0001013871FALSE2023FY322232http://fasb.org/us-gaap/2023#AccountingStandardsUpdate202006MemberP12MP3YP1YP1YP1YP1YP1YP5Yhttp://fasb.org/us-gaap/2023#LongTermDebtAndCapitalLeaseObligationshttp://fasb.org/us-gaap/2023#LongTermDebtAndCapitalLeaseObligations41.530.02407632.390792.30116P3YP3YP3YP1Y
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
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| ☒ | | |
x | | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Fiscal Year ended December 31, 2017.2023. |
| | |
o☐ | | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Transition period from to . |
Commission file No. 001-15891
NRG Energy, Inc.
(Exact name of registrant as specified in its charter)
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Delaware (State or other jurisdiction of incorporation or organization) | | 41-1724239 (I.R.S. Employer Identification No.) |
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804 Carnegie Center, Princeton, New Jersey910 Louisiana Street, Houston, Texas
(Address of principal executive offices) | | 08540 77002
(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:
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| Title of Each Class | Trading Symbol(s) | Name of Exchange on Which Registered |
| Common Stock, par value $0.01 | NRG | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act: None
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x☒ No o☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o☐ No x☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x☒ No o☐
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). Yes x☒ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o☐
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.
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| Large Accelerated Filer ☒ | | | | | | Accelerated filer | ☐ |
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Large accelerated filer x
| | Accelerated filer o
| | Non-accelerated filer o ☐ | | | | | |
Smaller reporting companyo | ☐ |
| | | | | (Do not check if a smaller reporting company) | Emerging growth companyo | ☐ |
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 has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C 7262(b)) by the registered public accounting firm that prepared or issued its audit report ☒
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o☐ No x☒
As of the last business day of the most recently completed second fiscal quarter, the aggregate market value of the common stock of the registrant held by non-affiliates was approximately $4,880,501,096$6,266,747,422 based on the closing sale price of $17.22$37.39 as reported on the New York Stock Exchange.
Indicate the number of shares outstanding of each of the registrant's classes of common stock as of the latest practicable date.
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| Class | | Outstanding at February 1, 2024 |
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Class | | Outstanding at January 31, 2018 |
| Common Stock, par value $0.01 per share | | 317,637,917208,021,012 |
Documents Incorporated by Reference:
Portions of the Registrant's definitive Proxy Statement relating to its 20182024 Annual Meeting of Stockholders
are incorporated by reference into Part III of this Annual Report on Form 10-K
TABLE OF CONTENTS
Glossary of Terms
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:
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| | |
| ACE | | Affordable Clean Energy |
| Acquisition | | The acquisition of Vivint Smart Home, Inc. by NRG completed on March 10, 2023 |
2023 Term Loan Facility | | The Company's $1.9 billion term loan facility due 2023, a component of the Senior Credit Facility |
AEP | | American Electric Power |
| Adjusted EBITDA | | Adjusted earnings before interest, taxes, depreciation and amortization |
AROAESO | | Alberta Electric System Operator |
| ARO | | Asset Retirement Obligation |
| ASC | | The FASB Accounting Standards Codification, which the FASB established as the source of authoritative GAAP |
ASUASR | | Accelerated Share Repurchases |
| ASU | | Accounting Standards Updates – updates to the ASC |
August 2017 Drop Down AssetsAUC | | The remaining 25% interest in NRG Wind TE Holdco, which was sold to NRG Yield, Inc. on August 1, 2017Alberta Utilities Commission |
| Average realized prices | | Volume-weighted average power prices, net of average fuel costs and reflecting the impact of settled hedges
| AZNMSNV | | Arizona, New Mexico and Southern Nevada
BacklogBTU | | Projects that are under construction, contracted, or awarded and represents a higher level of execution certainty |
BACT | | Best Available Control Technology |
Bankruptcy Code | | Chapter 11 of Title 11 of the U.S. Bankruptcy Code |
Bankruptcy Court | | United States Bankruptcy Court for the Southern District of Texas, Houston Division |
Baseload | | Units expected to satisfy minimum baseload requirements of the system and produce electricity at an essentially constant rate and run continuously |
BETM | | Boston Energy Trading and Marketing LLC |
BTU | | British Thermal Unit |
| Business | | NRG Business, Solutions | | NRG'swhich serves business solutions group, which includes demand response, commodity sales, energy efficiency and energy management servicescustomers |
| CAA | | Clean Air Act |
CAIRCAISO | | Clean Air Interstate Rule |
CAISO | | California Independent System Operator |
| Carlsbad | |
| | |
| CAMT | | Carlsbad Energy Center, a 527 MW natural gas fired project located in Carlsbad, CA15% Corporate Alternative Minimum Tax enacted by the IRA on August 16, 2022 |
CASPRCDD | | Competitive Auctions with Sponsored Resources |
CCF | | Carbon Capture Facility |
CDD | | Cooling Degree Day |
| CDWR | | California Department of Water Resources
| CEC | | California Energy Commission
CenterPointCFTC | | CenterPoint Energy Houston Electric, LLC |
CFTC | | U.S. Commodity Futures Trading Commission |
| Chapter 11 Cases | | Voluntary cases commenced by the GenOn Entities under the Bankruptcy Code in the Bankruptcy Court
C&ICO2 | | Commercial, industrial and governmental/institutional |
CES | | Clean Energy Standard |
Cleco | | Cleco Energy LLCCarbon Dioxide |
CO2e | | Carbon Dioxide |
CO2e
| | Carbon Dioxide Equivalents |
| COD | | Commercial Operation Date
ComEdCompany | | Commonwealth Edison |
Company | | NRG Energy, Inc. |
CPPConvertible Senior Notes | | As of December 31, 2023, consists of NRG’s $575 million unsecured 2.75% Convertible Senior Notes due 2048 |
| Cottonwood | | Cottonwood Generating Station, a 1,166 MW natural gas-fueled plant |
| CPP | | Clean Power Plan |
CPSCPUC | | Combined Pollutant Standard |
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CPUC | | California Public Utilities Commission |
CSAPRCWA | | Cross-State Air Pollution Rule |
CVSR | | California Valley Solar Ranch |
CWA | | Clean Water Act |
| D.C. Circuit | | U.S. Court of Appeals for the District of Columbia Circuit |
| DGPV Holdco 1 | | NRG DGPV Holdco 1 LLC
| DGPV Holdco 2 | | NRG DGPV Holdco 2 LLC
DGPV Holdco 3DSI | | NRG DGPV Holdco 3 LLC |
Distributed Solar | | Solar power projects that primarily sell power to customers for usage on site, or are interconnected to sell power into a local distribution grid |
DNREC | | Delaware Department of Natural Resources and Environmental Control |
Dominion | | Dominion Resources, Inc. |
Drop Down Assets | | Collectively, the June 2014 Drop Down Assets, the January 2015 Drop Down Assets, the November 2015 Drop Down Assets, the September 2016 Drop Down Assets, the March 2017 Drop Down Assets, the August 2017 Drop Down Assets, and the November 2017 Drop Down Assets |
DSI | | Dry Sorbent Injection |
| DSU | | Deferred Stock Unit |
| Dth | | Dekatherms |
| Dual fuel customers | | Customer that have both electricity and natural gas service with the Company |
| Economic gross margin | | Sum of retail revenue, energy revenue, capacity revenue, retail revenue and other revenue, less cost of fuels, purchased energy and other cost of sales |
El Segundo Energy CenterEGU | | NRG West Holdings LLC, the subsidiary of Natural Gas Repowering LLC, which owns the El Segundo Energy Center projectElectric Generating Unit |
| EME | | Edison Mission Energy
| EMAAC | | Eastern Mid-Atlantic Area Council
Energy Plus HoldingsEPA | | Energy Plus Holdings LLC |
EPA | | U.S. Environmental Protection Agency |
| EPC | | Engineering, Procurement and Construction |
EPSAERCOT | | The Electric Power Supply Association |
ERCOT | | Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas |
| ERISA | |
| ESP | | The Employee Retirement Income Security Act of 1974Electrostatic Precipitator |
ESPESPP | | Electrostatic Precipitator |
ESPP | | NRG Energy, Inc. Amended and Restated Employee Stock Purchase Plan |
| ESPS | | Existing Source Performance Standards
EWG | | Exempt Wholesale Generator |
| Exchange Act | | The Securities Exchange Act of 1934, as amended |
| FASB | | Financial Accounting Standards Board |
| FERC | | Federal Energy Regulatory Commission |
| FGD | | Flue gas desulfurization |
| FPA | | Federal Power Act |
Fresh Start | | Reporting requirements as defined by ASC-852, Reorganizations
|
FTRs | | Financial Transmission Rights |
GAAP | | Accounting principles generally accepted in the U.S. |
GenConn | | GenConn Energy LLC |
GenOn | | GenOn Energy, Inc. |
GenOn Americas Generation | | GenOn Americas Generation, LLC |
GenOn Americas Generation Senior Notes | | GenOn 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 2031 |
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| FTRs | | Financial Transmission Rights |
| GAAP | | Generally accepted accounting principles in the United States |
| GenOn Entities | |
| GHG | | GenOn and certain of its wholly owned subsidiaries, including GenOn Americas Generation, that filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court on June 14, 2017Greenhouse Gas |
| GenOn Mid-Atlantic | | GenOn Mid-Atlantic, LLC and, except where the context indicates otherwise, its subsidiaries, which include the coal generation units at two generating facilities under operating leases
GenOn Senior Notes | | GenOn'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 |
GHG | | Greenhouse Gas |
GIP | | Global Infrastructure Partners |
| Green Mountain Energy | | Green Mountain Energy Company |
| GW | | GigawattGigawatts |
| GWh | | Gigawatt HourHours |
| HAP | | Hazardous Air Pollutant
| HDD | | Heating Degree Day |
| Heat Rate | | A measure of thermal efficiency computed by dividing the total BTU content of the fuel burned by the resulting kWhs generated. Heat rates can be expressed as either gross or net heat rates, depending whether the electricity output measured is gross or net generation and is generally expressed as BTU per net kWh |
| HLBV | |
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| Home | | Hypothetical Liquidation at Book ValueNRG Home, which serves residential customers |
IASBICE | | International Accounting Standards BoardIntercontinental Exchange |
IFRSIoT | | International Financial Reporting StandardsInternet of Things |
IPAIRA | | Illinois Power AgencyInflation Reduction Act |
IPPNYISO | | Independent Power Producers of New York |
ISO | | Independent System Operator, also referred to as RTOs |
| ISO-NE | | ISO New England Inc. |
ITCIvanpah | | Investment Tax CreditIvanpah Solar Electric Generation Station, a 391 MW solar thermal power plant located in California's Mojave Desert in which NRG owns 54.5% interest |
| January 2015 Drop Down Assets | |
| kWh | | The Laredo Ridge, Tapestry and Walnut Creek projects, which were sold to NRG Yield, Inc. on January 2, 2015Kilowatt-hours |
June 2014 Drop Down AssetsLaGen | | The High Desert, Kansas South and El Segundo Energy Center projects, which were sold to NRG Yield, Inc. on June 30, 2014 |
kWh | | Kilowatt-hour |
LaGen | | Louisiana Generating LLC |
| LIBOR | | London Inter-Bank Offered Rate |
LSELSEs | | Load Serving Entities |
| LTIPs | | Collectively, the NRG LTIP and the NRG GenOnVivint LTIP |
| LTSA | |
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| MDth | | Long-Term Service AgreementThousand Dekatherms |
| MAAC | | Mid-Atlantic Area Council
March 2017 Drop Down Assets | | (i) 16% interest in the Agua Caliente solar project and (ii) NRG's interests in seven utility-scale solar projects located in Utah, which were sold to NRG Yield, Inc. on March 27, 2017 |
Marsh Landing | | NRG Marsh Landing, LLC (formerly known as GenOn Marsh Landing, LLC) |
Mass Market | | Residential and small commercial customers |
MATS | | Mercury and Air Toxics Standards promulgated by the EPA |
MDE | | Maryland Department of the Environment |
MDth | | Thousand Dekatherms |
Merger | | The merger completed on December 14, 2012 by NRG and GenOn pursuant to the Merger Agreement |
Merger Agreement | | The agreement by and among NRG, GenOn and Plus Merger Corporation, dated as of July 20, 2012 |
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| Midwest Generation | | Midwest Generation, LLC |
| MISO | | Midcontinent Independent System Operator, Inc. |
| MMBtu | | Million British Thermal Units |
MOPRMMDth | | Minimum Offer Price RuleMillion Dekatherms |
| MSU | |
| MW | | Market Stock UnitMegawatts |
| MW | | Megawatts
| MWh | | Saleable megawatt hour net of internal/parasitic load megawatt-hour |
MWtNAAQS | | Megawatts Thermal Equivalent |
NAAQS | | National Ambient Air Quality Standards |
NEPGANEPOOL | | New England Power Generators Association |
NEPOOL | | New England Power Pool |
| NERC | | North American Electric Reliability Corporation |
| NERC-CIP | | North American Electric Reliability Corporation Critical Infrastructure Protection |
| Net Capacity Factor | | The net amount of electricity that a generating unit produces over a period of time divided by the net amount of electricity it could have produced if it had run at full power over that time period. The net amount of electricity produced is the total amount of electricity generated minus the amount of electricity used during generation |
| Net Exposure | | Counterparty credit exposure to NRG, net of collateral |
| Net Generation | | The net amount of electricity produced, expressed in kWhs or MWhs, that is the total amount of electricity generated (gross) minus the amount of electricity used during generation |
| NJDEP | |
| NIST | | New Jersey DepartmentNational Institute of Environmental ProtectionStandards and Technology |
NOLNodal | | Nodal Exchange is a derivatives exchange |
| NOL | | Net Operating Loss |
NOV | | Notice of Violation |
November 2015 Drop Down Assets | | 75% of the Class B interests of NRG Wind TE Holdco, which owns a portfolio of 12 wind facilities totaling 814 net MW |
November 2017 Drop Down Assets | | A 38 MW solar portfolio primarily comprised of assets from SPP funds, in addition to other projects developed by NRG, which were sold to NRG Yield, Inc. on November 1, 2017 |
NOx | | Nitrogen Oxides |
NPDESNPNS | | National Pollutant Discharge Elimination System |
NPNS | | Normal Purchase Normal Sale |
| NQSO | | Non-Qualified Stock Option
| NRC | | U.S. Nuclear Regulatory Commission |
| NRG | | NRG Energy, Inc. |
| NRG GenOn LTIP | | NRG 2010 Stock Plan for GenOn Employees (formerly the GenOn Energy, Inc. 2010 Omnibus Incentive Plan, which was assumed by NRG in connection with the Merger)
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| NRG LTIP | | NRG Energy, Inc. Amended and Restated Long-Term Incentive Plan |
NRG Wind TE Holdco | | NRG Wind TE Holdco LLC |
NRG Yield | | Reporting 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 |
NRG Yield Operating 2024 Senior Notes | | NRG Yield Operating LLC's $500 million of 5.375% unsecured senior notes due 2024 |
NRG Yield Operating 2026 Senior Notes | | NRGY Yield Operating LLC's $350 million of 5.00% unsecured senior notes due 2026 |
NRG Yield LLC | | NRG Yield LLC, which owns, through its wholly owned subsidiary, NRG Yield Operating LLC, all of the assets set forth in the NRG Yield segment |
NSPS | | New Source Performance Standards |
NSR | | New Source Review |
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| Nuclear Decommissioning Trust Fund | | NRG's nuclear decommissioning trust fund assets, which arewere for the Company's portion of the decommissioning of the STP, units 1 & 2 through the sale of STP on November 1, 2023 |
Nuclear Waste Policy ActNYISO | | U.S. Nuclear Waste Policy Act of 1982 |
NYAG | | State of New York Office of Attorney General |
NYISO | | New York Independent System Operator |
| NYMEX | | New York Mercantile Exchange |
| NYSPSC | | New York State Public Service Commission
| OCI/OCL | | Other Comprehensive Income/(Loss) |
PeakingORDC | | Operating Reserve Demand Curve |
| ORDPA | | Online Reliability Deployment Price Adder |
| PCI DSS | | Payment Card Industry Data Security Standard |
| Peaking | | Units expected to satisfy demand requirements during the periods of greatest or peak load on the system |
PERPetra Nova | | Peak Energy RentPetra Nova Parish Holdings, LLC |
| Petition Date | | June 14, 2017
| Pipeline | | Projects that range from identified lead to shortlisted with an offtake, and represents a lower level of execution certainty
| PJM | | PJM Interconnection, LLC |
PPAPM2.5 | | Particulate Matter that has a diameter of less than 2.5 micrometers |
| PPA | | Power Purchase Agreement |
| PSD | | Prevention of Significant Deterioration
| PSU | | Performance Stock Unit
PTCPUCT | | Production Tax Credit |
PUCT | | Public Utility Commission of Texas |
PUHCARCRA | | Public Utility Holding Company Act of 2005 |
PURPA | | Public Utility Regulatory Policies Act of 1978 |
QF | | Qualifying Facility under PURPA |
RCRA | | Resource Conservation and Recovery Act of 1976 |
Reliant EnergyReceivables Facility | | Reliant Energy Retail Services, LLC |
REMA | | NRG REMAReceivables LLC, a bankruptcy remote, special purpose, wholly-owned indirect subsidiary of the Company's $1.4 billion accounts receivables securitization facility due 2024, 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 |
Restructuring Support Agreement | | Restructuring Support and Lock-Up Agreement, dated as of June 12, 2017 and aswas last amended on October 2, 2017, by and among GenOn Energy, Inc., GenOn Americas Generation, LLC, and subsidiaries signatory thereto, NRG Energy, Inc.6, 2023 |
| Receivables Securitization Facilities | | Collectively, the Receivables Facility and the noteholders signatory theretoRepurchase Facility |
RetailRECs | | Reporting segment that includes NRG's residential and small commercial businesses which go to market as Reliant, NRG and other brands owned by NRG, as well as Business SolutionsRenewable Energy Certificates |
| Renewable PPA | | A third-party PPA entered into directly with a renewable generation facility for the offtake of the RECs or other similar environmental attributes generated by such facility, coupled with the associated power generated by that facility |
| Renewables | | Consists of the following projects in which NRG has an ownership interest: Ivanpah and solar generating stations located at various NFL Stadiums |
| Renewables Platform | | The renewable operating and development platform sold to Global Infrastructure Partners with NRG's interest in NRG Yield |
| REP | | Retail electric provider |
| Repurchase Facility | | NRG's $150 million uncommitted repurchase facility related to the Receivables Facility due 2024, which was last amended on October 6, 2023 |
| 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, which was last modified on March 13, 2023 |
RFPRGGI | | Request For Proposal |
RGGI | | Regional Greenhouse Gas Initiative |
| RMR | | Reliability Must-Run |
ROFORPS | | Right of First Offer |
ROFO Agreement | | Second Amended and Restated Right of First Offer Agreement by and between NRG Energy, Inc. and NRG Yield, Inc. |
RPM | | Reliability Pricing Model |
RPS | | Renewable Portfolio Standards |
| RPSU | | Relative Performance Stock Unit |
RPV HoldcoRSU | | NRG RPV Holdco 1 LLC |
RSU | | Restricted Stock Unit |
| RTO | | Regional Transmission Organization |
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| SCR | | |
RTR | | Renewable Technology Resource |
SCE | | Southern California Edison Company |
SCR | | Selective Catalytic Reduction Control System |
SDG&ESEC | | San Diego Gas & Electric |
SEC | | U.S. Securities and Exchange Commission |
| Securities Act | | The Securities Act of 1933, as amended |
Senior Credit Facility | | NRG's senior secured credit facility, comprised of the Revolving Credit Facility and the 2023 Term Loan Facility
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 with the 2016 Senior Credit Facility
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| Senior Notes | | As of December 31, 2017,2023, NRG's $4.8$4.0 billion outstanding unsecured senior notes consisting of $992$375 million of 6.25% senior notes due 2022, $733 million of 6.25% senior notes due 2024, $1.0 billion of the 7.25% senior notes due 2026, $1.25 billion of the 6.625% senior notes due 2027, and $870$821 million of 5.75% senior notes due 2028, $733 million of the 5.25% senior notes due 2029, $500 million of the 3.375% senior notes due 2029, $1.0 billion of the 3.625% senior notes due 2031 and $480 million of the 3.875% senior notes due 2032 |
| | | | | | | | |
| Senior Secured First Lien Notes | | As of December 31, 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 |
| Series A Preferred Stock | | As of December 31, 2023, NRG's Series A Preferred Stock consists of 650,000 outstanding shares of the 10.25% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock, with a $1,000 liquidation preference per share |
| Services | | NRG Services, Agreement | | NRG provided 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 GenOn |
Settlement Agreement | | A settlement agreementDirect Energy acquisition and any other documents necessary to effectuate the settlement among NRG, GenOn, and certain holders of senior unsecured notes of GenOn Americas Generations and GenOn, and certain of GenOn's direct and indirect subsidiaries |
September 2016 Drop Down Assets | | The CVSR Holdco interest, which was sold to NRG Yield, Inc. on September 1, 2016 |
SIFMA | | Securities Industry and Financial Markets Association |
SNF | | Spent Nuclear FuelGoal Zero business |
SO2 | | Sulfur Dioxide |
| SOFR | | Secured overnight financing rate |
| South Central Portfolio | | NRG's South Central business,Portfolio, which ownsowned and operatesoperated a 3,555 MW portfolio of generation assets consisting of 225 MW Bayou Cove, 430 MW Big Cajun-I, 1,461 MW Big Cajun-II, 1,263 MW Cottonwood and 176 MW Sterlington, and serves a customer base of cooperatives, municipalities and regional utilities under load contracts. was sold on February 4, 2019. NRG is leasing back the Cottonwood facility through May 2025 |
SPPS&P | | Solar Power Partners |
S&P | | Standard & Poor's |
| STP | | South Texas Project — nuclear generating facility located near Bay City, Texas in which NRG ownsowned a 44% interest. NRG closed on the sale of its interest in STP on November 1, 2023 |
| STPNOC | | South Texas Project Nuclear Operating Company |
| Tax Act | | The Tax Cuts and Jobs Act of 2017 |
TCPATDSP | | Telephone Consumer Protection ActTransmission/distribution service provider |
Term Loan Facility | | Prior to June 30, 2016, the Company's $2.0 billion term loan facility due 2018. |
| Texas Genco | | Texas Genco LLC |
Thermal BusinessTSR | | NRG Yield, Inc.’s thermal business, which consists of thermal infrastructure assets that provide steam, hot water and/or chilled water, and in some instances electricity, to commercial businesses, universities, hospitals and governmental units |
TSA | | Transportation Services Agreement |
TSR | | Total Shareholder Return |
| TVA | |
| TWh | | Tennessee Valley AuthorityTerawatt Hours |
TWCCU.S. | | Texas Westmoreland Coal Co. |
TWh | | Terawatt Hour |
UNFCCC | | United Nations Framework Convention on Climate Change |
UPMC | | University of Pittsburgh Medical Center |
U.S. | | United States of America |
U.S. DOEVaR | | Value at Risk |
| | |
| VIE | | U.S. DepartmentVariable Interest Entity |
| Vivint LTIP | | Vivint Smart Home, Inc. Long-Term Incentive Plan assumed by NRG pursuant to merger between NRG and Vivint |
| Winter Storm Elliott | | A major winter storm that had impacts across the majority of Energythe United States and parts of Canada occurring in December 2022 |
| Winter Storm Uri | | A major winter and ice storm that had widespread impacts across North America occurring in February 2021 |
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| | |
Utility-Scale Solar | | Solar power projects, typically 20 MW or greater in size (on an alternating current basis), that are interconnected into the transmission or distribution grid to sell power at a wholesale level |
VaR | | Value at Risk |
VCP | | Voluntary Clean-Up Program |
VIE | | Variable Interest Entity |
WECC | | Western Electricity Coordinating Council |
WST | | Washington-St. Tammany Electric Cooperative, Inc. |
Yield Operating | | NRG Yield Operating LLC |
PART I
Item 1 — Business
General
NRG Energy, Inc., or NRG or the Company, sits at the intersection of energy and home services. NRG is a leading integrated powerenergy and home services company built onfueled by market-leading brands, proprietary technologies and complementary sales channels. Across the strengthU.S. and Canada, NRG delivers innovative, sustainable solutions, predominately under brand names such as NRG, Reliant, Direct Energy, Green Mountain Energy and Vivint, while also advocating for competitive energy markets and customer choice. The Company has a customer base that includes approximately 8 million residential consumers in addition to commercial, industrial, and wholesale customers, supported by approximately 13 GW of a diverse competitive electric generation portfolio and leading retail electricity platform. as of December 31, 2023.
NRG aims to create a sustainable energy future by producing, selling and deliveringsold 152 TWhs of electricity and related products and services1,892 MMDth of natural gas in major2023, making it one of the largest competitive power marketsenergy retailers in the U.S. As of the end of 2023, NRG had recurring electricity and/or natural gas sales in a manner that delivers value to25 U.S. states, the District of Columbia, and 8 provinces in Canada, as well as Vivint served customers in all 50 U.S. states. NRG's retail brands, collectively, have the largest share of competitively served residential electric customers in Texas and nationwide.
The following chart represents NRG's stakeholders. The Company owns and operates approximately 30,000 MW of generation; engages insales volumes for 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" and other retail brand names owned by NRG. NRG was incorporated as a Delaware corporation on May 29, 1992.year ended December 31, 2023:
Strategy
NRG's strategy is to maximize stockholderstakeholder value throughby being a leader in the safe productionemerging convergence of energy and sale ofsmart automation in the home and business. Through a diversified supply strategy, the Company sells reliable powerelectricity and natural gas to its customers in the markets served by the Company,it serves, while positioningalso providing innovative home solutions to customers. NRG's unique combination of assets and capabilities enables the Company to provide fullydevelop and sell highly differentiated offerings that bring together every day essential services like powering and securing the home through a seamless and integrated solutions to the end-use energy consumer.experience. This strategy is intended to enable the Company to createoptimize its unique integrated platform to delight customers, generate recurring cash flow, significantly strengthen earnings and maintain growth at reasonable margins while de-risking the Company in terms of reducedcost competitiveness, and mitigated exposure to cyclical commodity price risk. At the same time, the Company's relentless commitment to safetylower risk and volatility. Sustainability is a philosophy that underpins and facilitates value creation across NRG's business for its employees, customersstakeholders. It is an integral piece of NRG's strategy and partners continues unabated.ties directly to business success, reduced risks and enhanced reputation.
To effectuate the Company’s strategy, NRG is focused on: (i) excellence in operating performance of its existing assets including repowering its power generation assets at premium sites and optimal hedging of generation assets and retail load operations; (ii) serving the energy needs of end-use residential, commercial and industrial, customersand wholesale counterparties in competitive markets and optimizing on additional revenue opportunities through its multiple brands and channels withchannels; (ii) offering a variety of retail energy products and services, including renewable energy solutions and smart home products and services that are differentiated by innovative features, premium service, integrated platforms, sustainability and loyalty/affinity programs; (iii) deploying innovativeexcellence in operating performance of its assets; (iv) achieving the optimal mix of supply to serve its customer load requirements through a diversified supply strategy; and renewable energy solutions for consumers within its retail businesses; and (iv)(v) engaging in disciplined and transparent capital allocation.
The following transactions were completed during 2023 in furtherance of the Company’s strategy: (i) the March 10, 2023 acquisition of Vivint Smart Home, a proactiveleading smart home platform company; (ii) portfolio optimization, including the sale of the Company’s 44% equity interest in STP for $1.7 billion; and (iii) disciplined capital allocation plan focused on achievingthrough the regular returnexecution of $1.2 billion in share repurchases and on stockholder capital within the dictates of prudent balance sheet management, including reducing consolidated$1.4 billion in debt and pursuing selective acquisitions, joint ventures, divestitures and investments.
Transformation Plan
NRG is in the process of executing its Transformation Plan, which is designed to significantly strengthen earnings and cost competitiveness, lower risk and volatility, and create significant shareholder value. The Company expects to fully implement the Transformation Plan by the end of 2020 with significant completion by the end of 2018. The three-part, three-year plan is comprised of the following targets and the Company's progress toward achieving such targets are as follows:
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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. |
• During the year ended December 31, 2017, the Company realized annual cost savings of $150 million.
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Portfolio optimization | | |
Targeting up to $3.2 billion of asset sale 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. |
• On February 6, 2018, NRG announced agreements to sell (i) NRG's full ownership interest in NRG Yield, Inc. and NRG's renewables platform, a 3,440 MW portfolio, for cash of $1.375 billion, subject to certain adjustments; and (ii) NRG's South Central business, a 3,555 MW portfolio of generation assets, for cash of $1.0 billion, subject to certain adjustments. The transactions are subject to customary closing conditions and are expected to close in the second half of 2018.
• Also on February 6, 2018, NRG entered into agreements with NRG Yield, Inc. to sell Carlsbad Energy Center, a 527 MW natural gas fired project, for cash of $365 million, subject to certain adjustments, and Buckthorn Solar, a 154 MW solar facility, for cash of $42 million, subject to certain adjustments.
• On February 23, 2018, NRG entered into an agreement to sell BETM for $70 million. The transaction is subject to customary closing conditions and is expected to close in the second half of 2018.
• In 2017, NRG executed asset sales of 322 MW for aggregate cash of $150 million, which includes sales to NRG Yield, Inc. and sale of Minnesota wind projects to third parties.
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Capital structure and allocation enhancement | | |
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 approximately $5.3 billion in excess cash to be available for allocation through 2020, after achieving its targeted 3.0x net debt / Adjusted EBITDA corporate credit ratio. |
• During 2017, NRG reduced its net corporate debt by $604 million.
• Expected reduction in non-recourse debt related to the sale of NRG's ownership in NRG Yield, Inc. and the NRG renewables platform and the sales of Carlsbad Energy Center and Buckthorn Solar, which represented $7.1 billion as of December 31, 2017.
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Working Capital and Costs to Achieve | | |
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. |
• During 2017, NRG realized $221 million of working capital improvements and $44 million of one-time costs to achieve. |
reduction.
Business Overview
As of December 31, 2017, theThe Company’s core businesses include (i)are the sale of electricity and natural gas to residential, commercial and industrial and wholesale conventionalcustomers, supported by the Company's wholesale electric generation, (ii)as well as the sale of smart home products and services. NRG manages its electricity and natural gas operations based on the combined results of the retail electricity for residential and commercial, including personal power solutions and Business Solutions,wholesale generation businesses with a geographical focus. Vivint Smart Home operations are reported within the Vivint Smart Home segment.
The Company's business is segmented as follows:
•Texas, which includes C&I customersall activity related to customer, plant and market operations in Texas, other than Cottonwood;
•East, which includes all activity related to customer, plant and market operations in the East;
•West/Services/Other, which primarily includes the following assets and activities: (i) all activity related to customer, plant and market operations in the West and Canada, (ii) the Services businesses, (iii) activity related to the Cottonwood facility and other distributedinvestments;
•Vivint Smart Home; and reliability products (included in
•Corporate activities.
In Texas, the Retail segment, effective in January 2017), (iii) contractedCompany’s generation owned by NRG Yield, Inc. (included insupply is fully integrated with its retail load. This integrated model provides the NRG Yield segment) and (iv) renewable utility scale and distributed generation assets that are constructed or in development and that are not otherwise owned by NRG Yield, Inc. (included in the Renewables segment). On June 14, 2017, NRG deconsolidated GenOn for financial reporting purposes asadvantage of being able to supply a resultportion of the GenOn bankruptcy filings.
GenerationCompany’s retail customers with electricity from the Company’s assets, which reduces the need to sell electricity to, and buy electricity from, other institutions and intermediaries, resulting in more stable earnings and cash flows, lower transaction costs and less credit exposure. The integrated model also results in a reduction in actual and contingent collateral through offsetting transactions, thereby reducing transactions with third parties.
The Company’s wholesale power generation businessintegrated model consists of three core functions in each geographic segment above: Customer Operations, Market Operations and Plant Operations.
Customer Operations
Customer Operations is responsible for growing and retaining the customer base and delivering an outstanding customer experience. This includes plant operations,acquisition and retention of all of NRG’s residential, small commercial, operations, EPC, energycommercial and industrial, and government customers. NRG employs a multi-brand strategy that leverages a wide array of sales and partnership channels, direct face-to-face sales channels, call centers, websites, and brokers. Go-to-market activities include market strategy planning and development, product innovation, offer design, campaign execution, marketing and creative services, and other critical related functions. In addition to the traditional functions, the wholesale power generation business also includes NRG’s conventional distributed generation business, consisting of reliability, combined heatselling. Customer portfolio maintenance and powerretention activities include fulfillment, billing, payment processing, collections, customer service, issue resolution, and large-scale distributed generation.
The wholesale generation business is capital-intensive and commodity-driven with numerous industry participants that compete on the basis of the location of their plants, fuel mix, plant efficiency and the reliability of the services offered. The Company has a diversified power generation portfolio, with approximately 28,000 MW of fossil fuel and nuclear generation capacity at 51 plants as of December 31, 2017. The Company's power generation assets are diversified by fuel-type, dispatch level and region, which helps mitigate the risks associated with fuel price volatility and market demand cycles. NRG's U.S. baseload and intermediate facilities provide the Company with a significant source of cash flow, while its peaking facilities providecontract renewals. NRG with opportunities to capture significant upside potential that can arise during periods of high demand, which typically drive higher energy prices. As of December 31, 2017, less than 25% of the Company's consolidated operating revenues were derived from coal-fired operating assets. As noted above, the Company expects to sell its 3,555 MW South Central business in the second half of 2018.
Wholesale power generation is a regional business that is currently highly fragmented and diverse in terms of industry structure. As such, there is a wide variation in terms of the capabilities, resources, nature and identities of the companies the Company competes with depending on the market. Competitors include regulated utilities, municipalities, cooperatives, other independent power producers, and power marketers or trading companies, including those owned by financial institutions. Many of the Company's generation assets, however, are located within densely populated areas that tend to have higher wholesale pricing as a result of relatively favorable local supply-demand balance. The Company has generation assets located in or near major metropolitan areas. The Company believes that its extensive generation portfolio provides asset optimization opportunities. The Company currently has over 500 MW targeted for repowering initiatives, all of which are under development or construction. In addition, the Company evaluates opportunities for new generation, on both a merchant and contracted basis.
Retail
Retail provides energy and related services at either fixed, indexed or month-to-month prices. Home customers typically contract for terms ranging from one month to residential, industrialfive years, while Business contracts are often between one year and commercial consumers through variousfive years in length. Throughout all Customer Operations activities, the customer experience is kept at the forefront to inform decision-making and optimize retention, while creating supporters and advocates for NRG’s brands and sales channels across the U.S. In 2017, Retail delivered approximately 63 TWhs and served approximately 2.9 million customers. Retail's results make it one of the largest competitive energy retailers in the U.S. The majoritymarket. Customer Operations comprises three end-use customer facing teams: NRG Home, which serves residential customers, NRG Business, which serves business customers, and NRG Services, which primarily includes the Services businesses.
Product Offerings
NRG sells a variety of Retail's sales come in the competitive retail energy markets of Texas, Pennsylvania, Connecticut, Delaware, Illinois, Maryland, Massachusetts, New Jersey, New York and Ohio, as well as the District of Columbia. Retail's brands collectively are the largest providers of electricity in Texas.
Residentialproducts to residential and small commercial (Mass Market) consumerscustomers, including retail electricity and energy management, natural gas, line and surge protection products, HVAC installation, repair and maintenance, home protection products, carbon offsets, back-up power stations, portable power, portable solar and portable lighting. Home and Services customers make purchase decisions based on a variety of factors, including price, incentive, customer service, brand, product choicesinnovative offers/features and value-added features. These consumers purchase products through a variety of sales channels, including direct sales, call centers, websites, brokersreferrals from friends and brick-and-mortar stores.family. Through its broad range of service offerings and value propositions, Retail is ableNRG seeks to attract, retain, and increase the value of its customer relationships. Retail'sNRG's brands are recognized for exemplary customer service, innovative smart energy and technology product offerings, and environmentally friendlyenvironmentally-friendly solutions.
IncludedThe Company provides power and natural gas to the business-to-business markets in Retail is the Company's Business Solutions group, which includesNorth America, as well as retail services, including demand response, commodity sales, energy efficiency and energy management solutions. Ansolutions to Business customers. The Company is an integrated provider of supply and distributed energy resources Business Solutionsand focuses on distributed products and services as businesses seek greater reliability, cleaner power orand other benefits that they cannot obtain from the grid. These solutions include system power, distributed generation, solarrenewable and windlow-carbon products, carbon management
and specialty services, backup generation, storage and distributed solar, demand response, and energy efficiency and advisory services. In providing on-site energy solutions, the Company often benefits from its ability
Market Operations
Market Operations has two primary objectives: to supply energy products from its wholesale generation portfolio to commercial and industrial retail customers. In 2017, Business Solutions delivered approximately 21 TWhs of electricity and managed approximately 1,500 MWs of demand response positions across its portfolio.
Renewables and NRG Yield
As described above, NRG expects to sell its Renewables operating and development platform and its full ownership interest in NRG Yield, Inc.customers in the second half of 2018. The following description reflects the historical view of these businesses as a part of NRG’s business strategy through its announcement of the Transformation Plan in 2017.
Renewables
The Company’s renewables business focuses on the acquisition, developmentmost cost-efficient manner and operation and maintenance of utility scale wind and solar, community solar and distributed solar generation assets as well as the management and operations of the renewable generation assets owned by NRG Yield, Inc. In 2017, the Company acquired 209 MW of utility scale solar and wind projects and 82 MW of distributed generation and community solar projects that are currently under development or in operation across three states. The renewables business has in-house expertise that covers the full spectrum of development capabilities to execute on utility, distributed generation, and community solar projects. The asset management and operations and maintenance groups within the renewables business manage a portfolio of wind and solar assets across 27 states, serving as the primary commercial asset manager on the vast majority of assets owned by NRG and NRG Yield, Inc. In addition, the operations and maintenance group self-performs plant operations on 2,689 MW of the consolidated fleet of assets owned by NRG and NRG Yield, Inc. and 224 MW of assets owned by third parties.
The utility wind and solar generation business targets strategic partnerships with utilities, municipalities and large national corporations for offsite wind and solar solutions. The distributed solar business targets partnerships with companies, municipalities, schools and communities to provide on-site and virtual net metering off-site renewable generation. The community solar business targets relationships with companies and municipalities as well as residential homeowners to provide off-site solar generation under community solar regulations and tariffs. In addition to assets in operation, as of December 31, 2017, the Company held a backlog of in-construction, contracted and awarded projects of 1,500 MW, and a pipeline of 5,742 MW across the utility, community solar and distributed solar renewables markets.
The renewables business also competes for new generation opportunities through both RFPs and bilateral solicitations. The renewables business selects markets and projects based on resource relative tomaximize the value of the Company's assets in satisfying its customer load requirements. These objectives are intended to reduce supply costs and maximize earnings with predictable cash flows.
Power and natural gas are the two main commercial groups within Market Operations.
Power
The power while seeking to make use of NRG capabilities in a competitive landscape. The number and type of competitors vary based on location, generation type, project size and counterparty. The renewables business competes with traditional utilities as well as companies that provide products and services in the downstream solar and wind energy value chains.
NRG Yield
NRG Yield, Inc.commercial group is a publicly-traded, dividend growth-oriented company that has historically served as the primary vehicle through which NRG owns, operates and acquires diversified contracted renewable and conventional generation and thermal infrastructure assets. As of December 31, 2017, NRG owns a 55.1% voting interest in the outstanding common stock of NRG Yield, Inc. and receives distributions from NRG Yield LLC through its 46.3% ownership of Class B and Class D units. NRG Yield, Inc.’s contracted generation portfolio collectively represents 5,118 net MW as of December 31, 2017. Each of the assets sells most of its output pursuant to long-term, fixed-price offtake agreements with creditworthy counterparties. NRG Yield, Inc. also owns thermal infrastructure assets with an aggregate steam and chilled water capacity of 1,319 net MWt and electric generation capacity of 123 net MW. These thermal infrastructure assets provide steam, hot water and/or chilled water, and in some instancesresponsible for end-use electricity to commercial businesses, universities, hospitals and governmental units in multiple locations, principally through long-term contracts or pursuant to rates regulated by state utility commissions.
GenOn Chapter 11 Cases
As disclosed in Item 15 - Note 1, Nature of Business, to the Consolidated Financial Statements, on June 14, 2017, or the Petition Date, GenOn, along with GenOn Americas Generationsupply including power plant optimization and certain of their directly and indirectly-owned subsidiaries, or collectivelyfuel supply. To meet 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 has 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, which is included within the total loss from discontinuedmarket operations of $789 million for the year ended December 31, 2017. See Note 3, Discontinued Operations, Acquisitions and Dispositions, for more information. In addition, upon GenOn's emergence from bankruptcy, the Company will recognize an estimated $9.5 billion worthless stock deduction for tax purposes.
On June 29, 2017, the GenOn Entities filed the initial plan of reorganization and the disclosure statement with the Bankruptcy Court consistent with the Restructuring Support Agreement. On September 18, 2017 and October 2, 2017, the GenOn Entities filed amendments to the plan of reorganization and the disclosure statement which primarily provided the GenOn Entities with the flexibility to complete sales of certain assets pursuant to the amended plan of reorganization and removed the GenOn Entities' requirement to conduct a rights offering in connection with the GenOn Entities' exit financing.
On October 31, 2017, the GenOn Entities announced that they entered into a Consent Agreement with certain holders of GenOn’s Senior Notes and GenOn Americas Generation's Senior Notes, collectively, the Consenting Holders, whereby the GenOn Entities and the Consenting Holders agreed to extend the milestones in the Restructuring Support Agreement, by which the plan of reorganization must become effective, or the Effective Date. Specifically, the Consent Agreement extended the Effective Date milestone to June 30, 2018 or September 30, 2018, if regulatory approvals are still pending, or the Extended Effective Dates.
On December 12, 2017, the Bankruptcy Court entered an order confirming the plan of reorganization, and effective December 12, 2017, GenOn and NRG entered into agreements concerning (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, consistent with the Restructuring Support Agreement, which among other things, provide for the transition of GenOn to a standalone enterprise, resolution of substantial intercompany claims between GenOn and NRG, and the allocation of certain costs and liabilities between GenOn and NRG. The principal terms of these agreements are described further in Note 3, Discontinued Operations, Acquisitions and Dispositions. On December 12, 2017, the Bankruptcy Court also entered an order giving effect to the Consent Agreement.
NRG Operations
The NRG businesses described above are supported through the NRG operational infrastructure, which begins with the Company’s asset fleet and the associated commercial and retail operations. The images below illustrate NRG's U.S. power generation, net capacity and retail capabilities as of December 31, 2017:
The following table summarizes NRG's global generation portfolio as of December 31, 2017:
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| | | Global Generation Portfolio(a)(b) |
| | | (In MW) |
| | | Generation | | | | | | | | |
| Generation Type | | Gulf Coast(j) | | East/West (c) | | Renewables (d)(k) | | NRG Yield (e)(k) | | Other(f)(k) | | Total Global |
Natural gas(g) | | 7,464 |
| | 4,939 |
| | — |
| | 1,878 |
| | — |
| | 14,281 |
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| Coal | | 5,114 |
| | 3,870 |
| | — |
| | — |
| | — |
| | 8,984 |
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| Oil | | — |
| | 3,642 |
| | — |
| | 190 |
| | — |
| | 3,832 |
|
| Nuclear | | 1,136 |
| | — |
| | — |
| | — |
| | — |
| | 1,136 |
|
Wind(h) | | — |
| | — |
| | 648 |
| | 2,206 |
| | — |
| | 2,854 |
|
| Utility Scale Solar | | — |
| | — |
| | 738 |
| | 921 |
| | — |
| | 1,659 |
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| Distributed Solar | | — |
| | — |
| | 179 |
| | 52 |
| | 114 |
| | 345 |
|
Total generation capacity(i) | | 13,714 |
| | 12,451 |
| | 1,565 |
| | 5,247 |
| | 114 |
| | 33,091 |
|
Capacity attributable to noncontrolling interest(i) | | — |
| | — |
| | (685 | ) | | (2,359 | ) | | — |
| | (3,044 | ) |
| Total net generation capacity | | 13,714 |
| | 12,451 |
| | 880 |
| | 2,888 |
| | 114 |
| | 30,047 |
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(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.
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(b) | GenOn, which represented 16,423 MW of global generation at December 31, 2016, was deconsolidated from NRG for financial reporting purposes on June 14, 2017. |
(c) Includes International.
(d) Includes Distributed Solar capacity from assets held by DGPV Holdco 1, DGPV Holdco 2 and DGPV Holdco 3.
(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, 106 MW related to Encina Unit 1 which was deactivated on March 31, 2017 and 371 MWs related to Greens Bayou 5 which was mothballed on May 29, 2017 following ERCOT's termination of the RMR agreement. Greens Bayou 5 was retired in January 2018.
(h) In 2017 and 2018, NRG sold 111 and 10 MWs, respectively, to third parties related to certain Minnesota wind assets.
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(i) | 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 5,241 MWs. |
(j) On February 6, 2018, NRG announced the sale of its South Central business, which owns and operates a 3,555 MW portfolio of generation assets in Gulf Coast. NRG will lease back the 1,263 MW Cottonwood facility.
(k) On February 6, 2018, NRG announced the sale of its full ownership in NRG Yield, Inc. and its Renewables operating and development platform, which represents 3,440 MW.
NRG's portfolio diversification and commercial operations hedging strategy provides the Company with reliable future cash flows. NRG has hedged a portion of its coal and nuclear capacity with decreasing hedge levels through 2021. In addition, NRG's capacity revenues not only enhance the reliability of future cash flows but are not correlated to natural gas prices. As of December 31, 2017, the Company had purchased fuel forward under fixed price contracts, with contractually-specified price escalators, for approximately 41% of its expected coal requirement from 2018 to 2021. The Company enters into additional hedges when it believes market conditions are favorable.
The Company also has the advantage of being able to supply its retail businesses with its own generation, which can reduce the need to sell and buy power from other institutions and intermediaries, resulting in lower transaction costs and credit exposures. This combination of generation and retail allows for a reduction in actual and contingent collateral, through offsetting transactions and by reducing the need to hedge the retail power supply through third parties.
The generation and retail combination also provides stability in cash flows, as changes in commodity prices generally have offsetting impacts between the two businesses. The offsetting nature of generation and retail, in relation to changes in market prices, is an integral part of NRG's goal of providing a reliable source of future cash flow for the Company.
When developing new renewable and conventional power generation facilities, NRG typically secures long-term PPAs, which insulate the Company from commodity market volatility and provide future cash flow stability. These PPAs are typically contracted with high credit quality local utilities and typically have durations from 10 years to as much as 25 years.
Commercial Operations Overview
NRG seeks to maximize profitability and manage cash flow volatility through the marketing, trading and sale of energy, capacity and ancillary services into spot, intermediate and long-term markets and through the active management and trading of emissions allowances, fuel supplies and transportation-related services. The Company's principal objectives, are the realization of the full market value of its asset base, including the capture of its extrinsic value, the management and mitigation of commodity market risk and the reduction of cash flow volatility over time.
NRG enters into supply, power sales and gas hedging arrangementsagreements via a wide range of products and contracts, including PPAs,(i) physical and financial commodity instruments, (ii) fuel supply and transportation contracts, (iii) PPAs and Renewable PPAs and (iv) capacity auctions, natural gas derivative instruments and other financial instruments. contracted revenue or supply sources, as further discussed below.
In addition, because changes in power prices in the markets where NRG operates are generally correlated to changes in natural gas prices, NRG uses hedging strategies that may include power and natural gas forward purchases and sales contracts to manage the commodity price risk primarily associated with the Company's coalrisk.
Physical and nuclear generation assets. The objective of these hedging strategies is to stabilize the cash flow generated by NRG's portfolio of assets.Financial Commodity Instruments
In addition to power sales and hedging arrangements, NRG trades electric power, natural gas, environmental, weather and related commodityother physical and financial commodity related products, including forwards, futures, options and swaps. The Company seeksNRG enters into these instruments primarily to generate profits from volatilitymanage price and delivery risk, optimize physical and contractual assets in the price of electricity, capacity, fuelsportfolio, manage working capital requirements, reduce the carbon exposure in its business and transmission congestion by buyingto comply with laws and selling contracts in wholesale markets under guidelines approved by the Company's risk management committee.
Coal and Nuclear Operations
The following table summarizes NRG's U.S. coal and nuclear capacity and the corresponding revenues and average natural gas prices and positions resulting from coal and nuclear hedge agreements extending beyond December 31, 2017, and through 2021 for the Company's Gulf Coast region:
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| Gulf Coast | | 2018 | | 2019 | | 2020 | | 2021 | | Annual Average for 2018-2021 |
| | | (Dollars in millions unless otherwise stated) |
Net Coal and Nuclear Capacity (MW) (a) | | 6,250 |
| | 6,250 |
| | 6,250 |
| | 6,250 |
| | 6,250 |
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Forecasted Coal and Nuclear Capacity (MW) (b) | | 4,558 |
| | 4,402 |
| | 4,303 |
| | 4,114 |
| | 4,344 |
|
Total Coal and Nuclear Sales (GWh) (c) | | 33,394 |
| | 8,203 |
| | 7,348 |
| | 7,977 |
| | 14,231 |
|
Percentage Coal and Nuclear Capacity Sold Forward (d) | | 84 | % | | 21 | % | | 19 | % | | 22 | % | | 37 | % |
Total Forward Hedged Revenues (e) | | $ | 1,399 |
| | $ | 422 |
| | $ | 399 |
| | $ | 429 |
| | $ | — |
|
Weighted Average Hedged Price ($ per MWh) (e) | | $ | 41.90 |
| | $ | 51.47 |
| | $ | 54.36 |
| | $ | 53.74 |
| | $ | — |
|
Average Equivalent Natural Gas Price ($ per MMBtu) (e) | | $ | 3.17 |
| | $ | 4.47 |
| | $ | 4.79 |
| | $ | 5.01 |
| | $ | — |
|
| Gross Margin Sensitivities | | | | | | | | | | |
| Gas Price Sensitivity Up $0.50/MMBtu on Coal and Nuclear Units | | $ | 5 |
| | $ | 134 |
| | $ | 136 |
| | $ | 138 |
| | $ | — |
|
| Gas Price Sensitivity Down $0.50/MMBtu on Coal and Nuclear Units | | $ | — |
| | $ | (150 | ) | | $ | (148 | ) | | $ | (126 | ) | | $ | — |
|
| Heat Rate Sensitivity Up 1 MMBtu/MWh on Coal and Nuclear Units | | $ | 57 |
| | $ | 90 |
| | $ | 94 |
| | $ | 96 |
| | $ | — |
|
| Heat Rate Sensitivity Down 1 MMBtu/MWh on Coal and Nuclear Units | | $ | (38 | ) | | $ | (74 | ) | | $ | (78 | ) | | $ | (79 | ) | | $ | — |
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(a) | Net coal and nuclear capacity represents nominal summer net MW capacity of power generated as adjusted for the Company's current ownership position excluding capacity from inactive/mothballed units, see Item 2 - Properties for units scheduled to be deactivated.
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(b) | Forecasted generation dispatch output (MWh) based on forward price curves as of December 31, 2017, which is then divided by number of hours in a given year to arrive at MW capacity. The dispatch takes into account planned and unplanned outage assumptions. |
| |
(c) | Includes amounts under power sales contracts and natural gas hedges. The forward natural gas quantities are reflected in equivalent GWh based on forward market implied heat rate as of December 31, 2017, and then combined with power sales to arrive at equivalent GWh hedged. The coal and nuclear sales include swaps and delta of options sold which is subject to change. For detailed information on the Company's hedging methodology through use of derivative instruments, see discussion in Item 15 - Note 5, Accounting for Derivative Instruments and Hedging Activities, to the Consolidated Financial Statements. Includes inter-segment sales from the Company's wholesale power generation business to the retail business.
|
| |
(d) | Percentage hedged is based on total coal and nuclear sales as described in (c) above divided by the forecasted coal and nuclear capacity. |
| |
(e) | Represents U.S. coal and nuclear sales, including energy revenue and demand charges. |
The following table summarizes NRG's U.S. coal capacity and the corresponding revenues and average natural gas prices and positions resulting from coal hedge agreements extending beyond December 31, 2017 and through 2021 for the East/West region:
|
| | | | | | | | | | | | | | | | | | | | |
| East/West | | 2018 | | 2019 | | 2020 | | 2021 | | Annual Average for 2018-2021 |
| | | (Dollars in millions unless otherwise stated) |
Net Coal Capacity (MW) (a) | | 3,267 |
| | 3,267 |
| | 3,267 |
| | 3,267 |
| | 3,267 |
|
Forecasted Coal Capacity (MW) (b) | | 1,579 |
| | 1,456 |
| | 1,258 |
| | 881 |
| | 1,294 |
|
Total Coal Sales (GWh) (c) | | 12,520 |
| | 1,521 |
| | 644 |
| | 46 |
| | 3,683 |
|
Percentage Coal Capacity Sold Forward (d) | | 91 | % | | 12 | % | | 6 | % | | 1 | % | | 27 | % |
Total Forward Hedged Revenues (e) | | $ | 408 |
| | $ | 46 |
| | $ | 20 |
| | $ | 1 |
| | $ | — |
|
Weighted Average Hedged Price ($ per MWh) (e) | | $ | 32.60 |
| | $ | 30.57 |
| | $ | 30.68 |
| | $ | — |
| | $ | — |
|
Average Equivalent Natural Gas Price ($ per MMBtu) (e) | | $ | 2.76 |
| | $ | 2.84 |
| | $ | 2.73 |
| | $ | — |
| | $ | — |
|
| Gross Margin Sensitivities | | | | | | | | | | |
| Gas Price Sensitivity Up $0.50/MMBtu on Coal Units | | $ | 47 |
| | $ | 113 |
| | $ | 114 |
| | $ | 118 |
| | $ | — |
|
| Gas Price Sensitivity Down $0.50/MMBtu on Coal Units | | $ | (36 | ) | | $ | (96 | ) | | $ | (91 | ) | | $ | (71 | ) | | $ | — |
|
| Heat Rate Sensitivity Up 1 MMBtu/MWh on Coal Units | | $ | 31 |
| | $ | 66 |
| | $ | 64 |
| | $ | 66 |
| | $ | — |
|
| Heat Rate Sensitivity Down 1 MMBtu/MWh on Coal Units | | $ | (23 | ) | | $ | (59 | ) | | $ | (56 | ) | | $ | (49 | ) | | $ | — |
|
| |
(a) | Net coal capacity represents nominal summer net MW capacity of power generated as adjusted for the Company's current ownership position excluding capacity from inactive/mothballed units, see Item 2 - Properties for units scheduled to be deactivated.
|
| |
(b) | Forecasted generation dispatch output (MWh) based on forward price curves as of December 31, 2017, which is then divided by number of hours in a given year to arrive at MW capacity. The dispatch takes into account planned and unplanned outage assumptions. |
| |
(c) | Includes amounts under power sales contracts and natural gas hedges. The forward natural gas quantities are reflected in equivalent GWh based on forward market implied heat rate as of December 31, 2017, and then combined with power sales to arrive at equivalent GWh hedged. The coal sales include swaps and delta of options sold which is subject to change. For detailed information on the Company's hedging methodology through use of derivative instruments, see discussion in Item 15 - Note 5, Accounting for Derivative Instruments and Hedging Activities, to the Consolidated Financial Statements. Includes inter-segment sales from the Company's wholesale power generation business to the retail business.
|
| |
(d) | Percentage hedged is based on total coal sales as described in (c) above divided by the forecasted coal capacity. |
| |
(e) | Represents U.S. coal sales, including energy revenue and demand charges, excluding revenues derived from capacity auctions. |
Capacity and Other Contracted Revenue Sources
NRG's revenues and cash flows benefit from capacity/demand payments and other contracted revenue sources, originating from market clearing capacity prices, Resource Adequacy contracts, tolling arrangements, PPAs and other long-term contractual arrangements:
Capacity auctions — The Company's largest sources of capacity revenues are capacity auctions in PJM, ISO-NE, and NYISO. Both ISO-NE and PJM operate a pay-for-performance model where capacity payments are modified based on real-time performance, where NRG's actual revenues will be the combination of revenues based on the cleared auction MWs plus the net of any over- and under-performance of NRG's fleet. In addition, MISO has an annual auction, known as the Planning Resource Auction, or PRA. The Gulf Coast assets situated in the MISO market may participate in this auction.
Resource adequacy and bilateral contracts — In California, there is a resource adequacy requirement that is primarily satisfied through bilateral contracts. Such bilateral contracts are typically short-term resource adequacy contracts. When bilateral contracting does not satisfy the resource adequacy need, such shortfalls can be addressed through procurement tools administered by the CAISO, including the capacity procurement mechanism or reliability must-run contracts. In addition, NRG earns demand payments from its long-term full-requirements load contracts with nine Louisiana distribution cooperatives, which expire in 2025. Demand payments from the current long-term contracts are tied to summer peak demand and provide a mechanism for recovering a portion of the costs associated with new or changed environmental laws or regulations. In Texas, capacity and contracted revenues are through bilateral contracts with load serving entities.
Long-term PPAs — Output from the majority of renewable energy assets and certain conventional energy plants is sold through long-term PPAs and tolling agreements to a single counterparty, which is often a utility or commercial customer.
Fuel Supply and Transportation Contracts
NRG's fuel requirements consist of various forms of fossil fuel (including coal, natural gas and oil) and nuclear fuel. The prices of fossil fuels are highlycan be volatile. The Company obtains its fossil fuels from multiple suppliers and through multiple transporters. Although availability is generally not an issue, localized shortages, transportation availability, delays arising from extreme weather conditions and supplier financial stability issues can and do occur. The preceding factors related to the sources and availability of raw materials are fairly uniform across the Company's businessesbusiness and fuel products used.
Coal — The Company believes it is adequately hedged, using forward coal supply agreements, for its domestic coal consumption for 2018. NRG actively manages its coal NRG's primary fuel requirements based on forecasted generation, market volatility and its inventory on site. As of December 31, 2017, NRG had purchased forward contracts to provide fuel for approximately 41%consist of the Company's expected requirements from 2018 through 2021, including expected coal inventory draw down. NRG purchased approximately 21 million tons of coal in 2017, almost all of which was Powder River Basin coal. For fuel transport, NRG has entered into various rail and barge transportation and rail car lease agreements with varying tenures that provide for most of the Company's transportation requirements of Powder River Basin coal for the next 4 years.following:
The following table shows the percentage of the Company's coal requirements from 2018 through 2021 that have been purchased forward as of December 31, 2017:
|
| | |
| | Percentage of Company's Requirement (a) |
| 2018 | 97 | % |
| 2019 | 40 | % |
| 2020 | 26 | % |
| 2021 | — | % |
| |
(a) | Includes expected coal inventory draw down. |
Natural Gas — NRG operates a fleet of mid-merit and peaking natural gas plants across all its U.S. wholesale regions.plants. Fuel needs are managed by the natural gas commercial group, generally on a spot basis, especially for peaking assets, as the Company does not believe it is prudent to forward purchase natural gas for these types of units as the dispatch of which is highly unpredictable. Natural gas storage and transportation contracts are utilized to reduce daily volatility.
Coal —NRG actively manages its coal requirements based on forecasted generation, market volatility and its inventory on site. The Company believes it is adequately hedged, using forward coal supply agreements, for its domestic coal consumption for 2024. As of December 31, 2023, NRG had purchased forward contracts to provide fuel for the Company's expected requirements for 2024. For the domestic fleet, NRG purchased approximately 13 million tons of coal in 2023, almost all of which was Powder River Basin coal. For fuel transport, NRG has entered into various rail transportation and rail car lease agreements with varying tenures, which will provide for the Company's transportation requirements of Powder River Basin coal for the next two years.
Renewable PPAs
The Company's strategy is to procure mid to long-term renewable generation through power purchase agreements. As of December 31, 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 entered into through Renewable PPAs may be impacted by contract terminations when they occur.
Capacity and Other Contracted Revenue or Supply Sources
NRG's revenues and/or cash flows, primarily in the East and West, benefit from capacity/demand payments and other contracted revenue sources, originating from market clearing capacity prices, tolling arrangements and other long-term contractual arrangements.
Natural Gas
The natural gas storage services as well as natural gas transportation services to deliver natural gas when needed.
Nuclear Fuel — STP's owners satisfy their fuel supply requirements by: (i) acquiring uranium concentrates and contracting for conversion of the uranium concentrates into uranium hexafluoride; (ii) contracting for enrichment of uranium hexafluoride; and (iii) contracting for fabrication of nuclear fuel assemblies. Through its proportionate participation in STPNOC, whichcommercial group is the NRC-licensed operator of STP and responsible for costing, logistics and supply for all aspects of fuel procurement, NRG is party to a number of long-term forward purchase contracts with many of the world's largest suppliers covering STP's requirements for uranium concentrates with only approximately 25% of STP's requirements outstanding for the duration of the original operating license. Similarly, NRG is party to long-term contracts to procure STP's requirements for conversion and enrichment services and fuel fabrication for the life of the operating license. Since the operating license was renewed for another 20 years in September 2017, STPNOC has begun to review a second phase of fuel purchasing.
Retail Operations
In 2017, NRG's retail businesses sold electricity to residential, commercial and industrial, consumersand wholesale customers. NRG has contractual rights to natural gas transportation and storage assets across its footprint that allow for optimal supply economics in support of its various businesses. NRG's diversified load coupled with this asset portfolio enables the Company to deliver supply economically while providing incremental optimization activities when market conditions allow. The scale of the natural gas operation extends from the wellhead (through its producer services business) to end use customers (through NRG's various sales channels). This scale, coupled with the Company's associated assets, gas system platform and people, create significant value across North America.
Plant Operations
The Company owns and leases a diversified wholesale generation portfolio with approximately 13 GW of fossil fuel, and renewable generation capacity at either fixed, indexed or variable prices. Residential19 plants as of December 31, 2023. The Company's wholesale generation assets are diversified by fuel-type and smaller commercial consumers typically contractdispatch level, which helps mitigate the risks associated with fuel price volatility and market demand cycles. NRG continually evaluates its generation portfolio to focus on asset optimization opportunities and the locational value of its generation assets in each of the markets where the Company participates, as well as opportunities for terms ranging from one monththe development of new generation.
The following table summarizes NRG's generation portfolio as of December 31, 2023:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | |
| | (In MW)(a) |
| Type | | Texas | | East | | West/Services/Other(b) | | | | Total |
| Natural gas | | 4,353 | | | 80 | | | 1,279 | | | | | 5,712 | |
| Coal | | 4,174 | | | 1,948 | | | 605 | | | | | 6,727 | |
| Oil | | — | | | 455 | | | — | | | | | 455 | |
| | | | | | | | | | |
| Utility Scale Solar | | — | | | — | | | 216 | | | | | 216 | |
| Battery Storage | | 2 | | | — | | | — | | | | | 2 | |
| | | | | | | | | | |
| Total generation capacity | | 8,529 | | | 2,483 | | | 2,100 | | | | | 13,112 | |
| | | | | | | | | | |
| | | | | | | | | | |
(a)Utility Scale Solar is 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 interest
(b)Includes proportionate share of equity owned investments
Plant Operations is responsible for operating the Company's generation facilities at the highest standards of safety and regulatory compliance, and includes (i) operations and maintenance, (ii) asset management, and (iii) development, engineering and construction.
Operations & Maintenance
NRG operates and maintains its generation portfolio, as well as approximately 6,500 MW of additional coal, natural gas and wind generation capacity at 15 plants operated on behalf of third parties, as of December 31, 2023, using prudent industry practices for the safe, reliable and economic generation of electricity in compliance with all local, state and federal requirements. The Company follows a consistent set of operating requirements, including a solid base of training, required adherence to five years while industrialspecific safety and environmental limits, procedure and checklist usage, and the implementation of continuous process improvement through incident investigations.
NRG uses best-in-class maintenance practices for preventive, predictive, and corrective maintenance planning. The Company’s strategic planning process evaluates equipment condition, performance, and obsolescence to support the development of a comprehensive work scope and schedule for long-term performance.
Asset Management
NRG manages all aspects of its generation portfolio to optimize the lifecycle value of the assets, consistent with the Company’s goals. The Company evaluates capital projects required for continued operation and strategic enhancement of the assets, provides quality assurance on capital outlays, and assesses the impact of rules, regulations, and laws on business profitability. In addition, the Company manages its long-term contracts, are often between one yearPPAs, and five years in length. In 2017, NRG's retail businesses sold approximately 63 TWhsreal estate holdings and provides third-party asset management services.
Development, Engineering & Construction
NRG develops, engineers and executes major plant modifications, “new build” generation and energy storage projects that enhance the value of electricity. In any given year, the quantity of TWhs sold can be affected by weather, economic conditions and competition. The wholesale supply is typically purchased as the load is contracted from a combination of NRG's wholesaleits generation portfolio and provide options to meet generation growth needs in the retail markets it serves, in accordance with the Company’s strategic goals. These projects have included gas-fired generation development and
construction, coal to gas conversions, grid scale energy storage development, grid scale renewable construction, and asset demolition, remediation and reclamation work.
Vivint Smart Home
In March 2023, NRG completed the acquisition of Vivint Smart Home, which is a leading smart home platform that provides subscribers with technology, products and services to create a smarter, greener, safer home. A smart home has multiple devices integrated into a single expandable platform that incorporates artificial intelligence and machine-learning in its operating system allowing customers to interact with and manage their home from anywhere via the Vivint app on their smart device. Vivint Smart Home enables a customized solution for the home using integrated smart cameras (indoor, outdoor and doorbell), locks, lights, thermostats, garage door control and a host of other third parties.safety and security sensors.
Vivint Smart Home provides a fully integrated solution for consumers, including hardware, software, sales, installation by trained and experienced in-home service professionals, customer service, technical support and professional monitoring. This seamless integration of high-quality products and services resulted in an average subscriber lifetime of approximately nine years as of December 31, 2023. The Company believes its ability to choose supply fromoffer related or adjacent products and services that leverage the market orexisting smart home platform, as well as energy services, can extend the Company's portfolio allows for an optimal combinationaverage subscriber lifetime and increase the lifetime value of subscribers. Vivint Smart Home's cloud-based home platform currently manages more than 30 million in-home devices as of December 31, 2023. The average subscriber on Vivint Smart Home's cloud-based home platform engages with the smart home app approximately 16 times per day and has approximately 15 devices in its home.
Through the addition of Vivint Smart Home, NRG identified opportunities to supportimprove gross margin, customer retention and stabilize retail margins.customer lifetime value.
Operational Statistics
The following statistics represent the Company's retail load and customer count:
| | | | | | | | | | | | | | | | | |
| | Year ended December 31, |
| | 2023 | | 2022 | | 2021 |
Sales volumes - Electricity (in GWh) | | | | | |
| Home - Texas | 40,032 | | | 43,155 | | | 42,397 | |
| Home - East | 12,838 | | | 13,269 | | | 14,108 | |
| Home - West/Services/Other | 2,243 | | | 2,250 | | | 2,252 | |
| Business - Texas | 40,250 | | | 38,447 | | | 34,367 | |
| Business - East | 46,438 | | | 47,724 | | | 53,204 | |
| Business - West/Services/Other | 10,393 | | | 10,231 | | | 10,625 | |
| Total Load | 152,194 | | | 155,076 | | | 156,953 | |
| | | | | |
Sales volumes - Natural gas (in MDth) | | | | | |
| Home - East | 49,990 | | | 53,051 | | | 50,417 | |
| Home - West/Services/Other | 75,150 | | | 92,035 | | | 97,272 | |
| Business - East | 1,587,052 | | | 1,618,946 | | | 1,620,036 | |
| Business - West/Services/Other | 179,888 | | | 154,074 | | | 109,021 | |
| Total Load | 1,892,080 | | | 1,918,106 | | | 1,876,746 | |
| | | | | |
| | | | | | | | | | | | | | | | | |
| | Year ended December 31, |
| | 2023 | | 2022 | | 2021 |
Customer count - Electricity customers(a)(b) (in thousands) | | | | | |
| Home - Texas | | | | | |
| Average retail | 2,878 | | | 2,961 | | | 3,040 | |
| Ending retail | 2,928 | | | 2,859 | | | 3,010 | |
Home - East | | | | | |
| Average retail | 1,466 | | | 1,408 | | | 1,484 | |
| Ending retail | 1,752 | | | 1,381 | | | 1,402 | |
| Home - West/Services/Other | | | | | |
Average retail(c) | 393 | | | 383 | | | 525 | |
Ending retail(c) | 404 | | | 390 | | | 512 | |
| | | | | |
Customer count - Natural gas customers(b) (in thousands) | | | | | |
Home - East | | | | | |
| Average retail | 390 | | | 375 | | | 360 | |
| Ending retail | 385 | | | 380 | | | 364 | |
| Home - West/Services/Other | | | | | |
| Average retail | 381 | | | 416 | | | 452 | |
| Ending retail | 358 | | | 396 | | | 434 | |
| | | | | |
Total Customer count (in thousands) | | | | | |
| Average retail - Home - Electricity and Natural gas | 5,508 | | | 5,543 | | | 5,861 | |
Average - Vivint Smart Home(d) | 2,008 | | | — | | | — | |
| | | | | |
| Ending retail - Home - Electricity and Natural gas | 5,827 | | | 5,406 | | | 5,722 | |
Ending - Vivint Smart Home(d) | 2,043 | | | — | | | — | |
| Total Ending retail and Vivint Smart Home | 7,870 | | | 5,406 | | | 5,722 | |
| (a) Includes Services customers | | | | | |
| (b) Dual fuel customers are included within electricity customer counts only | | | | | |
| (c) Includes 135 thousand whole home warranty customers as of December 31, 2021. The whole home warranty business was sold in January 2022 |
| (d) Vivint Smart Home subscribers includes customers that also purchase other NRG products | | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
The following are industry statistics for the Company's fossil and nuclear plants, as defined by the NERC, and are more fully described below:NERC:
Annual Equivalent Availability Factor, or EAF — Measures the percentage of maximum generation available over time as the fraction of net maximum generation that could be provided over a defined period of time after all types of outages and deratings, including seasonal deratings, are taken into account.
Net Heat Rate — The net heat rate represents the total amount of fuel in BTU required to generate one net kWh provided.
Net Capacity Factor — The net amount of electricity that a generating unit produces over a period of time divided by the net amount of electricity it could have produced if it had run at full power over that time period. The net amount of electricity produced is the total amount of electricity generated minus the amount of electricity used during generation.generation by the station.
