 $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

26

The fair value of the Company's publicly-traded long-term debt isand the Vivint Smart Home Senior Secured Term Loan are based on quoted market prices and isare classified as Level 2 within the fair value hierarchy. The estimated fair value of debt securities, non-publicly traded long-term debt and certain notes receivable of the Company are based on expected future cash flows discounted atborrowing under the Revolving Credit Facility approximates the carrying 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 SeptemberJune 30, 20172023 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



June 30, 2023December 31, 2022
(In millions)Level 2Level 3Level 2Level 3
Convertible Senior Notes$618 $— $576 $— 
Other long-term debt, including current portion9,863 700 6,432 — 
Total long-term debt, including current portion$10,481 $700 $7,008 $— 
Recurring Fair Value Measurements
Debt securities, equity securities, and trust fund investments, which are comprised of various U.S. debt and equity securities, and derivative assets and liabilities, are carried at fair market value.
The following tables present assets and liabilities measured and recorded at fair value on the Company's condensed consolidated balance sheets on a recurring basis and their level within the fair value hierarchy:
June 30, 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 (classified within non-current assets - held-for-sale): 
Cash and cash equivalents21 21 — — 
U.S. government and federal agency obligations90 88 2 — 
Federal agency mortgage-backed securities103 — 103 — 
Commercial mortgage-backed securities34 — 34 — 
Corporate debt securities116 — 116 — 
Equity securities464 464 — — 
Foreign government fixed income securities1 — 1 — 
Derivative assets: 
Foreign exchange contracts8 — 8 — 
Commodity contracts7,301 1,225 4,564 1,512 
Interest rate contracts24 — 24 — 
Measured using net asset value practical expedient:
Equity securities — nuclear trust fund investments (classified within non-current assets - held-for-sale)93 
       Equity securities (classified within other non-current assets)6 
Total assets$8,280 $1,798 $4,871 $1,512 
Derivative liabilities: 
Foreign exchange contracts$6 $— $6 $— 
Commodity contracts5,600 1,072 3,921 607 
Consumer Financing Program115 — — 115 
Total liabilities$5,721 $1,072 $3,927 $722 

27

As of September 30, 2017December 31, 2022
Fair ValueFair 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 ninesix months ended SeptemberJune 30, 20172023 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 June 30, 2023Three months ended June 30, 2022Six months ended June 30, 2023Six months ended June 30, 2022
Beginning balance$471 $528 $505 $293 
    Total (losses)/gains realized/unrealized included in earnings(86)293 (177)459 
Purchases99 6 140 29 
Transfers into Level 3(b)
414 568 438 621 
Transfers out of Level 3(b)
7 8 (1)1 
Ending balance$905 $1,403 $905 $1,403 
(Losses)/Gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of period end$(76)$297 $(131)$534 
(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.


28

The following table reconciles, for the three and six months ended June 30, 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)
Consumer Financing Program
(In millions)Three months ended June 30, 2023Six months ended June 30, 2023
Beginning balance$111 $— 
Contractual obligations added from the acquisition of Vivint Smart Home— 112 
New contractual obligations20 22 
Settlements(19)(22)
Total losses included in earnings3 3 
Ending balance$115 $115 
 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,Gains and losses that are related to the Consumer Financing Program derivative are recorded in other income, net.
(b)Transfers into/out of Level 3 are related to the availability of external broker quotes and are valued as of the end of the reporting period. All transfers in/out are with Level 2.


 Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
 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)Consists of derivative assets and liabilities, net.
(b)Transfers into/out of Level 3 are related to the availability of external broker quotes and are valued as of the end of the reporting period. All transfers in/out are with Level 2.

Derivative Fair Value Measurements
A portion of NRG's contracts are exchange-traded contracts with readily available quoted market prices. A majority of NRG's contracts are non-exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter and on-line exchanges. The remainder of the assets and liabilities represent contracts for which external sources or observable market quotes are not available 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 SeptemberJune 30, 2017,2023, contracts valued with prices provided by models and other valuation techniques make up 14%21% of the total derivative assets and 18%13% 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 SeptemberJune 30, 20172023 and December 31, 2016:2022:
June 30, 2023
Fair ValueInput/Range
(In millions)AssetsLiabilitiesValuation TechniqueSignificant Unobservable InputLowHighWeighted Average
Natural Gas Contracts$105 $123 Discounted Cash FlowForward Market Price (per MMBtu)$1 $17 $4 
Power Contracts1,373 427 Discounted Cash FlowForward Market Price (per MWh)1 263 47 
FTRs34 57 Discounted Cash FlowAuction Prices (per MWh)(23)146 1 
Consumer Financing Program— 115 Discounted Cash FlowCollateral Default Rates1.51 %76.59 %5.86 %
Discounted Cash FlowCollateral Prepayment Rates2.00 %3.00 %2.64 %
Discounted Cash FlowLoss Severity Rates6.00 %36.00 %10.20 %
$1,512 $722 

29

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 SeptemberJune 30, 20172023 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 SeptemberJune 30, 2017,2023, the credit reserve resulted in a $1$8 million increase in fair value in operating revenue anddecrease primarily within cost of operations. As of December 31, 2016,2022, the credit reserve resulted in a $10$9 million decrease in fair value in operating revenue andprimarily 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.



30

Counterparty Credit Risk
The Company's counterparty credit risk policies are disclosed in its 20162022 Form 10-K. As of SeptemberJune 30, 2017, the Company's2023, 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.$1.9 billion and NRG held collateral (cash and letters of credit) against those positions of $14$616 million,. resulting in a net exposure of $1.3 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%59% 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 other9173 %
Financial institutions927 
Total as of SeptemberJune 30, 20172023100%
Net Exposure (a)(b)
Category by Counterparty Credit Quality(% of Total)
Investment grade7955 %
Non-InvestmentNon-investment grade/Non-Ratednon-rated2145 
Total as of SeptemberJune 30, 20172023100%
(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 certain counterparties, eachone wholesale counterparty in excess of which represent more than 10% of total net exposure discussed above. The aggregate of such counterparties' exposure was $50 millionas of SeptemberJune 30, 2017.2023. 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 SeptemberJune 30, 2017,2023, aggregate credit risk exposure managed by NRG to these counterparties was approximately $4.3 billion, including $2.8 billion related to assets of NRG Yield, Inc.,$889 million 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 Smart Home, 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-moneyin-

31

the-money 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 SeptemberJune 30, 2017,2023, 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. As of June 30, 2023, the trust liability is classified within non-current liabilities - held-for-sale on the Company's condensed consolidated balance sheet.
The following table summarizes the aggregate fair values and unrealized gains and losses (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 June 30, 2023, the trust funds are classified within non-current assets - held-for-sale on the Company's condensed consolidated balance sheet.
As of June 30, 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$21 $— $— — $15 $— $— — 
U.S. government and federal agency obligations44
 2
 —
 10
 73
 1
 —
 11
U.S. government and federal agency obligations90 1 5 1286 — 5 11
Federal agency mortgage-backed securities74
 1
 1
 24
 62
 1
 1
 25
Federal agency mortgage-backed securities103 — 8 25101 — 11 26
Commercial mortgage-backed securities11
 —
 —
 23
 17
 —
 1
 26
Commercial mortgage-backed securities34 — 4 2935 — 4 30
Corporate debt securities108
 2
 1
 11
 84
 1
 2
 11
Corporate debt securities116 — 10 12114 — 13 12
Equity securities398
 260
 —
 —
 346
 214
 —
 —
Equity securities557 408 — — 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$922 $409 $27 $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.
 Six months ended June 30,
(In millions)20232022
Realized gains$6 $8 
Realized losses(10)(11)
Proceeds from sale of securities180 278 

 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 SeptemberJune 30, 2017,2023, 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 2036 that qualified for the NPNS exception and were therefore exempt from fair value accounting treatment.

32

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 Smart Home acquisition. Additionally, the Company has entered into interest rate swaps to hedge the floating rate on the Revolving Credit Facility extending through 2024, with $400 million outstanding as of June 30, 2023.
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 SeptemberJune 30, 2017,2023, NRG had foreign exchange contracts extending through 2027. The Company marks these derivatives to market through the statement of operations.
Consumer Financing Program
Under the Consumer Financing Program, Vivint Smart Home pays a monthly fee to Financing Providers based on either the average daily outstanding balance of the Loans or the number of outstanding Loans. For certain loans, Vivint Smart Home incurs fees at the time of the loan origination and receives proceeds that are net of these fees. Vivint Smart Home also shares the liability for credit losses, depending on the credit quality of the subscriber. Due to the nature of certain provisions under the Consumer Financing Program, the Company 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 Smart Home pays either a monthly fee based on the average daily outstanding balance of the Loans, or the number of outstanding Loans, depending on the Financing Provider;
•    Vivint Smart Home shares the liability for credit losses depending on the credit quality of the subscriber; and
•    Vivint Smart Home pays transactional fees associated with subscriber payment processing.
The derivative is classified as a Level 3 instrument. The derivative positions are valued using a discounted cash flow 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 Smart Home will be obligated to pay to the Financing Provider for each component of the derivative.
Volumetric Underlying Derivative Transactions
The following table summarizes the net notional volume buy/(sell) of NRG's open derivative transactions broken out by category, excluding those derivatives that qualified for the NPNS exception, as of SeptemberJune 30, 20172023 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)
CategoryUnitsJune 30, 2023December 31, 2022
EmissionsShort Ton— 1 
Renewable Energy CertificatesCertificates13 15 
CoalShort Ton12 11 
Natural GasMMBtu804 422 
OilBarrels— 1 
PowerMWh210 192 
Consumer Financing ProgramDollars942 — 
Foreign ExchangeDollars590 569 
InterestDollars1,400 — 

33

  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)June 30, 2023December 31, 2022June 30, 2023December 31, 2022
Derivatives Not Designated as Cash Flow or Fair Value Hedges:   
Interest rate contracts - current$20 $— $— $— 
Interest rate contracts - long-term4 — — — 
Foreign exchange contracts - current5 11 3 1 
Foreign exchange contracts - long-term3 7 3 1 
Consumer Financing Program - short-term— — 78 — 
Consumer Financing Program - long-term— — 37 — 
Commodity contracts - current4,398 7,875 3,751 6,194 
Commodity contracts - long-term2,903 4,101 1,849 2,245 
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges$7,333 $11,994 $5,721 $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 June 30, 2023
Foreign exchange contracts:
Derivative assets$8 $(5)$— $3 
Derivative liabilities(6)5 — (1)
Total foreign exchange contracts$2 $— $— $2 
Commodity contracts:
Derivative assets$7,301 $(5,344)$(340)$1,617 
Derivative liabilities(5,600)5,344 5 (251)
Total commodity contracts$1,701 $— $(335)$1,366 
Consumer Financing Program:
Derivative liabilities$(115)$— $— $(115)
Interest rate contracts:
Derivative assets$24 $— $— $24 
Total derivative instruments$1,612 $— $(335)$1,277 

34

  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. 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 are included within interest expense. The effect of the Consumer Financing Program is included in interest expense.other income, net.

(In millions)Three months ended June 30,Six months ended June 30,
Unrealized mark-to-market results2023202220232022
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges$(151)$(197)$(997)$(605)
Reversal of acquired loss/(gain) positions related to economic hedges35 48 10 (12)
Net unrealized gains/(losses) on open positions related to economic hedges180 868 (893)3,613 
Total unrealized mark-to-market gains/(losses) for economic hedging activities64 719 (1,880)2,996 
Reversal of previously recognized unrealized losses on settled positions related to trading activity10 8 11 9 
Net unrealized gains/(losses) on open positions related to trading activity3 (10)14 (25)
Total unrealized mark-to-market gains/(losses) for trading activity13 (2)25 (16)
Total unrealized gains/(losses) - commodities and foreign exchange$77 $717 $(1,855)$2,980 

Three months ended June 30,Six months ended June 30,
(In millions)2023202220232022
Unrealized gains/(losses) included in revenues - commodities$88 $(150)$191 $(297)
Unrealized gains/(losses) included in cost of operations - commodities5 858 (2,032)3,272 
Unrealized (losses)/gains included in cost of operations - foreign exchange(16)9 (14)5 
Total impact to statement of operations - commodities and foreign exchange$77 $717 $(1,855)$2,980 
Total impact to statement of operations - consumer financing program$(3)$— $(3)$— 
Total impact to statement of operations - interest rate contracts$29 $— $24 $— 
 Three months ended September 30, Nine months ended September 30,
 2017 2016 2017 2016
Unrealized mark-to-market results(In millions)
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges$(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)
35

The reversals of acquired gain or lossloss/(gain) 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 ninesix months ended SeptemberJune 30, 2017,2023, the $1$893 million unrealized loss 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 decreasesprices in coal, natural gas,the East 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.West.
For the ninesix months ended SeptemberJune 30, 2016,2022, the $27 million$3.6 billion unrealized gain from open economic hedge positions was primarily the result of an increase in value of forward purchases of natural gas due to increases in the value of forward positions as a result of increases in natural gas and power prices.


Credit Risk Related Contingent Features
Certain of the Company's 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 SeptemberJune 30, 2017,2023 was $27 million. The collateral required for contracts with credit rating contingent features as of September 30, 2017, was $34$743 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$91 million as of SeptemberJune 30, 2017.2023. In the event of a downgrade in the Company's credit rating and if called for by the counterparty, $15 million of additional collateral would be required for all contracts with credit rating contingent features as of June 30, 2023.
See Note 4, 5, Fair Value of Financial Instruments, to this Form 10-Q for discussion regarding concentration of credit risk.

Note 78 — Impairments

20172022 Impairment Losses
Bacliff Project PJM Asset Impairments— 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 2017,2022, the results of the PJM Base Residual Auction for the 2023/2024 delivery year were released leading the Company recorded impairment lossesto revise its long-term view of approximately $22 million in connection withcertain facilities and announce 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 amountplanned retirement of the Joliet generating facility in 2023. The Company considered the near-term retirement date of Joliet and the decline in PJM capacity prices to be a trigger for impairment and performed impairment tests on the PJM generating assets and as a result, the assets were considered to be impaired.goodwill associated with Midwest Generation. The Company measured the impairment loss aslosses on the difference between the carrying amount of thePJM generating 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 lossMidwest Generation goodwill as the difference between the carrying amount and the fair value of the investmentPJM generating assets and Midwest Generation reporting unit, respectively. Fair values were determined using an income approach in which the Company applied a discounted cash flow methodology to the long-term budgets for the plants and reporting unit. Significant inputs impacting the income approach include the Company's long-term view of capacity and fuel prices, projected generation, the physical and economic characteristics of each plant and the reporting unit as a whole, and the discount rate applied to the after-tax cash flow projections. Impairment losses of $20 million and $130 million were recorded an impairment lossin the second quarter of $140 million.2022 in the East segment on the PJM generating assets and Midwest Generation goodwill, respectively.


36

                                                                                                                                                



Note 89 — 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)June 30, 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 Facility700 — various
Tax-exempt bonds466 466 1.250 - 4.750
Subtotal recourse debt9,540 8,100 
Non-recourse debt:
Vivint Smart Home Senior Secured Notes, due 2027600 — 6.750
Vivint Smart Home Senior Notes, due 2029800 — 5.750
Vivint Smart Home Senior Secured Term Loan, due 20281,326 — various
Subtotal all Vivint Smart Home non-recourse debt2,726 — 
Subtotal long-term debt (including current maturities)12,266 8,100 
Finance leases19 11 various
Subtotal long-term debt and finance leases (including current maturities)12,285 8,111 
Less current maturities(1,319)(63)
Less debt issuance costs(73)(70)
Discounts(156)(2)
Total long-term debt and finance leases$10,737 $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 July 31, 2023, the Utah Portfolio term loans.