The tables below present these performance metrics for the Company's global power generation portfolio, including leased facilities, and those accounted for through equity method investments, for the years ended December 31, 20172023 and 2016:2022:
|
| | | | | | | | | | | | | | |
| | Year Ended December 31, 2017 |
| | | | | | Fossil and Nuclear Plants |
| | Net Owned Capacity (MW) | | Net Generation (MWh) (In thousands) (b) | | Annual Equivalent Availability Factor | | Average Net Heat Rate BTU/kWh | | Net Capacity Factor |
| | | | | | | | | | |
| Generation | | | | | | | | | |
| Gulf Coast | 13,714 |
| | 49,573 |
| | 89.5 | % | | 10,106 |
| | 38.9 | % |
| East/West | 12,451 |
| | 13,373 |
| | 85.4 |
| | 10,757 |
| | 12.2 |
|
| Renewables | 1,565 |
| | 3,836 |
| | 94.7 |
| | — |
| | 38.2 |
|
NRG Yield (a) | 5,247 |
| | 10,686 |
| | 95.5 |
| | 8,938 |
| | 21.4 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2023 |
| | | | | Fossil and Nuclear Plants (a) |
| | Net Owned
Capacity (MW) | | Net Generation (In thousands of MWh) (a) | | Annual Equivalent Availability Factor | | Average Net Heat Rate BTU/kWh | | Net Capacity Factor |
| | | | | | | | | |
| Texas | 8,529 | | | 30,776 | | | 74.2 | % | | 11,175 | | | 35.4 | % |
| East | 2,483 | | | 2,016 | | | 85.5 | % | | 13,007 | | | 6.6 | % |
| West/Services/Other | 1,169 | | | 5,903 | | | 73.5 | % | | 7,449 | | | 56.8 | % |
|
| | | | | | | | | | | | | | |
| | Year Ended December 31, 2016 |
| | | | | | Fossil and Nuclear Plants |
| | Net Owned Capacity (MW) | | Net Generation (MWh) (In thousands) (b) | | Annual Equivalent Availability Factor | | Average Net Heat Rate BTU/kWh | | Net Capacity Factor |
| | |
| Generation | | | | | | | | | |
| Gulf Coast | 14,085 |
| | 47,827 |
| | 88.2 | % | | 10,028 |
| | 38.6 | % |
| East/West | 12,519 |
| | 17,114 |
| | 78.3 |
| | 10,258 |
| | 15.7 |
|
| Renewables | 1,788 |
| | 3,827 |
| | 96.9 |
| | — |
| | 35.3 |
|
NRG Yield (a) | 3,310 |
| | 11,230 |
| | 96.6 |
| | 8,848 |
| | 22.6 |
|
| |
(a) | NRG Yield includes thermal generation. |
| |
(b) | Net generation excludes equity method investments. |
(a)Excludes equity method investments
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2022 |
| | | | | Fossil and Nuclear Plants (a) |
| | Net Owned
Capacity (MW) | | Net Generation (In thousands of MWh) (a) | | Annual Equivalent Availability Factor | | Average Net Heat Rate BTU/kWh | | Net Capacity Factor |
| |
| Texas | 10,027 | | | 37,275 | | | 69.5 | % | | 10,733 | | | 41.8 | % |
| East | 4,285 | | | 7,282 | | | 78.1 | % | | 11,959 | | | 17.3 | % |
| West/Services/Other | 1,172 | | | 6,676 | | | 84.5 | % | | 7,442 | | | 64.9 | % |
(a)Excludes equity method investments
The generation performance by region for the three years ended December 31, 2017, 20162023, 2022 and 2015,2021 is shown below:
| | | | | | | | | | | | | | | | | |
| Net Generation |
| (In thousands of MWh) | 2023 | | 2022 | | 2021 |
| Texas | | | | | |
| Coal | 15,576 | | | 18,860 | | | 18,876 | |
| Gas | 7,333 | | | 8,763 | | | 8,846 | |
Nuclear (a) | 7,867 | | | 9,652 | | | 9,198 | |
| Total Texas | 30,776 | | | 37,275 | | | 36,920 | |
| East | | | | | |
| Coal | 1,328 | | | 6,738 | | | 5,774 | |
| Oil | 3 | | | 7 | | | 201 | |
| Gas | 685 | | | 537 | | | 1,519 | |
Total East (b) | 2,016 | | | 7,282 | | | 7,494 | |
| West/Services/Other | | | | | |
| Gas | 5,899 | | | 6,669 | | | 7,941 | |
| Renewables | 4 | | | 7 | | | 8 | |
Total West/Services/Other (c) | 5,903 | | | 6,676 | | | 7,949 | |
| | | | | |
| Total generation performance | 38,695 | | | 51,233 | | | 52,363 | |
(a)Reflects the Company's undivided interest in total MWh generated by STP. The Company sold its interest in STP on November 1, 2023
(b)Includes gas generation of 855 thousand MWh and oil generation of 199 thousand MWh for the year ended December 31, 2021, that was sold to Generation Bridge on December 1, 2021
(c)Includes gas generation of 2,445 thousand MWh for the year ended December 31, 2021, that was sold to Generation Bridge on December 1, 2021
|
| | | | | | | | |
| | Net Generation |
| | 2017 | | 2016 | | 2015 |
| | (In thousands of MWh) |
| Generation | | | | | |
| Gulf Coast | | | | | |
| Coal | 28,622 |
| | 25,197 |
| | 29,301 |
|
| Gas | 11,442 |
| | 13,071 |
| | 16,288 |
|
Nuclear (a) | 9,509 |
| | 9,559 |
| | 8,573 |
|
| Total Gulf Coast | 49,573 |
| | 47,827 |
| | 54,162 |
|
| East/West | | | | | |
| Coal | 8,407 |
| | 11,096 |
| | 19,155 |
|
| Oil | 319 |
| | 318 |
| | 567 |
|
| Gas | 4,647 |
| | 5,700 |
| | 4,909 |
|
| Total East/West | 13,373 |
| | 17,114 |
| | 24,631 |
|
| Renewables | | | | | |
| Solar | 1,740 |
| | 1,634 |
| | 1,027 |
|
| Wind | 2,096 |
| | 2,193 |
| | 2,281 |
|
| Total Renewables | 3,836 |
| | 3,827 |
| | 3,308 |
|
| NRG Yield | | | | | |
| Solar | 1,248 |
| | 1,281 |
| | 1,332 |
|
| Wind | 5,597 |
| | 6,010 |
| | 4,479 |
|
Gas and Dual-Fuel (b) | 3,841 |
| | 3,939 |
| | 4,731 |
|
| Total NRG Yield | 10,686 |
| | 11,230 |
| | 10,542 |
|
| |
(a) | MWh information reflects the Company's undivided interest in total MWh generated by STP. |
| |
(b) | Gas and Dual-Fuel includes thermal heating and chilled water generation as well as assets contracted under tolling agreements. |
While there has been consolidation in the competitive retail energy space over the past few years, there is still considerable competition for customers. In Texas, there is healthy competition in deregulated areas and customers can choose providers based on the most appealing offers. Outside of Texas, electricity retailers compete with the incumbent utilities, in addition to other retail electric providers, which can inhibit competition depending on the market rules of the state. There is a high degree of fragmentation, with both large and small competitors offering a range of value propositions, including value, rewards, and sustainability-based offerings.
Segment ReviewWholesale generation is highly fragmented and diverse in terms of industry structure by region. As such, there is wide variation in terms of the capabilities, resources, nature and identities of the Company’s competitors depending on the market. Competitors include regulated utilities, municipalities, cooperatives, other independent power producers, and power marketers or trading companies, including those owned by financial institutions.
The Company's segment structure reflects how management currently makes financial decisionssmart home market is an expanding global opportunity and allocates resources. Effective January 2017,is in the Company's businesses are segregatedearly stages of broad consumer adoption. It is highly competitive and fragmented. Major competitors range from large-cap technology companies seeking to expand their core market opportunity who predominantly offer do-it-yourself ("DIY") devices that put a large burden on homeowners to self-install and support many devices, to security-based providers, as follows: Generation , whichwell as industrial and telecommunications companies that offer connected home experiences. Vivint Smart Home provides the full smart home experience, with an end-to-end solution that includes generation, internationala wide range of unique capabilities and BETM; Retail which includes Mass customersuse cases. Currently, the vast majority of competitors do not offer comprehensive smart home solutions 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. Intersegment sales are accounted for at market. The Company has recast data from prior periods to reflect changes in reportable segments to conform to the current year presentation.accompanying services.
During 2017, NRG Yield acquired several projects totaling 555 MW for cash consideration of approximately $245 million from NRG. These acquisitions were accounted for as transfers of entities under common control and accordingly, all historical periods have been recast to reflect this change.
On June 14, 2017, NRG deconsolidated GenOn for financial reporting purposes. The financial information for all historical periods have been recast to present GenOn as discontinued operations within the corporate segment.
Revenues
The following table contains a summary of NRG's operating revenues by segment for the years ended December 31, 2017, 2016 and 2015, as discussed in Item 15 — Note 18, Segment Reporting, to the consolidated financial statements. Refer to that footnote for additional financial information about NRG's business segments including a profit measure and total assets. In addition, refer to Item 2 — Properties, to the consolidated financial statements for information about facilities in each of NRG's business segments.
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| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2017 |
| | Energy Revenues | | Capacity Revenues | | Retail Revenues | | Mark-to- Market Activities | | Contract Amortization | | Other Revenues(a) | | Total Operating Revenues(b) |
| | (In millions) |
| Generation | $ | 2,636 |
| | $ | 851 |
| | $ | — |
| | $ | 37 |
| | $ | 14 |
| | $ | 235 |
| | $ | 3,773 |
|
| Retail | — |
| | — |
| | 6,385 |
| | (4 | ) | | (1 | ) | | — |
| | 6,380 |
|
| Renewables | 359 |
| | — |
| | — |
| | (12 | ) | | — |
| | 77 |
| | 424 |
|
| NRG Yield | 554 |
| | 346 |
| | — |
| | — |
| | (69 | ) | | 178 |
| | 1,009 |
|
Corporate and Eliminations (b) | (1,088 | ) | | (11 | ) | | 3 |
| | 218 |
| | — |
| | (79 | ) | | (957 | ) |
| Total | $ | 2,461 |
| | $ | 1,186 |
| | $ | 6,388 |
| | $ | 239 |
| | $ | (56 | ) | | $ | 411 |
| | $ | 10,629 |
|
| |
(a) | Primarily consists of revenues generated by the Thermal business (NRG Yield segment), operation and maintenance revenues and unrealized trading activities, primarily at BETM (Generation segment). |
| |
(b) | Energy revenues include inter-segment sales primarily between Generation and Retail. |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2016 |
| | Energy Revenues | | Capacity Revenues | | Retail Revenues | | Mark-to- Market Activities | | Contract Amortization | | Other Revenues(c) | | Total Operating Revenues(d) |
| | (In millions) |
| Generation | $ | 3,171 |
| | $ | 891 |
| | $ | — |
| | $ | (566 | ) | | $ | 15 |
| | $ | 322 |
| | $ | 3,833 |
|
| Retail | — |
| | — |
| | 6,336 |
| | — |
| | (1 | ) | | — |
| | 6,335 |
|
| Renewables | 369 |
| | — |
| | — |
| | (6 | ) | | (1 | ) | | 44 |
| | 406 |
|
| NRG Yield | 582 |
| | 345 |
| | — |
| | — |
| | (69 | ) | | 177 |
| | 1,035 |
|
Corporate and Eliminations (d) | (991 | ) | | (11 | ) | | 21 |
| | (70 | ) | | — |
| | (46 | ) | | (1,097 | ) |
| Total | $ | 3,131 |
| | $ | 1,225 |
| | $ | 6,357 |
| | $ | (642 | ) | | $ | (56 | ) | | $ | 497 |
| | $ | 10,512 |
|
| |
(c) | Primarily consists of revenues generated by the Thermal business (NRG Yield segment), operation and maintenance revenues and unrealized trading activities, primarily at BETM (Generation segment). |
| |
(d) | Energy revenues include inter-segment sales primarily between Generation and Retail. |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2015 |
| | Energy Revenues | | Capacity Revenues | | Retail Revenues(f) | | Mark-to- Market Activities | | Contract Amortization | | Other Revenues(e) | | Total Operating Revenues(f) |
| | (In millions) |
| Generation | $ | 4,072 |
| | $ | 1,027 |
| | $ | — |
| | $ | (142 | ) | | $ | 15 |
| | $ | 207 |
| | $ | 5,179 |
|
| Retail | — |
| | — |
| | 6,910 |
| | 4 |
| | (1 | ) | | — |
| | 6,913 |
|
| Renewables | 356 |
| | — |
| | — |
| | (3 | ) | | — |
| | 30 |
| | 383 |
|
| NRG Yield | 495 |
| | 341 |
| | — |
| | (2 | ) | | (54 | ) | | 188 |
| | 968 |
|
Corporate and Eliminations(f) | (1,056 | ) | | (7 | ) | | (43 | ) | | 9 |
| | — |
| | (18 | ) | | (1,115 | ) |
| Total | $ | 3,867 |
| | $ | 1,361 |
| | $ | 6,867 |
| | $ | (134 | ) | | $ | (40 | ) | | $ | 407 |
| | $ | 12,328 |
|
| |
(e) | Primarily consists of revenues generated by the Thermal business (NRG Yield segment), operation and maintenance revenues and unrealized trading activities, primarily at BETM (Generation segment). |
| |
(f) | Energy revenues include inter-segment sales primarily between Generation and Retail. |
Seasonality and Price Volatility
The sale of power and natural gas to retail customers are seasonal businesses with the demand for power generally peaking during the summer, and the demand for natural gas generally peaking during the winter. As a result, net working capital requirements for the Company's retail operations generally increase during summer and winter months along with the higher revenues, and then decline during off-peak months. Weather may impact operating results and extreme weather conditions could have a material impact. The rates charged to retail customers may be impacted by fluctuations in total power prices and market dynamics, such as the price of natural gas, transmission constraints, competitor actions, and changes in market heat rates.
Annual and quarterly operating results of the Company's wholesale power generation segmentsportfolio can be significantly affected by weather including wind resource availability, and energy commodity price volatility. Significant other events, such as the demand for natural gas, interruptions in fuel supply infrastructure and relative levels of hydroelectric capacity can increase seasonal fuel and power price volatility. The preceding factors related to seasonality and price volatility are fairly uniform across the Company's wholesale generation business segments.
The sale of electric power to retail customers is also a seasonal business withregions in which the demand for power generally peaking during the summer months. As a result, net working capital requirements for the Company's retail operations generally increase during summer months along with the higher revenues, and then decline during off-peak months. Weather may impact operating results and extreme weather conditions could materially affect results of operations. The rates charged to retail customers may be impacted by fluctuations in total power prices and market dynamics like the price of natural gas, transmission constraints, competitor actions, and changes in market heat rates.Company operates.
Market Framework
Organized Energy MarketsNRG sells electricity, natural gas and related products and services, and smart home products and services to customers throughout the U.S. and Canada. In most of the states and regions that have introduced retail consumer choice, NRG competitively offers electricity, natural gas, portable power and other value-enhancing services to customers. Each retail consumer choice state or province establishes its own retail competition laws and regulations, and the specific operational, licensing, and compliance requirements vary by state or province. Regulated terms and conditions of default service, as well as any movement to replace default service with competitive services, as is done in CAISO, ERCOT, ISO-NE, MISO, NYISOcan affect customer participation in retail competition. In Canada, NRG sells energy and PJM
related services to residential and commercial customers in the province of Alberta pursuant both to a regulated rate service governed by provincial regulations as well as a competitive service with rates set by market forces. Sales of energy to commercial customers take place in other provinces as well. The majorityattractiveness of NRG's retail offerings may be impacted by the rules, regulations, market structure and communication requirements from public utility commissions in each state and province.
NRG's fleet of power plants which it owns, operates or manages are located in one of the organized energy markets, known as RTOs or ISOs. Each organized market administers day-ahead and real-time centralized bid-based energy and ancillary services markets pursuant to tariffs approved by FERC, or in the case of ERCOT, market rules approved by the PUCT. These tariffs and rules dictate how the energy markets operate, how market participants make bilateral sales with one another and how entities with market-based rates are compensated. Established prices reflect the value of energy at the specific location and time it is delivered, which is known as the Locational Marginal Price, or LMP.Price. Each market is subject to market mitigation measures designed to limit the exercise of locational market power. These market structures facilitate NRG's sale of power and capacity products at market-based rates.
Other than ERCOT and AESO, each of the ISO regions also operates a capacity or resource adequacy market that provides an opportunity for generating and demand response resources to earn revenues to offset their fixed costs that are not recovered in the energy and ancillary services markets. The ISOs are also responsible for transmission planning and operations.
Texas
NRG's Gulf Coast wholesale power generation business in Texas is locatedsubject to standards and regulations adopted by the PUCT and ERCOT1, including the requirement for retailers to be certified by the PUCT in the ERCOT and MISO markets.order to contract with end-users to sell electricity. The ERCOT market is one of the nation's largest and, historically, fastest growing power markets. ERCOT is an energy only market, and has implemented market rule changes to provide pricing more reflectiveenergy-only market. The majority of higher energy value when operating reserves are scarce or constrained. NRG also operates generation assets that are located within MISO, participatingthe retail load in the MISO day-aheadERCOT market region is served by competitive retail suppliers, except certain areas that have not opted into competitive consumer choice and real-time energyare served by municipal utilities and ancillary services markets. Additionally, MISO employs a one-year forward resource adequacy construct, in which capacity resources can compete for fixed cost recoveryelectric cooperatives.
East
While most of the states in the capacity auction. NRG continues toEast region of the U.S. have introduced some level of retail consumer choice for electricity and/or natural gas, the incumbent utilities currently provide full requirementsdefault service to LSEs, including cooperativesin most of the states and municipalitiesas a result typically serve the majority of residential customers. NRG’s retail activities in the MISO region.East are subject to standards and regulations adopted by the ISOs, state public utility commissions and legislators, including the requirement for retailers to be certified in each state in order to contract with end-users to sell electricity.
East/West
Power plants owned, operated or managed by NRG and NRG's generation and demand response assets located in the East region of the U.S. are within the control areas of ISO-NE,PJM, NYISO and PJM.MISO. Each of the market regions in the East region provides for robust competition in the day-ahead and real-time energy and ancillary services markets. Additionally, the assets in the East region receivesreceive a significant portion of itstheir revenues from capacity markets in ISO-NE, NYISO and PJM.markets. PJM and ISO-NE useuses a three-year forward capacity auction, while NYISO uses a month-ahead capacity auction. MISO has an annual auction. Capacity market prices are sensitive to design parameters, as well as additions of new capacity. Both ISO-NE and PJM operateoperates a pay-for-performance model where capacity payments are modified based on real-time generator performance. In such markets, NRG’s actual capacity revenues will be the combination of cleared auction prices times the quantity of MWsMW cleared, plus the net of any over-performance “bonus payments”"bonus payments" and any under-performance charges. In both markets,Additionally, bidding rules allow for the incorporation of a risk premium into generator bids.
West
In the West region of the U.S., NRG owns equity interests, operates a fleet of natural gas fired facilitiesor manages power plants located entirely within the CAISO footprint. The CAISO operates day-ahead and real-time locational markets for energy and ancillary services, while managing congestion primarily through nodal prices. The CAISO system facilitates NRG's sale of power, ancillary services and capacity products at market-based rates, either within the CAISO's centralized energy and ancillary service markets or bilaterally pursuant to tolling arrangements or other capacity sales with California's LSEs.bilaterally. The CPUC also determines capacity requirements for LSEs and for specified local areas utilizing inputs from the CAISO. Both the CAISO and CPUC rules require LSEs to contract with sufficient generation resources in order to maintain minimum levels of generation within defined local areas. Additionally, the CAISO has independent authority to contract with needed resources under certain circumstances, typically either when LSEs have failed to procure sufficient resources, or system conditions change unexpectedly.
RenewablesCanada
In Canada, NRG operates a fleet of utility scalesells to residential and distributed renewable generating assets acrosscommercial retail customers in Alberta, within the U.S. Many states have implemented their own renewable portfolio standards requiring LSEs to provide a given percentage of their energy sales from renewable resources. As a result, a number of LSEs have entered into long-term PPAs with NRG's utility scale renewable generating facilities. There are examples of states increasing their RPS from initially stated levels, such as California’s 50% RPSAESO footprint, under both regulated rates approved by 2030 and Hawaii’s goal of achieving 100% renewables by 2045. In addition, given the cost competitiveness of renewables, LSEs are procuring renewables in excess of their RPS obligations. In December 2015, the U.S. Congress extended the 30% solar ITC so that projects which begin construction in 2016 through 2019 will continue to qualify for the 30% ITC. Projects beginning construction in 2020 and 2021 will be eligible for the ITC at the rates of 26% and 22%, respectively. The same legislation also extended the 10-year wind PTC for wind projects which begin construction in years 2016 through 2019. Wind projects which begin construction in the years 2017, 2018 and 2019 are eligible for PTC at 80%, 60% and 40% of the statutory rate per kWh, respectively.
Retail
NRG's retail businesses sell energy and related servicesAUC as well as portablethrough competitive service. The Company's regulated rates are approved through periodic rate applications that establish rates for power and battery solutionsgas sales as well as for recovery of other costs associated with operating the regulated business. In addition, the Company sells energy to commercial customers across the country. In most of the states that have introduced retail competition, NRG's retail businesses competitively offer retail power, natural gas, portable power orin other value-enhancing services to end-use customers. Each retail choice state establishes its own retail competition lawsprovinces. All sales and regulations, and the specific operational, licensing, and compliance requirements vary on a state-by-state basis. In the East markets, incumbent utilities currently provide default service and as a result typically serve a majority of residential customers. In Texas, NRG’s retail business activitiesoperations are subject to standardsapplicable federal and regulations adopted byprovincial laws and regulations.
Vivint Smart Home
Vivint Smart Home operates in states that regulate in some manner the PUCTsale, installation, servicing, monitoring or maintenance of smart home and ERCOT, includingelectronic security systems. Vivint Smart Home and Vivint Smart Home sales representatives are typically required to obtain and maintain licenses, certifications or similar permits from governmental entities as a condition to engaging in the requirement for retailerssmart home and security service business. Vivint Smart Home is subject to be certified by the PUCT in orderfederal and state laws related to contract with end-usersconsumer financing which may include rules related to sell electricity. A majorityfees and charges, disclosures and regulation of the retail loadparty extending consumer credit.
1The Cottonwood facility is located in Deweyville, Texas, but operates in the ERCOTMISO market region and is served by competitive retail suppliers, except certain areas that are served by municipal utilities and electric cooperatives that have not opted into competitive choice. Regulated terms and conditions of default service, as well as any movement to replace default service with competitive services, as is done in ERCOT, can affect customer participation in retail competition. The attractiveness of NRG's retail offerings in each state may be impacted by the rules, regulations, market structure and communication requirements from public utility commissions across the country.
Energy Regulatory 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, state and state governmentprovincial 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 retailThese power markets are subject to rulesongoing legislative and regulations established by the states in which NRG entities are licensed to sell at retail.regulatory changes that may impact NRG's wholesale and retail operations. 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.PUCT.
Federal Energy Regulation
FERC
FERC regulates the transmission and the wholesale sale by public utilities of electricity in interstate commerce under the authority of the FPA. Under existing regulations, FERC determines whether an entity owning a generation facility is an EWG as defined in the PUHCA. FERC also determines whether a generation facility meets the ownership and technical criteria of a QF under PURPA. The transmission of electric energy occurring wholly within ERCOT is not subject to FERC's rate jurisdiction under Sections 203 or 205 of the FPA. Each of NRG's non-ERCOT U.S. generating facilities either qualifies as a QF, or the subsidiary owning the facility qualifies as an EWG.
Public utilities are required to obtain FERC's acceptance, pursuant to Section 205 of the FPA, of their rate schedules for the wholesale sale of electricity. Generally all of NRG's non-QF generating and power marketing entities located outside of ERCOT make sales of electricity pursuant to market-based rates, as opposed to traditional cost-of-service regulated rates.
Derivatives Regulatory Reforms
In the U.S., the CFTC regulates the trading of swaps, futures and many commodities under the Commodity Exchange Act, or CEA. In recent years, there have been a number of reforms to the regulation of the derivatives markets, both in the U.S. and internationally. These regulations, and any further changes thereto, or adoption of additional regulations, including any regulations relating to position limits on futures and other derivatives or margin for derivatives, could negatively impact NRG’s ability to hedge its portfolio in an efficient, cost-effective manner by, among other things, potentially decreasing liquidity in the forward commodity and derivatives markets or limiting NRG’s ability to utilize non-cash collateral for derivatives transactions.
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 proposed that FERC take action to reform the ISO/RTO markets to value certain reliability and resiliency attributes of electric generation resources. 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. On January 8, 2018, FERC terminated the proposed rulemaking and opened a new rulemaking asking each ISO/RTO to address specific questions focused on grid resilience.
State Energy Regulation
In Texas, NRG's operations within the ERCOT footprint are not subject to rate regulation by FERC, because they operate solely within the ERCOT market. 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.
In New York, NRG's generation subsidiaries are electric corporations subject to "lightened" regulation by the NYSPSC. As such, the NYSPSC exercises its jurisdictional authority over certain non-rate aspects of the facilities, including safety, retirements, and the issuance of debt secured by recourse to NRG's generation assets located in New York.
In California, NRG's generation subsidiaries are subject to regulation by the CPUC with regard to certain non-rate aspects of the facilities, including health and safety, outage reporting and other aspects of the facilities' operations. Additionally, the competitiveness of many of NRG's businesses depends on state competition and other policies.
State Out-Of-Market Subsidy Proposals — Certain states in the areas of the country in which NRG operates, including New Jersey, Ohio and Pennsylvania have considered but have not enacted proposals to provide out-of-market subsidy payments to potentially uneconomic nuclear and fossil generating units. NRG has opposed efforts to provide out-of-market subsidies, and intends to continue opposing them in the future.
Nuclear Operations
NRG South Texas LP owns 44% of a joint undivided interest in STP. The other owners of STP are the City of Austin, Texas (16%) and the City Public Service Board of San Antonio (40%). STP Nuclear Operating Company, or STPNOC, was founded by the then-owners in 1997 to operate the plant and it is the operator, licensee and holder of the Facility Operating Licenses NPF-76 and NPF-80. STPNOC is a nonstock, nonprofit, nonmember corporation. Each owner of STP appoints a board member (and the three directors then choose a fourth director who also serves as the chief executive officer of STPNOC). A participation agreement establishes an owners' committee with voting interests consistent with ownership interests.
As a holder of an ownership interest in STP, NRG South Texas LP is an NRC licensee and is subject to NRC regulation. The NRC license gives the Company the right only to possess an interest in STP but not to operate it. As a possession-only licensee, i.e., non-operating co-owner, the NRC's regulation of NRG South Texas LP is primarily focused on the Company's ability to meet its financial and decommissioning funding assurance obligations. In connection with the NRC license, the Company and its subsidiaries have a support agreement to provide up to $120 million to support operations at STP.
Decommissioning Trusts — Upon expiration of the operating licenses for the two generating units at STP, recently extended until 2047 and 2048, respectively, the co-owners of STP are required under federal law to decontaminate and decommission the STP facility. Under NRC regulations, a power reactor licensee generally must pre-fund the full amount of its estimated NRC 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.
NRG South Texas LP, through its 44% ownership interest, is the beneficiary of decommissioning trusts that have been established to provide funding for decontamination and decommissioning of STP. CenterPoint and AEP collect, through rates or other authorized charges to their electric utility customers, amounts designated for funding NRG South Texas LP's portion of the decommissioning of the facility. See also Item 15 — Note 6, Nuclear Decommissioning Trust Fund, to the Consolidated Financial Statements for additional discussion.
If the funds from the trusts are ultimately determined to be inadequate to decommission the STP facilities, the original owners of the Company's STP interests, CenterPoint and AEP, each will be required to collect, through their PUCT-authorized non-bypassable rates or other charges to customers, additional amounts required to fund NRG South Texas LP's obligations relating to the decommissioning of the facility. Following the completion of the decommissioning, if surplus funds remain in the decommissioning trusts, those excesses will be refunded to the respective rate payers of CenterPoint or AEP, or their successors.
Regional Regulatory Developments
NRG is affected by rule/tariff changes that occur in the ISO regions. For further discussion on regulatory developments see Item 15 — Note 23, 24, Regulatory Matters, to the Consolidated Financial Statements.
Gulf CoastTexas
MISOPublic Utility Commission of Texas’s Actions with Respect to Wholesale Pricing and Market Design — The PUCT continues to analyze and implement multiple options for promoting increased reliability in the wholesale electric market, including the adoption of a reliability standard for resource adequacy and market-based mechanisms to achieve this standard. During the 88th Regular Session, the Texas Legislature authorized deployment of the Performance Credit Mechanism ("PCM"), which will measure real-time contribution to system reliability and provide compensation for resources to be available, subject to certain "guardrails" such as an annual net cost cap, as part of its adoption of the PUCT Sunset Bill (House Bill 1500). The Texas Legislature also directed the PUCT to implement additional market design changes such as the creation of a new ancillary service called Dispatchable Reliability Reserve Service ("DRRS") to further increase ERCOT's capability to manage net load variability and firming requirements for new generation resources which penalize poor performance during periods of low grid reserves. The PUCT directed ERCOT to implement DRRS as a standalone product which will delay implementation until late 2025 or 2026. Additionally, through Senate Bill 2627, the Texas Legislature created the Texas Energy Fund, which received voter approval in November 2023, and will provide grants and low-interest loans to incentivize the development of more dispatchable generation and smaller backup generation in ERCOT. The PUCT has initiated a rulemaking proceeding to establish the process by which the Texas Energy fund loan proceeds will be distributed. A final rule creating the general structure of the loan program is expected to be adopted in March 2024.
Revisions to MISO Capacity Construct Operating Reserve Demand Curve ("ORDC")— On February 28, 2018, FERCAugust 3, 2023, the PUCT approved implementation of an enhancement to the ORDC as a bridge solution that was recommended by the ERCOT Technical Advisory Committee and the ERCOT board of directors. The ORDC enhancement will install price floors of $10 and $20 at reserve levels of 7,000 MW and 6,500 MW or below, respectively. ERCOT completed implementation on November 1, 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 MISO’s capacityFebruary 15 and 16, 2021, respectively, governing scarcity pricing in the ERCOT wholesale electricity market design, which together, re-affirm MISO’s existing capacity market structure. FERC also held that, even though there was a period of time between where MISO’s capacity market structure may not have just and reasonable, that FERC exercised its remedial authority not to rerun past auctions.during Winter Storm Uri. The Company has 30 days to seek an administrative rehearing with FERC. The eventual outcome of this proceeding will affect capacity prices in MISO and the incentive for generators in MISO to sell capacity into neighboring markets.
East/West
FERC’s Fast-Start Pricing Dockets —On December 28, 2017, notices were published regarding FERC’s initiation of FPA section 206 proceedings for the NYISO, PJM, and SPP to investigate these ISO pricing practices for fast-start generating resources. FERCThird Court found that the practicesPUCT exceeded its statutory authority by ordering the market price of each ISO regardingenergy to be set at the pricinghigh system wide offer cap due to scarcity conditions as a result of fast-start resources may be unjustfirm load shed occurring in ERCOT. The Third Court reversed the PUCT's orders and unreasonable becauseremanded the practices do not allow pricescase. On March 23, 2023, the PUCT filed a petition for review to reflect the marginal costSupreme Court of serving load. FERC also terminated its generic rulemaking into these issues.Texas seeking reversal of the Third Court's decision, which was granted on September 29, 2023. The proceeding is ongoing.Court received briefing on the merits and oral arguments occurred on January 30, 2024. The outcome of this proceedingappeal could affectpotentially require a retroactive repricing of the ERCOT 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. On February 23, 2024, NRG filed a notice of intent with the PUCT to terminate its existing VMP as of March 1, 2024.
ERCOT Request for Proposals for Winter Capacity — On October 2, 2023, ERCOT issued a Request for Proposals for Capacity ("RFP") for Winter 2023-2024. Proposals were due in early November to provide capacity for the December 1, 2023 to February 29, 2024 period. The RFP requirements were limited to demand response resources that have not participated in ERCOT or price formationresponsive products. Ultimately, ERCOT cancelled the procurement due to lack of participation by qualified participants.
Lubbock, Texas Transition to Competition — The customers of Lubbock Power and Light ("LP&L"), a municipally owned utility, will enter the Texas retail competitive market in the respective energy markets.March 2024. Starting in January 2024, LP&L customers can shop for a REP. Customers who do not select a REP by February 15, 2024 will be assigned to one of three default REPs, one of which is Reliant. LP&L customers will start transitioning to their chosen REP or a default REP on March 4, 2024.
PJM
Minimum Offer Price Rule Exemption Appeal —On July 7, 2017, the D.C. Circuit vacated a FERC order from 2013 relatedRevisions to an exemption to the Minimum Offer Price Rule, or MOPR, and remanded the issue back to FERC. On October 23, 2017, PJM re-filed its initial 2012 MOPR. On December 8, 2017, FERC rejected PJM's filing and directed PJM to submit a compliance filing reinstating the MOPR in effect prior to PJM's December 2012 filing. PJM submitted a compliance filing modifying certain PJM tariff sections, retaining the unit-specific exception, which FERC has accepted.
Generators’ Complaint on Existing Generation MOPR —On January 9, 2017, NRG, its trade association and other generators filed a joint amendment to the pending complaint seeking to apply the MOPR in the capacity market to existing resources that receive out-of-market subsidies. This filing amends the March 21, 2016 complaint filed by NRG and other companies related to ratepayer-funded subsidies approved by the PUCO. The national trade association sought expedited treatment to implement countermeasures to protect consumers and wholesale power markets from the negative effects of out-of-market subsidies, like the Zero Emission Credit. The complaint is pending at FERC.
2020/2021 PJM Auction Results Local Deliverability Area Reliability Requirement— On May 23, 2017, PJM announced the results of its 2020/2021 Base Residual Auction. NRG cleared approximately 3,992 MW of Capacity Performance product. NRG’s expected capacity revenues from theThe Base Residual Auction for the 2020/20212024/2025 delivery year arecommenced 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, 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 $268 million.
23 hours of Capacity Performance events from December 23-24, 2022 across PJM's entire footprint. The table below provides a detailed description of NRG’s 2020/2021 base residual auction results from May 23, 2017:
|
| | | | | | |
| | | Capacity Performance Product |
| Zone | | Cleared Capacity (MW)(a) | | Price ($/MW-day) |
| COMED | | 3,315 | | $ | 188.12 |
|
| EMAAC | | 519 | | $ | 187.87 |
|
| MAAC | | 158 | | $ | 86.04 |
|
| Total | | 3,992 | | |
(a) Includes imports. Does not include capacity sold by NRG Curtailment Solutions.
PJM Seasonal Capacity Proceeding —Company is subject to penalty and bonus payments related to the events. On November 17, 2016, PJM proposedApril 3, 2023, FERC approved PJM's request to allow winter-Winter Storm Elliott penalty payments to be spread over 9 months (with interest) and summer-peaking capacity resourcesallow future penalties to “aggregate” their seasonal capacity into an annual capacity product eligible to participate as Capacity Performance resources. NRG filed comments specifically supporting PJM’s proposal to modify the aggregation rules to allow seasonal capacity resources to aggregate across LDAs and to allow aggregations through RPM auctions. On January 23, 2017, PJM amended its proposal to address questions from FERC. On March 21, 2017, FERC issued a decision accepting PJM's seasonal capacity aggregation filing pursuant to FERC staff's delegated authority, since FERC did not have a quorum at the time. On February 23, 2018, FERC re-affirmed its prior order. Rehearings are pending at FERC. The outcome of this proceeding could have a material impact on future9 month window to be satisfied without interest. Multiple generators filed various complaints against PJM capacity prices.
Complaints Related to Extension of Base Capacity — In 2015, FERC approved changes to PJM’s capacity market, which included moving from the Base Capacity product to the higher performance Capacity Performance product over the course of a five year transition. Under this transition, as of the May 2017 BRA, the Base Capacity product will no longer be available. Several parties have filed complaints at FERC seeking to maintainalleging that PJM violated its Tariff in, among other things, the RPM Base Capacity product for at least one more delivery year or until such time as PJM develops a model for seasonal resources to participate. Ifmanner in which it operated the transition is delayed,system during Winter Storm Elliott and the resulting assessment of capacity prices could be materially impacted. The matters are pending at FERC.
Complaints Regarding Pseudo-Ties for Capacity — On April 6, 2017, Potomac Economics, the market monitor for MISO and NYISO, filed a complaint against PJM regarding the participation of external capacity resources in PJM’s auction. Currently, external resources must enter into a pseudo-tie agreement in order to sell capacity into PJM. The complaint alleges that the pseudo-tie requirement is causing market inefficiencies in PJM, New York and MISO and suggests a new protocol for incorporating external resources into PJM’s markets. In addition, other market participants have filed separate complaints at FERC against MISO or PJM, respectively, for issues resulting from pseudo-tied generators. The complainants argue that the generation owners with pseudo-ties from MISO to PJM are receiving double-charges for congestion. The outcome could impact the PJM, NYISO and MISO capacity markets.
Midwest Generation Reactive Power Compensation —performance penalties. On June 21, 2016,5, 2023, FERC issued an order directing Midwest Generationsetting the various complaints for settlement. A settlement in principle was filed with FERC on September 29, 2023 and was approved on December 19, 2023.
PJM Base Residual Auction Revisions and Delay — On April 11, 2023, PJM filed, and FERC subsequently approved, to make a compliance filing setting forth refundsdelay the Base Residual Auctions for payments received in violation of its 2004 reactive power settlement orthe 2025/2026 to show cause why it has not violated the settlement. FERC also ordered Midwest Generation to revise its tariff to reflect the costs of units continuing to provide reactive power or show cause why it should not be required to do so. FERC also referred this matter to FERC's Office of Enforcement. On June 30, 2016, Midwest Generation filed a revised tariff, and on July 22, 2016, Midwest Generation made a compliance filing as ordered by FERC.2028/2029 delivery years. On October 13, 2016,2023, PJM made two filings proposing to develop market reforms to improve the operation of the capacity market through changes to the Market Seller Offer Cap rules, changes to PJM's resource adequacy risk modeling and capacity accreditation processes, and changes to capacity performance enhancements. On January 30, 2024, FERC found that Midwest Generation should only be liable for refunds that accrued after bankruptcy on April 1, 2014 through June 30, 2016. On November 16, 2017, Midwest Generation filed its Offer of Settlement, which was approved by FERCaccepted certain reforms to PJM's resource adequacy risk modeling and accreditation processes; on February 22, 2018. In addition, FERC's Office6, 2024, FERC rejected PJM's proposed changes to certain Market Seller Offer Cap rules and capacity performance enhancements. The approved changes will be in effect for the 2025/2026 Base Residual Auction scheduled to occur in July 2024, and will impact both demand and supply characteristics.
PJM Files to Make Changes to the Performance Assessment Interval Trigger — On May 30, 2023, PJM filed proposed tariff revisions at FERC that narrow the definition of Enforcement has closedEmergency Actions used to determine Performance Assessment Intervals ("PAIs"). On July 28, 2023, FERC accepted the investigation into Midwest Generation without further action.tariff revisions, and PJM made its compliance filing on August 28, 2023. The new definition narrows the instances of when PAIs can occur and therefore decrease the instances of when capacity performance penalties are assessed.
New England
Competitive Auctions with Sponsored Resources Proposal (CASPR) Independent Market Monitor Market Seller Offer Cap Complaint —On January 8, 2018, ISO-NE filedMarch 18, 2021, finding that the CASPR proposal which attempts to accommodate state sponsored resources while maintaining competitive market pricing. On January 29, 2018, NRG protested certain aspectscalculation of the proposaldefault Market Seller Offer Cap was unjust and also supported ISO-NE’s beginning attemptsunreasonable, FERC issued an Order, which permitted the PJM May 2021 capacity auction for the 2022/2023 delivery rule to address state sponsored resources enteringcontinue under the capacity market. The outcome of this proceeding will potentially affect future capacity market prices.
Renewable Technology Resource (RTR) Exemption —In 2014, FERC approvedexisting rules and set a package of revisions that included a renewables exemption called the RTR Exemption. After FERC denied rehearing, the case was appealedprocedural schedule for parties to the D.C. Circuit. After a voluntary remand motion, the Court remanded the case back to FERC. In 2016,file briefs with possible solutions. On September 2, 2021, FERC issued an order reaffirmingin response to a complaint filed by the PJM Independent Market Monitor's proposal, which eliminated the Cost of New Entry-based Market Seller Offer Cap, implemented a limited default cap for certain asset classes based on going-forward costs and provided for unit specific cost review by the Independent Market Monitor for all other non-zero offers into the auctions. On October 4, 2021, as required by the Order, PJM submitted its decision. In 2017,compliance tariff and certain parties filed a groupmotion for rehearing, which was denied by operation of generators, including NRG,law. On February 18, 2022, FERC addressed the arguments raised on rehearing and rejected the rehearing requests. Multiple parties filed appeals at the Court of Appeals for the D.C. Circuit, and on August 15, 2023, the Court denied the petitions for review. On January 12, 2024, the generator trade association filed a petition for review with the D.C. Circuit. Briefing is complete. Oral argument is scheduled for April 13, 2018.U.S. Supreme Court to overturn the August 15, 2023 judgment.
Challenge to ISO-NE’s Capacity Carry Forward Rule California
California Resource Planning Proceedings— On February 2, 2018, the D.C. Circuit remanded a FERC order regarding how generators that previously received a seven-year “price lock” should be priced in future auctions, known as the Capacity Carry Forward Rule. The price-lock mechanism permits qualified new resources that clear the auction to receive their first-year clearing price for seven years. Because the underlying orders focused on the implementation of the Capacity Carry Forward Rule, this remand does not implicate the validity of the underlying price-lock. Because several auctions have been held under the existing rules, any subsequent order from FERC could affect future capacity prices in New England, as well as affect the price that non-price locked resources could receive from prior capacity auction.
2021/2022 ISO-NE Auction Results — On February 6, 2018, ISO-NE announced the results of its 2021/2022 forward capacity auction. NRG cleared 1,529 MW at $4.631 kW-month providing expected annualized capacity revenues of $85 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-month for the 2021/2022 deliverability year, are excluded from these results.
Massachusetts GHG Regulations — On September 11, 2017, multiple generators, including GenOn Energy, Inc. and the New England Power Generators Association, or NEPGA, filed complaints regarding the Massachusetts GHG regulations with the Superior Court in Massachusetts. The complaint alleges that the final regulation does not demonstrate a lowering of emissions and that the regulation violates the state’s Global Warming Solutions Act law. On January 30, 2018, the Massachusetts Supreme Judicial Court transferred the superior court cases to the Supreme Judicial Court for Suffolk County. At the same time, the Court stayed two pending appeals of siting certificates, one of which is the certificate of NRG’s Canal 3 development. The outcome of the matter may affect generators’ abilities to run their plants without violating environmental regulations.
Northern Pass Siting Application — On February 1, 2018, the New Hampshire Site Evaluation Committee denied the application for Northern Pass to cross the state with a 160-mile transmission line from Quebec into southern New Hampshire. The Northern Pass transmission line project had previously been awarded a contract by the State of Massachusetts, which is now in doubt. The addition of 1,000 MW of additional Canadian hydropower associated with Northern Pass would have affected energy and capacity prices.
Peak Energy Rent Adjustment Complaint — On September 30, 2016, the New England Power Generators Association, or NEPGA, filed a complaint against ISO-NE asking FERC to find the Peak Energy Rent, or PER, unjust and unreasonable. The PER adjustment reduces capacity payments on days where energy prices exceed a pre-defined level, known as the "PER strike price." On January 9, 2017, FERC granted NEPGA’s complaint requiring a change to the methodology used to calculate the PER strike price. FERC also directed the parties to determine any refunds for PER paid between September 30, 2016 and May 31, 2018. On July 26, 2017, NEPGA filed settlement documents at FERC, which NRG supported. On February 20, 2018, FERC accepted the settlement and directed ISO-NE to submit a compliance filing setting out the PER calculation.
New York
Independent Power Producers of New York (IPPNY) Complaint — On January 9, 2017, EPSA requested FERC to promptly direct the NYISO to file tariff provisions to address pending market concerns related to out-of-market payments to existing generation in the NYISO. This request was prompted by the ZEC program initiated by the NYSPSC. This request follows IPPNY’s complaint at FERC against the NYISO on May 10, 2013, as amended on March 25, 2014. The generators asked FERC to direct the NYISO to require that capacity from existing generation resources that would have exited the market but for out-of-market payments be mitigated. Failure to implement buyer-side mitigation measures could result in uneconomic entry, which artificially decreases capacity prices below competitive market levels.
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 noticed both an evidentiary and a collaborative track to address the functioning of the competitive retail markets. An administrative hearing commenced on November 29, 2017 asAs part of the evidentiary track, whichIntegrated Resource Procurement docket, the CPUC is ongoing.requiring that all LSEs procure a pro rata share of 15.5 GW of new non-fossil resource adequacy ("RA") from 2023 to 2026. The outcomenew RA program rules adopted in 2023 are now in an implementation phase with a compliance process likely to be continually recalibrated through the first quarter of 2024. CPUC jurisdictional retail providers will be required to procure RA that meets their hourly load shape beginning in 2025. The result of these changes may create upward pressure on RA prices through 2024, and if LSEs cannot meet their RA obligations, penalties and restrictions on serving new customers may be issued. As relief to the tightness of the evidentiaryRA market, the CPUC adopted a final decision in December 2023 to extend PG&E's
Diablo Canyon nuclear facility. The decision would allow the RA and collaborative processes, combined withGHG-free attributes of this 2-GW facility to be allocated to all LSEs to provide some relief to all LSEs' RA positions.
Other Regulatory Matters
From time to time, NRG entities may be subject to examinations, investigations and/or enforcement actions by federal, state and provincial licensing agencies and may face the outcomerisk of the appealpenalties for violation of the Reset Order, could affect the viability of the New York retail energy market.financial services, consumer protections and other applicable laws and regulations.
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 proceeding for at least six months, which was granted on November 3, 2017. During the six month suspension period, which could be extended, NRG will evaluate the progress of a procurement process initiated by SCE to replace the Puente Power Project.
Environmental Regulatory Matters
NRG is subject to numerous 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. Federal and state environmental laws historically have become more stringent over time. Future laws may require the addition of emissions controls or other environmental controls or impose restrictions on our operations, which could affect the Company's operations.operations including unit retirements. Complying with environmental laws often involves specialized human resources and significant capital and operating expenses, as well as occasionally curtailing operations. NRG decides to invest capital for environmental controls based on the relative certainty of the requirements, an evaluation of compliance options and the expected economic returns on capital.
A number of regulations that may affect the Company are under reviewhave been and continue to be revised by the EPA, including ESPS for GHGs,requirements regarding coal ash, disposal requirements, NAAQS revisions and implementation, and effluent limitation guidelines. NRG will evaluate the impact of these regulations as they are revised but cannot fully predict the impact of each until anticipated revisions and legal challenges are finally resolved.
Air
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. 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 havemay become more stringent. On February 7, 2024, the EPA released a prepublication version of a final rule that when published in the Federal Register will increase the stringency of the PM2.5 NAAQS. The Company maintains a comprehensive compliance strategy to address continuing and new requirements. Complying with increasingly stringent air regulations could require the installation of additional emissions control equipment at some NRG facilities or retiring of units if installing such controls is not economic. Significant changes to air regulatory programs affecting the Company are described below.
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.
Cross-State Air Pollution Rule — The EPA finalized CSAPR in 2011, which was intended to replace CAIR in January 2012, to address certain states' obligations to reduce emissions so that downwind states can achieve federal air quality standards. In December 2011, the D.C. Circuit stayed the implementation of CSAPR and then vacated CSAPR in August 2012 but kept CAIR in place until the EPA could replace it. In April 2014, 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 exceeded its authority by requiring certain reductions that were not necessary for downwind states to achieve federal standards. Although the D.C. Circuit kept the rule in place, the court ordered the EPA to revise the Phase 2 (or 2017) (i) SO2 budgets for four states including Texas and (ii) ozone-season NOx budgets for 11 states including Maryland, New Jersey, New York, Ohio, Pennsylvania and Texas. On October 26, 2016, the EPA finalized the CSAPR Update Rule, which reduces future NOx allocations and discounts the current banked allowances to account for the more stringent 2008 Ozone NAAQS and to address the D.C. Circuit's July 2015 decision. This rule has been challenged in the D.C. Circuit. The Company believes its investment in pollution controls and cleaner technologies leave the fleet well-positioned for compliance.
MATS — In 2012, the EPA promulgated standards (the MATS rule) to control emissions of HAPs from coal and oil-fired electric generating units. The rule established limits for mercury, non-mercury metals, certain organics and acid gases, which had to be met beginning in April 2015 (with some units getting a 1-year extension). In June 2015, the U.S. Supreme Court issued a decision in the case of Michigan v. EPA, and held that the EPA unreasonably refused to consider costs when it determined that it was "appropriate and necessary" to regulate HAPs emitted by electric generating units. The U.S. Supreme Court did not 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 costs to address the U.S. Supreme Court's ruling that the EPA had not properly considered costs. This finding has been challenged in the D.C. Circuit. On April 18, 2017, the EPA asked the D.C. Circuit to postpone oral argument that had been scheduled for May 18, 2017 because the EPA is closely reviewing the supplemental finding to determine whether it should reconsider all or part of the rule. On April 27, 2017, the D.C. Circuit granted the EPA's request to postpone the oral argument and hold the case in abeyance. While NRG cannot predict the final outcome of this rulemaking, NRG believes that because it has already invested in pollution controls and cleaner technologies, the fleet is well-positioned to comply with the MATS rule.
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 2015,2019, the EPA finalizedpromulgated the Clean Power Plan, orACE rule, which rescinded the CPP, addressing GHGwhich had sought to broadly regulate CO2 emissions from existing EGUs.the power sector. On January 19, 2021, the D.C. Circuit vacated the ACE rule (but on February 9, 2016,22, 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 over the next several years.
Cross-State Air Pollution Rule ("CSAPR") — On March 15, 2023, the EPA signed and released a prepublication of a final rule that 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 CPP.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 D.C. Circuit heard oral argument onfinal rule decreases, over time, the ozone-season NOx allowances allocated to generators in the states not affected by the judicial stays beginning in 2023 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 ato withdraw the existing Texas Sulfur Dioxide Trading Program and replace it with unit-specific SO2 limits for 12 units in Texas to address requirements to improve visibility at National Parks and Wilderness areas. If finalized as proposed, the rule to repealwould result in more stringent SO2 limits for two of the CPP.Company's coal-fired units in Texas. The Company believescannot predict the CPP is not likely to survive.outcome of this proposal.
Greenhouse Gas Emissions — NRG emits CO2 (and small quantities of other greenhouse gases, or GHGs,GHGs) when generating electricity at mosta majority of its facilities. The graphs presented below illustrateNearly all of NRG's domestic GHG emissions of CO2e for 2015, 2016 and 2017. A significant majority (>99%) of NRG's emission sources are subject to federal (U.S. EPA) GHG reporting requirements programs. NRG anticipates further reductionsrequirements.
NRG's climate goals are to reduce greenhouse gas emissions by 50% by 2025, from its current 2014 base year, and to achieve net-zero emissions by 2050. Greenhouse gas emissions included in CO2e NRG's goals are directly controlled emissions, emissions from purchased electricity for NRG's consumption and emissions from employee business travel. In March 2021, the Science Based Targets initiative validated NRG's 2025 and 2050 goals as aligned with a 1.5 degree Celsius trajectory. This validation was based on NRG’s business in 2020, prior to its acquisition of Direct Energy and Vivint.Following the acquisitions, the magnitude of NRG’s indirect emissions changed, and the Company modernizesis currently in the fleet. process of analyzing theseemissions.
From 2016 to 2017,the current 2014 base year through 2023, the Company's directly controlled CO2e 2e emissions decreased from 4858 million metric tons to approximately 4624 million metric tons, representing a 4% reduction year over year.cumulative 58% reduction. The primary factor leadingdecrease is attributed to the decreased emissions include reductions in fleet widefleet-wide annual net generation due to a continuedand an overall market-driven shift towards increased generationaway from natural gas over coal. The Company's goal is to reduce CO2e emissions by 50% by 2030, and 90% by 2050, using 2014coal as a baseline.primary fuel to natural gas. The achievement of NRG's 2025 emissions reduction targets could be impacted by volatility within the power markets, driven by market conditions and changes in regulatory policies.
The effects from federal, regional or state regulationAs of GHGs onDecember 31, 2023, less than 5% of the Company's financial performance will dependconsolidated revenues were derived from coal-fired operating assets.
The following charts reflect the Company’s domestic generation portfolio, including leased facilities and those accounted for through equity method investments, but excluding the battery storage and remaining renewables activity. Prior year information on a number of factors, including the outcome of the legal challengesU.S. CO2e emissions and actions of the current U.S. presidential administration.generation was adjusted to remove divested assets.
Byproducts, Wastes, Hazardous Materials and Contamination
Byproducts
In April 2015, the EPA finalized thea rule regulating byproducts of coal combustion (e.g.(e.g., ash and gypsum) as solid wastes under the RCRA. On September 13, 2017,August 21, 2018, the D.C. Circuit found, among other things, that the EPA grantedhad not adequately regulated unlined ponds and legacy surface impoundments. On August 28, 2020, the petition for reconsideration thatEPA finalized "A Holistic Approach to Closure Part A: Deadline to Initiate Closure," which amended the Utility Solid Waste Activities Group filed in May 2017. The Company has evaluatedApril 2015 Rule to address the impactAugust 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 legacy surface impoundments and has accrued its environmental and asset retirement obligations under the rule based on current estimates as of December 31, 2017.Federal Permit Program.
Domestic Site Remediation Matters
Under certain federal, state and local environmental laws, a current or previous owner or operator of anya 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 including the Comprehensive Environmental Response, Compensation and Liability Act of 1980 as amended by the Superfund Amendments and Reauthorization Act of 1986, or SARA, impose liability without regard to whether the owner knew of or caused the presence of the hazardous substances, and the courts have interpreted liability under such laws to be strict (without fault) and joint and several. Cleanup obligations can often be triggered during the closure or decommissioning of a facility, in addition to spills during its operations. Further discussions
Jewett Mine Lignite Contract — The Company's Limestone facility historically burned lignite obtained from the Jewett mine. Active mining ceased as of affectedDecember 31, 2016; however, the Company remains responsible for reclamation activities and is responsible for all reclamation costs. NRG sites can be found in Item 15 — Note 24, Environmental Matters, tohas recorded an adequate ARO liability. The Railroad Commission of Texas has imposed a bond obligation of approximately $112 million for the Consolidated Financial Statements.
Nuclear Waste — The federal government's program to construct a nuclear waste repository at Yucca Mountain, Nevada was discontinued in 2010. Since 1998, the U.S. DOE has been in defaultreclamation 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 obligationsJewett mine, which NRG supports through surety bonds. The cost of the owners andreclamation may exceed the U.S. DOE, includingvalue of the fees to be paidbonds. NRG may provide additional performance assurance if required 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.Railroad Commission of Texas.
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 was extended through an addendum dated January 24, 2014, to 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 was reviewed and accepted. 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.Water
Under the federal Low-Level Radioactive Waste Policy Act of 1980, as amended, 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 capacity is adequate for on-site storage until a site in Andrews County, Texas becomes fully operational.
Water
Clean Water Act —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.
Once Through Cooling Regulation — In August 2014, 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 the rule. Accordingly,(iii) changing several deadlines. 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 ruleend of 2028 at its domestic coal units outside of Texas, and installing appropriate controls by the end of 2025 at its two plants that have coal-fired units in Texas. On March 29, 2023, the EPA proposed revisions to the ELG and sought comments, which the EPA is revised.analyzing.
Regional Environmental Developments
New Source Review Ash Regulation in Illinois— In 2007, Midwest Generation received an NOV fromOn July 30, 2019, Illinois enacted legislation that required the EPA alleging that past work at Crawford, Fisk, Joliet, Powerton, Waukegan and Will County generating stations violated NSR and other regulations. These alleged violations are the subject of litigation described in Item 15 — Note 22, Commitments and Contingencies. Additionally, in April 2013, the Connecticut Department of Energy and Environmental Protection issued four NOVs alleging that past work at oil-fired combustion turbines at the Torrington Terminal, Franklin, Branford and Middletown generating stations violatedstate to promulgate regulations regarding NSR.
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 locatedcoal ash at surface impoundments. On April 15, 2021, the Indian River facility. On October 1, 2007,state promulgated the implementing regulation, which became effective on April 21, 2021. 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 no further action was required in relation to surface waterhas applied for initial operating permits and that a previously planned shoreline stabilization project would satisfactorily address shoreline erosion. The landfill itself required a Remedial Investigationconstruction permits (for closure 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, the Company's Closure Report and the Company's Long Term Stewardship Plan. The cost of completing the workretrofits) as required by the approved remediation planregulation and is consistent with amounts budgeted in early 2016waiting for permits to be issued by the Illinois EPA.
Houston Nonattainment for 2008 Ozone Standard — During the fourth quarter of 2022, the EPA changed the Houston area’s classification from Serious to Severe nonattainment for the 2008 Ozone Standard. Accordingly, Texas is required to develop a new control strategy and remediation was completed in 2017. The estimated cost to comply with the Long-Term Stewardship Plan was addedsubmit it 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 development and performance of a Natural Resource Damage Assessment at the Burton Island Old Ash Landfill. NRG is currently working with DNREC and other trustees to close out the assessment process.
RGGI — The Company operates generating units in Connecticut, Delaware, Maryland, and New York that are subject to RGGI,EPA, which is a regional cap and trade system. In 2013, each of these states finalized a rule that reduced and will continue to reduce the number of allowances through 2020. The nine RGGI states re-evaluated the program and published a model rule to further reduce the number of allowances. The revisions being currently contemplated could adversely impact NRG's results of operations, financial condition and cash flows.expected by May 2024.
Texas Regional Haze — On October 17, 2017, the EPA promulgated a final rule creating a Texas-only SO2 cap-and-trade program 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. The rule has been challenged by several environmental groups in the Fifth Circuit of the U.S. Court of Appeals.
Customers
NRG sells to a wide variety of customers. No individual customer accounted for 10% or more of NRG's total revenuecustomers, primarily end-use customers in 2017.the residential, commercial and industrial, and wholesale sectors. The Company owns and operates power plants to generate and sell power to wholesale customers, such as utilities and other intermediaries. The Company also directly sells to end-use customers inhad no customer that comprised more than 10% of the residential, commercial and industrial sectors. NRG also receives significantCompany's consolidated revenues from PJM in its capacity as the regional transmission organization for the PJM footprint.year ended December 31, 2023.
EmployeesHuman Capital
As of December 31, 2017,2023, NRG and its consolidated subsidiaries had 18,131 employees, including NRG Yield, Inc., had 5,9405,187 active smart home direct sales and installation individuals, which are largely seasonal. Approximately 4% of the Company's employees approximately 24% of whom were covered by U.S. collective bargaining agreements. During 2017,2023, the Company did not experience any labor stoppages or labor disputes at any of its facilities.
NRG believes its employees are vital to its success and is committed to offering employees a rewarding career that provides opportunities for growth and the ability to make valuable contributions toward the achievement of the Company’s business objectives. NRG focuses on safety, health and wellness, diversity, equity and inclusion, talent development and total rewards for its employees.
Safety
Safety is embedded in the culture at NRG. The Company strives to begin meetings with a safety moment and regularly reminds its employees that safety comes first. NRG has achieved its targeted top decile safety record of Occupational Safety and Health Administration recordable injury rates in each of the 5 previous years.
The following chart reflects the Company's 5 year safety record, excluding Vivint Smart Home which uses different industry specific safety benchmarks.
Health and Wellness
For several years, NRG has invested in the health and well-being of its employees and their families. NRG provides programs that holistically support its employees’ physical, emotional and financial wellness, allowing employees the opportunity to take control of their well-being and focus on what matters most to them for a healthy, secure future.
For the 2023 plan year, the Company included well-being goals in the Annual Incentive Plan (AIP), ensuring participants are motivated to improve their physical, emotional and financial well-being.
Diversity, Equity and Inclusion
NRG is committed to diversity, equity and inclusion (DE&I) as an integral way the Company operates. In 2023, NRG completed a gender and race pay equity study to analyze the Company's pay decisions in light of gender, race, or other similar factors. The study demonstrated equitable pay practices after accounting for job level, experience, tenure and location. The Company first conducted this study in 2020 and committed to conduct the study every three years. In 2023, Forbes and Statista recognized NRG as one of The Best Employers for Diversity. Also in 2023, NRG created designated reflection rooms in its headquarters to accommodate religious practices and reflection. NRG held its first Lunar New Year's celebrations hosted by VIVIDH, the Company's Asian American Pacific Islander Business Resource Group. The Company also hosted its inaugural listening session in recognition of Canada's National Day for Truth and Reconciliation sponsored by RISE, its Indigenous Communities Business Resource Group.
Talent Development
NRG deploys various talent development strategies and programs with the goal of ensuring a pipeline of leadership that can execute on the Company’s strategy and drive value for all stakeholders. The Board of Directors regularly engages with management on leadership development and succession planning, including providing feedback on development plans and bench strength for key senior leader positions. The Board of Directors also has a structured program that allows directors to interact directly with individuals deeper within the organization whom management, through a robust talent assessment program, as well as mentoring relationships, has identified as high potential future leaders. In 2021, the Company launched an annual Emerging Leaders Program to strengthen the identified pipeline of future leaders and create a cohort of high potential candidates for leadership positions. In 2023, the Company launched a front-line leader program called Peak Leadership with the intent to onboard first-level leaders into their leadership role in select business units and is planning to expand its impact in 2024. The Company has a performance management tool that emphasizes a continuous feedback loop and a robust online training curriculum with topics including leadership, communication and productivity.
Total Rewards
NRG seeks to provide market competitive compensation and benefits, benchmarked against direct peers, industry, and, where appropriate, general peers. To ensure incentives are properly aligned with business needs and can attract and retain qualified employees, the Compensation Committee of the Board of Directors actively reviews the Company's total rewards programs, including benchmarking programs against peer groups, assessing the risks of programs and evaluating the design of the short-term and long-term incentive programs. NRG continues to evaluate its benefits and offerings taking into consideration the needs of its employees to ensure they are competitive and best serve its employees. Every two years, the Company engages an independent third-party to benchmark its compensation and benefits programs against its peers and report the results to the Compensation Committee of the Board of Directors.
For further discussion and recent available data regarding the Company’s efforts and programs please see the Company’s 2023 Proxy Statement and 2022 Sustainability Report, which are available on the Company’s website at: www.nrg.com. Information included in these documents is not intended to be incorporated into this Form 10-K.
Available Information
NRG's annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to section 13(a) or 15(d) of the Exchange Act are available free of charge through the SEC's website, www.sec.gov, and through the Company's website, www.nrg.com, as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC. The Company also routinely posts press releases, presentations, webcasts, sustainability reports and other information regarding the Company on the Company's website. The information posted on the Company's website is not a part of this report.
Item 1A — Risk Factors
NRG's risk factors are grouped into the following categories: (i) Risks Related to the Acquisition of Vivint Smart Home; (ii) Risks Related to the Operation of NRG's Business; (iii) Risks Related to Governmental Regulation and Laws; and (iv) Risks Related to Economic and Financial Market Conditions, and the Company's Indebtedness.
Risks Related to the Acquisition of Vivint Smart Home
The acquisition of Vivint Smart Home may not achieve its intended results and its integration may disrupt or have a negative impact on the Company’s business.
Achieving the anticipated cost savings and operating efficiencies from the acquisition of Vivint Smart Home is subject to risks, including whether the businesses of NRG Energy, Inc.and Vivint Smart Home are integrated in an efficient and effective manner. These risks include, but are not limited to:
•the difficulty of managing and integrating Vivint Smart Home and its operations;
•difficulties in implementing and maintaining uniform processes, systems, standards, controls, procedures, practices, policies and compensation standards;
•unanticipated issues in integrating information technology, communications, and other systems;
•the possibility of faulty assumptions underlying expectations regarding the integration process;
•the potential difficulty in managing an increased number of locations and employees;
•difficulty addressing any possible differences in corporate cultures and management philosophies; and
•the effect of any government regulations which relate to the business acquired.
Many of these factors are outside of the Company’s control. Failure to address these risks effectively could result in increased costs, lower-than-expected revenues or income generated by the combined company and diversion of management's time and energy and could have an adverse effect on the Company's business, financial results and prospects.
Risks Related to the Operation of NRG's Business
The GenOn Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code, and NRG is subject to the risks and uncertainties associated with bankruptcy proceedings.
On the Petition Date, the GenOn Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. GenOn Mid-Atlantic, as well as its consolidated subsidiaries, and REMA, did not file for relief under Chapter 11.
NRG is subject to a number of risks and uncertainties associated with the Chapter 11 Cases, which may lead to potential adverse effects on NRG’s business, results of operations, or financial condition. NRG cannot assure you of the outcome of the Chapter 11 Cases. Potential risks to NRG associated with the Chapter 11 Cases include the following:
the length of time the GenOn Entities will operate under the Chapter 11 proceedings and their ability to successfully emerge, including with respect to obtaining any necessary regulatory approvals;
the ability of the GenOn Entities to consummate their plan of reorganization;
risks associated with third party motions, proceedings and litigation in the Chapter 11 proceedings, which may interfere with the GenOn Entities’ plan of reorganization;
NRG’s and the GenOn Entities’ ability to manage contracts that are critical to NRG’s operations, and to obtain and maintain appropriate credit and other terms with customers, suppliers and service providers;
NRG’s ability to attract, retain and motivate key employees;
NRG’s ability to fund and execute its business plan;
the disposition or resolution of all pre-petition claims against NRG and the GenOn Entities; and
NRG’s ability to maintain existing customers and vendor relationships and expand sales to new customers.
The Settlement Agreement may not be consummated if certain conditions are not met. If the Settlement Agreement is not consummated, NRG may not be entitled to receive certain benefits contemplated by the Restructuring Support Agreement and plan of reorganization.
Under the Restructuring Support Agreement to which GenOn, NRG and certain of GenOn's and GenOn Americas Generation's senior unsecured noteholders are parties, each of them agreed to support Bankruptcy Court approval of the Settlement Agreement, subject to conditions.
While the Bankruptcy Court approved the Settlement Agreement and confirmed the proposed plan of reorganization on December 12, 2017, there can be no assurance that the conditions to the effectiveness of either the Settlement Agreement or plan of reorganization will be satisfied. In addition, GenOn is entitled to terminate the Restructuring Support Agreement and consider alternative transactions in accordance with its fiduciary duties. If the Settlement Agreement or plan of reorganization is not consummated, NRG may not receive certain of the benefits contemplated by the Restructuring Support Agreement.
The Chapter 11 Cases may disrupt NRG's business and may materially and adversely affect NRG's operations.
NRG has attempted to minimize the adverse effect of the GenOn Entities’ Chapter 11 Cases on NRG's relationships with its employees, suppliers, customers and other parties. Nonetheless, NRG's relationships with its employees, suppliers, customers and other parties may be adversely impacted by negative publicity or otherwise and NRG's operations could be materially and adversely affected. In addition, the Chapter 11 Cases could negatively affect NRG's ability to attract new employees and retain existing high performing employees or executives, which could materially and adversely affect NRG's operations.
As a result of the Chapter 11 Cases, NRG's historical financial information will not be indicative of NRG's future financial performance.
NRG's corporate structure will be significantly altered under any plan of reorganization. As of June 14, 2017, GenOn and its consolidated subsidiaries were deconsolidated from NRG's financial statements. Consequently, NRG's results of operations following the deconsolidation will not be comparable to the financial condition and results of operations reflected in NRG's historical financial statements for periods prior to the deconsolidation.
NRG adopted and initiated the Transformation Plan. If the Transformation Plan does not achieve its expected benefits, there could be negative impacts to NRG’s business, results of operations and financial condition.
NRG adopted and initiated the 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 components: (i) operations and cost excellence; (ii) portfolio optimization; and (iii) capital structure and allocation enhancements.
As part of the Transformation, Plan, on February 6, 2018, NRG and GIP entered into a purchase and sale agreement for NRG to sell its ownership in NRG Yield, Inc. and its renewables platform to GIP for cash of $1.375 billion, subject to certain adjustments. Also on February 6, 2018, NRG and Cleco entered into a purchase and sale agreement for NRG to sell its South Central business to Cleco for cash of $1.0 billion, subject to certain adjustments. Both of these transactions are subject to various closing conditions and approvals.
NRG may be unable to fully implement the components of the Transformation Plan, in which case, NRG would not realize the anticipated benefits. Alternatively, such components of the Transformation Plan, even if implemented, may not result in the anticipated benefits to NRG’s business, results of operations and financial condition in a timely manner if at all. Further, NRG could experience unexpected delays, business disruptions resulting from supporting these initiatives during and following completion of these activities, decreased productivity, adverse effects on employee morale and employee turnover as a result of such initiatives, any of which may impair NRG’s ability to achieve anticipated results or otherwise harm NRG’s business, results of operations and financial condition.
The proposed sales of assets to GIP and Cleco could be delayed or fail to close, or otherwise cause unanticipated issues, which could adversely affect NRG's business, results of operations and financial condition.
As described above, on February 6, 2018, NRG entered into a purchase and sale agreement with GIP pursuant to which NRG agreed to sell its ownership interest in NRG Yield, Inc. and NRG’s Renewables platform. Also on February 6, 2018, NRG and Cleco entered into a purchase and sale agreement for Cleco to purchase NRG's South Central business. The proposed sales are subject to numerous closing conditions, including, among others, the receipt of certain consents and regulatory approvals. A number of the closing conditions are outside of NRG’s control and it cannot be predicted with certainty whether all of the required closing conditions will be satisfied or waived or if other uncertainties may arise. In addition, regulators could impose additional requirements or obligations as conditions for their approval, which may be burdensome. If such closing conditions are not met or additional obligations are imposed, the proposed sales may not be consummated at all or may encounter delays or other roadblocks that are not currently anticipated. Planning and executing the proposed separation and sale of NRG’s renewables platform will require significant time, effort, and expense, and may divert management’s attention from other aspects of NRG’s business operations, and any delays in completion of the proposed sale may increase the amount of time, effort, and expense that NRG devotes to the transactions, which could adversely affect NRG’s other operations. The current price of NRG’s stock may reflect an assumption that the pending sales will occur and failure to complete the proposed sales could result in a decline in NRG’s stock price. In addition, even if NRG completes the proposed sales, the actual impacts on NRG's business and financial results may differ from the anticipated results.
NRG's financial performance may be impacted by price fluctuations in the retail and wholesale power and natural gas markets, as well as fluctuations in coal and oil markets and other market factors that are beyond the Company's control.
Market prices for power, capacity, ancillary services, natural gas, coal, oil and oilrenewable energy credits are unpredictable and tend to fluctuate substantially. Unlike most other commodities, electricElectric power can only be stored on a very limited basis and generally must be produced concurrently with its use. As a result, power prices are subject to significant volatility due to supply and demand imbalances, especially in the day-ahead and spot markets. Long-Long and short-term power and gas prices may also fluctuate substantially due to other factors outside of the Company's control, including:
•changes in generation capacity in the Company’s markets, including the addition of new supplies of power as a result of the development of new plants, expansion of existing plants, the continued operation of uneconomic power plants due to state subsidies, retirement of existing plants or additionaladdition of new transmission capacity;
environmental regulations and legislation;
•electric supply disruptions, including plant outages and transmission disruptions;
•changes in power and gas transmission infrastructure;
fuel •transportation capacity constraints or inefficiencies;
changes in law, including judicial decisions;
•weather conditions, including extreme weather conditions and seasonal fluctuations, including the effects of climate change;
•changes in commodity prices and the supply of commodities, including but not limited to natural gas, coal and oil;
•changes in the demand for power or gas, or in patterns of power or gas usage, including the potential development of demand-side management tools and practices, distributed generation, and more efficient end-use technologies;
•development of new fuels, new technologies and new forms of competition for the production of power;
fuel price volatility;
•economic and political conditions;
•changes in law, including judicial decisions, environmental regulations and environmental legislation; and
•federal, state and provincial power regulations and legislation, and regulations and actions of the ISO and RTOs.
While retail rates are generally designed to allow retail sellers of electricity and natural gas to pass through price fluctuations and other changes to costs, the Company may not be able to pass through all such changes to customers. For example, serving retail power customers in ISOs that have a capacity market exposes the Company to the risk that capacity costs can change and RTOs;may not be recoverable, or the Company may engage in sales of power at fixed prices. Additionally, increases in wholesale costs to retail customers may cause additional customer defaults or increased customer attrition, or may be impacted by regulatory rules.
federal and state power regulations and legislation;Further, in low natural gas price environments, natural gas can be the more cost-competitive fuel compared to coal for generating electricity. The Company enters into guaranteed supply contracts to provide for the amount of coal needed to operate its base load coal-fired generating facilities. The Company may experience periods where it holds excess amounts of coal if fuel
pricing results in prices relatedthe Company reducing or idling coal-fired generating facilities. In addition, the Company may incur costs to RECs; and
changesterminate supply contracts for coal in capacity prices and capacity markets.excess of its generating requirements.
Such factors and the associated fluctuations in power prices have affected the Company's wholesale power operating resultsand retail profitability in the past and willare expected to continue to do so in the future.
ManyVolatile power and gas supply costs and demand for power and gas could adversely affect the financial performance of NRG's retail operations.
The Company's earnings and cash flows could be adversely affected in any period in which the wholesale power generation facilities operate, wholly or partially, without long-termgas prices rise at a greater rate than the rates the Company can charge to customers. The price of wholesale electricity and gas supply purchases associated with the retail operations' energy commitments can be different than that reflected in the rates charged to customers due to, among other factors:
•varying supply procurement contracts used and the timing of entering into related contracts;
•subsequent changes in the overall price of natural gas;
•daily, monthly or seasonal fluctuations in the price of natural gas relative to the 12-month forward prices;
•transmission and transportation constraints and the Company's ability to move power sale agreements.or gas to its customers; and
Many•changes in market heat rate (i.e., the relationship between power and natural gas prices).
The Company's earnings and cash flows could also be adversely affected in any period in which its customers' actual usage of electricity or gas significantly varies from the forecasted usage, which could occur due to, among other factors, weather events, changes in usage patterns, competition and economic conditions.
NRG's facilities operatetrading operations and use of hedging agreements could result in financial losses that negatively impact its results of operations, and NRG's hedging activities may increase the volatility in the Company's quarterly and annual financial results.
The Company typically enters into hedging agreements, including contracts to purchase or sell commodities at future dates and at fixed prices, to manage the commodity price risks inherent in its business. The Company’s risk management policies and hedging procedures may not mitigate risk as "merchant" facilities without long-termplanned, and the Company may fail to fully or effectively hedge its commodity supply and price risk. In addition, these activities, although intended to mitigate price volatility, expose the Company to other risks. When the Company sells or buys power salesor gas forward, it gives up the opportunity to buy or sell at the future price, which not only may result in lost opportunity costs but also may require the Company to post significant amounts of cash collateral or other credit support to its counterparties. The Company also relies on counterparty performance under its hedging agreements for some or all of their generating capacity and output and therefore areis exposed to market fluctuations. Without the benefitcredit quality of long-term power sales agreements for these assets, NRG cannot be sure that it will be able to sell any or allits counterparties under those agreements. Further, if the values of the financial contracts change in a manner that the Company does not anticipate, or if a counterparty fails to perform under a contract, it could harm the Company's business, operating results or financial position.
NRG does not typically hedge the entire exposure of its operations against commodity price volatility. To the extent it does not hedge against commodity price volatility, the Company's results of operations and financial position may be improved or diminished based upon movement in commodity prices.
NRG may engage in trading activities, including the trading of power, generated by these facilities at commercially attractive rates ornatural gas, fuel, emissions allowances, environmental attributes and credits, weather, and other physical and financial commodity related products that these facilities will be ableare not directly related to operate profitably. This could lead to future impairmentsthe operation of the Company's property, plantgeneration facilities or the management of related risks. These trading activities take place in volatile markets and equipment orsome of these trades could be characterized as speculative. This trading activity may expose the Company to the closingrisk of certain of its facilities, resulting in economicsignificant financial losses and liabilities, which could have a material adverse effect on its business and financial condition.
NRG generally attempts to balance its fixed-price physical and financial purchases and sales commitments in terms of contract volumes and the timing of performance and delivery obligations through the use of financial and physical derivative contracts. These derivatives are accounted for in accordance with the FASB ASC 815, Derivatives and Hedging ("ASC 815"), which requires the Company to record all derivatives on the balance sheet at fair value with changes in the fair value resulting from fluctuations in the underlying commodity prices immediately recognized in earnings, unless the derivative qualifies for cash flow hedge accounting treatment or a scope exception. As a result, the Company's quarterly and annual results are subject to significant fluctuations caused by changes in market prices.
Competition may have a material adverse effect on NRG's results of operations, cash flows and the market value of its assets.
The Company's retail operations face competition for customers. Competitors may offer different products, lower prices, and other incentives which may attract customers away from the Company. In some retail electricity markets, the principal competitor may be the incumbent utility. The incumbent utility often has the advantage of long-standing relationships with its customers and strong brand recognition. Furthermore, NRG may face competition from other energy service providers, other
energy industry participants, or nationally branded providers of consumer products and services, who have, and may in the future, develop businesses and offerings that compete with NRG.
The Company's smart home services market faces competition from residential security companies as well as other companies that are able to bundle their existing offerings, such as cable, telecommunications and internet service, with automation and monitored security services, and from do-it-yourself smart home systems, which customers are able to install without subscription services.
The Company’s plant operations face competition from newer or more efficient plants owned by competitors, which may put some of the Company's plants at a disadvantage to the extent these competitors are able to consume the same or less fuel as the Company's plant. Over time, the Company's plants may be unable to compete with these more efficient plants, which could result in asset retirements.
NRG’s competitors may have greater liquidity, greater access to credit and other financial resources, lower cost structures, more effective risk management policies and procedures, greater ability to incur losses, longer-standing relationships with customers, greater brand awareness, greater potential for profitability from retail sales or greater flexibility in the timing of their sale of generation capacity and ancillary services than NRG does. Competitors may also have better access to subsidies or other out-of-market payments that put NRG at a competitive disadvantage.
NRG's competitors may be able to respond more quickly to new laws or regulations or emerging technologies, or devote greater resources to marketing of retail energy and home services than NRG can. In addition, current and potential competitors may make strategic acquisitions or establish cooperative relationships among themselves or with third parties. Accordingly, it is possible that new competitors or alliances among current and new competitors may emerge and rapidly gain significant market share.
There can be no assurance that NRG will be able to compete successfully against current and future competitors, and any failure to do so would have a material adverse effect on the Company's business, financial condition, results of operations and cash flow.
NRG’s strategy relies, in part, on its ability to cross-serve and optimize its network of retail and Smart Home services customers, and if it is unable to retain existing customers and expand their use of the Company’s products and services, its expected growth and operating results could be adversely affected.
As part of NRG’s growth strategy, it is important for the Company to cross-sell energy sales and services to smart home services subscribers and smart home services to residential retail customers. As the Company continues pursuing cross-selling opportunities between these customers, there can be no assurances that its efforts in this regard will be successful. Additionally, for the Company to be successful in such cross-selling opportunities, it must retain its existing customers. The length of the terms for which NRG’s retail customers are contracted can be for multi-year periods, but many customers are contracted for a period of one year or cash flows.less. Smart home services customers historically have entered into subscriptions that range from three to five years. These customers are not obligated to, and may not, renew their contracts or subscriptions after the expiration of their original commitments. If customers terminate their contracts, do not renew their contracts or do not expand their use of NRG’s products and services, the Company’s growth strategy may not be successful and its expected results of operations may be adversely affected.
NRG's costs, results of operations, financial condition and cash flows could be adversely impacted by disruption of its fuel supplies.
NRG relies on natural gas, coal and oil to fuel a majority of its power generation facilities. Delivery of these fuels to the facilities is dependent uponGrid operations depend on the continuing financial viability of contractual counterparties, as well as upon the infrastructure (including rail lines, rail cars, barge facilities, roadways, riverways and natural gas pipelines) available to serve each generation facility.facilities and to ensure that there is sufficient power produced to meet retail demand. As a result, the Company isCompany’s wholesale generation facilities are subject to the risks of disruptions or curtailments in the production of power at its generation facilities if no fuel is available at any price, or if a counterparty fails to perform or if there is a disruption in the fuel delivery infrastructure.
NRG has sold forward a substantial portion ofroutinely hedges both its coalwholesale sales and nuclear power in orderpurchases to lock in long-term prices that it deemed to be favorable at the time it entered into the forward power sales contracts.support its retail load obligations. In order to hedge itsthese obligations, under these forward power sales contracts, the Company has enteredmay enter into long-term and short-term contracts for the purchase and delivery of fuel. Many of the forward power sales contracts do not allow the Company to pass through changes in fuel costs or discharge the power sale obligations in the case of a disruption in fuel supply due to force majeure events or the default of a fuel supplier or transporter. Disruptions in the Company's fuel supplies or power supply arrangements may therefore require it to find alternative fuelsupply replacement power either by running its other, higher cost power plants or by obtaining power from third-party sources at higher costs, to find other sources of power to deliver to counterparties at a higher cost,market prices that could substantially exceed the contract price, or to pay damages to counterparties for failure to deliver power or sell electricity or natural gas as contracted. Any such event could have a material adverse effect on the Company's financial performance.
NRG also buys significant quantities ofenergy and fuel on a short-term or spot market basis. Prices for all of the Company's fuels fluctuate, sometimes risingrise or fallingfall significantly over a relatively short period of time. The price NRG can obtain for the sale of energy may not rise at the same rate, or may not rise at
all, to match a rise in fuel or delivery costs. Retail rates may also not rise at the same rate or may not rise at all. This may have a material adverse effect on the Company's financial performance. Changes in market prices for natural gas, coal and oil may result from the following:
weather conditions;
seasonality;
demand for energy commodities and general economic conditions;
disruption or other constraints or inefficiencies of electricity, gas or coal transmission or transportation;
additional generating capacity;
availability and levels of storage and inventory for fuel stocks;
natural gas, crude oil, refined products and coal production levels;
changes in market liquidity;
federal, state and foreign governmental regulation and legislation; and
the creditworthiness and liquidity and willingness of fuel suppliers/transporters to do business with the Company.
NRG's plant operating characteristics and equipment, particularly at its coal-fired plants, often dictate the specific fuel quality to be combusted. The availability and price of specific fuel qualities may vary due to supplier financial or operational disruptions, transportation disruptions and force majeure. At times, coal of specific quality may not be available at any price or the Company may not be able to transport such coal to its facilities on a timely basis. In this case, the Company may not be able to run the coal facility even if it would be profitable. Operating a coal facility with different quality coal can lead to emission or operating problems. If the Company had sold forward the power from such a coal facility, it could be required to supply or purchase power from alternate sources, perhaps at a loss. This could have a material adverse impact on the financial results of specific plants and on the Company's results of operations.
Changes in the price of coal and natural gas could cause the Company to hold excess coal inventories and incur contract termination costs.
Low natural gas prices can cause natural gas to be the more cost-competitive fuel compared to coal for generating electricity. Because the Company enters into guaranteed supply contracts to provide for the amount of coal needed to operate its base load coal-fired generating facilities, the Company may experience periods where it holds excess amounts of coal if fuel pricing results in the Company reducing or idling coal-fired generating facilities. In addition, the Company may incur costs to terminate supply contracts for coal in excess of its generating requirements.
Volatile power supply costs and demand for power could adversely affect the financial performance of NRG's retail businesses.
Although NRG is the primary provider of its retail businesses' wholesale electricity supply requirements, the retail businesses purchase a significant portion of their supply requirements from third parties. As a result, financial performance depends on the ability to obtain adequate supplies of electric generation from third parties at prices below the prices it charges its customers. Consequently, the Company's earnings and cash flows could be adversely affected in any period in which the retail businesses' wholesale electricity supply costs rise at a greater rate than the rates it charges to customers. The price of wholesale electricity supply purchases associated with the retail businesses' energy commitments can be different than that reflected in the rates charged to customers due to, among other factors:
varying supply procurement contracts used and the timing of entering into related contracts;
subsequent changes in the overall price of natural gas;
daily, monthly or seasonal fluctuations in the price of natural gas relative to the 12-month forward prices;
transmission constraints and the Company's ability to move power to its customers; and
changes in market heat rate (i.e., the relationship between power and natural gas prices).
The retail businesses' earnings and cash flows could also be adversely affected in any period in which its customers' actual usage of electricity significantly varies from the forecasted usage, which could occur due to, among other factors, weather events, competition and economic conditions.
There may be periods when NRG will not be able to meet its commitments under forward sale or purchase obligations at a reasonable cost or at all.
A substantial portion of the output from NRG's coal and nuclear facilities has been sold forward under fixed price power sales contracts through 2018 and the Company also sells forward the output from its intermediate and peaking facilities when it is commercially advantageous to do so. The Company also sellsmay sell fixed price gas as a proxy for power. Because the obligations under most of thesethe Company's forward sale agreements are not contingent on a unit being available to generate power, NRG is generally required to deliver power to the buyer, even in the event of a plant outage, fuel supply disruption or a reduction in the available capacity of the unit. To the extent that the Company does not have sufficient lower-cost capacity to meet its commitments under its forward sale obligations, the Company would be required to supply replacement power either by running its other, higher cost power plants or by obtaining power from third-party sources at market prices that could substantially exceed the contract price. If NRG fails to deliver the contracted power, it would be required to pay the difference between the market price at the delivery point and the contract price, and the amount of such payments could be substantial.
In the Gulf Coast region, NRG has long-term contracts with rural cooperatives that require it to serve all of the cooperatives' requirements at prices for energy that generally reflect the cost of coal-fired generation. On December 19, 2013, the Entergy region joined the MISO RTO, which employs a two settlement market in which NRG submits bids for energy to cover its load obligations and submits offers to sell energy from its resources. Given the “full requirements” obligation contained in the cooperative contracts, and the possibility of unplanned forced outages of its generation, NRG may be exposed to locational market prices as a net buyer of energy for certain periods, which could have a negative impact on NRG's financial returns from its Gulf Coast region.
NRG's trading operations and use of hedging agreements could result in financial losses that negatively impact its results of operations.
The Company typically enters into hedging agreements, including contracts to purchase or sell commodities at future dates and at fixed prices, to manage the commodity price risks inherent in its power generation operations. These activities, although intended to mitigate price volatility, expose the Company to other risks. When the Company sells power forward, it gives up the opportunity to sell power at higher prices in the future, which not only may result in lost opportunity costs but also may require the Company to post significant amounts of cash collateral or other credit support to its counterparties. The Company also relies on counterparty performance under its hedging agreements and is exposed to the credit quality of its counterparties under those agreements. Further, if the values of the financial contracts change in a manner that the Company does not anticipate, or if a counterparty fails to perform under a contract, it could harm the Company's business, operating results or financial position.
NRG does not typically hedge the entire exposure of its operations against commodity price volatility. To the extent it does not hedge against commodity price volatility, the Company's results of operations and financial position may be improved or diminished based upon movement in commodity prices.
NRG may engage in trading activities, including the trading of power, fuel and emissions allowances that are not directly related to the operation of the Company's generation facilities or the management of related risks. These trading activities take place in volatile markets and some of these trades could be characterized as speculative. The Company would expect to settle these trades financially rather than through the production of power or the delivery of fuel. This trading activity may expose the Company to the risk of significant financial losses which could have a material adverse effect on its business and financial condition.
NRG may not have sufficient liquidity to hedge market risks effectively.
The Company is exposed to market risks through its power marketing business,retail and wholesale operations, which involvesinvolve the purchase of electricity and natural gas for resale, the sale of energy, capacity and related products, and the purchase and sale of fuel, transmission services and emission allowances. These market risks include, among other risks, volatility arising from location and timing differences that may be associated with buying and transporting fuel, converting fuel into energy and delivering energy to a buyer.
NRG undertakes to hedge these marketingmarket activities through agreements with various counterparties. Many of the Company's agreements with counterparties include provisions that require the Company to provide guarantees, offset ofor netting arrangements, letters of credit, a first lien on assets and/or cash collateral to protect the counterparties against the risk of the Company's default or insolvency. The amount of such credit support that must be provided typically is based on the difference between the price of the commodity in a given contract and the market price of the commodity. Significant movements in market prices can result in the Company being required to provide cash collateral and letters of credit in very large amounts. The effectiveness of the Company's strategy may depend on the amount of collateral available to enter into or maintain these contracts, and liquidity requirements may be greater than the Company anticipates or will be able to meet. Without a sufficient amount of working capital to post as collateral in support of performance guarantees or as a cash margin, the Company may not be able to manage price volatility effectively or to implement its strategy. An increase in the amount of letters of credit or cash collateral required to be provided to the Company's counterparties may negatively affect the Company's liquidity and financial condition.
Further, if retail customers use more power or gas than expected, or if any of NRG's facilities experience unplanned outages, the Company may be required to procure replacementadditional power or gas at spot market prices to fulfill contractual commitments. Without adequate liquidity to meet margin and collateral requirements, the Company may be exposed to significant losses, may miss significant opportunities, and may have increased exposure to the volatility of spot markets.
The accounting for NRG's hedging activities may increase the volatility inoperation of the Company's quarterlybusinesses is subject to advanced persistent cyber-based security threats and annual financial results.integrity risk. Attacks on NRG's infrastructure that breach cyber/data security measures could expose the Company to significant liabilities, reputational damage, regulatory action, and disrupt business operations, which could have a material adverse effect.
NRG engagesNumerous functions affecting the efficient operation of NRG’s businesses depend on the secure and reliable storage, processing and communication of electronic data and the use of sophisticated computer hardware and software systems, much of which is connected (directly or indirectly) to the internet. As a result, NRG's information technology systems and infrastructure, and those of its vendors and suppliers, are susceptible to cyber-based security threats which could compromise confidentiality, integrity or availability. While the Company has controls in commodity-related marketingplace designed to protect its infrastructure, such breaches and price-risk management activities in orderthreats are becoming increasingly sophisticated and complex, requiring continuing evolution of its program. Any such breach, disruption or similar event that impairs NRG's information technology infrastructure could disrupt normal business operations and affect the Company's ability to financially hedge its exposure to market risk with respect to electricity sales fromcontrol its generation assets, fuel utilized by those assetsprovide smart home services, maintain
confidentiality, availability and emission allowances.
NRG generally attempts to balance its fixed-price physicalintegrity of restricted data, access retail customer information and financial purchases and sales commitments in terms of contract volumes and the timing of performance and delivery obligations through the use of financial and physical derivative contracts. These derivatives are accounted for in accordancelimit communication with the FASB ASC 815, Derivatives and Hedging, or ASC 815,third parties, which requires the Company to record all derivatives on the balance sheet at fair value with changes in the fair value resulting from fluctuations in the underlying commodity prices immediately recognized in earnings, unless the derivative qualifies for cash flow hedge accounting treatment. Whether a derivative qualifies for cash flow hedge accounting treatment depends upon it meeting specific criteria used to determine if the cash flow hedge is and will remain appropriate for the term of the derivative. All economic hedges may not necessarily qualify for cash flow hedge accounting treatment. As a result, the Company's quarterly and annual results are subject to significant fluctuations caused by changes in market prices.
Competition in wholesale power markets maycould have a material adverse effect on the Company.
As part of the continuing development of new and modified reliability standards, the FERC has approved changes to its Critical Infrastructure Protection reliability standards and has established standards for assets identified as "critical cyber assets." Under the Energy Policy Act of 2005, the FERC can impose penalties (up to $1 million per day, per violation) for failure to comply with mandatory electric reliability standards, including standards to protect the power system against potential disruptions from cyber/data and physical security breaches.
Further, the Company's retail, Home and Services businesses, as well as Vivint Smart Home's smart home platform, require accessing, collecting, storing and transmitting sensitive customer data in the ordinary course of business. Concerns about data privacy have led to increased regulation and other actions that could impact NRG's results of operations, cash flowsbusinesses and changes in data privacy and data protection laws and regulations or any failure to comply with such laws and regulations could adversely affect the market value of its assets.
NRG has numerous competitors in all aspects of itsCompany's business and additional competitorsfinancial results. NRG's retail, Home, Services and Smart Home businesses may enter the industry. Because many of the Company's facilities are old, newer plants owned by the Company's competitors are often more efficient than NRG's aging plants, which may put some of the Company's plants at a competitive disadvantageneed to the extent the Company's competitors are ableprovide sensitive customer data to consume the same or less fuel as the Company's plants consume. Over time, the Company's plants may be squeezed out of their markets or may be unable to compete with these more efficient plants.
In NRG's power marketingvendors and commercial operations, NRG competes on the basis of its relative skills, financial position andservice providers who require access to capital with other providers of electric energythis information in the procurement of fuel and transportationorder to provide services, such as call center operations, to such businesses. The services and the sale of capacity, energynetworks and related products. In order to compete successfully,information systems utilized by the Company seeksmay be at risk for breaches as a result of third-party actions, employee or vendor error, malfeasance or other factors.
Although the Company takes precautions to aggregate fuel suppliesprotect its infrastructure, it has been, and will likely continue to be, subject to attempts at competitive prices from different sources and locations and to efficiently utilize transportation services from third-party pipelines, railwaysphishing and other fuel transporterscybersecurity intrusions. International conflict increases the risk of state-sponsored cyber threats and transmission services from electric utilities.
Other companiesescalated use of cybercriminal and cyber-espionage activities. In particular, the current geopolitical climate has further escalated cybersecurity risk, with which NRG competes may have greater liquidity, greater access to creditvarious government agencies, including the U.S. Cybersecurity & Infrastructure Security Agency, issuing warnings of increased cyber threats, particularly for U.S. critical infrastructure. While the Company has not experienced a cyber/data event causing any material operational, reputational or financial impact, it recognizes the growing threat within the general marketplace and other financial resources, lower cost structures, more effective risk management policiesthe industry, and procedures, greater ability to incur losses, longer-standing relationships with customers, greater potential for profitability from ancillary services or greater flexibility in the timing of their sale of generation capacity and ancillary services than NRG does.
NRG's competitors may be able to respond more quickly to new laws or regulations or emerging technologies, or to devote greater resources to the construction, expansion or refurbishment of their power generation facilities than NRG can. In addition, current and potential competitors may make strategic acquisitions or establish cooperative relationships among themselves or with third parties. Accordingly, itthere is possible that new competitors or alliances among current and new competitors may emerge and rapidly gain significant market share. There can be no assurance that NRG will be able to compete successfullyprevent any such impacts in the future. If a material breach of the Company's information technology systems were to occur, the critical operational capabilities and reputation of its business may be adversely affected, customer confidence may be diminished, and NRG may be subject to substantial legal or regulatory scrutiny and claims, any of which may contribute to potential legal or regulatory actions against currentthe Company, loss of customers, fines, penalties or other sanctions and future competitors, and any failure to do so wouldotherwise have a material adverse effecteffect. Any loss or disruption of critical operational capabilities to support the Company's generation, commercial or retail operations, loss of customers, or loss of confidential or proprietary data through a breach, unauthorized access, disruption, misuse or disclosure could adversely affect NRG's reputation, expose the Company to material legal or regulatory claims and impair the Company's ability to execute its business strategy, which could have a material adverse effect. In addition, NRG may experience increased capital and operating costs to implement increased security for its information technology infrastructure. NRG cannot provide any assurance that such events and impacts will not be material in the future, and the Company's efforts to deter, identify and mitigate future breaches may require additional significant capital and may not be successful.
NRG relies on storage, transportation assets and suppliers, which it does not own or control, to deliver natural gas.
The Company depends on natural gas pipelines and other transportation and storage facilities owned and operated by third parties to deliver natural gas to wholesale and retail markets and to provide retail energy services to customers. The Company's ability to provide natural gas for its present and projected customers will depend upon its suppliers' ability to obtain and deliver supplies of natural gas, as well as NRG's ability to acquire supplies. Factors beyond the control of the Company and its suppliers may affect the Company's ability to deliver such supplies. These factors include other parties' control over the drilling of new wells and the facilities to transport natural gas to the Company's receipt points, development of additional interstate pipeline infrastructure, availability of supply sources competition for the acquisition of natural gas, priority allocations, impact of severe weather disruptions to natural gas supplies and the regulatory and pricing policies of federal and state regulatory agencies, as well as the availability of Canadian reserves for export to the U.S. Energy deregulation legislation may increase competition among natural gas utilities and impact the quantities of natural gas requirements needed for sales service. If supply, transportation or storage is disrupted, including for reasons of force majeure, the ability of the Company to sell and deliver its products and services may be hindered. As a result, the Company may be responsible for damages incurred by its customers, such as the additional cost of acquiring alternative supply at then-current market rates. These conditions could have a material impact on the Company's business, financial condition, results of operations and cash flow.flows.
Operation of power generation facilities involves significant risks and hazards customary to the power industry that could have a material adverse effect on NRG's revenues and results of operations, and NRG may not have adequate insurance to cover these risks and hazards.
The ongoing operation of NRG's facilities involves risks that include the breakdown or failure of equipment or processes, performance below expected levels of output or efficiency and the inability to transport the Company's productproducts to its customers in an efficient manner due to a lack of transmission capacity. Unplanned outages of generating units, including extensions of scheduled outages due to mechanical failures or other problems occur from time to time and are an inherent risk of the
Company's business. Unplanned outages typically increase the Company's operation and maintenance expenses and may reduce the Company's revenues as a result of selling fewer MWh or incurring non-performance penalties and/or require NRG to incur significant costs as a result of running one of its higher cost units or obtaining replacement power from third parties in the open market or running one of its higher cost units to satisfy the Company's forward power sales obligations. NRG's inability to operate the Company's plants efficiently, manage capital expenditures and costs, and generate earnings and cash flow from the Company's asset-based businesses could have a material adverse effect on the Company's results of operations, financial condition or cash flows. While
In addition, NRG maintains insurance, obtains warranties from vendorsprovides plant operations and obligates contractorscommercial services to meet certain performance levels,a variety of third parties. There is a risk that mistakes, mis-operations or actions taken by these third parties could be attributed to NRG, including the proceedsrisk of such insurance, warrantiesinvestigation or performance guarantees may not be adequatepenalties being assessed to coverNRG in connection with the Company's lost revenues, increased expensesservices it offers, or liquidated damages payments shouldthat regulators could question whether NRG had the Company experience equipment breakdown or non-performance by contractors or vendors.appropriate safeguards in place.
Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of rotating equipment and delivering electricity to transmission and distribution systems. In addition to natural risks such as earthquake, flood, lightning, hurricane and wind, other hazards, such as fire, explosion, structural collapse and machinery failure are inherent risks in the Company's operations. These and other hazards can cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment, contamination of, or damage to, the environment and suspension of operations. The occurrence of any one of these events may result in NRG being named as a defendant in lawsuits asserting claims for substantial damages, including for environmental cleanup costs, personal injury and property damage and fines and/or penalties.
NRG maintains an amount of insurance protection that it considers adequate, obtains warranties from vendors and obligates contractors to meet certain performance levels, but the Company cannot provide any assurance that its insurancethese measures will be sufficient or effective under all circumstances and against all hazards or liabilities to which it may be subject. A successful claim for which the Company is not fullyadequately insured or protected could hurt its financial results and materially harm NRG's financial condition. NRG cannot provide any assurance that its insurance coverage will continue to be available at all or at rates or on terms similar to those presently available. Any losses not covered by insurance could have a material adverse effect on the Company's financial condition, results of operations or cash flows.
Supplier and/or customer concentration, the inability of suppliers to meet their obligations and dependence on third-party service providers may expose the Company to significant financial credit or performance risks and adversely affect NRG's results of operations, cash flows and financial condition.
NRG often relies on a single contracted supplier or a small number of suppliers for the provision and transportation of fuel, chemicals and other services required for the operation of certain of its facilities. If these suppliers cannot perform these services, the Company utilizes the marketplace. There can be no assurance that the marketplace can provide these services as, when and where required or at comparable prices. The Company also relies on a number of sole or limited source suppliers for critical components for its smart home products and services, and those services are dependent on third-party cellular, telecommunications and/or internet providers.
The failure of any supplier or customer to fulfill its contractual obligations to NRG, the inability of NRG to source products and services on acceptable terms, if at all, and the failure of third parties to provide services to its customers that are necessary for the Company’s smart home services could have a material adverse effect on the Company's financial results. As a result, the financial performance of the Company's facilities is dependent on the credit quality of, and continued performance by, suppliers and customers, which cannot be guaranteed.
Maintenance, expansion and refurbishment of power generation facilities involve significant risks that could result in unplanned power outages or reduced output and could have a material adverse effect on NRG's results of operations, cash flows and financial condition.
Many of NRG's facilities are old and require periodic maintenance and repair. Any unexpected failure, including failure associated with breakdowns, forced outages or any unanticipated capital expenditures could result in reduced profitability.
NRG cannot be certain of the level of capital expenditures that will be required due to changing environmental and safety laws (including changes in the interpretation or enforcement thereof), needed facility repairs and unexpected events (such as natural disasters or terrorist attacks). The unexpected requirement of large capital expenditures could have a material adverse effect on the Company's liquidity and financial condition.
If NRG significantly modifies a unit, the Company may be required to install the best available control technology or to achieve the lowest achievable emission rates as such terms are defined under the new source review provisions of the CAA, which would likely result in substantial additional capital expenditures.
The Company may incur additional costs or delays in the development, construction and operation of new plants, improvements to existing plants, or the implementation of environmental control equipment at existing plants and may not be able to recover their investment or complete the project.
The Company is developing or constructing new generation facilities, improving its existing facilities and adding environmental controls to its existing facilities. The development, construction, expansion, modification and refurbishment of power generation facilities involve many risks, including:
inability to obtain sufficient funding on reasonable terms and/or necessary government financial incentives;
delays in obtaining necessary permits and licenses;
inability to sell down interests in a project or develop successful partnering relationships;
environmental remediation of soil or groundwater at contaminated sites;
interruptions to dispatch at the Company's facilities;
supply interruptions;
work stoppages;
labor disputes;
weather interferences;
unforeseen engineering, environmental and geological problems, including those related to climate change;
unanticipated cost overruns;
exchange rate risks; and
failure of contracting parties to perform under contracts, including EPC contractors.
Any of these risks could cause NRG's financial returns on new investments to be lower than expected or could cause the Company to operate below expected capacity or availability levels, which could result in lost revenues, increased expenses, higher maintenance costs and penalties. Insurance is maintained to protect against these risks, warranties are generally obtained for limited periods relating to the construction of each project and its equipment in varying degrees, and contractors and equipment suppliers are obligated to meet certain performance levels. The insurance, warranties or performance guarantees, however, may not be adequate to cover increased expenses. As a result, a project may cost more than projected and may be unable to fund principal and interest payments under its construction financing obligations, if any. A default under such a financing obligation could result in the Company losing its interest in a power generation facility.
Furthermore, where the Company has partnering relationships with a third party, the Company is subject to the viability and performance of the third party. The Company's inability to find a replacement contracting party, particularly an EPC contractor, where the original contracting party has failed to perform, could result in the abandonment of the development and/or construction of such project, while the Company could remain obligated on other agreements associated with the project, including PPAs.
If the Company is unable to complete the development or construction of a facility or environmental control, or decides to delay, downsize, or cancel such project, it may not be able to recover its investment in that facility or environmental control. Furthermore, if construction projects are not completed according to specification, the Company may incur liabilities and suffer reduced plant efficiency, higher operating costs and reduced net income.
NRG and its subsidiaries have guaranteed the performance of third parties, which may result in substantial costs in the event of non-performance.
NRG and its subsidiaries have issued certain guarantees of the performance of others, which obligate NRG and its subsidiaries to perform in the event that the third parties do not perform. In the event of non-performance by the third parties, NRG could incur substantial cost to fulfill their obligations under these guarantees. Such performance guarantees could have a material impact on the operating results, financial condition, or cash flows of the Company.
The Company's development programs are subject to financing and public policy risks that could adversely impact NRG's financial performance or result in the abandonment of such development projects.
While NRG currently intends to develop and finance its more capital intensive projects on a non-recourse or limited recourse basis through separate project financed entities and intends to seek additional investments in most of these projects from third parties, NRG anticipates that it will need to make significant equity investments in these projects. NRG may also decide to develop and finance some of the projects using corporate financial resources rather than non-recourse debt, which could subject NRG to significant capital expenditure requirements and to risks inherent in the development and construction of new generation facilities. In addition to providing some or all of the equity required to develop and build the proposed projects, NRG's ability to finance these projects on a non-recourse basis is contingent upon a number of factors, including the terms of the EPC contracts, construction costs, PPAs and fuel procurement contracts, capital markets conditions, the availability of tax credits and other government incentives for certain new technologies. To the extent NRG is not able to obtain non-recourse financing for any project or should credit rating agencies attribute a material amount of the project finance debt to NRG's credit, the financing of the development projects could have a negative impact on the credit ratings of NRG.
NRG may also choose to undertake the repowering, refurbishment or upgrade of current facilities based on the Company's assessment that such activity will provide adequate financial returns. Such projects often require several years of development and capital expenditures before commencement of commercial operations, and key assumptions underpinning a decision to make such an investment may prove incorrect, including assumptions regarding construction costs, timing, available financing and future fuel and power prices.
Furthermore, the viability of the Company's renewable development projects are contingent on public policy mechanisms including production and investment tax credits, cash grants, loan guarantees, accelerated depreciation tax benefits, renewable portfolio standards, or RPS, and carbon-related mandates or controls. These mechanisms have been implemented at the state and federal levels to support the development of renewable generation, demand-side and smart grid, and other clean infrastructure technologies. The availability and continuation of public policy support mechanisms will drive a significant part of the economics and viability of the Company's development program and expansion into clean energy investments.
The Company’s renewables business has a pipeline of projects across the utility scale and distributed generation markets, including both organically developed projects and projects acquired from third-parties. If a number of the projects fail to proceed to construction or are not completed, the Company’s business, financial condition or operating results could be materially adversely affected.
The development process is long and includes many steps such as project siting, financing, construction, permitting, government approvals and the negotiation of project development agreements. There can be no assurance that the projects in the Company’s renewables project pipeline will be completed on schedule or within budget, generate revenues, or receive the necessary financing for construction, among other risks. As the Company develops its renewables project pipeline, some of the projects in the pipeline may not be completed or proceed to construction as a result of various factors. These factors may include changes in applicable laws and regulations, including government incentives, environmental concerns regarding a project or changes in the economics related to a project, including the ability to finance a particular project. If a number of projects are not completed, the Company’s business, financial condition or operating results could be materially adversely affected.
Supplier and/or customer concentration at certain of NRG's facilities may expose the Company to significant financial credit or performance risks.
NRG often relies on a single contracted supplier or a small number of suppliers for the provision of fuel, transportation of fuel and other services required for the operation of certain of its facilities. If these suppliers cannot perform, the Company utilizes the marketplace to provide these services. There can be no assurance that the marketplace can provide these services as, when and where required or at comparable prices.
At times, NRG relies on a single customer or a few customers to purchase all or a significant portion of a facility's output, in some cases under long-term agreements that account for a substantial percentage of the anticipated revenue from a given facility. The Company has also hedged a portion of its exposure to power price fluctuations through forward fixed price power sales and natural gas price swap agreements. Counterparties to these agreements may breach or may be unable to perform their obligations. NRG may not be able to enter into replacement agreements on terms as favorable as its existing agreements, or at all. If the Company was unable to enter into replacement PPAs, the Company would sell its plants' power at market prices. If the Company is unable to enter into replacement fuel or fuel transportation purchase agreements, NRG would seek to purchase the Company's fuel requirements at market prices, exposing the Company to market price volatility and the risk that fuel and transportation may not be available during certain periods at any price.
The failure of any supplier or customer to fulfill its contractual obligations to NRG could have a material adverse effect on the Company's financial results. Consequently, the financial performance of the Company's facilities is dependent on the credit quality of, and continued performance by, suppliers and customers.
The Company's retail businesses may lose a significant number of retail customers due to competitive marketing activity by other retail electricity providers which could adversely affect the financial performance of the Company's retail businesses.
The Company's retail businesses face competition for customers. Competitors may offer different products, lower prices, and other incentives, which may attract customers away from NRG's retail businesses. In some retail electricity markets, the principal competitor may be the incumbent utility. The incumbent utility has the advantage of long-standing relationships with its customers and strong brand recognition. Furthermore, NRG's retail businesses may face competition from a number of other energy service providers, other energy industry participants, or nationally branded providers of consumer products and services, who may develop businesses that will compete with NRG and its retail businesses.
NRG relies on power transmission and distribution facilities that it does not own or control and that are subject to transmission constraints within a number of the Company's core regions. If these facilities fail to provide NRG with adequate transmission capacity, the Company may be restricted in its ability to deliver wholesale electric power to its customers and the Company may either incur additional costs or forego revenues. Conversely, improvements to certain transmission systems could also reduce revenues.
NRG depends on transmission and distribution facilities owned and operated by others to deliver the wholesale power it sells from the Company's power generation plants to its customers. If transmission or distribution is disrupted, including by force majeure events, or if the transmission capacityor distribution infrastructure is inadequate, NRG's ability to sell and deliver wholesale power may be adversely impacted. If a region's power transmission infrastructure is inadequate, the Company's recovery of wholesale costs and profits may be limited. If restrictive transmission price regulation is imposed, the transmission companies may not have sufficient incentive to invest in expansion of transmission infrastructure. The Company also cannot predict
whether transmission or distribution facilities will be expanded in specific markets to accommodate competitive access to those markets.
In addition, in certain of the markets in which NRG operates, energy transmission congestion may occur and the Company may be deemed responsible for congestion costs if it schedules delivery ofassociated with power between congestion zones during times when congestion occurs betweensales or purchases, or retail sales, particularly where the zones.Company’s load is not co-located with its retail sales obligations. If NRG were liable for such congestion costs, the Company's financial results could be adversely affected.
Rates and terms for service of certain residential and commercial customers in Alberta are subject to regulatory review and approval.
The Company hasowns Direct Energy Regulated Services, which serves as a regulated rate supplier for residential and commercial energy customers in portions of the province of Alberta. It is required to engage in regulatory approval proceedings as a part of the process of establishing the terms and rates for sales of power and natural gas. These proceedings typically involve multiple parties, including governmental bodies and officials, consumer advocacy groups and various consumers of energy, who have differing concerns but also have the common objective of limiting rate increases or even reducing rates. Decisions are subject to appeal, potentially leading to additional uncertainty associated with the approval proceedings. The potential duration of such proceedings creates a risk that rates ultimately approved by the applicable regulatory body may not be sufficient for the Company to recover its costs by the time the rates become effective. Established rates are also subject to subsequent reviews by regulators, whereby various portions of rates could be adjusted, subject to refund or disallowed. In certain instances, the Company could agree to negotiated settlements related to various rate matters and other cost recovery elements. These settlements are subject to regulatory approval. The ultimate outcome and timing of regulatory rate proceedings have a significant amount of generation located in load pockets, making that generation valuable, particularly with respect to maintaining the reliability of the transmission grid. Expansion of transmission systems to reduce or eliminate these load pockets could negatively impact the value or profitability of the Company's existing facilities in these areas.
The Company’s use and enjoyment of real property rights for its projects may be adversely affected by the rights of lienholders and leaseholders that are superior to those of the grantors of those real property rights to the Company.
Solar and wind projects generally are, and are likely to be, locatedeffect on land occupied by the project pursuant to long-term easements and leases. The ownership interests in the land subject to these easements and leases may be subject to mortgages securing loans or other liens (such as tax liens) and other easement and lease rights of third parties (such as leases of oil or mineral rights) that were created prior to the project’s easements and leases. As a result, the project’s rights under these easements or leases may be subject, and subordinate, to the rights of those third parties. The Company performs title searches and obtains title insurance to protect itself against these risks. Such measures may, however, be inadequate to protect the Company against all risk of loss ofto recover its rights to usecosts or earn an adequate return. In addition, subsequent legislative or regulatory action could alter the landterms on which the renewable projects are located, whichregulated business operates and future earnings could havebe negatively impacted. The Company also operates a material adverse effectcompetitive energy supply business in Alberta that is not subject to rate regulation and is subject to stringent requirements to segregate operations and information relating to the competitive business from the regulated business. Failure to comply with these and other requirements on the Company’s business financial condition and results of operations.
One ofcould subject the Company's subsidiaries, NRG Yield, Inc., is a publicly traded corporation, which may involve a greater exposureregulated and competitive businesses in Alberta to legal liability than the Company's historic business operations.
One of the Company's subsidiaries is NRG Yield, Inc., a publicly traded corporation. NRG's controlling voting interest in NRG Yield, Inc.fines, penalties, and the position of certain of its executive officers that are servingrestrictions on the Board of Directors of NRG Yield, Inc. or as executive officers may increase the possibility of claims of breach of fiduciary duties including claims of conflicts of interest relatedability to NRG Yield, Inc. Any liability resulting from such claims could have a material adverse effect on NRG's future business, financial condition, results of operations and cash flows.
continue business.
Because NRG owns less than a majority of the ownership interests of some of its project investments, the Company cannot exercise complete control over their operations.
NRG has limited control over the operation of some project investments and joint ventures because the Company's investments are in projects where it beneficially owns less than a majority of the ownership interests. NRG seeks to exert a degree of influence with respect to the management and operation of projects in which it owns less than a majority of the ownership interests by negotiating to obtain positions on management committees or to receive certain limited governance rights, such as rights to veto significant actions. However, the Company may not always succeed in such negotiations. NRG may be dependent on its co-venturers to operate such projects. The Company's co-venturers may not have the level of experience, technical expertise, human resources management andor other attributes necessary to operate these projects optimally. The approval of co-venturers also may be required for NRG to receive distributions of funds from projects or to transfer the Company's interest in projects.
NRG may be unable to integrate the operations of acquired entities in the manner expected.
NRG enters into acquisitions that result in various benefits, including, among other things, cost savings and operating efficiencies. Achieving the anticipated benefits of these acquisitions depends on whether the businesses can be integrated into NRG in an efficient and effective manner. The integration process could take longer than anticipated and could result in the loss of valuable employees, the disruption of NRG's businesses, processes and systems or inconsistencies in standards, controls, procedures, practices, policies and compensation arrangements, any of which could adversely affect the Company's ability to achieve the anticipated benefits of the acquisitions. NRG may have difficulty addressing possible differences in corporate cultures and management philosophies. Failure to achieve these anticipated benefits could result in increased costs or decreases in the amount of expected revenues and could adversely affect NRG's future business, financial condition, operating results and prospects.
Future acquisition or disposition activities could involve unknown risks and may have materially adverse effects.effects and NRG may be subject to trailing liabilities from businesses that it disposes of or that are inactive.
NRG may in the future make acquisitionsacquire or dispositionsdispose of businesses or assets, acquire or sell books of retail customers, or pursue other business activities, directly or indirectly, through subsidiaries that involve a number of risks. The acquisition of companies and assets, and their integration, is subject to substantial risks, including the failure to identify material problems during due diligence, the risk of over-paying for assets or customers, the abilityinability to retain customers and the inability to arrange financing for an acquisition as may be required or desired. Further, the integration and consolidation of acquisitions requires substantial human, financial and other resources and, ultimately, the Company's acquisitions may not be successfully integrated. In the case of dispositions, such risks may relate to employment matters, counterparties, regulators and other stakeholders in the disposed business, risks relating to separating the separation of disposed assets from NRG’s business, risks related to the management of NRG’s ongoing business, risks unknown to NRG at the time, and other financial, legal and operational risksmatters related to such disposition.disposition, which may be unknown to NRG at the time. In addition, NRG may be subject to material trailing liabilities from disposed businesses. Any such risk may result in one or more costly disputes or litigation. There can be no assurances that any future acquisitions will perform as expected or that the returns from such acquisitions will support the indebtedness incurred to acquire them or the capital expenditures needed to develop them. There can also be no assurances that NRG will realize the anticipated benefits from any such dispositions. The failure to realize the anticipated returns or benefits from an acquisition or disposition could adversely affect NRG's results of operations, cash flows and financial condition.
Negative publicity may damage NRG's reputation or its brands and negatively impact its business, financial condition, results of operations and ability to attract and retain highly qualified employees.
NRG’s reputation and brands could be damaged for numerous reasons, including negative views of the Company’s environmental impact, sustainability goals, supply chain practices, product and service offerings, sponsorship relationships, charitable giving programs and public statements made by Company officials. Additionally, the Company is from time to time named in investigations, claims and lawsuits arising in the ordinary course of business, and customers have in the past communicated complaints to consumer protection organizations, regulators or the media. Negative claims or publicity regarding the Company or its operations, offerings, practices or customer service may damage its brands or reputation, even if such claims are untrue. The Company may also experience criticism or backlash from media, customers, employees, government entities, advocacy groups and other stakeholders that disagree with positions taken by the Company or its executives. If the Company’s brands or reputation are damaged, it could negatively impact the Company’s business, financial condition, results of operations, and ability to attract and retain highly qualified employees.
The Company has made investments focused on consumer products that may not be successful, may not achieve the intended financial results or may result in product liability and reputational risk that could adversely affect the Company.
The Company may be liable to customers for any damage caused to customers’ homes, facilities, belongings or property during the installation of Company products and systems, such as smart home systems, home back-up generators and residential HVAC system repairs, installation and replacements. Where such work is performed by independent contractors, such as repairs performed under the Company's home protection plan products, the Company may nonetheless face claims and costs for damage. In addition, shortages of skilled labor for Company projects could significantly delay a project or otherwise increase its costs. The products that the Company sells or manufactures may expose the Company to product liability claims relating to personal injury, death, or environmental or property damage, and may require product recalls or other actions. Although the Company maintains liability insurance and its service contracts limit Company liability, the Company cannot be certain that its coverage will be adequate for liabilities actually incurred or that insurance will continue to be available to the Company on economically reasonable terms, or at all, or that contractual limitations will be enforced. The laws of some states limit or prohibit insurance coverage for certain liabilities and actions, and any significant uninsured damages could have a material adverse effect on the Company’s business, financial condition and cash flows. Further, any product liability claims or damage caused by the Company could significantly impair the Company’s brand and reputation, which may result in a failure to maintain customers and achieve the Company’s desired growth initiatives in these new businesses.
Changes in technology may impair the value of, and the attractiveness of, its retail products, smart home services and NRG’s generation facilities.
Research and development activities are ongoing in the industry to provide alternative and more efficient technologies to produce power, including wind, photovoltaic (solar) cells, hydrogen, energy storage, and improvements in traditional technologies and equipment, such as more efficient gas turbines. Advances in these or other technologies, including through artificial intelligence, could reduce the costs of power production to a level below what the Company has currently forecasted, which could adversely affect its cash flows, results of operations or competitive position. Technology, including distributed technology or changes in retail rate structures, may also have a material impact on the Company’s ability to retain retail customers. Further, technological innovation and changes could cause the Company’s smart home products and services to become obsolete, or otherwise more expensive and less effective than those of competitors, putting the Company at a competitive disadvantage.
Some emerging technologies, such as distributed renewable energy technologies, broad consumer adoption of electric vehicles and energy storage devices, could affect the price of energy. These emerging technologies may affect the financial viability of utility counterparties and could have significant impacts on wholesale market prices, which could ultimately have a material adverse effect on NRG's financial condition, results of operations and cash flows.
The Company’s smart home services rely on intellectual property and any failure to adequately protect such intellectual property, or claims that the Company has infringed on others’ intellectual property rights, could have an adverse effect on its business and operations and result in a competitive disadvantage.
The Company relies on a combination of patent, trademark, copyright and trade secret laws of the United States and other countries and a combination of confidentiality procedures, contractual provisions and other methods, to protect its intellectual property, all of which offer only limited protection. If the Company fails to acquire the necessary intellectual property rights or adequately protect or assert its intellectual property rights, competitors may manufacture and market similar products and services or convert customers, which could adversely affect market share and results of operations for smart home services. In addition, patent rights may not prevent competitors from developing, using or selling products or services that are similar to or address the same market as the Company’s smart home products and services. Certain of the Company’s smart home solutions contain software modules licensed under “open-source” licenses, which may entail greater risks than the use of third-party commercial software, as open-source licensors generally do not provide warranties or other contractual protections regarding
infringement claims or the quality of the code. Further, if proprietary software is combined with open-source software, in certain cases the Company could be required to release the source code of the proprietary software to the public, allowing competitors to create similar products with lower development effort and time.
It is possible that certain of the Company’s smart home products and services or those of third parties incorporated into its offerings could infringe the intellectual property rights of others. From time to time, Vivint Smart Home has been subject to claims based on allegations of infringement, misappropriation or other violations of the intellectual property rights of others. If the Company is unable to successfully defend against such claims or license necessary third-party technology or other intellectual property on acceptable terms it may be required to develop alternative, non-infringing technology, which could require significant time, effort, and expense and may ultimately not be successful.
NRG's business, financial condition and results of operations could be adversely impacted by strikes or work stoppages by its unionized employees or inability to replace employees as they retire.
As of December 31, 2017,2023, approximately 24%4% of NRG's employees at its U.S. generation plants were covered by collective bargaining agreements. In the event that the Company's union employees strike, participate in a work stoppage or slowdown or engage in other forms of labor strife or disruption, NRG would be responsible for procuring replacement labor or the Company could experience reduced power generation or outages. Although NRG's ability to procure such labor is uncertain, contingency staffing planning is completed as part of each respective contract negotiations.negotiation. Strikes, work stoppages or the inability to negotiate future collective bargaining agreements on favorable terms could have a material adverse effect on the Company's business, financial condition, results of operations and cash flows. In addition, a number of the Company's employees at NRG's plants are close to retirement. The Company's inability to replace retiring workers could create potential knowledge and expertise gaps as such workers retire.
Changes in technology may impair the value of NRG's power plants.
Researchfailure to manage key executive succession and development activities are ongoingretention and to provide alternative and more efficient technologiescontinue to produce power, including wind, photovoltaic (solar) cells, energy storage, and improvements in traditional technologies and equipment, such as more efficient gas turbines. Advances in these or other technologies could reduce the costs of power production to a level below what the Company has currently forecasted, whichattract qualified personnel could adversely affect its cash flows,the Company's financial condition and results of operations or competitive position.
operations.
The Company may potentially be affected by emerging technologies that may over time affect change in capacity markets andloss of one or more of the energy industry overall withCompany’s key personnel or the inclusion of distributed generation and clean technology.
Some emerging technologies like distributed renewable energy technologies, broad consumer adoption of electric vehicles and energy storage devicesinability to effectively identify a suitable successor to a key role could adversely affect the priceCompany’s business. The failure to successfully transition and assimilate key employees, the effectiveness of energy. These emerging technologies maythe Company’s leaders, and any further transition, could adversely affect the financial viability of utility counterparties and could have significant impacts on wholesale market prices, which could ultimately have a material adverse effect on NRG'sCompany’s financial condition and results of operations and cash flows.operations.
Risks that are beyond NRG's control, including but not limited to acts of terrorism or related acts of war, natural disaster hostile cyber intrusions or other catastrophic events could have a material adverse effect on NRG's financial condition, results of operations and cash flows.
NRG's generation facilities and the facilities of third parties on which they rely may be targets of terrorist activities, as well as events occurring in response to or in connection with them, thatsuch activities, all of which could cause environmental repercussions and/or result in full or partial disruption of the facilities ability to generate, transmit, transport or distribute electricity or natural gas. Strategic targets, such as energy-related facilities, may be at greater risk of future terrorist activities than other domestic targets. Hostile cyber intrusions, including those targeting information systems as well as electronic control systems used at the generating plants and for the distribution systems, could severely disrupt business operations and result in loss of service to customers, as well as significant expense to repair security breaches or system damage. Any such environmental repercussions or disruption could result in a significant decrease in revenues or significant reconstruction or remediation costs beyond what could be recovered through insurance policies, which could have a material adverse effect on the Company's financial condition, results of operations and cash flows. In addition, significant weather events or terrorist actions could damage or shut down the power or gas transmission and distribution facilities upon which the Company'sCompany is dependent, which may reduce retail businesses are dependent.volume for extended periods of time. Power or gas supply may be sold at a loss if these events cause a significant loss of retail customer load.demand.
The operation of NRG’s businesses is subject to cyber-based security and integrity risk.
Numerous functions affecting the efficient operation of NRG’s businesses depend on the secure and reliable storage, processing and communication of electronic data and the use of sophisticated computer hardware and software systems. The operation of NRG’s generation plants, including STP, and of NRG's energy and fuel trading businesses rely on cyber-based technologies and, therefore, subject to the risk that such systems could be the target of disruptive actions, particularly through cyber-attack or cyber intrusion, including by computer hackers, foreign governments and cyber terrorists, or otherwise be compromised by unintentional events. As a result, operations could be interrupted, property could be damaged and sensitive customer information could be lost or stolen, causing NRG to incur significant losses of revenues, other substantial liabilities and damages, costs to replace or repair damaged equipment and damage to NRG's reputation. In addition, NRG may experience increased capital and operating costs to implement increased security for its cyber systems and plants.
The Company's retail businesses are subject to the risk that sensitive customer data may be compromised, which could result in an adverse impact to its reputation and/or the results of operations of the Company's retail businesses.
The Company's retail businesses require access to sensitive customer data in the ordinary course of business. Examples of sensitive customer data are names, addresses, account information, historical electricity usage, expected patterns of use, payment history, credit bureau data, credit and debit card account numbers, driver's license numbers, social security numbers and bank account information. NRG's retail businesses may need to provide sensitive customer data to vendors and service providers, who require access to this information in order to provide services, such as call center operations, to NRG's retail businesses. If a significant breach occurred, the reputation of NRG and its retail businesses may be adversely affected, customer confidence may be diminished, or NRG and its retail businesses may be subject to legal claims, any of which may contribute to the loss of customers and have a negative impact on the business and/or results of operations.
Risks Related to Governmental Regulation and Laws
NRG's business is subject to substantial energy regulation and may be adversely affected by legislative or regulatory changes, as well as liability under, or any future inability to comply with, existing or future energy regulations or requirements.
NRG's business is subject to extensive U.S. federal, state and local laws and foreign laws. Compliance with, or changes to, the requirements under these legal and regulatory regimes may cause the Company to incur significant additional costs, reduce the Company's ability to hedge exposure or to sell retail power within certain states or to certain classes of retail customers, or restrict the Company’s marketing practices, its ability to pass through costs to retail customers, or its ability to compete on favorable terms with competitors, including the incumbent utility. Retail competition and failurehome protection services are regulated on a state-by-state or at the province-by-province level and are highly dependent on state and provincial laws, regulations and policies, which could change at any moment. Failure to comply with such requirements could result in the shutdown of a non-complying facility or line of business, the imposition of liens, fines, and/or civil or criminal liability.
Public utilities under the FPA are required to obtain FERC acceptance of their rate schedules for wholesale sales of electricity. Except for ERCOT generatinggeneration facilities and power marketers, all of NRG's non-qualifying facility generating companies and power marketing affiliates in the U.S. make sales of electricity in interstate commerce and are public utilities for
purposes of the FPA. FERC has granted each of NRG's generating and power marketing companies that make sales of electricity outside of ERCOT the authority to sell electricity at market-based rates. FERC's orders that grant NRG's generating and power marketing companies market-based rate authority reserve the right to revoke or revise that authority if FERC subsequently determines that NRG can exercise market power in transmission or generation, create barriers to entry, or engage in abusive affiliate transactions. In addition, NRG's market-based sales are subject to certain market behavior rules, and if any of NRG's generating and power marketing companies were deemed to have violated those rules, they are subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of their market-based rate authority. If NRG's generating and power marketing companies were to lose their market-based rate authority, such companies would be required to obtain FERC's acceptance of a cost-of-service rate schedule and could become subject to the accounting, record-keeping, and reporting requirements that are imposed on utilities with cost-based rate schedules. This could have a material adverse effect on the rates NRG charges for power from its facilities.
Substantially all of theThe Company's generation assets are also subject to the reliability standards promulgated by the designated Electric Reliability Organization (currently NERC) and approved by FERC. If NRG fails to comply with the mandatory reliability standards, NRG could be subject to sanctions, including substantial monetary penalties and increased compliance obligations. NRG is also affected by legislative and regulatory changes, as well as changes to market design, market rules, tariffs, cost allocations, and bidding rules that occur in the existing ISOs. The ISOs that oversee most of the wholesale power markets impose, and in the future may continue to impose, mitigation, including price limitations, offer caps, non-performance penalties and other mechanisms to address some of the volatility and the potential exercise of market power in these markets. These types of price limitations and other regulatory mechanisms may have a material adverse effect on the profitability of NRG's generation facilities that sell energy and capacity into the wholesale power markets.
The regulatory environment has undergoneis subject to significant changes in the last several years due to state and federal policies affecting wholesale and retail competition and the creation of incentives for the addition of large amounts of new renewable generation and, in some cases, transmission. These changes are ongoing, and the Company cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on NRG's business. In addition, in some of these markets, interested parties have proposed material market design changes, including the elimination of a single clearing price mechanism, as well as proposals to reinstate the vertical monopoly utility of the markets or require divestiture by generating companies to reduce their market share.changes. If competitive restructuring of the electric power markets is reversed, discontinued, or delayed, the Company's business prospects and financial results could be negatively impacted. In addition, since 2010, there have been a number of reforms to the regulation of the derivatives markets, both in the United States and internationally. These regulations, and any further changes thereto, or adoption of additional regulations, including any regulations relating to position limits on futures and other derivatives or margin for derivatives, could negatively impact NRG’s ability to hedge its portfolio in an efficient, cost-effective manner by, among other things, potentially decreasing liquidity in the forward commodity and derivatives markets or limiting NRG’s ability to utilize non-cash collateral for derivatives transactions.
NRG’s business may be affected by state interference in the competitive wholesale marketplace.
NRG’s legacy generation and competitive retail businessesoperations rely on a competitive wholesale marketplace. The competitive wholesale marketplace may be underminedimpacted by out-of-market subsidies, provided by states or state entities, including bailouts of uneconomic nuclear plants, imports of power from Canada, renewable mandates or subsidies, mandates to sell power below its cost of acquisition and associated costs as well as out-of-market payments to new or existing generators. These out-of-market subsidies to existing or new generation undermine the competitive wholesale marketplace, which can lead to premature retirement of existing facilities, including those owned by the Company. If these measures continue, capacity and energy prices may be suppressed, and the Company may not be successful in its efforts to insulate the competitive market from this interference.
Government regulations providing incentives for renewable generation could change at any time and such changes may adversely impact NRG's business, revenues, margins, results of operations and cash flows.
The Company's growth strategy dependsretail operations may be materially impacted by rules or regulations that allow regulated utilities to participate in part on government policiescompetitive retail markets or own and operate facilities that support renewable generationcould be provided by competitive market participants.
Additions or changes in tax laws and enhanceregulations could potentially affect the economic viabilityCompany’s financial results or liquidity.
NRG is subject to various types of owning renewable electric generation assets. Renewable generation assets currently benefittax arising from various federal, state and local governmental incentives such as ITCs, PTCs, cash grants in lieu of ITCs, loan guarantees, RPS programs, modified accelerated cost-recovery system of depreciation and bonus depreciation. For example, in December 2015, the U.S. Congress enacted an extension of the 30% solar ITC so that projects which began construction in 2016 through 2019 will continue to qualify for the 30% ITC. Projects beginning construction in 2020 and 2021 will be eligible for the ITC at the rates of 26% and 22%, respectively. The same legislation also extended the 10-year wind PTC for wind projects which began construction in 2016 through 2019. Wind projects which begin constructionnormal business operations in the years 2017, 2018jurisdictions in which the Company operates. Any additions or changes to tax legislation, or their interpretation and 2019 are eligible for PTCs at 80%, 60% and 40% of the statutory rate per kWh, respectively.
Many states have adopted RPS programs mandating that a specified percentage of electricity sales come from eligible sources of renewable energy. However, the regulations that govern the RPS programs,application, including pricing incentives for renewable energy, or reasonableness guidelines for pricing that increase valuation compared to conventional power (such as a projected value for carbon reduction or consideration of avoided integration costs), may change. If the RPS requirements are reduced or eliminated, it could lead to fewer future power contracts or lead to lower prices for the sale of power in future power contracts, whichthose with retroactive effect, could have a material adverse effect on the Company's future growth prospects.
Such material adverse effects may result from decreased revenues, reduced economic returns on certain project company investments, increased financing costs, and/or difficulty obtaining financing. Furthermore, the ARRA included incentives to encourage investmentNRG’s financial condition and results of operations, including income tax provision and accruals reflected in the renewable energy sector, such as cash grantsconsolidated financial statements. Beginning in lieu of ITCs, bonus depreciation and expansion of the U.S. DOE loan guarantee program. It is uncertain what loan guarantees may be made by the U.S. DOE loan guarantee program in the future. In addition, the cash grant in lieu of ITCs program only applies to facilities that commenced construction prior to December 31, 2011, which commencement date may be determined in accordance with the safe harbor if more than 5% of the total cost of the eligible property was paid or incurred by December 31, 2011.
If2023, the Company is unablenow subject to utilize various federal, state and local government incentivesa 15% corporate alternative minimum tax as a result of the Inflation Reduction Act. The CAMT may lead to acquire additional renewable assetsvolatility in the future,Company’s cash tax payment obligations, particularly in periods of significant commodity or currency variability resulting from potential changes in the termsfair value of such incentives are revised in a mannerderivative instruments. The Company continuously monitors and assesses proposed tax legislation that is less favorable to the Company, it may suffer a material adverse effect on the business, financial condition, results of operations and cash flows.could negatively impact its business.
The integration of the Capacity Performance product into the PJM market and the Pay-for-Performance mechanism in ISO-NE could lead to substantial changes in capacity income and non-performance penalties, which could have a material adverse effect on NRG’s results of operations, financial condition and cash flows.
Both ISO-NE and PJM operateoperates a pay-for-performance model where capacity payments are modified based on real-time generator performance. Capacity market prices are sensitive to design parameters, as well as additions of new capacity. NRG may experience substantial changes in capacity income and incur non-performance penalties, which could have a material adverse effect on NRG’s results of operations, financial condition and cash flows.
Certain of NRG's long-term bilateral contracts result from state-mandated procurements and could be declared invalid by a court of competent jurisdiction.
A significant portion of NRG’s revenues are derived from long-term bilateral contracts with utilities that are regulated by their respective states, and have been entered into pursuant to certain state programs. Certain long-term contracts that other companies have with state-regulated utilities have been challenged in federal court and have been declared unconstitutional on the grounds that the rate for energy and capacity established by the contracts impermissibly conflicts with the rate for energy and capacity established by FERC pursuant to the FPA. If certain of the Company's state-mandated agreements with utilities are ever held to be invalid, NRG may be unable to replace such contracts, which could have a material adverse effect on NRG's business, financial condition, results of operations and cash flows.
NRG's ownership interest in a nuclear power facility subjects the Company to regulations, costs and liabilities uniquely associated with these types of facilities.
Under the Atomic Energy Act of 1954, as amended, or AEA, ownership and operation of STP, of which NRG indirectly owns a 44% interest, is subject to regulation by the NRC. Such regulation includes licensing, inspection, enforcement, testing, evaluation and modification of all aspects of nuclear reactor power plant design and operation, environmental and safety performance, technical and financial qualifications, decommissioning funding assurance and transfer and foreign ownership restrictions. The current facility operating licenses for STP expire on August 20, 2047 (Unit 1) and December 15, 2048 (Unit 2).
There are unique risks to owning and operating a nuclear power facility. These include liabilities related to the handling, treatment, storage, disposal, transport, release and use of radioactive materials, particularly with respect to spent nuclear fuel, and uncertainties regarding the ultimate, and potential exposure to, technical and financial risks associated with modifying or decommissioning a nuclear facility. The NRC could require the shutdown of the plant for safety reasons or refuse to permit restart of the unit after unplanned or planned outages. New or amended NRC safety and regulatory requirements may give rise to additional operation and maintenance costs and capital expenditures. Additionally, aging equipment may require more capital expenditures to keep each of these nuclear power plants operating efficiently. This equipment is also likely to require periodic upgrading and improvement. Any unexpected failure, including failure associated with breakdowns, forced outages, or any unanticipated capital expenditures, could result in reduced profitability. STP will be obligated to continue storing spent nuclear fuel if the U.S. DOE continues to fail to meet its contractual obligations to STP made pursuant to the U.S. Nuclear Waste Policy Act of 1982 to accept and dispose of STP's spent nuclear fuel. See also Item 1 —Regulatory Matters — Nuclear Operations - Decommissioning Trusts and Item 1 — Environmental Matters — Federal Environmental Initiatives — Nuclear Waste for further discussion. Costs associated with these risks could be substantial and could have a material adverse effect on NRG's results of operations, financial condition or cash flow to the extent not covered by the Decommissioning Trusts or recovered from ratepayers. In addition, to the extent that all or a part of STP is required by the NRC to permanently or temporarily shut down or modify its operations, or is otherwise subject to a forced outage, NRG may incur additional costs to the extent it is obligated to provide power from more expensive alternative sources — either NRG's own plants, third party generators or the ERCOT — to cover the Company's then existing forward sale obligations. Such shutdown or modification could also lead to substantial costs related to the storage and disposal of radioactive materials and spent nuclear fuel.
While STP maintains property and liability insurance for losses related to nuclear operations, there may be limitations on the amounts and types of insurance commercially available. See also Item 15 — Note 22, Commitments and Contingencies, Nuclear Insurance. An accident at STP or another nuclear facility could have a material adverse effect on NRG's financial condition, its operational results, or liquidity as losses may exceed the insurance coverage available and/or may result in the obligation to pay retrospective premium obligations.
NRG is subject to environmental laws that impose extensive and increasingly stringent requirements on the Company's ongoing operations, as well as potentially substantial liabilities arising out of environmental contamination. These environmental requirements and liabilities could adversely impact NRG's results of operations, financial condition and cash flows.
NRG is subject to the environmental laws of foreign and U.S., federal, state and local authorities. The Company must comply with numerous environmental laws and obtain numerous governmental permits and approvals to build and operate the Company's plants. Federal and state environmental laws generally have become more stringent over time, although this trend could slow or pause.time. Should NRG fail to comply with any environmental requirements that apply to its operations, the Company could be subject to administrative, civil and/or criminal liability and fines, and regulatory agencies could take other actions seeking to curtail the Company's operations. In addition, when new requirements take effect or when existing environmental requirements are revised, reinterpreted or subject to changing enforcement policies, NRG's business, results of operations, financial condition and cash flows could be adversely affected.
NRG's businesses are subject to physical, market and economic risks relating to potential effects of climate change.change, and policies at the national, regional and state levels to regulate GHG emissions and mitigate climate change which could adversely impact NRG's results of operations, financial condition and cash flows.
Climate change is producing changesFluctuations in weather and other environmental conditions, including temperature and precipitation levels, and thus may affect consumer demand for electricity.electricity or natural gas. In addition, the potential physical effects of climate change, such as increased frequency and severity of storms, floods and other climatic events, could disrupt NRG's operations and supply chain, and cause themit to incur significant costs in preparing for or responding to these effects. These or other meteorological changes in climate could lead to increased operating costs or capital expenses or power purchase costs.expenses. NRG's commercial and residential customers may also experience the potential physical impacts of climate change and may incur significant costs in preparing for or responding to these efforts, including increasingchanging the fuel mix and resiliency of their energy solutions and supply.
The contribution of climate change to the frequency or intensity of weather-related events could affect NRG's operations and planning process. Climate change could also affect the availability of a secure and economical supply of water in some locations, which is essential for the continued operation of NRG's generation plants. WaterNRG monitors water supply risk is monitored by the risk owners (individual plant operators) and reported to Company management upon changes with a significance threshold of 20% in water consumption and withdrawal levels.carefully. If it is determined that a water supply risk exists that could impact projected generation levels at any plant, within the subsequent two year time frame, risk mitigation efforts are identified and economically evaluated for implementation. Water risk regarding the impact for barge delivery is evaluated on a daily basis, with contingency plans developed as needed.
GHG regulation could increase the cost of electricity generated by fossil fuels, and such increases could reduce demand for the power NRG generates and markets. Also,Further, demand for NRG's energy-related services could be similarly impacted by consumers’ preferences or market or regulatory factors favoring energy efficiency, low-carbon powerlower carbon energy sources or reduced electricity or natural gas usage.
Policies at the national, regional and state levels to regulate GHG emissions, as well as mitigate climate change, could adversely impact NRG's results of operations, financial condition and cash flows.
NRG's GHG emissions for 2017reduction targets can be found in Item 1, Business — Environmental Matters. —Environmental Regulatory Matters. The Company's ability to achieve these targets depends on many factors, including the ability to retire high emitting assets, ability to reduce emissions based on technological advances and innovation, and ability to source energy from less carbon intense resources. In 2015, the EPA promulgated the finaladdition, any future decarbonization efforts may increase costs, or NRG may otherwise be limited in its ability to apply them. The cost associated with NRG's GHG emissions rulesreduction goals could be significant. Failure to achieve the Company's emissions targets could result in a negative impact on access to and cost of capital, changing investor sentiment regarding investment in the Company or reputation harm.
Enhanced data privacy and data protection laws and regulations or any non-compliance with such laws and regulations, could adversely affect NRG’s business and financial results.
The consumer privacy landscape continues to experience momentum for newgreater privacy protection and existing fossil-fuel-fired electric generating units, which have been stayedreform at the state and federal level in response to precedents set forth by the U.S. Supreme CourtGeneral Data Protection Regulation (the "GDPR") and the EPA has proposed repealing.
California Consumer Privacy Act (the "CCPA"). The development and evolving nature of domestic and international privacy regulation and enforcement could impact and potentially limit how NRG processes personally identifiable information. California residents now have increased access rights (including the right to limit the use and disclosure of sensitive personal information), which are enforced by a new state privacy regulator, resulting in more scrutiny of business practices and disclosures. Additional states including Virginia, Utah, Connecticut, Colorado, Nevada and Texas have similarly adopted enhanced data privacy legislation and patterned after the standards set forth by CCPA, including broader data access rights, with Virginia going a step further requiring businesses to perform data protection assessments for certain processing activities. The Company operates generating unitsis also
bound by contractual requirements relating to privacy and data protection, and may agree to additional contractual requirements addressing these matters from time to time.
As new laws and regulations are created, amended or expanded, requiring businesses to implement processes to enable customers access to their data and enhanced data protection and management standards, NRG cannot forecast with any certainty the impact that they may have on the Company’s business; however, it is possible the Company may find it necessary or desirable to change certain of its business practices or to expend resources to modify its home products and services and otherwise adapt to these changes. It is possible that the Company may be unable to make such changes and modifications in Connecticut, Delaware, Maryland,a commercially reasonable manner or at all, and New Yorkits ability to develop new home services and features could be limited. Any non-compliance with laws may result in proceedings or actions against the Company by governmental entities or individuals. Moreover, any inquiries or investigations, government penalties or sanctions, or civil actions by individuals may be costly to comply with, resulting in negative publicity, increased operating costs, significant management time and attention, and may lead to remedies that harm the business, including fines, demands or orders that existing business practices be modified or terminated.
NRG's retail operations and smart home services are subject to RGGI, which is a regional cap and trade system. In 2013, each of these states finalized a rule that reduced and will continue to reduce the number of allowances through 2020. The nine RGGI states re-evaluated the program and published a model rule to further reduce the number of allowances. The revisions being currently contemplated could adversely impact NRG's results of operations, financial condition and cash flows.
California has a CO2 cap and trade program for electric generating units greater than 25 MW. The impact on the Company depends on the cost of the allowances and the ability to pass these costs through to customers.
Hazards customary to the power production industry include the potential for unusual weather conditions, which could affect fuel pricing and availability, the Company's route to market or access to customers, i.e., transmission and distribution lines, or critical plant assets. The contribution of climate change to the frequency or intensity of weather-related events could affect NRG's operations and planning process.
NRG's retail businesses are subject to changing state rules and regulations that could have a material impact on the profitability of its business lines.Company's profitability.