Convertible Senior Notes were convertible at a price of $42.17, which is equivalent to a conversion rate of approximately 23.7112 shares of common stock per $1,000 principal amount
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.subsidiaries that guarantee indebtedness under the Revolving Credit Facility. The 2033 Senior Secured First Lien Notes are secured by a first priority security interest in the same collateral that is pledged for the benefit of the lenders under the Revolving Credit Facility, which collateral consists of a substantial portion of the property and assets owned by the Company and the guarantors. The collateral securing the 2033 Senior Secured First Lien Notes will be released at the Company’s request if the senior unsecured long-term debt securities of the Company are rated investment grade by any two of the three rating agencies, subject to reversion if such rating agencies withdraw such investment grade rating or downgrade such rating below investment grade. Interest is paid semi-annually beginning on 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 proceeds from certain other financings, were used to fund the acquisition of Vivint Smart Home.
Issuance of 2027

37

2048 Convertible Senior Notes
As of June 30, 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 $42.57 per common share, which is equivalent to a conversion rate of approximately 23.4925 shares of common stock per $1,000 principal amount of Convertible Senior Notes. The net carrying amounts of the Convertible Senior Notes as of June 30, 2023 and December 31, 2022 were $571 million and $570 million, respectively. The Convertible Senior Notes mature on June 1, 2048, unless earlier repurchased, redeemed or converted in accordance with their terms. The Convertible Senior notes are convertible at the option of the holders under certain circumstances. Prior to the close of business on the business day immediately preceding December 1, 2024, the Convertible Senior Notes will be convertible only upon the occurrence of certain events and during certain periods, and thereafter during specified periods as follows:
•from December 1, 2024 until the close of business on the second scheduled trading day immediately before June 1, 2025; and
•from December 1, 2047 until the close of business on the second scheduled trading day immediately before the maturity date
The following table details the interest expense recorded in connection with the Convertible Senior Notes, due 2048:
Three months ended June 30,Six months ended June 30,
($ In millions)2023202220232022
Contractual interest expense$4 $4 $8 $8 
Amortization of deferred finance costs— 1 1 1 
Total$4 $5 $9 $9 
Effective Interest Rate0.75 %0.76 %1.52 %1.52 %
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 further amended its Revolving Credit Facility to increase the existing revolving commitments by an additional $45 million. As of June 30, 2023, there were outstanding borrowings of $700 million and there were $823 million in letters of credit issued under the Revolving Credit Facility. As of July 31, 2023, there were outstanding borrowings of $700 million and $879 million in letters of credit issued under the Revolving Credit Facility.
Bilateral Letter of Credit Facilities
On May 19, 2023 and May 30, 2023, the Company increased the size of its bilateral letter of credit facilities by $25 million and $100 million, respectively, to provide additional liquidity and to allow for the issuance of up to $800 million of letters of credit. These facilities are uncommitted. As of June 30, 2023, $589 million was issued under these facilities.
Receivables Securitization Facilities
On June 22, 2023, NRG issued $1.25Receivables LLC (“NRG Receivables”), an indirect wholly-owned subsidiary of the Company, amended its existing Receivables Facility to, among other things, (i) extend the scheduled termination date to June 21, 2024, (ii) increase the aggregate commitments from $1.0 billion to $1.4 billion (adjusted seasonally) and (iii) add a new originator. As of June 30, 2023, there were no outstanding borrowings and there were $842 million in letters of credit issued.
In addition, in connection with the amendments to the Receivables Facility, on June 22, 2023, the Company and the originators thereunder renewed the existing uncommitted Repurchase Facility. Such renewal, among other things, extended the maturity date to June 21, 2024 and joined an additional originator to the Repurchase Facility. As of June 30, 2023, there were no outstanding borrowings.
For further information on the above facilities, see Note 13, Long-term Debt and Finance Leases, of the Company's 2022 Form 10-K.

38

Dunkirk Bonds
On April 3, 2023, NRG remarketed $59 million in aggregate principal amount of 4.25% tax-exempt refinancing bonds of the Chautauqua County Capital Resource Corporation (the "Dunkirk Bonds"). The Dunkirk Bonds are guaranteed on a first-priority basis by each of NRG's current and future subsidiaries that guarantee indebtedness under the Revolving Credit Facility. The Dunkirk Bonds are secured by a first priority security interest in the same collateral that is pledged for the benefit of the lenders under the Revolving Credit Facility, which consists of a substantial portion of the property and assets owned by NRG and the guarantors. The collateral securing the Dunkirk Bonds will, at 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 directAcquired Vivint Smart Home Debt
On March 10, 2023, in connection with the Vivint Smart Home acquisition, Vivint Smart Home's indirect wholly owned 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 Smart Home 2027 Senior Secured Notes
Vivint Smart Home has outstanding $600 million aggregate principal amount of 6.750% senior secured notes due 2027 (the "Vivint Smart Home 2027 Senior Secured Notes"). The Vivint Smart Home 2027 Senior Secured Notes are senior secured obligations of APX and are guaranteed by APX Group Holdings, Inc., each of APX's existing and future wholly owned U.S. restricted subsidiaries (subject to customary exclusions and qualifications) and Vivint Smart Home. Interest on the Vivint Smart Home 2027 Senior Secured Notes is paid semi-annually in arrears on February 15 and August 15 until the maturity date of February 15, 2027.
Vivint Smart Home 2029 Senior Notes
Vivint Smart Home has outstanding $800 million aggregate principal amount of 5.750% senior notes due 2029 (the "Vivint Smart Home 2029 Senior Notes"). The Vivint Smart Home 2029 Senior Notes are senior unsecured obligations of APX and are guaranteed by APX Group Holdings, Inc., each of APX's existing and future wholly owned U.S. restricted subsidiaries (subject to customary exclusions and qualifications) and Vivint Smart Home. Interest on the Vivint Smart Home 2029 Senior Notes is paid semi-annually in arrears on January 15 and July 15 until the maturity date of July 15, 2029.
Vivint Smart Home Senior Secured Credit Facilities
The Vivint Smart Home senior secured credit agreement (the “Vivint Smart Home Credit Agreement”) provides for (i) a term loan facility in an aggregate principal amount of $1.4 billion (the “Vivint Smart Home Term Loan Facility”, and the loans thereunder, the “Vivint Smart Home Term Loans”) and (ii) a revolving credit facility in an aggregate principal amount of $370 million (the “Vivint Smart Home Revolving Credit Facility,” and the loans thereunder, the “Vivint Smart Home Revolving Loans”).
All of APX’s obligations under the Vivint Smart Home Credit Agreement are guaranteed by APX Group Holdings, Inc. and each of APX’s existing and future wholly-owned U.S. restricted subsidiaries (subject to customary exclusions and qualifications). The obligations under the Vivint Smart Home Credit Agreement are secured by a first priority perfected security interest in (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 certain excluded assets and subject to the limitations and exclusions provided in the applicable collateral documents.

39

The Vivint Smart Home 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 Smart Home 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;
•materially change the issuancenature of letterstheir business;
•enter into agreements that restrict the ability of credit. At Septemberrestricted subsidiaries to make dividends or other payments to APX or grant liens on their assets;
•designate restricted subsidiaries as unrestricted subsidiaries;
•amend, prepay, redeem or purchase certain material contractually subordinated debt; and
•transfer or sell certain assets.
On June 9, 2023, Vivint Smart Home entered into an amendment to the Vivint Smart Home Credit Agreement which transitioned the benchmark rate applicable to the Vivint Smart Home Term Loans and the Vivint Smart Home Revolving Loans from LIBOR to SOFR. As of June 30, 2017, there2023, the aggregate outstanding principal amount of the Vivint Term Loans was $68$1.3 billion. As of June 30, 2023, Vivint Smart Home had $10 million ofin letters of credit issued under the revolving credit facilityVivint Smart Home Revolving Credit Facility and no borrowing outstanding onborrowings.

Note 10 — Investments Accounted for Using the revolver.
Project Financings
Agua Caliente Project Financing
On February 17, 2017, Agua Caliente Borrower 1 LLCEquity Method 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% 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. During 2022, the equity method of accounting for Ivanpah was suspended based on losses generated by the project, including the impact of debt service and depreciation.
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)June 30, 2023December 31, 2022
Accounts receivable and Other current assets$1,256 $2,108 
Current liabilities152 152 
Net assets$1,104 $1,956 


40
(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 1011 — Changes in Capital Structure
As of SeptemberJune 30, 20172023 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— 778,213 — 778,213 
Shares issued under ESPP— — 86,516 86,516 
Issuance of Series A Preferred Stock650,000 — — — 
Balance as of June 30, 2023650,000 424,675,214 (194,249,455)230,425,759 
Shares issued under LTIPs— 13,812 — 13,812 
Shares repurchased— — (1,322,141)(1,322,141)
Balance as of July 31, 2023650,000 424,689,026 (195,571,596)229,117,430 
 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,Share Repurchases
In June 2023, NRG entered an agreement with Credit Suisse Grouprevised its long-term capital allocation policy to repurchase 100%target allocating approximately 80% of cash available for allocation, after debt reduction, to be returned to shareholders. As part of the outstandingrevised capital allocation framework, the Company announced an increase to its share repurchase authorization to $2.7 billion, to be executed through 2025. During July 2023, the Company purchased 1,322,141 shares for $50 million at an average price of $37.82 under the $2.7 billion authorization.
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 90% of its market value on the offering date or 90% of the redemptionfair market value on the exercise date. An offering date occurs each April 1 and October 1. An exercise date occurs each September 30 and March 31. On April 27, 2023, NRG stockholders approved the adoption of $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 included a reduction in the price at which eligible employees may purchase shares of NRG common stock from 95% to 90% of the fair market value of the shares on the applicable date. NRG stockholders also approved an increase of 3,000,0004,400,000 shares available for issuance under the ESPP. As of September 30, 2017, there were 3,107,050 shares of treasury stock available for issuance under the ESPP.
Amended and Restated Long-term Incentive Plan
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 SeptemberJune 30, 2017:
 Third Quarter 2017 Second Quarter 2017
First Quarter 2017
Dividends per Common Share$0.03
 $0.03

$0.03
2023. On October 18, 2017,July 17, 2023, NRG declared a quarterly dividend on the Company's common stock of $0.03$0.3775 per share, payable Novemberon August 15, 2017,2023 to stockholders of record as of NovemberAugust 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 $635 million, net of issuance costs, were used to partially fund the Vivint Smart Home acquisition.
The Series A Preferred Stock is not convertible into or exchangeable for any other securities or property and has limited voting rights. The Series A Preferred Stock may be redeemed, in whole or in part, on one or more occasions, at the option of the Company at any time after March 15, 2028 ("Series A First Reset Date") and in certain other circumstances prior to the Series A First Reset Date.

41

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 1112 — Earnings/Income/(Loss) Per Share
Basic earnings/income/(loss) per common share is computed by dividing net income/(loss) 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/income/(loss) per share is computed in a manner consistent with that of basic income/(loss) 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 income/(loss) 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 three and six months ended June 30, 2023 and 2022, there was no dilutive effect for the Convertible Senior Notes since there were no potential share settlements for the periods.
NRG's basic and diluted earnings/income/(loss) per share is shown in the following table:
 Three months ended September 30, Nine months ended September 30,
(In millions, except per share data)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
Three months ended June 30,Six months ended June 30,
(In millions, except per share data)2023202220232022
Basic income/(loss) per share:
Net income/(loss)$308 $513 $(1,027)$2,249 
Less: Cumulative dividends attributable to Series A Preferred Stock17 — 21 — 
Net income/(loss) available for common stockholders$291 $513 $(1,048)$2,249 
Weighted average number of common shares outstanding - basic231 237 230 240 
Income/(loss) per weighted average common share — basic$1.26 $2.16 $(4.56)$9.37 
Diluted income/(loss) per share:
Net income/(loss)$308 $513 $(1,027)$2,249 
Less: Cumulative dividends attributable to Series A Preferred Stock17 — 21 — 
Net income/(loss) available for common stockholders$291 $513 $(1,048)$2,249 
Weighted average number of common shares outstanding - basic231 237 230 240 
Incremental shares attributable to the issuance of equity compensation (treasury stock method)1 — — — 
Weighted average number of common shares outstanding - dilutive232 237 230 240 
 Income/(loss) per weighted average common share — diluted$1.25 $2.16 $(4.56)$9.37 
The following table summarizes NRG’sthe Company's outstanding equity instruments that are anti-dilutive and were not included in the computation of the Company’sCompany's diluted earnings/income/(loss) per share:
Three months ended June 30,Six months ended June 30,
(In millions of shares)2023202220232022
Equity compensation plans1 — 7 — 

42
 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 1213 — Segment Reporting
The Company'sCompany’s segment structure reflects how management currently makes financial decisions and allocates resources. The Company'sCompany manages its operations based on the combined results of the retail and wholesale generation 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.with a geographical focus. The financial information for 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,operations 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 theVivint Smart Home acquisition as if they had occurred at the beginning of the financial statement period.
On June 14, 2017, as described in Note 3, Discontinued Operations, Dispositions 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 operationsare reported within the corporateVivint Smart Home segment.
NRG’s chief operating decision maker, its chief executive officer, evaluates the performance of itsthe Company's segments based on operational measures including adjusted earnings before interest, taxes, depreciation and amortization, or Adjusted EBITDA, free cash flow and allocation of capital, for allocation, as well as net income/(loss). The accounting policies of the segments are the same as those applied in the consolidated financial statements as disclosed in Note 2, Summary of Significant Accounting Policies, to the Company’s 2022 Form 10-K.

Three months ended June 30, 2023
(In millions)TexasEastWest/Services/OtherVivint Smart HomeCorporateEliminationsTotal
Revenue$2,515 $2,503 $892 $444 $— $(6)$6,348 
Depreciation and amortization73 30 23 180 9 — 315 
Gain on sale of assets— 3 — — — — 3 
Equity in earnings of unconsolidated affiliates— — 5 — — — 5 
Income/(loss) before income taxes785 (100)(128)(23)(137)— 397 
Net income/(loss)$785 $(101)$(129)$(23)$(224)$— $308 
Three months ended June 30, 2022
(In millions)TexasEastWest/Services/OtherCorporateEliminationsTotal
Revenue$2,692 $3,514 $1,076 $— $— $7,282 
Depreciation and amortization77 50 22 8 — 157 
Impairment losses— 155 — — — 155 
(Loss)/gain on sale of assets(12)— 44 — — 32 
Equity in earnings of unconsolidated affiliates— — 4 — — 4 
Income/(loss) before income taxes762 (13)35 (119)— 665 
Net income/(loss)$762 $(12)$24 $(261)$— $513 
Six months ended June 30, 2023
(In millions)TexasEastWest/Services/Other
Vivint Smart Home(a)
CorporateEliminationsTotal
Revenue$4,549 $6,679 $2,266 $592 $— $(16)$14,070 
Depreciation and amortization148 60 47 232 18 — 505 
Gain on sale of assets— 202 — — — — 202 
Equity in earnings of unconsolidated affiliates— — 10 — — — 10 
Income/(loss) before income taxes1,069 (1,502)(479)(62)(300)— (1,274)
Net income/(loss)$1,069 $(1,503)$(433)$(62)$(98)$— $(1,027)
(a)Includes results of operations following the acquisition date of March 10, 2023
Six months ended June 30, 2022
(In millions)TexasEastWest/Services/OtherCorporateEliminationsTotal
Revenue$4,712 $8,229 $2,220 $— $17 $15,178 
Depreciation and amortization154 127 43 16 — 340 
Impairment losses— 155 — — — 155 
(Loss)/gain on sale of assets(12)— 43 (2)— 29 
Equity in losses of unconsolidated affiliates(1)— (10)— — (11)
Income/(loss) before income taxes1,533 1,525 164 (250)— 2,972 
Net income/(loss)$1,533 $1,526 $154 $(964)$— $2,249 

 
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

(a) Operating revenues include inter-segment sales and net derivative gains and losses of:$491
 $(8) $19
 $—
 $21
 $—
 $523
43
 
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) Operating revenues include inter-segment sales and net derivative gains and losses of:$506
 $(2) $8
 $—
 $50
$52
$—
 $562




 
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 1314 — Income Taxes
Effective Income Tax Rate
The income tax provision consisted of the following:
 Three months ended June 30,Six months ended June 30,
(In millions, except rates)2023202220232022
Income/(Loss) before income taxes$397 $665 $(1,274)$2,972 
Income tax expense/(benefit)89 152 (247)723 
Effective income tax rate22.4 %22.9 %19.4 %24.3 %
 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 ninesix months ended SeptemberJune 30, 2017, NRG's overall2023, 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 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.
expense which has an inverted effect and reduces the effective tax rate when applied to year-to-date financial statement losses. For the three months ended SeptemberJune 30, 2016, NRG's overall2023, the effective tax rate was differenthigher 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 and state tax expense.
For the ninethree and six months ended SeptemberJune 30, 2016, NRG's overall2022, 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 expense partially offset by tax benefit resulting from the release of valuation allowance on state net operating losses.