The competitiveness of NRG's retail businessesoperations partially depends on state regulatory policies that establish the structure, rules, terms and conditions onupon which services are offered to retail customers. These state policies which can include, among other things, controls on the retail rates NRG's retail businessesthat NRG can charge, the imposition of additional costs on sales, restrictions on the Company's sell certain types of products or ability to obtain new customers through various marketing channels and disclosure requirements, which can affect the competitiveness of NRG'srequirements. The Company's retail businesses.operations may be materially impacted by rules or regulations that allow regulated utilities to participate in competitive retail markets or own and operate facilities that could be provided by competitive market participants. Additionally, state, federal or federalprovincial imposition of net metering or RPS programs can make it more or less expensive for retail customers to supplement or replace their reliance on grid power. NRG's retail businesses have limited
The Company’s smart home services focus on transactions with residential customers, subjecting it to a variety of laws, regulations and licensing requirements governing interactions with residential consumers, including those pertaining to privacy and data security, consumer financial and credit transactions, home improvements, warranties and door-to-door solicitation. In certain jurisdictions, the Company is required to obtain licenses or permits to comply with standards governing marketing and sales efforts, installation of equipment or servicing of subscribers, and monitoring station employee selection and training. Increased regulation of matters relating to interactions with residential consumers could require modification to the Company’s home services operations and the incurrence of additional expenses. Further, any expansion of the scope of products or services into new markets may require additional licenses and expenditures to otherwise maintain compliance with additional laws, regulations or licensing requirements. These laws and regulations, as well as their interpretation, and any new laws, regulations or licensing requirements could negatively affect the Company’s ability to influence developmentacquire new residential customers. Any of these policies,measures could increase costs for providing, or reduce customer satisfaction with respect to, smart home services.
The Federal Trade Commission ("FTC") and the Federal Communications Commission have issued regulations that restrict direct-to-home marketing, telemarketing, email marketing and other sales practices, including limitations on methods of communication, requirements to maintain a “do not call” list, cancellation rights and required training for personnel to comply with these restrictions. Any noncompliance, or alleged noncompliance, of applicable regulations by the Company, third-party vendors used for marketing, telemarketing or lead generation activities or independent, third-party authorized dealers of smart home services could result in private rights of actions or enforcement actions for civil or criminal penalties. Changes in regulations or interpretations that further restrict lead generating activities also could result in a reduction in the number of new smart home services customers.
The Company’s smart home business exposes it to risks of liability for the acts or omissions of its employees, including with respect to sales practices.
Activities in connection with sales efforts by employees, independent contractors, and other agents, including predatory door-to-door sales tactics and fraudulent misrepresentations, have in the past subjected it to, and could in the future subject the Company to, governmental investigations and class action lawsuits for, among others, false advertising and deceptive trade practice damage claims. Any litigation or regulatory proceedings resulting from such activities could adversely impact the Company’s business, modelfinancial condition, results of operations, and cash flows.
The Company is subject to various risks in connection with Vivint Smart Home’s ongoing settlement administration process involving the FTC, and may be more or less effective, depending on changessubject to FTC Actions in the future.
In 2021, Vivint Smart Home entered into a settlement with the FTC where Vivint Smart Home paid a total of $20 million to the United States and agreed to implement various compliance-related measures. The settlement requires an initial assessment and thereafter biennial assessments by an independent third-party assessor of Vivint Smart Home’s compliance
programs and for the assessor to provide a report to the FTC staff on ongoing compliance with the settlement. Although Vivint Smart Home took action to enhance its compliance programs, these and other measures that the Company may take in the future may not be successful. If any assessments identify deficiencies in the Company’s efforts to comply, and should the FTC determine that Vivint Smart Home is not in full compliance with the settlement, the FTC could take further action, such as seeking judicial remedies for any noncompliance, and Vivint Smart Home could be subject to additional sanctions and restrictions on its smart home operations. In addition, the filing of an application with the court for noncompliance with the settlement could lead to regulatory environment. actions by other agencies or private litigation, which could impact Vivint Smart Home’s ability to obtain regulatory approvals necessary to carry out present or future plans and operations, and result in negative publicity.
The Company's international operations are exposed to political and economic risks, commercial instability and events beyond the Company's control in the countries in which it operates, which risks may negatively impact the Company's business.
The Company's international operations depend on products manufactured, purchased and sold in the U.S. and internationally, including in countries with political and economic instability.internationally. In some cases, these countries have greater political and economic volatility and greater vulnerability to infrastructure labor, and laborsupply chain disruptions than in NRG's other markets. The Company's business could be negatively impacted by adverse fluctuations in freight costs, limitations on shipping and receiving capacity, and other disruptions in the transportation and shipping infrastructure at important geographic points of exit and entry for the Company's products. Operating and seeking to expanda business in a number of different regions and countries exposes the Company to a number of risks, including:
imposition of burdensome tariffs or quotas, multiple and potentially conflicting laws, regulations and policies that are subject to change;
change, imposition of currency restrictions on repatriation of earnings or other restraints;
imposition of burdensome tariffs or quotas;
restraints, national and international conflict, including terrorist acts;acts and
political and economic instability or civil unrest that may severely disrupt economic activity in affected countries.
countries and result in increased cost. The occurrence of one or more of these events may negatively impact the Company's business, results of operations and financial condition.
Risks Related to Economic and Financial Market Conditions and the Company's Indebtedness
NRG's level of indebtedness could adversely affect its ability to raise additional capital to fund its operations or return capital to stockholders. It could also expose it to the risk of increased interest rates and limit its ability to react to changes in the economy or its industry.
NRG's substantial amount of debt could have negative consequences, including:
•increasing NRG's vulnerability to general economic and industry conditions;
•requiring a substantial portion of NRG's cash flow from operations be used to be dedicated to the payment ofpay principal and interest on its indebtedness, therefore reducingwhich reduces NRG's ability to pay dividends to holders of its preferred or common stock or to use its cash flow to fund its operations, capital expenditures and future business opportunities;
•limiting NRG's ability to enter into long-term power sales or fuel purchases, which require credit support;
exposing NRG to the risk of increased interest rates because certain of its borrowings, including borrowings under its senior secured•adversely impacting NRG's credit facility are at variable rates of interest;rating, which could increase borrowing costs;
•limiting NRG's ability to obtain additional financing for working capital, including collateral postings, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes; and
•limiting NRG's ability to adjust to changing market conditions and placing it at a competitive disadvantage compared to its competitors, who may have less debt.debt; and
•exposing NRG to the risk of increased interest rates because certain of its borrowings are at variable rates of interest.
The indentures for NRG's notes and senior secured credit facilityCompany’s debt agreements contain financial and other restrictive covenants that may limit the Company's ability to return capital to stockholders, including by paying dividends, or otherwise engage in activities that may be in its long-term best interests. Furthermore, financial and other restrictive covenants contained in any project level subsidiary debt may limit the ability of NRG to receive distributions from such subsidiary. NRG's failure to comply with those covenants could result in an event of default which, if not cured or waived, could result in the acceleration of such indebtedness, which in turn could cause a cross default to NRG's other indebtedness. NRG's assets and available cash balances may not be sufficient to fully repay all outstanding indebtedness if accelerated upon an event of default. If NRG is unable to repay, refinance, or restructure its indebtedness as required, or amend the covenants contained in those agreements, the lenders or other creditors may be entitled to obtain a lien or institute foreclosure proceedings against its assets, which could have a material adverse effect on its business, results of operations and financial condition. In addition, the Company's indebtedness.Revolving Credit Facility and sustainability-linked bonds include a sustainability-linked metric, which could result in increased interest expense for the Company if the sustainability metrics set forth therein are not achieved. Furthermore, financial and other restrictive covenants contained in any subsidiary or project level debt may limit the ability of NRG to receive distributions from such subsidiary.
In addition, NRG's ability to arrange financing, either at the corporate level, a non-recourse project-level subsidiary or otherwise, and the costs of such capital are dependent on numerous factors, including:
general economic and capital market conditions;
conditions, credit availability from banks and other financial institutions;
institutions, investor confidence in NRG, its partners and the regional wholesale power markets;
markets, NRG's financial performance and the financial performance of its subsidiaries;
subsidiaries, NRG's level of indebtedness and compliance with covenants in debt agreements;
agreements, maintenance of acceptable credit ratings;
ratings, cash flow;flow and
provisions of tax and securities laws that may impact raising capital.
NRG's ability to meet its payment obligations under its debt agreements is dependent on its ability to generate significant cash flows or obtain additional capital in the future. This, to some extent, is subject to market, economic, financial, competitive, legislative, and regulatory factors as well as other factors that are beyond its control. NRG may not be successful in obtaining additional capital for these or other reasons. The failure to obtain additional capital on terms acceptable to NRG, or at all, from time to time may have a material adverse effect on its business and operations.
NRG's preferred stock is senior to its common stock, and a failure to pay dividends on its preferred stock will prohibit the payment of dividends on its common stock.
NRG has outstanding 650,000 shares of 10.25% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock, with a $1,000 liquidation preference per share. The Series A Preferred Stock is senior to NRG's common stock in right of payment of dividends and other distributions and could adversely affect NRG's ability to declare or pay dividends or distributions on its common stock. In the event of NRG's voluntary or involuntary liquidation, winding-up or dissolution, the holders of Series A Preferred Stock must receive their $1,000 per share, plus accumulated but unpaid dividends, prior to any distributions to holder of common stock. NRG must be current on dividends payable to holders of Series A Preferred Stock before any dividends can be paid on its common stock.
Whenever dividends on any shares of Series A Preferred Stock have not been declared and paid for the equivalent of three or more dividend payments, whether or not for consecutive dividend periods, the number of directors on the Company's Board of Directors will be increased by two, and the holders of Series A Preferred Stock will have the right to elect two members of the Company's Board of Directors to fill such newly created openings.
Adverse economic conditions could adversely affect NRG’s business, financial condition, results of operations and cash flows.
Adverse economic conditions, including inflation, and declines in wholesale energy prices, partially resulting from adverse economic conditions, may impact NRG’s earnings. The breadth and depthNRG's results of negative economic conditions may have a wide-ranging impact on the U.S. business environment,operations, including NRG’s businesses. In addition, adverse economic conditions also reduceby reducing the demand for energy commodities. Reduced demand from negative economic conditions continues to impact the key domestic wholesale energy markets NRG serves. The combination of lower demand for power and increased supply of natural gas has put downward price pressure on wholesale energy markets in general, further impacting NRG’s energy marketing results. In general, economic and commodity market conditions will continue to impact NRG’s unhedged future energy margins, liquidity, earnings growth and overall financial condition. Macroeconomic factors may also impact consumer spending, which could adversely affect the Company’s Smart Home services, and increase the Company’s costs for such products and services, which it may not be able to pass on to customers. In addition, adverse economic conditions, declines in wholesale energy prices, reduced demand for powerenergy and other factors may negatively impact the trading price of NRG’s common stock and impact forecasted cash flows, which may require NRG to evaluate its goodwill and other long-lived assets for impairment. Any such impairment could have a material impact on NRG’s financial statements.
condition.
Goodwill and/orand other intangible assets not subject to amortization that NRG has recorded in connection with its acquisitions are subject to mandatory annual impairment evaluations and, as a result, the Company could be required to write off some or all of this goodwill and other intangible assets, which may adversely affect the Company's financial condition and results of operations.
In accordance with ASC 350, Intangibles — Goodwill and Other, or ASC 350, goodwill is not amortized but is reviewed annually or more frequently for impairment and otherimpairment. Other intangibles are also reviewed at least annually or more frequently, if certain conditions exist, and may beare amortized. Any reduction in or impairment of the value of goodwill or other intangible assets will result in a charge against earnings, which could materially adversely affect NRG's reported results of operations and financial position in future periods.
A valuation allowance may be required for NRG's deferred tax assets.
A valuation allowance may need to be recorded against the Company's remaining net deferred tax assets, which are predominantly related to NRG Yield, Inc., that the Company estimates as more likely than not to be unrealizable, based on available evidence including cumulative and forecasted pretax book earnings at the time the estimate is made. Currently, the Company has recorded a valuation allowance of approximately $1.8 billion against NRG's net deferred tax assets that are not related to NRG Yield, Inc. A valuation allowance related to deferred tax assets can be affected by changes to tax laws, statutory tax rates and future taxable income levels. In the event that the Company determines that it would not be able to realize all or a portion of its net deferred tax assets in the future, the Company would reduce such amounts accordingly through a charge to income tax expense in the period in which that determination was made, which could have a material adverse impact on the Company's financial condition and results of operations.
The Company has made investments, and may continue to make investments, in new business initiatives predominantly focused on consumer products and in markets that may not be successful, may not achieve the intended financial results or may result in product liability and reputational risk that could adversely affect the Company.
NRG continues to pursue growth in its existing businesses and markets and further diversification across the competitive energy value chain. NRG is continuing to pursue investment opportunities in renewables, consumer products and distributed generation. Such initiatives may involve significant risks and uncertainties, including distraction of management from current operations, inadequate return on capital, and unidentified issues not discovered in the diligence performed prior to launching an initiative or entering a market.
As part of these initiatives, the Company may be liable to customers for any damage caused to customers’ homes, facilities, belongings or property during the installation of Company products and systems, such as residential solar systems and mass market back-up generators. In addition, shortages of skilled labor for Company projects could significantly delay a project or otherwise increase its costs. The products that the Company sells or manufactures may expose the Company to product liability claims relating to personal injury, death, or environmental or property damage, and may require product recalls or other actions. Although the Company maintains liability insurance, the Company cannot be certain that its coverage will be adequate for liabilities actually incurred or that insurance will continue to be available to the Company on economically reasonable terms, or at all. Further, any product liability claim or damage caused by the Company could significantly impair the Company’s brand and reputation, which may result in a failure to maintain customers and achieve the Company’s desired growth initiatives in these new businesses.
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This Annual Report on Form 10-K 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 Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or 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 that may cause NRG's actual results, performance and achievements, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. These factors, risks and uncertainties include the factors described under Item 1A — Risk Factors Related to NRG Energy, Inc. and the following:
•Business uncertainties related to NRG's ability to achieveintegrate the expected benefitsoperations of Vivint Smart Home with its Transformation Plan;own;
•NRG's ability to engage in successful salesobtain and divestitures as well as mergers and acquisitions activity;maintain retail market share;
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;
•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, including the impacts of weather;
Changes in law, including judicial decisions;
•Hazards customary to the power production industry and power generation operations, such as fuel and electricity price volatility, unusual weather conditions, (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;
•Changes in law, including judicial and regulatory decisions;
•Government regulation, including changes in market rules, rates, tariffs and environmental laws;
•NRG's ability to develop and innovate new products, as retail and wholesale markets continue to change and evolve;
•Price mitigation strategies and other market structures employed by ISOs or RTOs that result in a failure to adequately and fairly compensate NRG's generation units;
•NRG's ability to mitigate forced outage risk 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.
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 Energy, Inc. 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 Annual Report on Form 10-K should not be construed as exhaustive.
Item 1B — Unresolved Staff Comments
None.
Item 1C — Cybersecurity
Risk Management and Strategy
The Company leverages a comprehensive, multi-tiered cybersecurity strategy to manage cybersecurity risk based on criteria established by the NIST Cybersecurity Framework. As part of the cybersecurity strategy the Company utilizes a range of industry and regulatory standards including, but not limited to, NERC-CIP, PCI DSS, and IoT Security Assurance Framework. Compliance with NERC-CIP standards is mandated for entities involved in power generation, transmission, and distribution by regulatory bodies to which the purpose of is to protect critical infrastructure within the United States. NRG engages certified external assessors to ensure compliance with standards.
The Company’s strategy seeks to align underlying processes not only with industry standards but also mirror best practices among peer organizations. The strategy ensures a standardized method across all activities at NRG allowing for consistent recognition, assessment and potential mitigation of significant cybersecurity risks. To further the strategy, the Company established the NRG Cybersecurity Integration Center ("CIC") which is composed of experienced team members from across cybersecurity disciplines with relevant educational and industry experience. The CIC provides the following functions to the Company: cyber governance, operations, detection and response, engineering, testing, cyber risk management (including third-party), compliance, training and awareness, and reporting. The CIC utilizes advanced continuous monitoring systems and investigative techniques for real-time threat detection. The systematic monitoring approach allows for risk classification and prioritization based on potential impacts, facilitating targeted resource allocation according to risk severity. The Company conducts regular penetration testing to proactively identify vulnerabilities and enhance its defense measures. The Company engages third-party assessors to gain comprehensive insights into its cyber risk profile's composition.
The Company relies on third-party service providers in the normal course of business. The Company has established a comprehensive approach to identify and manage cybersecurity risks associated with providers including, but not limited to, rigorous due diligence and assessments of third-party service providers' cybersecurity protocols before engagement, requirements relating to information handling, incident notification and assessment against the Company's cybersecurity requirements. Furthermore, the Company has implemented additional control measures and procedures in business processes to enable continuous risk identification, assessment and to support monitoring mechanisms to oversee and manage supplier cybersecurity practices.
Through December 31, 2023, no cybersecurity threats have been identified or are anticipated to have a material adverse effect on NRG’s business strategy, financial standing, or operational performance.
Governance
Management
The Chief Information Security Officer ("CISO") is the head of cybersecurity for the Company and leads the NRG Cybersecurity Integration Center. The CISO has decades of professional experience, education, and certification in security analysis, design, implementation, and management, with a particularly strong background in technical vulnerability assessment and program development. Within various roles throughout the CISO's career, he has overseen information assurance and cybersecurity efforts, including critical infrastructure protection in government agencies and industry.
At least twice per year, the CISO provides comprehensive updates to the Board on cybersecurity and any recent developments impacting the Company. These updates include, among other items:
•Incident reports and developments from any cybersecurity events;
•Current cybersecurity landscape and emerging cybersecurity threats, with a particular emphasis on Company and industry-specific threats; and
•Status of ongoing initiatives to strengthen the Company's cybersecurity program.
In addition, the CISO regularly informs other members of senior management, including the Interim President and CEO, of all aspects related to cybersecurity risks and incidents. This is intended to ensure that the highest levels of management remain
updated on the cybersecurity preparedness and potential risks facing the Company. Furthermore, significant cybersecurity matters and strategic risk management decisions are escalated to the Board of Directors ensuring that they have comprehensive oversight and can provide guidance on critical cybersecurity issues.
In preparation for a potential cybersecurity incident, the Company has implemented structured processes and procedures aligned with the NIST framework. This framework provides a foundation for a systematic and consistent approach to preparing for, identifying, containing, eradicating, and recovering from incidents. The effectiveness of these protocols is routinely verified through tabletop exercises involving relevant teams and Company leadership. In accordance with the Company’s process and procedures, incidents which may have a material impact on the Company are promptly referred to senior leadership and the Board of Directors for review and appropriate determination.
Board of Directors
The Board of Directors is primarily responsible for the risk oversight of the Company, and has delegated oversight of risks related to cybersecurity to the Finance and Risk Management ("FARM") Committee of the Board. The FARM Committee regularly reports on its activities to the Board after each meeting. The FARM Committee, as well as the overall Board, is composed of members with diverse expertise, including risk management, incident response and technology. The Board is aware of the critical nature of managing risks associated with cybersecurity threats and has worked with the Company’s management to establish comprehensive oversight mechanisms to ensure effective cybersecurity governance.
The FARM Committee and the Board receive updates on any significant developments in the cybersecurity domain, seeking to ensure that the Board’s oversight is proactive and responsive. The Board remains involved in ensuring that cybersecurity considerations are integrated into the Company’s broader strategic objectives. Pursuant to the charter of the FARM Committee, the Committee's responsibilities include an annual review of the Company’s cybersecurity program and the effectiveness of its risk management strategies. This review is intended to help identify areas for improvement and ensure the alignment of cybersecurity efforts with the overall risk management framework.
Item 2 — Properties
Listed below are descriptions of NRG's interests in facilities, operations and/or projects owned or leased as of December 31, 2017.2023. The rated MW capacity figures provided represent nominal summer net MW capacity of power generated asgenerated. Net MW capacity is adjusted for the Company's owned or leased interest excluding capacity from inactive/mothballed units as of December 31, 2017.2023. The Company believes its existing facilities, operations and/or projects are suitable for the conduct of its business. The following table summarizes NRG's power production and cogeneration facilities by region:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Name of Facility | | Power Market | | Plant Type | | Primary Fuel | | Location | | Rated MW Capacity(a) | | Net MW Capacity(b) | | % Owned | |
| Texas | | | | | | | | | | | | | | | |
| Cedar Bayou | | ERCOT | | Fossil | | Natural Gas | | TX | | 1,494 | | | 1,494 | | | 100.0 | | |
| Cedar Bayou 4 | | ERCOT | | Fossil | | Natural Gas | | TX | | 504 | | | 252 | | | 50.0 | | |
| Elbow Creek | | ERCOT | | Other | | Battery Storage | | TX | | 2 | | | 2 | | | 100.0 | | |
| Greens Bayou | | ERCOT | | Fossil | | Natural Gas | | TX | | 327 | | | 327 | | | 100.0 | | |
| Limestone | | ERCOT | | Fossil | | Coal | | TX | | 1,660 | | | 1,660 | | | 100.0 | | |
| San Jacinto | | ERCOT | | Fossil | | Natural Gas | | TX | | 160 | | | 160 | | | 100.0 | | |
| T.H. Wharton | | ERCOT | | Fossil | | Natural Gas | | TX | | 1,002 | | | 1,002 | | | 100.0 | | |
W.A. Parish(c) | | ERCOT | | Fossil | | Coal | | TX | | 2,514 | | | 2,514 | | | 100.0 | | |
| W.A. Parish | | ERCOT | | Fossil | | Natural Gas | | TX | | 1,118 | | | 1,118 | | | 100.0 | | |
| Total Texas | | 8,781 | | | 8,529 | | | | |
| East | | | | | | | | | | | | | | | |
| Chalk Point | | PJM | | Fossil | | Natural Gas | | MD | | 80 | | | 80 | | | 100.0 | | |
| Fisk | | PJM | | Fossil | | Oil | | IL | | 171 | | | 171 | | | 100.0 | | |
Indian River(d) | | PJM | | Fossil | | Coal | | DE | | 410 | | | 410 | | | 100.0 | | |
| Indian River | | PJM | | Fossil | | Oil | | DE | | 16 | | | 16 | | | 100.0 | | |
Powerton(e) | | PJM | | Fossil | | Coal | | IL | | 1,538 | | | 1,538 | | | 100.0 | |
Vienna(f) | | PJM | | Fossil | | Oil | | MD | | 167 | | | 167 | | | 100.0 | | |
| Waukegan | | PJM | | Fossil | | Oil | | IL | | 101 | | | 101 | | | 100.0 | | |
| Total East | | 2,483 | | | 2,483 | | | | |
| West/Services/Other | | | | | | | | | | | | | | | |
| Cottonwood | | MISO | | Fossil | | Natural Gas | | TX | | 1,166 | | | 1,166 | | | ___(g) | |
| Gladstone | | | | Fossil | | Coal | | AUS | | 1,613 | | | 605 | | | 37.5 | | |
| Ivanpah | | CAISO | | Renewable | | Solar | | CA | | 391 | | | 213 | | | 54.5 | | |
| Midway-Sunset | | CAISO | | Fossil | | Natural Gas | | CA | | 226 | | | 113 | | | 50.0 | | |
| Stadiums and Other | | | | Renewable | | Solar | | various | | 3 | | | 3 | | | 100.0 | | |
| Total West/Services/Other | | 3,399 | | | 2,100 | | | | |
| Total Fleet | | 14,663 | | | 13,112 | | | | |
(a)MW capacity of the facility without taking into account NRG ownership percentage
(b)Actual capacity can vary depending on factors including weather conditions, operational conditions, and other factors. Additionally, ERCOT and PJM require periodic demonstration of capability, and the capacity may vary individually and in the aggregate from time to time
(c)In May 2022, W.A. Parish Unit 8 came offline as a result of damage to the steam turbine/generator. The extended forced outage ended in September 2023 and the unit has returned to service
(d)The Company previously announced the shut down of the Indian River facility. However, PJM identified reliability impacts resulting from the proposed deactivation and Indian River Unit 4 currently remains active under a RMR agreement that ends December 31, 2026
(e)Powerton is projected to close by December 31, 2028 to comply with ELG regulations
(f)A retirement notice was filed with PJM that the Vienna facility will retire in June 2025
(g)NRG leases 100% interests in the Cottonwood facility through a facility lease agreement expiring in May 2025 and operates the Cottonwood facility
|
| | | | | | | | | | | | | | | | | |
| Name of Facility | | Power Market | | Plant Type | | Primary Fuel | | Location | | Rated MW Capacity | | Net MW Capacity(a) | | % Owned |
| Gulf Coast | | | | | | | | | | | | | | |
Bayou Cove(i) | | MISO | | Fossil | | Natural Gas | | LA | | 225 |
| | 225 |
| | 100.0 |
|
Big Cajun I(i) | | MISO | | Fossil | | Natural Gas | | LA | | 430 |
| | 430 |
| | 100.0 |
|
Big Cajun II(i) | | MISO | | Fossil | | Coal | | LA | | 580 |
| | 580 |
| | 100.0 |
|
Big Cajun II(i) | | MISO | | Fossil | | Natural Gas | | LA | | 540 |
| | 540 |
| | 100.0 |
|
Big Cajun II(i) | | MISO | | Fossil | | Coal | | LA | | 588 |
| | 341 |
| | 58.0 |
|
| Cedar Bayou | | ERCOT | | Fossil | | Natural Gas | | TX | | 1,495 |
| | 1,495 |
| | 100.0 |
|
| Cedar Bayou 4 | | ERCOT | | Fossil | | Natural Gas | | TX | | 498 |
| | 249 |
| | 50.0 |
|
Cottonwood(i) | | MISO | | Fossil | | Natural Gas | | TX | | 1,263 |
| | 1,263 |
| | 100.0 |
|
| Greens Bayou | | ERCOT | | Fossil | | Natural Gas | | TX | | 344 |
| | 344 |
| | 100.0 |
|
| Gregory | | ERCOT | | Fossil | | Natural Gas | | TX | | 388 |
| | 388 |
| | 100.0 |
|
| Limestone | | ERCOT | | Fossil | | Coal | | TX | | 1,689 |
| | 1,689 |
| | 100.0 |
|
| Petra Nova Cogen | | ERCOT | | Fossil | | Natural Gas | | TX | | 44 |
| | 22 |
| | 50.0 |
|
| San Jacinto | | ERCOT | | Fossil | | Natural Gas | | TX | | 162 |
| | 162 |
| | 100.0 |
|
South Texas Project(b) | | ERCOT | | Nuclear | | Uranium | | TX | | 2,582 |
| | 1,136 |
| | 44.0 |
|
Sterlington(i) | | MISO | | Fossil | | Natural Gas | | LA | | 176 |
| | 176 |
| | 100.0 |
|
| T.H. Wharton | | ERCOT | | Fossil | | Natural Gas | | TX | | 1,025 |
| | 1,025 |
| | 100.0 |
|
| W.A. Parish | | ERCOT | | Fossil | | Coal | | TX | | 2,504 |
| | 2,504 |
| | 100.0 |
|
| W.A. Parish | | ERCOT | | Fossil | | Natural Gas | | TX | | 1,145 |
| | 1,145 |
| | 100.0 |
|
| Total Gulf Coast | | 15,678 |
| | 13,714 |
| | |
| | | | | | | | | | | | | | | |
| East/West | | | | | | | | | | | | | | |
| Arthur Kill | | NYISO | | Fossil | | Natural Gas | | NY | | 858 |
| | 858 |
| | 100.0 |
|
| Astoria Turbines | | NYISO | | Fossil | | Natural Gas | | NY | | 404 |
| | 404 |
| | 100.0 |
|
| Conemaugh & Keystone | | PJM | | Fossil | | Coal | | PA | | 3,343 |
| | 125 |
| | 3.7 |
|
| Conemaugh & Keystone | | PJM | | Fossil | | Oil | | PA | | 20 |
| | 1 |
| | 3.7 |
|
| Connecticut Jet Power | | ISO-NE | | Fossil | | Oil | | CT | | 142 |
| | 142 |
| | 100.0 |
|
| Devon | | ISO-NE | | Fossil | | Oil | | CT | | 133 |
| | 133 |
| | 100.0 |
|
| Doga | | | | Fossil | | Natural Gas | | Turkey | | 180 |
| | 144 |
| | 80.0 |
|
Encina(f) | | CAISO | | Fossil | | Natural Gas | | CA | | 859 |
| | 859 |
| | 100.0 |
|
| Fisk | | PJM | | Fossil | | Oil | | IL | | 172 |
| | 172 |
| | 100.0 |
|
| Gladstone | | | | Fossil | | Coal | | AUS | | 1,613 |
| | 605 |
| | 37.5 |
|
| Indian River | | PJM | | Fossil | | Coal | | DE | | 410 |
| | 410 |
| | 100.0 |
|
| Indian River | | PJM | | Fossil | | Oil | | DE | | 16 |
| | 16 |
| | 100.0 |
|
Joliet(c) | | PJM | | Fossil | | Natural Gas | | IL | | 1,326 |
| | 1,326 |
| | 100.0 |
|
| Long Beach | | CAISO | | Fossil | | Natural Gas | | CA | | 260 |
| | 260 |
| | 100.0 |
|
| Middletown | | ISO-NE | | Fossil | | Oil | | CT | | 770 |
| | 770 |
| | 100.0 |
|
| Midway-Sunset | | CAISO | | Fossil | | Natural Gas | | CA | | 226 |
| | 113 |
| | 50.0 |
|
| Montville | | ISO-NE | | Fossil | | Oil | | CT | | 494 |
| | 494 |
| | 100.0 |
|
| Oswego | | NYISO | | Fossil | | Oil | | NY | | 1,639 |
| | 1,639 |
| | 100.0 |
|
Powerton(c) | | PJM | | Fossil | | Coal | | IL | | 1,538 |
| | 1,538 |
| | 100.0 |
|
| Saguaro | | WECC | | Fossil | | Natural Gas | | NV | | 92 |
| | 46 |
| | 50.0 |
|
|
| | | | | | | | | | | | | | | | | |
| Name of Facility | | Power Market | | Plant Type | | Primary Fuel | | Location | | Rated MW Capacity | | Net MW Capacity(a) | | % Owned |
| East/West (continued) | | | | | | | | | | | | | | |
San Diego Turbines(d) | | CAISO | | Fossil | | Natural Gas | | CA | | 61 |
| | 61 |
| | 100.0 |
|
| SMECO | | PJM | | Fossil | | Natural Gas | | MD | | 78 |
| | 78 |
| | 100.0 |
|
| Sunrise | | CAISO | | Fossil | | Natural Gas | | CA | | 586 |
| | 586 |
| | 100.0 |
|
| Vienna | | PJM | | Fossil | | Oil | | MD | | 167 |
| | 167 |
| | 100.0 |
|
| Watson | | CAISO | | Fossil | | Natural Gas | | CA | | 416 |
| | 204 |
| | 49.0 |
|
| Waukegan | | PJM | | Fossil | | Coal | | IL | | 682 |
| | 682 |
| | 100.0 |
|
| Waukegan | | PJM | | Fossil | | Oil | | IL | | 108 |
| | 108 |
| | 100.0 |
|
| Will County | | PJM | | Fossil | | Coal | | IL | | 510 |
| | 510 |
| | 100.0 |
|
| Total East/West | | 17,103 |
| | 12,451 |
| | |
| | | | | | | |
| Renewables | | | | | | | | | | | | | | |
Agua Caliente(g)(j) | | CAISO/WECC | | Renewable | | Solar | | AZ | | 290 |
| | 102 |
| | 35.0 |
|
| Blythe II | | CAISO | | Renewable | | Solar | | CA | | 20 |
| | 20 |
| | 100.0 |
|
Broken Bow(g) | | MISO | | Renewable | | Wind | | NE | | 80 |
| | 13 |
| | 16.0 |
|
Cedro Hill(g) | | ERCOT | | Renewable | | Wind | | TX | | 150 |
| | 47 |
| | 31.0 |
|
Crofton Bluffs(g) | | MISO | | Renewable | | Wind | | NE | | 42 |
| | 8 |
| | 20.0 |
|
| Distributed Solar | | AZNMSNV/WECC | | Renewable | | Solar | | various | | 179 |
| | 179 |
| | 100.0 |
|
Eastridge(h) | | MISO | | Renewable | | Wind | | MN | | 10 |
| | 10 |
| | 99.0 |
|
Guam(j) | | | | Renewable | | Solar | | Guam | | 26 |
| | 26 |
| | 100.0 |
|
Ivanpah(g)(j) | | CAISO | | Renewable | | Solar | | CA | | 392 |
| | 196 |
| | 50.1 |
|
| Langford Wind Farm | | ERCOT | | Renewable | | Wind | | TX | | 150 |
| | 150 |
| | 100.0 |
|
Mountain Wind I(g) | | WECC | | Renewable | | Wind | | WY | | 61 |
| | 19 |
| | 31.0 |
|
Mountain Wind II(g) | | WECC | | Renewable | | Wind | | WY | | 80 |
| | 25 |
| | 31.0 |
|
Sherbino Wind Farm(j) | | ERCOT | | Renewable | | Wind | | TX | | 150 |
| | 75 |
| | 50.0 |
|
Spanish Town(j) | | | | Renewable | | Solar | | USVI | | 4 |
| | 4 |
| | 100.0 |
|
Stadiums(j) | | | | Renewable | | Solar | | various | | 6 |
| | 6 |
| | 100.0 |
|
| Total Renewables | | 1,640 |
| | 880 |
| | |
| | | | | | | | | | | | | | | |
| NRG Yield | | | | | | | | | | | | | | |
Agua Caliente(g) | | CAISO/WECC | | Renewable | | Solar | | AZ | | 290 |
| | 46 |
| | 16.0 |
|
| Alpine | | CAISO | | Renewable | | Solar | | CA | | 66 |
| | 66 |
| | 100.0 |
|
| Alta Wind | | CAISO | | Renewable | | Wind | | CA | | 947 |
| | 947 |
| | 100.0 |
|
| Avenal | | CAISO | | Renewable | | Solar | | CA | | 45 |
| | 23 |
| | 50.0 |
|
| Avra Valley | | CAISO | | Renewable | | Solar | | AZ | | 26 |
| | 26 |
| | 100.0 |
|
| Blythe | | CAISO | | Renewable | | Solar | | CA | | 21 |
| | 21 |
| | 100.0 |
|
| Borrego | | CAISO | | Renewable | | Solar | | CA | | 26 |
| | 26 |
| | 100.0 |
|
| Buffalo Bear | | SPP | | Renewable | | Wind | | OK | | 19 |
| | 19 |
| | 100.0 |
|
| California Valley Solar Ranch | | CAISO/WECC | | Renewable | | Solar | | OK | | 250 |
| | 250 |
| | 100.0 |
|
| Crosswinds | | MISO | | Renewable | | Wind | | CA | | 21 |
| | 21 |
| | 99.0 |
|
| Desert Sunlight | | CAISO | | Renewable | | Solar | | IA | | 550 |
| | 138 |
| | 25.0 |
|
| Distributed Solar | | Various | | Renewable | | Solar | | various | | 27 |
| | 27 |
| | 100.0 |
|
| Dover Cogeneration | | PJM | | Fossil | | Natural Gas | | DE | | 103 |
| | 103 |
| | 100.0 |
|
| El Segundo | | CAISO | | Fossil | | Natural Gas | | CA | | 550 |
| | 550 |
| | 100.0 |
|
| Elbow Creek | | ERCOT | | Renewable | | Wind | | TX | | 122 |
| | 122 |
| | 100.0 |
|
| Elkhorn Ridge | | MISO | | Renewable | | Wind | | NE | | 81 |
| | 54 |
| | 66.7 |
|
| Forward | | PJM | | Renewable | | Wind | | PA | | 29 |
| | 29 |
| | 100.0 |
|
| Four Brothers Solar | | WECC | | Renewable | | Solar | | UT | | 320 |
| | 160 |
| | 50.0 |
|
|
| | | | | | | | | | | | | | | | | |
| Name of Facility | | Power Market | | Plant Type | | Primary Fuel | | Location | | Rated MW Capacity | | Net MW Capacity(a) | | % Owned |
| NRG Yield (continued) | | | | | | | | | | | | | | |
| GenConn Devon | | ISO-NE | | Fossil | | Dual-fuel | | CT | | 190 |
| | 95 |
| | 50.0 |
|
| GenConn Middletown | | ISO-NE | | Fossil | | Dual-fuel | | CT | | 190 |
| | 95 |
| | 50.0 |
|
| Goat Mountain Wind | | ERCOT | | Renewable | | Wind | | TX | | 150 |
| | 150 |
| | 100.0 |
|
| Granite Mountain | | WECC | | Renewable | | Solar | | UT | | 130 |
| | 65 |
| | 50.0 |
|
| Hardin | | MISO | | Renewable | | Wind | | IA | | 15 |
| | 15 |
| | 99.0 |
|
| High Desert | | WECC | | Renewable | | Solar | | CA | | 20 |
| | 20 |
| | 100.0 |
|
| Iron Springs | | WECC | | Renewable | | Solar | | UT | | 80 |
| | 40 |
| | 50.0 |
|
| Kansas South | | WECC | | Renewable | | Solar | | CA | | 20 |
| | 20 |
| | 100.0 |
|
| Laredo Ridge | | MISO | | Renewable | | Wind | | NE | | 80 |
| | 80 |
| | 100.0 |
|
| Lookout | | PJM | | Renewable | | Wind | | PA | | 38 |
| | 38 |
| | 100.0 |
|
| Marsh Landing | | CAISO | | Fossil | | Natural Gas | | CA | | 720 |
| | 720 |
| | 100.0 |
|
| Odin | | MISO | | Renewable | | Wind | | MN | | 20 |
| | 20 |
| | 99.9 |
|
| Paxton Creek Cogeneration | | PJM | | Fossil | | Natural Gas | | PA | | 12 |
| | 12 |
| | 100.0 |
|
| Pinnacle | | PJM | | Renewable | | Wind | | WV | | 55 |
| | 55 |
| | 100.0 |
|
Princeton Hospital(e) | | PJM | | Fossil | | Natural Gas | | NJ | | 5 |
| | 5 |
| | 100.0 |
|
| Roadrunner | | WECC | | Renewable | | Solar | | NM | | 20 |
| | 20 |
| | 100.0 |
|
| San Juan Mesa | | MISO | | Renewable | | Wind | | NM | | 120 |
| | 90 |
| | 75.0 |
|
| Sleeping Bear | | SPP | | Renewable | | Wind | | OK | | 95 |
| | 95 |
| | 100.0 |
|
| SPP projects | | Various | | Renewable | | Solar | | various | | 25 |
| | 25 |
| | 100.0 |
|
| South Trent Wind Farm | | ERCOT | | Renewable | | Wind | | TX | | 101 |
| | 101 |
| | 100.0 |
|
| Spanish Fork, UT | | WECC | | Renewable | | Wind | | UT | | 19 |
| | 19 |
| | 100.0 |
|
| Spring Canyon II and III | | WECC | | Renewable | | Wind | | CO | | 60 |
| | 54 |
| | 90.1 |
|
| Taloga | | SPP | | Renewable | | Wind | | OK | | 130 |
| | 130 |
| | 100.0 |
|
| Tucson Convention Center | | WECC | | Fossil | | Natural Gas | | AZ | | 2 |
| | 2 |
| | 100.0 |
|
| University of Bridgeport | | ISO-NE | | Fossil | | Natural Gas | | CT | | 1 |
| | 1 |
| | 100.0 |
|
| Wildorado | | ERCOT | | Renewable | | Wind | | TX | | 161 |
| | 161 |
| | 100.0 |
|
| Walnut Creek | | CAISO | | Fossil | | Natural Gas | | CA | | 485 |
| | 485 |
| | 100.0 |
|
| | | | | | | Total NRG Yield | | 6,437 |
| | 5,241 |
| | |
| NRG's Noncontrolling Interest | | | | (2,353 | ) | | |
| | | | | | | Net NRG Yield | | | | 2,888 |
| | |
| | | | | | | | | | | | | | | |
| Other | | | | | | | | | | | | | | |
| Residential solar | | | | Renewable | | Solar | | various | | 114 |
| | 114 |
| | 100.0 |
|
| Total Other | | 114 |
| | 114 |
| | |
| | | | | | | | | | | | | | | |
| Total | | 40,972 |
| | 30,047 |
| |
|
|
| |
(a) | Actual capacity can vary depending on factors including weather conditions, operational conditions, and other factors. Additionally, ERCOT requires periodic demonstration of capability, and the capacity may vary individually and in the aggregate from time to time. |
| |
(b) | Generation capacity figure consists of the Company's 44% interest in the two units at STP. |
| |
(c) | NRG leases 100% interests in the Powerton facility and Units 7 and 8 of the Joliet facility through facility lease agreements expiring in 2034 and 2030, respectively. NRG owns 100% interest in Joliet Unit 6. NRG operates the Powerton and Joliet facilities. |
| |
(d) | These units are located on property owned by SDG&E under an annual license agreement. The Miramar and El Cajon sites (51 MW) retired on January, 1, 2017. |
| |
(e) | The output of Princeton Hospital is primarily dedicated to serving the hospital. Excess power is sold to the local utility under its state-jurisdictional tariff. |
| |
(f) | Encina Unit 1 was deactivated on March 31, 2017. |
| |
(g) | Capacity attributable to noncontrolling interest for these Renewables facilities was 685 MWs as of December 31, 2017. |
| |
(h) | In January 2018, NRG sold the Eastridge assets to a third party. |
| |
(i) | Assets that are part of NRG's South Central business. |
| |
(j) | Assets that are not included in the announced sale of NRG's ownership in NRG Yield, Inc. Agua Caliente remains as a ROFO asset under the ROFO Agreement between NRG and NRG Yield, Inc. |
Thermal Facilities
The Company's thermal businesses in Pittsburgh, Harrisburg and San Francisco are regulated by their respective state's Public Utility Commission. The other thermal businesses are subject to contract terms with their customers. The Company's thermal businesses are owned by NRG Yield LLC. The following table summarizes NRG's thermal steam and chilled water facilities as of December 31, 2017:the primary changes that occurred during 2023:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Name of Facility | | Power Market | | Plant Type | | Primary Fuel | | Status | | Location | | Rated MW Capacity | | Net MW Capacity | | % Owned |
| Texas | | | | | | | | | | | | | | | | |
| Gregory | | ERCOT | | Fossil | | Natural Gas | | Sold | | TX | | 365 | | | 365 | | | 100.0 | % |
| South Texas Project | | ERCOT | | Nuclear | | Uranium | | Sold | | TX | | 2,572 | | | 1,132 | | | 44.0 | % |
| East | | | | | | | | | | | | | | | | |
| Astoria Turbines | | NYISO | | Fossil | | Natural Gas | | Retired | | NY | | 420 | | | 420 | | | 100.0 | % |
| Joliet | | PJM | | Fossil | | Natural Gas | | Retired | | IL | | 1,381 | | | 1,381 | | | 100.0 | % |
| | | | | | | | | | Total | | 4,738 | | | 3,298 | | | |
|
| | | | | | | | | | | | | |
| Name and Location of Facility | | Thermal Energy Purchaser | | % Owned | | Rated Megawatt Thermal Equivalent Capacity (MWt) | | Net Megawatt Thermal Equivalent Capacity (MWt) | | Generating Capacity |
| NRG Energy Center Minneapolis, MN | | Approx 100 steam and 55 chilled water customers | | 100 |
| | 322
136 |
| | 322
136 |
| | Steam: 1,100 MMBtu/hr.
Chilled water: 38,700 tons |
| NRG Energy Center San Francisco, CA | | Approx 180 steam customers | | 100 |
| | 133 |
| | 133 |
| | Steam: 454 MMBtu/hr. |
| NRG Energy Center Omaha, NE | | Approx 60 steam and 65 chilled water customers | | 100
12(a) 100 0(a) |
| | 142
73
77 26 |
| | 142
9
77 0 |
| | Steam: 485 MMBtu/hr Steam: 250 MMBtu/hr Chilled water: 22,000 tons Chilled water: 7,250 tons |
| NRG Energy Center Harrisburg, PA | | Approx 125 steam and 5 chilled water customers | | 100 |
| | 108
13 |
| | 108
13 |
| | Steam: 370 MMBtu/hr.
Chilled water: 3,600 tons |
| NRG Energy Center Phoenix, AZ | | Approx 35 chilled water customers | | 24(a) 100 12(a) 0(a) |
| | 5 104 14 28 |
| | 1 104 2 0 |
| | Steam: 17 MMBtu/hr Chilled water: 29,600 tons Chilled water: 3,920 tons Chilled water: 8,000 tons |
| NRG Energy Center Pittsburgh, PA | | Approx 25 steam and 25 chilled water customers | | 100 |
| | 88
49 |
| | 88
49 |
| | Steam: 302 MMBtu/hr.
Chilled water: 13,874 tons |
| NRG Energy Center San Diego, CA | | Approx 20 chilled water customers | | 100 |
| | 31 |
| | 31 |
| | Chilled water: 8,825 tons |
| NRG Energy Center Dover, DE | | Kraft Foods Inc. and Procter & Gamble Company | | 100 |
| | 66 |
| | 66 |
| | Steam: 225 MMBtu/hr. |
| NRG Energy Center Princeton, NJ | | Princeton HealthCare System | | 100 |
| | 21
17 |
| | 21
17 |
| | Steam: 72 MMBtu/hr.
Chilled water: 4,700 tons |
| | | Total Generating Capacity (MWt) | | | | 1,453 |
| | 1,319 |
| | |
| |
(a) | Net MWt capacity excludes 134 MWt available under the right-to-use provisions contained in agreements between two of NRG Yield Inc.'s thermal facilities and certain of its customers. |
Other Properties
NRG owns several real properties and facilities related to its generation assets, other vacant real property unrelated to the Company'sits generation assets, interests in construction projects, and properties not used for operational purposes. NRG believes it has satisfactory title to its plants and facilities in accordance with standards generally accepted in the electric power industry, subject to exceptions that, in the Company's opinion, would not have a material adverse effect on the use or value of its portfolio.
NRG leases its financialoperational and commercial corporate headquarters at 804 Carnegie Center, Princeton, New Jersey, its operational headquarters in Houston, Texas, its financial and commercial corporate offices in Princeton, New Jersey, its smart home corporate offices in Provo, Utah, as well as its retail businessoperations offices, andsmart home monitoring stations, call centers, warehouses and various other office space.
Item 3 — Legal Proceedings
See Item 15 — Note 22, 23, Commitments and Contingencies, to the Consolidated Financial Statements for discussion of the material legal proceedings to which NRG is a party.
Item 4 — Mine Safety Disclosures
Not applicable.There have been no events that are required to be reported under this Item.
PART II
Item 5 — Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity SecuritiesSecurities.
Market Information and Holders and Dividends
NRG's common stock trades on the New York Stock Exchange under the symbol "NRG". NRG's authorized capital stock consists of 500,000,000 shares of NRG common stock and 10,000,000 shares of preferred stock. A total of 25,000,000 shares of the Company's common stock are authorized for issuance under the NRG LTIP. NoLTIP, and a total of 17,500,000 shares of NRG common stock were availableare authorized for future issuance under the NRG GenOnVivint LTIP. For more information about the NRG LTIP and the NRG GenOn LTIP,LTIPs, refer to Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters and Item 15 — Note 20, 21, Stock-Based Compensation, to the Consolidated Financial Statements.
NRG's common stock is listed on the New York Stock Exchange and has been assigned the symbol: NRG. The high and low sales prices, as well as the closing price for the Company's common stock on a per share basis for 2017 and 2016 are set forth below:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Common Stock Price | Fourth Quarter 2017 | | Third Quarter 2017 | | Second Quarter 2017 | | First Quarter 2017 | | Fourth
Quarter
2016 | | Third
Quarter
2016 | | Second
Quarter
2016 | | First
Quarter
2016 |
| High | $ | 29.78 |
| | $ | 26.25 |
| | $ | 19.07 |
| | $ | 18.95 |
| | $ | 13.06 |
| | $ | 16.02 |
| | $ | 18.32 |
| | $ | 14.47 |
|
| Low | 24.55 |
| | 15.95 |
| | 14.52 |
| | 12.19 |
| | 9.84 |
| | 10.70 |
| | 11.69 |
| | 8.92 |
|
| Closing | 28.48 |
| | 25.59 |
| | 17.22 |
| | 18.70 |
| | 12.26 |
| | 11.21 |
| | 14.99 |
| | 13.01 |
|
| Dividends Per Common Share | $ | 0.030 |
| | $ | 0.030 |
| | $ | 0.030 |
| | $ | 0.030 |
| | $ | 0.030 |
| | $ | 0.030 |
| | $ | 0.030 |
| | $ | 0.145 |
|
NRG had 316,743,089shares outstanding as of December 31, 2017.As of January 31, 2018,February 1, 2024, there were 317,637,917 shares outstanding, and there were 21,15015,102 common stockholders of record.
On January 19, 2018, NRG declared a quarterlyJune 22, 2023, the Company updated its capital allocation framework, and plans, after debt reduction, to return approximately 80% of excess cash to shareholders and invest 20% in growth initiatives. The Company expects to return the capital to shareholders through share repurchases and dividends on its common stock.
Consistent with its capital allocation framework, in 2021, 2022 and 2023, the Company increased the annual dividend on the Company'sits common stock of $0.030to $1.30, $1.40 and $1.51 per share, or $0.12respectively, representing an 8% increase each year. The Company further increased the annual dividend by 8% to $1.63 per share beginning in the first quarter of 2024. The long-term capital allocation policy targets an annual dividend growth rate of 7-9% per share.
Issuer Purchases of Equity Securities
NRG engages in share repurchase programs with the goal of returning excess cash to shareholders. The share repurchase plan permits the execution of the plan through open-market purchases, private transactions, accelerated share repurchases and other similar transactions. The timing, price and volume of repurchases is based on an annualized basis, payable on February 15, 2018, to stockholdersa number of record as of February 1, 2018.
The Company's common stock dividends are subject tofactors, including available capital, market conditions, and compliance with associated laws and regulations.
On June 22, 2023, as part of the updated capital allocation framework, the Company announced that the Board of Directors has increased the share repurchase authorization of its common stock to $2.7 billion to be executed through 2025. Through December 31, 2023, the Company completed $1.2 billion of share repurchases under the $2.7 billion authorization. For further information regarding share repurchases, see Item 15 — Note 16, Capital Structure in this Form 10-K.
The table below sets forth the information with respect to purchases made by or on behalf of NRG or any "affiliated purchaser" (as defined in Rule 10b-18(a)(3) under the Exchange Act) of NRG's common stock during the quarter ended December 31, 2023.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the three months ended December 31, 2023 | | Total Number of Shares Purchased | | Average Price Paid per Share(a) | | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (in millions)(b) |
| Month #1 | | | | | | | | |
| (October 1, 2023 to October 31, 2023 | | 3,732,657 | | | $ | 40.17 | | | 3,732,657 | | | $ | 2,500 | |
| Month #2 | | | | | | | | |
| (November 1, 2023 to November 30, 2023) | | 4,494,224 | | | (c) | | 4,494,224 | | | $ | 1,550 | |
| Month #3 | | | | | | | | |
| (December 1, 2023 to December 31, 2023) | | 13,181,918 | | | (c) | | 13,181,918 | | | $ | 1,550 | |
| | | | | | | | |
| Total at December 31, 2023 | | 21,408,799 | | | | | 21,408,799 | | | |
(a)The average price paid per share excludes excise taxes and commissions per share paid in connection with the open market share repurchases
(b)Includes commissions of $0.015 per share paid in connection with the open market share repurchases
(c)Represents shares delivered under the November 6, 2023 ASR agreements. The total number of shares delivered and the average price per share under the ASR agreements will be determined at the end of the ASR period which is expected to occur in March of 2024. See Item 15—Note 16, Capital Structure for additional information on the ASR agreements
Director and Officer Trading Arrangements
The Company’s officers and directors are required to comply with the Company’s Securities Trading and Non-Disclosure Policy at all times, including during a share repurchase program. The securities trading and non-disclosure policy, among other things, prohibits trading in the Company’s securities when in possession of material non-public information and restricts the ability of certain officers or directors from transacting in the Company’s securities during specific blackout periods, subject to certain limited exceptions, including transactions pursuant to a Rule 10b5-1 trading plan that complies with the conditions of Securities Exchange Act Rule 10b5-1. The Company’s policy also requires officers and directors to obtain preclearance in advance of effecting any purchase, sale or other trading of Company stock. See Item 9B — Other Information, for details of any "Rule 10b5-1 trading arrangement" or "non-Rule 10b5-1 trading arrangement" by any director or officer of the Company during the three months ended December 31, 2023.
Stock Performance Graph
The performance graph below compares NRG'sthe cumulative total stockholder return on the Company'sNRG's common stock for the period December 31, 20122018 through December 31, 20172023, with the cumulative total return of the Standard & Poor's 500 Composite Stock Price Index or ("S&P 500,500") and the Philadelphia Utility Sector Index or UTY. NRG's common stock trades on the New York Stock Exchange under the symbol "NRG."("UTY").
The performance graph shown below is being furnished and compares each period assuming that $100 was invested on December 31, 2012,2018, in each of the common stock of NRG, the stocks included in the S&P 500 and the stocks included in the UTY, and that all dividends were reinvested.
Comparison of Cumulative Total Return
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 12/31/2018 | | 12/31/2019 | | 12/31/2020 | | 12/31/2021 | | 12/31/2022 | | 12/31/2023 |
| NRG Energy, Inc. | $ | 100.00 | | | $ | 100.69 | | | $ | 98.53 | | | $ | 116.81 | | | $ | 89.40 | | | $ | 151.29 | |
| S&P 500 | 100.00 | | | 131.49 | | | 155.68 | | | 200.37 | | | 164.08 | | | 207.21 | |
| UTY | 100.00 | | | 126.82 | | | 130.27 | | | 154.04 | | | 155.04 | | | 140.83 | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Dec-2012 | | Dec-2013 | | Dec-2014 | | Dec-2015 | | Dec-2016 | | Dec-2017 |
| NRG Energy, Inc. | $ | 100.00 |
| | $ | 127.02 |
| | $ | 121.33 |
| | $ | 54.56 |
| | $ | 58.06 |
| | $ | 135.68 |
|
| S&P 500 | 100.00 |
| | 132.39 |
| | 150.51 |
| | 152.59 |
| | 170.84 |
| | 208.14 |
|
| UTY | 100.00 |
| | 110.98 |
| | 143.09 |
| | 134.14 |
| | 157.47 |
| | 177.66 |
|
Item 6 — Selected Financial DataReserved
The following table presents NRG's historical selected financial data. This historical data should be read in conjunction with the Consolidated Financial Statements and the related notes thereto in Item 15 and Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. The Company has completed several acquisitions and dispositions, as described in Item 15 — Note 3, Discontinued Operations, Acquisitions and Dispositions.
|
| | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| | (In millions except ratios and per share data) |
| Statement of income data: | | | | | | | | | |
| Total operating revenues | $ | 10,629 |
| | $ | 10,512 |
| | $ | 12,328 |
| | $ | 12,810 |
| | $ | 8,820 |
|
Total operating costs and other expenses (a) | (10,484 | ) | | (10,633 | ) | | (12,612 | ) | | (13,033 | ) | | (8,944 | ) |
Impairment losses (b) | (1,709 | ) | | (702 | ) | | (4,860 | ) | | (15 | ) | | (459 | ) |
| Operating (loss)/income | (587 | ) | | 266 |
| | (4,051 | ) | | 895 |
| | 198 |
|
| Impairment losses on investments | (79 | ) | | (268 | ) | | (56 | ) | | — |
| | (99 | ) |
| Loss from continuing operations, net | (1,548 | ) | | (983 | ) | | (6,331 | ) | | (72 | ) | | (308 | ) |
| (Loss)/income from discontinued operations, net | (789 | ) | | 92 |
| | (105 | ) | | 204 |
| | (43 | ) |
| Net (loss)/income attributable to NRG Energy, Inc. | $ | (2,153 | ) | | $ | (774 | ) | | $ | (6,382 | ) | | $ | 134 |
| | $ | (386 | ) |
| Common share data: | | | | | | | | | |
| Basic shares outstanding — average | 317 |
| | 316 |
| | 329 |
| | 334 |
| | 323 |
|
| Diluted shares outstanding — average | 317 |
| | 316 |
| | 329 |
| | 339 |
| | 323 |
|
| Shares outstanding — end of year | 317 |
| | 315 |
| | 314 |
| | 337 |
| | 324 |
|
| Per share data: | | | | | | | | | |
| Net (loss)/income attributable to NRG — basic and diluted | $ | (6.79 | ) | | $ | (2.22 | ) | | $ | (19.46 | ) | | $ | 0.23 |
| | $ | (1.22 | ) |
| Dividends declared per common share | 0.12 |
| | 0.24 |
| | 0.58 |
| | 0.54 |
| | 0.45 |
|
| Book value | $ | 6.20 |
| | $ | 14.09 |
| | $ | 17.29 |
| | $ | 34.68 |
| | $ | 32.33 |
|
| Business metrics: | | | | | | | | | |
| Cash flow from operations | $ | 1,387 |
| | $ | 2,088 |
| | $ | 1,349 |
| | $ | 1,559 |
| | $ | 1,149 |
|
Liquidity position (c) | 3,210 |
| | 2,373 |
| | 2,418 |
| | 2,757 |
| | 2,767 |
|
| Ratio of earnings to fixed charges | (0.52) | | 0.29 |
| | (4.01 | ) | | 0.98 |
| | 0.36 |
|
| Ratio of earnings to fixed charges and preferred dividends | (0.52) | | 0.29 |
| | (3.88 | ) | | 0.89 |
| | 0.36 |
|
| Return on equity | (109.40 | )% | | (17.41 | )% | | (117.45 | )% | | 1.15 | % | | (3.69 | )% |
| Ratio of debt to total capitalization | 88.70 | % | | 77.75 | % | | 72.58 | % | | 56.98 | % | | 52.81 | % |
| Balance sheet data: | | | | | | | | | |
| Current assets | $ | 4,415 |
| | $ | 6,714 |
| | $ | 7,619 |
| | $ | 8,784 |
| | $ | 7,776 |
|
| Current liabilities | 3,317 |
| | 4,702 |
| | 4,602 |
| | 5,236 |
| | 4,381 |
|
| Property, plant and equipment, net | 13,908 |
| | 15,369 |
| | 15,901 |
| | 19,321 |
| | 16,676 |
|
| Total assets | 23,318 |
| | 30,682 |
| | 33,125 |
| | 40,856 |
| | 34,081 |
|
| Long-term debt, including current maturities, and capital leases | 16,404 |
| | 16,473 |
| | 16,698 |
| | 17,047 |
| | 13,485 |
|
| Total stockholders' equity | $ | 1,968 |
| | $ | 4,446 |
| | $ | 5,434 |
| | $ | 11,676 |
| | $ | 10,467 |
|
| |
(a) | Excludes impairment losses and impairment losses on investments. |
| |
(b) | Includes goodwill impairment as described in Item 15 - Note 11, Goodwill and Other Intangibles, to the Consolidated Financial Statements.
|
| |
(c) | Liquidity position is determined as disclosed in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, Liquidity and Capital Resources, Liquidity Position. It excludes collateral funds deposited by counterparties of $37 million, $2 million, and $91 million as of December 31, 2017, 2016 and 2015, respectively, which represents cash held as collateral from hedge counterparties in support of energy risk management activities. It is the Company's intention to limit the use of these funds for repayment of the related current liability for collateral received in support of energy risk management activities.
|
The following table provides the details of NRG's operating revenues:
|
| | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| | (In millions) |
Energy revenue | $ | 3,549 |
| | $ | 4,122 |
| | $ | 4,923 |
| | $ | 4,960 |
| | $ | 3,638 |
|
Capacity revenue | 1,197 |
| | 1,236 |
| | 1,368 |
| | 1,201 |
| | 936 |
|
Retail revenue | 6,385 |
| | 6,336 |
| | 6,910 |
| | 7,372 |
| | 6,315 |
|
| Mark-to-market for economic hedging activities | 21 |
| | (572 | ) | | (143 | ) | | 690 |
| | (185 | ) |
| Contract amortization | (56 | ) | | (56 | ) | | (40 | ) | | (12 | ) | | (32 | ) |
| Other revenues | 490 |
| | 543 |
| | 425 |
| | 536 |
| | 287 |
|
| Corporate/Eliminations | (957 | ) | | (1,097 | ) | | (1,115 | ) | | (1,937 | ) | | (2,139 | ) |
Total operating revenues(a) | $ | 10,629 |
| | $ | 10,512 |
| | $ | 12,328 |
| | $ | 12,810 |
| | $ | 8,820 |
|
(a) Inter-segment sales and net derivative gains and losses included in operating revenues.
Energy revenue consists of revenues received from third parties as well as from the Company's retail businesses, for sales of electricity in the day-ahead and real-time markets, as well as bilateral sales. It also includes energy sold through long-term PPAs for renewable facilities. In addition, energy revenue includes revenues from the settlement of financial instruments and net realized trading revenues.
Capacity revenue consists of revenues received from a third party at either the market or negotiated contract rates for making installed generation capacity available in order to satisfy system integrity and reliability requirements. Capacity revenue also includes revenues from the settlement of financial instruments. In addition, capacity revenue includes revenues received under tolling arrangements, which entitle third parties to dispatch NRG's facilities and assume title to the electrical generation produced from that facility.
Retail revenue, representing operating revenues of NRG's retail businesses, consists of revenues from retail sales to residential, small business, commercial, industrial and governmental/institutional customers, revenues from the sale of excess supply into various markets, primarily in Texas, as well as product sales.
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.
Contract amortization revenue consists of the amortization of the intangible assets for net in-market C&I contracts established in connection with the acquisitions of Reliant Energy and Green Mountain Energy, as well as acquired power contracts, gas derivative instruments, and certain power sales agreements assumed at Fresh Start and Texas Genco purchase accounting dates related to the sale of electric capacity and energy in future periods. These amounts are amortized into revenue over the term of the underlying contracts based on actual generation or contracted volumes.
Other revenues include revenues generated by the Thermal Business consisting of revenues received from the sale of steam, hot and chilled water generally produced at a central district energy plant and sold to commercial, governmental and residential buildings for space heating, domestic hot water heating and air conditioning. It also includes the sale of high-pressure steam produced and delivered to industrial customers that is used as part of an industrial process. Other revenues also consists of operations and maintenance fees, or O&M fees, construction management services, or CMA fees, sale of natural gas and emission allowances, and revenues from ancillary services. O&M fees consist of revenues received from providing certain unconsolidated affiliates with services under long-term operating agreements. CMA fees are earned where NRG provides certain management and oversight of construction projects pursuant to negotiated agreements such as for the GenConn, Cedar Bayou 4 and certain solar construction projects. Ancillary services are comprised of the sale of energy-related products associated with the generation of electrical energy such as spinning reserves, reactive power and other similar products. Other revenues also include unrealized trading activities.
Item 7 — 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 the business environment in which NRGthe Company operates, a discussion of regulation, weather, competition and other factors that affect the business, and other significant events that are important to understanding the results of operations and financial condition;
•Results of operations for the years ended December 31, 2023 and December 31, 2022, including an explanation of significant differences between the periods in the specific line items of NRG's Consolidated Statements of Operations;
Financial•Liquidity and capital resources including liquidity position, financial condition addressing credit ratings, liquidity position, sourcesmaterial cash requirements and uses of cash, capital resources and requirements, commitments, and off-balance sheet arrangements;other obligations; and
•Critical accounting policies whichestimates that are most important to both the portrayal of the Company's financial condition and results of operations, and which require management's most difficult, subjective, or complex judgment.judgments.
As you read this discussion and analysis, refer to NRG's Consolidated Statements of Operations toin this Form 10-K, which presentspresent the results of the Company's operations for the years ended December 31, 2017, 2016,2023 and 2015,2022, and also refer to Item 1 — Business to this Form 10-K for more detaileddetail discussion about the Company's business. A discussion and analysis of fiscal year 2021 may be found in Part II, Item 7 — Management's Discussion and Analysis of Financial Condition and Results of Operations of the Annual Report on Form 10-K for the fiscal year ended December 31, 2022.
Executive Summary
NRG Energy, Inc., or NRG or the Company, sits at the intersection of energy and home services. NRG is a leading integrated powerenergy and home services company built on the strength of a diverse competitive electric generation portfoliofueled by market-leading brands, proprietary technologies and leading retail electricity platform. NRG aims to create a sustainable energy future by producing, selling and delivering electricity and related products and services in major competitive power markets incomplementary sales channels. Across the U.S. in a manner thatand Canada, NRG delivers value to all of NRG's stakeholders.innovative, sustainable solutions, predominately under the 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 ownshas a customer base that includes approximately 8 million residential consumers in addition to commercial, industrial, and operateswholesale customers, supported by approximately 30,000 MW13 GW of generation; trades 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" and other retail brand names owned by NRG.generation as of December 31, 2023.
Business Environment
The industry dynamics and external influences affecting the Company, and its businesses, and the retail energy and power generation and retail energy industry in general in 20172023 and for the future medium term include:
Capacity Markets — Capacity markets are a major source of revenue for the Company. Centralized capacity markets exist in ISO-NE, MISO, NYISO and PJM. Bilateral markets exist in CAISO and MISO. These auctions are either an annual market held three years ahead of the delivery period as in the case of PJM and ISO-NE, or six months to one month ahead as in the case of NYISO. Many variables affect the prices derived in these auctions. These variables include the load forecast, the target reserve margin, rules surrounding demand response, capacity performance penalties, capacity imports and exports from the region, new generation entrants, slope of the demand curve, generation retirements, the cost of retrofitting old generation to meet new environmental rules, expected profitability of the units themselves in the energy market and various other auction rules. In theory, a high capacity price indicates that the ISO doesn't have sufficient generation capacity against its needed reserve margin and new construction should enter the market. Similarly, a low capacity price suggests the market is over-built and units should retire. The Company has seen many swings in the pricing for capacity markets and the rules in many of the markets are undergoing significant changes, as discussed in this Management's Discussion and Analysis of Financial Condition and Results of Operations.
Commodities MarketsMarket Dynamics — The price of natural gas plays an important role in setting the price of electricity in many of the regions where NRG operates power plants.operates. Natural gas prices are driven by variables including demand from the industrial, residential, and electric sectors, productivity across natural gas supply basins, costs of natural gas production, changes in pipeline infrastructure, global LNG demand, exports of natural gas, and the financial and hedging profile of natural gas consumerscustomers and producers. In 2017,2023, the average natural gas pricesprice at Henry Hub were 26.3% higher thanwas $2.74 per MMBtu compared to $6.64 per MMBtu in 2016.2022, representing a decrease of 59%.
If long-term gas prices decrease, the Company is likelyNRG may experience impacts to encounter lower realized energy prices, leading to lower energy revenues as higher priced hedge contracts mature and are replaced by contracts with lower gas and power prices. NRG's retail gross margins have historically improved asdue to significant, rapid changes in current natural gas prices, declinethe impact those prices have on power prices, and are likelythe lag in its ability to partially offsetmake a corresponding adjustment to the retail rates it charges customers on term and month to month contracts. The Company hedges its load commitments in order to mitigate the impact of decliningchanges in commodity prices, and as a result, these gross margin impacts would be realized in future periods until it is able to make the corresponding adjustments to the retail customer rates.
The relative price of natural gas prices on conventional wholesale power generation. To further mitigate this impact, NRG may increase its percentage ofas compared to coal and nuclear capacity sold forward using a variety of hedging instruments, as described under the heading "Energy-Related Commodities" in Item 15 — Note 5, Accounting for Derivative Instruments and Hedging Activities, to the Consolidated Financial Statements.
Natural gasprevailing power prices are athe primary driver of coal demand. The low pricedCoal commodity environment has stressed coal equities, leading coal suppliers to file for bankruptcy protection, launch debt exchanges, rationalize assets, and cut production. If multiple parties withdraw from the market, liquidity could be challengedprices decreased slightly in the short term. Inventory overhang will be utilized to offset production losses. Coal prices are typically affected by the price of natural gas. 2023.
Electricity Prices — The price of electricity is a key determinant of the profitability of the Company. Many variables such as the price of different fuels, weather, load growth and unit availability all coalesce to impact the final price for electricity and the Company's profitability. An increase in supply cost volatility in the competitive retail markets may result in smaller companies choosing to exit the market, which may result in further consolidation in the competitive retail space. The following table summarizes average on-peak power prices for each of the major markets in which NRG operates for the years ended December 31, 2017, 2016, and 2015.operates. For the year ended December 31, 20172023, as compared to the same period in 2016, the average on-peak power prices increased primarily due to the increase in natural gas prices. For the year ended December 31, 2016 as compared to the same period in 2015 the2022, Texas, East and West average on-peak power prices decreased primarily due to the decrease inas a result of lower natural gas prices.
| | | | | | | | | | | | | | | | | |
| | Average On-Peak Power Price ($/MWh) |
| Year Ended December 31, | | 2023 vs 2022 |
| Region | 2023 | | 2022 | | Change % |
| Texas | | | | | |
ERCOT - Houston(a) | $ | 74.32 | | | $ | 90.62 | | | (18) | % |
ERCOT - North(a) | 72.89 | | | 78.34 | | | (7) | % |
| East | | | | | |
NY J/NYC(b) | 38.95 | | | 93.58 | | | (58) | % |
NEPOOL(b) | 41.36 | | | 92.42 | | | (55) | % |
COMED (PJM)(b) | 32.72 | | | 71.86 | | | (54) | % |
PJM West Hub(b) | 39.34 | | | 83.48 | | | (53) | % |
| West | | | | | |
CAISO - SP15(b) | 60.17 | | | 87.67 | | | (31) | % |
MISO - Louisiana Hub(b) | 33.64 | | | 71.12 | | | (53) | % |
|
| | | | | | | | | | | | | | | | | |
| | Average on Peak Power Price ($/MWh) |
| | Year Ended December 31 | | 2017 vs 2016 | | 2016 vs 2015 |
| Region | 2017 | | 2016 | | 2015 | | Change % | | Change % |
Gulf Coast (a) | | | | | | | | | |
ERCOT - Houston(b) | $ | 33.95 |
| | $ | 26.91 |
| | $ | 28.15 |
| | 26 | % | | (4 | )% |
ERCOT - North(b) | 25.86 |
| | 24.53 |
| | 27.61 |
| | 5 | % | | (11 | )% |
MISO - Louisiana Hub(c) | 40.02 |
| | 34.30 |
| | 34.55 |
| | 17 | % | | (1 | )% |
| East/West | | | | | | | | |
|
NY J/NYC(c) | 38.34 |
| | 35.29 |
| | 46.42 |
| | 9 | % | | (24 | )% |
NEPOOL(c) | 37.18 |
| | 35.05 |
| | 48.25 |
| | 6 | % | | (27 | )% |
COMED (PJM)(c) | 32.46 |
| | 32.11 |
| | 34.13 |
| | 1 | % | | (6 | )% |
PJM West Hub(c) | 34.14 |
| | 33.79 |
| | 41.97 |
| | 1 | % | | (19 | )% |
CAISO - NP15(c) | 35.68 |
| | 31.73 |
| | 35.50 |
| | 12 | % | | (11 | )% |
CAISO - SP15(c) | 36.48 |
| | 31.17 |
| | 32.45 |
| | 17 | % | | (4 | )% |
(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 aheadday-ahead settlement prices as published by the respective ISOs.ISOs
Increased Awareness of, and Action to Combat, Climate Change —Diverse groups of stakeholders, including investors, asset managers, financial institutions, non-government organizations, industry coalitions, individual companies, consumer groups and academic institutions, are increasingly engaged in efforts to limit global warming in the post-industrial era to 1.5 degrees Celsius. As a result, policymakers and regulators at regional, national, sub-national and local levels of government, both in the U.S. and other parts of the world, are increasingly focused on actions to combat climate change.
The following table summarizes average realized power prices for each region in which NRG operates for the years ended December 31, 2017, 2016,actively monitors climate change related developments that could impact its business and 2015, which reflects the impactregularly engages with a diverse set of settled hedges.
|
| | | | | | | | | | | | | | | | | |
| | Average Realized Power Price ($/MWh) |
| | Year Ended December 31 | | 2017 vs 2016 | | 2016 vs 2015 |
| Region | 2017 | | 2016 | | 2015 | | Change % | | Change % |
| Gulf Coast | $ | 36.43 |
| | $ | 43.34 |
| | $ | 42.89 |
| | (16 | )% | | 1 | % |
| East/West | 62.07 |
| | 64.16 |
| | 68.79 |
| | (3 | )% |
| (7 | )% |
Though the averagestakeholders on peak power prices have increased on average by 9% for the year ended December 31, 2017 as compared to the same period in 2016, and decreased on average by 15% for the year ended December 31, 2016 as compared to the same period in 2015, average realized prices by region forthese issues. Such engagement helps the Company were driven by the Company's multi-year hedging programidentify and the successpursue potential opportunities both to decarbonize its business and better serve its customers. NRG is committed to providing transparent disclosures of its climate risks and opportunities to stakeholders. The Company was an early supporter of the Company's commercial operations teamTask Force on Climate-related Financial Disclosures ("TCFD") recommendations after they were issued in optimizing the value of the Company's assets on2017, published a daily basis.TCFD mapping disclosure in December 2020 and issued a stand-alone TCFD report in December 2021.
Environmental Regulatory Landscape — The MATS rule, finalized in 2012, had been the primary regulatory force behind the decision to retrofit, repower or retire uncontrolled coal fired power plants. In June 2015, the U.S. Supreme Court held that the EPA unreasonably refused to consider costs when it determined 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 costs to address the U.S. Supreme Court's ruling that the EPA had not properly considered costs. This finding has been challenged in the D.C. Circuit. On April 18, 2017, the EPA asked the D.C. Circuit to postpone oral argument that had been scheduled for May 18, 2017 because the EPA is closely reviewing the supplemental finding to determine whether it should reconsider all or part of the rule. On April 27, 2017, the D.C. Circuit granted the EPA's request to postpone the oral argument and hold the case in abeyance. A number of regulations on GHGs, ambient air quality, coal combustion byproducts and water use with the potential for increased capital costs or operational impacts have been finalized and are under review by the courts and being re-evaluated by the current Administration. The design, timing and stringency of these regulations and the legal outcomes will affect the decision to retrofit or retire existing fossil plants. See Item 1— Business, Environmental Matters, for further discussion.
Public Policy Support and Government Financial Incentives for CleanLower Carbon Infrastructure Development — Policy mechanisms at the state and federal level, including production and investment tax credits, cash grants, loan guarantees, accelerated depreciation tax benefits, RPS, and carbon trading plans, have been implemented at the statesupported and federal levelscontinue to support the development of renewable generation, demand-side and smart grid, and other cleanlower carbon infrastructure technologies. The availabilityU.S. Inflation Reduction Act, signed into law in August 2022, is intended to further support the deployment of lower carbon energy technologies. As costs associated with the development of lower carbon infrastructure, such as wind and continuationsolar generating facilities, continue to evolve and impact the development of public policy support mechanisms will drive a significant part oflower carbon infrastructure in the economicsmarkets where the Company participates, it may impact the ability of the Company's development program. In December 2015, the U.S. Congress enacted an extensiongenerating facilities to participate in those markets. According to ERCOT, 41% of the 30% solar ITC so that projects that began construction in 2016 through 2019 will continue to qualify for the 30% ITC. Projects beginning construction in 2020 and 2021 will be eligible for the ITC at the rates of 26% and 22% respectively. The same legislation also extended the 10 year wind PTC for wind projects that began construction in years 2016 through 2019. Wind projects that begin construction2023 energy consumption in the years 2017, 2018ERCOT market was generated from carbon emission-free resources, with wind power contributing 24%. In addition, as subsidies and 2019incentives contribute to increases in renewable power sources, customer awareness and preferences are eligibleshifting toward sustainable solutions. Increased demand for PTC at 80%, 60%sustainable energy products from both residential and 40%commercial customers creates opportunities for diversified product offerings in competitive retail markets.
Digitization and Customization — The electric industry is experiencing major technological changes in the way power is distributed and consumed by end-use customers. The electric grid is shifting from a centralized analog system, where power is generated from limited sources and flows in one direction, to a decentralized multidirectional system, where power can be generated from a number of the statutory rate per kilowatt hour respectively.distributed resources and stored or dispatched on an as-needed basis. In addition, customers are seeking new ways to engage with their power providers. Technologies like smart thermostats, smart appliances and electric vehicles are giving individuals more choice and control over their electricity usage. Power providers are starting to engage with customers who have transitioned to smart homes with new offerings, including but not limited to behind-the-meter demand
response, or virtual power plant products. Companies with large customer bases in competitive market places are poised to create further engagement with their customer bases and help their customers further integrate their smart home into their daily lives.
Weather— Weather conditions in the regions of the U.S. in which NRG doesconducts business influence the Company's financial results. Weather conditions can affect the supply and demand for electricity and fuels. Weatherfuels and may also impact the availability of the Company's generating assets. Changes in energy supply and demand may impact the price of these energy commodities in both the spot and forward markets, which may affect the Company's results in any given period. Typically, demand for and the price of electricity is higher in the summer and the winter seasons, when temperatures and resultant demand are more extreme. The demand for and price of natural gas is also generally higher in the winter. However, all regions of the U.S. typically do not experience extreme weather conditions at the same time, thus NRG isNRG's operations are typically not exposed to the effects of extreme weather in all parts of its business at once.
Wind and Solar Resource Availability — The availability of the wind and solar resources affects the financial performance of the wind and solar facilities, which may impact the Company’s overall financial performance. Due to the variable nature of the wind and solar resources, the Company cannot predict the availability of the wind and solar resources and the potential variances from expected performance levels from quarter to quarter. To the extent the wind and solar resources are not available at expected levels, it could have a negative impact on the Company’s financial performance for such periods.
ERCOT Retirements — A number of announced retirement notices of coal generating facilities owned by others 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.
Net Impact of Tax Reform — The Tax Cuts and Jobs Act of 2017, or the Tax Act, which was signed into law on December 22, 2017, makes significant changes to the taxation of U.S. businesses. These changes include a permanent reduction to the federal corporate income tax rate, changes in the deductibility of interest on certain debt obligations and limiting the amount of NOL available to offset taxable income, among other things. The Tax Act requires the Company to revalue its deferred tax assets, which reduced the Company’s deferred tax assets by $733 million offset by valuation allowance of $660 million. In addition, the Company established a non-current receivable for its refundable AMT credits of $64 million, net of sequestration. The net impact of the Tax Act on net income is a decrease of $9 million due to the expense of $73 million resulting from the Company's revaluation of its net deferred tax asset, partially offset by a $64 million benefit from establishing the AMT credit receivable.
Other Factors— A number of other factors significantly influence the level and volatility of prices for energy commodities and related derivative products for NRG's business. These factors include:
•seasonal, daily and hourly changes in demand;
•extreme peak demands;
•performance of renewable generation;
•available supply resources;
•transportation and transmission availability and reliability within and between regions;
•location of NRG's generating facilities relative to the location of its load-serving opportunities;
•procedures used to maintain the integrity of the physical electricity system during extreme conditions; and
•changes in the nature and extent of federal and state regulations.
These factors can affect energy commodity and derivative prices in different ways and to different degrees. These effects may vary throughout the country as a result of regional differences in:
•weather conditions;
•market liquidity;
•capability and reliability of the physical electricity and gas systems;
•local transportation systems; and
•the nature and extent of electricity deregulation.
Environmental Matters, Regulatory Matters and Legal Proceedings— Details of environmental matters are presented in Item 15 — Note 24, 25, Environmental Matters, to the Consolidated Financial Statements and Item 1— Business, Environmental Matters section.. Details of regulatory matters are presented in Item 15 — Note 23, 24, Regulatory Matters, to the Consolidated Financial Statements and Item 1— Business, Regulatory Matters section.. Details of legal proceedings are presented in Item 15 — Note 22, 23, Commitments and Contingencies, to the Consolidated Financial Statements. Some of this information relates to costs that may be material to the Company's financial results.
Significant Events
NRG Transformation PlanThe following significant events occurred during 2023 and through the filing date, as further described within this Management's Discussion and Analysis and the Consolidated Financial Statements:
Vivint Smart Home Acquisition and related financings
NRG isOn March 10, 2023, the Company completed the acquisition of Vivint Smart Home. The Company paid $12 per share, or $2.6 billion in processcash. See Item 15 — Note 4, Acquisitions and Dispositions, to the Consolidated Financial Statements for further discussion.
On March 9, 2023, the Company issued 650,000 shares of executing its Transformation Plan.10.25% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock. The three-part, three-year plan is comprisedproceeds, net of targets inissuance costs, of $635 million were used to partially fund the areasVivint Smart Home acquisition.
On March 9, 2023, the Company issued $740 million of operational and cost excellence, portfolio optimization, and capital structure and allocation enhancement. For further discussion, refer to Item 1 - Business.
During 2017, NRG received cash proceeds from asset sales in theaggregate principal amount of $1507.000% senior secured first lien notes due 2033. The net proceeds of $724 million, which includesnet of issuance costs, were used to partially fund the sales to NRG Yield, Inc. (also included below in Transfers of Assets Under Common Control) andVivint Smart Home acquisition.
Dispositions
On November 1, 2023, the Company closed on the previously announced sale of Minnesota wind projects to third parties.
On February 6, 2018, NRG entered into a purchase and sale agreement with GIP to sell NRG's ownership in NRG Yield, Inc. and NRG's renewables platform for a total purchase price of $1.375 billion, subject to certain conditions.
On February 6, 2018, NRG entered into a purchase and sale agreement with Cleco to sell NRG's South Central business for a total purchase price of $1.0 billion, subject to certain adjustments.
On January 24, 2018, the Company entered into an agreement with NRG Yield, Inc. to sell 100% of its ownership44% equity interest in Buckthorn Solar for cash considerationSTP to Constellation. Proceeds of $42 million, subject to other adjustments.
On February 6, 2018, the Company entered into an agreement with NRG Yield, Inc. to sell 100% of the membership interests in Carlsbad Energy Holdings LLC, which owns the Carlsbad project, a 527 MW natural gas fired project in Carlsbad, CA, pursuant to the ROFO Agreement. The purchase price for the transaction is $365 million in cash consideration, subject to customary$1.75 billion were reduced by working capital and other adjustments.adjustments of $96 million, resulting in net proceeds of $1.654 billion.
On February 23, 2018,October 2, 2023, the Company closed on the sale of its 100% ownership in the Gregory natural gas generating facility in Texas for $102 million.
On January 6, 2023, NRG closed on the sale of land and related assets from the Astoria site, within the East region of operations, for proceeds of $212 million subject to transaction fees of $3 million and certain indemnifications. NRG recognized a gain on the sale of $199 million. As part of the transaction, NRG entered into an agreement to sell BETMlease the land back for the purpose of operating the Astoria gas turbines. Decommissioning was completed in December 2023 and the lease agreement has been terminated.
Operations
In May 2022, W.A. Parish Unit 8 came offline as a result of damage to a third party for $70 million.the steam turbine/generator. The transaction is expectedextended forced outage ended in September 2023 and the unit has returned to close inservice.
During the second halfquarter of 2018 and is subject to various customary closing conditions, approvals and consents.
GenOn Chapter 11 Bankruptcy Filing
On June 14, 2017,2022, the GenOn Entities filed voluntary petitions for relief under Chapter 11Company announced the planned retirement of the Bankruptcy CodeJoliet generating facility in 2023. On September 1, 2023, the Bankruptcy Court. On December 12, 2017, the Bankruptcy Court entered an order confirming the plan of reorganization. For further discussion, referJoliet generating facility fully retired.
The Company's strategy is to Item 15 — Note 1, Nature of Business, Note 3, Discontinued Operations, Acquisitions and Dispositions, and Note 21, Related Party Transactions, procure mid to the Consolidated Financial Statements.
Tax Act
long-term renewable generation through power purchase agreements. As of December 31, 2017, as a result2023, 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 tenor of these agreements is eleven years. The Company expects to continue evaluating and executing similar agreements that support the needs of the Tax Act,business. The total GW entered into through Renewable PPAs may be impacted by contract terminations when they occur.
Capital Allocation
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 reducedannounced an increase to its deferred tax assets by $733 million offset by valuation allowance of $660 million. In addition,share repurchase authorization to $2.7 billion, to be executed through 2025.
On November 6, 2023, the Company establishedexecuted Accelerated Share Repurchase agreements to repurchase a non-current receivable for its refundable AMT creditstotal of $64$950 million net of sequestration. The net impactNRG's outstanding common stock. Under the ASR, the Company paid a total of $950 million and will receive shares of NRG's common stock on specified settlement dates.
During the Tax Act on net income is a decrease of $9 million primarily due to the expense of $73 million resulting from the Company's revaluation of its net deferred tax asset, partially offset by a $64 million benefit from establishing the AMT credit receivable.
Transfers of Assets Under Common Control
During 2017,year ended December 31, 2023, the Company completed $1.2 billion of share repurchases, including the sale$950 million ASR and $200 million of several projects totaling 555 MW to NRG Yield, Inc. for aggregate cash consideration of approximately $245 million, as discussed in more detail in Item 15 — Note 3, Discontinued Operations, Acquisitions and Dispositions, toopen market repurchases, under the Consolidated Financial Statements.
Financing Activities
Debt Issuances — During 2017, the Company issued approximately $0.9$2.7 billion in recourse debt, approximately $0.8 billion in non-recourse debt and repriced the 2023 Term Loan Facility as discussed in more detail inauthorization. See Item 15 - Note 12, Debt and 16, Capital Leases, to the Consolidated Financial Statements.
Debt Repurchases —During 2017, the Company repurchased $1.5 billion in aggregate principal of outstanding Senior Notes for approximately $1.5 billion, including accrued interest, as discussed in more detail in Item 15 - Note 12, Debt and Capital Leases, to the Consolidated Financial Statements.
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 floodgates 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. The Company estimates the impact of the Cottonwood damage and Hurricane Harvey on Gulf Coast Generation to be approximately $20 million.
Impairments
Impairment losses — During 2017, the Company recorded impairment losses of $1.7 billion as discussed in more detail in Item 15 — Note 10, Asset Impairments and Note 11, Goodwill and Other IntangiblesStructure, to the Consolidated Financial Statements.
for additional discussion.Impairment lossesIn the first quarter of 2023, NRG increased the annual dividend on Investments — its common stock to $1.51 from $1.40 per share, representing an 8% increase from 2022. Beginning in the first quarter of 2024, NRG increased the annual dividend by 8% to $1.63 per share. The Company expects to target an annual dividend growth rate of 7-9% per share in subsequent years.
During 2017,2023, the Company recorded impairment losses of $79reduced its debt by $900 million related primarily to Petra Nova, as discussed in more detail in Item 15 — Note 10, Asset Impairments, to the Consolidated Financial Statements.
Operational Matters
Bacliff Project
On June 16, 2017,using funds from cash from operations. Additionally, 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 $38redeemed $620 million in purchaser incurred costs and $10aggregate principal amount of its 3.875% Senior Notes, due 2032, for $502 million in liquidated damages. On July 18, 2017, BTEC filedusing a lawsuit alleging that NRG Texas Power LLC breached the MIPA by improperly terminating it, and seeks a declaratory judgment as to the rights and obligationsportion of the parties. On August 14, 2017, NRG filedproceeds from the sale of STP.
The Company intends to spend approximately $500 million reducing debt during 2024 to maintain its answer. On September 7, 2017, NRG filed a counterclaim for breach of contract seeking damages in excess of $48 million.targeted credit metrics. The Company intends to fund the debt reduction from cash from operations.
Consolidated Results of Operations for the years ended 2017December 31, 2023 and 20162022
The following table provides selected financial information for the Company:
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, | | |
| (In millions) | 2023 | | 2022 | | Change |
| Revenue | | | | | |
| Retail revenue | $ | 27,467 | | | $ | 29,722 | | | $ | (2,255) | |
Energy revenue(a) | 553 | | | 1,250 | | | (697) | |
Capacity revenue(a) | 197 | | | 272 | | | (75) | |
| Mark-to-market for economic hedging activities | 144 | | | (83) | | | 227 | |
| Contract amortization | (32) | | | (39) | | | 7 | |
Other revenues(a)(b) | 494 | | | 421 | | | 73 | |
| Total revenue | 28,823 | | | 31,543 | | | (2,720) | |
| Operating Costs and Expenses | | | | | |
| Cost of fuel | 992 | | | 1,919 | | | 927 | |
Purchased energy and other cost of sales(c) | 20,647 | | | 24,984 | | | 4,337 | |
| Mark-to-market for economic hedging activities | 3,007 | | | (1,331) | | | (4,338) | |
Contract and emissions credit amortization(c) | 93 | | | 111 | | | 18 | |
| Operations and maintenance | 1,397 | | | 1,352 | | | (45) | |
| Other cost of operations | 390 | | | 411 | | | 21 | |
| Cost of operations (excluding depreciation and amortization shown below) | 26,526 | | | 27,446 | | | 920 | |
| Depreciation and amortization | 1,127 | | | 634 | | | (493) | |
| Impairment losses | 26 | | | 206 | | | 180 | |
| Selling, general and administrative costs | 1,968 | | | 1,228 | | | (740) | |
| Provision for credit losses | 251 | | | 11 | | | (240) | |
| Acquisition-related transaction and integration costs | 119 | | | 52 | | | (67) | |
| Total operating costs and expenses | 30,017 | | | 29,577 | | | (440) | |
| | | | | |
| Gain on sale of assets | 1,578 | | | 52 | | | 1,526 | |
| Operating Income | 384 | | | 2,018 | | | (1,634) | |
| Other Income/(Expense) | | | | | |
| Equity in earnings of unconsolidated affiliates | 16 | | | 6 | | | 10 | |
| Impairment losses on investments | (102) | | | — | | | (102) | |
| Other income, net | 47 | | | 56 | | | (9) | |
| | | | | |
| Gain on debt extinguishment | 109 | | | — | | | 109 | |
| Interest expense | (667) | | | (417) | | | (250) | |
| Total other expenses | (597) | | | (355) | | | (242) | |
| (Loss)/Income Before Income Taxes | (213) | | | 1,663 | | | (1,876) | |
| Income tax (benefit)/expense | (11) | | | 442 | | | (453) | |
| | | | | |
| | | | | |
| Net (Loss)/Income | $ | (202) | | | $ | 1,221 | | | $ | (1,423) | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
|
| | | | | | | | | | | |
| | Year Ended December 31, | | |
| (in millions except otherwise noted) | 2017 | | 2016 | | Change |
| Operating Revenues | | | | | |
Energy revenue (a) | $ | 2,461 |
|
| $ | 3,131 |
| | $ | (670 | ) |
Capacity revenue (a) | 1,186 |
|
| 1,225 |
| | (39 | ) |
| Retail revenue | 6,388 |
| | 6,357 |
| | 31 |
|
| Mark-to-market for economic hedging activities | 239 |
| | (642 | ) | | 881 |
|
| Contract amortization | (56 | ) | | (56 | ) | | — |
|
Other revenues (b) | 411 |
|
| 497 |
| | (86 | ) |
| Total operating revenues | 10,629 |
| | 10,512 |
| | 117 |
|
| Operating Costs and Expenses | | | | | |
Cost of sales (b) | 5,698 |
| | 5,827 |
| | 129 |
|
| Mark-to-market for economic hedging activities | 46 |
| | (508 | ) | | (554 | ) |
Contract and emissions credit amortization (c) | 34 |
| | 43 |
| | 9 |
|
| Operations and maintenance | 1,393 |
| | 1,599 |
| | 206 |
|
| Other cost of operations | 365 |
|
| 340 |
| | (25 | ) |
| Total cost of operations | 7,536 |
| | 7,301 |
| | (235 | ) |
| Depreciation and amortization | 1,056 |
| | 1,172 |
| | 116 |
|
| Impairment losses | 1,709 |
| | 702 |
| | (1,007 | ) |
| Selling, general and administrative | 907 |
|
| 1,095 |
| | 188 |
|
| Reorganization costs | 44 |
| | — |
| | (44 | ) |
| Development costs | 67 |
| | 89 |
| | 22 |
|
| Total operating costs and expenses | 11,319 |
| | 10,359 |
| | (960 | ) |
| Other income - affiliate | 87 |
| | 193 |
| | (106 | ) |
| Gain/(loss) on sale of assets | 16 |
| | (80 | ) | | 96 |
|
| Operating (Loss)/ Income | (587 | ) | | 266 |
| | (853 | ) |
| Other Income/(Expense) | | | | | |
| Equity in earnings of unconsolidated affiliates | 31 |
| | 27 |
| | 4 |
|
| Impairment losses on investments | (79 | ) | | (268 | ) | | 189 |
|
| Other income, net | 38 |
| | 34 |
| | 4 |
|
| Net loss on debt extinguishment | (53 | ) | | (142 | ) | | 89 |
|
| Interest expense | (890 | ) | | (895 | ) | | 5 |
|
| Total other (expense)/income | (953 | ) | | (1,244 | ) | | 291 |
|
| Loss from Continuing Operations Before Income Taxes | (1,540 | ) | | (978 | ) | | (562 | ) |
| Income tax expense | 8 |
| | 5 |
| | 3 |
|
| Loss from Continuing Operations | (1,548 | ) | | (983 | ) | | (565 | ) |
| (Loss)/income from discontinued operations, net of income tax | (789 | ) | | 92 |
| | (881 | ) |
| Net Loss | (2,337 | ) | | (891 | ) | | (1,446 | ) |
| Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests | (184 | ) | | (117 | ) | | (67 | ) |
| Net Loss Attributable to NRG Energy, Inc. | $ | (2,153 | ) | | $ | (774 | ) | | $ | (1,379 | ) |
| Business Metrics | | | | | |
| Average natural gas price — Henry Hub ($/MMBtu) | $ | 3.11 |
| | $ | 2.46 |
| | 26 | % |
| |
(a) | Includes realized gains and losses from financially settled transactions. |
| |
(b) | Includes unrealized trading gains and losses. |
| |
(c) | Includes amortization of SO2 and NOx credits and excludes amortization of RGGI credits.
|
(a)Includes realized gains and losses from financially settled transactions
(b)Includes trading gains and losses and ancillary revenues
(c)Includes amortization of SO2 and NOx credits and excludes amortization of RGGI credits
Gross Margin
The Company calculates gross margin in order to evaluate operating performance as operating revenues less cost of sales, which includes cost of fuel, purchased energy and other costs of sales, mark-to-market for economic hedging activities, contract and emission credit amortization and mark-to-market for economic hedging activities.depreciation and amortization.
Economic Gross Margin
In addition to gross margin, the Company evaluates its operating performance using the measure of economic gross margin, which is not a GAAP measure and may not be comparable to other companies’ presentations or deemed more useful
than the GAAP information provided elsewhere in this report. Economic gross margin should be viewed as a supplement to and not a substitute for the Company's presentation of gross margin, which is the most directly comparable GAAP measure. Economic gross margin is not intended to represent gross margin. The Company believes that economic gross margin is useful to investors as it is a key operational measure reviewed by the Company's chief operating decision maker. Economic gross margin is defined as the sum of retail revenue, energy revenue, capacity revenue and other revenue, less cost of fuels, 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, emission credit amortization, depreciation and amortization, operations and maintenance, or other operating costs.costs of operations.
The following tables below present the composition and reconciliation of gross margin and economic gross margin which reflects the Company's current view of reporting segments for the years ended December 31, 20172023 and 2016:2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2023 |
| ($ in millions, except otherwise noted) | Texas | | East | | West/Services/Other | | | | Vivint Smart Home | | Corporate/Eliminations | | Total |
| Retail revenue | $ | 10,030 | | | $ | 11,946 | | | $ | 3,943 | | | | | $ | 1,549 | | | $ | (1) | | | $ | 27,467 | |
| Energy revenue | 77 | | | 291 | | | 185 | | | | | — | | | — | | | 553 | |
| Capacity revenue | — | | | 197 | | | 2 | | | | | — | | | (2) | | | 197 | |
| Mark-to-market for economic hedging activities | — | | | 57 | | | 103 | | | | | — | | | (16) | | | 144 | |
| Contract amortization | — | | | (32) | | | — | | | | | — | | | — | | | (32) | |
Other revenue(a) | 369 | | | 88 | | | 48 | | | | | — | | | (11) | | | 494 | |
| Total revenue | 10,476 | | | 12,547 | | | 4,281 | | | | | 1,549 | | | (30) | | | 28,823 | |
| Cost of fuel | (760) | | | (112) | | | (120) | | | | | — | | | — | | | (992) | |
Purchased energy and other costs of sales(b)(c)(d) | (6,288) | | | (10,683) | | | (3,532) | | | | | (153) | | | 9 | | | (20,647) | |
| Mark-to-market for economic hedging activities | 315 | | | (2,471) | | | (867) | | | | | — | | | 16 | | | (3,007) | |
| Contract and emissions credit amortization | (11) | | | (68) | | | (14) | | | | | — | | | — | | | (93) | |
| Depreciation and amortization | (294) | | | (116) | | | (95) | | | | | (586) | | | (36) | | | (1,127) | |
| Gross margin | $ | 3,438 | | | $ | (903) | | | $ | (347) | | | | | $ | 810 | | | $ | (41) | | | $ | 2,957 | |
| Less: Mark-to-market for economic hedging activities, net | 315 | | | (2,414) | | | (764) | | | | | — | | | — | | | (2,863) | |
| Less: Contract and emissions credit amortization, net | (11) | | | (100) | | | (14) | | | | | — | | | — | | | (125) | |
| Less: Depreciation and amortization | (294) | | | (116) | | | (95) | | | | | (586) | | | (36) | | | (1,127) | |
| Economic gross margin | $ | 3,428 | | | $ | 1,727 | | | $ | 526 | | | | | $ | 1,396 | | | $ | (5) | | | $ | 7,072 | |
(a)Includes trading gains and losses and ancillary revenues |
(b)Includes capacity and emissions credits |
(c)Includes $3.1 billion, $244 million and $1.1 billion of TDSP expense in Texas, East, and West/Services/Other respectively |
(d)Excludes depreciation and amortization shown separately |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2017 |
| Generation |
|
|
|
|
|
|
|
|
|
| (In millions except otherwise noted) | Gulf Coast |
| East/West(a) |
| Subtotal |
| Retail |
| Renewables |
| NRG Yield |
| Corporate/Eliminations |
| Total |
| Energy revenue | $ | 1,806 |
|
| $ | 830 |
|
| $ | 2,636 |
|
| $ | — |
|
| $ | 359 |
|
| $ | 554 |
|
| $ | (1,088 | ) |
| $ | 2,461 |
|
| Capacity revenue | 266 |
|
| 585 |
|
| 851 |
|
| — |
|
| — |
|
| 346 |
|
| (11 | ) |
| 1,186 |
|
| Retail revenue | — |
|
| — |
|
| — |
|
| 6,385 |
|
| — |
|
| — |
|
| 3 |
|
| 6,388 |
|
| Mark-to-market for economic hedging activities | 72 |
|
| (35 | ) |
| 37 |
|
| (4 | ) |
| (12 | ) |
| — |
|
| 218 |
|
| 239 |
|
| Contract amortization | 14 |
|
| — |
|
| 14 |
|
| (1 | ) |
| — |
|
| (69 | ) |
| — |
|
| (56 | ) |
Other revenue(b) | 186 |
|
| 49 |
|
| 235 |
|
| — |
|
| 77 |
|
| 178 |
|
| (79 | ) |
| 411 |
|
| Operating revenue | 2,344 |
|
| 1,429 |
|
| 3,773 |
|
| 6,380 |
|
| 424 |
|
| 1,009 |
|
| (957 | ) |
| 10,629 |
|
| Cost of fuel | (994 | ) |
| (401 | ) |
| (1,395 | ) |
| (12 | ) |
| (4 | ) |
| (35 | ) |
| 45 |
|
| (1,401 | ) |
Other costs of sales(c) | (344 | ) |
| (238 | ) |
| (582 | ) |
| (4,756 | ) |
| (11 | ) |
| (28 | ) |
| 1,080 |
|
| (4,297 | ) |
| Mark-to-market for economic hedging activities | (20 | ) |
| 11 |
|
| (9 | ) |
| 181 |
|
| — |
|
| — |
|
| (218 | ) |
| (46 | ) |
| Contract and emission credit amortization | (30 | ) |
| (4 | ) |
| (34 | ) |
| — |
|
| — |
|
| — |
|
| — |
|
| (34 | ) |
| Gross margin | $ | 956 |
|
| $ | 797 |
|
| $ | 1,753 |
|
| $ | 1,793 |
|
| $ | 409 |
|
| $ | 946 |
|
| $ | (50 | ) |
| $ | 4,851 |
|
| Less: Mark-to-market for economic hedging activities, net | 52 |
|
| (24 | ) |
| 28 |
|
| 177 |
|
| (12 | ) |
| — |
|
| — |
|
| 193 |
|
| Less: Contract and emission credit amortization, net | (16 | ) |
| (4 | ) |
| (20 | ) |
| (1 | ) |
| — |
|
| (69 | ) |
| — |
|
| (90 | ) |
| Economic gross margin | $ | 920 |
|
| $ | 825 |
|
| $ | 1,745 |
|
| $ | 1,617 |
|
| $ | 421 |
|
| $ | 1,015 |
|
| $ | (50 | ) |
| $ | 4,748 |
|
| Business Metrics |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MWh sold (thousands)(d)(e) | 53,802 |
|
| 19,954 |
|
|
|
|
|
|
|
| 3,836 |
|
| 6,880 |
|
|
|
|
|
|
|
MWh generated (thousands)(f) | 49,574 |
|
| 13,373 |
|
|
|
|
|
|
|
| 3,836 |
|
| 8,761 |
|
|
|
|
|
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2023 |
| Business Metrics | Texas | | East | | West/Services/Other | | | | Vivint Smart Home | | Corporate/Eliminations | | Total |
| Home electricity sales volume (GWh) | 40,032 | | | 12,838 | | | 2,243 | | | | | — | | | — | | | 55,113 | |
| Business electricity sales volume (GWh) | 40,250 | | | 46,438 | | | 10,393 | | | | | — | | | — | | | 97,081 | |
| Home natural gas retail sales volumes (MDth) | — | | | 49,990 | | | 75,150 | | | | | — | | | — | | | 125,140 | |
| Business natural gas retail sales volumes (MDth) | — | | | 1,587,052 | | | 179,888 | | | | | — | | | — | | | 1,766,940 | |
Average retail Home customer count (in thousands)(a) | 2,878 | | | 1,856 | | | 774 | | | | | — | | | — | | | 5,508 | |
Ending retail Home customer count (in thousands)(a) | 2,928 | | | 2,137 | | | 762 | | | | | — | | | — | | | 5,827 | |
Average Vivint Smart Home subscriber count (in thousands)(b) | — | | | — | | | — | | | | | 2,008 | | | — | | | 2,008 | |
Ending Vivint Smart Home subscriber count (in thousands)(b) | — | | | — | | | — | | | | | 2,043 | | | — | | | 2,043 | |
| GWh sold | 30,776 | | | 5,396 | | | 5,903 | | | | | — | | | — | | | 42,075 | |
GWh generated (c) | 30,776 | | | 2,016 | | | 5,903 | | | | | — | | | — | | | 38,695 | |
(a)Home customer count includes recurring residential customers, services customers and community choice. |
(b)Vivint Smart Home subscribers includes customers that also purchase other NRG products |
| (c) Includes owned and leased generation, excludes tolled generation and equity investments |
(a) Includes International, BETM and Generation eliminations.
(b) Renewables Other revenue includes $29 million of intercompany revenue to NRG Yield.
(c) Includes purchased energy, capacity and emissions credits.
(d) MWh sold excludes generation at facilities in the West and NRG Yield that generate revenue under tolling agreements.
(e) Does not include MWh of 35 thousand or MWt of 1,926 thousand for thermal sold by NRG Yield.
(f) Does not include MWh of 108 thousand or MWt of 1,926 thousand for thermal generated by NRG Yield.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2022 |
| ($ in millions, except otherwise noted) | Texas | | East | | West/Services/Other | | | | Corporate/Eliminations | | Total |
| Retail revenue | $ | 9,617 | | | $ | 15,856 | | | $ | 4,250 | | | | | $ | (1) | | | $ | 29,722 | |
| Energy revenue | 111 | | | 641 | | | 466 | | | | | 32 | | | 1,250 | |
| Capacity revenue | — | | | 232 | | | 40 | | | | | — | | | 272 | |
| Mark-to-market for economic hedging activities | 2 | | | (30) | | | (56) | | | | | 1 | | | (83) | |
| Contract amortization | — | | | (40) | | | 1 | | | | | — | | | (39) | |
Other revenue(a) | 327 | | | 104 | | | 5 | | | | | (15) | | | 421 | |
| Total revenue | 10,057 | | | 16,763 | | | 4,706 | | | | | 17 | | | 31,543 | |
| Cost of fuel | (1,213) | | | (376) | | | (330) | | | | | — | | | (1,919) | |
Purchased energy and other costs of sales(b)(c)(d) | (6,379) | | | (14,782) | | | (3,804) | | | | | (19) | | | (24,984) | |
| Mark-to-market for economic hedging activities | 611 | | | 218 | | | 503 | | | | | (1) | | | 1,331 | |
| Contract and emissions credit amortization | — | | | (91) | | | (20) | | | | | — | | | (111) | |
| Depreciation and amortization | (310) | | | (208) | | | (85) | | | | | (31) | | | (634) | |
| Gross margin | $ | 2,766 | | | $ | 1,524 | | | $ | 970 | | | | | $ | (34) | | | $ | 5,226 | |
| Less: Mark-to-market for economic hedging activities, net | 613 | | | 188 | | | 447 | | | | | — | | | 1,248 | |
| Less: Contract and emissions credit amortization, net | — | | | (131) | | | (19) | | | | | — | | | (150) | |
| Less: Depreciation and amortization | (310) | | | (208) | | | (85) | | | | | (31) | | | (634) | |
| Economic gross margin | $ | 2,463 | | | $ | 1,675 | | | $ | 627 | | | | | $ | (3) | | | $ | 4,762 | |
(a)Includes trading gains and losses and ancillary revenues |
(b)Includes capacity and emissions credits |
(c)Includes $3.0 billion, $120 million and $1.1 billion of TDSP expense in Texas, East, and West/Services/Other respectively |
(d)Excludes depreciation and amortization shown separately |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2022 |
| Business Metrics | Texas | | East | | West/Services/Other | | | | Corporate/Eliminations | | Total |
| Home electricity sales volume (GWh) | 43,155 | | | 13,269 | | | 2,250 | | | | | — | | | 58,674 | |
| Business electricity sales volume (GWh) | 38,447 | | | 47,724 | | | 10,231 | | | | | — | | | 96,402 | |
| Home natural gas retail sales volumes (MDth) | — | | | 53,051 | | | 92,035 | | | | | — | | | 145,086 | |
| Business natural gas retail sales volumes (MDth) | — | | | 1,618,946 | | | 154,074 | | | | | — | | | 1,773,020 | |
Average retail Home customer count (in thousands)(a) | 2,961 | | | 1,783 | | | 799 | | | | | — | | | 5,543 | |
Ending retail Home customer count (in thousands)(a) | 2,859 | | | 1,761 | | | 786 | | | | | — | | | 5,406 | |
| GWh sold | 37,275 | | | 10,832 | | | 6,676 | | | | | — | | | 54,783 | |
GWh generated(b) | 37,275 | | | 7,282 | | | 6,676 | | | | | — | | | 51,233 | |
(a)Home customer count includes recurring residential customers, services customers and community choice |
(b)Includes owned and leased generation, excludes tolled generation and equity investments |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2016 |
| Generation |
|
|
|
|
|
|
|
|
|
| (In millions except otherwise noted) | Gulf Coast |
| East/West(a) |
| Subtotal |
| Retail |
| Renewables |
| NRG Yield |
| Corporate/Eliminations |
| Total |
| Energy revenue | $ | 2,073 |
|
| $ | 1,098 |
|
| $ | 3,171 |
|
| $ | — |
|
| $ | 369 |
|
| $ | 582 |
|
| $ | (991 | ) |
| $ | 3,131 |
|
| Capacity revenue | 293 |
|
| 598 |
|
| 891 |
|
| — |
|
| — |
|
| 345 |
|
| (11 | ) |
| 1,225 |
|
| Retail revenue | — |
|
| — |
|
| — |
|
| 6,336 |
|
| — |
|
| — |
|
| 21 |
|
| 6,357 |
|
| Mark-to-market for economic hedging activities | (518 | ) |
| (48 | ) |
| (566 | ) |
| — |
|
| (6 | ) |
| — |
|
| (70 | ) |
| (642 | ) |
| Contract amortization | 15 |
|
| — |
|
| 15 |
|
| (1 | ) |
| (1 | ) |
| (69 | ) |
| — |
|
| (56 | ) |
Other revenue (b) | 237 |
|
| 85 |
|
| 322 |
|
| — |
|
| 44 |
|
| 177 |
|
| (46 | ) |
| 497 |
|
| Operating revenue | 2,100 |
|
| 1,733 |
|
| 3,833 |
|
| 6,335 |
|
| 406 |
|
| 1,035 |
|
| (1,097 | ) |
| 10,512 |
|
| Cost of fuel | (938 | ) |
| (469 | ) |
| (1,407 | ) |
| (8 | ) |
| (3 | ) |
| (33 | ) |
| 130 |
|
| (1,321 | ) |
Other costs of sales(c) | (387 | ) |
| (299 | ) |
| (686 | ) |
| (4,679 | ) |
| (11 | ) |
| (28 | ) |
| 898 |
|
| (4,506 | ) |
| Mark-to-market for economic hedging activities | 71 |
|
| 2 |
|
| 73 |
|
| 365 |
|
| — |
|
| — |
|
| 70 |
|
| 508 |
|
| Contract and emission credit amortization | (29 | ) |
| (5 | ) |
| (34 | ) |
| (6 | ) |
| — |
|
| (6 | ) |
| 3 |
|
| (43 | ) |
| Gross margin | $ | 817 |
|
| $ | 962 |
|
| $ | 1,779 |
|
| $ | 2,007 |
|
| $ | 392 |
|
| $ | 968 |
|
| $ | 4 |
|
| $ | 5,150 |
|
| Less: Mark-to-market for economic hedging activities, net | (447 | ) |
| (46 | ) |
| (493 | ) |
| 365 |
|
| (6 | ) |
| — |
|
| — |
|
| (134 | ) |
| Less: Contract and emission credit amortization, net | (14 | ) |
| (5 | ) |
| (19 | ) |
| (7 | ) |
| (1 | ) |
| (75 | ) |
| 3 |
|
| (99 | ) |
| Economic gross margin | $ | 1,278 |
|
| $ | 1,013 |
|
| $ | 2,291 |
|
| $ | 1,649 |
|
| $ | 399 |
|
| $ | 1,043 |
|
| $ | 1 |
|
| $ | 5,383 |
|
| Business Metrics |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MWh sold (thousands)(d)(e) | 52,929 |
|
| 25,995 |
|
|
|
|
|
|
|
| 3,827 |
|
| 7,363 |
|
|
|
|
|
|
|
MWh generated (thousands)(f) | 47,828 |
|
| 17,114 |
|
|
|
|
|
|
|
| 3,827 |
|
| 9,264 |
|
|
|
|
|
|
|
(a) Includes International, BETM and Generation eliminations.
(b) Renewables Other revenue includes $19 million of intercompany revenue to NRG Yield.
(c) Includes purchased energy, capacity and emissions credits.
(d) MWh sold excludes generation at facilities in the West and NRG Yield that generate revenue under tolling agreements.
(e) Does not include MWh of 71 thousand or MWt of 1,966 thousand for thermal sold by NRG Yield.
(f) Does not include MWh of 275 thousand or MWt of 1,966 thousand for thermal generated by NRG Yield.
The following table below represents the weather metrics for 20172023 and 2016:2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year ended
December 31, | | Quarter ended
December 31, | | Quarter ended September 30, | | Quarter ended
June 30, | | Quarter ended
March 31, |
| Weather Metrics | Texas | | East | | West/Services/Other(a) | | Texas | | East | | West/Services/Other(a) | | Texas | | East | | West/Services/Other(a) | | Texas | | East | | West/Services/Other(a) | | Texas | | East | | West/Services/Other(a) |
| 2023 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
CDDs(b) | 3,468 | | | 1,229 | | | 2,024 | | | 285 | | | 85 | | | 158 | | | 2,039 | | | 817 | | | 1,291 | | | 978 | | | 273 | | | 502 | | | 166 | | | 54 | | | 73 | |
HDDs(b) | 1,469 | | | 4,139 | | | 2,105 | | | 613 | | | 1,520 | | | 688 | | | — | | | 48 | | | 4 | | | 57 | | | 479 | | | 254 | | | 799 | | | 2,092 | | | 1,159 | |
| 2022 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| CDDs | 3,417 | | | 1,340 | | | 2,133 | | | 277 | | | 72 | | | 160 | | | 1,789 | | | 874 | | | 1,268 | | | 1,283 | | | 352 | | | 674 | | | 68 | | | 42 | | | 31 | |
| HDDs | 1,935 | | | 4,627 | | | 2,232 | | | 734 | | | 1,683 | | | 884 | | | — | | | 54 | | | 3 | | | 24 | | | 486 | | | 194 | | | 1,177 | | | 2,404 | | | 1,151 | |
| 10-year average | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| CDDs | 3,051 | | | 1,311 | | | 1,939 | | | 290 | | | 91 | | | 163 | | | 1,673 | | | 824 | | | 1,173 | | | 986 | | | 356 | | | 557 | | | 102 | | | 40 | | | 46 | |
| HDDs | 1,715 | | | 4,766 | | | 2,064 | | | 665 | | | 1,642 | | | 774 | | | 5 | | | 52 | | | 9 | | | 67 | | | 547 | | | 188 | | | 978 | | | 2,525 | | | 1,093 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Years ended December 31, | Quarters ended December 31, | Quarters ended September 30, | Quarters ended June 30, | Quarters ended March 31, |
| Weather Metrics | Gulf Coast(b) | | East/West | | Gulf Coast(b) | | East/West | | Gulf Coast(b) | | East/West | | Gulf Coast(b) | | East/West | | Gulf Coast(b) | | East/West |
| 2017 | | | | | | | | | | | | | | | | | | | |
CDDs(a) | 2,949 |
| | 1,155 |
| | 296 |
| | 84 |
| | 1,528 |
| | 770 |
| | 921 |
| | 281 |
| | 204 |
| | 20 |
|
HDDs(a) | 1,383 |
| | 3,199 |
| | 710 |
| | 1,157 |
| | 1 |
| | 34 |
| | 41 |
| | 380 |
| | 631 |
| | 1,628 |
|
| 2016 | | | | | | | | | | | | | | | | | | | |
| CDDs | 2,966 |
| | 1,169 |
| | 362 |
| | 71 |
| | 1,655 |
| | 806 |
| | 873 |
| | 273 |
| | 76 |
| | 19 |
|
| HDDs | 1,529 |
| | 3,191 |
| | 545 |
| | 1,145 |
| | — |
| | 23 |
| | 53 |
| | 410 |
| | 931 |
| | 1,613 |
|
| 10 year average | | | | | | | | | | | | | | | | | | | |
| CDDs | 2,904 |
| | 1,043 |
| | 249 |
| | 67 |
| | 1,617 |
| | 705 |
| | 957 |
| | 254 |
| | 81 |
| | 17 |
|
| HDDs | 1,903 |
| | 3,504 |
| | 736 |
| | 1,227 |
| | 6 |
| | 40 |
| | 75 |
| | 438 |
| | 1,086 |
| | 1,799 |
|
| |
(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,(b)National Oceanic and Atmospheric Administration-Climate Prediction Center - A Cooling Degree Day ("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 ("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) CDDs/HDDs for the Gulf Coast region represent an averagea period of cumulative population-weightedtime are calculated by adding the CDDs/HDDs for Texas andeach day during the West South-Central Climate region.period
Generation grossGross margin and economic gross margin
Generation grossGross margin decreased $26 million$2.3 billion and economic gross margin decreased $546 million,increased $2.3 billion, both of which include intercompany sales, during the year ended December 31, 20172023, compared to the same period in 2016.2022. The detail by segment is as follows:
The tables below describe the changes in Generation gross margin and in economic gross margin:
Gulf Coast Region
|
| | | |
| | (In millions) |
| Lower gross margin due to a 14% decrease in average realized prices primarily in Texas due to lower hedged power prices | $ | (315 | ) |
| Lower energy margins due to increased supply cost on load contracts | (48 | ) |
| Lower capacity margins on contract expirations and lower demand in South Central business | (27 | ) |
| Lower gross margin due to lower gas generation driven by the current mothball status of Gregory in Texas | (17 | ) |
| Lower gross margin due to a 24% decrease in ISO capacity prices and a 76% decrease in volume | (14 | ) |
| Higher gross margin due to a 17% increase in coal generation mainly in Texas driven by the timing of planned and unplanned outages | 68 |
|
| Other | (5 | ) |
| Decrease in economic gross margin | (358 | ) |
| Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges | 499 |
|
| Decrease in contract and emission credit amortization | (2 | ) |
| Increase in gross margin | $ | 139 |
|
East/West Region
|
| | | |
| | (In millions) |
| Lower gross margin from commercial optimization activities | $ | (59 | ) |
| Lower gross margin due to a decrease in generation driven by lower economic generation due to milder weather conditions and the Will County outage | (54 | ) |
| Lower gross margin due to lower load contracted prices coupled with slightly lower volumes | (28 | ) |
| Lower gross margin due to a lower cost of market adjustment for fuel oil inventory | (33 | ) |
| 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 congestion strategies | (20 | ) |
| Other | 6 |
|
| Decrease in economic gross margin | $ | (188 | ) |
| Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges | 22 |
|
| Increase in contract and emission credit amortization | 1 |
|
| Decrease in gross margin | $ | (165 | ) |
Retail gross margin and economic gross margin
The following is a discussion of gross margin and economic gross margin for Retail.
|
| | | | | | | |
| | Years ended December 31, |
| (In millions except otherwise noted) | 2017 | | 2016 |
| Retail revenue | $ | 6,115 |
| | $ | 6,100 |
|
| Supply management revenue | 187 |
| | 154 |
|
| Capacity revenues | 83 |
| | 82 |
|
| Customer mark-to-market | (4 | ) | | — |
|
| Contract amortization | (1 | ) | | (1 | ) |
| Other | — |
| | — |
|
Operating revenue (a) | 6,380 |
| | 6,335 |
|
Cost of sales (b) | (4,768 | ) | | (4,687 | ) |
| Mark-to-market for economic hedging activities | 181 |
| | 365 |
|
| Contract amortization | — |
| | (6 | ) |
| Gross margin | $ | 1,793 |
| | $ | 2,007 |
|
| Less: Mark-to-market for economic hedging activities, net | 177 |
| | 365 |
|
| Less: Contract and emission credit amortization | (1 | ) | | (7 | ) |
| Economic gross margin | $ | 1,617 |
| | $ | 1,649 |
|
| Business Metrics | | | |
| Mass electricity sales volume (GWh) - Gulf Coast | 36,169 |
| | 35,102 |
|
| Mass electricity sales volume (GWh) - All other regions | 6,221 |
| | 6,764 |
|
C&I electricity sales volume (GWh) All regions (c) | 20,400 |
| | 18,906 |
|
| Natural gas sales volumes (MDth) | 3,212 |
| | 2,199 |
|
| Average Retail Mass customer count (in thousands) | 2,863 |
| | 2,778 |
|
| Ending Retail Mass customer count (in thousands) | 2,876 |
| | 2,818 |
|
| | | | | |
| (In millions) |
(a)Higher gross margin due to the net effect of: •a 15%, or $548 million, decrease in cost to serve the retail load, primarily driven by lower supply costs which were a result of lower realized power pricing, the diversified supply strategy and improved plant performance coupled with the 2022 impact of the W.A. Parish Unit 8 extended outage that began in May 2022, net of business interruption insurance proceeds; and •increased net revenue rates of $5.45 per MWh, or $523 million, partially offset by changes in customer term, product and mix of $61 million | Includes intercompany$ | 1,010 | |
| Lower gross margin due to a decrease in load of 1.5 TWhs from weather | (58) | |
| Higher gross margin from market optimization activities | 33 | |
| |
| |
| Other | (20) | |
| Increase in economic gross margin | $ | 965 | |
| Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges | (298) | |
| Increase in contract and emissions credit amortization | (11) | |
| Decrease in depreciation and amortization | 16 | |
| Increase in gross margin | $ | 672 | |
East | | | | | |
| (In millions) |
| Lower gross margin due to a decrease in generation and capacity as a result of asset retirements | $ | (116) | |
| Lower natural gas gross margin including the impact of transportation and storage contract optimization, reflects lower net revenue rates from changes in customer term, product and mix of $2.35 per Dth, or $3.86 billion, partially offset by lower supply costs of $2.30 per Dth, or $3.78 billion | (82) | |
Lower gross margin from the sales of $5NOx emissions credits | (24) | |
| Lower natural gas gross margin from a decrease in load of 6.9 MMDth due to weather and changes in customer mix | (16) | |
| Lower electric gross margin from a decrease in load of 686 GWhs primarily due to weather | (16) | |
| Higher electric gross margin due to higher net revenue rates as a result of changes in customer term, product and mix of $2.50 per MWh, or $155 million, as well as lower supply costs of $1.50 per MWh, or $86 million driven primarily by decreases in power prices | 241 | |
| Higher gross margin due to an increase in average realized pricing and a decrease in supply costs at Midwest Generation, offset by lower gross margin as a result of a 74% decrease in generation volumes due to dark spread contractions | 56 | |
| Higher gross margin primarily due to net capacity performance penalties resulting from Winter Storm Elliott in 2022 and an increase in NYISO capacity pricing, partially offset by a decrease in PJM capacity prices | 16 | |
| Other | (7) | |
| Increase in economic gross margin | $ | 52 | |
| Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges | (2,602) | |
| Decrease in contract amortization | 31 | |
| Decrease in depreciation and amortization | 92 | |
| Decrease in gross margin | $ | (2,427) | |
West/Services/Other | | | | | |
| (In millions) |
| Lower gross margin at Cottonwood driven by lower average realized power prices, planned outages in 2023 and capacity performance bonus resulting from PJM Winter Storm Elliott in 2022 | $ | (76) | |
| Lower gross margin primarily due to lower Services sales | (51) | |
| Lower electric gross margin due to an increase in supply costs of $6.50 per MWh, or $82 million, partially offset by higher revenue rates of $5.25 per MWh, or $64 million, and changes in customer mix of $2 million | (16) | |
| Higher gross margin from market optimization activities | 28 | |
| Higher natural gas gross margin due to a decrease in supply costs of $0.90 per Dth, or $228 million, and changes in customer mix of $4 million, partially offset by lower revenue rates of $0.85 per Dth, or $218 million | 14 | |
| |
Decrease in 2017economic gross margin | $ | (101) | |
| Decrease in mark-to-market for economic hedges primarily due to net unrealized gains/losses on open positions related to economic hedges | (1,211) | |
| Decrease in contract amortization | 5 | |
Increase in depreciation and 2016, respectively, representing sales from Retailamortization | (10) | |
| Decrease in gross margin | $ | (1,317) | |
Vivint Smart Home(a)
| | | | | |
| (In millions) |
Increase due to the Gulf Coast region. |
| acquisition of Vivint Smart Home | $ | 1,396 | |
| (b) | Includes intercompany purchases of $1,035 million and $850 million in 2017 and 2016, respectively.
| |
(c)Increase in economic gross margin | Includes volumes for 2017 for one customer that self-supplied their volumes for all of 2016 versus only two months$ | 1,396 | |
| |
| |
Increase in 2017.depreciation and amortization | (586) | |
| Increase in gross margin | $ | 810 | |
Retail gross margin decreased $214 million and economic gross margin decreased $32 million for(a) Includes results of operations following the year ended December 31, 2017, compared to the same period in 2016, due to:acquisition date of March 10, 2023
|
| | | |
| | (In millions) |
| Lower gross margin due to lower rates to customers driven by customer product, term, and mix of $103 million or approximately $1.60 per MWh, partially offset by lower supply costs of $28 million or approximately $0.50 per MWh driven primarily by a decrease in power prices at the time of procurement | $ | (75 | ) |
| Lower gross margin due to milder weather conditions in 2017 as compared to 2016 resulting in a reduction in load of 350,000 MWh | (11 | ) |
| Lower gross margin related to the impact of Hurricane Harvey in 2017, driven by $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 | (16 | ) |
| Higher gross margin driven by higher average customer counts of 85,000 along with higher average usage due to customer mix | 70 |
|
| Decrease in economic gross margin | $ | (32 | ) |
| Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges | (188 | ) |
| Increase in contract and emission credit amortization | 6 |
|
| Decrease in gross margin | $ | (214 | ) |
Renewables gross margin and economic gross margin
Renewables gross margin increased $17 million and economic gross margin increased $22 million for the year ended December 31, 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 which focus on servicing NRG Yield assets 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 $22 million and economic gross margin decreased $28 million for the year ended December 31, 2017, compared to the same period in 2016, primarily due to a 5% decrease in volume generated at our Alta Wind and NRG Wind TE Holdco projects, due to lower wind resources.
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 increaseddecreased by $327 million$4.1 billion during the year ended December 31, 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 region wassegment is as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2023 |
| (In millions) | Texas | | East | | West/Services/Other | | Eliminations | | Total |
| Mark-to-market results in revenues | | | | | | | | | |
| Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges | $ | — | | | $ | (25) | | | $ | 56 | | | $ | (12) | | | $ | 19 | |
| Reversal of acquired (gain) positions related to economic hedges | — | | | (2) | | | — | | | — | | | (2) | |
| Net unrealized gains on open positions related to economic hedges | — | | | 84 | | | 47 | | | (4) | | | 127 | |
| Total mark-to-market gains in revenues | $ | — | | | $ | 57 | | | $ | 103 | | | $ | (16) | | | $ | 144 | |
| Mark-to-market results in operating costs and expenses | | | | | | | | | |
| Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges | $ | (473) | | | $ | (812) | | | $ | (480) | | | $ | 12 | | | $ | (1,753) | |
| Reversal of acquired loss/(gain) positions related to economic hedges | 17 | | | 11 | | | (6) | | | — | | | 22 | |
| Net unrealized gains/(losses) on open positions related to economic hedges | 771 | | | (1,670) | | | (381) | | | 4 | | | (1,276) | |
| Total mark-to-market gains/(losses) in operating costs and expenses | $ | 315 | | | $ | (2,471) | | | $ | (867) | | | $ | 16 | | | $ | (3,007) | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2017 |
| | Generation | | | | | | | | |
| | Gulf Coast | | East/West | | Retail | | Renewables | | | Elimination (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 | $ | 107 |
| | $ | (40 | ) | | $ | (2 | ) | | $ | 1 |
| | | $ | 64 |
| | $ | 130 |
|
| Net unrealized (losses)/gains on open positions related to economic hedges | (35 | ) | | 5 |
| | (2 | ) | | (13 | ) | | | 154 |
| | 109 |
|
| Total mark-to-market gains/(losses) in operating revenues | $ | 72 |
| | $ | (35 | ) | | $ | (4 | ) | | $ | (12 | ) | | | $ | 218 |
| | $ | 239 |
|
| Mark-to-market results in operating costs and expenses | | | | | | | | | | | | |
| Reversal of previously recognized unrealized gains on settled positions related to economic hedges | $ | (17 | ) | | $ | (1 | ) | | $ | (1 | ) | | $ | — |
| | | $ | (64 | ) | | $ | (83 | ) |
| Net unrealized (losses)/gains on open positions related to economic hedges | (3 | ) | | 12 |
| | 182 |
| | — |
| | | (154 | ) | | 37 |
|
| Total mark-to-market (losses)/gains in operating costs and expenses | $ | (20 | ) | | $ | 11 |
| | $ | 181 |
| | $ | — |
| | | $ | (218 | ) | | $ | (46 | ) |
| |
(a) | Represents the elimination of the intercompany activity between Retail and Generation. |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2016 |
| | Generation | | | | | | | | | |
| | Gulf Coast | | East/West | | Retail | | Renewables | | NRG Yield | | Elimination(a) | | Total |
| | (In millions) |
| Mark-to-market results in operating revenues | | | | | | | | | | | | | |
| Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges | $ | (389 | ) | | $ | (89 | ) | | $ | (2 | ) | | $ | — |
| | $ | — |
| | $ | 33 |
| | $ | (447 | ) |
| Net unrealized (losses)/gains on open positions related to economic hedges | (129 | ) | | 41 |
| | 2 |
| | (6 | ) | | — |
| | (103 | ) | | (195 | ) |
| Total mark-to-market losses in operating revenues | $ | (518 | ) | | $ | (48 | ) | | $ | — |
| | $ | (6 | ) | | $ | — |
| | $ | (70 | ) | | $ | (642 | ) |
| Mark-to-market results in operating costs and expenses | | | | | | | | | | | | | |
| Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges | $ | 31 |
| | $ | 16 |
| | $ | 305 |
| | $ | — |
| | $ | — |
| | $ | (33 | ) | | $ | 319 |
|
| Reversal of acquired gain positions related to economic hedges | — |
| | (12 | ) | | — |
| | — |
| | — |
| | — |
| | (12 | ) |
| Net unrealized gains/(losses) on open positions related to economic hedges | 40 |
| | (2 | ) | | 60 |
| | — |
| | — |
| | 103 |
| | 201 |
|
| Total mark-to-market gains in operating costs and expenses | $ | 71 |
| | $ | 2 |
| | $ | 365 |
| | $ | — |
| | $ | — |
| | $ | 70 |
| | $ | 508 |
|
(a) Represents the elimination of the intercompany activity between Retail and Generation. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2022 |
| (In millions) | Texas | | East | | West/Services/Other | | Eliminations | | Total |
| Mark-to-market results in revenues | | | | | | | | | |
| Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges | $ | 2 | | | $ | (5) | | | $ | 40 | | | $ | (8) | | | $ | 29 | |
| Reversal of acquired (gain) positions related to economic hedges | — | | | (3) | | | — | | | — | | | (3) | |
| Net unrealized (losses) on open positions related to economic hedges | — | | | (22) | | | (96) | | | 9 | | | (109) | |
| Total mark-to-market gains/(losses) in revenues | $ | 2 | | | $ | (30) | | | $ | (56) | | | $ | 1 | | | $ | (83) | |
| Mark-to-market results in operating costs and expenses | | | | | | | | | |
| Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges | $ | (366) | | | $ | (738) | | | $ | (165) | | | $ | 8 | | | $ | (1,261) | |
| Reversal of acquired loss/(gain) positions related to economic hedges | 29 | | | (5) | | | (19) | | | — | | | 5 | |
| Net unrealized gains on open positions related to economic hedges | 948 | | | 961 | | | 687 | | | (9) | | | 2,587 | |
| Total mark-to-market gains in operating costs and expenses | $ | 611 | | | $ | 218 | | | $ | 503 | | | $ | (1) | | | $ | 1,331 | |
Mark-to-market results consist of unrealized gains and losses on contactscontracts that are yet to be 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 year ended December 31, 2017,2023, the $239$144 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 and an increase in the value of open positions as a result of decreases in gaspower prices. The $46 million$3.0 billion loss in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period, as well as a decrease in the value of East and West/Other open positions as a result of decreases in natural gas and power prices. This was partially offset by an increase in the value of Texas open positions as a result of increases in ERCOT power prices.
For the year ended December 31, 2022, the $83 million loss in revenues from economic hedge positions was driven by a decrease in the value of open positions as a result of increases in power prices across all segments, partially offset by the reversal of previously recognized unrealized losses on contracts that settled during the period. The $1.3 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 ERCOT heat rate.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.
In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the years ended December 31, 20172023 and 2016.2022. The realized and unrealized financial and physical trading results are included in operating revenue. The Company's trading activities are subject to limits within the Company's Risk Management Policy and are primarily transacted through BETM.Policy.
| | | | | | | | | | | |
| | Year ended December 31, |
| (In millions) | 2023 | | 2022 |
| Trading gains/(losses) | | | |
| Realized | $ | 11 | | | $ | 6 | |
| Unrealized | 38 | | | (4) | |
| Total trading gains | $ | 49 | | | $ | 2 | |
|
| | | | | | | |
| | Year ended December 31, |
| (In millions) | 2017 | | 2016 |
| Trading gains/(losses) | | | |
| Realized | $ | 43 |
| | $ | 71 |
|
| Unrealized | (11 | ) | | 28 |
|
| Total trading gains | $ | 32 |
| | $ | 99 |
|
Operations and Maintenance ExpenseExpenses
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Generation |
| Retail |
| Renewables |
| NRG Yield |
| Corporate |
| Eliminations |
|
|
| Gulf Coast |
| East/West |
|
|
|
|
|
| Total |
| (In millions) |
| Year Ended December 31, 2017 | $ | 515 |
|
| $ | 371 |
|
| $ | 222 |
|
| $ | 118 |
|
| $ | 196 |
|
| $ | 15 |
|
| $ | (44 | ) |
| $ | 1,393 |
|
| Year Ended December 31, 2016 | $ | 577 |
|
| $ | 488 |
|
| $ | 245 |
|
| $ | 122 |
|
| $ | 176 |
|
| $ | 27 |
|
| $ | (36 | ) |
| $ | 1,599 |
|
Operations and maintenance expenses decreased by $206 million forare comprised of the year ended December 31, 2017, compared to the same period in 2016, due to the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Texas | | East | | West/Services/Other | | Vivint Smart Home(a) | | Corporate | | Eliminations | | Total |
| | | |
| Year Ended December 31, 2023 | $ | 624 | | | $ | 345 | | | $ | 245 | | | $ | 187 | | | $ | — | | | $ | (4) | | | $ | 1,397 | |
| Year Ended December 31, 2022 | 749 | | | 391 | | | 214 | | | — | | | 1 | | | (3) | | | 1,352 | |
|
| | | |
| | (In millions) |
| Decrease in operation and maintenance expenses due to major maintenance activities and environmental control work at Midwest Generation offset by higher variable operating costs | $ | (96 | ) |
| Decrease in operations and maintenance expenses due to timing of planned outages in Texas | (32 | ) |
| Decrease in operations and maintenance expenses due to lower expenses at Big Cajun II in 2017 | (24 | ) |
| Decrease in operations and maintenance expenses due to the deactivation of the Huntley and Dunkirk facilities in 2016 | (18 | ) |
| Decrease in Retail operation and maintenance expenses due to reduced headcount | (22 | ) |
| Decrease in operations and maintenance expense due to a reduction in headcount related to the sale of the engine services business | (10 | ) |
| Operations and maintenance expense increased due to forced outages at Walnut Creek and El Segundo in 2017 | 20 |
|
| Other | (24 | ) |
| | $ | (206 | ) |
Other Cost of Operations
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Generation | Retail |
| Renewables |
| NRG Yield |
| Corporate |
|
|
| Gulf Coast |
| East/West |
|
|
|
|
| Total |
| (In millions) |
| Year Ended December 31, 2017 | $ | 101 |
|
| $ | 76 |
|
| $ | 100 |
|
| $ | 21 |
|
| $ | 67 |
|
| $ | — |
|
| $ | 365 |
|
| Year Ended December 31, 2016 | $ | 95 |
|
| $ | 66 |
|
| $ | 93 |
|
| $ | 20 |
|
| $ | 65 |
|
| $ | 1 |
|
| $ | 340 |
|
Other cost(a) Includes results of operations following the acquisition date of March 10, 2023
Operations and maintenance expenses increased by $25$45 million for the year ended December 31, 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 | $ | 187 | |
| Increase in retail operation personnel costs primarily driven by an increase in accruals as part of the Company's annual incentive plan reflecting financial outperformance for the year | 48 |
| Increase in major maintenance expenditures associated with the scope and duration of outages at the Texas gas facilities and Cottonwood, partially offset by the Texas coal facilities (excluding W.A. Parish Unit 8 included below) | 21 | |
| Decrease due to the current year partial property insurance claim for the extended outage at W.A. Parish Unit 8, as well as restoration expenses incurred in 2022, partially offset by the prior year Limestone property insurance claim | (124) | |
| Decrease driven by the disposition of STP and Gregory in 2023 | (28) | |
| Decrease in variable operation and maintenance expense due to a reduction in PJM generation volumes in 2023 | (26) | |
| Decrease due to change in estimates of environmental remediation costs at deactivated sites in the East in 2022 | (23) | |
| Decrease driven primarily by East asset retirements, partially offset by an increase in deactivation costs in the West | (8) | |
| Other | (2) | |
| Increase in operations and maintenance expense | $ | 45 | |
|
| | | |
| | (In millions) |
| Increase in asset retirement expenses of $18 million in the East, offset by a reduction in property taxes at Huntley and Dunkirk | $ | 10 |
|
| Increase in expense due to a $10 million sales tax audit settlement received in 2016, offset slightly by a decrease in gross receipt taxes in 2017 | 7 |
|
| Increase of $14 million in reclamation expenses at the Jewett Mine, offset by favorable tax assessments related to coal plants in Texas | 4 |
|
| Other | 4 |
|
| | $ | 25 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Texas | | East | | West/Services/Other | | | | Vivint Smart Home(a) | | Total |
| | | | | |
| Year Ended December 31, 2023 | $ | 243 | | | $ | 131 | | | $ | 13 | | | | | $ | 3 | | | $ | 390 | |
| Year Ended December 31, 2022 | 246 | | | 149 | | | 16 | | | | | — | | | 411 | |
(a) Includes results of operations following the acquisition date of March 10, 2023
Depreciation and Amortization
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | Retail | | Renewables | | NRG Yield | | Corporate | | |
| | Generation | | | | | | Total |
| | (In millions) |
| Year Ended December 31, 2017 | $ | 377 |
| | $ | 117 |
| | $ | 196 |
| | $ | 334 |
| | $ | 32 |
| | $ | 1,056 |
|
| Year Ended December 31, 2016 | $ | 516 |
| | $ | 111 |
| | $ | 185 |
| | $ | 303 |
| | $ | 57 |
| | $ | 1,172 |
|
Depreciation and amortization expenseOther cost of operations decreased by $116$21 million for the year ended December 31, 2017,2023, compared to the same period in 2016,2022, due to the Jewett Mine being fully depreciated in December 2016 as well as impairments in 2016.following:
Impairment Losses | | | | | |
| (In millions) |
| Decrease due to changes in current year ARO cost estimates, primarily at Jewett Mine | $ | (28) | |
| Decrease in retail gross receipt taxes due to lower revenue in the East offset by higher revenues in Texas | (10) | |
| Decrease driven by the disposition of STP and Gregory in 2023 | (5) | |
| Increase due to higher property insurance premiums | 18 | |
| Other | 4 | |
| Decrease in other cost of operations | $ | (21) | |
For the year ended December 31, 2017, the Company recorded impairment losses of $1,709 million related to various facilities as further described in Item 15 — Note 10, Asset Impairments and Note 11, Goodwill and Other Intangibles, to the Consolidated Financial Statements.
In 2016, the Company recorded impairment losses of $702 million related to various facilities, as well as goodwill for its Texas reporting units, as further described in Item 15 — Note 10, Asset Impairments and Note 11, Goodwill and Other Intangibles, to the Consolidated Financial Statements.
Selling, General and Administrative Expenses
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Generation |
| Retail |
| Renewables |
| NRG Yield |
| Corporate |
| Total |
| (In millions) |
| Year Ended December 31, 2017 | $ | 207 |
|
| $ | 452 |
|
| $ | 56 |
|
| $ | 22 |
|
| $ | 170 |
|
| $ | 907 |
|
| Year Ended December 31, 2016 | $ | 265 |
|
| $ | 498 |
|
| $ | 61 |
|
| $ | 17 |
|
| $ | 254 |
|
| $ | 1,095 |
|
Selling, generalDepreciation and administrativeAmortization
Depreciation and amortization expenses decreasedare comprised of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Texas | | East | | West/Services/Other | | Vivint Smart Home(a) | | Corporate | | Total |
| |
| Year Ended December 31, 2023 | $ | 294 | | | $ | 116 | | | $ | 95 | | | $ | 586 | | | $ | 36 | | | $ | 1,127 | |
| Year Ended December 31, 2022 | 310 | | | 208 | | 85 | | | — | | | 31 | | | 634 | |
(a) Includes results of operations following the acquisition date of March 10, 2023
Depreciation and amortization expense increased by $188$493 million for the year ended December 31, 20172023, 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.
Reorganization CostsImpairment Losses
Reorganization costs of $44 million, primarily related to employee costs were incurred as part of the Transformation Plan announced in 2017.
Other Income - Affiliate
Other income - affiliate represents the services fees charged to GenOn for shared services under the Services Agreement through the June 14, 2017, the date of deconsolidation.
Gain/(Loss) on Sale of Assets
During the year ended December 31, 2017,2023, the Company sold landrecorded impairment losses related to property plant and certain wind assets which resultedequipment and leases of $2 million, $4 million and $20 million in gains of $16 million. the Texas, East and West/Services/Other segments, respectively.
During the year ended December 31, 2016,2022, the Company sold a majority interestrecorded impairment losses of $206 million, of which $150 million were related to the decline in PJM capacity prices and the near-term retirement date of the Joliet facility, $43 million related to the purchase and sale agreement for the sale of the land and related assets at the Astoria generating site and the planned withdrawal and cancellation of its EVgo businessproposed Astoria redevelopment project, and an additional $13 million in the East segment.
Refer to Vision Ridge Partners, which resulted in a loss on sale as described in Item 15 — Note 3, Discontinued Operations, Acquisitions and Dispositions11, Asset Impairments, to the Consolidated Financial Statements.Statements for further discussion.