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 SeptemberJune 30, 2017,2023, NRG has recordedhad a non-current tax liability of $40$45 million for uncertain tax benefits from positions taken on various federal and state income tax returns includinginclusive of accrued interest. For the ninesix months ended SeptemberJune 30, 2017,2023, NRG accrued an immaterial amount of interest relating to the uncertain tax benefits. As of SeptemberJune 30, 2017,2023, 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 1415 — 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 June 30,Six months ended June 30,
(In millions)2023202220232022
Revenues from Related Parties Included in Revenue   
Gladstone$— $— $1 $1 
Ivanpah(a)
21 9 55 22 
Midway-Sunset1 1 2 3 
Total$22 $10 $58 $26 
(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 agreements with each project company


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Note 3, Discontinued Operations, Dispositions and Acquisitions, in connection 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.
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 GenOn
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.
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 1516 — 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 SeptemberJune 30, 2017,2023, 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 17, Regulatory Matters, and Note 18, Environmental Matters. In addition, legal costs are expensed as incurred. Management has assessed each of the following matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought, and the probability of success. Unless specified below, the Company is unable to predict the outcome of these legal proceedings or reasonably estimate the scope or amount of any associated costs and potential liabilities. As additional information becomes available, management adjusts its assessment and estimates of such contingencies accordingly. Because litigation is subject to inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate resolution of the Company's liabilities and contingencies could be at amounts that are different from its currently recorded 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 held hearings regarding the appropriate relief. Midwest Generation has been working with the Illinois EPA to address the groundwater issues since 2010.
Consumer Lawsuits
Similar to other energy service companies (“ESCOs”) operating in the industry, from time-to-time, the Company and/or its subsidiaries may be subject to potential asbestos liabilities as a result of its acquisition of EME. The Company is currently analyzingconsumer lawsuits in various jurisdictions where they sell natural gas and electricity.
Variable Price Cases — In the scope of potential liability as it may relatecases set forth below, referred to Midwest Generation. The Company believes that it has established an adequate reserve for these cases.
Energy Plus Holdings—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, filed a complaint, or 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 owner of the stations, including alleged failures to obtain PSD construction permits and to comply with BACT requirements. The Government Plaintiffs also alleged violations 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 asVariable Price Cases, such actions involve consumers alleging that one of the ten PSD violations alleged inCompany’s ESCOs promised that consumers would pay the Governments’ Amended Complaint. Midwest Generation again moved to dismiss all but onesame or less than they would have paid if they stayed with their default utility or previous energy supplier. The underlying claims of the Government Plaintiffs’ PSD claimseach case are similar and the related Title V claims. Midwest Generation also filed a motionCompany continues to dismissdeny the PSD claim in the Intervenors’ Amended Complaintallegations 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 did not address other counts in the amended complaints that allege violations of opacityis vigorously defending these matters. These matters were known 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 Appealsaccrued 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’s consolidated financial position, results of operations or cash flows.
Telephone Consumer Protection Act Purported Class Actions —Three purported class action lawsuits have been filed against NRG Residential Solar Solutions, LLC — one in California and two in New Jersey.  The plaintiffs generally allege misrepresentation by the call agents and violations of the TCPA, claiming that the defendants engaged in a telemarketing campaign placing unsolicited calls to individuals on the “Do Not Call List.” 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 be 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 confirmed by a term sheet signed by the 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.



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.  Atat the time the PPA was entered into, Sunrise hadof each acquisition.
XOOM Energy
Mirkin v. XOOM Energy (E.D.N.Y. Aug. 2019) is 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 Riverdefendant 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 pending in New York. Summary judgment is fully briefed. XOOM is waiting for a ruling from the trial court.
Direct Energy
There are two putative class actions pending against NRG Yield, Inc.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 appeal is fully briefed. Oral argument has not been set. Given the result of Martin Forte v. Direct Energy (N.D.N.Y. Mar. 2017), the currenttrial

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court's summary judgment will be upheld and former members of its board of directors individually,Direct Energy is expected to prevail; and other parties in California Superior Court in Kern County, CA.  Plaintiffs allege various(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 the SecuritiesTelephone Consumer Protection Act of 1991, as amended, by receiving calls, texts or voicemails without consent in violation of the federal Telemarketing Sales Rule, and/or state counterpart legislation. The underlying claims of each case are similar. The Company denies the allegations asserted by plaintiffs and intends to vigorously defend these matters. These matters were known and accrued for at the time of the acquisition.
There are two putative class actions pending against Direct Energy: (1) Holly Newman v. Direct Energy, LP (D. Md Sept 2021) - Direct Energy filed its Motion to Dismiss asserting the ruling in the Brittany Burk v. Direct Energy (S.D. Tex. Feb 2019) preempts the Plaintiff's ability to file suit based on the same facts. The Court denied Direct Energy's motion stating the Court does not have the benefit of all of the facts that were in front of the Burk court to issue a similar ruling. On October 19, 2022, Direct Energy filed a Motion to Transfer Venue asking the Court to transfer the case to the Southern District where the 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 Sixth Circuit found that Dickson has standing and reversed the trial court's dismissal of the case. The case will go back to the trial court where Direct Energy will seek a stay to file a petition for review by the U.S. Supreme Court.
Sales Practice Lawsuits
There are three litigation matters relating to claims made by Vivint Smart Home competitors against Vivint Smart Home alleging, among other things, that Vivint Smart Home's sales representatives used deceptive sales practices. Vivint Smart Home intends to vigorously defend these matters. These matters were known and accrued for at the time of the acquisition. The three matters are: (1) CPI Security Systems, Inc. ("CPI") v. Vivint Smart Home, Inc. (W.D.N.C. Sept. 2020). The CPI matter that was filed in 2020 went to trial, and in February 2023, the jury issued a verdict against Vivint Smart Home, in favor of CPI for $50 million of compensatory damages and an additional $140 million of punitive damages. Vivint Smart Home filed its post-trial motion in March 2023 and continues to evaluate its post-trial and appeal options. While Vivint Smart Home believes the CPI jury verdict is not legally or factually supported and intends to pursue post judgment remedies and file an appeal, there can be no assurance that such defense efforts will be successful; (2) ADT LLC, et al. ("ADT") v. Vivint Smart Home, Inc. f/k/a Mosaic Acquisition Corporation, et al.(S.D.Fl. Aug. 2020). The parties mediated in May 2023 and agreed on a settlement. In June 2023, the Court granted final approval of the settlement, which was paid in June 2023; and (3) Alert 360 Opco, Inc, et al. ("Alert 360") v. Vivint Smart Home, Inc., et al (N.D.Ok. March 2023). On March 1, 2023, Alert 360 filed a complaint against Vivint Smart Home alleging, among other things, deceptive sales practices.
Contract Disputes
Alarm.com — In September 2022, Vivint Smart Home sent Alarm.com a notice asserting that it was no longer obligated to pay certain license fees under the Patent Cross License Agreement between the parties on the basis that Vivint Smart Home no longer practices any claim under any valid Alarm.com patent and, therefore, no license fees are due. Alarm.com filed an arbitration demand against Vivint Smart Home alleging, among other things, breach of the agreement due to continued use of the defendants’ alleged failurepatents in question. The arbitration panel recently determined that Vivint Smart Home's challenge to disclose material factsthe validity of certain Alarm.com patents will be considered as part of the arbitration proceeding.
STP — In July 2023, the partners in STP, CPS and Austin Energy, initiated a lawsuit and filed to intervene in the license transfer application with the NRC, claiming a right of first refusal exists in relation to the proposed sale of NRG South Texas' 44% interest in STP to Constellation. NRG believes the claims set forth by CPS and Austin Energy in the lawsuit and the NRC proceedings are without merit and intends to vigorously defend against them. For further discussion of the transaction, see Note 4, Acquisitions and Dispositions.
Winter Storm Uri Lawsuits
The Company has been named in certain property damage and wrongful death claims that have been filed in connection with Winter Storm Uri in its capacity as a generator and a REP. Most of the lawsuits related to low wind production prior toWinter 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 NRG Yield, Inc.'s June 22, 2015 Class C common stock offering.  Plaintiffs seek compensatory damages, rescission, attorney’s feesmulti-district litigation and costs.will be seeking dismissal in any remaining cases. As a power generator, the Company is named in various cases with claims ranging from: wrongful death; personal injury only; property damage and personal injury; property damage only; and subrogation. The 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' oppositioncase 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., andcurrently stayed pending appeal by other parties in the Delaware Chancery Court.on other issues. The complaint alleges that the defendants breached their respective fiduciary duties with regardCompany intends to the recapitalization of NRG Yield, Inc. common stock in 2015. The plaintiffs generally seek economic damages, attorney’s feesvigorously defend these matters.

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Indemnifications 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.Other Contractual Arrangements

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. 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 17 — 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.18, 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 18 — 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 by Congress. The Court did not address the related issues of whether the EPA may adopt only measures applied at each source. On May 23, 2023, the EPA proposed significantly revising the manner in which new and existing EGU's GHG emissions should be regulated including using hydrogen as a fuel, capturing and storing/sequestering CO2 and requiring new units to be more efficient. The EPA has stated that it intends to finalize these revisions in 2024. The Company expects that the final rule will be challenged in the courts and accordingly uncertain for several years.
Cross-State Air Pollution Rule ("CSAPR") — On March 15, 2023, the EPA signed and released a prepublication of a final rule that sought to significantly revise the Phase 2 (or 2017) (i) SO2 budgetsCSAPR to address the good-neighbor obligations of the 2015 ozone NAAQS for four23 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 (ii)Louisiana's state plans, which disapprovals are a condition precedent to the EPA imposing its plan on Texas and Louisiana. Several other states are also similarly situated because of similar stays. Nonetheless, on June 5,

47

2023, the EPA published this rule in the Federal Register. On July 31, 2023, the EPA promulgated an interim final rule that addresses the various judicial orders that have stayed several State-Implementation-Plan disapprovals by limiting the effectiveness of certain requirements of the final rule promulgated on June 5, 2023 in Texas and five other states. The final rule decreases, over time, the ozone-season NOx budgets for 11allowances allocated to generators in the states including Maryland, New Jersey, New York, Ohio, Pennsylvanianot affected by the judicial stays beginning this summer by assuming that participants in this cap-and-trade program had or would optimize existing NOx controls and Texas. On October 26, 2016,later install additional NOx controls. The Company cannot predict the EPA finalizedoutcome of the CSAPR Update Rule, which reduces future NOx allocationslegal challenges to the: (i) various state disapprovals; (ii) the final rule promulgated on June 5, 2023; and discounts(iii) the current banked allowances to account for the more stringent 2008 Ozone NAAQS andinterim final rule promulgated on July 31, 2023 that seeks to address the D.C. Circuit's July 2015 decision. This rule has been challenged in the D.C. Circuit. The Company believes its investment in pollution controls and cleaner technologies leave the fleet well-positioned for compliance.judicial orders.
In February 2012,Regional Haze Proposal — On May 2023, the EPA promulgated standards (the MATS rule)proposed to control emissions of HAPs from coalwithdraw the existing Texas Sulfur Dioxide Trading Program and oil-fired electric generating units. The rule established replace it with unit-specific SO2 limits for mercury, non-mercury metals, certain organics and acid gases, which had to be met beginning12 units 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 vacate 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 to the EPA without vacatur. On April 25, 2016, the EPA released a supplemental finding that the benefits of this regulation outweigh the costsTexas to address the U.S. Supreme Court's ruling that the EPA had not properly considered costs. This finding has been challengedrequirements to improve visibility at National Parks and Wilderness areas. If finalized as proposed, it would result in the D.C. Circuit. On April 18, 2017, the EPA asked the D.C. Circuit to postpone oral argument that had been scheduledmore stringent SO2 limits for May 18, 2017 because the EPA is closely reviewing the supplemental finding to determine whether it should reconsider all or parttwo of the rule. On April 27, 2017, the D.C. Circuit granted EPA's request to postpone the oral argument and hold the caseCompany's coal-fired units in abeyance. While NRGTexas. The Company 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.proposal.
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 permits are renewed.
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. In 2021, the rule. Accordingly,EPA announced that it was initiating a new rulemaking to evaluate revising the ELG rule but keeping the existing rule (as amended in 2020) in place. On March 29, 2023, the EPA proposed revisions to the ELG and sought comments on the proposal, which the EPA are currently analyzing. 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 ruledeadlines. On November 12, 2020, the EPA finalized "A Holistic Approach to Closure Part B," which further amended the April 2015 Rule to, among other things, provide procedures for requesting approval to operate existing impoundments with an alternative liner. On May 23, 2023, the EPA proposed establishing requirements for: (i) inactive (or legacy) surface impoundments at inactive facilities and (ii) all coal combustion residual ("CCR") management units (regardless of how or when the CCR was placed) at regulated facilities. The EPA also solicited comments on the Company's consolidated financial position, results of operations, or cash flows and has accrued its environmental and asset retirement obligations under 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 party with respect to Burton Island Old Ash Landfill, a historic captive landfill located at the Indian River facility. On October 1, 2007,this proposal. 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.

48
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.



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 ninesix months ended SeptemberJune 30, 20172023 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. Across the United States and Canada, NRG delivers innovative, sustainable solutions, predominately under brand names such as NRG, Reliant, Direct Energy, Green Mountain Energy and Vivint, while also advocating for competitive energy markets and customer choice. The Company has a customer base that includes approximately 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 home 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, 17, 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.