Selling, General and Administrative Costs
Selling, general and administrative costs are comprised of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | | Texas | | East | | West/Services/Other | | Vivint Smart Home(a) | | Corporate/ Eliminations | | Total |
| | |
| Year Ended December 31, 2023 | | $ | 637 | | | $ | 573 | | | $ | 202 | | | $ | 499 | | | $ | 57 | | | $ | 1,968 | |
| Year Ended December 31, 2022 | | 559 | | | 428 | | | 202 | | | — | | | 39 | | | 1,228 | |
(a) Includes results of operations following the acquisition date of March 10, 2023
Selling, general and administrative costs increased by $740 million for the year ended December 31, 2023 compared to the same period in 2022, due to the following: | | | | | |
| (In millions) |
| Increase due to the acquisition of Vivint Smart Home | $ | 499 | |
| Increase in personnel costs primarily driven by an increase in accruals as part of the Company's annual incentive plan reflecting financial outperformance for the year | 140 | |
| Increase in broker fee and commissions expenses | 49 | |
| Increase in marketing and media expenses | 28 | |
| Increase in consulting and legal expenses | 17 | |
| Other | 7 | |
| Increase in selling, general and administrative costs | $ | 740 | |
Provision for Credit Losses
Provision for credit losses are comprised of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | | Texas | | East | | West/Services/Other | | | | Vivint Smart Home(a) | | Total |
| | |
| Year Ended December 31, 2023 | | $ | 159 | | | $ | 28 | | | $ | 30 | | | | | $ | 34 | | | $ | 251 | |
| Year Ended December 31, 2022 | | (40) | | | 28 | | | 23 | | | | | — | | | 11 | |
(a) Includes results of operations following the acquisition date of March 10, 2023
Provision for credit losses increased by $240 million for the year ended December 31, 2023, compared to the same period in 2022, due to the following:
| | | | | |
| (In millions) |
| Increase due to Winter Storm Uri loss mitigation recognized as income in 2022 | $ | 126 | |
| Increase due to higher Home retail revenues, deteriorated customer payment behavior and the longer duration of the Texas disconnect moratorium in 2023 as compared to 2022 | 80 | |
| Increase due to the acquisition of Vivint Smart Home | 34 | |
| Increase in provision for credit losses | $ | 240 | |
Acquisition-Related Transaction and Integration Costs
Acquisition-related transaction and integration costs were $119 million and $52 million for the years ended December 31, 2023 and 2022, respectively, include:
| | | | | | | | | | | |
| As of December 31, |
| (In millions) | 2023 | | 2022 |
| Vivint Smart Home acquisition costs | $ | 38 | | | $ | 17 | |
| Vivint Smart Home integration costs | 52 | | | — | |
| Other integration costs, primarily related to Direct Energy | 29 | | | 35 | |
| Acquisition-related transaction and integration costs | $ | 119 | | | $ | 52 | |
Gain on Sale of Assets
The gain on sale of assets of $1.6 billion and $52 million recorded for the years ended December 31, 2023 and 2022, respectively, include:
| | | | | | | | | | | |
| As of December 31, |
| (In millions) | 2023 | | 2022 |
| Sale of the Company's 44% equity interest in STP | $ | 1,236 | | | $ | — | |
| Sale of Astoria land and related assets | 199 | | | — | |
| Sale of the Company's 100% ownership in the Gregory natural gas generating facility | 82 | | | — | |
| Sale of the Company's 49% ownership in the Watson natural gas generating facility | — | | | 46 | |
| Sale of land and structures at the Company's deactivated Norwalk Harbor, LLC site | 38 | | | — | |
| Sale of the Company's 50% ownership in Petra Nova | — | | | 22 | |
| Sale of land at the Company's Indian River Power, LLC site | 19 | | | — | |
| Other asset sales | 4 | | | (16) | |
| Gain on sale of assets | $ | 1,578 | | | $ | 52 | |
Impairment Losses on Investments
ForDuring the year ended December 31, 2017,2023, the Company recorded other-than-temporary impairment losses of $79$102 million which is primarily due to an other-than-temporary impairment ofon the Company's equity method investment in Petra Nova Parish Holdings,Gladstone generation facility in Queensland, Australia, as further described in Item 15 — Note 10, 11, Asset Impairments,,to the Consolidated Financial Statements.
For the year ended December 31, 2016, the Company recorded other-than-temporary impairment losses of $268 million, which is primarily due to other-than-temporary impairments on the Company's interests in Petra Nova Parish Holdings, Sherbino and Community Wind North, as further described in Item 15 — Note 10, Asset Impairments, to the Consolidated Financial Statements.
LossGain on Debt Extinguishment
A lossgain on debt extinguishment of $53$109 million was recorded for the year ended December 31, 2017, primarily2023, driven by thea partial redemption of NRGthe 3.875% Senior Notes, at a price above par value.due 2032, as further discussed in Item 15 — Note 13, Long-term Debt and Finance Leases, to the Consolidated Financial Statements.
A loss on debt extinguishment of $142Interest Expense
Interest expense increased by $250 million was recorded for the year ended December 31, 2016,2023, compared to the same period in 2022, primarily driven bydue to the repurchaseVivint Smart Home acquisition including the impact of NRGnewly issued Senior Secured First Lien Notes, at a price above par valuethe acquired debt of Vivint Smart Home, the borrowings on the Revolving Credit Facility and the Receivables Securitization Facilities, as well as the write-off of the unamortized debt issuancedeferred financing costs related toassociated with the replacementcancellation of the 2018 Term Loan Facility with the new 2023 Term Loan Facility.bridge facility.
Income Tax ExpenseMark-to-market for Economic Hedging Activities
ForMark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges. Total net mark-to-market results decreased by $4.1 billion during the year ended December 31, 2017, NRG recorded income tax expense of $8 million on a pre-tax loss of $1,540 million. For2023, compared to the same period in 2016, NRG recorded income tax expense2022.
The breakdown of $5 milliongains and losses included in revenues and operating costs and expenses by segment is as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2023 |
| (In millions) | Texas | | East | | West/Services/Other | | Eliminations | | Total |
| Mark-to-market results in revenues | | | | | | | | | |
| Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges | $ | — | | | $ | (25) | | | $ | 56 | | | $ | (12) | | | $ | 19 | |
| Reversal of acquired (gain) positions related to economic hedges | — | | | (2) | | | — | | | — | | | (2) | |
| Net unrealized gains on open positions related to economic hedges | — | | | 84 | | | 47 | | | (4) | | | 127 | |
| Total mark-to-market gains in revenues | $ | — | | | $ | 57 | | | $ | 103 | | | $ | (16) | | | $ | 144 | |
| Mark-to-market results in operating costs and expenses | | | | | | | | | |
| Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges | $ | (473) | | | $ | (812) | | | $ | (480) | | | $ | 12 | | | $ | (1,753) | |
| Reversal of acquired loss/(gain) positions related to economic hedges | 17 | | | 11 | | | (6) | | | — | | | 22 | |
| Net unrealized gains/(losses) on open positions related to economic hedges | 771 | | | (1,670) | | | (381) | | | 4 | | | (1,276) | |
| Total mark-to-market gains/(losses) in operating costs and expenses | $ | 315 | | | $ | (2,471) | | | $ | (867) | | | $ | 16 | | | $ | (3,007) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2022 |
| (In millions) | Texas | | East | | West/Services/Other | | Eliminations | | Total |
| Mark-to-market results in revenues | | | | | | | | | |
| Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges | $ | 2 | | | $ | (5) | | | $ | 40 | | | $ | (8) | | | $ | 29 | |
| Reversal of acquired (gain) positions related to economic hedges | — | | | (3) | | | — | | | — | | | (3) | |
| Net unrealized (losses) on open positions related to economic hedges | — | | | (22) | | | (96) | | | 9 | | | (109) | |
| Total mark-to-market gains/(losses) in revenues | $ | 2 | | | $ | (30) | | | $ | (56) | | | $ | 1 | | | $ | (83) | |
| Mark-to-market results in operating costs and expenses | | | | | | | | | |
| Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges | $ | (366) | | | $ | (738) | | | $ | (165) | | | $ | 8 | | | $ | (1,261) | |
| Reversal of acquired loss/(gain) positions related to economic hedges | 29 | | | (5) | | | (19) | | | — | | | 5 | |
| Net unrealized gains on open positions related to economic hedges | 948 | | | 961 | | | 687 | | | (9) | | | 2,587 | |
| Total mark-to-market gains in operating costs and expenses | $ | 611 | | | $ | 218 | | | $ | 503 | | | $ | (1) | | | $ | 1,331 | |
Mark-to-market results consist of unrealized gains and losses on a pre-taxcontracts that are yet to be 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 of $978 million. The effective tax rate was (0.5)% and (0.5)% forpositions were valued based upon the years ended December 31, 2017 and 2016, respectively.forward prices on the acquisition date.
For the year ended December 31, 2017, NRG's overall effective tax rate2023, the $144 million gain in revenues from economic hedge positions was different thandriven by an increase in the statutory ratevalue of 35%open positions as a result of decreases in power prices. The $3.0 billion loss in operating costs and expenses from economic hedge positions was driven primarily due to tax expense recorded fromby the revaluationreversal of previously recognized unrealized gains on contracts that settled during the existing net deferred tax assetperiod, as well as a decrease in the value of East and state taxes,West/Other open positions as a result of decreases in natural gas and power prices. This was partially offset by the change in valuation allowance, establishing the AMT credit receivable and the generation of PTC's from various wind facilities. The tax expense recorded for revaluation of the net deferred tax asset is required to reflect the reductionan increase in the corporate income tax rate from 35% to 21%value of Texas open positions as a result of increases in accordance with the Tax Act.ERCOT power prices.
|
| | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 |
| | (In millions except as otherwise stated) |
| Loss before income taxes | $ | (1,540 | ) | | $ | (978 | ) |
| Tax at 35% | (539 | ) | | (342 | ) |
| State taxes | 19 |
| | — |
|
| Foreign operations | 2 |
| | 10 |
|
| Tax Act - corporate income tax rate change | 733 |
| | — |
|
| Valuation allowance due to corporate income tax rate change | (660 | ) | | — |
|
| Valuation allowance - current period activities | 482 |
| | 398 |
|
| Impact of non-taxable entity earnings | (5 | ) | | 22 |
|
| Book goodwill impairment | 30 |
| | — |
|
| Net interest accrued on uncertain tax positions | — |
| | 1 |
|
| Production tax credits | (20 | ) | | (26 | ) |
| Recognition of uncertain tax benefits | (5 | ) | | 2 |
|
| Tax expense attributable to consolidated partnerships | 4 |
| | (1 | ) |
| State rate change including true-up to current period activity | 18 |
| | (59 | ) |
| AMT refundable credit | (64 | ) | | — |
|
| Other | 13 |
| | — |
|
| Income tax expense | $ | 8 |
|
| $ | 5 |
|
| Effective income tax rate | (0.5 | )% | | (0.5 | )% |
The effective income tax rate may vary from period to period depending on, among other factors, the geographic and business mix of earnings and losses and changes in valuation allowances in accordance with ASC 740, Income Taxes, or ASC 740. These factors and others, including the Company's history of pre-tax earnings and losses, are taken into account in assessing the ability to realize deferred tax assets.
Income from Discontinued Operations, Net of Income Tax
For the year ended December 31, 2017, NRG recorded2022, the $83 million loss in revenues from discontinued operations, neteconomic hedge positions was driven by a decrease in the value of income tax (benefit)/expenseopen positions as a result of $789 million, related to GenOn,increases in power prices across all segments, partially offset by the reversal of previously recognized unrealized losses on contracts that settled during the period. The $1.3 billion gain in operating costs and expenses from economic hedge positions was driven primarily by an increase in the value of open positions as further describeda result of increases in Item 15 — Note 3, Discontinued Operations, Acquisitionsnatural gas and Dispositions.power prices across all segments partially offset by the reversal of previously recognized unrealized gains on contracts that settled during the period.
ForIn accordance with ASC 815, the yearfollowing table represents the results of the Company's financial and physical trading of energy commodities for the years ended December 31, 2016, NRG recorded income from discontinued2023 and 2022. The realized and unrealized financial and physical trading results are included in revenue. The Company's trading activities are subject to limits within the Company's Risk Management Policy.
| | | | | | | | | | | |
| | Year ended December 31, |
| (In millions) | 2023 | | 2022 |
| Trading gains/(losses) | | | |
| Realized | $ | 11 | | | $ | 6 | |
| Unrealized | 38 | | | (4) | |
| Total trading gains | $ | 49 | | | $ | 2 | |
Operations and Maintenance Expenses
Operations and maintenance expenses are comprised of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Texas | | East | | West/Services/Other | | Vivint Smart Home(a) | | Corporate | | Eliminations | | Total |
| | | |
| Year Ended December 31, 2023 | $ | 624 | | | $ | 345 | | | $ | 245 | | | $ | 187 | | | $ | — | | | $ | (4) | | | $ | 1,397 | |
| Year Ended December 31, 2022 | 749 | | | 391 | | | 214 | | | — | | | 1 | | | (3) | | | 1,352 | |
(a) Includes results of operations netfollowing the acquisition date of income tax (benefit)/expense of $92 million, related to GenOn, as further described in Item 15 — Note 3, Discontinued March 10, 2023
Operations Acquisitions and Dispositions.
Net loss attributable to noncontrolling interests and redeemable noncontrolling interests
Net loss attributable to noncontrolling interests and redeemable noncontrolling interests was $184maintenance expenses increased by $45 million for the year ended December 31,
2017,2023, compared to
$117the same period in 2022, due to the following: | | | | | |
| (In millions) |
| Increase due to the acquisition of Vivint Smart Home | $ | 187 | |
| Increase in retail operation personnel costs primarily driven by an increase in accruals as part of the Company's annual incentive plan reflecting financial outperformance for the year | 48 |
| Increase in major maintenance expenditures associated with the scope and duration of outages at the Texas gas facilities and Cottonwood, partially offset by the Texas coal facilities (excluding W.A. Parish Unit 8 included below) | 21 | |
| Decrease due to the current year partial property insurance claim for the extended outage at W.A. Parish Unit 8, as well as restoration expenses incurred in 2022, partially offset by the prior year Limestone property insurance claim | (124) | |
| Decrease driven by the disposition of STP and Gregory in 2023 | (28) | |
| Decrease in variable operation and maintenance expense due to a reduction in PJM generation volumes in 2023 | (26) | |
| Decrease due to change in estimates of environmental remediation costs at deactivated sites in the East in 2022 | (23) | |
| Decrease driven primarily by East asset retirements, partially offset by an increase in deactivation costs in the West | (8) | |
| Other | (2) | |
| Increase in operations and maintenance expense | $ | 45 | |
Other Cost of Operations
Other Cost of operations are comprised of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Texas | | East | | West/Services/Other | | | | Vivint Smart Home(a) | | Total |
| | | | | |
| Year Ended December 31, 2023 | $ | 243 | | | $ | 131 | | | $ | 13 | | | | | $ | 3 | | | $ | 390 | |
| Year Ended December 31, 2022 | 246 | | | 149 | | | 16 | | | | | — | | | 411 | |
(a) Includes results of operations following the acquisition date of March 10, 2023
Other cost of operations decreased by $21 million for the year ended December 31, 2016. For the years ended December 31, 2017, and 2016, the net losses attributable to noncontrolling interests primarily reflect losses allocated to tax equity investors using the hypothetical liquidation at book value, or HLBV, method, offset in part by NRG Yield, Inc.'s share of income for the period.
Consolidated Results of Operations for the years ended 2016 and 2015
The following table provides selected financial information for the Company:
|
| | | | | | | | | | | |
| | Year Ended December 31, | | |
| (In millions except otherwise noted) | 2016 | | 2015 | | Change |
| Operating Revenues | | | | | |
Energy revenue (a) | $ | 3,131 |
| | $ | 3,867 |
| | $ | (736 | ) |
Capacity revenue (a) | 1,225 |
| | 1,361 |
| | (136 | ) |
| Retail revenue | 6,357 |
| | 6,867 |
| | (510 | ) |
| Mark-to-market for economic hedging activities | (642 | ) | | (134 | ) | | (508 | ) |
| Contract amortization | (56 | ) | | (40 | ) | | (16 | ) |
Other revenues (b) | 497 |
| | 407 |
| | 90 |
|
| Total operating revenues | 10,512 |
| | 12,328 |
| | (1,816 | ) |
| Operating Costs and Expenses | | | | | |
Cost of sales (a) | 5,827 |
| | 6,870 |
| | 1,043 |
|
| Mark-to-market for economic hedging activities | (508 | ) | | 59 |
| | 567 |
|
Contract and emissions credit amortization (c) | 43 |
| | 41 |
| | (2 | ) |
| Operations and maintenance | 1,599 |
| | 1,657 |
| | 58 |
|
| Other cost of operations | 340 |
| | 373 |
| | 33 |
|
| Total cost of operations | 7,301 |
| | 9,000 |
| | 1,699 |
|
| Depreciation and amortization | 1,172 |
| | 1,351 |
| | 179 |
|
| Impairment losses | 702 |
| | 4,860 |
| | 4,158 |
|
| Selling, general and administrative | 1,095 |
| | 1,228 |
| | 133 |
|
| Development costs | 89 |
| | 154 |
| | 65 |
|
| Total operating costs and expenses | 10,359 |
| | 16,593 |
| | 6,234 |
|
| Other income - affiliate | 193 |
| | 193 |
| | — |
|
| Loss on sale of assets | (80 | ) | | — |
| | (80 | ) |
| Gain on postretirement benefits curtailment | — |
| | 21 |
| | (21 | ) |
| Operating Income/(Loss) | 266 |
| | (4,051 | ) | | 4,317 |
|
| Other Income/(Expense) | | | | | |
| Equity in earnings of unconsolidated affiliates | 27 |
| | 36 |
| | (9 | ) |
| Impairment losses on investments | (268 | ) | | (56 | ) | | (212 | ) |
| Other income, net | 34 |
| | 26 |
| | 8 |
|
| Loss on sale of equity method investment | — |
| | (14 | ) | | 14 |
|
| Net (loss)/gain on debt extinguishment | (142 | ) | | 10 |
| | (152 | ) |
| Interest expense | (895 | ) | | (937 | ) | | 42 |
|
| Total other expense | (1,244 | ) | | (935 | ) | | (309 | ) |
| Loss from Continuing Operations Before Income Taxes | (978 | ) | | (4,986 | ) | | 4,008 |
|
| Income tax expense | 5 |
| | 1,345 |
| | 1,340 |
|
| Net Loss from Continuing Operations | (983 | ) | | (6,331 | ) | | 5,348 |
|
| Income/(loss) from discontinued operations, net of tax | 92 |
| | (105 | ) | | 197 |
|
| Net Loss | (891 | ) | | (6,436 | ) | | 5,545 |
|
| Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests | (117 | ) | | (54 | ) | | (63 | ) |
| Net Loss Attributable to NRG Energy, Inc. | $ | (774 | ) | | $ | (6,382 | ) | | $ | 5,608 |
|
| Business Metrics | | | | | |
| Average natural gas price — Henry Hub ($/MMBtu) | $ | 2.46 |
| | $ | 2.66 |
| | (8 | )% |
| |
(a) | Includes realized gains and losses from financially settled transactions. |
| |
(b) | Includes unrealized trading gains and losses. |
| |
(c) | Includes amortization of SO2 and NOx credits and excludes amortization of RGGI.
|
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 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 tables below present the composition and reconciliation of gross margin and economic gross margin which reflects the Company's current view of reporting segments for the years ended December 31, 2016 and 2015:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2016 |
| | Generation | | | | | | | | | | |
| (In millions except otherwise noted) | Gulf Coast | | East/West | | Subtotal | | Retail | | Renewables | | NRG Yield | | Corporate/Eliminations | | Total |
| Energy revenue | $ | 2,073 |
| | $ | 1,098 |
| | $ | 3,171 |
| | $ | — |
| | $ | 369 |
| | $ | 582 |
| | $ | (991 | ) | | $ | 3,131 |
|
| Capacity revenue | 293 |
| | 598 |
| | 891 |
| | — |
| | — |
| | 345 |
| | (11 | ) | | 1,225 |
|
| Retail revenue | — |
| | — |
| | — |
| | 6,336 |
| | — |
| | — |
| | 21 |
| | 6,357 |
|
| Mark-to-market for economic hedging activities | (518 | ) | | (48 | ) | | (566 | ) | | — |
| | (6 | ) | | — |
| | (70 | ) | | (642 | ) |
| Contract amortization | 15 |
| | — |
| | 15 |
| | (1 | ) | | (1 | ) | | (69 | ) | | — |
| | (56 | ) |
Other revenue (a) | 237 |
| | 85 |
| | 322 |
| | — |
| | 44 |
| | 177 |
| | (46 | ) | | 497 |
|
| Operating revenue | 2,100 |
| | 1,733 |
| | 3,833 |
| | 6,335 |
| | 406 |
| | 1,035 |
| | (1,097 | ) | | 10,512 |
|
| Cost of fuel | (938 | ) | | (469 | ) | | (1,407 | ) | | (8 | ) | | (3 | ) | | (33 | ) | | 130 |
| | (1,321 | ) |
Other costs of sales(b) | (387 | ) | | (299 | ) | | (686 | ) | | (4,679 | ) | | (11 | ) | | (28 | ) | | 898 |
| | (4,506 | ) |
| Mark-to-market for economic hedging activities | 71 |
| | 2 |
| | 73 |
| | 365 |
| | — |
| | — |
| | 70 |
| | 508 |
|
| Contract and emission credit amortization | (29 | ) | | (5 | ) | | (34 | ) | | (6 | ) | | — |
| | (6 | ) | | 3 |
| | (43 | ) |
| Gross margin | $ | 817 |
| | $ | 962 |
| | $ | 1,779 |
| | $ | 2,007 |
| | $ | 392 |
| | $ | 968 |
| | $ | 4 |
| | $ | 5,150 |
|
| Less: Mark-to-market for economic hedging activities, net | (447 | ) | | (46 | ) | | (493 | ) | | 365 |
| | (6 | ) | | — |
| | — |
| | (134 | ) |
| Less: Contract and emission credit amortization, net | (14 | ) | | (5 | ) | | (19 | ) | | (7 | ) | | (1 | ) | | (75 | ) | | 3 |
| | (99 | ) |
| Economic gross margin | $ | 1,278 |
| | $ | 1,013 |
| | $ | 2,291 |
| | $ | 1,649 |
| | $ | 399 |
| | $ | 1,043 |
| | $ | 1 |
| | $ | 5,383 |
|
| Business Metrics | | | | | | | | | | | | | | | |
MWh sold (thousands)(c)(d) | 52,929 |
| | 25,995 |
| | | |
|
| | 3,827 |
| | 7,363 |
| | | | |
MWh generated (thousands)(e) | 47,828 |
| | 17,114 |
| | | |
|
| | 3,827 |
| | 9,264 |
| | | | |
(a) Renewables Other revenue includes $19 million of intercompany revenue to NRG Yield.
(b) Includes purchased energy, capacity and emissions credits.
(c) MWh sold excludes generation at facilities in the West and NRG Yield that generate revenue under tolling agreements.
(d) Does not include MWh of 71 thousand or MWt of 1,966 thousand for thermal sold by NRG Yield.
(e) Does not include MWh of 275 thousand or MWt of 1,966 thousand for thermal generated by NRG Yield.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2015 |
| | Generation | | | | | | | | | |
| (In millions except otherwise noted) | Gulf Coast | | East/West | | Subtotal | | Retail | | Renewables | | NRG Yield | | Corporate/Eliminations | | Total |
| Energy revenue | $ | 2,443 |
| | $ | 1,629 |
| | $ | 4,072 |
| | $ | — |
| | $ | 356 |
| | $ | 495 |
| | $ | (1,056 | ) | | $ | 3,867 |
|
| Capacity revenue | 290 |
| | 737 |
| | 1,027 |
| | — |
| | — |
| | 341 |
| | (7 | ) | | 1,361 |
|
| Retail revenue | — |
| | — |
| | — |
| | 6,910 |
| | — |
| | — |
| | (43 | ) | | 6,867 |
|
| Mark-to-market for economic hedging activities | (66 | ) | | (76 | ) | | (142 | ) | | 4 |
| | (3 | ) | | (2 | ) | | 9 |
| | (134 | ) |
| Contract amortization | 15 |
| | — |
| | 15 |
| | (1 | ) | | — |
| | (54 | ) | | — |
| | (40 | ) |
Other revenue (a) | 207 |
| | — |
| | 207 |
| | — |
| | 30 |
| | 188 |
| | (18 | ) | | 407 |
|
| Operating revenue | 2,889 |
| | 2,290 |
| | 5,179 |
| | 6,913 |
| | 383 |
| | 968 |
| | (1,115 | ) | | 12,328 |
|
| Cost of fuel | (1,137 | ) | | (715 | ) | | (1,852 | ) | | (9 | ) | | (4 | ) | | (43 | ) | | 152 |
| | (1,756 | ) |
Other costs of sales(b) | (355 | ) | | (442 | ) | | (797 | ) | | (5,236 | ) | | (12 | ) | | (28 | ) | | 959 |
| | (5,114 | ) |
| Mark-to-market for economic hedging activities | (17 | ) | | (29 | ) | | (46 | ) | | (4 | ) | | — |
| | — |
| | (9 | ) | | (59 | ) |
| Contract and emission credit amortization | (28 | ) | | (7 | ) | | (35 | ) | | (6 | ) | | — |
| | — |
| | — |
| | (41 | ) |
| Gross margin | $ | 1,352 |
| | $ | 1,097 |
| | $ | 2,449 |
| | $ | 1,658 |
| | $ | 367 |
| | $ | 897 |
| | $ | (13 | ) | | $ | 5,358 |
|
| Less: Mark-to-market for economic hedging activities, net | (83 | ) | | (105 | ) | | (188 | ) | | — |
| | (3 | ) | | (2 | ) | | — |
| | (193 | ) |
| Less: Contract and emission credit amortization, net | (13 | ) | | (7 | ) | | (20 | ) | | (7 | ) | | — |
| | (54 | ) | | — |
| | (81 | ) |
| Economic gross margin | $ | 1,448 |
| | $ | 1,209 |
| | $ | 2,657 |
| | $ | 1,665 |
| | $ | 370 |
| | $ | 953 |
| | $ | (13 | ) | | $ | 5,632 |
|
| Business Metrics | | | | | | | | | | | | | | | |
MWh sold (thousands)(c)(d) | 58,127 |
| | 37,403 |
| | | | | | 3,685 |
| | 6,760 |
| | | | |
MWh generated (thousands)(e) | 54,162 |
| | 24,623 |
| | | | | | 3,739 |
| | 9,247 |
| | | | |
(a) Renewables Other revenue includes $11 million of intercompany revenue to NRG Yield.
(b) Includes purchased energy, capacity and emissions credits.
(c) MWh sold excludes generation at facilities in the West and NRG Yield that generate revenue under tolling agreements.
(d) Does not include MWh of 297 thousand or MWt of 1,946 thousand for thermal sold by NRG Yield.
(e) Does not include MWh of 297 thousand or MWt of 1,946 thousand for thermal generated by NRG Yield.
The table below represents the weather metrics for 2016 and 2015:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Years ended December 31, | Quarter ended December 31, | | Quarter ended September 30, | | Quarter ended June 30, | | Quarter ended March 31, |
| Weather Metrics | Gulf Coast(b) | | East/West | | Gulf Coast(b) | | East/West | | Gulf Coast(b) | | East/West | | Gulf Coast(b) | | East/West | | Gulf Coast(b) | | East/West |
| 2016 | | | | | | | | | | | | | | | | | | | |
CDDs(a) | 2,967 |
| | 1,169 |
| | 362 |
| | 71 |
| | 1,655 |
| | 806 |
| | 873 |
| | 273 |
| | 76 |
| | 19 |
|
HDDs(a) | 1,529 |
| | 3,190 |
| | 545 |
| | 1,145 |
| | — |
| | 23 |
| | 53 |
| | 410 |
| | 931 |
| | 1,613 |
|
| 2015 | | | | | | | | | | | | | | | | | | | |
| CDDs | 2,870 |
| | 1,223 |
| | 286 |
| | 107 |
| | 1,652 |
| | 798 |
| | 892 |
| | 293 |
| | 41 |
| | 25 |
|
| HDDs | 1,887 |
| | 3,322 |
| | 556 |
| | 1,029 |
| | — |
| | 16 |
| | 47 |
| | 390 |
| | 1,285 |
| | 1,887 |
|
| 10 year average | | | | | | | | | | | | | | | | | | | |
| CDDs | 2,897 |
| | 1,028 |
| | 240 |
| | 65 |
| | 1,597 |
| | 688 |
| | 969 |
| | 259 |
| | 90 |
| | 16 |
|
| HDDs | 1,928 |
| | 3,556 |
| | 754 |
| | 1,233 |
| | 4 |
| | 49 |
| | 77 |
| | 448 |
| | 1,092 |
| | 1,827 |
|
(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) CDDs/HDDs for the Gulf Coast region represent an average of cumulative population-weighted CDDs/HDDs for Texas and the West South-Central Climate region.
Generation gross margin and economic gross margin
Generation gross margin decreased $670 million and economic gross margin decreased $366 million, both of which include intercompany sales, during the year ended December 31, 2016,2023, compared to the same period in 2015.2022, due to the following:
The tables below describe the decrease in Generation gross margin and economic gross margin:
Gulf Coast Region
|
| | | |
| | (In millions) |
| Lower gross margin resulting from lower average realized energy prices due to a decline in natural gas prices and increased wind generation in Texas | $ | (148 | ) |
| Lower gross margin primarily due to 11% lower coal generation and 21% lower gas generation in Texas, which was driven by lower gas prices, increased wind generation in Texas, an increase in unplanned outages and timing of planned outages | (82 | ) |
| Higher gross margin resulting from a 12% increase in nuclear generation driven by reduced unplanned outages and the timing of planned outages | 55 |
|
| Other | 5 |
|
| Decrease in economic gross margin | $ | (170 | ) |
| Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges | (364 | ) |
| Decrease in contract and emission credit amortization | (1 | ) |
| Decrease in gross margin | $ | (535 | ) |
East/West Region
|
| | | |
| | (In millions) |
| Lower gross margin due to a 24% decrease in generation primarily driven by the environmental control work at Powerton and fuel conversion projects at Joliet | $ | (141 | ) |
| Lower gross margin due to decreased realized capacity prices in New York due to a change in the mix of capacity resources and a 15% decrease in PJM cleared auction prices | (79 | ) |
| Lower gross margin due to the deactivation of the Huntley and Dunkirk facilities as well as the sale of the Rockford | (66 | ) |
| Lower gross margin due to lower contracted volumes | (12 | ) |
| Lower gross margin due to a decrease in realized energy prices due to the decline in natural gas prices | (12 | ) |
| Lower gross margin due to a 7% decrease in resource adequacy capacity volumes sold in California due to unit retirements and a 4% decrease in price | (10 | ) |
| Higher gross margin by BETM due to higher gains in 2016 on over the counter strategies | 88 |
|
| Changes in commercial optimization activities | 50 |
|
| Other | (14 | ) |
| Decrease in economic gross margin | $ | (196 | ) |
| Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges | 59 |
|
| Increase in contract and emission credit amortization | 2 |
|
| Decrease in gross margin | $ | (135 | ) |
Retail gross margin and economic gross margin
The following is a discussion of gross margin and economic gross margin for Retail.
|
| | | | | | | |
| | Years ended December 31, |
| (In millions except otherwise noted) | 2016 | | 2015 |
| Retail revenue | $ | 6,100 |
| | $ | 6,629 |
|
| Supply management revenue | 154 |
| | 165 |
|
| Capacity revenues | 82 |
| | 116 |
|
| Customer mark-to-market | — |
| | 4 |
|
| Contract amortization | (1 | ) | | (1 | ) |
| Other | — |
| | — |
|
Operating revenue (a) | 6,335 |
| | 6,913 |
|
Cost of sales (b) | (4,687 | ) | | (5,245 | ) |
| Mark-to-market for economic hedging activities | 365 |
| | (4 | ) |
| Contract amortization | (6 | ) | | (6 | ) |
| Gross margin | $ | 2,007 |
| | $ | 1,658 |
|
| Less: Mark-to-market for economic hedging activities, net | 365 |
| | — |
|
| Less: Contract and emission credit amortization | (7 | ) | | (7 | ) |
| Economic gross margin | $ | 1,649 |
| | $ | 1,665 |
|
| Business Metrics | | | |
| Mass electricity sales volume (GWh) - Gulf Coast | 25,102 |
| | 34,600 |
|
| Mass electricity sales volume (GWh) - All other regions | 6,674 |
| | 8,090 |
|
| C&I electricity sales volume (GWh) All regions | 18,906 |
| | 19,342 |
|
| Natural gas sales volumes (MDth) | 2,199 |
| | 1,901 |
|
| Average Retail Mass customer count (in thousands) | 2,778 |
| | 2,775 |
|
| Ending Retail Mass customer count (in thousands) | 2,818 |
| | 2,755 |
|
| | | | | |
| (In millions) |
(a)Decrease due to changes in current year ARO cost estimates, primarily at Jewett Mine | Includes intercompany sales of $4 million and $3 million in 2016 and 2015, respectively, representing sales from Retail to the Gulf Coast region. |
| $ | (28) | |
(b)Decrease in retail gross receipt taxes due to lower revenue in the East offset by higher revenues in Texas | Includes intercompany purchases(10) | |
Decrease driven by the disposition of $850 millionSTP and $895 millionGregory in 2016 and 2015, respectively.2023 | (5) | |
| Increase due to higher property insurance premiums | 18 | |
| Other | 4 | |
| Decrease in other cost of operations | $ | (21) | |
Retail gross margin
Depreciation and Amortization
Depreciation and amortization expenses are comprised of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Texas | | East | | West/Services/Other | | Vivint Smart Home(a) | | Corporate | | Total |
| |
| Year Ended December 31, 2023 | $ | 294 | | | $ | 116 | | | $ | 95 | | | $ | 586 | | | $ | 36 | | | $ | 1,127 | |
| Year Ended December 31, 2022 | 310 | | | 208 | | 85 | | | — | | | 31 | | | 634 | |
(a) Includes results of operations following the acquisition date of March 10, 2023
Depreciation and amortization expense increased $350 million and economic gross margin decreased $15by $493 million for the year ended December 31, 2016,2023, compared to the same period in 2015,2022, primarily due to: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.
|
| | | |
| | (In millions) |
| Higher gross margin due to lower supply costs of $452 million or approximately $7.00 per MWh driven by a decrease in natural gas prices, partially offset by lower rates to customers of $431 million or approximately $6.50 per MWh | $ | 21 |
|
| Lower gross margin of $19 million due to the unfavorable impact of selling back excess supply and $3 million in lower margin from a reduction in load of 86,000 MWhs due to milder weather conditions in 2016 as compared to 2015 | (22 | ) |
| Lower gross margin due to lower volumes driven by lower average customer usage and mix | (14 | ) |
| Decrease in economic gross margin | $ | (15 | ) |
| Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges | 365 |
|
| Increase in gross margin | $ | 350 |
|
Renewables gross marginDuring the year ended December 31, 2023, the Company recorded impairment losses related to property plant and economic gross margin
Renewables gross margin increased $25equipment and leases of $2 million, $4 million and economic gross margin$20 million in the Texas, East and West/Services/Other segments, respectively.
During the year ended December 31, 2022, the Company recorded impairment losses of $206 million, of which $150 million were related to the decline in PJM capacity prices and the near-term retirement date of the Joliet facility, $43 million related to the purchase and sale agreement for the sale of the land and related assets at the Astoria generating site and the planned withdrawal and cancellation of its proposed Astoria redevelopment project, and an additional $13 million in the East segment.
Refer to Item 15 — Note 11, Asset Impairments, to the Consolidated Financial Statements for further discussion.
Selling, General and Administrative Costs
Selling, general and administrative costs are comprised of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | | Texas | | East | | West/Services/Other | | Vivint Smart Home(a) | | Corporate/ Eliminations | | Total |
| | |
| Year Ended December 31, 2023 | | $ | 637 | | | $ | 573 | | | $ | 202 | | | $ | 499 | | | $ | 57 | | | $ | 1,968 | |
| Year Ended December 31, 2022 | | 559 | | | 428 | | | 202 | | | — | | | 39 | | | 1,228 | |
(a) Includes results of operations following the acquisition date of March 10, 2023
Selling, general and administrative costs increased $29by $740 million for the year ended December 31, 2016,2023 compared to the same period in 2015,2022, due to the following: | | | | | |
| (In millions) |
| Increase due to the acquisition of Vivint Smart Home | $ | 499 | |
| Increase in personnel costs primarily driven by an increase in accruals as part of the Company's annual incentive plan reflecting financial outperformance for the year | 140 | |
| Increase in broker fee and commissions expenses | 49 | |
| Increase in marketing and media expenses | 28 | |
| Increase in consulting and legal expenses | 17 | |
| Other | 7 | |
| Increase in selling, general and administrative costs | $ | 740 | |
Provision for Credit Losses
Provision for credit losses are comprised of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | | Texas | | East | | West/Services/Other | | | | Vivint Smart Home(a) | | Total |
| | |
| Year Ended December 31, 2023 | | $ | 159 | | | $ | 28 | | | $ | 30 | | | | | $ | 34 | | | $ | 251 | |
| Year Ended December 31, 2022 | | (40) | | | 28 | | | 23 | | | | | — | | | 11 | |
(a) Includes results of operations following the acquisition date of March 10, 2023
Provision for credit losses increased by a 15% increase in generation at both the Mountain Wind I and II facilities, a 4% increase in generation at the Ivanpah solar plant and generation from the Guam solar plant that reached COD in the third quarter of 2015.
NRG Yield gross margin and economic gross margin
NRG Yield gross margin increased $71 million and economic gross margin increased $90$240 million for the year ended December 31, 2016,2023, compared to the same period in 2015,2022, due to the following:
| | | | | |
| (In millions) |
| Increase due to Winter Storm Uri loss mitigation recognized as income in 2022 | $ | 126 | |
| Increase due to higher Home retail revenues, deteriorated customer payment behavior and the longer duration of the Texas disconnect moratorium in 2023 as compared to 2022 | 80 | |
| Increase due to the acquisition of Vivint Smart Home | 34 | |
| Increase in provision for credit losses | $ | 240 | |
Acquisition-Related Transaction and Integration Costs
Acquisition-related transaction and integration costs were $119 million and $52 million for the years ended December 31, 2023 and 2022, respectively, include:
| | | | | | | | | | | |
| As of December 31, |
| (In millions) | 2023 | | 2022 |
| Vivint Smart Home acquisition costs | $ | 38 | | | $ | 17 | |
| Vivint Smart Home integration costs | 52 | | | — | |
| Other integration costs, primarily related to Direct Energy | 29 | | | 35 | |
| Acquisition-related transaction and integration costs | $ | 119 | | | $ | 52 | |
Gain on Sale of Assets
The gain on sale of assets of $1.6 billion and $52 million recorded for the years ended December 31, 2023 and 2022, respectively, include:
| | | | | | | | | | | |
| As of December 31, |
| (In millions) | 2023 | | 2022 |
| Sale of the Company's 44% equity interest in STP | $ | 1,236 | | | $ | — | |
| Sale of Astoria land and related assets | 199 | | | — | |
| Sale of the Company's 100% ownership in the Gregory natural gas generating facility | 82 | | | — | |
| Sale of the Company's 49% ownership in the Watson natural gas generating facility | — | | | 46 | |
| Sale of land and structures at the Company's deactivated Norwalk Harbor, LLC site | 38 | | | — | |
| Sale of the Company's 50% ownership in Petra Nova | — | | | 22 | |
| Sale of land at the Company's Indian River Power, LLC site | 19 | | | — | |
| Other asset sales | 4 | | | (16) | |
| Gain on sale of assets | $ | 1,578 | | | $ | 52 | |
Impairment Losses on Investments
During the year ended December 31, 2023, the Company recorded other-than-temporary impairment losses of $102 million on the Company's equity method investment in Gladstone generation facility in Queensland, Australia, as further described in Item 15 — Note 11, Asset Impairments, to the Consolidated Financial Statements.
Gain on Debt Extinguishment
A gain on debt extinguishment of $109 million was recorded for the year ended December 31, 2023, driven by a partial redemption of the 3.875% Senior Notes, due 2032, as further discussed in Item 15 — Note 13, Long-term Debt and Finance Leases, to the Consolidated Financial Statements.
Interest Expense
Interest expense increased by $250 million for the year ended December 31, 2023, compared to the same period in 2022, primarily relateddue to a 26% increase in volume generated at Alta wind projectsthe Vivint Smart Home acquisition including the impact of newly issued Senior Secured First Lien Notes, the acquired debt of Vivint Smart Home, the borrowings on the Revolving Credit Facility and the Receivables Securitization Facilities, as well as an increase in price per MWh at Alta X and XI wind projects as the PPAs began in January 2016 compared to merchant prices in 2015.write-off of the deferred financing costs associated with the cancellation of the bridge facility.
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 increaseddecreased by $59 million in$4.1 billion during the year ended December 31, 2016,2023, compared to the same period in 2015.2022.
The breakdown of gains and losses included in operating revenues and operating costs and expenses by region aresegment is as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2023 |
| (In millions) | Texas | | East | | West/Services/Other | | Eliminations | | Total |
| Mark-to-market results in revenues | | | | | | | | | |
| Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges | $ | — | | | $ | (25) | | | $ | 56 | | | $ | (12) | | | $ | 19 | |
| Reversal of acquired (gain) positions related to economic hedges | — | | | (2) | | | — | | | — | | | (2) | |
| Net unrealized gains on open positions related to economic hedges | — | | | 84 | | | 47 | | | (4) | | | 127 | |
| Total mark-to-market gains in revenues | $ | — | | | $ | 57 | | | $ | 103 | | | $ | (16) | | | $ | 144 | |
| Mark-to-market results in operating costs and expenses | | | | | | | | | |
| Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges | $ | (473) | | | $ | (812) | | | $ | (480) | | | $ | 12 | | | $ | (1,753) | |
| Reversal of acquired loss/(gain) positions related to economic hedges | 17 | | | 11 | | | (6) | | | — | | | 22 | |
| Net unrealized gains/(losses) on open positions related to economic hedges | 771 | | | (1,670) | | | (381) | | | 4 | | | (1,276) | |
| Total mark-to-market gains/(losses) in operating costs and expenses | $ | 315 | | | $ | (2,471) | | | $ | (867) | | | $ | 16 | | | $ | (3,007) | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2016 |
| | Generation | | | | | | | | | | |
| | Gulf Coast | | East/West | | Retail | | Renewables | | NRG Yield | | Elimination(a) | | Total |
| | (In millions) |
| Mark-to-market results in operating revenues | | | | | | | | | | | | | |
| Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges | $ | (389 | ) | | $ | (89 | ) | | $ | (2 | ) | | $ | — |
| | $ | — |
| | $ | 33 |
| | $ | (447 | ) |
| Net unrealized (losses)/gains on open positions related to economic hedges | (129 | ) | | 41 |
| | 2 |
| | (6 | ) | | — |
| | (103 | ) | | (195 | ) |
| Total mark-to-market losses in operating revenues | $ | (518 | ) | | $ | (48 | ) | | $ | — |
| | $ | (6 | ) | | $ | — |
| | $ | (70 | ) | | $ | (642 | ) |
| Mark-to-market results in operating costs and expenses | | | | | | | | | | | | | |
| Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges | $ | 31 |
| | $ | 16 |
| | $ | 305 |
| | $ | — |
| | $ | — |
| | $ | (33 | ) | | $ | 319 |
|
| Reversal of acquired gain positions related to economic hedges | — |
| | (12 | ) | | — |
| | — |
| | — |
| | — |
| | (12 | ) |
| Net unrealized gains/(losses) on open positions related to economic hedges | 40 |
| | (2 | ) | | 60 |
| | — |
| | — |
| | 103 |
| | 201 |
|
| Total mark-to-market gains in operating costs and expenses | $ | 71 |
| | $ | 2 |
| | $ | 365 |
| | $ | — |
| | $ | — |
| | $ | 70 |
| | $ | 508 |
|
| |
(a) | Represents the elimination of the intercompany activity between Retail and Generation. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2022 |
| (In millions) | Texas | | East | | West/Services/Other | | Eliminations | | Total |
| Mark-to-market results in revenues | | | | | | | | | |
| Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges | $ | 2 | | | $ | (5) | | | $ | 40 | | | $ | (8) | | | $ | 29 | |
| Reversal of acquired (gain) positions related to economic hedges | — | | | (3) | | | — | | | — | | | (3) | |
| Net unrealized (losses) on open positions related to economic hedges | — | | | (22) | | | (96) | | | 9 | | | (109) | |
| Total mark-to-market gains/(losses) in revenues | $ | 2 | | | $ | (30) | | | $ | (56) | | | $ | 1 | | | $ | (83) | |
| Mark-to-market results in operating costs and expenses | | | | | | | | | |
| Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges | $ | (366) | | | $ | (738) | | | $ | (165) | | | $ | 8 | | | $ | (1,261) | |
| Reversal of acquired loss/(gain) positions related to economic hedges | 29 | | | (5) | | | (19) | | | — | | | 5 | |
| Net unrealized gains on open positions related to economic hedges | 948 | | | 961 | | | 687 | | | (9) | | | 2,587 | |
| Total mark-to-market gains in operating costs and expenses | $ | 611 | | | $ | 218 | | | $ | 503 | | | $ | (1) | | | $ | 1,331 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2015 |
| | Generation | | | | | | | | | | |
| | Gulf Coast | | East/West | | Retail | | Renewables | | NRG Yield | | Elimination(a) | | Total |
| | (In millions) |
| Mark-to-market results in operating revenues | | | | | | | | | | | | | |
| Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges | $ | (408 | ) | | $ | (158 | ) | | $ | (1 | ) | | $ | (3 | ) | | $ | (2 | ) | | $ | 45 |
| | $ | (527 | ) |
| Net unrealized gains/(losses) on open positions related to economic hedges | 342 |
| | 82 |
| | 5 |
| | — |
| | — |
| | (36 | ) | | 393 |
|
| Total mark-to-market (losses)/gains in operating revenues | $ | (66 | ) | | $ | (76 | ) | | $ | 4 |
| | $ | (3 | ) | | $ | (2 | ) | | $ | 9 |
| | $ | (134 | ) |
| Mark-to-market results in operating costs and expenses | | | | | | | | | | | | | |
| Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges | $ | 34 |
| | $ | 3 |
| | $ | 373 |
| | $ | — |
| | $ | — |
| | $ | (45 | ) | | $ | 365 |
|
| Reversal of acquired gain positions related to economic hedges | — |
| | (18 | ) | | (4 | ) | | — |
| | — |
| | — |
| | (22 | ) |
| Net unrealized (losses)/gains on open positions related to economic hedges | (51 | ) | | (14 | ) | | (373 | ) | | — |
| | — |
| | 36 |
| | (402 | ) |
| Total mark-to-market losses in operating costs and expenses | $ | (17 | ) | | $ | (29 | ) | | $ | (4 | ) | | $ | — |
| | $ | — |
| | $ | (9 | ) | | $ | (59 | ) |
| |
(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 to be 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 year ended December 31, 2016,2023, the $642$144 million gain in revenues from economic hedge positions was driven by an increase in the value of open positions as a result of decreases in power prices. The $3.0 billion loss in operating revenuescosts and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period, andas well as a decrease in the value of East and West/Other open positions as a result of decreases in natural gas and power prices. This was partially offset by an increase in the value of Texas open positions as a result of increases in ERCOT power prices.
For the year ended December 31, 2022, the $83 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 gas prices.power prices across all segments, partially offset by the reversal of previously recognized unrealized losses on contracts that settled during the period. The $508 million$1.3 billion 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 and an increase in the value of open positions as a result of increases in coalnatural gas and gaspower prices across all segments partially offset by the reversal of acquired contracts.previously recognized unrealized gains on contracts that settled during the period.
In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the years ended December 31, 20162023 and 2015.2022. The realized and unrealized financial and physical trading results are included in operating revenues.revenue. The Company's trading activities are subject to limits within the Company's Risk Management Policy.
| | | | | | | | | | | |
| | Year ended December 31, |
| (In millions) | 2023 | | 2022 |
| Trading gains/(losses) | | | |
| Realized | $ | 11 | | | $ | 6 | |
| Unrealized | 38 | | | (4) | |
| Total trading gains | $ | 49 | | | $ | 2 | |
|
| | | | | | | |
| | Year Ended December 31, |
| | 2016 | | 2015 |
| | (In millions) |
| Trading gains/(losses) | | | |
| Realized | $ | 71 |
| | $ | 57 |
|
| Unrealized | 28 |
| | (76 | ) |
| Total trading gains/(losses) | $ | 99 |
| | $ | (19 | ) |
Operations and Maintenance Expense
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Generation | | Retail | | Renewables | | NRG Yield | | Corporate | | Eliminations | | |
| | Gulf Coast | | East/West | | | | | | | Total |
| | (In millions) |
| Year Ended December 31, 2016 | $ | 577 |
| | $ | 488 |
| | $ | 245 |
| | $ | 122 |
| | $ | 176 |
| | $ | 27 |
| | $ | (36 | ) | | $ | 1,599 |
|
| Year Ended December 31, 2015 | $ | 654 |
| | $ | 487 |
| | $ | 225 |
| | $ | 96 |
| | $ | 180 |
| | $ | 25 |
| | $ | (10 | ) | | $ | 1,657 |
|
Operations and maintenance expenses decreasedare comprised of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Texas | | East | | West/Services/Other | | Vivint Smart Home(a) | | Corporate | | Eliminations | | Total |
| | | |
| Year Ended December 31, 2023 | $ | 624 | | | $ | 345 | | | $ | 245 | | | $ | 187 | | | $ | — | | | $ | (4) | | | $ | 1,397 | |
| Year Ended December 31, 2022 | 749 | | | 391 | | | 214 | | | — | | | 1 | | | (3) | | | 1,352 | |
(a) Includes results of operations following the acquisition date of March 10, 2023
Operations and maintenance expenses increased by $58$45 million for the year ended December 31, 2016,2023, compared to the same period in 2015,2022, due to the following:
|
| | | |
| | (In millions) |
| Decrease in Gulf Coast operations and maintenance expense primarily related to the timing of planned outages at the Texas coal plants and STP | $ | (66 | ) |
| Decrease in East operations and maintenance expense due to unit deactivations at Huntley, Dunkirk, and Will County | (19 | ) |
| Decrease in West operations and maintenance expense primarily due to the retirement of the El Segundo facility and lower operation and maintenance costs at Encina | (8 | ) |
| Increase in East operations and maintenance expense due to the Joliet conversion project and environmental control work at Midwest Generation, offset by lower variable operating costs due to the decreased generation volumes. | 20 |
|
| Increase in Renewables operating costs due primarily to increased production at the Ivanpah solar plant, Mountain Wind I and II facilities and the Guam solar plant which reached COD in the fourth quarter of 2015 | 9 |
|
| Other | 6 |
|
| | $ | (58 | ) |
| | | | | |
| (In millions) |
| Increase due to the acquisition of Vivint Smart Home | $ | 187 | |
| Increase in retail operation personnel costs primarily driven by an increase in accruals as part of the Company's annual incentive plan reflecting financial outperformance for the year | 48 |
| Increase in major maintenance expenditures associated with the scope and duration of outages at the Texas gas facilities and Cottonwood, partially offset by the Texas coal facilities (excluding W.A. Parish Unit 8 included below) | 21 | |
| Decrease due to the current year partial property insurance claim for the extended outage at W.A. Parish Unit 8, as well as restoration expenses incurred in 2022, partially offset by the prior year Limestone property insurance claim | (124) | |
| Decrease driven by the disposition of STP and Gregory in 2023 | (28) | |
| Decrease in variable operation and maintenance expense due to a reduction in PJM generation volumes in 2023 | (26) | |
| Decrease due to change in estimates of environmental remediation costs at deactivated sites in the East in 2022 | (23) | |
| Decrease driven primarily by East asset retirements, partially offset by an increase in deactivation costs in the West | (8) | |
| Other | (2) | |
| Increase in operations and maintenance expense | $ | 45 | |
Other costCost of operationsOperations
Other Cost of operations are comprised of the following: |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Generation | | Retail | | Renewables | | NRG Yield | | Corporate | | |
| | Gulf Coast | | East/West | | | | | | Total |
| | (In millions) |
| Year Ended December 31, 2016 | $ | 95 |
| | $ | 66 |
| | $ | 93 |
| | $ | 20 |
| | $ | 65 |
| | $ | 1 |
| | $ | 340 |
|
| Year Ended December 31, 2015 | $ | 94 |
| | $ | 74 |
| | $ | 112 |
| | $ | 21 |
| | $ | 72 |
| | $ | — |
| | $ | 373 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Texas | | East | | West/Services/Other | | | | Vivint Smart Home(a) | | Total |
| | | | | |
| Year Ended December 31, 2023 | $ | 243 | | | $ | 131 | | | $ | 13 | | | | | $ | 3 | | | $ | 390 | |
| Year Ended December 31, 2022 | 246 | | | 149 | | | 16 | | | | | — | | | 411 | |
(a) Includes results of operations following the acquisition date of March 10, 2023
Other cost of operations comprised of asset retirement expense, insurance expense and property tax expense, decreased by $33$21 million for the year ended December 31, 2016,2023, compared to the same period in 2015, primarily2022, due to a decrease in gross tax receipts taxes of $10 million related to lower retail revenue and $10 million favorable settlement of Texas sales tax audit.the following:
| | | | | |
| (In millions) |
| Decrease due to changes in current year ARO cost estimates, primarily at Jewett Mine | $ | (28) | |
| Decrease in retail gross receipt taxes due to lower revenue in the East offset by higher revenues in Texas | (10) | |
| Decrease driven by the disposition of STP and Gregory in 2023 | (5) | |
| Increase due to higher property insurance premiums | 18 | |
| Other | 4 | |
| Decrease in other cost of operations | $ | (21) | |
Depreciation and Amortization
Depreciation and amortization expenses are comprised of the following: |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Retail | | Renewables | | NRG Yield | | Corporate | | |
| | Generation | | | | | | Total |
| | (In millions) |
| Year Ended December 31, 2016 | $ | 516 |
| | $ | 111 |
| | $ | 185 |
| | $ | 303 |
| | $ | 57 |
| | $ | 1,172 |
|
| Year Ended December 31, 2015 | $ | 693 |
| | $ | 132 |
| | $ | 176 |
| | $ | 303 |
| | $ | 47 |
| | $ | 1,351 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Texas | | East | | West/Services/Other | | Vivint Smart Home(a) | | Corporate | | Total |
| |
| Year Ended December 31, 2023 | $ | 294 | | | $ | 116 | | | $ | 95 | | | $ | 586 | | | $ | 36 | | | $ | 1,127 | |
| Year Ended December 31, 2022 | 310 | | | 208 | | 85 | | | — | | | 31 | | | 634 | |
(a) Includes results of operations following the acquisition date of March 10, 2023
Depreciation and amortization expense decreasedincreased by $179 million for the year ended December 31, 2016, compared to the same period in 2015, primarily due to a $116 million decrease related to the impairment of the Limestone and W.A. Parish facilities located in the Gulf Coast region in 2015 and a $68 million decrease related to the impairment of the Dunkirk and Huntley facilities located in the East region in 2015.
Impairment Losses
In 2016, the Company recorded impairment losses of $702 million related to various facilities, as well as goodwill for its Texas reporting unit, as further described in Item 15 — Note 10, Asset Impairments and Note 11, Goodwill and Other Intangibles, to the Consolidated Financial Statements.
In 2015, the Company recorded impairment losses of $4,860 million related to various facilities, as well as goodwill for its Texas and Home Solar reporting units, as further described in Item 15 - Note 10, Asset Impairments and Note 11, Goodwill and Other Intangibles, to the Consolidated Financial Statements.
Selling, General and Administrative Expenses
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Generation | | Retail | | Renewables | | NRG Yield | | Corporate | | Total |
| | (In millions) |
| Year Ended December 31, 2016 | $ | 265 |
| | $ | 498 |
| | $ | 61 |
| | $ | 17 |
| | $ | 254 |
| | $ | 1,095 |
|
| Year Ended December 31, 2015 | $ | 159 |
| | $ | 546 |
| | $ | 54 |
| | $ | 15 |
| | $ | 454 |
| | $ | 1,228 |
|
Selling, general and administrative expenses decreased by $133$493 million for the year ended December 31, 20162023, compared to the same period in 2015,2022, 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 decreaseresult of asset impairments and retirements in advertising2022.
Impairment Losses
During the year ended December 31, 2023, the Company recorded impairment losses related to property plant and equipment and leases of $2 million, $4 million and $20 million in the Texas, East and West/Services/Other segments, respectively.
During the year ended December 31, 2022, the Company recorded impairment losses of $206 million, of which $150 million were related to the decline in PJM capacity prices and the continued focus on cost management.near-term retirement date of the Joliet facility, $43 million related to the purchase and sale agreement for the sale of the land and related assets at the Astoria generating site and the planned withdrawal and cancellation of its proposed Astoria redevelopment project, and an additional $13 million in the East segment.
DevelopmentRefer to Item 15 — Note 11, Asset Impairments, to the Consolidated Financial Statements for further discussion.
Selling, General and Administrative Costs
DevelopmentSelling, general and administrative costs decreasedare comprised of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | | Texas | | East | | West/Services/Other | | Vivint Smart Home(a) | | Corporate/ Eliminations | | Total |
| | |
| Year Ended December 31, 2023 | | $ | 637 | | | $ | 573 | | | $ | 202 | | | $ | 499 | | | $ | 57 | | | $ | 1,968 | |
| Year Ended December 31, 2022 | | 559 | | | 428 | | | 202 | | | — | | | 39 | | | 1,228 | |
(a) Includes results of operations following the acquisition date of March 10, 2023
Selling, general and administrative costs increased by $65$740 million for the year ended December 31, 2016,2023 compared to the same period in 2015,2022, due to the strategic decisionfollowing: | | | | | |
| (In millions) |
| Increase due to the acquisition of Vivint Smart Home | $ | 499 | |
| Increase in personnel costs primarily driven by an increase in accruals as part of the Company's annual incentive plan reflecting financial outperformance for the year | 140 | |
| Increase in broker fee and commissions expenses | 49 | |
| Increase in marketing and media expenses | 28 | |
| Increase in consulting and legal expenses | 17 | |
| Other | 7 | |
| Increase in selling, general and administrative costs | $ | 740 | |
Provision for a more focused development program primarily relatedCredit Losses
Provision for credit losses are comprised of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | | Texas | | East | | West/Services/Other | | | | Vivint Smart Home(a) | | Total |
| | |
| Year Ended December 31, 2023 | | $ | 159 | | | $ | 28 | | | $ | 30 | | | | | $ | 34 | | | $ | 251 | |
| Year Ended December 31, 2022 | | (40) | | | 28 | | | 23 | | | | | — | | | 11 | |
(a) Includes results of operations following the acquisition date of March 10, 2023
Provision for credit losses increased by $240 million for the year ended December 31, 2023, compared to Renewablesthe same period in 2022, due to the following:
| | | | | |
| (In millions) |
| Increase due to Winter Storm Uri loss mitigation recognized as income in 2022 | $ | 126 | |
| Increase due to higher Home retail revenues, deteriorated customer payment behavior and the longer duration of the Texas disconnect moratorium in 2023 as compared to 2022 | 80 | |
| Increase due to the acquisition of Vivint Smart Home | 34 | |
| Increase in provision for credit losses | $ | 240 | |
Acquisition-Related Transaction and Integration Costs
Acquisition-related transaction and integration costs were $119 million and $52 million for the sale of EVgo in 2016.years ended December 31, 2023 and 2022, respectively, include:
Loss | | | | | | | | | | | |
| As of December 31, |
| (In millions) | 2023 | | 2022 |
| Vivint Smart Home acquisition costs | $ | 38 | | | $ | 17 | |
| Vivint Smart Home integration costs | 52 | | | — | |
| Other integration costs, primarily related to Direct Energy | 29 | | | 35 | |
| Acquisition-related transaction and integration costs | $ | 119 | | | $ | 52 | |
Gain on Sale of Assets
The gain on sale of assets of $1.6 billion and $52 million recorded for the years ended December 31, 2023 and 2022, respectively, include:
| | | | | | | | | | | |
| As of December 31, |
| (In millions) | 2023 | | 2022 |
| Sale of the Company's 44% equity interest in STP | $ | 1,236 | | | $ | — | |
| Sale of Astoria land and related assets | 199 | | | — | |
| Sale of the Company's 100% ownership in the Gregory natural gas generating facility | 82 | | | — | |
| Sale of the Company's 49% ownership in the Watson natural gas generating facility | — | | | 46 | |
| Sale of land and structures at the Company's deactivated Norwalk Harbor, LLC site | 38 | | | — | |
| Sale of the Company's 50% ownership in Petra Nova | — | | | 22 | |
| Sale of land at the Company's Indian River Power, LLC site | 19 | | | — | |
| Other asset sales | 4 | | | (16) | |
| Gain on sale of assets | $ | 1,578 | | | $ | 52 | |
Impairment Losses on Investments
During the year ended December 31, 2016, the Company sold a majority interest in its EVgo business to Vision Ridge Partners, which resulted in a loss on sale as described in Item 15 — Note 3, Discontinued Operations, Acquisitions and Dispositions, to the Consolidated Financial Statements.
Impairment Losses on Investments
For the year ended December 31, 2016,2023, the Company recorded other-than-temporary impairment losses of $268$102 million which is primarily due to other-than-temporary impairments on the Company's interestsequity method investment in Petra Nova Parish Holdings, Sherbino and Community Wind North,Gladstone generation facility in Queensland, Australia, as further described in Item 15 — Note 10, 11, Asset Impairments,, to the Consolidated Financial Statements.
For the year ended December 31, 2015, the Company recorded other-than-temporary impairment losses on certain of its cost and equity method investments of $56 million, as further described in Item 15 — Note 10, Asset Impairments, to the Consolidated Financial Statements.
LossGain on Debt Extinguishment
A lossgain on debt extinguishment of $142$109 million was recorded for the year ended December 31, 2016, primarily2023, driven by the repurchase of NRG senior notes at a price above par value and the write-offpartial redemption of the unamortized debt issuance costs related3.875% Senior Notes, due 2032, as further discussed in Item 15 — Note 13, Long-term Debt and Finance Leases, to the replacement of the 2018 Term Loan Facility with the new 2023 Term Loan Facility.
Consolidated Financial Statements.
Interest Expense
NRG's interestInterest expense decreasedincreased by $42$250 million for the year ended December 31, 2016,2023, compared to the same period in 2015,2022, primarily due to the following:Vivint Smart Home acquisition including the impact of newly issued Senior Secured First Lien Notes, the acquired debt of Vivint Smart Home, the 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.
|
| | | |
| | (In millions) |
| Decrease due to the repurchases of Senior Notes at the end of 2015 and 2016 | $ | (40 | ) |
| Decrease in derivative interest expense from changes in fair value of interest rate swaps | (19 | ) |
| Decrease due to the redemption of outstanding bonds related to NRG Peakers Finance Company | (8 | ) |
| Decrease due to the termination of Alta X and XI term loans and the related interest rate swaps in 2015 | (6 | ) |
| Increase due to the replacement of the 2018 Term Loan Facility with the 2023 Term Loan Facility | 9 |
|
| Increase due to the issuance of NRG Yield Inc. 3.25% Convertible Senior Notes due 2020 and NRG Yield Operating LLC Revolving Credit Facility issued in 2015 | 8 |
|
| Increase due to the issuance of NRG Yield Operating LLC 5.00% Senior Notes due 2026 | 7 |
|
| Increase due to $200 million of debt issued by CVSR Holdco in August 2016 | 4 |
|
| Other | 3 |
|
| | $ | (42 | ) |
Income Tax Expense
For the year ended December 31, 2016,2023, NRG recorded an income tax expensebenefit of $5$11 million on a pre-tax loss of $978$213 million. For the same period in 2015,2022, NRG recorded an income tax expense of $1,345$442 million on pre-tax lossincome of $4,986 million.$1.7 billion. The effective tax rate was (0.5)%5.2% and (27.0)%26.6% for the years ended December 31, 20162023 and 2015,2022, respectively.
For the year ended December 31, 2016,2023, NRG's overall effective tax rate was differentlower than the federal statutory tax rate of 35%21%, primarily due to recording of apermanent differences and changes in state valuation allowance on the federal and certain state net deferred tax assets that may not be realizable under a “more likely than not” measurement. In addition, a portion of the book goodwill impairment is classified as a permanent reversal impacting the effective tax rate.allowances.
| | | | | | | | | | | |
| | Year Ended December 31, |
| (In millions, except effective income tax rate) | 2023 | | 2022 |
| (Loss)/Income before income taxes | $ | (213) | | | $ | 1,663 | |
| Tax at federal statutory tax rate | (45) | | | 349 | |
| State taxes | (22) | | | 69 | |
| Foreign rate differential | (10) | | | 7 | |
| Changes in state valuation allowances | 42 | | | (3) | |
| Permanent differences | 31 | | | 17 | |
| Recognition of uncertain tax benefits | 12 | | | 8 | |
| Deferred impact of state tax rate changes | 3 | | | 14 | |
| | | |
| Foreign tax refunds | (17) | | | — | |
| | | |
| | | |
| Return to provision adjustments | (5) | | | — | |
| Carbon capture tax credits | — | | | (19) | |
| | | |
| | | |
| | | |
| | | |
| Income tax (benefit)/expense | $ | (11) | | | $ | 442 | |
| Effective income tax rate | 5.2 | % | | 26.6 | % |
|
| | | | | | | |
| | Year Ended December 31, |
| | 2016 | | 2015 |
| | (In millions except as otherwise stated) |
| (Loss) before income taxes | $ | (978 | ) | | $ | (4,986 | ) |
| Tax at 35% | (342 | ) | | (1,745 | ) |
| State taxes | — |
| | (215 | ) |
| Foreign operations | 10 |
| | 1 |
|
| Federal and state tax credits, excluding PTCs | — |
| | (5 | ) |
| Valuation allowance - current period activities | 398 |
| | 3,023 |
|
| Impact of non-taxable entity earnings | 22 |
| | (10 | ) |
| Book goodwill impairment | — |
| | 340 |
|
| Net interest accrued on uncertain tax positions | 1 |
| | (3 | ) |
| Production tax credits | (26 | ) | | (33 | ) |
| Recognition of uncertain tax benefits | 2 |
| | (15 | ) |
| Tax expense attributable to consolidated partnerships | (1 | ) | | 12 |
|
| State rate change including true-up to current period activity | (59 | ) | | (7 | ) |
| Other | — |
| | 2 |
|
| Income tax expense | $ | 5 |
| | $ | 1,345 |
|
| Effective income tax rate | (0.5 | )% | | (27.0 | )% |
The effective income tax rate may vary from period to period depending on, among other factors, the geographic and business mix of earnings and losses and changes in valuation allowances in accordance with ASC 740.740, Income Taxes ("ASC 740"). These factors and others, including the Company's history of pre-tax earnings and losses, are taken into account in assessing the ability to realize deferred tax assets.
Income/(Loss) from Discontinued Operations, Net of Income Tax
For the year ended December 31, 2016, NRG recorded income from discontinued operations, net of income tax (benefit)/expense of $92 million related to GenOn, as further described in Item 15 — Note 3, Discontinued Operations, Acquisitions and Dispositions.
For the year ended December 31, 2015, NRG recorded loss from discontinued operations, net of income tax (benefit)/expense of $105 million related to GenOn, as further described in Item 15 — Note 3, Discontinued Operations, Acquisitions and Dispositions.
Net loss attributable to noncontrolling interests and redeemable noncontrolling interests
Net loss attributable to noncontrolling interests and redeemable noncontrolling interests was $117 million for the year ended December 31, 2016, compared to $54 million for the year ended December 31, 2015. For the years ended December 31, 2016 and 2015, the net losses attributable to noncontrolling interests primarily reflect losses allocated to tax equity investors using the hypothetical liquidation at book value, or HLBV, method, as well as NRG Yield, Inc.'s share of losses for the period.
Liquidity and Capital Resources
Liquidity Position
As of December 31, 20172023 and 2016,2022, NRG's liquidity, excluding collateral funds deposited by counterparties, was approximately $3.2$4.8 billion and $2.4$2.8 billion, respectively, comprised of the following:
| | | | | | | | | | | |
| | As of December 31, |
| (In millions) | 2023 | | 2022 |
| | | |
| Cash and cash equivalents | $ | 541 | | | $ | 430 | |
| Restricted cash - operating | 21 | | | 5 | |
Restricted cash - reserves (a) | 3 | | | 35 | |
| Total | 565 | | | 470 | |
Total availability under Revolving Credit Facility and collective collateral facilities(b) | 4,278 | | | 2,324 | |
| Total liquidity, excluding collateral funds deposited by counterparties | $ | 4,843 | | | $ | 2,794 | |
|
| | | | | | | |
| | As of December 31, |
| | 2017 | | 2016 |
| | (In millions) |
| Cash and cash equivalents: | | |
|
|
| NRG excluding NRG Yield | $ | 843 |
| | $ | 621 |
|
| NRG Yield and subsidiaries | 148 |
| | 317 |
|
| Restricted cash - operating | 71 |
| | 56 |
|
Restricted cash - reserves (a) | 437 |
| | 390 |
|
| Total | 1,499 |
| | 1,384 |
|
| Total credit facility availability | 1,711 |
| | 989 |
|
| Total liquidity, excluding collateral funds deposited by counterparties | $ | 3,210 |
| | $ | 2,373 |
|
| |
(a) | Includes reserves primarily for debt service, performance obligations, and capital expenditures. |
For the year ended (b)Total capacity of Revolving Credit Facility and collective collateral facilities was $7.4 billion and $6.4 billion as of December 31, 2017,2023 and December 31, 2022, respectively
As of December 31, 2023, total liquidity, excluding collateral funds deposited by counterparties, increased by $837 million.$2.0 billion. Changes in cash and cash equivalent balances are further discussed hereinafter under the heading Cash Flow Discussion. Cash and cash equivalents at December 31, 2017,2023, were predominantly held in money market funds invested in treasury securities, treasury repurchase agreements or government agency debt.bank deposits.
Management believes that the Company's liquidity position and cash flows from operations will be adequate to finance operating and maintenance capital expenditures, to fund dividends, to NRG's common stockholders, and to fund other liquidity commitments.commitments in the short and long-term. Management continues to regularly monitor the Company's ability to finance the needs of its operating, financing and investing activity within the dictates of prudent balance sheet management.
On July 12, 2017, NRG announced its Transformation Plan,
The consolidated statement of cash flows includes certain draws from, and payments to, the revolving credit facility and other credit facilities which is described further in Item 1 — Business.are not eligible for net reporting. These transactions are for short term liquidity purposes.
Credit Ratings
On October 6, 2017,March 1, 2023, following the 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 upgradedand Fitch ratings at the NRG rating outlook to positive from stable and affirmed NRG's Ba3 Corporate Family Rating.time.
The following table summarizes the Company's current credit ratings:
| | | | | | | | | | | | | | | | | |
| S&P | | Moody's | | Fitch |
| | | |
| S&P | | Moody's |
| NRG Energy, Inc. | BB-BB Stable | | Ba1 Stable | | Ba3 PositiveBB+ Stable |
6.25%3.75% Senior Notes, due 2022 | BB- | | B1 |
6.25% SeniorSecured Notes, due 2024 | BB-BBB- | | Baa3 | | B1BBB- |
7.25%2.00% Senior Secured Notes, due 20262025 | BB-BBB- | | Baa3 | | B1BBB- |
| 2.45% Senior Secured Notes, due 2027 | BBB- | | Baa3 | | BBB- |
| 6.625% Senior Notes, due 2027 | BB-BB | | Ba2 | | B1BB+ |
| 6.75% Vivint Smart Home Senior Secured Notes, due 2027 | BB | | Ba2 | | n/a |
| 5.75% Senior Notes, due 2028 | BB-BB | | Ba2 | | B1BB+ |
Term Loan Facility, due 2023 | BB+ | | Baa3 |
NRG Yield, Inc. | BB | | Ba2 |
5.375% NRG Yield Operating LLC3.375% Senior Notes, due 20242029 | BB | | Ba2 | | Ba2BB+ |
5.00% NRG Yield Operating LLC4.45% Senior Secured Notes, due 2029 | BBB- | | Baa3 | | BBB- |
5.25% Senior Notes, due 20262029 | BB | | Ba2 | | BB+ |
| 5.75% Vivint Smart Home Senior Notes, due 2029 | B | | Ba3 | | n/a |
| 3.625% Senior Notes, due 2031 | BB | | Ba2 | | BB+ |
| 3.875% Senior Notes, due 2032 | BB | | Ba2 | | BB+ |
| 7.00% Senior Secured Notes, due 2033 | BBB- | | Baa3 | | BBB- |
| Revolving Credit Facility, due 2028 | BBB- | | Baa3 | | BBB- |
| Vivint Smart Home Senior Secured Term Loan, due 2028 | BB | | Ba2 | | n/a |
Sources of Liquidity
The principal sources of liquidity for NRG's future operating and capital expenditures are expected to be derived from cash on hand, cash flows from operations cash proceeds from future sales of assets, including sales to NRG Yield, Inc. and financing arrangements. As described in Item 15 — Note 12, 13, Long-term Debt and CapitalFinance Leases,, to the Consolidated Financial Statements, 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. The Company also issues letters of credit through bilateral letter of credit facilities and the NRG Yield 2019 Convertible Notes, the NRG Yield 2020 Convertible Notes, the Yield Operating 2020 senior unsecured notes, the NRG Yield, Inc. revolvingP-Caps letter of credit facility, and project-related financings.