49

East Region
PJMRegional Regulatory Developments
Minimum Offer Price Rule Exemption Appeal NRG is affected by rule/tariff changes that occur in the ISO regions. For further discussion on regulatory developments, see Note 17, Regulatory Matters.
Texas
Public Utility Commission of Texas’ Actions with Respect to Wholesale Pricing and Market Design —Throughout 2022, the PUCT analyzed multiple options for promoting increased reliability in the wholesale electric market. 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 relatedadopting the PCM as their policy direction for resource adequacy in ERCOT, however, implementation was delayed until the legislature reviewed. Subsequently, during the 88th Regular Session, the Texas Legislature authorized deployment of the PCM, subject to certain "guardrails" such as an exemptionannual net cost cap, as part of its adoption of the PUCT Sunset Bill (House Bill 1500). The Texas Legislature also directed the PUCT to implement additional market design changes such as the creation of a new ancillary service called Dispatchable Reliability Reserve Service to further increase ERCOT's capability to manage net load variability, firming requirements for new generation resources which penalize poor performance during periods of low grid reserves, and a loan program to incentivize expansion and construction of dispatchable generation resources.
Operating Reserve Demand Curve ("ORDC") — On August 3, 2023, the PUCT approved implementation of an enhancement to the Minimum Offer Price Rule,ORDC as a bridge solution that was recommended by the ERCOT Technical Advisory Committee and the ERCOT Board of Directors. The ORDC enhancement will install price floors of $10 and $20 at reserve levels of 7,000 MW and 6,500 MW or MOPR,below, respectively. ERCOT is expected to complete implementation in the fourth quarter of 2023.
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 appeal relating to the validity of two orders issued by the PUCT on February 15 and 16, 2021, respectively, governing scarcity pricing in the ERCOT wholesale electricity market during Winter Storm Uri. The Third Court found that the PUCT exceeded its statutory authority by ordering the market price of energy to be set at the high system wide offer cap due to scarcity conditions as a result of firm load shed occurring in ERCOT. The Third Court reversed the PUCT's orders and remanded the issue backcase. On March 23, 2023, the PUCT filed a petition for review to FERC.the Supreme Court of Texas seeking reversal of the Third Court's decision. The outcome of this case could require a repricing of the market prices during the subject time period.
Voluntary Mitigation Plan ("VMP") Changes — On March 13, 2023, the PUCT Staff determined that a portion of NRG's VMP should be terminated due to the increase in procurement of ancillary services by ERCOT, specifically non-spin reserve services, following Winter Storm Uri. As such, PUCT Staff terminated part of the VMP for NRG which provides protection from wholesale market power abuse accusations related to offers for ancillary services. NRG agreed with these changes to the VMP. At the March 23, 2023 open meeting, the PUCT approved the amended VMP. Pursuant to amendments to Public Utility Regulation Act § 15.023 adopted during the 88th Legislative Session, NRG's VMP will be reviewed by the PUCT within two years or, in the event a wholesale market design change is made, not later than the 90th day after the implementation date of such change.
PJM
Revisions to PJM Local Deliverability Area Reliability Requirement — The Base Residual Auction for the 2024/2025 delivery year commenced on December 7, 2022 and closed on December 13, 2022. On December 19, 2022, PJM announced that it would delay the publication of the auction results. On December 23, 2022, PJM made a 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, have filed for rehearing. Rehearing was denied by operation of law, and multiple parties, including the Company, filed appeals to the Third Circuit Court of Appeals. The price of the auction cleared significantly lower as a result of the PJM Tariff change.
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 2, 2023, PJM made a filing at FERC that, if approved, would give PJM the ability to extend the payment period for PJM members who incurred penalties for an additional 9 months. On April 3, 2023, FERC

50

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 Tariff in, among other things, the manner in which it operated the system during Winter Storm Elliott and the resulting assessment of capacity performance penalties. On June 5, 2023, FERC issued an order setting the various complaints for settlement. Settlement discussions are ongoing at FERC.
FERC Delays PJM 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 filing regarding those reforms by October 23, 2017,1, 2023. PJM re-filed its initial 2012 MOPR.proposes to restart the auctions after FERC's ruling on PJM's renewed proposal could affect how generators participatethese market changes. On June 9, 2023, FERC issued an order approving the delay in the PJM Base Residual Auction.Auctions and required PJM to make a compliance filing that will specify future auction dates. On June 26, 2023, PJM made its compliance filing specifying the dates for the 2025/2026 Delivery Year through the 2028/2029 Delivery Year.
2020/2021 PJM Auction Results Files to Make Changes to the Performance Assessment Interval Trigger— On May 23, 2017,30, 2023, PJM announcedfiled proposed tariff revisions at FERC that narrow the resultsdefinition 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 methodologyEmergency Actions 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.Performance Assessment Intervals ("PAIs"). The settlementmatter is pending at FERC. The outcomeIf approved, the new definition would decrease the instances of when PAIs would occur and therefore decrease the instances of when capacity performance penalties are assessed.
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. Further, a procurement order in this matter will determinedocket issued in February 2023 directed LSEs to procure an additional four GW of clean resources in the amount2026 to 2028 timeframe. A May 2023 proposed decision in the docket would keep the reserve margin at 17 percent in 2024 and 2025, but extend the CPUC orders for the state's major investor-owned utilities to procure additional summer reliability resources through 2025, creating an "effective" reserve margin of refunds that the NRG fleet may receive as21 to 23.5 percent. SB846 establishes a result of negotiating the PER strike price methodology.
New York
New York Public Service Commission Retail Energy Market Proceedings — On February 23, 2016, the NYSPSC issued what it refers to as its “Retail Reset” order, or Reset Order, in docket 12-M-0476 et al.  Among other things, the Reset Order placed a price cap on energy supply offers 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 suppliers in New York state court.  In conjunction with the court challenges, the NYPSC ispathway 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 decontaminateif LSEs cannot meet their RA obligations, penalties and decommission the STP facility. Under NRC regulations, a power reactor licensee generally must pre-fund the full amount of its estimated NRC decommissioning 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.restrictions on serving new customers 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, 18,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.


51


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. On May 23, 2023, the EPA proposed significantly revising the manner in which new and existing EGU's GHG emissions should be regulated including using hydrogen as a fuel, capturing and storing/sequestering CO2 and requiring new units to be more efficient. The EPA has stated that it intends to finalize these revisions in 2024. The Company expects that the final rule will be challenged in the courts and accordingly uncertain for several years.
Cross-State Air Pollution Rule ("CSAPR") — On March 15, 2023, the EPA signed and released a prepublication of a final rule that sought to significantly revise the CSAPR to address the good-neighbor obligations of the 2015 ozone NAAQS for 23 states after earlier having disapproved numerous state plans to address the issue. Several states, including Texas, challenged the EPA's disapproval of their state plans. On May 1, 2023, the United States Court of Appeals for the Fifth Circuit stayed the EPA's disapproval of Texas' and Louisiana's state plans, which disapprovals are a condition precedent to the EPA imposing its plan on Texas and Louisiana. Several other states are also similarly situated because of similar stays. Nonetheless, on June 5, 2023, the EPA published this rule in the Federal Register. On July 31, 2023, the EPA promulgated an interim final rule that addresses the various judicial orders that have stayed several State-Implementation-Plan disapprovals by limiting the effectiveness of certain requirements of the final rule promulgated on June 5, 2023 in Texas and five other states. The final rule decreases, over time, the ozone-season NOx allowances allocated to generators in the states not affected by the judicial stays beginning this summer by assuming that participants in this cap-and-trade program had or would optimize existing NOx controls and later install additional NOx controls. The Company cannot predict the outcome of the legal challenges to the: (i) various state disapprovals; (ii) the CPP in September 2016. Atfinal rule promulgated on June 5, 2023; and (iii) the EPA's request,interim final rule promulgated on July 31, 2023 that seeks to address the D.C. Circuit agreed on April 28, 2017 to hold the case in abeyance.judicial orders.
Regional Haze Proposal — On October 16, 2017,May 2023, the EPA proposed a rule to repealwithdraw the CPP. Accordingly,existing Texas Sulfur Dioxide Trading Program and replace it with unit-specific SO2 limits for 12 units in Texas to address requirements to improve visibility at National Parks and Wilderness areas. If finalized as proposed, it would result in more stringent SO2 limits for two of the Company's coal-fired units in Texas. The Company believescannot predict the CPP is not likely to survive.outcome of this proposal.
Byproducts, Wastes, Hazardous Materials and Contamination
In April 2015, the EPA finalized the rule regulating byproducts of coal combustion (e.g., ash and gypsum) as solid wastes under the RCRA. 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. On May 23, 2023, the EPA proposed establishing requirements for: (i) inactive (or legacy) surface impoundments at inactive facilities and (ii) all CCR management units (regardless of operations,how or cash flowswhen the CCR was placed) at regulated facilities. NRG anticipates further rulemaking related to the Federal Permit Program and has accruedlegacy surface impoundments.
Domestic Site Remediation Matters
Under certain federal, state and local environmental laws, a current or previous owner or operator of a facility, including an electric generating facility, may be required to investigate and remediate releases or threatened releases of hazardous or toxic substances or petroleum products. NRG may be responsible for property damage, personal injury and investigation and remediation costs incurred by a party in connection with hazardous material releases or threatened releases. These laws impose liability without regard to whether the owner knew of or caused the presence of the hazardous substances, and the courts have interpreted liability under such laws to be strict (without fault) and joint and several. Cleanup obligations can often be triggered during the closure or decommissioning of a facility, in addition to spills during its 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.

52

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; and (iii) changing several deadlines. In 2021, the EPA announced that it was initiating a new rulemaking to evaluate revising the ELG rule but keeping the existing rule (as amended in 2020) in place. On March 29, 2023, the EPA proposed revisions to the ELG and sought comments, which the EPA are currently analyzing. In October 2021, NRG informed its regulators that the Company intends to comply with the ELG by ceasing combustion of coal by the end of 2028 at its domestic coal units outside of Texas, and installing appropriate controls by the end of 2025 at its two plants that have coal-fired units in Texas.
Regional Environmental Developments
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 Plan
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 thePlanned sale of the following projects to NRG Yield, Inc.: (i) a 16%44% equity interest in STP
On May 31, 2023, the Agua Caliente solar project,Company entered into a definitive equity purchase agreement to sell its 44% equity interest in STP to Constellation for $1.75 billion, subject to customary purchase price adjustments. The transaction is expected to close by the end of 2023 and (ii) NRG's interestsis subject to regulatory approval by the NRC. The waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, expired in seven utility-scale solar projects locatedJuly 2023. For further discussion, see Note 4, Acquisitions and Dispositions.
Vivint Smart Home Acquisition
On March 10, 2023, the Company completed the acquisition of Vivint Smart Home. The Company paid $12 per share, or $2.6 billion in Utah, which have reached commercial operations, for $130cash. 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 $635 million cash consideration, as discussedwere used to partially fund the Vivint Smart Home acquisition. For further discussion, see Note 11, Changes in more detail inCapital Structure.

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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 partially fund the Vivint Smart Home acquisition. For further discussion, see Note 3, Discontinued Operations, Dispositions9, Long-term Debt and Acquisitions of this Form 10-Q.Finance Leases.
Astoria
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. NRGyear after decommissioning 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.complete.


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 expects to complete repairs and return the unit to service in late August 2023.
Share Repurchases
In June 2023, NRG revised its long-term capital allocation policy to target allocating approximately 80% of cash available for allocation after debt reduction to be returned to shareholders. As part of the revised capital allocation framework, the Company announced an increase to its share repurchase authorization to $2.7 billion, to be executed through 2025. During July 2023, the Company purchased 1,322,141 shares for $50 million at an average price of $37.82 under the $2.7 billion authorization.
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. As of June 30, 2023, 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. 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.
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.




54

Consolidated Results of Operations
The following table provides selected financial information for the Company:
 Three months ended June 30,Six months ended June 30,
(In millions, except as otherwise noted)20232022Change20232022Change
Revenue
Retail revenue$6,027 $6,951 $(924)$13,390 $14,521 $(1,131)
Energy revenue(a)
83 306 (223)211 584 (373)
Capacity revenue(a)
49 90 (41)91 206 (115)
Mark-to-market for economic hedging activities75 (148)223 166 (281)447 
Contract amortization(8)(13)5 (19)(22)3 
Other revenues(a)(b)
122 96 26 231 170 61 
Total revenue6,348 7,282 (934)14,070 15,178 (1,108)
Operating Costs and Expenses
Cost of fuel227 532 305 390 861 471 
Purchased energy and other cost of sales(c)
4,282 5,811 1,529 10,284 12,263 1,979 
Mark-to-market for economic hedging activities11 (867)(878)2,046 (3,277)(5,323)
Contract and emissions credit amortization(c)
(18)(35)(17)90 103 13 
Operations and maintenance361 354 (7)746 690 (56)
Other cost of operations99 92 (7)184 177 (7)
Cost of operations (excluding depreciation and amortization shown below)4,962 5,887 925 13,740 10,817 (2,923)
Depreciation and amortization315 157 (158)505 340 (165)
Impairment losses— 155 155 — 155 155 
Selling, general and administrative costs522 351 (171)948 698 (250)
Acquisition-related transaction and integration costs22 10 (12)93 18 (75)
Total operating costs and expenses5,821 6,560 739 15,286 12,028 (3,258)
Gain on sale of assets3 32 (29)202 29 173 
Operating Income/(Loss)530 754 (224)(1,014)3,179 (4,193)
Other Income/(Expense)
Equity in earnings/(losses) of unconsolidated affiliates5 4 1 10 (11)21 
Other income, net13 12 1 29 12 17 
Interest expense(151)(105)(46)(299)(208)(91)
Total other expense(133)(89)(44)(260)(207)(53)
Income/(Loss) Before Income Taxes397 665 (268)(1,274)2,972 (4,246)
Income tax expense/(benefit)89 152 63 (247)723 970 
Net Income/(Loss)$308 $513 $(205)$(1,027)$2,249 $(3,276)
 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 NOxcredits and excludes amortization of RGGI credits.    

credits     


55

Management’s discussion of the results of operations for the three months ended SeptemberJune 30, 20172023 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 SeptemberJune 30, 20172023 and 2016. The average2022. Average on-peak power prices have generally decreased primarily due to the increase in natural gas prices for the three months ended SeptemberJune 30, 20172023 as compared to the same period in 2016.2022 as a result of lower natural gas prices.
 Average on Peak Power Price ($/MWh)
Three months ended June 30,
Region20232022Change %
Texas
ERCOT - Houston(a)
$56.54 $126.30 (55)%
ERCOT - North(a)
54.02 79.14 (32)%
East
    NY J/NYC(b)
$32.02 $81.32 (61)%
    NEPOOL(b)
32.55 73.28 (56)%
    COMED (PJM)(b)
30.00 84.77 (65)%
    PJM West Hub(b)
35.41 93.00 (62)%
West
MISO - Louisiana Hub(b)
$35.30 $91.97 (62)%
CAISO - SP15(b)
30.00 60.34 (50)%
 Average on Peak Power Price ($/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


Natural Gas Prices
The following table summarizes the average realized power prices for each region in which NRG operatesHenry Hub natural gas price for the three months ended SeptemberJune 30, 20172023 and 2016, which reflects the impact of settled hedges.2022.
 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.

Three months ended June 30,
20232022Change %
($/MMBtu)$2.10 $7.17 (71)%
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 depreciation and amortization.
Economic Gross Margin
In addition to gross margin, the Company evaluates its operating performance using the measure of economic gross margin, which is not a GAAP measure and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Economic gross margin should be viewed as a supplement to and not a substitute for the Company's presentation of gross margin, which is the most directly comparable GAAP measure. Economic gross margin is not intended to represent gross margin. The Company believes that economic gross margin is useful to investors as it is a key operational measure reviewed by the Company's chief operating decision maker. Economic gross margin is defined as the sum of retail revenue, energy revenue, capacity revenue and other revenue, less cost of fuel, purchased energy and other cost of sales. Economic gross margin does not include mark-to-market gains or losses on economic hedging activities, contract amortization, emissions credit amortization, depreciation and amortization, operations and maintenance, or other cost of operations.