Sale of Ownership in NRG Yield, Inc. and Renewables Platform
On February 6, 2018, NRG and Global Infrastructure Partners, or GIP, entered into a purchase and sale agreement for GIP to purchase NRG's ownership in NRG Yield, Inc. and NRG's renewables platform for cash of $1.375 billion, subject to certain adjustments. The purchase and sale agreement includes the sale of all of NRG's ownership in NRG Yield, Inc., NRG's renewable energy development and operations platforms and NRG's renewable energy non-ROFO backlog and pipeline.
In connection with the transaction, the Company entered into a Consent and Indemnity Agreement with NRG Yield, Inc. and GIP setting forth key terms and conditions of NRG Yield, Inc.'s consent to the transaction.facility. As part of the Consentacquisition of Vivint Smart Home on March 10, 2023, NRG acquired Vivint Smart Home's existing debt, which includes senior secured notes, senior notes and Indemnity Agreement, NRG has agreeda senior secured term-loan.
The Company's requirements for liquidity and capital resources, other than for operating its facilities, can generally be categorized by the following: (i) market operations activities; (ii) debt service obligations, as described more fully in Item 15 — Note 13, Long-term Debt and Finance Leases, to indemnify GIPthe Consolidated Financial Statements; (iii) capital expenditures, including maintenance, environmental, and NRG Yield, Inc.investments and its project companies for any increaseintegration; and (iv) allocations in property taxes atconnection with acquisition opportunities, debt repayments, share repurchases and dividend payments to stockholders, as described in Item 15 — Note 16, Capital Structure, to the California-based solar projects resulting from the transaction.Consolidated Financial Statements.
The transaction is expectedCompany remains committed to close inmaintaining a strong balance sheet and continues to work to achieve investment grade credit metrics over time primarily through debt reduction and the second halfrealization of 2018 and is subject to various customary closing conditions, approvals and consents. Upon the closing of the transaction, NRG’s Ivanpah asset will no longer be part of the NRG Yield ROFO assets.growth initiatives.
Sale of South Central Businessthe 44% equity interest in STP
On February 6, 2018, NRG and Cleco Energy LLC, or Cleco, entered into a purchase and sale agreement for Cleco to purchase NRG's South Central business for cash of $1.0 billion, subject to certain adjustments. The transaction is expected to close in the second half of 2018 and is subject to various customary closing conditions, approvals and consents. The South Central business owns and operates a 3,555 MW portfolio of generation assets in the Gulf Coast region. Upon the closing of the transaction, NRG will enter into a sale leaseback agreement for the Cottonwood plant through May 2025.
Sale of BETM
On February 23, 2018,November 1, 2023, the Company entered into an agreementclosed on the sale of its 44% equity interest in STP to sell BETM to a third party for $70 million. The transaction is expected to close in the second halfConstellation. Proceeds of 2018 and is subject to various customary closing conditions, approvals and consents.
Sale of Assets to NRG Yield, Inc.
On February 6, 2018, the Company entered into an agreement with NRG Yield, Inc. to sell 100% of the membership interests in Carlsbad Energy Holdings LLC, which owns the Carlsbad project, a 527 MW natural gas fired project in Carlsbad, CA, pursuant to the ROFO Agreement. The purchase price for the transaction is $365 million in cash consideration, subject to customary$1.75 billion were reduced by working capital and other adjustments. The transaction is expected to close during the fourth quarteradjustments of 2018.$96 million, resulting in net proceeds of $1.654 billion.
Sale of Gregory
On January 24, 2018,October 2, 2023, the Company entered into an agreement with NRG Yield, Inc. to sell 100% of its ownership interest in Buckthorn Solar for cash consideration of $42 million, subject to other adjustments. The transaction is expected to close during the first quarter of 2018.
On November 1, 2017, NRG completedclosed on the sale of a 38 MW solar portfolio primarily comprised of assetsits 100% ownership in the Gregory natural gas generating facility in Texas for $102 million.
Debt Reduction
During 2023, the Company reduced its debt by $900 million using funds from SPP funds, in addition to other projects developed by NRG, to NRG Yield, Inc. for cash consideration of $71 million, plus $3from operations. Additionally, the Company redeemed $620 million in working capital adjustments.
On August 1, 2017, NRG closed onaggregate principal amount of its 3.875% Senior Notes, due 2032, for $502 million using a portion of the proceeds from the sale of STP.
The Company intends to spend approximately $500 million reducing debt during 2024 to maintain its targeted credit metrics. The Company intends to fund the remaining 25% interest in NRG Wind TE Holdco, a portfolio of 12 wind projects, to NRG Yield, Inc. for totaldebt reduction from 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.from operations.
Vivint Smart Home Acquisition
On March 27, 2017,10, 2023, the Company sold (i)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 16% interest in the Agua Caliente solar project, representing ownershipcombination 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$740 million in working capital adjustments, and assumed non-recourse projectnewly-issued secured corporate 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 realized interest savings of approximately $9$650 million in 2017newly-issued preferred stock, $900 million drawn from its Revolving Credit Facility and expects approximately $60 million in interest savings over the life of the loan.Receivables Facilities, and cash on hand.
Issuance of 20282033 Senior Notes
On December 7, 2017, NRGMarch 9, 2023, the Company issued $870$740 million of aggregate principal amount at par of 5.75%7.000% senior unsecured notes due 2028.2033. The 20282033 Senior Notes are senior unsecuredsecured obligations of NRG and are guaranteed by certain of its subsidiaries. Interest is paid semi-annually beginning on JulySeptember 15, 2018,2023 until the maturity date of JanuaryMarch 15, 2028. The proceeds from2033. For further discussion, see Note 13,Long-term Debt and Finance Leases.
Series A Preferred Stock
On March 9, 2023, the issuanceCompany issued 650,000 shares of 10.25% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock. For further discussion, see Note 16,Capital Structure.
Revolving Credit Facility
On February 14, 2023, the Company amended its Revolving Credit Facility to: (i) increase the existing revolving commitments thereunder by $600 million, (ii) extend the maturity date of a portion of the revolving commitments thereunder to February 14, 2028, Senior Notes(iii) transition the benchmark rate applicable to revolving loans from LIBOR to SOFR and (iv) make certain other amendments to the terms of the Revolving Credit Facility for purposes of, among other things, providing additional flexibility.
On March 13, 2023, the Company further amended its Revolving Credit Facility to increase the existing revolving commitments by an additional $45 million. As of December 31, 2023, there were utilizedno outstanding borrowings and there were $883 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, redeemamong other things, (i) extend the Company's 6.625% Senior Notes due 2023.scheduled termination date to June 21, 2024, (ii) increase the aggregate commitments from $1.0 billion to $1.4 billion (adjusted seasonally) and (iii) add a new originator. On October 6, 2023, the Receivables Facility was further amended to replace the benchmark interest rate of the Receivable Facility's subordinated note from LIBOR to SOFR. As of December 31, 2023, there were no outstanding borrowings and there were $1.0 billion in letters of credit issued.
Carlsbad Project FinancingIn addition, in connection with the amendments to the Receivables Facility, on June 22, 2023, the Company and the originators thereunder renewed the existing uncommitted Repurchase Facility that provides short-term financing secured by a subordinated note issued by NRG Receivables LLC. Such renewal, among other things, extends the maturity date to June 21, 2024 and joins an additional originator to the Repurchase Facility. On October 6, 2023, the Repurchase Facility was further amended to reflect the concurrent amendment to the Receivables Facility's subordinated note. As of December 31, 2023, there were no outstanding borrowings.
Bilateral Letter of Credit Facilities
On May 26, 2017, Carlsbad Energy Holdings LLC entered into a note payable agreement with financial institutions19, 2023, May 30, 2023 and October 17, 2023 the Company increased the size of its bilateral letter of credit facilities by $25 million, $100 million and $50 million, respectively, to provide additional liquidity, allowing for the issuance of up to $407$850 million of senior secured notes, that bear interest at a rateletters of 4.12%, and mature on October 31, 2038.credit. These facilities are uncommitted. As of December 31, 2017, $4072023, $671 million ofwas issued under these notes were outstanding.facilities.
Also on May 26, 2017, Carlsbad Energy Holdings, LLCPre-CapitalizedTrustSecuritiesFacility
On August 29, 2023, the Company entered into a credit agreement, or the Carlsbad FinancingFacility Agreement with the issuing banks, for a $194Trust, in connection with the sale by the Trust of $500 million construction loan, that will convertP-Caps. The P-Caps are to a term loanbe redeemed by the Trust on July 31, 2028 or earlier upon completionan early redemption of the project.P-Caps Secured Notes. The Carlsbad FinancingP-Caps replaced the Company’s existing pre-capitalized trust securities redeemable 2023 issued by Alexander Funding Trust, which matured on November 15, 2023.
The Facility Agreements allows for the issuance of the P-Caps Secured Notes by the Company to the Trust. In addition, the Company entered into a LC Agreement also includes a letterfor the issuance of letters of credit facility not to exceedin an aggregate amount of $83 million, and a working capital loan facility with an aggregate principal amount not to exceed $4$485 million.
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 proceeds of $212 million, subject to transactions fees of $3 million and certain indemnifications. As part of the transaction, NRG entered into an agreement to lease the land back for the purpose of operating the Astoria gas turbines. Decommissioning was completed in December 2023 and the lease agreement has been terminated.
Pension and Other postretirement benefit contributions
As of December 31, 2017, $202023, the Company’s estimated pension minimum funding requirements for the next 5 years were $142 million, wasof which $43 million are required to be made within the next 12 months. As of December 31, 2023, the Company’s estimated other postretirement benefits minimum funding requirements for the next 5 years were $28 million, of which $6 million are required to be made within the next 12 months. These amounts represent estimates based on assumptions that are subject to change. For further discussion, see Item 15 — Note 15, Benefit Plans and Other Postretirement Benefits, to the Consolidated Financial Statements.
Debt Service Obligations
Principal payments on debt and finance leases as of December 31, 2023, are due in the following periods: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | | | | | | | | | | | | | |
| Description | 2024 | | 2025 | | 2026 | | 2027 | | 2028 | | Thereafter | | Total |
| Recourse Debt: | | | | | | | | | | | | | |
| Senior Notes, due 2027 | $ | — | | | $ | — | | | $ | — | | | $ | 375 | | | $ | — | | | $ | — | | | $ | 375 | |
| Senior Notes, due 2028 | — | | | — | | | — | | | — | | | 821 | | | — | | | 821 | |
| Senior Notes, due 2029 | — | | | — | | | — | | | — | | | — | | | 733 | | | 733 | |
| Senior Notes, due 2029 | — | | | — | | | — | | | — | | | — | | | 500 | | | 500 | |
| Senior Notes, due 2031 | — | | | — | | | — | | | — | | | — | | | 1,030 | | | 1,030 | |
| Senior Notes, due 2032 | — | | | — | | | — | | | — | | | — | | | 480 | | | 480 | |
| Convertible Senior Notes, due 2048 | — | | | — | | | — | | | — | | | — | | | 575 | | | 575 | |
| Senior Secured First Lien Notes, due 2024 | 600 | | | — | | | — | | | — | | | — | | | — | | | 600 | |
| Senior Secured First Lien Notes, due 2025 | — | | | 500 | | | — | | | — | | | — | | | — | | | 500 | |
| Senior Secured First Lien Notes, due 2027 | — | | | — | | | — | | | 900 | | | — | | | — | | | 900 | |
| Senior Secured First Lien Notes, due 2029 | — | | | — | | | — | | | — | | | — | | | 500 | | | 500 | |
| Senior Secured First Lien Notes, due 2033 | — | | | | | | | | | | | 740 | | | 740 | |
| | | | | | | | | | | | | |
| Tax-exempt bonds | — | | | 247 | | | — | | | — | | | 59 | | | 160 | | | 466 | |
| Subtotal Recourse Debt | 600 | | | 747 | | | — | | | 1,275 | | | 880 | | | 4,718 | | | 8,220 | |
| Non-Recourse Debt: | | | | | | | | | | | | | |
| Vivint Smart Home Senior Secured Notes, due 2027 | — | | | — | | | — | | | 600 | | | — | | | — | | | 600 | |
| Vivint Smart Home Senior Notes, due 2029 | — | | | — | | | — | | | — | | | — | | | 800 | | | 800 | |
| Vivint Smart Home Senior Secured Term Loan, due 2028 | 14 | | | 14 | | | 14 | | | 14 | | | 1,264 | | | — | | | 1,320 | |
| Subtotal Vivint Smart Home Non-Recourse Debt | 14 | | | 14 | | | 14 | | | 614 | | | 1,264 | | | 800 | | | 2,720 | |
| Subtotal Debt | 614 | | | 761 | | | 14 | | | 1,889 | | | 2,144 | | | 5,518 | | | 10,940 | |
| Finance Leases: | | | | | | | | | | | | | |
| Finance leases | 6 | | | 8 | | | 2 | | | 1 | | | 1 | | | 1 | | | 19 | |
| | | | | | | | | | | | | |
| Total Debt and Finance Leases | $ | 620 | | | $ | 769 | | | $ | 16 | | | $ | 1,890 | | | $ | 2,145 | | | $ | 5,519 | | | $ | 10,959 | |
| | | | | | | | | | | | | |
| Interest Payments | $ | 609 | | | $ | 595 | | | $ | 587 | | | $ | 521 | | | $ | 403 | | | $ | 806 | | | $ | 3,521 | |
For further discussion, see Item 15 — Note 13, Long-term Debt and Finance Leases.
Market Operations
The Company's market operations activities require a significant amount of liquidity and capital resources. These liquidity requirements are primarily driven by: (i) margin and collateral posted with counterparties; (ii) margin and collateral required to participate in physical markets and commodity exchanges; (iii) timing of disbursements and receipts (e.g. buying power before receiving retail revenues); and (iv) initial collateral for large structured transactions. As of December 31, 2023, market operations had total cash collateral outstanding under the construction loanof $441 million and $29 million$3.1 billion outstanding in letters of credit into third parties primarily to support its market activities. As of the project were issued.
Asset Dispositions
During the year ended December 31, 2017,2023, total funds deposited by counterparties were $84 million in cash and $478 million of letters of credit.
The Company has entered into long-term contractual arrangements related to energy purchases, gas transportation and storage, and fuel and transportation services. As of December 31, 2023, the Company received proceedshad minimum payment obligations under such outstanding agreements of $87$3.4 billion, with $573 million primarily related topayable within the next 12 months and an additional $978 million of short-term purchase energy commitments. For further discussion, see Item 15 — Note 23, Commitments and Contingencies.
saleFuture 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 dependent on the Company's credit ratings and general perception of certain equipment, sale of certain Minnesota wind assets and the sale of theCrawford site.its creditworthiness.
First Lien Structure
NRG has grantedthe capacity to grant first liens to certain counterparties on a substantial portion of the Company's assets, excluding assets acquired in the GenOn and EME (including Midwest Generation) acquisitions, assets held by NRG Yield, Inc. andsubject to various exclusions including NRG's assets that have project-level financing. NRG usesfinancing and the first lien structureassets of certain non-guarantor subsidiaries, to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or 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.agreements. The first lien program limitsdoes not limit the volume that can be hedged notor 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. Within the first lien structure, the Company can hedge up to 80% of its coal and nuclear capacity and 10% of its other assets with these counterparties for the first 60 months and then declining thereafter. Net exposure to a counterparty on all trades must be positively correlated to the price of the relevant commodity for the first lien to be available to that counterparty. The first lien structure is not subject to unwind or termination upon a ratings downgrade of a counterparty and has no stated maturity date.
The Company's first lien counterparties may have a claim on its assets to the extent market prices exceed the hedged prices. As of December 31, 2017,2023, all hedges under the first liens were in-the-money on a counterparty aggregate basis.
The following table summarizes the amount of MW hedged against the Company's coal and nuclear assets and as a percentage relative to the Company's coal and nuclear capacity under the first lien structure as of December 31, 2017:
|
| | | | | | | | | | | |
Equivalent Net Sales Secured by First Lien Structure (a) | 2018 | | 2019 | | 2020 | | 2021 |
| In MW | 719 |
| | — |
| | — |
| | — |
|
As a percentage of total net coal and nuclear capacity (b) | 13 | % | | — | % | | — | % | | — | % |
| |
(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 GenOn and EME (including Midwest Generation) acquisitions, 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) commercial operations activities; (ii) debt service obligations, as described more fully in Item 15 — Note 12, Debt and Capital Leases, to the Consolidated Financial Statements; (iii) capital expenditures, including repowering and renewable development, and environmental; and (iv) allocations in connection with acquisition opportunities, debt repayments, return of capital and dividend payments to stockholders, as described in Item 15 — Note 15, Capital Structure, to the Consolidated Financial Statements.
Restructuring Support Agreement
As described in Note 3, Discontinued Operations, Acquisitions and Dispositions, NRG, the GenOn Entities and certain holders of the GenOn and GenOn Americas Generation Senior Notes entered into a Restructuring Support Agreement that provides for a restructuring and recapitalization of GenOn through a prearranged plan of reorganization. Certain principal terms of the Restructuring Support Agreement include that NRG will provide settlement consideration to GenOn of $261.3 million, which will be paid in cash less any amounts owed to NRG under the intercompany secured revolving credit facility. As of June 30, 2017, GenOn owed NRG approximately $125 million under the intercompany secured revolving credit facility. NRG agreed to provide GenOn with a letter of credit facility during the pendency of the Chapter 11 Cases, to be utilized for required letters of credit in lieu of the intercompany secured revolving credit facility. GenOn can no longer utilize the intercompany secured revolving credit facility and, on July 27, 2017, the letter of credit facility was terminated, as GenOn has obtained a separate letter of credit facility with a third party financial institution. In addition, NRG will retain the pension liability for GenOn employees for service provided prior to the completion of the reorganization. GenOn’s net pension liability as of December 31, 2017, was approximately $92 million. NRG will also retain the liability for GenOn’s post-employment and retiree health and welfare benefits, in an amount up to $25 million, which was recorded as a liability as of December 31, 2017.
Commercial Operations
The Company's commercial operations activities require a significant amount of liquidity and capital resources. These liquidity requirements are primarily driven by: (i) margin and collateral posted with counterparties; (ii) margin and collateral required to participate in physical markets and commodity exchanges; (iii) timing of disbursements and receipts (i.e. buying fuel before receiving energy revenues); (iv) initial collateral for large structured transactions; and (v) collateral for project development. As of December 31, 2017, commercial operations had total cash collateral outstanding of $187 million and $515 million outstanding in letters of credit to third parties primarily to support its commercial activities for both wholesale and retail transactions. As of December 31, 2017, total collateral held from counterparties was $38 million in cash and $17 million of letters of credit.
Future liquidity requirements may change based on the Company's hedging activities and structures, fuel purchases, and future market conditions, including forward prices for energy and fuel and market volatility. In addition, liquidity requirements are dependent on the Company's credit ratings and general perception of its creditworthiness.
2017 Senior Note Redemptions
During the year ended December 31, 2017, the Company redeemed $1.5 billion in aggregate principal of its Senior Notes for $1.5 billion, which included accrued interest of $29 million. In connection with the redemptions, a $49 million loss on debt extinguishment was recorded, which included the write-off of previously deferred financing costs of $7 million. In addition, the Company expects to save approximately $55 million in annualized interest, after consideration of the issuance of the 2028 Senior Note.
|
| | | | | | | | | | |
| | Principal Repurchased | | Cash Paid (a) | | Average Early Redemption Percentage |
| Amount in millions, except rates | | | | | |
7.625% senior notes due 2018 | $ | 398 |
| | $ | 411 |
| | 101.42 | % |
| 7.875% senior notes due 2021 | 206 |
| | 218 |
| | 102.63 | % |
| 6.625% senior notes due 2023 | 869 |
| | 915 |
| | 103.57 | % |
| Total | $ | 1,473 |
| | $ | 1,544 |
| | |
(a) Includes payment for accrued interest.
Debt Service Obligations
Principal payments on debt and capital leases as of December 31, 2017 are due in the following periods:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Description | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | Thereafter | | Total |
| | (In millions) |
| Recourse Debt: | | | | | | | | | | | | | |
| Senior notes, due 2022 | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 992 |
| | $ | — |
| | $ | 992 |
|
| Senior notes, due 2024 | — |
| | — |
| | — |
| | — |
| | — |
| | 733 |
| | 733 |
|
| Senior notes, due 2026 | — |
| | — |
| | — |
| | — |
| | — |
| | 1,000 |
| | 1,000 |
|
| Senior notes, due 2027 | — |
| | — |
| | — |
| | — |
| | — |
| | 1,250 |
| | 1,250 |
|
| Senior notes, due 2028 | — |
| | — |
| | — |
| | — |
| | — |
| | 870 |
| | 870 |
|
| Term loan facility, due 2023 | 19 |
| | 19 |
| | 19 |
| | 19 |
| | 19 |
| | 1,777 |
| | 1,872 |
|
| Tax-exempt bonds | — |
| | — |
| | — |
| | — |
| | — |
| | 465 |
| | 465 |
|
| Subtotal Recourse Debt | 19 |
| | 19 |
| | 19 |
| | 19 |
| | 1,011 |
| | 6,095 |
| | 7,182 |
|
| Non-Recourse Debt: | | | | | | | | | | | | | |
| NRG Yield Operating LLC Senior Notes, due 2024 | — |
| | — |
| | — |
| | — |
| | — |
| | 500 |
| | 500 |
|
| NRG Yield Operating LLC Senior Notes, due 2026 | — |
| | — |
| | — |
| | — |
| | — |
| | 350 |
| | 350 |
|
| NRG Yield Inc. Convertible Senior Notes, due 2019 | — |
| | 345 |
| | — |
| | — |
| | — |
| | — |
| | 345 |
|
| NRG Yield Inc. Convertible Senior Notes, due 2020 | — |
| | — |
| | 288 |
| | — |
| | — |
| | — |
| | 288 |
|
| Yield LLC and Yield Operating LLC Revolving Credit Facility, due 2019 | — |
| | 55 |
| | — |
| | — |
| | — |
| | — |
| | 55 |
|
| El Segundo Energy Center, due 2023 | 48 |
| | 49 |
| | 53 |
| | 57 |
| | 63 |
| | 130 |
| | 400 |
|
| Marsh Landing, due 2023 | 55 |
| | 57 |
| | 60 |
| | 62 |
| | 65 |
| | 19 |
| | 318 |
|
| Alta Wind I-V lease financing arrangements, due 2034 and 2035 | 40 |
| | 42 |
| | 43 |
| | 45 |
| | 47 |
| | 709 |
| | 926 |
|
| Walnut Creek, term loans due 2023 | 45 |
| | 47 |
| | 49 |
| | 52 |
| | 55 |
| | 19 |
| | 267 |
|
| Utah Portfolio, due 2022 | 12 |
| | 13 |
| | 14 |
| | 13 |
| | 226 |
| | — |
| | 278 |
|
| Tapestry, due 2021 | 11 |
| | 11 |
| | 11 |
| | 129 |
| | — |
| | — |
| | 162 |
|
| CVSR, due 2037 | 26 |
| | 24 |
| | 21 |
| | 23 |
| | 25 |
| | 627 |
| | 746 |
|
| CVSR Holdco, due 2037 | 6 |
| | 6 |
| | 6 |
| | 7 |
| | 9 |
| | 160 |
| | 194 |
|
| Alpine, due 2022 | 8 |
| | 8 |
| | 8 |
| | 8 |
| | 103 |
| | — |
| | 135 |
|
| Energy Center Minneapolis, due 2025 and 2031 | 7 |
| | 11 |
| | 11 |
| | 11 |
| | 11 |
| | 157 |
| | 208 |
|
| Viento, due 2023 | 16 |
| | 18 |
| | 15 |
| | 16 |
| | 17 |
| | 81 |
| | 163 |
|
| NRG Yield Other | 32 |
| | 36 |
| | 77 |
| | 32 |
| | 33 |
| | 369 |
| | 579 |
|
Subtotal NRG Yield debt (non-recourse to NRG) (a) | 306 |
| | 722 |
| | 656 |
| | 455 |
| | 654 |
| | 3,121 |
| | 5,914 |
|
| Ivanpah, due 2033 and 2038 | 41 |
| | 42 |
| | 44 |
| | 45 |
| | 47 |
| | 854 |
| | 1,073 |
|
Carlsbad Energy Project (a) | — |
| | 19 |
| | 1 |
| | — |
| | — |
| | 407 |
| | 427 |
|
| Agua Caliente, due 2037 | 32 |
| | 33 |
| | 34 |
| | 35 |
| | 35 |
| | 649 |
| | 818 |
|
| Agua Caliente Borrower 1, due 2038 | 3 |
| | 3 |
| | 3 |
| | 3 |
| | 3 |
| | 74 |
| | 89 |
|
Cedro Hill, due 2029 (a) | 12 |
| | 12 |
| | 12 |
| | 12 |
| | 13 |
| | 90 |
| | 151 |
|
| Midwest Generation, due 2019 | 103 |
| | 49 |
| | — |
| | — |
| | — |
| | — |
| | 152 |
|
NRG Other Renewables (a) | 166 |
| | 24 |
| | 27 |
| | 27 |
| | 83 |
| | 320 |
| | 647 |
|
| NRG Other | 9 |
| | 9 |
| | 9 |
| | 10 |
| | 8 |
| | 135 |
| | 180 |
|
| Subtotal other non-recourse debt | 366 |
| | 191 |
| | 130 |
| | 132 |
| | 189 |
| | 2,529 |
| | 3,537 |
|
| Subtotal all non-recourse debt | 672 |
| | 913 |
| | 786 |
| | 587 |
| | 843 |
| | 5,650 |
| | 9,451 |
|
| Subtotal long-term debt | 691 |
| | 932 |
| | 805 |
| | 606 |
| | 1,854 |
| | 11,745 |
| | 16,633 |
|
| Capital Leases: | | | | | | | | | | | | |
|
| Capital leases | 4 |
| | 1 |
| | — |
| | — |
| | — |
| | — |
| | 5 |
|
| Subtotal Capital Leases | 4 |
| | 1 |
| | — |
| | — |
| | — |
| | — |
| | 5 |
|
| Total Debt and Capital Leases | $ | 695 |
| | $ | 933 |
| | $ | 805 |
| | $ | 606 |
| | $ | 1,854 |
| | $ | 11,745 |
| | $ | 16,638 |
|
| |
(a) | Debt associated with the asset sales announced in February 2018. |
In addition to the debt and capital leases shown in the above table, NRG had issued $733 million of letters of credit under the Company's $2.5 billion Revolving Credit Facility as of December 31, 2017.
Capital Expenditures
The following table and descriptions summarizesummarizes the Company's capital expenditures for maintenance, environmental and growth investments for the year ended December 31, 2017,2023:
| | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Maintenance | | Environmental | | Investments and Integration | | Total |
| Texas | $ | 455 | | | $ | 3 | | | $ | 37 | | | $ | 495 | |
| East | 4 | | | — | | | 1 | | | 5 | |
| West/Services/Other | 21 | | | — | | | 6 | | | 27 | |
Vivint Smart Home(a) | 17 | | | — | | | 1 | | | 18 | |
| Corporate | 19 | | | — | | | 34 | | | 53 | |
| Total cash capital expenditures for 2023 | 516 | | | 3 | | | 79 | | | 598 | |
| Integration operating expenses and cost to achieve | — | | | — | | | 81 | | | 81 | |
| Investments | — | | | — | | | 164 | | | 164 | |
| Total cash capital expenditures and investments for the year ended December 31, 2023 | $ | 516 | | | $ | 3 | | | $ | 324 | | | $ | 843 | |
(a)Includes expenditures following the acquisition date of March 10, 2023
Investments and the estimated capital expenditure and growth investments forecastIntegration for2018.
|
| | | | | | | | | | | | | | | |
| | Maintenance | | Environmental | | Growth Investments | | Total |
| | (In millions) |
| Generation | | | | | | | |
| Gulf Coast | $ | 95 |
| | $ | 1 |
| | $ | 4 |
| | $ | 100 |
|
East/West (a) | 22 |
| | 24 |
| | 321 |
| | 367 |
|
| Retail | 29 |
| | — |
| | 52 |
| | 81 |
|
| Renewables | 5 |
| | — |
| | 506 |
| | 511 |
|
| NRG Yield | 27 |
| | — |
| | 4 |
| | 31 |
|
| Corporate | 15 |
| | — |
| | 6 |
| | 21 |
|
Total cash capital expenditures for the year ended December 31, 2017 | 193 |
| | 25 |
| | 893 |
| | 1,111 |
|
| Funding from debt financing, net of fees | — |
| | — |
| | (1,076 | ) | | (1,076 | ) |
Other investments(b) | — |
| | — |
| | 267 |
| | 267 |
|
| Total capital expenditures and investments, net of financings | $ | 193 |
| | $ | 25 |
| | $ | 84 |
| | $ | 302 |
|
| | | | | | | | |
Estimated capital expenditures for 2018 (c) | $ | 221 |
| | $ | 3 |
| | $ | 500 |
| | $ | 724 |
|
| Funding from debt financing, net of fees | — |
| | — |
| | (391 | ) | | (391 | ) |
Other investments(b) | — |
| | — |
| | 86 |
| | 86 |
|
| Estimated capital expenditures for 2018, net of financings | $ | 221 |
| | $ | 3 |
| | $ | 195 |
| | $ | 419 |
|
(a) Includes International
(b) Other investments include restricted cash activity and acquisitions
(c) Maintenance capital expenditures includes approximately $66 million related to announced asset sales
Environmental capital expenditures — For the year ended December 31, 2017, the Company's environmental capital2023, include growth expenditures, included the final payments for 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 year ended December 31, 2017, the Company's growth investment capital expenditures included $414 million for solar projects, $324 million for repowering projects, $93 million for wind projects, and $62 million for the Company's other growth projects.
Environmental Capital Expenditures Estimate
NRG estimates that environmental capital expenditures from 20182024 through 20222028 required to comply with environmental laws will be approximately $82 million, which includes $14 million for Midwest Generation. These costs are primarily associated with$66 million. The largest component is the cost of complying with anticipated CCR requirements and NOx Controls.
ELG at the Company's coal units in Texas.
The table below summarizes the status of NRG's coal fleet with respect to air quality controls. Planned investments are either in construction or budgeted in the existing capital expenditures budget. Changes to regulations could result in changes to planned installation dates. NRG uses an integrated approach to fuels, controls and emissions markets to meet environmental standards.requirements.
|
| | | | | | | | | | | | | | | | | | |
| | | | | SO2 | | NOx | | Mercury | | Particulate |
| Units | | State | | Control Equipment | | Install Date | | Control Equipment | | Install Date | | Control Equipment | | Install Date | | Control Equipment | | Install Date |
| Big Cajun II 1 | | LA | | DSI | | 2015 | | LNBOFA/ SNCR | | 2005/2014 | | ACI | | 2015 | | ESP/upgrade | | 1981/2015 |
| Big Cajun II 2 | | LA | | Gas Conversion | | 2015 | | LNBOFA/ SNCR | | 2004/2014 | | Gas Conversion | | 2015 | | Gas Conversion | | 2015 |
| Big Cajun II 3 | | LA | | PAL | | 2013 | | LNBOFA/ SNCR | | 2002/2014 | | ACI | | 2015 | | ESP/upgrade | | 1983/2015 |
| Conemaugh 1-2 | | PA | | FGD | | 1994, 95 | | SCR | | 2014 | | FGD/ESP/SCR | | 1994,95/ 2014 | | ESP | | 1970, 1971 |
| Indian River 4 | | DE | | CDS | | 2011 | | LNBOFA/SCR | | 1999/2011 | | ACI/CDS/FF | | 2008/2011 | | ESP/FF | | 1980/2011 |
| Keystone 1-2 | | PA | | FGD | | 2009 | | SCR | | 2003 | | FGD/ESP/SCR | | 2003 | | ESP | | 1967, 1968 |
| Limestone 1-2 | | TX | | FGD | | 1985-86 | | LNBOFA | | 2002/2022 | | ACI | | 2015 | | ESP | | 1985-1986 |
| Powerton 5 | | IL | | DSI | | 2016 | | OFA/SNCR | | 2003/2012 | | ACI | | 2009 | | ESP/upgrade | | 1973/2016 |
| Powerton 6 | | IL | | DSI | | 2014 | | OFA/SNCR | | 2002/2012 | | ACI | | 2009 | | ESP/upgrade | | 1976/2014 |
| W.A. Parish 5, 6, 7 | | TX | | FF co-benefit | | 1988 | | SCR | | 2004 | | ACI | | 2015 | | FF | | 1988 |
W.A. Parish 8(a) | | TX | | FGD | | 1982 | | SCR | | 2004 | | ACI | | 2015 | | FF | | 1988 |
| Waukegan 7 | | IL | | DSI | | 2014 | | LNBOFA | | 2002 | | ACI | | 2008 | | ESP/upgrade | | 1958/2002, 2014 |
| Waukegan 8 | | IL | | DSI | | 2015 | | LNBOFA | | 1999 | | ACI | | 2008 | | ESP/upgrade | | 1962/1999, 2015 |
| Will County 4 | | IL | | DSI | | 2017 | | LNBOFA/SNCR | | 1999,2001/ 2012 | | ACI | | 2009 | | ESP/upgrade | | 1963,72/ 2000 |
(a) Unit expected to be converted into a cogeneration facility to provide power and steam to the Petra Nova CCF.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | SO2 | | NOx | | Mercury | | Particulate |
| Units | | State | | Control Equipment | | Install Date | | Control Equipment | | Install Date | | Control Equipment | | Install Date | | Control Equipment | | Install Date |
| Indian River 4 | | DE | | CDS | | 2011 | | LNBOFA/SCR | | 1999/2011 | | ACI/CDS/FF | | 2008/2011 | | ESP/FF | | 1980/2011 |
| | | | | | | | | | | | | | | | | | |
| Limestone 1-2 | | TX | | FGD | | 1985-86 | | LNBOFA | | 2002/2003 | | ACI | | 2015 | | ESP | | 1985-1986 |
| Powerton 5 | | IL | | DSI | | 2016 | | OFA/SNCR | | 2003/2012 | | ACI | | 2009 | | ESP/upgrade | | 1973/2016 |
| Powerton 6 | | IL | | DSI | | 2014 | | OFA/SNCR | | 2002/2012 | | ACI | | 2009 | | ESP/upgrade | | 1976/2014 |
| W.A. Parish 5, 6, 7 | | TX | | FF co-benefit | | 1988 | | SCR | | 2004 | | ACI | | 2015 | | FF | | 1988 |
| W.A. Parish 8 | | TX | | FGD | | 1982 | | SCR | | 2004 | | ACI | | 2015 | | FF | | 1988 |
|
| | | | |
ACI - Activated Carbon Injection CDS - Circulating Dry Scrubber DSI - Dry Sorbent Injection with Trona ESP - Electrostatic Precipitator FGD - Flue Gas Desulfurization (wet)
| FF- Fabric Filter | LNBOFA - Low NOx Burner with Overfire Air OFA - Overfire Air PAL - Plantwide Applicability Limit
SCR - Selective Catalytic Reduction SNCR - Selective Non-Catalytic Reduction |
The following table summarizes the estimated environmental capital expenditures for the referenced periods by region:year:
| | | | | | | | | | | | | | |
| (In millions) | | | | | | | | Total |
| 2024 | | | | | | | | $ | 28 | |
| 2025 | | | | | | | | 26 | |
| | | | | | | | |
| | | | | | | | |
| Thereafter | | | | | | | | 12 | |
| Total | | | | | | | | $ | 66 | |
|
| | | | | | | | | | | | | | | |
| | Gulf Coast | | East (excluding MWG) | | MWG | | Total |
| | (In millions) |
| 2018 | $ | — |
| | $ | 3 |
| | $ | — |
| | $ | 3 |
|
| 2019 | 7 |
| | 2 |
| | 1 |
| | 10 |
|
| 2020 | 4 |
| | — |
| | 7 |
| | 11 |
|
| 2021 | 3 |
| | 23 |
| | 6 |
| | 32 |
|
| 2022 | 7 |
| | 19 |
| | — |
| | 26 |
|
| Total | $ | 21 |
| | $ | 47 |
| | $ | 14 |
| | $ | 82 |
|
NRG's current contracts with the Company's rural electrical customers in the Gulf Coast region allow for recovery of a portion of the region's capital costs once in operation, along with a capital return incurred by complying with any change in law, including interest over the asset life of the required expenditures. The actual recoveries will depend, among other things, on the timing of the completion of the capital projects and the remaining duration of the contracts.
Common Stock Dividends
The following table lists the dividends paid during 2017:
|
| | | | | | | | | | | | | | | |
| | Fourth Quarter 2017 | | Third Quarter 2017 | | Second Quarter 2017 | | First Quarter 2017 |
| Dividends per Common Share | $ | 0.030 |
| | $ | 0.030 |
| | $ | 0.030 |
| | $ | 0.030 |
|
On January 19, 2018, NRG declared a quarterly dividend on the Company's common stock of $0.03 per share, or $0.12 per share on an annualized basis, payable on February 15, 2018, to stockholders of record as of February 1, 2018. The Company's common stock dividends are subject to available capital, market conditions, and compliance with associated laws and regulations. The Company expects that, based on current circumstances, comparable cash dividends will continue to be paid in the foreseeable future.
Share Repurchases
The Company’s boardIn June 2023, NRG revised its long-term capital allocation policy to target allocating approximately 80% of directors has authorizedcash 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.
On November 6, 2023, the Company executed Accelerated Share Repurchase agreements to repurchase a total of up to $1$950 million of NRG's outstanding common stock. Under the ASR, the Company paid a total of $950 million and will receive shares of NRG's common stock on specified settlement dates.
During the year ended December 31, 2023, the Company completed $1.2 billion of share repurchases, including the $950 million ASR and $200 million of open market repurchases, under the $2.7 billion authorization. See Item 15 - Note 16, Capital Structure, to the Consolidated Financial Statements for additional discussion.
Dividend Increase on Common Stock
In the first quarter of 2023, NRG increased the annual dividend on its common stock to $1.51 from $1.40 per share. The Company returned $352 million of capital to shareholders in the year ended 2023 through a $1.51 dividend per common share. In 2024, NRG further increased the annual dividend to $1.63 per share, representing an 8% increase from 2023. The Company expects to target an annual dividend growth rate of 7-9% per share in subsequent years.
On January 19, 2024, NRG declared a quarterly dividend on the Company's common stock of $0.4075 per share, or $1.63 per share on an annualized basis, payable on February 15, 2024, to stockholders of record as of February 1, 2024. The Company's common stock dividends are subject to available capital, market conditions, and compliance with associated laws and regulations.
Series A Preferred Stock Dividends
In September 2023, the first $500Company declared and paid a semi-annual dividend of $52.96 per share on its outstanding Series A Preferred Stock, totaling $34 million. Cumulative cash dividends on the Series A Preferred Stock are payable semiannually, in arrears, on each March 15 and September 15, when, as and if declared by the Board of Directors.
Additional Material Cash Requirements Not Discussed Above
Operating leases —The Company leases generating facilities, land, office and equipment, railcars, fleet vehicles and storefront space at retail stores. As of December 31, 2023, the Company had lease payment obligations of $311 million, program to begin inof which $118 million is payable within the first quarternext 12 months. For further discussion, see Item 15 — Note 10, Leases.
Other liabilities — Other liabilities includes water right agreements, service and maintenance agreements, stadium naming rights, stadium sponsorships, long-term service agreements and other contractual obligations. As of 2018. Following completionDecember 31, 2023, the Company had total of $213 million under such commitments,of which $40 million are payable within the next 12 months.
Contingent obligations for guarantees — NRG and its subsidiaries enter into various contracts that include indemnifications and guarantee provisions as a routine part of the initial program,Company’s business activities. For further discussion, see Item 15 —Note 27, Guarantees.
Obligations Arising Out of a Variable Interest in an Unconsolidated Entity
Variable interest in Equity investments — NRG's investment in Ivanpah is a variable interest entity for which NRG is not the primary beneficiary. See also Item 15 — Note 17, Investments Accounted for by the Equity Method and as NRG progresses towards the closing of the announced asset sales, the Company expects to execute the remaining $500 million of the $1 billion share repurchase program.
Fuel Repowerings
Carlsbad —The Company is currently overseeing construction of the Carlsbad project, which when completed will consist of approximately 527 MWs of net generation capacity. On February 6, 2018, the Company entered into an agreement with NRG Yield, Inc. to sell the Carlsbad project pursuantVariable Interest Entities, to the ROFO Agreement. The transaction is expected to close duringConsolidated Financial Statements for additional discussion. NRG's pro-rata share of non-recourse debt was approximately $461 million as of December 31, 2023. This indebtedness may restrict the fourth quarterability of 2018.
Canal 3 — The Company is currently overseeing construction of the Canal 3 project, a dual-fueled peaking facility, which when completed will consist of approximately 333 MWs of net generating capacity. In January 2018, Final Notice To Proceed was issued, and construction commenced with an anticipated COD by summer 2019. Under a cooperation agreement with GenOn, GenOn has the right to purchase the project from NRG until March 31, 2018.
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 intentionIvanpah to issue a proposed decision that would deny a permit for the Puente Power Project. On October 16, 2017, NRG filed a motiondividends or distributions to suspend the permitting proceeding for at least six months, which was granted on November 3, 2017. During the six month suspension period, which could be extended, NRG will evaluate the progress of a procurement process initiated by SCE to replace the Puente Power Project.NRG.
Cash Flow Discussion
20172023 compared to 20162022
The following table reflects the changes in cash flows for the comparative years:
| | | | | | | | | | | | | | | | | |
| Year ended December 31, | | |
| (In millions) | 2023 | | 2022 | | Change |
| Cash (used)/provided by operating activities | $ | (221) | | | $ | 360 | | | $ | (581) | |
| Cash used by investing activities | (910) | | | (332) | | | (578) | |
| Cash (used)/provided by financing activities | (400) | | | 1,043 | | | (1,443) | |
|
| | | | | | | | | | | |
| | Year ended December 31, |
| (In millions) | 2017 | | 2016 | | Change |
| Net cash provided by operating activities | $ | 1,387 |
| | $ | 2,088 |
| | $ | (701 | ) |
| Net cash used by investing activities | (1,066 | ) | | (792 | ) | | (274 | ) |
| Net cash used by financing activities | (485 | ) | | (915 | ) | | 430 |
|
Net Cash Provided By Operating Activities
Changes to net cash (used)/provided by operating activities were driven by: | | | | | |
| (In millions) |
| Increase in operating income adjusted for other non-cash items | $ | 2,892 | |
| Changes in cash collateral in support of risk management activities due to change in commodity prices | (2,702) | |
| Decrease due to receipt of uplift securitization proceeds from ERCOT in 2022 | (689) | |
| Decrease in working capital primarily driven by Vivint Smart Home capitalized contract costs partially offset by deferred revenues | (361) | |
| Increase in working capital related to accrued personnel costs primarily due to the Company's annual incentive plan reflecting financial outperformance for 2023 | 188 | |
| Increase in working capital related to accounts receivable and inventory primarily due to lower gas and power market pricing coupled with lower gas volumes, partially offset by a decrease in accounts payable | 91 | |
| |
| |
| |
| |
| |
| |
| |
| |
| |
| |
| $ | (581) | |
|
| | | |
| | (In millions) |
| Changes in cash collateral in support of risk management activities due to changes in commodity prices | $ | (478 | ) |
| Other changes in working capital | (284 | ) |
| Decrease in operating income adjusted for non-cash items | (172 | ) |
| Increase in accounts receivable due to the timing of cash receipts | (92 | ) |
| Decrease in prepaid expenses and total current assets due to reduced spending | 56 |
|
| Decrease in inventory as a result of initiatives related to the Transformation Plan | 72 |
|
| Cash provided by discontinued operations | 81 |
|
| Increase in accounts payable as a result of initiatives related to the Transformation Plan | 116 |
|
| | $ | (701 | ) |
Net Cash Used By Investing Activitiesused by investing activities
Changes to net cash used(used)/provided by investing activities were driven by:
| | | | | |
| (In millions) |
| Increase in cash paid for acquisitions primarily due to the acquisition of Vivint Smart Home in March 2023 | $ | (2,461) | |
| Increase in proceeds from the sale of assets primarily due to the sale of the Company's 44% equity interest in STP in November 2023 | 1,898 | |
| Increase from insurance proceeds for property, plant and equipment, net, in 2023 | 240 | |
| Increase in capital expenditures | (231) | |
| Decrease in proceeds from sales of emissions allowances, net of purchases | (18) | |
| Increase due to fewer purchases of investments in nuclear decommissioning trust fund securities, net of sales | (6) | |
| |
| |
| |
| |
| |
| |
| $ | (578) | |
|
| | | |
| | (In millions) |
| Change in discontinued operations cash primarily related to the sale of the Aurora, Shelby and Seward in 2016 | $ | (350 | ) |
| Decrease in capital expenditures related to environmental projects at Powerton and Joliet, as well as a decrease in maintenance capital expense in our generation businesses, offset by an increase in growth capital expenditures related to our solar and repowering projects | (135 | ) |
| Decrease in cash grants received in 2017 | (28 | ) |
| Increase in other investments | (17 | ) |
| Increase in investments in unconsolidated affiliates related primarily to investments in the utility-scale solar portfolio | (17 | ) |
| Other | (6 | ) |
| Proceeds from sale of assets | 14 |
|
| Net increase in nuclear decommissioning trust fund activity due to a decrease in purchases of securities | 30 |
|
| Proceeds from sale of emissions allowances | 67 |
|
| Decrease in cash paid for acquisitions in 2017 compared to 2016 primarily due to acquisition of assets from SunEdison in 2016 | 168 |
|
| | |
| | $ | (274 | ) |
Net Cash Used By Financing Activities(used)/provided by financing activities
Changes in net cash used(used)/provided by financing activities were driven by:
| | | | | |
| (In millions) |
| Decrease in net receipts from settlement of acquired derivatives | $ | (1,653) | |
| Increase in proceeds from issuance of long-term debt in 2023 | 731 | |
| Increase in proceeds from issuance of preferred stock in 2023 | 635 | |
| Increase in share repurchase activity | (566) | |
| Increase of repayments of long-term debt and finance leases | (518) | |
| Increase in payments of dividends primarily due to preferred stock issued in 2023 | (49) | |
| Increase in payments of deferred issuance costs | (23) | |
| |
| |
| |
| |
| |
| |
| |
| |
| $ | (1,443) | |
|
| | | |
| | (In millions) |
| Net decrease in borrowings, 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 as compared to 2017 | $ | 303 |
|
| Increase in cash contributions, net of distributions from noncontrolling interest primarily due to tax equity financing | 251 |
|
| Change due to repurchase of preferred stock in 2016 | 226 |
|
| Decrease in debt extinguishment costs due to fewer debt repurchases in 2017 as compared to 2016 | 79 |
|
| Decrease in payment of dividends, due to the annualized dividend rate being reduced from $0.58/share to $0.12/share in the first quarter of 2016 | 38 |
|
| Change in debt issuance costs is primarily due to the refinancing of the senior credit facility and the issuance of the 2026 and 2027 Senior Notes in 2016 | 26 |
|
| Payment for affiliate receivable - GenOn | (125 | ) |
| Change in discontinued operations cash related to an increase in long term deposits and financing fees in 2017 | (364 | ) |
| Other | (4 | ) |
| | $ | 430 |
|
2016 compared to 2015
The following table reflects the changes in cash flows for the comparative years:
|
| | | | | | | | | | | |
| | Year ended December 31, |
| (In millions) | 2016 | | 2015 | | Change |
| Net cash provided by operating activities | $ | 2,088 |
| | $ | 1,349 |
| | $ | 739 |
|
| Net cash used by investing activities | (792 | ) | | (1,528 | ) | | 736 |
|
| Net cash used by financing activities | (915 | ) | | (432 | ) | | (483 | ) |
Net Cash Provided By Operating Activities
Changes to net cash provided by operating activities were driven by:
|
| | | |
| | (In millions) |
| Change in cash collateral in support of risk management activities | $ | 766 |
|
| Decrease in accounts payable primarily related to lower operations and maintenance expense in 2016 | 141 |
|
| Decrease in inventory primarily related to plant fuel conversions at Joliet and Unit 2 at the Big Cajun II facility and deactivations of the Huntley and Dunkirk facilities | 130 |
|
| Other changes in working capital driven by various timing differences | 54 |
|
| Cash used by discontinued operations | (181 | ) |
| Increase in accounts receivable due to timing of receipts | (120 | ) |
| Decrease in accrued interest primarily driven by redemption of Senior Notes in late 2015 and 2016 | (27 | ) |
| Increase in prepaid expense primarily related to timing of property tax and insurance payments that occurred in the first half of the year, and state tax receivables | (23 | ) |
| Decrease in operating income adjusted for non-cash items | (1 | ) |
| | $ | 739 |
|
Net Cash Used By Investing Activities
Changes to net cash used by investing activities were driven by:
|
| | | |
| | (In millions) |
| Cash provided by discontinued operations | $ | 556 |
|
| Decrease in investments in unconsolidated affiliates in 2016 compared to 2015, primarily related to the 25% investment in Desert Sunlight of $285 million, as well as, Petra Nova and Altenex in 2015 | 361 |
|
| Proceeds from the sale of assets related to the majority interest sale of EVgo and the sale of real property at the Potrero generating station in 2016 | 72 |
|
| Decrease in capital expenditures, primarily related to environmental projects at the Powerton and Joliet facilities | 53 |
|
| Insurance proceeds primarily related to the Cottonwood generation station outage in 2016 | 27 |
|
| Increase in cash paid for acquisitions in 2016 compared to 2015 | (178 | ) |
| Decrease in cash grants received as the final Ivanpah cash grant amount was received in 2015 after resolution of all open inquiries | (46 | ) |
| Net decrease in nuclear decommissioning trust fund activity due to increase in purchases of securities in Q4 2016 | (43 | ) |
| Net decrease in emission allowances activity | (42 | ) |
| Other | (24 | ) |
| | $ | 736 |
|
Net Cash Used By Financing Activities
Changes in net cash used by financing activities were driven by:
|
| | | |
| | (In millions) |
| Repurchases of treasury stock in 2015 | $ | 437 |
|
| Cash provided by discontinued operations | 195 |
|
| Decrease in payment of dividends which reflects the reduction to the annualized dividend rate in 2016 from $0.58/share to $0.12/share | 125 |
|
| Decrease in cash contributions from noncontrolling interest in 2016, primarily related to the NRG Yield, Inc. public offering in 2015 which had proceeds of $599 million | (803 | ) |
| Repurchase of preferred stock in 2016 | (226 | ) |
| Increase in debt extinguishment costs | (121 | ) |
| Increase in debt issuance costs primarily due to the refinancing of the senior credit facility and the issuance of the 2026 and 2027 Senior Notes | (68 | ) |
| Net decrease in borrowings, offset by debt payments, which includes debt repurchases in 2016 | (23 | ) |
| Decrease in settlement of financing element related to acquired derivatives | (8 | ) |
| Other | 9 |
|
| | $ | (483 | ) |
NOLs, Deferred Tax Assets and Uncertain Tax Position Implications under ASC 740
As of For the year ended December 31, 2017,2023, the Company had domestic pre-tax book lossincome of $1,557$261 million and foreign pre-tax book incomeloss of $17$474 million. For the year ended December 31, 2017,2023, the Company generated an NOLutilized U.S. federal NOLs of $630 million due to a current year taxable loss.$1.9 billion, and tax credits of $73 million. As of December 31, 2017,2023, the Company has cumulative domesticU.S. federal NOL carryforwards of $2.8$8.4 billion, of which will begin expiring in 2026$6.4 billion do not have an expiration date, and cumulative state NOL carryforwards of $2.2$6.4 billion for financial statement purposes. In addition, NRG also has cumulative foreign NOL carryforwards of $224$411 million, most of which do not have anno expiration date. In addition to the above NOLs, NRG has a $517 million indefinite carryforward for interest deductions, as well as $317 million of tax credits to be utilized in future years. As a result of the Company's tax position, including the benefitutilization of a worthless stock deduction of $9.5 billion upon GenOn emerging from bankruptcyfederal and upon evaluation of the Tax Cuts and Jobs Act potential impact on taxable incomestate NOLs, and based on current forecasts, the Company anticipates income tax payments, primarily due to federal, state and localforeign jurisdictions, of up to $20$160 million in 2018.2024. There is no impact on the Company's provision for income taxes from the CAMT for the year ended December 31, 2023.
The Company has recorded a long term receivable of $64 million representing refundable alternative minimum tax credits from the IRS, net of sequestration, which are anticipated to be received from 2019 through 2022 pursuant to the 50% annual limitation as enacted by the Tax Act upon repeal of corporate AMT effective January 1, 2018.
In addition to these amounts, the Company has $30$73 million of tax effected uncertain federal, state and foreign tax benefits for which the Company has recorded a non-current tax liability of $33$76 million (inclusive of accrued interest) until such final resolution with the related taxing authority. The $33 million non-current tax liability for uncertain tax benefits is from positions taken on various state returns, including accrued interest.
The Company is no longer subject to U.S. federal income tax examinations for years prior to 2015.2020. With few exceptions, state and localCanadian income tax examinations are no longer open for years before 2010.2015.
Off-Balance Sheet Arrangements
Obligations under Certain Guarantee ContractsGuarantor Financial Information
As of December 31, 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 13, 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 certainderives much of its income from its subsidiaries. Therefore, the Company's ability to make required payments with respect to its indebtedness and other obligations depends on the financial results and condition of its subsidiaries enter intoand NRG's ability to receive funds from its subsidiaries. There are no restrictions on the ability of any of the Guarantors to transfer funds to NRG. Other subsidiaries of the Company do not guarantee arrangementsthe registered
debt securities of either NRG Energy, Inc. or the Guarantors (such subsidiaries are referred to as the “Non-Guarantors”). The Non-Guarantors include all of NRG's foreign subsidiaries and certain domestic subsidiaries.
The tables below present summarized financial information of NRG Energy, Inc. and the Guarantors in accordance with Rule 3-10 under the normal courseSEC's Regulation S-X. The financial information may not necessarily be indicative of business to facilitate commercialresults of operations or financial position of NRG Energy, Inc. and the Guarantors in accordance with U.S. GAAP.
The following table presents the summarized statement of operations:
| | | | | | | |
| (In millions) | For the Year Ended December 31, 2023 | | |
Revenue(a) | $ | 24,202 | | | |
Operating income(b) | 600 | | | |
| Total other expense | (286) | | | |
| Income before income taxes | 314 | | | |
| Net Income | 182 | | | |
(a)Intercompany transactions with third parties. These arrangementsNon-Guarantors include financial and performance guarantees, stand-by lettersrevenue of credit, debt guarantees, surety bonds and indemnifications. See also Item 15 — Note 26, Guarantees, to$9 million during the Consolidated Financial Statements for additional discussion.
Retained or Contingent Interests
NRG does not have any material retained or contingent interests in assets transferred to an unconsolidated entity.
Obligations Arising Out of a Variable Interest in an Unconsolidated Entity
Variable interest in Equity investments — As of year ended December 31, 2017, NRG has several investments2023
(b)Intercompany transactions with an ownership interest percentageNon-Guarantors including cost of 50% or less in energyoperations of $50 million and energy-related entities that are accounted for underselling, general and administrative of $209 million during the equity methodyear ended December 31, 2023
The following table presents the summarized balance sheet information:
| | | | | | | |
| (In millions) | December 31, 2023 | | |
Current assets(a) | $ | 7,239 | | | |
| Property, plant and equipment, net | 1,217 | | | |
| Non-current assets | 11,843 | | | |
Current liabilities(b) | 7,997 | | | |
| Non-current liabilities | 9,706 | | | |
(a)Includes intercompany receivables due from Non-Guarantors of accounting. Several of these investments are variable interest entities for which NRG is not the primary beneficiary.
NRG's pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $606$92 million as of December 31, 2017. This indebtedness may restrict the ability2023
(b)Includes intercompany payables due to Non-Guarantors of these subsidiaries to issue dividends or distributions to NRG. See also Item 15 — Note 16, Investments Accounted for by the Equity Method and Variable Interest Entities, to the Consolidated Financial Statements for additional discussion.$4 million as of December 31, 2023
Contractual Obligations and Commercial Commitments
NRG has a variety of contractual obligations and other commercial commitments that represent prospective cash requirements in addition to the Company's capital expenditure programs. The following tables summarize NRG's contractual obligations and contingent obligations for guarantees. See also Item 15 — Note 12, Debt and Capital Leases, Note 22, Commitments and Contingencies, and Note 26, Guarantees, to the Consolidated Financial Statements for additional discussion.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | By Remaining Maturity at December 31, |
| | 2017 | | |
| Contractual Cash Obligations | Under 1 Year | | 1-3 Years | | 3-5 Years | | Over 5 Years | | Total (a) | | 2016 Total |
| | (In millions) |
| Long-term debt (including estimated interest) | $ | 1,521 |
| | $ | 3,315 |
| | $ | 3,913 |
| | $ | 14,738 |
| | $ | 23,487 |
| | $ | 24,863 |
|
| Capital lease obligations (including estimated interest) | 4 |
| | 1 |
| | — |
| | — |
| | 5 |
| | 7 |
|
| Operating leases | 79 |
| | 157 |
| | 138 |
| | 707 |
| | 1,081 |
| | 982 |
|
| Fuel purchase and transportation obligations | 527 |
| | 338 |
| | 215 |
| | 296 |
| | 1,376 |
| | 1,476 |
|
| Fixed purchased power commitments | 21 |
| | 26 |
| | 21 |
| | — |
| | 68 |
| | 87 |
|
Pension minimum funding requirement (b) | 29 |
| | 48 |
| | 42 |
| | 86 |
| | 205 |
| | 375 |
|
Other postretirement benefits minimum funding requirement (c) | 7 |
| | 16 |
| | 16 |
| | 35 |
| | 74 |
| | 80 |
|
Other liabilities (d) | 75 |
| | 151 |
| | 116 |
| | 309 |
| | 651 |
| | 917 |
|
| Total | $ | 2,263 |
| | $ | 4,052 |
| | $ | 4,461 |
| | $ | 16,171 |
| | $ | 26,947 |
| | $ | 28,787 |
|
| |
(a) | Excludes $30 million non-current payable relating to NRG's uncertain tax benefits under ASC 740 as the period of payment cannot be reasonably estimated. Also excludes $771 million of asset retirement obligations which are discussed in Item 15 — Note 13, Asset Retirement Obligations, to the Consolidated Financial Statements.
|
| |
(b) | These amounts represent the Company's estimated minimum pension contributions required under the Pension Protection Act of 2006. These amounts represent estimates that are based on assumptions that are subject to change. |
| |
(c) | These amounts represent estimates that are based on assumptions that are subject to change. The minimum required contribution for years after 2027 are currently not available. |
| |
(d) | Includes water right agreements, service and maintenance agreements, stadium naming rights, LTSA commitments and other contractual obligations. |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | By Remaining Maturity at December 31, |
| | 2017 | | |
| Guarantees | Under 1 Year | | 1-3 Years | | 3-5 Years | | Over 5 Years | | Total | | 2016 Total |
| | (In millions) |
Letters of credit and surety bonds(a) | $ | 1,467 |
| | $ | 66 |
| | $ | 7 |
| | $ | 93 |
| | $ | 1,633 |
| | $ | 1,837 |
|
| Asset sales guarantee obligations | — |
| | — |
| | 257 |
| | 55 |
| | 312 |
| | 677 |
|
| Other guarantees | — |
| | 32 |
| | — |
| | 613 |
| | 645 |
| | 253 |
|
| Total guarantees | $ | 1,467 |
| | $ | 98 |
| | $ | 264 |
| | $ | 761 |
| | $ | 2,590 |
| | $ | 2,767 |
|
| |
(a) | Excludes $92 million and $272 million of letters of credit issued under the intercompany revolving credit agreement between NRG and GenOn as of December 31, 2017 and 2016, respectively. |
Fair Value of Derivative Instruments
NRG may enter into powerenergy 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. In 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 are recognized in earnings.
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 December 31, 2017,2023, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at December 31, 2017.2023. For a full discussion of the Company's valuation methodology of its contracts, see Derivative Fair Value Measurements in Item 15 — Note 4, 5, Fair Value of Financial Instruments, to the Consolidated Financial Statements.
|
| | | |
| Derivative Activity (Losses)/Gains | (In millions) |
| Fair value of contracts as of December 31, 2016 | $ | (128 | ) |
| Contracts realized or otherwise settled during the period | 37 |
|
| Derivatives reclassified to held for sale | (14 | ) |
| Changes in fair value | 151 |
|
| Fair value of contracts as of December 31, 2017 | $ | 46 |
|
| | | | | |
| 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 | (1,629) | |
| Vivint Smart Home contracts acquired during the period | (112) | |
| Other changes in fair value | (1,164) | |
| Fair value of contracts as of December 31, 2023 | $ | 648 | |
| | | | | | | | | | | | | | Fair Value of Contracts as of December 31, 2023 |
| | Fair Value of Contracts as of December 31, 2017 |
| | Maturity | | |
| Fair value hierarchy (Losses)/Gains | 1 Year or Less | | Greater Than 1 Year to 3 Years | | Greater Than 3 Years to 5 Years | | Greater Than 5 Years | | Total Fair Value |
| | (In millions) |
| (In millions) | |
| Fair Value Hierarchy (Losses)/Gains | |
| Fair Value Hierarchy (Losses)/Gains | |
| Fair Value Hierarchy (Losses)/Gains | | 1 Year or Less | | Greater Than 1 Year to 3 Years | | Greater Than 3 Years to 5 Years | | Greater Than 5 Years | | Total Fair Value |
| Level 1 | $ | (22 | ) | | $ | (41 | ) | | $ | (3 | ) | | $ | — |
| | $ | (66 | ) |
| Level 2 | 98 |
| | 49 |
| | — |
| | (3 | ) | | 144 |
|
| Level 3 | (5 | ) | | (6 | ) | | (6 | ) | | (15 | ) | | (32 | ) |
| Total | $ | 71 |
| | $ | 2 |
| | $ | (9 | ) | | $ | (18 | ) | | $ | 46 |
|
The Company has elected to disclose derivative assets and liabilities on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. Also, collateral received or posted on the Company's derivative assets or liabilities are recorded on a separate line item on the balance sheet. Consequently, the magnitude of the changes in individual current and non-current derivative assets or liabilities is higher than the underlying credit and market risk of the Company's portfolio. As discussed in Item 7A — Quantitative and Qualitative Disclosures About Market Risk, Commodity Price Risk, 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 assets and liability position is a better indicator of NRG's hedging activity. As of December 31, 2017,2023, NRG's net derivative asset was $46$648 million, an increasea decrease to total fair value of $174 million$2.9 billion as compared to December 31, 2016.2022. This increasedecrease was primarily driven by gainsroll-off of trades that settled during the period, losses in fair value, and roll off trades that were settledVivint Smart Home contracts acquired during the period, partially offset by derivatives reclassified to held for sale.period.
Based on a sensitivity analysis using simplified assumptions, the impact of a $0.50 per MMBtu increase in natural gas prices across the term of the derivative contracts would result in an increase of approximately $64 million in the net value of derivatives as of December 31, 2017.
The impact of a $0.50 per MMBtuor decrease in natural gas prices across the term of the derivative contracts would result in a decreasechange of approximately $67 million$2.0 billion in the net value of derivatives as of December 31, 2017.
Critical Accounting Policies and Estimates
NRG'sThe Company's discussion and analysis of the financial condition and results of operations are based upon the 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 policiesappropriate 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 haveguidance 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.
NRG's significant accounting policies are summarized in Item 15 — Note 2, Summary of Significant Accounting Policies, to the consolidated financial statements.
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.
Such accounting estimates include: | | | | | |
| Accounting Estimate | |
| |
Accounting Policy | Judgments/Uncertainties Affecting Application |
| Derivative Instruments | Assumptions used in valuation techniques |
| | Assumptions used in forecasting generation
| Assumptions used in forecasting borrowings |
| Market maturity and economic conditions |
| Contract interpretation |
| Market conditions in the energy industry, especially the effects of price volatility on contractual commitments |
| Income Taxes and Valuation Allowance for Deferred Tax Assets | Ability to be sustained upon audit examination of taxing authorities |
| Interpret existing tax statute and regulations upon application to transactions |
| Ability to utilize tax benefits through carry backs to prior periods and carry forwards to future periods |
ImpairmentEvaluation of Long-Lived Assets and Investmentsfor Impairment | Recoverability of investment through future operations |
| Regulatory and political environments and requirements |
| Estimated useful lives of assets |
| Environmental obligations and operational limitations |
| Estimates of future cash flows |
| Estimates of fair value |
| Judgment about impairment triggering events |
| Goodwill and Other Intangible Assets | Estimated useful lives for finite-lived intangible assets |
| Judgment about impairment triggering events |
| Estimates of reporting unit's fair value |
| Fair value estimate of intangible assets acquired in business combinations |
ContingenciesBusiness Combinations | Fair value of assets acquired and liabilities assumed in business combinations |
| Estimated future cash flow |
| Estimated useful lives of assets |
| Contingencies | Estimated financial impact of event(s) |
| Judgment about likelihood of event(s) occurring |
| Regulatory and political environments and requirements |
Derivative Instruments
The Company follows the guidance of ASC 815,Derivatives and Hedging "(ASC 815"), to account for derivative instruments. ASC 815 requires the Company to mark-to-market all derivative instruments on the balance sheet and recognize changes in the fair value of non-hedge derivative instruments immediately in earnings. In certain cases, NRG may apply hedge accounting to the Company's derivative instruments. The criteria used to determine if hedge accounting treatment is appropriate are: (i) the designation of the hedge to an underlying exposure; (ii) whether the overall risk is being reduced; and (iii) if there is a correlation between the changes in fair value of the derivative instrument and the underlying hedged item. Changes in the fair value of derivatives instruments accounted for as hedges are deferred and recorded as a component of OCI and subsequently recognizedchange in earnings, whenunless they qualify for the hedged transactions occur.NPNS exception. ASC 815 applies to NRG's energy related commodity contracts, interest rate swaps, foreign exchange contracts and Consumer Financing Program.
ForEnergy-Related Commodities
As of December 31, 2023, for purposes of measuring the fair value of derivative instruments, NRGthe Company primarily uses quoted exchange prices and consensus pricing. Consensus pricing is provided by independent pricing services which are compiled from market makers with longer dated tenors as compared to broker quotes. Prior to the fourth quarter of 2023, the Company valued derivatives based on price quotes from brokers in active markets who regularly facilitate those transactions. The Company started using consensus pricing as it offers data from more market makers and for longer dated tenors as compared to broker quotes, enhances data integrity, and increases transparency. When external prices are not available, NRG uses internal models to determine the fair value. These internal models include assumptions of the future prices of energy commodities based on the specific market in which the energy commodity is being purchased or sold, using externally available forward market pricing curves for all periods possible under the pricing model. These estimations are considered to be critical accounting estimates.
Interest Rate Swaps
NRG is exposed to changes in interest rate through the Company's issuance of variable rate debt. To manage the Company's interest rate risk, NRG enters into interest rate swap agreements. In order to qualify the derivative instruments for hedged transactions, NRG estimates the forecasted generation and forecasted borrowings for interest rate swaps occurring within a specified time period. Judgments related
Foreign Exchange Contracts
In order to mitigate foreign exchange risk primarily associated with the purchase of USD denominated natural gas for the Company's Canadian business, the Company enters into foreign exchange contract agreements.
Consumer Financing Program
The derivative positions for the Company's Consumer Financing Program are valued using a discounted cash flow model, with inputs consisting of available market data, such as market yield discount rates, as well as unobservable internally derived assumptions, such as collateral prepayment rates, collateral default rates and credit loss rates. In summary, the fair value represents an estimate of the present value of the cash flows Vivint Smart Home will be obligated to pay to the probabilitythird-party financing provider for each component of forecasted generation occurring are based on available baseload capacity, internal forecasts of sales and generation, and historical physical delivery on similar contracts. Judgments related to the probability of forecasted borrowings are based on the estimated timing of project construction, which can vary based on various factors. The probability that hedged forecasted generation and forecasted borrowings will occur by the end of a specified time period could change the results of operations by requiring amounts currently classified in OCI to be reclassified into earnings, creating increased variability in the Company's earnings. These estimations are considered to be critical accounting estimates.derivative.
Certain derivative instruments that meet the criteria for derivative accounting treatment also qualify for a scope exception to derivative accounting, as they are considered to be NPNS. The availability of this exception is based upon the assumption that NRGthe Company has the ability and it is probable to deliver or take delivery of the underlying item. These assumptions are based on available baseload capacity,expected load requirements, internal forecasts of sales and generation and historical physical delivery on contracts. Derivatives that are considered to be NPNS are exempt from derivative accounting treatment and are accounted for under accrual accounting. If it is determined that a transaction designated as NPNS no longer meets the scope exception due to changes in estimates, the related contract would be recorded on the balance sheet at fair value combined with the immediate recognition through earnings.
Income Taxes and Valuation Allowance for Deferred Tax Assets
As of December 31, 2017, NRG had2023, NRG’s deferred tax assets were primarily the result of U.S. federal and state NOLs, the difference between book and tax basis in property, plant, and equipment, deferred revenues and tax credit carryforwards. The realization of deferred tax assets is dependent upon the Company's ability to generate sufficient future taxable income during the periods in which those temporary differences become deductible, prior to the expiration of the tax attributes. The evaluation of deferred tax assets requires judgment in assessing the likely future tax consequences of events that have been recognized in the Company's financial statements or tax returns and forecasting future profitability by tax jurisdiction.
The Company evaluates its deferred tax assets quarterly on a jurisdictional basis to determine whether adjustments to the valuation allowance are appropriate considering changes in facts or circumstances. As of each reporting date, management considers new evidence, both positive and negative, when determining the future realization of the Company’s deferred tax assets. Given the Company’s current level of pre-tax earnings and forecasted future pre-tax earnings, the Company expects to generate income before taxes in the U.S. in future periods at a level that would fully utilize its U.S. federal NOL carryforwards and the majority of its state NOL carryforwards prior to their expiration.
The Company continues to maintain a valuation allowance of $1.8 billion. This amount is comprised$275 million as of domestic federal netDecember 31, 2023 against deferred tax assets consisting of approximately $1.5 billion, domestic state netNOL carryforwards and foreign NOL carryforwards in jurisdictions where the Company does not currently believe that the realization of deferred tax assets of $267 million, foreign net operating loss carryforwards of $66 million, and foreign capital loss carryforwards of approximately $1 million. The Company believes it is more likely than not thatnot. As of December 31, 2022, the results of future operations will not generate sufficient taxable income which includes the future reversal of existing taxable temporary differences to realize deferred tax assets, requiring aCompany's valuation allowance to be recorded. In December 2017, the SEC staff issued Staff Accounting Bulletin No. 118, which addresses how a company may recognize provisional amounts for the effect of the changes related to the Tax Act. Consistent with that guidance, the Company recognized provisional amounts based upon our interpretation of the tax laws and estimates which require significant judgments.balance was $224 million.