56

The below tables present the composition and reconciliation of gross margin and economic gross margin for the three months ended June 30, 2023 and 2022:
Three months ended June 30, 2023
($ In millions)TexasEastWest/Services/OtherVivint Smart HomeCorporate/EliminationsTotal
Retail revenue$2,395 $2,358 $830 $444 $— $6,027 
Energy revenue16 28 40 — (1)83 
Capacity revenue— 49 — — — 49 
Mark-to-market for economic hedging activities— 52 23 — — 75 
Contract amortization— (7)(1)— — (8)
Other revenue(a)
104 23 — — (5)122 
Total revenue2,515 2,503 892 444 (6)6,348 
Cost of fuel(184)(15)(28)— — (227)
Purchased energy and other cost of sales(b)(c)(d)
(1,403)(2,129)(714)(41)5 (4,282)
Mark-to-market for economic hedging activities334 (204)(141)— — (11)
Contract and emission credit amortization(3)23 (2)— — 18 
Depreciation and amortization(73)(30)(23)(180)(9)(315)
Gross margin$1,186 $148 $(16)$223 $(10)$1,531 
Less: Mark-to-market for economic hedging activities, net334 (152)(118)— — 64 
Less: Contract and emission credit amortization, net(3)16 (3)— — 10 
Less: Depreciation and amortization(73)(30)(23)(180)(9)(315)
Economic gross margin$928 $314 $128 $403 $(1)$1,772 
(a) Includes trading gains and losses and ancillary revenues
(b) Includes capacity and emissions credits
(c) Includes $688 million, $56 million and $241 million of TDSP expense in Texas, East and West/Services/Other, respectively
(d) Excludes depreciation and amortization shown separately
Business MetricsTexasEastWest/Services/OtherVivint Smart HomeCorporate/EliminationsTotal
Retail sales
Home power sales volume (GWh)9,799 2,789 509 — — 13,097 
Business power sales volume (GWh)10,028 11,391 2,282 — — 23,701 
Home natural gas sales volume (MDth)— 7,716 11,582 — — 19,298 
Business natural gas sales volume (MDth)— 352,007 42,179 — — 394,186 
Average retail Home customer count (in thousands)(a)
2,866 1,850 777 — — 5,493 
Ending retail Home customer count (in thousands)(a)
2,869 1,858 772 — — 5,499 
Average Vivint Smart Home subscriber count (in thousands)(b)
— — — 1,965 — 1,965 
Ending Vivint Smart Home subscriber count (in thousands) (b)
— — — 2,004 — 2,004 
Power generation
GWh sold7,508 624 1,566 — — 9,698 
GWh generated(c)
   Coal3,690 148 — — — 3,838 
   Gas1,625 46 1,565 — — 3,236 
   Nuclear2,193 — — — — 2,193 
Renewables— — 1 — — 1 
Total7,508 194 1,566 — — 9,268 
(a) Home customer count includes recurring residential customers, services customers and municipal aggregations
(b) Vivint Smart Home subscribers includes customers that also purchase other NRG products
(c) Includes owned and leased generation, excludes tolled generation and equity investments


57

Three months ended June 30, 2022
($ In millions)TexasEast West/Services/OtherCorporate/EliminationsTotal
Retail revenue$2,565 $3,400 $987 $(1)$6,951 
Energy revenue38 128 131 9 306 
Capacity revenue— 89 1 — 90 
Mark-to-market for economic hedging activities(1)(106)(38)(3)(148)
Contract amortization— (11)(2)— (13)
Other revenue(a)
90 14 (3)(5)96 
Total revenue2,692 3,514 1,076 — 7,282 
Cost of fuel(354)(72)(106)— (532)
Purchased energy and other cost of sales(b)(c)(d)
(1,685)(3,267)(855)(4)(5,811)
Mark-to-market for economic hedging activities607 242 15 3 867 
Contract and emission credit amortization2 36 (3)— 35 
Depreciation and amortization(77)(50)(22)(8)(157)
Gross margin$1,185 $403 $105 $(9)$1,684 
Less: Mark-to-market for economic hedging activities, net606 136 (23)— 719 
Less: Contract and emission credit amortization, net2 25 (5)— 22 
Less: Depreciation and amortization(77)(50)(22)(8)(157)
Economic gross margin$654 $292 $155 $(1)$1,100 
(a) Includes trading gains and losses and ancillary revenues
(b) Includes capacity and emissions credits
(c) Includes $796 million, $50 million and $275 million of TDSP expense in Texas, East, and West/Services/Other, respectively
(d) Excludes depreciation and amortization shown separately
Business MetricsTexasEastWest/Services/OtherCorporate/EliminationsTotal
Retail sales
Home power sales volume (GWh)11,587 3,022 487—15,096 
Business power sales volume (GWh)10,162 12,210 2,442—24,814 
Home natural gas sales volume (MDth)— 7,096 14,333—21,429 
Business natural gas sales volume (MDth)— 328,490 37,829—366,319 
Average retail Home customer count (in thousands)(a)
3,015 1,789 800—5,604 
Ending retail Home customer count (in thousands)(a)
2,994 1,808 799—5,601 
Power generation
GWh sold10,035 1,946 1,874 —13,855
GWh generated(b)
   Coal4,852 1,361 — —6,213 
   Gas2,661 37 1,876 —4,574 
   Nuclear2,522 — — —2,522 
   Renewables— — 4 4 
Total10,035 1,398 1,880 — 13,313 
(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

58

The table below represents the weather metrics for the three months ended June 30, 2023 and 2022:
 Three months ended June 30,
Weather MetricsTexasEast
West/Services/Other(b)
2023
CDDs(a)
978 273 502 
HDDs(a)
57 479 254 
2022
CDDs1,283 352 674 
HDDs24 486 194 
10-year average
CDDs986 356 557 
HDDs67 547 188 
(a) National Oceanic and Atmospheric Administration-Climate Prediction Center - A Cooling Degree Day, or CDD, represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. A Heating Degree Day, or HDD, represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period
(b) The West/Services/Other weather metrics are comprised of the average of the CDD and HDD regional results for the West - California and West - South Central regions

Gross Margin and Economic Gross Margin
Gross margin decreased $153 million and economic gross margin increased $672 million during the three months ended June 30, 2023, compared to the same period in 2022.
The tables below describe the changes in gross margin and economic gross margin by segment:
Texas
(In millions)
Higher gross margin due to the net effect of:
•increased net revenue rates of $4.75 per MWh, or $157 million, primarily driven by changes in customer term, product and mix; and
•a $197 million decrease in cost to serve the retail load, primarily driven by lower supply costs which were a result of lower power pricing, the diversified supply strategy and improved plant performance coupled with the 2022 impact of the W.A. Parish Unit 8 extended outage that began in May 2022
$354 
Lower gross margin due to a decrease in load of 600,000 MWh, or $58 million, driven by a decrease in customer count and changes in customer mix, and a decrease in load of 1.3 TWh, or $44 million, from weather(102)
Higher gross margin due to market optimization activities26 
Other(4)
Increase in economic gross margin$274
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges(272)
Increase in contract and emission credit amortization(5)
Decrease in depreciation and amortization4 
Increase in gross margin$1



59

East
(In millions)
Lower gross margin due to a decrease in generation and capacity as a result of asset retirements$(43)
Higher electric gross margin due to higher net revenue rates as a result of changes in customer term, product and mix of $4.75 per MWh, or $66 million, as well as lower supply costs of $2.00 per MWh, or $28 million, driven primarily by decreases in power prices94 
Lower electric gross margin from decreased volume due to change in customer mix and weather(9)
Lower natural gas gross margin, including the impact of transportation and storage contract optimization, resulting in lower net revenue rates from changes in customer term, product, and mix of $3.30 per Dth, or $1.21 billion, partially offset by lower supply costs of $3.25 per Dth, or $1.17 billion, driven primarily by decrease in gas costs(43)
Higher natural gas gross margin from increased volume due to an increase in customer count and change in customer mix26 
Lower gross margin primarily due to a 58% decrease in PJM capacity prices and a 23% decrease in PJM capacity volumes(25)
Higher gross margin due to a decrease in supply costs at Midwest Generation, offset by an 81% decrease in generation volumes due to dark spread contractions17 
Other5 
Increase in economic gross margin$22
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges(288)
Increase in contract amortization(9)
Decrease in depreciation and amortization20 
Decrease in gross margin$(255)

West/Services/Other
(In millions)
Lower gross margin primarily due to lower Services sales$(18)
Lower electric gross margin due to an increase in supply rate of $17.75 per MWh, or $50 million, partially offset by higher revenue rate of $12.50 per MWh, or $35 million, and changes in customer mix of $2 million(13)
Higher natural gas gross margin due to lower supply rates of $2.10 per Dth, or $113 million, partially offset by lower net revenue rates of $1.90 per Dth, or $102 million11 
Lower gross margin from market optimization activities(7)
Decrease in economic gross margin$(27)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges(95)
Decrease in contract amortization2 
Increase in depreciation and amortization(1)
Decrease in gross margin$(121)

Vivint Smart Home
(In millions)
Increase due to the acquisition of Vivint Smart Home$403 
Increase in economic gross margin$403
Increase in depreciation and amortization(180)
Increase in gross margin$223

60

Mark-to-Market for Economic Hedging Activities
Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges. Total net mark-to-market results decreased by $655 million during the three months ended June 30, 2023, compared to the same period in 2022.
The breakdown of gains and losses included in revenues and operating costs and expenses by segment was as follows:
Three months ended June 30, 2023
(In millions)TexasEastWest/Services/OtherEliminationsTotal
Mark-to-market results in revenue 
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges$— $(2)$17 $(3)$12 
Net unrealized gains on open positions related to economic hedges— 54 6 3 63 
Total mark-to-market gains in revenue$— $52 $23 $— $75 
Mark-to-market results in operating costs and expenses  
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges$(39)$(73)$(54)$3 $(163)
Reversal of acquired loss positions related to economic hedges11 20 4 — 35 
Net unrealized gains/(losses) on open positions related to economic hedges362 (151)(91)(3)117 
Total mark-to-market gains/(losses) in operating costs and expenses$334 $(204)$(141)$— $(11)
 Three months ended June 30, 2022
(In millions)TexasEastWest/Services/OtherEliminationsTotal
Mark-to-market results in revenue    
Reversal of previously recognized unrealized losses on settled positions related to economic hedges$— $1 $6 $(2)$5 
Reversal of acquired (gain) positions related to economic hedges— (1)— — (1)
Net unrealized (losses) on open positions related to economic hedges(1)(106)(44)(1)(152)
Total mark-to-market (losses) in revenue$(1)$(106)$(38)$(3)$(148)
Mark-to-market results in operating costs and expenses     
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges$(51)$(135)$(18)$2 $(202)
Reversal of acquired loss positions related to economic hedges19 25 5 — 49 
Net unrealized gains on open positions related to economic hedges639 352 28 1 1,020 
Total mark-to-market gains in operating costs and expenses$607 $242 $15 $3 $867 
`
Mark-to-market results consist of unrealized gains and losses on contracts that are not yet settled. The settlement of these transactions is reflected in the same revenue or cost caption as the items being hedged.
For the three months ended June 30, 2023, the $75 million gain in revenues from economic hedge positions was driven primarily by an increase in the value of open positions as a result of decreases in power and natural gas prices as well as the reversal of previously recognized unrealized losses on contracts that settled during the period. The $11 million loss in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period, as well as a decrease in the value of East and West open positions as a result of decreases in natural gas and power prices. This was partially offset by an increase in the value of Texas open positions as a result of increases in ERCOT power prices and the reversal of acquired loss positions.

For the three months ended June 30, 2022, the $148 million loss in revenues from economic hedge positions was driven primarily by a decrease in the value of open positions as a result of increases in PJM power prices. The $867 million gain in operating costs and expenses from economic hedge positions was driven primarily by an increase in the value of open positions as a result of increases in natural gas and power prices, partially offset by the reversal of previously recognized unrealized gains on contracts that settled during the period.

61

In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the three months ended June 30, 2023 and 2022. The realized and unrealized financial and physical trading results are included in revenue. The Company's trading activities are subject to limits based on the Company's Risk Management Policy.
 Three months ended June 30,
(In millions)20232022
Trading (losses)/gains
Realized$(5)$(5)
Unrealized13 (2)
Total trading gains/(losses)$8 $(7)

Operations and Maintenance Expense
Operations and maintenance expense is comprised of the following:
(In millions)TexasEastWest/Services/OtherVivint Smart HomeEliminationsTotal
Three months ended June 30, 2023$164 $89 $55 $54 $(1)$361 
Three months ended June 30, 2022196 113 46 — (1)354 
Operations and maintenance expense increased by $7 million for the three months ended June 30, 2023, compared to the same period in 2022, due to the following:
(In millions)
Increase due to the acquisition of Vivint Smart Home$54 
Increase in major maintenance expenditures associated with the timing of planned outages at STP and scope
and duration of outages at Texas gas facilities, Midwest Generation and Cottonwood
31 
Decrease due to current year partial property insurance claim for the extended outage at W.A. Parish, partially offset by the cost of restoration efforts(49)
Decrease due to change in estimates of environmental remediation costs at deactivated sites in the
East in 2022		(19)
Decrease in variable operation and maintenance expense due to a reduction in PJM generation volumes in 2023(10)
Decrease driven primarily by East asset retirements partially offset by an increase in deactivation costs in the
West		(4)
Other4 
Increase in operations and maintenance expense$7 
Other Cost of Operations
Other cost of operations is comprised of the following:
(In millions)TexasEastWest/Services/OtherVivint Smart HomeTotal
Three months ended June 30, 2023$62 $34 $2 $1 $99 
Three months ended June 30, 202251 38 3 — 92 
Other cost of operations for the three months ended June 30, 2023 increased by $7 million, when compared to the same period in 2022, due to the following:
(In millions)
Increase due to higher property insurance premiums and property taxes$12 
Decrease primarily due to changes in timing of ARO spend at Midwest Generation(8)
Other3 
Increase in other cost of operations$7 


62

Depreciation and Amortization
Depreciation and amortization are comprised of the following:
(In millions)TexasEastWest/Services/OtherVivint Smart HomeCorporateTotal
Three months ended June 30, 2023$73 $30 $23 $180 $9 $315 
Three months ended June 30, 202277 50 22 — 8 157 
Depreciation and amortization increased by $158 million for the three months ended June 30, 2023, compared to the same period in 2022, primarily due to higher amortization of intangible assets due to the acquisition of Vivint Smart Home in March 2023, partially offset by lower depreciation at Midwest Generation as a result of asset impairments and retirements in 2022.
Impairment Losses
Impairment losses of $155 million were recorded during the three months ended June 30, 2022 primarily related to impairments at Midwest Generation due to the decline in PJM capacity prices and the planned retirement of Joliet. For further discussion, see Note 8, Impairments.
Selling, General and Administrative Costs
Selling, general and administrative costs are comprised of the following:
(In millions)TexasEastWest/Services/OtherVivint Smart HomeCorporateTotal
Three months ended June 30, 2023$173 $136 $54 $153 $6 $522 
Three months ended June 30, 2022164 115 58 — 14 351 
Selling, general and administrative costs increased by $171 million for the three months ended June 30, 2023, compared to the same period in 2022, due to the following:
(In millions)
Increase due to the acquisition of Vivint Smart Home$153 
Increase due to higher personnel costs16 
Increase due to higher provision for credit losses11 
Increase in broker fee and commission expenses8 
Decrease due to lower consulting and legal expenses(11)
Decrease in marketing and media expenses(2)
Other(4)
Increase in selling, general and administrative costs$171 
Acquisition-Related Transaction and Integration Costs
Acquisition-related transaction and integration costs of $22 million were incurred during the three months ended June 30, 2023, which consisted of $2 million of acquisition costs and $14 million of integration costs related to Vivint Smart Home, as well as $6 million of integration costs primarily related to Direct Energy.
Acquisition-related transaction and integration costs of $10 million were incurred during the three months ended June 30, 2022, which are comprised primarily of integration costs related to Direct Energy.
Gain on Sale of Assets
The gain on sale of assets of $32 million for the three months ended June 30, 2022 was due to a gain of $46 million related to the sale of the Company's 49% ownership in the Watson natural gas generating facility in June, partially offset by a loss of $14 million on other asset sales.
Interest Expense
Interest expense increased by $46 million for the three months ended June 30, 2023, compared to the same period in 2022, primarily due to the Vivint Smart Home acquisition including the impact of newly issued Senior Secured First Lien Notes, acquired debt of Vivint Smart Home, and borrowings on the Revolving Credit Facility and the Receivables Securitization Facilities.

63

Income Tax Expense
For the three months ended June 30, 2023, income tax expense of $89 million was recorded on a pre-tax income of $397 million. For the same period in 2022, income tax expense of $152 million was recorded on pre-tax income of $665 million. The effective tax rates were 22.4% and 22.9% for the three months ended June 30, 2023 and 2022, respectively.
For the three months ended June 30, 2023, the effective tax rate was higher than the statutory rate of 21% primarily due to state tax expense. For the same period in 2022, the effective tax rate was higher than the statutory rate of 21% primarily due to state tax expense, partially offset by tax benefit resulting from the release of valuation allowance on state net operating losses.


64

Management’s discussion of the results of operations for the six months ended June 30, 2023 and 2022
Electricity Prices
The following table summarizes average on peak power prices for each of the major markets in which NRG operates for the six months ended June 30, 2023 and 2022. Texas, East and MISO average on-peak power prices decreased for the six months ended June 30, 2023 as compared to the same period in 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)
Six months ended June 30,
Region20232022Change %
Texas
ERCOT - Houston (a)
$41.76 $87.50 (52)%
ERCOT - North(a)
40.37 62.70 (36)%
East
    NY J/NYC(b)
$38.71 $92.79 (58)%
    NEPOOL(b)
42.59 94.88 (55)%
    COMED (PJM)(b)
29.89 64.73 (54)%
    PJM West Hub(b)
35.95 75.66 (52)%
West
MISO - Louisiana Hub(b)
$32.54 $67.73 (52)%
CAISO - SP15(b)
61.27 52.77 16 %
(a) Average on peak power prices based on real time settlement prices as published by the respective ISOs
(b) Average on peak power prices based on day ahead settlement prices as published by the respective ISOs
Natural Gas Prices
The following table summarizes the average Henry Hub natural gas price for the six months ended June 30, 2023 and 2022.
Six months ended June 30,
20232022Change %
($/MMBtu)$2.76 $6.06 (54)%
Gross Margin
The Company calculates gross margin in order to evaluate operating performance as revenues less cost of fuel, purchased energy and other costs of sales, mark-to-market for economic hedging activities.activities, contract and emission credit amortization and depreciation and amortization.
Economic Gross Margin
In addition to gross margin, the Company evaluates its operating performance using the measure of economic gross margin, which is not a GAAP measure and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Economic gross margin should be viewed as a supplement to and not a substitute for the Company's presentation of gross margin, which is the most directly comparable GAAP measure. Economic gross margin is not intended to represent gross margin. The Company believes that economic gross margin is useful to investors as it is a key operational measure reviewed by the Company's chief operating decision maker. Economic gross margin is defined as the sum of energy revenue, capacity revenue, retail revenue and other revenue, less cost of 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, emissionand emissions credit amortization, depreciation and amortization, operations and maintenance, or other operating costs.cost of operations.



65

The below tables present the composition and reconciliation of gross margin and economic gross margin for the threesix months ended SeptemberJune 30, 20172023 and 2016:2022:
Six months ended June 30, 2023
($ In millions)TexasEastWest/Services/Other
Vivint Smart Home(a)
Corporate/EliminationsTotal
Retail revenue$4,353 $6,374 $2,071 $592 $— $13,390 
Energy revenue20 102 88 — 1 211 
Capacity revenue— 90 1 — — 91 
Mark-to-market for economic hedging activities— 87 90 — (11)166 
Contract amortization— (18)(1)— — (19)
Other revenue(b)
176 44 17 — (6)231 
Total revenue4,549 6,679 2,266 592 (16)14,070 
Cost of fuel(296)(38)(56)— — (390)
Purchased energy and other cost of sales(c)(d)(e)
(2,658)(5,706)(1,871)(52)3 (10,284)
Mark-to-market for economic hedging activities463 (1,994)(526)— 11 (2,046)
Contract and emission credit amortization(4)(81)(5)— — (90)
Depreciation and amortization(148)(60)(47)$(232)(18)(505)
Gross margin$1,906 $(1,200)$(239)$308 $(20)$755 
Less: Mark-to-market for economic hedging activities, net463 (1,907)(436)— — (1,880)
Less: Contract and emission credit amortization, net(4)(99)(6)— — (109)
Less: Depreciation and amortization(148)(60)(47)(232)(18)(505)
Economic gross margin$1,595 $866 $250 $540 $(2)$3,249 
(a) Includes results of operations following the acquisition date of March 10, 2023
(b) Includes trading gains and losses and ancillary revenues
(c) Includes capacity and emissions credits
(d) Includes $1.3 billion, $105 million and $598 million of TDSP expense in Texas, East, and West/Services/Other, respectively
   (e) Excludes depreciation and amortization shown separately
Business MetricsTexasEastWest/Services/OtherVivint Smart HomeCorporate/EliminationsTotal
Retail sales
Home electricity sales volume (GWh)17,413 5,868 1,145 — — 24,426 
Business electricity sales volume (GWh)18,596 21,842 4,675 — — 45,113 
Home natural gas sales volume (MDth)— 30,111 48,315 — — 78,426 
Business natural gas sales volume (MDth)— 823,128 93,058 — — 916,186 
Average retail Home customer count (in thousands)(a)
2,868 1,810 781 — — 5,459 
Ending retail Home customer count (in thousands)(a)
2,869 1,858 772 — — 5,499 
Average Vivint Smart Home subscriber count (in thousands)(b)
— — — 1,958 — 1,958 
Ending Vivint Smart Home subscriber count (in thousands)(b)
— — — 2,004 — 2,004 
Power generation
GWh sold12,694 1,882 2,869 — — 17,445 
GWh generated(c)
      Coal5,771 366 — — — 6,137 
      Gas2,410 85 2,867 — — 5,362 
      Nuclear4,513 — — — — 4,513 
Renewables— — 2 — — 2 
       Total12,694 451 2,869 — — 16,014 
(a) Home customer count includes recurring residential customers, services customers and municipal aggregations
(b) Vivint Smart Home subscribers includes customers that also purchase other NRG products
(c) Includes owned and leased generation, excludes tolled generation and equity investments

66

Six months ended June 30, 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)TexasEastWest/Services/OtherCorporate/EliminationsTotal
Retail revenueRetail revenue$4,511 $7,921 $2,090 $(1)$14,521 
Energy revenue$540
 $243
 $783
 $—
 $119
 $146
 $(383) $665
Energy revenue53 332 185 14 584 
Capacity revenue74
 172
 246
 —
 1
 92
 (4) 335
Capacity revenue— 204 2 — 206 
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(3)(236)(56)14 (281)
Contract amortization5
 —
 5
 1
 (1) (18) 1
 (12)Contract amortization— (20)(2)— (22)
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)
151 28 1 (10)170 
Total revenueTotal revenue4,712 8,229 2,220 17 15,178 
Cost of fuel(292) (123) (415) (1) (1) (6) 17
 (406)Cost of fuel(529)(175)(157)— (861)
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)
(2,967)(7,431)(1,860)(5)(12,263)
Mark-to-market for economic hedging activities2
 10
 12
 (174) —
 —
 112
 (50)Mark-to-market for economic hedging activities1,262 1,818 211 (14)3,277 
Contract and emission credit amortization(7) (1) (8) —
 —
 —
 —
 (8)Contract and emission credit amortization4 (102)(5)— (103)
Depreciation and amortizationDepreciation and amortization(154)(127)(43)(16)(340)
Gross margin$394
 $238
 $632
 $305
 $140
 $249
 $(14) $1,312
Gross margin$2,328 $2,212 $366 $(18)$4,888 
Less: Mark-to-market for economic hedging activities, net135

10

145
 (174)
5

—

—
 (24)Less: Mark-to-market for economic hedging activities, net1,259 1,582 155 — 2,996 
Less: Contract and emission credit amortization, net(2)
(1)
(3) 1

(1)
(18)
1
 (20)Less: Contract and emission credit amortization, net4 (122)(7)— (125)
Less: Depreciation and amortizationLess: Depreciation and amortization(154)(127)(43)(16)(340)
Economic gross margin$261
 $229

$490

$478

$136

$267

$(15)
$1,356
Economic gross margin$1,219 $879 $261 $(2)$2,357 
(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 $1.5 billion, $111 million and $664 million of TDSP expense in Texas, East and West/Services/Other, respectively(c) Includes $1.5 billion, $111 million and $664 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 electricity sales volume (GWh)Home electricity sales volume (GWh)20,826 6,460 1,096 — 28,382 
Business electricity sales volume (GWh)Business electricity sales volume (GWh)18,853 24,358 4,559 — 47,770 
Home natural gas sales volume (MDth)Home natural gas sales volume (MDth)— 31,211 53,618 — 84,829 
Business natural gas sales volume (MDth)Business natural gas sales volume (MDth)— 874,430 79,794 — 954,224 
Average retail Home customer count (in thousands)(a)
Average retail Home customer count (in thousands)(a)
3,006 1,781 803 — 5,590 
Ending retail Home customer count (in thousands)(a)
Ending retail Home customer count (in thousands)(a)
2,994 1,808 799 — 5,601 
Power generationPower generation
GWh soldGWh sold18,056 5,827 3,372 — 27,255 
GWh generated(b)
GWh generated(b)
Coal Coal9,316 3,827 — — 13,143 
Gas Gas3,669 152 3,376 — 7,197 
Nuclear Nuclear5,071 — — — 5,071 
RenewablesRenewables— — 5 — 5 
Total Total18,056 3,979 3,381 — 25,416 
(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

67

 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 threesix months ended SeptemberJune 30, 20172023 and 2016:2022:
 Six months ended June 30,
Weather MetricsTexasEast
West/Services/Other(b)
2023
CDDs(a)
1,144 327 575 
HDDs(a)
856 2,570 1,413 
2022
CDDs1,351 393 705 
HDDs1,202 2,890 1,344 
10-year average
CDDs1,088 396 602 
HDDs1,045 3,072 1,281 
(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.



Generation grossGross margin decreased $4.1 billion and economic gross margin
Generation gross margin decreased $225 million and economic gross margin decreased $102 increased $892 million, both of which include intercompany sales, during the threesix months ended SeptemberJune 30, 2017,2023, compared to the same period in 2016:

2022.
The tabletables below describesdescribe the decreasechanges 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.by segment:
Texas
(In millions)
Higher gross margin due to the net effect of:
•increased net revenue rates of $6.50 per MWh, or $317 million, primarily driven by changes in customer term, product and mix; and
•a $202 million decrease in cost to serve the retail load, primarily driven by lower supply costs which were a result of lower power pricing, the diversified supply strategy and improved plant performance coupled with the 2022 impact of the W.A. Parish Unit 8 extended outage that began in May 2022
$519 
Lower gross margin due to a decrease in load of 1.4 TWh, or $90 million, driven by attrition and changes in customer mix, and a decrease in load of 2.2 TWh, or $78 million, from weather(168)
Higher gross margin due to market optimization activities29 
Other(4)
Increase in economic gross margin$376
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges(796)
Increase in contract and emission credit amortization(8)
Decrease in depreciation and amortization6 
Decrease in gross margin$(422)



68

 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
East
(In millions)
Lower gross margin due to a decrease in generation and capacity as a result of asset retirements$(84)
Higher electric gross margin due to higher net revenue rates as a result of changes in customer term, product and mix of $8.75 per MWh, or $241 million, partially offset by higher supply costs of $2.75 per MWh, or $73 million, driven primarily by increases in power prices168 
Lower electric gross margin of $10 million from a decrease in volumes due to changes in customer mix, as well as a $7 million decrease in load of 353,000 MWh from weather(17)
Lower natural gas gross margin from a decrease in volumes due to weather and changes in customer mix(27)
Lower gross margin primarily due to a 61% decrease in PJM capacity prices and a 19% decrease in PJM capacity volumes(53)
(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
Higher gross margin due to a decrease in supply costs at Midwest Generation, offset by lower gross margin as a result of $365an 84% decrease in generation volumes due to dark spread contractions7 
Other(7)
Decrease in economic gross margin$(13)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges(3,489)
Decrease in contract amortization23 
Decrease in depreciation and amortization67 
Decrease in gross margin$(3,412)

West/Services/Other
(In millions)
Lower gross margin primarily due to lower Services sales$(19)
Lower electric gross margin due to an increase in supply rate of $21.50 per MWh, or $126 million, partially offset by higher revenue rate of $17.75 per MWh, or $104 million, and $340an increase in volumes due to increased customer count and changes in customer mix of $8 million(14)
Lower natural gas gross margin due to lower revenue rates of $0.20 per Dth, totaling $28 million, partially offset by higher supply rates of $0.15 per Dth, or $20 million, and an increase in 2017volumes due to changes in customer mix of $3 million(5)
Higher gross margin at Cottonwood was driven by reduced commodity costs partially offset by lower average realized prices and 2016, respectively.lower volumes associated with the current year planned outage14 
Higher gross margin from market optimization activities14 
Other(1)
Decrease in economic gross margin$(11)
Decrease in mark-to-market for economic hedges primarily due to net unrealized gains/losses on open positions related to economic hedges(591)
Decrease in contract amortization1 
Increase in depreciation and amortization(4)
Decrease in gross margin$(605)

Retail gross margin increased $140 million and economic gross margin decreased $46 million forVivint Smart Home(a)
(In millions)
Increase due to the acquisition of Vivint Smart Home$540 
Increase in economic gross margin$540
Increase in depreciation and amortization(232)
Increase in gross margin$308
(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


69
 (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





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$4.9 billion during the threesix months ended SeptemberJune 30, 2017,2023, compared to the same period in 2016.2022.
The breakdown of gains and losses included in operating revenues and operating costs and expenses by regionsegment was as follows:
Six months ended June 30, 2023
(In millions)TexasEastWest/Services/OtherEliminationsTotal
Mark-to-market results in revenue 
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges$— $(15)$26 $(6)$5 
Reversal of acquired (gain) positions related to economic hedges— (1)— — (1)
Net unrealized gains on open positions related to economic hedges— 103 64 (5)162 
Total mark-to-market gains in revenue$— $87 $90 $(11)$166 
Mark-to-market results in operating costs and expenses  
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges$(118)$(555)$(335)$6 $(1,002)
Reversal of acquired loss/(gain) positions related to economic hedges18 (8)1 — 11 
Net unrealized gains/(losses) on open positions related to economic hedges563 (1,431)(192)5 (1,055)
Total mark-to-market gains/(losses) in operating costs and expenses$463 $(1,994)$(526)$11 $(2,046)

 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.

 Six months ended June 30, 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 $(21)$36 $(4)$12 
Reversal of acquired loss positions related to economic hedges— 1 — — 1 
Net unrealized (losses) on open positions related to economic hedges(4)(216)(92)18 (294)
Total mark-to-market losses in revenue$(3)$(236)$(56)$14 $(281)
Mark-to-market results in operating costs and expenses    
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges$(145)$(396)$(80)$4 $(617)
Reversal of acquired loss/(gain) positions related to economic hedges31 (43)(1)— (13)
Net unrealized gains on open positions related to economic hedges1,376 2,257 292 (18)3,907 
Total mark-to-market gains in operating costs and expenses$1,262 $1,818 $211 $(14)$3,277 
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 threesix months ended SeptemberJune 30, 2017,2023, the $26$166 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, partially offset by a decrease in value of open positions as a result of an increase in natural gas prices. The $50 million loss in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period, partially offset by an increase in value of open positions as a result of an increase in coal prices.
For the three months ended September 30, 2016, the $62 million gain in operating revenues from economic hedge positions was driven primarily by an increase in value of open positions as a result of decreases in power and natural gas and electricity prices, partially offset by the reversal of previously recognized unrealized gains on contracts that settled during the period.prices. The $149 million$2.0 billion loss in operating costs and expenses from economic hedge positions was driven primarily by a decrease in the value of East and West open positions as a result of decreases in natural gas and power prices, as well as the reversal of previously recognized unrealized gains on contracts that settled during the period. This was partially offset by an increase in the value of Texas open positions as a result of increase in ERCOT electricitypower prices and the reversal of acquired loss positions.
For the six months ended June 30, 2022, the $281 million loss in revenues from economic hedge positions was driven by a decrease in the value of open positions as a result of increases in PJM power prices, partially offset by the reversal of previously recognized unrealized losses on contracts that settled during the period. The $3.3 billion gain in operating costs and expenses from economic hedge positions was driven primarily by an increase in the value of open positions as a result of increases in natural gas and power prices across all segments, partially offset by the reversal of previously recognized unrealized gains on contracts that settled during the period.

70

In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the threesix months ended SeptemberJune 30, 20172023 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.
 Six months ended June 30,
(In millions)20232022
Trading (losses)/gains
Realized$(3)$2 
Unrealized25 (16)
Total trading gains/(losses)$22 $(14)
 Three months ended September 30,
(In millions)2017 2016
Trading (losses)/gains   
Realized$(10) $20
Unrealized(5) (5)
Total trading (losses)/gains$(15) $15




Operations and Maintenance Expense
Operations and maintenance expense are 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 Smart Home(a)
EliminationsTotal
Six months ended June 30, 2023$382 $168 $126 $72 $(2)$746 
Six months ended June 30, 2022385 214 93 — (2)690 
(a)Includes International, BETM and generation eliminations of $2 million in 2017 and $1 million in 2016.

(a) Includes results of operations following the acquisition date of March 10, 2023
Operations and maintenance expense decreasedincreased by $28$56 million for the threesix months ended SeptemberJune 30, 2017,2023, compared to the same period in 2016,2022, due to the following:
(In millions)
Increase due to the acquisition of Vivint Smart Home$72 
Increase in major maintenance expenditures associated with the timing of planned outages at STP and the scope and duration of outages at Texas gas facilities, Midwest Generation and Cottonwood63 
Increase driven by higher retail operations costs13 
Decrease due to the current year partial property insurance claim for the extended outage at W.A. Parish, partially offset by the cost of restoration efforts(41)
Decrease in variable operation and maintenance expense due to a reduction in PJM generation volumes in 2023(19)
Decrease due to change in estimates of environmental remediation costs at deactivated sites in the
East in 2022		(17)
Decrease driven primarily by East asset retirements partially offset by an increase in deactivation costs in the
West
(13)
Other(2)
Increase in operations and maintenance expense$56 
Other Cost of Operations
Other Cost of operations are comprised of the following:
(In millions)TexasEastWest/Services/Other
Vivint Smart Home(a)
Total
Six months ended June 30, 2023$111 $66 $6 $1 $184 
Six months ended June 30, 202293 75 9 — 177 
(a) Includes results of operations following the acquisition date of March 10, 2023

71

 (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)
Other cost of operations increased by $7 million for the six months ended June 30, 2023, compared to the same period in 2022, due to the following:
Selling, General
(In millions)
Increase due to higher property insurance premiums and property taxes$20 
Decrease primarily due to changes in timing of ARO spend at Midwest Generation(10)
Decrease in retail gross receipt taxes due to lower revenues(5)
Other2 
Increase in other cost of operations$7 
Depreciation and AdministrativeAmortization
Selling, generalDepreciation and administrativeamortization expenses are comprised of the following:
(In millions)TexasEastWest/Services/Other
Vivint Smart Home(a)
CorporateTotal
Six months ended June 30, 2023$148 $60 $47 $232 $18 $505 
Six months ended June 30, 2022154 127 43 — 16 340 
 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) Includes results of operations following the acquisition date of March 10, 2023
Selling, generalDepreciation and administrative expenses decreasedamortization increased by $64$165 million for the threesix months ended SeptemberJune 30, 2017,2023, compared to the same period in 2016. The decrease2022, primarily due to higher amortization of intangible assets due to the acquisition of Vivint Smart Home in year over year expenses is due primarily toMarch 2023, partially offset by lower depreciation at Midwest Generation as a reductionresult of asset impairments and retirements in personnel costs and selling and marketing activities as the Company continues to focus on cost management.2022.
ReorganizationImpairment Losses
Reorganization expensesImpairment losses of $18$155 million were incurredrecorded during the third quarter of 2017six months ended June 30, 2022 primarily related to impairments at Midwest Generation due to the Transformation Plan announced on July 12, 2017.decline in PJM capacity prices and the planned retirement of Joliet. For further discussion, see Note 8, Impairments.
Loss on Debt ExtinguishmentSelling, General and Administrative Costs
A loss on debt extinguishmentSelling, general and administrative costs comprised of $50 million was recorded for the three months ended September 30, 2016, primarily drivenfollowing:
(In millions)TexasEastWest/Services/Other
Vivint Smart Home(a)
CorporateTotal
Six months ended June 30, 2023$343 $285 $105 $203 $12 $948 
Six months ended June 30, 2022310 247 115 — 26 698 
(a) Includes results of operations following the acquisition date of March 10, 2023
Total selling, general and administrative costs increased 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 $16$250 million for the threesix months ended SeptemberJune 30, 2017,2023, compared to the same period in 20162022, due to the following:
(In millions)
Increase due to Vivint Smart Home acquisition$203 
Increase due to higher personnel costs36 
Increase in broker fee and commissions expenses18 
Increase due to higher provision for credit losses18 
Decrease due to lower consulting and legal expenses(17)
Decrease in marketing and media expenses(4)
Other(4)
  Increase in selling, general and administrative costs$250 
Acquisition-Related Transaction and Integration Costs
Acquisition-related transaction and integration costs were $93 million for the six months ended June 30, 2023, which consisted of $38 million of acquisition costs and $44 million of integration costs related to Vivint Smart Home, as well as $11 million of integration costs primarily related to Direct Energy. Acquisition-related transaction and integration costs were $18 million for the six months ended June 30, 2022, which were primarily integration costs related to Direct Energy.

72

 (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)
Gain on Sale of Assets
The gain on sale of assets of $202 million and $29 million for the six months ended June 30, 2023 and 2022, respectively, include:
Six months ended June 30,
(In millions)20232022
Sale of Astoria Turbines in January 2023$199 $— 
Sale of the Company's 49% ownership in the Watson natural gas generating facility— 46 
Other asset sales3 (17)
Gain on sale of assets$202 $29 
Other Income, Net
Other income, net increased by $17 million in the six months ended June 30, 2023, compared to the same period in 2022, primarily driven by higher interest income.
Interest Expense
Interest expense increased by $91 million for the six months ended June 30, 2023, compared to the same period in 2022, primarily due to the Vivint Smart Home acquisition including the impact of newly issued Senior Secured First Lien Notes, acquired debt of Vivint Smart Home, borrowings on the Revolving Credit Facility and the Receivables Securitization Facilities, as well as the write-off of the deferred financing costs associated with the cancellation of the bridge facility for the Vivint Smart Home acquisition.
Income Tax ExpenseExpense/(Benefit)
For the threesix months ended SeptemberJune 30, 2017, NRG recorded2023, an income tax expensebenefit of $6$247 million was recorded on pre-tax incomeloss of $196 million.$1.3 billion. For the same period in 2016, NRG recorded2022, income tax expense of $28$723 million was recorded on pre-tax income of $156 million.$3.0 billion. The effective tax rate was 3.1%rates were 19.4% and 17.9%24.3% for the threesix months ended SeptemberJune 30, 20172023 and 2016,2022, respectively.
For the threesix months ended SeptemberJune 30, 2017,2023, NRG's overall effective tax rate was different thenlower than the statutory rate of 35%21%, 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.
expense which has an inverted effect and reduces the overall effective tax rate when applied to year-to-date financial statement losses. For the three months ended September 30, 2016,same period in 2022, NRG's overall effective tax rate was differenthigher than the statutory rate of 35%21%, primarily due to thestate tax benefit for the change in valuation allowance,expense, 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 as 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-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, 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 prices on the acquisition date.
For 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, 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 results of the Company's financial and physical trading of energy commodities 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.
 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 forresulting from the change inrelease of 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 currenton state tax expense.net operating losses.
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 nine months ended September 30, 2017, NRG recorded loss from discontinued operations, net of income tax (benefit)/expense of $802 million.
For the nine months ended September 30, 2016, NRG recorded income from discontinued operations, net of income tax (benefit)/expense of $256 million.


Liquidity and Capital Resources
Liquidity Position
As of SeptemberJune 30, 20172023 and December 31, 2016,2022, NRG's total liquidity, excluding collateral received, wasfunds deposited by counterparties, of approximately $3.4$4.5 billion and $2.4$2.8 billion,, respectively, was comprised of the following:
(In millions)June 30, 2023December 31, 2022
Cash and cash equivalents$422 $430 
Restricted cash - operating2 5 
Restricted cash - reserves24 35 
Total448 470 
Total availability under Revolving Credit Facility and collective collateral facilities(a)
4,067 2,324 
Total liquidity, excluding funds deposited by counterparties$4,515 $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 $7.8 billion and $6.4 billion as of June 30, 2023 and December 31, 2022, respectively
(a) Includes reserves primarily for debt service, performance obligations, and capital expenditures.
For the ninesix months ended SeptemberJune 30, 2017,2023, total liquidity, excluding collateral funds deposited by counterparties, increased by $1$1.7 billion. Changes in cash and cash equivalentsequivalent balances are further discussed hereinafter under the heading CashFlow Discussion. Cash and cash equivalents at SeptemberJune 30, 20172023 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 Discussion

73

The 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 Smart Home 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, 9, 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, the Senior Notes,Receivables Securitization Facilities and tax-exempt bonds. As part of the acquisition of Vivint Smart Home 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 Smart Home'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 9, 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, Dispositions and Acquisitions, NRG, the GenOn Entities and certain holders11, Changes in Capital Structure.
Planned sale of the GenOn and GenOn Americas Generation Senior Notes44% equity interest in STP
On May 31, 2023, the Company entered into a Restructuring Support Agreement, that providesdefinitive equity purchase agreement to sell its 44% equity interest in STP to Constellation for $1.75 billion, subject to customary purchase price adjustments. The transaction is expected to close by the end of 2023 and is subject to regulatory approval by the NRC. The waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, expired in July 2023. For further discussion, see Note 4, Acquisitions and Dispositions.
Debt Reduction
The Company plans to reduce debt by $900 million during 2023 as part of its plan to achieve target investment-grade credit metrics, and intends to fund the reduction from cash from operations. NRG plans an additional $500 million of debt reduction subsequent to the planned sale of STP as the transaction is intended to be leverage neutral. As of July 31, 2023, the Company executed $200 million in debt reduction.
Vivint Smart Home Acquisition
On March 10, 2023, the Company completed the acquisition of Vivint Smart Home. The Company paid $12 per share, or $2.6 billion in cash. The Company funded the acquisition using a restructuringcombination 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 recapitalizationReceivables Facilities, and cash on hand.
Issuance of GenOn through2033 Senior Notes
On March 9, 2023, the Company issued $740 million of aggregate principal amount of 7.000% senior notes due 2033. The 2033 Senior Notes are senior secured obligations of NRG and are guaranteed by certain of its subsidiaries. Interest is paid semi-annually beginning on September 15, 2023 until the maturity date of March 15, 2033. See Note 9,Long-term Debt and Finance Leases, for further discussion.
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. See Note 11,Changes in Capital Structure,for further discussion.
Revolving Credit Facility
On February 14, 2023, the Company amended its Revolving Credit Facility to: (i) increase the existing revolving commitments thereunder by $600 million (the “Incremental Commitment”), (ii) extend the maturity date of a prearranged planportion of reorganization. Certain principalthe 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 Restructuring Support Agreement include that NRG will provide settlement considerationRevolving Credit Facility for purposes of, among other things, providing additional flexibility.

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On March 13, 2023, the Company further amended its Revolving Credit Facility to GenOn of $261.3 million, which will be paid in cash less any amounts owed to NRG underincrease the intercompany securedexisting revolving credit facility.commitments by an additional $45 million. As of June 30, 2017, GenOn owed NRG approximately $1252023, there were outstanding borrowings of $700 million and there were $823 million in letters of credit issued under the intercompanyRevolving Credit Facility. As of July 31, 2023, there were outstanding borrowings of $700 million and $879 million in letters of credit issued under the Revolving Credit Facility.
Receivables Securitization Facilities
On June 22, 2023, NRG Receivables amended its existing Receivables Facility to, among other things, (i) extend the scheduled termination date to June 21, 2024, (ii) increase the aggregate commitments from $1.0 billion to $1.4 billion (adjusted seasonally) and (iii) add a new originator. As of June 30, 2023, there were no outstanding borrowings and there were $842 million in letters of credit issued.
In addition, in connection with the amendments to the Receivables Facility, on June 22, 2023, the Company and the originators thereunder renewed the existing uncommitted Repurchase Facility that provides short-term financing secured revolving credit facility.by a subordinated note issued by NRG agreedReceivables LLC. Such renewal, among other things, extends the maturity date to provide GenOn with aJune 21, 2024 and joins an additional originator to the Repurchase Facility. As of June 30, 2023, there were no outstanding borrowings.
Bilateral Letter of Credit Facilities
On May 19, 2023 and May 30, 2023, the Company increased the size of its bilateral letter of credit facility duringfacilities by $25 million and $100 million, respectively, to provide additional liquidity, allowing for the pendencyissuance of up to $800 million of letters of credit. These facilities are uncommitted. As of June 30, 2023, $589 million was issued under these facilities.
Sale of Astoria
On January 6, 2023, the Company closed on the sale of land and related assets from the Astoria site, within the East region of operations, for initial proceeds of $212 million, subject to transaction fees of $3 million and certain indemnifications. As part of the Chapter 11 Cases,transaction, NRG entered into an agreement to be utilizedlease the land back for required lettersthe purpose of credit in lieuoperating the Astoria gas turbines. The lease agreement is expected to terminate by the end 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. See Note 1, Basis of Presentation, for further discussion regarding the October 30, 2017 proposed changes to the Restructuring Support Agreement, which includes the retention of the liability 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.year after decommissioning is complete.


Revolving Credit Facility
As of September 30, 2017, there were no cash borrowings outstanding on the revolver.
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 SeptemberJune 30, 2017, commercial operations2023, the Company had total cash collateral outstanding of $274$270 million and $606 million$3.8 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 SeptemberJune 30, 2017,2023, total collateral held fromfunds deposited by counterparties was $31were $365 million in cash and $17$407 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 June 30, 2023, all hedges under the first liens were out-of-the-money on a counterparty aggregate basis.
The following table summarizes the amount of MW hedged against the Company's coal and nuclear assets and as a percentage relative to the Company's coal and nuclear capacity under the first lien structure as of June 30, 2023:
Equivalent Net Sales Secured by First Lien Structure(a)
2023
In MW341
As a percentage of total net coal and nuclear capacity(b)
8%
(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

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Capital Expenditures, Investments and Integration
The following tablestable and descriptions summarize the Company's maintenance capital expenditures, for maintenance, environmental capital expenditures, and growth investments and integration spend for the ninesix months ended SeptemberJune 30, 2017,2023, and the currently estimated capital expenditure and growth investments forecast for the remainder of 2017. the year.
(In millions)MaintenanceEnvironmental
Investments and Integration(a)
Total
Texas$248 $— $27 $275 
East— — 1 1 
West/Services/Other13 — 4 17 
Corporate7 — 17 24 
Vivint Smart Home(b)
7 — — 7 
Total cash capital expenditures for the six months ended June 30, 2023275 — 49 324 
Integration operating expenses(c)
— — 40 40 
Investments— — 70 70 
Total cash capital expenditures and investments for the six months ended June 30, 2023$275 $— $159 $434 
Estimated cash capital expenditures and investments for the remainder of 2023(d)
275 13 211 499 
Estimated full year 2023 cash capital expenditures and investments$550 $13 $370 $933 
 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)Full year estimate reflects the cash expected to be available for allocation for investments and Vivint Smart Home integration in 2023
(b)Includes expenditures following the acquisition date of March 10, 2023
Environmental(c)Excludes equity compensation related to integration
(d)Estimated capital expenditures — For related to W.A. Parish do not reflect expected insurance recoveries
Investments and Integration for the ninesix months ended SeptemberJune 30, 2017, the Company's environmental capital2023 include growth expenditures, included DSI/ESP upgrades at the Powerton facilityintegration, small book acquisitions and the Joliet gas conversion to satisfy CPS.
other investments.
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$45 million, which includes $16 million for Midwest Generation. The increase from last quarter isprimarily driven primarily by the additioncost of complying with ELG at the Company's coal units in Texas.
Share Repurchases
In June 2023, NRG revised its long-term capital allocation policy to target allocating approximately 80% of cash available for allocation after debt reduction to be returned to shareholders. As part of the anticipated costsrevised capital allocation framework, the Company announced an increase to its share repurchase authorization to $2.7 billion, to be executed through 2025. During July 2023, the Company purchased 1,322,141 shares for $50 million at an average price of adding NOx control equipment at certain$37.82 under the $2.7 billion authorization.
Common Stock Dividends
During the first 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 units in Connecticut.
Dividends
The following table lists the dividends paidcommon stock during the ninethree months ended SeptemberJune 30, 2017:
 Third Quarter 2017 Second Quarter 2017 First Quarter 2017
Dividends per Common Share$0.030
 $0.030
 $0.030
2023. On October 18, 2017,July 17, 2023, NRG declared a quarterly dividend on the Company's common stock of $0.03$0.3775 per share, payable Novemberon August 15, 2017,2023 to stockholders of record as of NovemberAugust 1, 2017 representing $0.12 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. The Company expects that, based on current circumstances, comparable cash dividends will continue to be paid in the foreseeable future.

Obligations under Certain Guarantees

Fuel Repowerings
The table below lists the Company's currently projected repowering 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 margin 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 Discussion and Analysis to this Form 10-Q for recent developments in the permitting process that may impact the viability of the Puente project.
(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 nine month periods:
 Nine months ended September 30,  
 2017 2016 Change
 (In millions)
Net cash used by operating activities$806
 $1,741
 $(935)
Net cash used by investing activities(765) (255) (510)
Net cash provided by financing activities59
 (587) 646
Net Cash Used By Operating Activities
Changes to net cash used by operating activities were driven by:
 (In millions)
Changes in cash collateral in support of risk management activities due to changes in commodity prices$(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
 $(935)
Net Cash Used By Investing Activities
Changes to net cash used by investing activities were driven by:
 (In millions)
Cash used by discontinued operations$(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 Activities
Changes to net cash provided by financing activities were driven by:
 (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


NOLs, Deferred Tax Assets and Uncertain Tax Position Implications, under ASC 740
For the nine months ended September 30, 2017, the Company had total domestic pre-tax book income of $112 million and foreign pre-tax book income of $13 million. As of December 31, 2016, the Company had cumulative domestic Federal NOL carryforwards of $3.4 billion, of which $1.2 billion is from GenOn Energy, Inc. and subsidiaries which will begin expiring in 2026 and cumulative state NOL carryforwards of $4.9 billion for financial statement purposes. In addition, NRG has cumulative foreign NOL carryforwards of $196 million, 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 Company has $36 million of tax effected uncertain tax benefits. As a result of the Company's tax position, and based on current forecasts, NRG anticipates income tax payments, primarily to state and local jurisdictions, of up to $25 million in 2017.
The Company has recorded a non-current tax liability of $40 million until final resolution 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 not subject to U.S. federal income tax examinations for years prior to 2015. With few exceptions, state and local income tax examinations are no longer open for years prior to 2010. The Company's primary foreign operations are also no longer subject to examination by local jurisdictions for years prior to 2010.
Off-Balance Sheet Arrangements
Obligations under Certain Guarantee Contracts
NRG and certain of its subsidiaries enter into various contracts that include indemnifications and guarantee arrangements inprovisions as a routine part of the normal course ofCompany’s business activities. For further discussion, see Note 27, Guarantees,to facilitate commercial transactions with third parties. These arrangements include financial and performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications.the Company's 2022 Form 10-K.
Retained or Contingent Interests

NRG does not have any material retained or contingent interests in assets transferred to an unconsolidated entity.76

Obligations Arising Out 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 lessNRG’s investment in energy and energy-related entities that are accounted for under the equity method of accounting. Several of these investments areIvanpah is a variable interest entitiesentity 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$471 million as of SeptemberJune 30, 2017.2023. This indebtedness may restrict the ability of these subsidiariesIvanpah 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.
Contractual Obligations and CommercialMarket Commitments
NRG has a variety of contractual obligations and other commercialmarket commitments that represent prospective cash requirements in addition to the Company's capital expenditure programs, as disclosed in the Company's 20162022 Form 10-K. See also Note 8, 9, Long-term Debt and CapitalFinance Leases, and Note 15, 16, Commitments and Contingencies, to this Form 10-Q for a discussion of new commitments and contingencies that also include contractual obligations and commercialmarket commitments that occurred during the three and ninesix months ended SeptemberJune 30, 2017.

2023.


Cash Flow Discussion
The following table reflects the changes in cash flows for the comparative six month periods:
Six months ended June 30,
(In millions)20232022Change
Cash (used)/provided by operating activities$(1,028)$3,189 $(4,217)
Cash used by investing activities(2,502)(119)(2,383)
Cash provided by financing activities2,162 414 1,748 

Cash (used)/provided by operating activities
Changes to cash (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$(4,476)
Increase in operating loss/income adjusted for other non-cash items1,121 
Decrease due to receipt of uplift securitization proceeds from ERCOT in 2022(689)
Decrease in working capital related to prepayments and other current assets primarily due to increased capitalized contract costs and FTR activity(104)
Decrease in working capital primarily due to lower gas and power market pricing coupled with lower gas volumes(56)
Decrease in other working capital(13)
$(4,217)
Cash used by investing activities
Changes to cash (used)/provided by investing activities were driven by:
(In millions)
Increase in cash paid for acquisitions primarily due to the acquisition of Vivint Smart Home in March 2023$(2,445)
Increase in capital expenditures(174)
Increase in proceeds from sale of assets primarily due to the sale of the land and related assets from the Astoria site in January 2023133 
Increase from insurance proceeds for property, plant and equipment, net in 2023121 
Decrease in proceeds from sales of investments in nuclear decommissioning trust fund securities, net of purchases(12)
Decrease in proceeds from sales of emissions allowances, net of purchases(6)
$(2,383)

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Cash provided by financing activities
Changes to cash provided/(used) by financing activities were driven by:
(In millions)
Increase in proceeds from issuance of long-term debt in 2023$731 
Increase in proceeds from Revolving Credit Facility in 2023700 
Increase in proceeds from issuance of preferred stock in 2023635 
Decrease in net receipts from settlement of acquired derivatives(632)
Increase due to lower payments for share repurchase activity in 2023350 
Increase in payments of deferred issuance costs(22)
Decrease due to repayments of long-term debt and finance leases(8)
Increase in payments of dividends to common stockholders(6)
$1,748 

NOLs, Deferred Tax Assets and Uncertain Tax Position Implications, under ASC 740
For the six months ended June 30, 2023, the Company had domestic pre-tax book loss of $1.1 billion and foreign pre-tax book loss of $159 million. As of December 31, 2022, the Company had cumulative U.S. Federal NOL carryforwards of $8.2 billion, which do not have an expiration date, and cumulative state NOL carryforwards of $5.3 billion for financial statement purposes. NRG also has cumulative foreign NOL carryforwards of $382 million, most of which do not have an expiration date. In addition to the above NOLs, NRG has a $270 million indefinite carryforward for interest deductions, as well as $393 million of tax credits to be utilized in future years. In connection with the Vivint Smart Home acquisition, additional federal and state NOLs of $2.1 billion and $1.8 billion, respectively, were added, as well as a federal carryforward for interest deductions of $739 million. As a result of the Company's tax position, including the utilization of federal and state NOLs, and based on current forecasts, the Company anticipates net income tax payments due to federal, state and foreign jurisdictions of up to $60 million in 2023.
As of June 30, 2023, the Company has $43 million of tax-effected uncertain federal and state tax benefits, for which the Company has recorded a non-current tax liability of $45 million (inclusive of accrued interest) until final resolution is reached with the related taxing authority.
The Company is no longer subject to U.S. federal income tax examinations for years prior to 2019. With few exceptions, state and Canadian income tax examinations are no longer open for years prior to 2014.
Deferred tax assets and valuation allowance
Net deferred tax balance — As of June 30, 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 June 30, 2023 and December 31, 2022 as discussed below.
NOL Carryforwards — As of June 30, 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 Smart Home. The Company estimates it will need to generate future taxable income to fully realize the net federal deferred tax asset before the expiration of certain carryforwards commences in 2030. In addition, NRG has tax-effected cumulative foreign NOL carryforwards of $101 million.
Valuation Allowance — As of June 30, 2023 and December 31, 2022, the Company’s tax-effected valuation allowance was $230 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 June 30, 2023, the Company's outstanding registered senior notes consisted of $375 million of the 2027 Senior Notes and $821 million of the 2028 Senior Notes as shown in Note 9, Long-term Debt and Finance Leases. These Senior Notes are guaranteed by certain of NRG's current and future 100% owned domestic subsidiaries, or guarantor subsidiaries (the “Guarantors”). See Exhibit 22.1 for a listing of the Guarantors. These guarantees are both joint and several.
NRG conducts much of its business through and derives much of its income from its subsidiaries. Therefore, the Company's ability to make required payments with respect to its indebtedness and other obligations depends on the financial

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results and condition of its subsidiaries and NRG's ability to receive funds from its subsidiaries. There are no restrictions on the ability of any of the Guarantors to transfer funds to NRG. Other subsidiaries of the Company do not guarantee the registered debt securities of either NRG Energy, Inc or the Guarantors (such subsidiaries are referred to as the “Non-Guarantors”). The Non-Guarantors include all of NRG's foreign subsidiaries and certain domestic subsidiaries.
The tables below present summarized financial information of NRG Energy, Inc. and the Guarantors in accordance with Rule 3-10 under the SEC's Regulation S-X. The financial information may not necessarily be indicative of results of operations or financial position of NRG Energy, Inc. and the Guarantors in accordance with U.S. GAAP.
The following table presents the summarized statement of operations:
(In millions)Six months ended June 30, 2023
Revenues(a)
$11,789 
Operating loss(b)
(991)
Total other expense(196)
Loss from continuing operations before income taxes(1,187)
Net Loss(985)
(a)Intercompany transactions with Non-Guarantors of $6 million during the six months ended June 30, 2023
(b)Intercompany transactions with Non-Guarantors including cost of operations of $52 million and selling, general and administrative of $76 million during the six months ended June 30, 2023
The following table presents the summarized balance sheet information:
(In millions)June 30, 2023
Current assets(a)
$7,662 
Property, plant and equipment, net1,133 
Non-current assets14,486 
Current liabilities(b)
8,310 
Non-current liabilities11,746 
(a)Includes intercompany receivables due from Non-Guarantors of $67 million as of June 30, 2023
(b)Includes intercompany payables due to Non-Guarantors of $17 million as of June 30, 2023

Fair Value of Derivative Instruments
NRG may enter into power purchase and sales contracts, fuel purchase contracts and other energy-related financial instruments to mitigate variability in earnings due to fluctuations in spot market prices and to hedge fuel requirements at 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 Flex Pay, offered by Vivint Smart Home, subscribers pay for smart home products by obtaining financing from a third-party financing provider under the Consumer Financing Program. Vivint Smart Home pays certain fees to the financing providers and shares in credit losses depending on the credit quality of the subscriber.
NRG's trading activities are subject to limits in accordance with the Company's Risk Management Policy. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments 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 SeptemberJune 30, 2017,2023, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at SeptemberJune 30, 20172023. 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(976)
Vivint Smart Home contracts acquired during the period(112)
Changes in fair value(853)
Fair Value of Contracts as of June 30, 2023$1,612 
Derivative Activity (Losses)/Gains(In millions)
Fair Value of Contracts as of December 31, 2016$(128)
Contracts realized or otherwise settled during the period21
Changes in fair value(41)
Fair Value of Contracts as of September 30, 2017$(148)
Fair Value of Contracts as of June 30, 2023
(In millions)Maturity
Fair Value Hierarchy (Losses)/Gains1 Year or LessGreater than 1 Year to 3 YearsGreater than 3 Years to 5 YearsGreater than 5 YearsTotal Fair
Value
Level 1$(67)$223 $(3)$— $153 
Level 2306 274 81 8 669 
Level 3352 219 72 147 790 
Total$591 $716 $150 $155 $1,612 
 Fair Value of Contracts as of September 30, 2017
 Maturity
Fair value hierarchy (Losses)/Gains1 Year or Less Greater than 1 Year to 3 Years Greater than 3 Years to 5 Years Greater than 5 Years 
Total Fair
Value
 (In millions)
Level 1$(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 SeptemberJune 30, 2017,2023, NRG's net derivative liabilityasset was $148 million,$1.6 billion, a decrease to total fair value of $20 million$1.9 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, losses in fair value, and Vivint Smart Home contracts acquired during the period.
Based on a sensitivity analysis using simplified assumptions, the impact of a $0.50 per MMBtu increase or decrease in natural gas prices across the term of the derivative contracts would result in an increasea change of approximately $39 million$1.9 billion in the net value of derivatives as of SeptemberJune 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, 2017.2023.



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 and ninesix months ended Septemberending June 30, 20172023 and 2016:2022:
(In millions)20232022
VaR as of June 30,$62 $35 
Three months ended June 30,
Average$63 $53 
Maximum78 86 
Minimum46 30 
Six months ended June 30,
Average$67 $45 
Maximum82 86 
Minimum46 27 
(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
In order to provide additional information for comparative purposes to NRG's peers, theThe 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$195 million, as of June 30, 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 June 30, 2023, counterparty credit exposure, excluding credit exposure from RTOs, ISOs, registered commodity exchanges and certain long-term agreements, was $1.9 billion and NRG held collateral (cash and letters of credit) against those positions of $616 million, resulting in a net exposure of $1.3 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 59% 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

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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 other73 %
Financial institutions27 
Total as of June 30, 2023100 %
Net Exposure (a)(b)
Category by Counterparty Credit Quality(% of Total)
Investment grade55 %
Non-investment grade/non-rated45 
Total as of June 30, 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 one wholesale counterparty in excess of 10% of total net exposure discussed above as of June 30, 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 June 30, 2023, aggregate credit risk exposure managed by NRG to these counterparties was approximately $889 million for the next five years.
Retail Customer Credit Risk
The Company is exposed to retail credit risk through the Company's retail electricity and gas providers as well as through Vivint Smart Home, which serve both Home and Business customers. Retail credit risk results in losses when a customer fails to pay for services rendered. The losses may result from both non-payment of customer accounts receivable and the loss of in-the-money forward value. The Company manages retail credit risk 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 June 30, 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 June 30, 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 $1.1 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 $285 million. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of June 30, 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 through 2027 to hedge the floating rate on the Term Loan acquired with the Vivint Smart Home acquisition. Additionally, the Company has entered into interest rate swaps intended 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's interest rate swaps.Revolving Credit Facility extending through 2024, with $400 million outstanding as of June 30, 2023.
If all of the above swaps had been discontinued on September 30, 2017, the Company would have owed the counterparties $43 million. Based 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.
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 SeptemberJune 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, 2017,2023, the fair value and related carrying value of the Company's debt was $17.4$11.2 billion and $17.1$12.1 billion, respectively. NRG estimates that a 1% decrease in market interest rates would have increased the fair value of the Company's long-term debt as of June 30, 2023 by $984$870 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 SeptemberJune 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.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.$590 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 June 30, 2023 would have resulted in a 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 June 30, 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 SeptemberJune 30, 2017,2023, see Note 15, 16, Commitments and Contingencies, to this Form 10-Q.

ITEM 1A — RISK FACTORS
Information regarding risk factors appearsDuring the three months ended June 30, 2023, there were no material changes to the Risk Factors disclosed in Part I, Item 1A, RiskFactors Related to NRG Energy, Inc., in the Company's 2016 Form 10-K, and Part II, Item 1A, Risk Factors, of the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2017. There have been no material changes inMarch 31, 2023, filed with the Company's risk factors since those reported in its 2016 Form 10‑K and its Form 10-Q for the quarter ended June 30, 2017.SEC on May 4, 2023.

ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None.During the quarter ended June 30, 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.

During the three months ended June 30, 2023, no director or officer of the Company adopted or terminated a 'Rule 10b5-1 trading arrangement' or 'non-Rule 10b5-1 trading arrangement,' as each term is defined in Item 408(a) of Regulation S-K.


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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 June 1, 2023.
4.1Filed herewith.
10.1*Filed herewith.
10.2Incorporated herein by reference to Exhibit 10.1 to the Registrant's Current Reportcurrent report on Form 8-K filed on October 6, 2017.June 27, 2023.
10.210.3Incorporated herein by reference to Exhibit 10.2 to the Registrant's Current Reportcurrent report on Form 8-K filed on October 6, 2017.June 27, 2023.
10.322.1Incorporated herein by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on November 1, 2017.Filed 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  WOO-SUNG CHUNG
Kirkland B. Andrews Woo-Sung Chung
Chief Financial Officer
(Principal Financial Officer)
/s/ DAVID CALLENEMILY PICARELLO
David CallenEmily Picarello
Date: November 2, 2017August 8, 2023
Chief Accounting OfficerCorporate Controller
(Principal Accounting Officer)







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