NRG continues to be under audit for multiple years by taxing authorities in other jurisdictions. Considerable judgment is required to determine the tax treatment of a particular item that involves interpretations of complex tax laws including the impact of the Tax Cuts and Jobs Act effective December 22, 2017. NRGlaws. The Company 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 continues to be under audit for multiple years by taxing authorities in various jurisdictions.
The Company is no longer subject to U.S. federal income tax examinations for years prior to 2015. 2020.With few exceptions, state and localCanadian income tax examinations are no longer open for years before 2010.2015.
NRG does not intend, nor currently foresee a need, to repatriate funds held at its international operations into the U.S. These funds are deemed to be indefinitely reinvested in its foreign operations and the Company has not changed its assertion with respect to distributions of funds that would require the accrual of U.S. income tax.
Evaluation of Assets for Impairment and Other-Than-Temporary Decline in Value
In accordance with ASC 360, Property, Plant, and Equipment ("ASC 360"), or ASC 360, NRGthe Company evaluates property, plant and equipment and certain intangible assets for impairment whenever indicators of impairment exist. Examples of such indicators or events are:include:
•Significant decrease in the market price of a long-lived asset;
•Significant adverse change in the manner an asset is being used or its physical condition;
•Adverse business climate;
•Accumulation of costs significantly in excess of the amountamounts originally expected for the construction or acquisition of an asset;
•Current period loss combined with a history of losses or the projection of future losses; and
•Change in the Company's intent about an asset from an intent to hold to a greater than 50% likelihood that an asset will be sold, or disposed of before the end of its previously estimated useful life.
Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the assets to the future net cash flows expected to be generated by the asset, through considering project specific assumptions for long-term power pooland natural gas prices, escalated future project operating costs and expected plant operations. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets by factoring in the probability weighting of different courses of action available to the Company. Generally, fair value will be determined using valuation techniques, such as the present value of expected future cash flows. NRG uses its best estimates in making these evaluations and considers various factors, including forward price curves for energy, fuel costs and operating costs. However, actual future market prices and project costs could vary from the assumptions used in the Company's estimates and the impact of such variations could be material.
For assets to be held and used, if the Company determines that the undiscounted cash flows from the asset are less than the carrying amount of the asset, NRG must estimate fair value to determine the amount of any impairment loss. Assets held-for-sale are reported at the lower of the carrying amount or fair value less the cost to sell. The estimation of fair value, under ASC 360, whether in conjunction with an asset to be held and used or with an asset held-for-sale, and the evaluation of asset impairment are, by their nature, subjective. NRGThe Company considers quoted market prices in active markets to the extent they are available. In the absence of such information, the CompanyNRG may consider prices of similar assets, consult with brokers or employ other valuation techniques. NRGThe Company will also discount the estimated future cash flows associated with the asset using a single interest rate representative of the risk involved with such an investment or employ an expected present value method that probability-weights a range of possible outcomes.asset. The use of these methods involves the same inherent uncertainty of future cash flows as previously discussed with respect to undiscounted cash flows. Actual future market prices and project costs could vary from those used in the Company'sNRG's estimates and the impact of such variations could be material.
Annually, during the fourth quarter, the Company revises its views of power and fuel prices including the Company's fundamental view for long termlong-term prices, forecasted generation and operating and capital expenditures, in connection with the preparation of its annual budget. Changes to the Company’sCompany's views of long termlong-term power and fuel prices impactedimpact the Company’s projections of profitability, based on management's estimate of supply and demand within the sub-markets for each plantits operations and the physical and economic characteristics of each plant. During the fourth quarter of 2017, the Company completed its annual budget and revised its view of long-term power and fuel prices and the corresponding impact on estimated cash flows associated with its long-lived assets. The most significant impact was a decrease in the Company’s long-term view of natural gas prices which resulted in a reduction to long-term power prices and had a negative impact on the Company’s coal, nuclear and renewable facilities.businesses.
As a result, the following long-lived asset impairments were recorded during the fourth quarter of 2017, asFor further described indiscussion, see Item 15 —Note 10, — Note 11, Asset Impairments, to the consolidated financial statements:.
•South Texas Project, or STP - The Company recognized an impairment loss of $1,248 million related to its interest in STP as a result of the decrease in the Company's view of long-term power prices in ERCOT.
•Indian River - The Company recognized an impairment loss of $36 million for Indian River as a result of the decrease in the Company's view of long-term power prices in PJM.
•Keystone and Conemaugh - The Company recognized impairment losses of $35 million for Keystone and $35 million for Conemaugh as a result of the decrease in the Company's view of long-term power prices in PJM.
•Wind Facilities - The Company recorded impairment losses of $110 million, $26 million and $4 million for Langford, Elbow Creek and Forward, respectively, as a result of the decrease in the Company's view of long-term merchant power prices in ERCOT and PJM. While Elbow Creek and Forward have contracts to sell power, the significant decrease in estimated power prices had an impact on cash flows in post-contract periods.
The Company also recorded the following impairments in 2017 based on specific triggering events that occurred:
•Bacliff Project - On June 16, 2017, NRG Texas Power LLC provided notice to BTEC New Albany, LLC that it was exercising its right to terminate the Amended and Restated Membership Interest Purchase Agreement, or MIPA, due to the Bacliff Project, a new peaking facility at the former P.H. Robinson Electric Generating Station, not achieving commercial completion by the contractual expiration date of May 31, 2017. As a result of the MIPA termination, the Company recorded an impairment loss of $41 million to reduce the carrying amount of the related construction in progress to zero during the second quarter of 2017.
•Other Impairments - During the second, third and fourth quarters of 2017, the Company recorded impairment losses of approximately $22 million, $14 million and $15 million, respectively, in connection with the Company's Renewables business. These impairment losses were primarily to record the value of certain long-lived assets, including property, plant and equipment and intangible assets, at fair market value at acquisition date or in connection with an impairment indicator.
NRG is also required to evaluate its equity method and cost method investments to determine whether or not they are impaired in accordance with ASC 323, Investments - Equity Method and Joint Ventures, or ASC 323. The standard for determining whether an impairment must be recorded under ASC 323 is whether a decline in the value is considered an other-than-temporary decline in value. The evaluation and measurement of impairments under ASC 323 involves the same uncertainties as described for long-lived assets that the Company owns directly and accounts for in accordance with ASC 360. Similarly, the estimates that NRG makes with respect to its equity and cost-method investments are subjective, and the impact of variations in these estimates could be material. Additionally, if the projects in which the Company holds these investments recognize an impairment under the provisions of ASC 360, NRG would record its proportionate share of that impairment loss and would evaluate its investment for an other-than-temporary decline in value under ASC 323. During the year ended December 31, 2016, the Company recorded impairment losses on its equity method and cost method investments of $79 million due to other-than-temporary declines in value, including the following:
During the fourth quarter of 2017, in connection with the preparation of the annual budget, management revised its view of oil production expectations with respect to Petra Nova Parish Holdings. As a result, the Company reviewed its 50% interest in Petra Nova Parish Holdings for impairment utilizing the other-than-temporary impairment model. In determining fair value, the Company utilized an income approach and considered project specific assumptions for the future project cash flows. The carrying amount of the Company's equity method investment exceeded the fair value of the investment and the Company concluded that the decline is considered to be other-than-temporary. As a result, the Company measured the impairment loss as the difference between the carrying amount and the fair value of the investment and recorded an impairment loss of $69 million.
Goodwill and Other Intangible Assets
At December 31, 2017, NRG2023, the Company reported goodwill of $539 million,$5.1 billion, consisting of $165 million associated with$3.5 billion from the acquisition of EME, $341 million forVivint in 2023, $1.3 billion from the acquisition of Direct Energy in 2021 and $0.3 billion from other retail business acquisitions, and $33 million associated with other business acquisitions.
The Company applies ASC 805, Business Combinations, or ("ASC 805,805"), and ASC 350,Intangibles-Goodwill and Other ("ASC 350") to account for its goodwill and intangible assets. Under these standards, the Company amortizes all finite-lived intangible assets over their respective estimated weighted-average useful lives, while goodwill has an indefinite life and is not amortized. Goodwill and all intangible assets not subject to amortization areis tested for impairmentsimpairment at least annually, or more frequently whenever an event or change in circumstances occurs that would more likely than not reduce the fair value of a reporting unit below its carrying amount. The Company tests goodwill for impairment at the reporting unit level, which is identified by assessing whether the components of the Company's operating segments constitute businesses for which discrete financial information is available and whether segment management regularly reviews the operating results of those components. The Company performs the annual goodwill impairment assessment as of December 31 or when events or changes in circumstances indicate that the fair value of the reporting unit may be below the carrying value may not be recoverable.amount. The Company may first assessesassess qualitative factors to determine whether it is more likely than not that an impairment has occurred. In the absence of sufficient qualitative factors, the Company performs a quantitative assessment by determining the fair value of the reporting unit and comparing to its book value. If it is determined that the fair value of a reporting unit is below its carrying amount, where necessary, the Company's goodwill will be impaired at that time.
The Company performed its qualitative assessment of macroeconomic, industry and market events and circumstances, and the overall financial performance of the NRG Business Solutions (NRG Curtailment Solutions) and Retail Mass reporting units. The Company determined it was not more likely than not that the fair value of the goodwill attributed to these reporting units were less than their carrying amount and accordingly, no impairment existed for the year ended December 31, 2017.
The Company performed a quantitative assessment for the reporting units in the following table. The Company determined the fair value of these reporting units using primarily an income approach. Under the income approach, the Company estimated the fair value of the reporting units' invested capital exceeds its carrying value and, as such, the Company concluded that goodwill associated with the reporting units in the following table is not impaired as of December 31, 2017:
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| | | |
Reporting Unit | | % Fair Value Over Carrying Value |
Midwest Generation (Generation Segment) | | 133 | % |
Texas Non-Commodity - excluding Goal Zero (Retail Segment) | | 325 | % |
Goal Zero (Retail Segment) | | 141 | % |
The Company believes the methodology and assumptions used in its quantitative assessment are consistent with the views of market participants. Significant inputs to the determination of fair value were as follows:
The Company applied a discounted cash flow methodology to the long-term budgets for all of the plants in the region. The significant assumptions used to derive the long-term budgets used in the income approach are affected by the following key inputs:
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◦ | The Company's views of power and fuel prices consider market prices for the first five-year period and the Company's fundamental view for the longer term, which reflect the Company's long-term view of the price of natural gas. The Company's fundamental view for the longer term reflects the implied power price and heat rate that would support new build of a combined cycle gas plant. The price of natural gas plays an important role in setting the price of electricity in many of the regions where NRG operates power plants. Hedging is included to the extent of contracts already in place; |
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◦ | The Company's estimate of generation, fuel costs, capital expenditure requirements and the existing and anticipated impact of environmental regulations; |
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◦ | The Company's fundamental view for the longer term, cash flows for the plants in the region were included in the fair value calculation through the end of each plants' estimated useful life; and |
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◦ | Projected generation and resulting energy gross margin in the long-term budgets is based on an hourly dispatch that simulates dispatch of each unit into the power market. The dispatch simulation is based on power prices, fuel prices, and the physical and economic characteristics of each plant. |
The Company applied a discounted cash flow methodology to the long-term budgets for the Texas Non-Commodity and Goal Zero reporting units. The significant assumptions used to derive the long-term budgets used in the income approach are affected by the following key inputs: a terminal value utilizing assumed growth rates and discount rates that reflect the inherent cash flow risk for each reporting unit.
During the fourth quarter of 2017, the Company concluded that BETM was held for sale in connection with board approval and advanced negotiations to sell the business. Accordingly, the Company recorded the assets and liabilities at fair market value as of December 31, 2017, which resulted in an impairment loss of $90 million to record BETM's goodwill at fair market value.
During the fourth quarter of 2017, NRG sold its interests in certain SPP projects to NRG Yield. The goodwill recorded during the SPP acquisition was related primarily to its development pipeline, which was not sold to NRG Yield. As the Company does not expect to separately develop these projects and accordingly, has no cash flow stream associated with the goodwill, an impairment loss of $12 million was recorded to reduce the value to zero as of December 31, 2017.
Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. As a result, there can be no assurance that the estimates and assumptions made for purposes of the annual goodwill impairment test will prove to be accurate predictions of the future.
For further discussion, see Evaluation of Assets for Impairment caption above, and Item 15 — Note 11, Asset Impairments.
Business Combinations
NRG accounts for business acquisitions using the acquisition method of accounting prescribed under ASC 805. Under this method, the Company is required to record on its Consolidated Balance Sheets the estimated fair values of the acquired company’s assets and liabilities assumed at the acquisition date. The excess of the consideration transferred over the fair value of the net identifiable assets acquired and liabilities assumed is recorded as goodwill. Determining fair values of assets acquired and liabilities assumed requires significant estimates and judgments. Fair value is determined based on the estimated price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The acquired assets and assumed liabilities from the Vivint Smart Home acquisition that involved the most subjectivity in determining fair value consisted of customer relationships, developed technology, trade names, acquired debt and derivative instruments. NRG describes in detail its acquisitions in Item 15 — Note 4, Acquisitions and Dispositions, to the Consolidated Financial Statements.
The fair value of the customer relationships, technology and trade names are measured using income-based valuation methodologies, which include certain assumptions such as forecasted future cash flows, customer attrition rates, royalty rates and discount rates. Customer relationships and technology are amortized to depreciation and amortization, ratably based on discounted future cash flows. Trade names are amortized to depreciation and amortization, on a straight line basis.
The acquired Vivint Smart Home debt was measured at fair value using observable market inputs based on interest rates at the acquisition closing date. The difference between the fair value at the acquisition closing date and the principal outstanding is being amortized through interest expense over the remaining term of the debt.
The derivative liabilities in connection with the contractual future payment obligations with the financing providers under Vivint Smart Home’s Consumer Financing Program were measured at fair value at the acquisition closing date using a discounted cash flow model, with inputs consisting of available market data, such as market yield discount rates, as well as unobservable internally derived assumptions, such as collateral prepayment rates, collateral default rates and credit loss rates. Changes to the fair value are recorded each period through other income, net in the consolidated statement of operations.
Contingencies
NRG records reserves 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. Gain contingencies are not recorded until management determines it is certain that the future event will become or does become a reality. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events, and estimates of the financial impacts of such events. NRG describes in detail its contingencies in Item 15 — Note 22, 23, Commitments and Contingencies,, to the consolidated financial statements.
Consolidated Financial Statements.
Recent Accounting Developments
See Item 15 — Note 2,, Summary of Significant Accounting Policies,, to the consolidated financial statementsConsolidated Financial Statements for a discussion of recent accounting developments.
Item 7A — 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. In order to manage these risks, the Company uses various fixed-price forward purchase and sales contracts, futures and option contracts traded on NYMEX and other exchanges, and swaps and options traded in the over-the-counter financial markets to:
•Manage and hedge fixed-price purchase and sales commitments;
Manage and hedge exposure to variable rate debt obligations;
•Reduce exposure to the volatility of cash market prices, and
•Hedge fuel requirements for the Company's generating facilities.
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 servicing 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 electricitypower and fuel. These instruments include forwards, futures, swaps, and option contracts traded on various exchanges, such as NYMEX and ICE, as well as over-the-counter markets. The portion of forecasted transactions hedged may vary based upon management's assessment of market, weather, operation and other factors.
While some of the contracts the Company uses to manage risk represent commodities or instruments for which prices are available from external sources, other commodities and certain contracts are not actively traded and are valued using other pricing sources and modeling techniques to determine expected future market prices, contract quantities, or both. NRG uses the Company's best estimates to determine the fair value of those derivative contracts. However, it is likely that future market prices could vary from those used in recording mark-to-market derivative instrument valuation and such variations could be material.
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 the Company'sits energy assets and liabilities, which includes generation assets, load obligations,gas transportation and bilateral physical and financial transactions. The key assumptions for the Company's VaR model include: (i) lognormal distribution of prices; (ii) one-day holding period; (iii) 95% confidence interval; (iv) rolling 36-month forward looking period; and (v) market implied volatilities and historical price correlations.
As of December 31, 2017, the VaR for NRG's commodity portfolio, including generationstorage assets, load obligations and bilateral physical and financial transactions, calculated using thebased on historical and forward values for factors such as customer demand, weather, commodity availability and commodity prices. The Company's VaR model was $46 million.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 NRGNRG's commodity portfolio, calculated using the VaR model for the years ended December 31, 20172023 and 2016:2022:
| | | | | | | | | | | |
| (In millions) | 2023 | | 2022 |
| VaR as of December 31, | $ | 51 | | | $ | 74 | |
| For the year ended December 31, | | | |
| Average | $ | 62 | | | $ | 51 | |
| Maximum | 82 | | | 86 | |
| Minimum | 41 | | | 26 | |
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| | | | | | | |
| (In millions) | 2017 | | 2016 |
| VaR as of December 31, | $ | 46 |
| | $ | 41 |
|
| For the year ended December 31, | | | |
| Average | $ | 51 |
| | $ | 53 |
|
| Maximum | 66 |
| | 72 |
|
| Minimum | 40 |
| | 32 |
|
Due to the inherent limitations of statistical measures such as VaR, the evolving nature of the competitive markets for electricity and related derivatives, and the seasonality of changes in market prices, the VaR calculation may not capture the full extent of commodity price exposure. As a result, actual changes in the fair value of mark-to-market energy assets and liabilities could differ from the calculated VaR, and such changes could have a material impact on the Company's financial results.
In order to provide additional information, 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 for the entire term of these instruments entered into for both asset management and trading was $30$185 million as of December 31, 2017,2023, primarily driven by asset-backed transactions.
Interest RateCredit Risk
NRG is exposed to fluctuations in interest rates through the Company's issuance of fixed rate and variable rate debt. Exposures to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, caps, collars and put or call options. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt obligations when taking into account the combination of the variable rate debt and the interest rate derivative instrument. NRG'sCredit risk management policies allow the Company to reduce interest rate exposure from variable rate debt obligations.
In addition to those discussed above, the Company's project subsidiaries enter into interest rate swaps, intended to hedge the risks associated with interest rates on non-recourse project level debt. See Item 15 — Note 12,Debt and Capital Leases, to the Consolidated Financial Statements, for more information about interest rate swaps of the Company's project subsidiaries.
If all of the above swaps had been discontinued on December 31, 2017, the Company would have owed the counterparties $11 million. Based on the investment grade rating 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 Companyrelates to the risk of loss associated with movements in market interest rates. Asresulting from non-performance or non-payment by counterparties pursuant to the terms of December 31, 2017, a 1% change in interest rates would result in a $14.2 million change in interest expense on a rolling twelve month basis.
As of December 31, 2017, the Company's debt fair value was $16.9 billion and carrying value was $16.6 billion.their contractual obligations. NRG estimates that a 1% decrease in market interest rates would have increased the fair value of the Company's long-term debt by $989 million.
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 atcounterparty credit risk through various exchanges used to hedge NRG'sactivities including wholesale sales, fuel purchases and retail supply arrangements, and retail customer credit risk through its retail load obligations.
Based on a sensitivity analysisactivities. Counterparty credit risk and retail customer credit risk are discussed below. See Note 6, Accounting for powerDerivative Instruments and gas positions under marginable contracts, a $0.50 per MMBtu change in natural gas prices across the term of the marginable contracts would cause a change in margin collateral posted of approximately $120 million as of December 31, 2017Hedging Activities, and a 1.00 MMBtu/MWh change in heat ratesto this Form 10-K for heat rate positions would result in a change in margin collateral posted of approximately $64 million as of December 31, 2017. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of December 31, 2017.discussion regarding credit risk contingent features.
Counterparty 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. The Company monitors and manages credit risk through credit policies that include: (i) an established credit approval process; (ii) a daily monitoring of counterparties' credit limits; (iii) the use of credit mitigation measures such as margin, collateral, prepayment arrangements, or volumetric limits; (iv) the use of payment netting agreements; and (v) the use of master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with a single counterparty. Risks surrounding counterparty performance and credit could ultimately impact the amount and timing of expected cash flows. The Company seeks to mitigate counterparty risk by having a diversified portfolio of counterparties. The Company also has credit protection within various agreements to call on additional collateral support if and when necessary. Cash margin is collected and held at the Company to cover the credit risk of the counterparty until positions settle.
As of December 31, 2017, aggregate2023, counterparty credit exposure, to a significant portion of the Company's counterparties totaled $220 million,excluding credit exposure from RTOs, ISOs, registered commodity exchanges and certain long-term agreements, was $1.6 billion, of which the Company held collateral (cash and letters of credit) against those positions of $30$426 million resulting in a net exposure of $196 million.$1.2 billion. NRG periodically receives collateral from counterparties in excess of their exposure. Collateral amounts shown include such excess while net exposure shown excludes excess collateral received. Approximately 73%63% of the Company's exposure before collateral is expected to roll off by the end of 2019.2025. The following table highlights the 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, NPNS, and non-derivative transactions. As of December 31, 2017,2023, the aggregate credit exposure is shown net of collateral held, and includes amounts net of receivables or payables.
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| Category | Net Exposure (a) (b) (% of Total) |
Financial institutions | 14 | % |
| Utilities, energy merchants, marketers and other | 8680 |
% |
| Financial institutions | 20 | |
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| |
| Total | 100 | % |
| | | | | |
| | |
| Category | Net Exposure (a) (b) (% of Total) |
| Investment grade | 6944 | % |
| Non-Investment grade/Non-Rated | 3156 | |
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| Total | 100 | % |
(a)Counterparty credit exposure excludes coal transportation contracts because of the unavailability of market prices
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(a) | Counterparty credit exposure excludes uranium and coal transportation contracts because of the unavailability of market prices. |
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(b) | The figures in the tables above exclude potential counterparty credit exposure related to RTOs, ISOs, registered commodity exchanges and certain long term contracts. |
(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 has credit exposure to certainone wholesale counterparties, eachcounterparty in excess of which represent more than 10% of the total net exposure discussed above and the aggregate credit exposure to such counterparties was $37 million as of December 31, 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, the Company does not anticipate a material impact on its financial position or results of operations from nonperformance by any counterparty.
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 whereas in the case of AESO and IESO, both exist provincially with AESO primarily subject to Alberta Utilities Commission and the IESO subject 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 applicable 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 termlong-term contracts, including California tolling agreements, Gulf Coast load obligations, and wind andprimarily solar under Renewable PPAs. As external sources or observable market quotes are not available to estimate such exposure, the Company values these contracts based on various techniques including, but not limited to, internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. Based on these valuation techniques, as of December 31, 2017,2023, aggregate credit risk exposure managed by NRG to these counterparties was approximately $4.1 billion, of which $2.6 billion related to assets of NRG Yield, Inc.,$882 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, which NRG is unable to predict.
Retail Customer Credit Risk
NRG is exposed to retail credit risk through itsthe Company's retail electricity and gas providers which serve C&I customers and the Mass market.as well as through Vivint Smart Home. Retail credit risk results in losses when a customer fails to pay for services rendered. The losses could be incurredmay result from both nonpayment of customer accounts receivable and anythe loss of in-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 December 31, 2017,2023, the Company's retail customer credit exposure to C&IHome and MassBusiness customers was diversified across many customers and various industries, as well as government entities. The Company is also subject to risk with respect to its residential solar customers. The Company's bad debt expense resulting from credit risk was $68 million, $48 million, and $64 million for the years ending December 31, 2017, 2016, and 2015, respectively. 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 bad debt expense.credit losses. The Company's provision for credit losses resulting from credit risk was $251 million, $11 million and $698 million for the years ended December 31, 2023, 2022 and 2021, respectively. During the year ended December 31, 2022, the provision for credit losses included the Company's loss mitigation efforts recognized as income of $126 million related to Winter Storm Uri. During the year ended December 31, 2021, the provision for credit losses included $596 million of expenses due to the impacts of Winter Storm Uri.
CreditLiquidity Risk Related Contingent Features
CertainLiquidity risk arises from the general funding needs of the Company's hedging agreements containactivities and 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 December 31, 2023, a $0.50 per MMBtu decrease in natural gas prices across the term of the marginable contracts would cause an increase in margin collateral posted of approximately $1.5 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 $350 million. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions that requireas of December 31, 2023.
Interest Rate Risk
NRG is exposed to fluctuations in interest rates through its issuance of variable rate debt. Exposures to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, caps, collars and put or call options. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt obligations when taking into account the combinations of the variable rate debt and the interest rate derivative instrument. NRG's risk management policies allow the Company to post additional collateral ifreduce interest rate exposure from variable rate debt obligations. In the counterparty determines that there has been deterioration in credit quality, generally termed "adequate assurance" under the agreements, or requirefirst quarter of 2023, the Company entered into $1.0 billion of interest rate swaps through 2027 to post additional collateral if there were a one notch downgradehedge the floating rate on the Term Loan acquired with the Vivint Smart Home acquisition. Additionally, in the Company's credit rating. The collateral required for contracts that have adequate assurance clauses that arefirst quarter of 2023, the Company had entered into interest rate swaps to hedge the floating rate on the Revolving Credit Facility extending through 2024, which was fully terminated in a net liability position asconjunction with the pay down of the Revolving Credit Facility.
As of December 31, 2017,2023, the Company's debt fair value was $25$10.6 billion and carrying value was $10.8 billion. NRG estimates that a 1% decrease in market interest rates would have increased the fair value of the Company's long-term debt by $602 million. The collateral required for contracts with credit rating contingent features that are in a net liability position as of December 31, 2017, was $7 million. The Company is also a party to certain marginable agreements under which it has a net liability position, but the counterparty has not called for the collateral due, which is approximately $4 million as of December 31, 2017.
Currency Exchange Risk
NRG's foreign earnings and investments may beNRG is subject to transactional exchange rate risk from transactions with customers in countries outside of the U.S., primarily within Canada, as well as from intercompany transactions between affiliates. Transactional exchange rate risk arises from the purchase and sale of goods and services in currencies other than the Company's functional currency or the functional currency of an applicable subsidiary. NRG hedges a portion of its forecasted currency transactions with foreign exchange forward contracts. As of December 31, 2023, NRG is exposed to changes in foreign currency primarily associated with the purchase of U.S. dollar denominated natural gas for its Canadian business and entered into foreign exchange contracts with a notional amount of $548 million.
The Company is subject to translation exchange rate risk which NRG generally does not hedge.related to the translation of the financial statements of its foreign operations into U.S. dollars. Costs incurred and sales recorded by subsidiaries operating outside of the U.S. are translated into U.S. dollars using exchange 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 December 31, 2023, would have resulted in a decrease of $36 million to net income within the Consolidated Statement of Operations.
Item 8 — Financial Statements and Supplementary Data
The financial statements and schedules are listedincluded in Part IV, Item 15 of this Form 10-K.
Item 9 — Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
Item 9A — Controls and Procedures
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures and Internal Control Over Financial Reporting
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 Annual Report on Form 10-K. Management's report on the Company's internal control over financial reporting and the report of the Company's independent registered public accounting firm are incorporated under the caption "Management's Report on Internal Control over Financial Reporting" and under the caption "Report of Independent Registered Public Accounting Firm" in this Annual Report on Form 10-K for the fiscal year ended December 31, 2017.2023.
Changes in Internal Control over Financial Reporting
ThereDuring the year ended December 31, 2023, the Company completed its acquisition of Vivint Smart Home, Inc. As part of integration, the Company designed and implemented a control structure over Vivint Smart Home's operations. Other than the Vivint Smart Home acquisition, there were no changes in NRG’s internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred in the fourth quarter of 20172023 that materially affected, or are reasonably likely to materially affect, NRG’s internal control over financial reporting.
Inherent Limitations over Internal Controls
NRG's internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with GAAP. The Company's internal control over financial reporting includes those policies and procedures that:
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1. | Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the Company's assets; |
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2. | Provide reasonable assurance that transactions are recorded as necessary to permit preparation of consolidated financial statements in accordance with GAAP, and that the Company's receipts and expenditures are being made only in accordance with authorizations of its management and directors; and |
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3. | Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the consolidated financial statements. |
1.Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the Company's assets;
2.Provide reasonable assurance that transactions are recorded as necessary to permit preparation of consolidated financial statements in accordance with GAAP, and that the Company's receipts and expenditures are being made only in accordance with authorizations of its management and directors; and
3.Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the consolidated financial statements.
Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations, including the possibility of human error and circumvention by collusion or overriding of controls. Accordingly, even an effective internal control system may not prevent or detect material misstatements on a timely basis. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
Management's Report on Internal Control over Financial Reporting
The Company's management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of the Company's management, including its principal executive officer, principal financial officer and principal accounting officer, the Company conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Company's evaluation under the framework in Internal Control — Integrated Framework (2013), the Company's management concluded that its internal control over financial reporting was effective as of December 31, 2017.2023.
TheOn March 10, 2023, NRG acquired Vivint Smart Home, Inc., and management excluded from its assessment of the effectiveness of the Company's internal control over financial reporting as of December 31, 20172023, Vivint Smart Home, Inc.'s internal control over financial reporting associated with total assets (excluding acquired goodwill and intangible assets) of 5% and total revenues of 5% included in the consolidated financial statements of the Company as of and for the year ended December 31, 2023.
The effectiveness of the Company's internal control over financial reporting as of December 31, 2023 has been audited by KPMG LLP, the Company's independent registered public accounting firm, as stated in its report which is included in this Annual Report on Form 10‑K.10-K.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
TheTo the Board of Directors and Stockholders
NRG Energy, Inc.:
Opinion on Internal Control Over Financial Reporting
We have audited NRG Energy, Inc.’s and subsidiariessubsidiaries' (the Company) internal control over financial reporting as of December 31, 2017,2023, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017,2023, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 20172023 and 2016,2022, the related consolidated statements of operations, comprehensive (loss)/income, stockholders’ equity, and cash flows and stockholders’ equity for each of the years in the three-year period ended December 31, 2017,2023, and the related notes and financial statement schedule II (collectively, the consolidated financial statements), and our report dated March 1, 2018February 28, 2024 expressed an unqualified opinion on those consolidated financial statements.
The Company acquired Vivint Smart Home, Inc. during 2023, and management excluded from its assessment of the effectiveness of the Company's internal control over financial reporting as of December 31, 2023, Vivint Smart Home, Inc.'s internal control over financial reporting associated with total assets (excluding acquired goodwill and intangible assets) of 5% and total revenues of 5% included in the consolidated financial statements of the Company as of and for the year ended December 31, 2023. Our audit of internal control over financial reporting of the Company also excluded an evaluation of the internal control over financial reporting of Vivint Smart Home, Inc.
Basis for Opinion
The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
(signed)/s/ KPMG LLP
Philadelphia, Pennsylvania
March 1, 2018February 28, 2024
Item 9B — Other Information
None.Director and Officer Trading Arrangements
During the three months ended December 31, 2023, the following directors or officers of the Company adopted or terminated a 'Rule 10b5-1 trading arrangement' or 'non-Rule 10b5-1 trading arrangement,' as each term is defined in Item 408(a) of Regulation S-K, as described in the table below:
| | | | | | | | | | | | | | | | | | | | |
| Name | Title | Date Adopted | Character of Trading Arrangement | Aggregate Number of Shares of Common Stock to be Purchased or Sold Pursuant to Trading Arrangement(a) | Duration | Date Terminated |
| Elizabeth Killinger | Executive Vice President | 12/15/2023 | Rule 10b5-1 Trading Arrangement | 65,583 shares to be Sold(b) | 3/15/2024-1/31/2025 | N/A |
| Rasesh Patel | Executive Vice President, Smart Home | 12/15/2023 | Rule 10b5-1 Trading Arrangement | Up to 73,638 shares to be Sold | 3/14/2024-11/01/2024 | N/A |
(a)Potential sales may be subject to certain price limitations set forth in the 10b5-1 plans and therefore actual number of shares sold could vary if certain minimum stock prices are not met
(b)Represents approximate number of shares to be sold based on outstanding awards expected to vest during the period, where any underlying performance share awards are being calculated at target. Actual number of shares to be sold will depend on actual vesting, the number of shares withheld by NRG to satisfy tax withholding obligations and vesting of dividend equivalent rights
Item 9C — Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable.
PART III
Item 10 — Directors, Executive Officers and Corporate Governance
Directors
E. Spencer Abrahamhas been a director of NRG since December 2012. Previously, he served as a director of GenOn Energy, Inc. from January 2012 to December 2012. He is Chairman and Chief Executive Officer of The Abraham Group, an international strategic consulting firm based in Washington, D.C which he founded in 2005. Prior to that, Secretary Abraham served as Secretary of Energy under President George W. Bush from 2001 through January 2005 and was a U.S. Senator for the State of Michigan from 1995 to 2001. Secretary Abraham serves on the boards of the following public companies: Occidental Petroleum Corporation, PBF Energy, and Two Harbors Investment Corp., as well as chairman of the board of Uranium Energy Corp. He also serves on the board of C3 IoT, a private company. Secretary Abraham previously served as the non-executive chairman of AREVA, Inc., the U.S. subsidiary of the French-owned nuclear company, and as a director of Deepwater Wind LLC, International Battery, Green Rock Energy, ICx Technologies, PetroTiger and Sindicatum Sustainable Resources. He also previously served on the advisory board or committees of Midas Medici (Utilipoint), Millennium Private Equity, Sunovia and Wetherly Capital.
Kirbyjon H. Caldwell has been a director of NRG since March 2009. He was a director of Reliant Energy, Inc. from August 2003 to March 2009. Since 1982, he has served as Senior Pastor at the 16,000-member Windsor Village United Methodist Church in Houston, Texas. Pastor Caldwell was also a director of United Continental Holdings, Inc. (formerly Continental Airlines, Inc.) from 1999 to September 2011. Pastor Caldwell is also on the Board of Trustees of Baylor College of Medicine.
Lawrence S. Coben has served as Chairman of the Board of NRG since 2017 and has been a director of NRG since December 2003. He is currently Chairman and Chief Executive Officer of Tremisis Energy Corporation LLC. Dr. Coben was Chairman and Chief Executive Officer of Tremisis Energy Acquisition Corporation II, a publicly held company, from July 2007 through March 2009 and of Tremisis Energy Acquisition Corporation from February 2004 to May 2006. From January 2001 to January 2004, he was a Senior Principal of Sunrise Capital Partners L.P., a private equity firm. From 1997 to January 2001, Dr. Coben was an independent consultant. From 1994 to 1996, Dr. Coben was Chief Executive Officer of Bolivian Power Company. Dr. Coben serves on the board of Freshpet, Inc. and served on the advisory board of Morgan Stanley Infrastructure II, L.P. from September 2014 through December 2016. Dr. Coben is also Executive Director of the Sustainable Preservation Initiative and a Consulting Scholar at the University of Pennsylvania Museum of Archaeology and Anthropology.
Terry G. Dallas has been a director of NRG since December 2012. Previously, he served as a director of GenOn Energy, Inc. from December 2010 to December 2012. Mr. Dallas served as a director of Mirant Corporation from 2006 until December 2010. Mr. Dallas was also the former Executive Vice President and Chief Financial Officer of Unocal Corporation, an oil and gas exploration and production company prior to its merger with Chevron Corporation, from 2000 to 2005. Prior to that, Mr. Dallas held various executive finance positions in his 21-year career with Atlantic Richfield Corporation, an oil and gas company with major operations in the United States, Latin America, Asia, Europe and the Middle East.
Mauricio Gutierrez has served as President and Chief Executive Officer of NRG since December 2015 and as a director of NRG since January 2016. Prior to December 2015, Mr. Gutierrez was the Executive Vice President and Chief Operating Officer of NRG from July 2010 to December 2015. Mr. Gutierrez also served as the Interim President and Chief Executive Officer of NRG Yield, Inc. from December 2015 to May 2016 and Executive Vice President and Chief Operating Officer of NRG Yield, Inc. from December 2012 to December 2015. Mr. Gutierrez has also served on the board of NRG Yield, Inc. since its formation in December 2012. Mr. Gutierrez has been with NRG since August 2004 and served in multiple executive positions within NRG including Executive Vice President - Commercial Operations from January 2009 to July 2010 and Senior Vice President - Commercial Operations from March 2008 to January 2009. Prior to joining NRG in August 2004, Mr. Gutierrez held various commercial positions within Dynegy, Inc.Officers
William E. Hantke has been a director of NRG since March 2006. Mr. Hantke served as Executive Vice President and Chief Financial Officer of Premcor, Inc., a refining company, from February 2002 until December 2005. Mr. Hantke was Corporate Vice President of Development of Tosco Corporation, a refining and marketing company, from September 1999 until September 2001, and he also served as Corporate Controller from December 1993 until September 1999. Prior to that position, he was employedInformation required by Coopers & Lybrand as Senior Manager, Mergers and Acquisitions from 1989 until 1990. He also held various positions from 1975 until 1988 with AMAX, Inc., including Corporate Vice President, Operations Analysis and Senior Vice President, Finance and Administration, Metals and Mining. He was employedthis Item is incorporated by Arthur Young from 1970 to 1975 as Staff/Senior Accountant. Mr. Hantke was Non-Executive Chairman of Process Energy Solutions, a private alternative energy company until March 31, 2008 and served as director and Vice-Chairman of NTR Acquisition Co., an oil refining start-up, until January 2009. Mr. Hantke has served on the board of PBF Energy Inc. since February 2016.
Paul W. Hobby has been a director of NRG since March 2006. Mr. Hobby is the Managing Partner of Genesis Park, L.P., a Houston-based private equity business specializing in technology and communications investments which he founded in 1999. Mr. Hobby routinely provides management and governance services to Genesis Park portfolio companies, and is currently serving as Chairman of Texas Monthly. He previously served as the Chief Executive Officer of Alpheus Communications, Inc., a Texas wholesale telecommunications provider from 2004 to 2011, and as Former Chairman of CapRock Services Corp., the largest provider of satellite servicesreference to the global energy business from 2002 to 2006. From November 1992 until January 2001, he served as Chairman and Chief Executive Officersimilarly named section of Hobby Media Services and was ChairmanNRG's Definitive Proxy Statement for its 2024 Annual Meeting of Columbine JDS Systems, Inc. from 1995 until 1997. Mr. Hobby is former Chairman of the Houston Branch of the Federal Reserve Bank of Dallas and the Greater Houston Partnership and is former Chairman of the Texas Ethics Commission. He was an Assistant U.S. Attorney for the Southern District of Texas from 1989 to 1992, Chief of Staff to the Lieutenant Governor of Texas, Bob Bullock and an Associate at Fulbright & Jaworski from 1986 to 1989.Stockholders.
Anne C. Schaumburg has been a director of NRG since April 2005. From 1984 until her retirement in January 2002, she was Managing Director of Credit Suisse First Boston and a Senior Banker in the Global Energy Group. From 1979 to 1984, she was in the Utilities Group at Dean Witter Financial Services Group, where she last served as Managing Director. From 1971 to 1978, she was at The First Boston Corporation in the Public Utilities Group. Ms. Schaumburg is also a director of Brookfield Infrastructure Partners L.P.
Evan J. Silverstein has been a director of NRG since December 2012. Previously, he served as a director of GenOn from August 2006 to December 2012. He served as General Partner and Portfolio Manager of SILCAP LLC, a market-neutral hedge fund that principally invests in utilities and energy companies, from January 1993 until his retirement in December 2005. Previously, he served as portfolio manager specializing in utilities and energy companies and as senior equity utility analyst. Mr. Silverstein has given numerous speeches and has testified before Congress on a variety of energy-related issues. He is an audit committee financial expert.
Barry T. Smitherman has been a director of NRG since February 2017. Mr. Smitherman is currently an energy industry consultant and senior advisor, as well as a licensed attorney in Texas and an adjunct professor of Energy Law at The University of Texas School of Law. From April 2015 to January 2017, Mr. Smitherman was a partner with the law firm Vinson & Elkins LLP. Mr. Smitherman served on the Railroad Commission of Texas (RRC) from July 2011 through January 2015 where he acted as chairman from February 2012 to August 2014. From April 2004 through July 2011, Mr. Smitherman served on the Public Utility Commission of Texas where he acted as chairman from November 2007 through July 2011.
Thomas H. Weidemeyer has been a director of NRG since December 2003. Until his retirement in December 2003, Mr. Weidemeyer served as Director, Senior Vice President and Chief Operating Officer of United Parcel Service, Inc., the world's largest transportation company and President of UPS Airlines. Mr. Weidemeyer became Manager of the Americas International Operation in 1989, and in that capacity directed the development of the UPS delivery network throughout Central and South America. In 1990, Mr. Weidemeyer became Vice President and Airline Manager of UPS Airlines and, in 1994, was elected its President and Chief Operating Officer. Mr. Weidemeyer became Senior Vice President and a member of the Management Committee of United Parcel Service, Inc. that same year, and he became Chief Operating Officer of United Parcel Service, Inc. in January 2001. Mr. Weidemeyer also serves as a director of The Goodyear Tire & Rubber Co., Waste Management, Inc. and Amsted Industries Incorporated.
C. John Wilder has been a director of NRG since February 2017. Mr. Wilder has served as the Executive Chairman and a member of Investment Committees of three investment vehicles: (i) Bluescape Resources Company; (ii) Parallel Resource Partners; and (iii) Bluescape Energy Partners since 2007. Wilder has served as Executive Chairman and director of Exco Resources, Inc. from September 2015 to November 2017. Mr. Wilder is on the advisory boards of the McCombs School of Business at the University of Texas at Austin and the A.B. Freeman School of Business at Tulane University. Mr. Wilder is a Trustee of Texas Health Resources and is a past member of the National Petroleum Council, a Secretary of Energy Appointment.
Walter R. Young has been a director of NRG since December 2003. From May 1990 to June 2003, Mr. Young was Chairman, Chief Executive Officer and President of Champion Enterprises, Inc., an assembler and manufacturer of manufactured homes. Mr. Young has held senior management positions with The Henley Group, The Budd Company and BFGoodrich.
Executive Officers
Mauricio Gutierrez has served as President and Chief Executive Officer of NRG since December 2015 and as a director of NRG since January 2016. For additional biographical information for Mr. Gutierrez, see above under "Directors."
Kirkland Andrews has served as Executive Vice President and Chief Financial Officer of NRG Energy since September 2011. Mr. Andrews is a director of NRG Yield, Inc. and also served as Executive Vice President, Chief Financial Officer of NRG Yield, Inc. from December 2012 to November 2016. Prior to joining NRG, he served as Managing Director and Co-Head Investment Banking, Power and Utilities - Americas at Deutsche Bank Securities from June 2009 to September 2011. Prior to this, he served in several capacities at Citigroup Global Markets Inc., including Managing Director, Group Head, North American Power from November 2007 to June 2009, and Head of Power M&A, Mergers and Acquisitions from July 2005 to November 2007. In his banking career, Mr. Andrews led multiple large and innovative strategic, debt, equity and commodities transactions.
David Callen has served as Senior Vice President and Chief Accounting Officer since February 2016 and Vice President and Chief Accounting Officer from March 2015 to February 2016. In this capacity, Mr. Callen is responsible for directing NRG's financial accounting and reporting activities. Mr. Callen also has served as Vice President and Chief Accounting Officer of NRG Yield, Inc. since March 2015. Prior to this, Mr. Callen served as the Company's Vice President, Financial Planning & Analysis from November 2010 to March 2015. He previously served as Director, Finance from October 2007 through October 2010, Director, Financial Reporting from February 2006 through October 2007, and Manager, Accounting Research from September 2004 through February 2006. Prior to NRG, Mr. Callen was an auditor for KPMG LLP in both New York City and Tel Aviv Israel from October 1996 through April 2001.
John Chillemi has served as Executive Vice President, National Business Development of NRG since December 2015. In this role, Mr. Chillemi is responsible for all wholesale generation development activities for NRG across the nation. Prior to December 2015, Mr. Chillemi was Senior Vice President and Regional President, West since the acquisition of GenOn in December 2012. Mr. Chillemi served as the Regional President in California and the West for GenOn from December 2010 to December 2012, and as President and Vice President of the West at Mirant Corporation from 2007 to December 2010. Mr. Chillemi has also served as a director of NRG Yield, Inc. since May 2016. Mr. Chillemi has 30 years of power industry experience, beginning with Georgia Power in 1986.
David R. Hill has served as Executive Vice President and General Counsel since September 2012. Mr. Hill also has served as the Executive Vice President and General Counsel of NRG Yield, Inc. since December 2012. Prior to joining NRG, Mr. Hill was a partner and co-head of Sidley Austin LLP's global energy practice group from February 2009 to August 2012. Prior to this, Mr. Hill served as General Counsel of the U.S. Department of Energy from August 2005 to January 2009 and, for the three years prior to that, as Deputy General Counsel for Energy Policy of the U.S. Department of Energy. Before his federal government service, Mr. Hill was a partner in major law firms in Washington, D.C. and Kansas City, Missouri, and handled a variety of regulatory, litigation and corporate matters.
Elizabeth Killinger has served as Executive Vice President and President, NRG Retail and Reliant of NRG since February 2016. Ms. Killinger was Senior Vice President and President, NRG Retail from June 2015 to February 2016 and Senior Vice President and President, NRG Texas Retail from January 2013 to June 2015. Ms. Killinger has also served as President of Reliant, a subsidiary of NRG, since October 2012. Prior to that, Ms. Killinger was Senior Vice President of Retail Operations and Reliant Residential from January 2011 to October 2012. Ms. Killinger has been with the Company and its predecessors since 2002 and has held various operational and business leadership positions within the retail organization. Prior to joining the Company, Ms. Killinger spent a decade providing strategy, management and systems consulting to energy, oilfield services and retail distribution companies across the U.S. and in Europe.
Christopher Moser has served as Executive Vice President, Operations of NRG since January 2018. Mr. Moser previously served as Senior Vice President, Operations of NRG, with responsibility for Plant Operations, Commercial Operations, Business Operations and Engineering and Construction, beginning in March 2016. From June 2010 to March 2016, Mr. Moser served as Senior Vice President, Commercial Operations. In this capacity, he was responsible for the optimization of the Company's wholesale generation fleet.
Code of Ethics
NRG has adopted a code of ethics entitled "NRG Code of Conduct" that applies to directors, officers and employees, including the chief executive officer and senior financial officers of NRG. It may be accessed through the "Governance" section of the Company's website at www.nrg.com. NRG also elects to disclose the information required by Form 8-K, Item 5.05, "Amendments to the Registrant's Code of Ethics, or Waiver of a Provision of the Code of Ethics," through the Company's website, and such information will remain available on this website for at least a 12-month period. A copy of the "NRG Energy, Inc. Code of Conduct" is available in print to any stockholder who requests it.
Other information required by this Item will beis incorporated by reference to the similarly named section of NRG's Definitive Proxy Statement for its 20182024 Annual Meeting of Stockholders.
Item 11 — Executive Compensation
Information required by this Item will beis incorporated by reference to the similarly named section of NRG's Definitive Proxy Statement for its 20182024 Annual Meeting of Stockholders.
Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Securities Authorized for Issuance under Equity Compensation Plans
| | | | | | | | | | | | | | | | | | | | |
| Plan Category | (a)
Number of Securities
to be Issued Upon
Exercise of
Outstanding Options,
Warrants and Rights | | (b)
Weighted-Average Exercise
Price of Outstanding
Options, Warrants and
Rights | | (c)
Number of Securities
Remaining Available
for Future Issuance
Under Equity Compensation
Plans (Excluding
Securities Reflected
in Column (a)) | |
| Equity compensation plans approved by security holders | 2,997,640 | | (1) | $ | — | | | 14,419,264 | | |
| Equity compensation plans not approved by security holders | 3,970,872 | | (2) | $ | — | | | 12,749,736 | | |
| Total | 6,968,512 | | | $ | — | | | 27,169,000 | | (3) |
|
| | | | | | | | | | |
| Plan Category | (a) Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights | | (b) Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights | | (c) Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a)) | |
| Equity compensation plans approved by security holders | 6,211,050 |
| (1) | $ | 21.49 |
| | 11,831,645 |
| |
| Equity compensation plans not approved by security holders | 1,369,880 |
| (2) | 25.21 |
| | — |
| (4) |
| Total | 7,580,930 |
| | $ | 23.21 |
| | 11,831,645 |
| (3) |
| |
(1) | (1)Consists of shares issuable under the NRG LTIP and the ESPP. The NRG LTIP became effective upon the Company's emergence from bankruptcy. On April 27, 2017, the NRG LTIP was amended and restated to increase the number of shares available for issuance to 25,000,000. The ESPP, as amended and restated, was approved by the Company's stockholders on April 27, 2017, and became effective April 28, 2017. As of December 31, 2017, there were 3,107,050 shares reserved from the Company's treasury shares for the ESPP. |
| |
(2) | Consists of shares issuable under the NRG GenOn LTIP. On December 14, 2012, in connection with the Merger, NRG assumed the GenOn Energy, Inc. 2010 Omnibus Incentive Plan and changed the name to the NRG 2010 Stock Plan for GenOn Employees, or the NRG GenOn LTIP. While the GenOn Energy, Inc. 2010 Omnibus Incentive Plan was previously approved by stockholders of RRI Energy, Inc. before it became GenOn, the plan is listed as “not approved” because the NRG GenOn LTIP was not subject to separate line item approval by NRG's stockholders when the Merger (which included the assumption of this plan) was approved. As part of the Merger, NRG also assumed the GenOn Energy, Inc. 2002 Long-Term Incentive Plan, the GenOn Energy, Inc. 2002 Stock Plan, and the Mirant Corporation 2005 Omnibus Incentive Compensation Plan. NRG has no intention of making any grants or awards of its own equity securities under these plans. The number of securities to be issued upon the exercise of outstanding awards under these plans is 227,531 at a weighted-average exercise price of $36.07. See Item 15 — Note 20, Stock-Based Compensation, to Consolidated Financial Statements for a discussion of the NRG GenOn LTIP.
|
| |
(3) | Consists of 8,724,595 shares of common stock under NRG's LTIP and 3,107,050 shares of treasury stock reserved for issuance under the ESPP. In the first quarter of 2018, 175,862 shares were issued to employees' accounts from the treasury stock reserve for the ESPP. Beginning January 2018, NRG suspended the ESPP. |
| |
(4) | Upon adoption of the NRG Amended and Restated LTIP effective April 27, 2017, no securities remain available for future issuance under the NRG GenOn LTIP. See Note 20, Stock-Based Compensation, for additional information.
|
Both the NRG LTIP and the ESPP. On April 27, 2023, NRG GenOnstockholders approved an increase of 4,400,000 shares available for issuance under the ESPP. As of December 31, 2023, there were 6,702,125 shares reserved from the Company's treasury shares for the ESPP
(2)Consists of shares issuable under the Vivint LTIP. On March 10, 2023, in connection with the Acquisition, NRG assumed the Vivint Smart Home, Inc. 2020 Omnibus Incentive Plan. While the Vivint Smart Home, Inc. 2020 Omnibus Incentive Plan was previously approved by stockholders of Vivint Smart Home, Inc., the plan is listed as "not approved" because it was assumed as part of the Acquisition and not subject to approval by NRG stockholders. The Company intends to make subsequent grants under the Vivint LTIP. See Note 21, Stock-Based Compensation for a discussion of the Vivint LTIP provide
(3)Consists of 7,717,139 shares of common stock under the NRG LTIP, 12,749,736 shares of common stock under the Vivint LTIP and 6,702,125 shares of treasury stock reserved for issuance under the ESPP
The NRG LTIP currently provides for grants of stock options, restricted stock market stock units, relative performance stock units, deferred stock units and dividend equivalent rights. NRG'sThe Vivint LTIP currently provides for grants of restricted stock units and performance stock units. The Company's directors, officers and employees, as well as other individuals performing services for, or to whom an offer of employment has been extended by the Company, are eligible to receive grants under the NRG LTIP and the NRG GenOn LTIP. However, participants eligible for the NRG LTIP at the time of the Merger are not eligible to receive grants under the NRG GenOn LTIP.LTIPs. The purpose of the NRG LTIP and the NRG GenOn LTIPLTIPs is to promote the Company's long-term growth and profitability by providing these individuals with incentives to maximize stockholder value and otherwise contribute to the Company's success and to enable the Company to attract, retain and reward the best available persons for positions of responsibility. The Compensation Committee of the Board of Directors administers the NRG LTIP and the NRG GenOn LTIP.LTIPs.
Other information required by this Item will beis incorporated by reference to the similarly named section of NRG's Definitive Proxy Statement for its 20182024 Annual Meeting of Stockholders.
Item 13 — Certain Relationships and Related Transactions, and Director Independence
Information required by this Item will beis incorporated by reference to the similarly named section of NRG's Definitive Proxy Statement for its 20182024 Annual Meeting of Stockholders.
Item 14 — Principal Accounting Fees and Services
Information required by this Item will beis incorporated by reference to the similarly named section of NRG's Definitive Proxy Statement for its 20182024 Annual Meeting of Stockholders.
PART IV
Item 15 — Exhibits, Financial Statement Schedules
(a)(1) Financial Statements
The following consolidated financial statements of NRG Energy, Inc. and related notes thereto, together with the reports thereon of KPMG LLP, Philadelphia, PA, Auditor Firm ID: 185, are included herein:
Consolidated Statements of Operations — Years ended December 31, 2017, 2016,2023, 2022, and 20152021
Consolidated Statements of Comprehensive (Loss)/Income — Years ended December 31, 2017, 2016,2023, 2022, and 20152021
Consolidated Balance Sheets — As of December 31, 20172023 and 20162022
Consolidated Statements of Cash Flows — Years ended December 31, 2017, 2016,2023, 2022, and 20152021
Consolidated StatementStatements of Stockholders' Equity — Years ended December 31, 2017, 2016,2023, 2022, and 20152021
Notes to Consolidated Financial Statements
(a)(2) Financial Statement Schedule
The following Consolidated Financial Statement Schedule of NRG Energy, Inc. is filed as part of Item 15 of this report and should be read in conjunction with the Consolidated Financial Statements.
Schedule II — Valuation and Qualifying Accounts
All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions or are inapplicable, and therefore, have been omitted.
(a)(3) Exhibits: See Exhibit Index submitted as a separate section of this report.
(b) Exhibits
See Exhibit Index submitted as a separate section of this report.
(c) Not applicable
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
TheTo the Board of Directors and Stockholders
NRG Energy, Inc.:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of NRG Energy, Inc. and subsidiaries (the Company) as of December 31, 20172023 and 2016,2022, the related consolidated statements of operations, comprehensive (loss)/income, stockholders' equity, and cash flows and stockholders’ equity for each of the years in the three‑yearthree-year period ended December 31, 2017,2023, and the related notes and financial statement schedule II (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20172023 and 2016,2022, and the results of its operations and its cash flows for each of the years in the three‑yearthree-year period ended December 31, 2017,2023, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’sCompany's internal control over financial reporting as of December 31, 2017,2023, based on criteria established in Internal Control -– Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 1, 2018February 28, 2024 expressed an unqualified opinion on the effectiveness of the Company’sCompany's internal control over financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’sCompany's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
(signed)The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Evaluation of the sufficiency of audit evidence over revenues
As discussed in Note 3 to the consolidated financial statements, the Company had $28,823 million of revenues. Revenue is derived from various revenue streams in different geographic markets and the Company’s processes and related information technology (IT) systems used to record revenue differ for each of these revenue streams.
We identified the evaluation of the sufficiency of audit evidence over revenues as a critical audit matter which required a high degree of auditor judgment due to the number of revenue streams and IT systems involved in the revenue recognition process. This included determining the revenue streams over which procedures were to be performed and evaluating the nature and extent of evidence obtained over the individual revenue streams as well as revenue in the aggregate. It also included the involvement of IT professionals with specialized skills and knowledge to assist in the performance of certain procedures.
The following are the primary procedures we performed to address this critical audit matter. We, with the assistance of IT professionals, applied auditor judgment to determine the revenue streams over which procedures were performed as well as the nature and extent of such procedures. For certain revenue streams over which procedures were performed,
we evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s revenue recognition processes. For certain revenue streams, we involved IT professionals, who assisted in testing certain IT applications used by the Company in its revenue recognition processes. In addition, we assessed recorded revenue for a selection of transactions by comparing the amounts recognized to underlying documentation, including contracts with customers, and for certain revenue streams, we performed a software-assisted data analysis to assess certain relationships among revenue transactions. In addition, we evaluated the sufficiency of audit evidence obtained over revenues by assessing the results of procedures performed, including the appropriateness of such evidence.
Fair value of certain acquired intangible assets
As discussed in Note 4 to the consolidated financial statements, the Company acquired Vivint Smart Home, Inc. on March 10, 2023 for total consideration of $2,623 million. In connection with the business combination, the Company recorded various intangible assets, which included customer relationships and technology intangible assets with an acquisition-date fair value of $1,740 million and $860 million, respectively.
We identified the evaluation of the acquisition-date fair value of the customer relationships and technology intangible assets as a critical audit matter. A high degree of subjective and complex auditor judgment was required to evaluate key assumptions used to value these acquired intangible assets. We performed sensitivity analyses to determine the key assumptions used to value the intangible assets acquired which required challenging auditor judgment. Specifically, key assumptions included the customer attrition for the customer relationships intangible asset and the discount rate for the customer relationships and technology intangible assets. Changes to these assumptions could have had a significant impact on the fair value of such assets. In addition, valuation professionals with specialized skills and knowledge were needed to assist in the evaluation of the discount rate.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the Company’s acquisition-date valuation process, including controls related to the selection of the customer attrition used in the customer relationships intangible asset and the discount rate used in the customer relationships and technology intangible assets. We evaluated the customer attrition used by the Company by comparing it to historical attrition experienced by the acquired company and comparable company attrition. We involved valuation professionals with specialized skills and knowledge, who assisted in evaluating the discount rate by assessing the relative risk profile of the customer relationships and technology intangible assets compared to the required rate of return of all acquired assets in the business combination.
/s/ KPMG LLP
We have served as the Company's auditor since 2004.
Philadelphia, Pennsylvania
March 1, 2018February 28, 2024
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
|
| | | | | | | | | | | |
| | For the Year Ended December 31, |
| (In millions, except per share amounts) | 2017 | | 2016 | | 2015 |
| Operating Revenues |
| | | | |
| Total operating revenues | $ | 10,629 |
| | $ | 10,512 |
| | $ | 12,328 |
|
| Operating Costs and Expenses |
| | | | |
| Cost of operations | 7,536 |
| | 7,301 |
| | 9,000 |
|
| Depreciation and amortization | 1,056 |
| | 1,172 |
| | 1,351 |
|
| Impairment losses | 1,709 |
| | 702 |
| | 4,860 |
|
| Selling, general and administrative | 907 |
| | 1,095 |
| | 1,228 |
|
| Reorganization costs | 44 |
| | — |
| | — |
|
| Development costs | 67 |
| | 89 |
| | 154 |
|
| Total operating costs and expenses | 11,319 |
| | 10,359 |
| | 16,593 |
|
| Other income - affiliate | 87 |
| | 193 |
| | 193 |
|
| Gain/(loss) on sale of assets | 16 |
| | (80 | ) | | — |
|
| Gain on postretirement benefits curtailment | — |
| | — |
| | 21 |
|
| Operating (Loss)/Income | (587 | ) | | 266 |
| | (4,051 | ) |
| Other Income/(Expense) |
| | | | |
| Equity in earnings of unconsolidated affiliates | 31 |
| | 27 |
| | 36 |
|
| Impairment losses on investments | (79 | ) | | (268 | ) | | (56 | ) |
| Other income, net | 38 |
| | 34 |
| | 26 |
|
| Loss on sale of equity method investment | — |
| | — |
| | (14 | ) |
| Net (loss)/gain on debt extinguishment | (53 | ) | | (142 | ) | | 10 |
|
| Interest expense | (890 | ) | | (895 | ) | | (937 | ) |
| Total other expense | (953 | ) | | (1,244 | ) | | (935 | ) |
| Loss from Continuing Operations Before Income Taxes | (1,540 | ) | | (978 | ) | | (4,986 | ) |
| Income tax expense | 8 |
| | 5 |
| | 1,345 |
|
| Net Loss from Continuing Operations | (1,548 | ) | | (983 | ) | | (6,331 | ) |
| (Loss)/income from discontinued operations, net of income tax | (789 | ) | | 92 |
| | (105 | ) |
| Net Loss | (2,337 | ) | | (891 | ) | | (6,436 | ) |
| Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests | (184 | ) | | (117 | ) | | (54 | ) |
| Net Loss Attributable to NRG Energy, Inc. | (2,153 | ) | | (774 | ) | | (6,382 | ) |
| Dividends for preferred shares | — |
| | 5 |
| | 20 |
|
| Gain on redemption of preferred shares | — |
| | (78 | ) | | — |
|
| Loss Available for Common Stockholders | $ | (2,153 | ) | | $ | (701 | ) | | $ | (6,402 | ) |
| Loss Per Share Attributable to NRG Energy, Inc. Common Stockholders | | | | | |
| Weighted average number of common shares outstanding — basic and diluted | 317 |
| | 316 |
| | 329 |
|
| Loss from continuing operations per weighted average common share — basic and diluted | $ | (4.30 | ) |
| $ | (2.51 | ) |
| $ | (19.14 | ) |
| (Loss)/Income from discontinued operations per weighted average common share — basic and diluted | $ | (2.49 | ) |
| $ | 0.29 |
|
| $ | (0.32 | ) |
| Net Loss per Weighted Average Common Share — Basic and Diluted | $ | (6.79 | ) | | $ | (2.22 | ) | | $ | (19.46 | ) |
| Dividends Per Common Share | $ | 0.12 |
|
| $ | 0.24 |
|
| $ | 0.58 |
|
| | | | | | | | | | | | | | | | | |
| | For the Year Ended December 31, |
| (In millions, except per share amounts) | 2023 | | 2022 | | 2021 |
| Revenue | | | | | |
| Revenue | $ | 28,823 | | | $ | 31,543 | | | $ | 26,989 | |
| Operating Costs and Expenses | | | | | |
| Cost of operations (excluding depreciation and amortization shown below) | 26,526 | | | 27,446 | | | 20,482 | |
| Depreciation and amortization | 1,127 | | | 634 | | | 785 | |
| Impairment losses | 26 | | | 206 | | | 544 | |
| Selling, general and administrative costs | 1,968 | | | 1,228 | | | 1,293 | |
| Provision for credit losses | 251 | | | 11 | | | 698 | |
| Acquisition-related transaction and integration costs | 119 | | | 52 | | | 93 | |
| Total operating costs and expenses | 30,017 | | | 29,577 | | | 23,895 | |
| | | | | |
| Gain on sale of assets | 1,578 | | | 52 | | | 247 | |
| Operating Income | 384 | | | 2,018 | | | 3,341 | |
| Other Income/(Expense) | | | | | |
| Equity in earnings of unconsolidated affiliates | 16 | | | 6 | | | 17 | |
| Impairment losses on investments | (102) | | | — | | | — | |
| Other income, net | 47 | | | 56 | | | 63 | |
| | | | | |
| Gain/(Loss) on debt extinguishment | 109 | | | — | | | (77) | |
| Interest expense | (667) | | | (417) | | | (485) | |
| Total other expense | (597) | | | (355) | | | (482) | |
| (Loss)/Income Before Income Taxes | (213) | | | 1,663 | | | 2,859 | |
| Income tax (benefit)/expense | (11) | | | 442 | | | 672 | |
| | | | | |
| | | | | |
| Net (Loss)/Income | (202) | | | 1,221 | | | 2,187 | |
| Less: Cumulative dividends attributable to Series A Preferred Stock | 54 | | | — | | | — | |
| Net (Loss)/Income Available for Common Stockholders | $ | (256) | | | $ | 1,221 | | | $ | 2,187 | |
| (Loss)/Income Per Share | | | | | |
| Weighted average number of common shares outstanding — basic and diluted | 228 | | | 236 | | | 245 | |
| | | | | |
| | | | | |
| (Loss)/Income per Weighted Average Common Share — Basic and Diluted | $ | (1.12) | | | $ | 5.17 | | | $ | 8.93 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
See notes to Consolidated Financial Statements.Statements
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS)/INCOME
|
| | | | | | | | | | | |
| | For the Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In millions) |
| Net Loss | $ | (2,337 | ) |
| $ | (891 | ) |
| $ | (6,436 | ) |
| Other Comprehensive Income, net of tax |
| | | | |
| Unrealized gain/(loss) on derivatives, net of income tax expense of $1, $1, and $19 | 13 |
| | 35 |
| | (15 | ) |
| Foreign currency translation adjustments, net of income tax benefit of $(2), $0, and $0 | 12 |
| | (1 | ) | | (11 | ) |
| Available-for-sale securities, net of income tax expense/(benefit) of $10, $0, and $(3) | (8 | ) | | 1 |
| | 17 |
|
| Defined benefit plan, net of income tax (benefit)/expense of $(21), $0 and $69 | 46 |
| | 3 |
| | 10 |
|
| Other comprehensive income | 63 |
| | 38 |
| | 1 |
|
| Comprehensive Loss | (2,274 | ) | | (853 | ) | | (6,435 | ) |
| Less: Comprehensive loss attributable to noncontrolling interests and redeemable noncontrolling interests | (179 | ) | | (117 | ) | | (73 | ) |
| Comprehensive Loss Attributable to NRG Energy, Inc. | (2,095 | ) | | (736 | ) | | (6,362 | ) |
| Dividends for preferred shares | — |
|
| 5 |
|
| 20 |
|
| Gain on redemption of preferred shares | — |
| | (78 | ) | | — |
|
| Comprehensive Loss Available for Common Stockholders | $ | (2,095 | ) | | $ | (663 | ) | | $ | (6,382 | ) |
| | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, |
| (In millions) | 2023 | | 2022 | | 2021 |
| Net (Loss)/Income | $ | (202) | | | $ | 1,221 | | | $ | 2,187 | |
| Other Comprehensive Income/(Loss), net of tax | | | | | |
| | | | | |
| Foreign currency translation adjustments | 9 | | | (35) | | | (5) | |
| | | | | |
| Defined benefit plans | 30 | | | (16) | | | 85 | |
| Other comprehensive income/(loss) | 39 | | | (51) | | | 80 | |
| Comprehensive (Loss)/Income | $ | (163) | | | $ | 1,170 | | | $ | 2,267 | |
| | | | | |
| | | | | |
See notes to Consolidated Financial Statements.Statements
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS | | | | | | | | | | | |
| | As of December 31, |
| (In millions) | 2023 | | 2022 |
| ASSETS | | | |
| Current Assets | | | |
| Cash and cash equivalents | $ | 541 | | | $ | 430 | |
| Funds deposited by counterparties | 84 | | | 1,708 | |
| Restricted cash | 24 | | | 40 | |
| Accounts receivable, net | 3,542 | | | 4,773 | |
| | | |
| Inventory | 607 | | | 751 | |
| Derivative instruments | 3,862 | | | 7,886 | |
| Cash collateral paid in support of energy risk management activities | 441 | | | 260 | |
| | | |
| Prepayments and other current assets | 626 | | | 383 | |
| | | |
| | | |
| Total current assets | 9,727 | | | 16,231 | |
| Property, plant and equipment, net | 1,763 | | | 1,692 | |
| Other Assets | | | |
| Equity investments in affiliates | 42 | | | 133 | |
| Operating lease right-of-use assets, net | 179 | | | 225 | |
| | | |
| Goodwill | 5,079 | | | 1,650 | |
| Customer relationships, net | 2,164 | | | 943 | |
| Other intangible assets, net | 1,763 | | | 1,189 | |
| Nuclear decommissioning trust fund | — | | | 838 | |
| Derivative instruments | 2,293 | | | 4,108 | |
| Deferred income taxes | 2,251 | | | 1,881 | |
| Other non-current assets | 777 | | | 256 | |
| | | |
| | | |
| Total other assets | 14,548 | | | 11,223 | |
| Total Assets | $ | 26,038 | | | $ | 29,146 | |
|
| | | | | | | |
| | As of December 31, |
| | 2017 | | 2016 |
| | (In millions) |
| ASSETS | | | |
| Current Assets | | | |
| Cash and cash equivalents | $ | 991 |
|
| $ | 938 |
|
| Funds deposited by counterparties | 37 |
| | 2 |
|
| Restricted cash | 508 |
| | 446 |
|
| Accounts receivable — trade | 1,079 |
| | 1,058 |
|
| Inventory | 532 |
|
| 721 |
|
| Derivative instruments | 626 |
| | 1,067 |
|
| Cash collateral posted in support of energy risk management activities | 171 |
| | 150 |
|
| Accounts receivable — affiliate | 95 |
|
| — |
|
| Current assets held-for-sale | 115 |
|
| 9 |
|
| Prepayments and other current assets | 261 |
|
| 404 |
|
| Current assets - discontinued operations | — |
|
| 1,919 |
|
| Total current assets | 4,415 |
| | 6,714 |
|
| Property, plant and equipment, net | 13,908 |
|
| 15,369 |
|
| Other Assets | | | |
| Equity investments in affiliates | 1,038 |
| | 1,120 |
|
| Notes receivable, less current portion | 2 |
|
| 16 |
|
| Goodwill | 539 |
| | 662 |
|
| Intangible assets, net | 1,746 |
|
| 1,973 |
|
| Nuclear decommissioning trust fund | 692 |
| | 610 |
|
| Derivative instruments | 172 |
| | 181 |
|
| Deferred income taxes | 134 |
|
| 225 |
|
| Non-current assets held-for-sale | 43 |
| | 10 |
|
| Other non-current assets | 629 |
| | 841 |
|
| Non-current assets - discontinued operations | — |
|
| 2,961 |
|
| Total other assets | 4,995 |
| | 8,599 |
|
| Total Assets | $ | 23,318 |
| | $ | 30,682 |
|
See notes to Consolidated Financial Statements.
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Continued) |
| | | | | | | |
| | As of December 31, |
| | 2017 | | 2016 |
| | (In millions, except share data) |
| LIABILITIES AND STOCKHOLDERS' EQUITY | | | |
| Current Liabilities | | | |
| Current portion of long-term debt and capital leases | $ | 688 |
|
| $ | 516 |
|
| Accounts payable | 881 |
| | 782 |
|
| Accounts payable - affiliate | 33 |
|
| 31 |
|
| Derivative instruments | 555 |
|
| 1,092 |
|
| Cash collateral received in support of energy risk management activities | 37 |
| | 81 |
|
| Accrued interest expense | 156 |
| | 180 |
|
| Current liabilities - held for sale | 72 |
|
| — |
|
| Other accrued expenses and other current liabilities | 734 |
| | 810 |
|
| Other accrued expenses and other current liabilities - affiliate | 161 |
| | — |
|
| Current liabilities - discontinued operations | — |
| | 1,210 |
|
| Total current liabilities | 3,317 |
| | 4,702 |
|
| Other Liabilities | | | |
| Long-term debt and capital leases | 15,716 |
|
| 15,957 |
|
| Nuclear decommissioning reserve | 269 |
| | 287 |
|
| Nuclear decommissioning trust liability | 415 |
| | 339 |
|
| Postretirement and other benefit obligations | 458 |
| | 510 |
|
| Deferred income taxes | 21 |
|
| 20 |
|
| Derivative instruments | 197 |
|
| 284 |
|
| Out-of-market contracts, net | 207 |
| | 230 |
|
| Non-current liabilities held-for-sale | 8 |
| | 11 |
|
| Other non-current liabilities | 664 |
| | 666 |
|
| Non-current liabilities - discontinued operations | — |
|
| 3,184 |
|
| Total non-current liabilities | 17,955 |
| | 21,488 |
|
| Total Liabilities | 21,272 |
| | 26,190 |
|
| Redeemable noncontrolling interest in subsidiaries | 78 |
| | 46 |
|
| Commitments and Contingencies |
| |
|
| Stockholders' Equity | | | |
| Common stock; $0.01 par value; 500,000,000 shares authorized; 418,323,134 and 417,583,825 shares issued; and 316,743,089 and 315,443,011 shares outstanding at December 31, 2017 and 2016 | 4 |
| | 4 |
|
| Additional paid-in capital | 8,376 |
| | 8,358 |
|
| Accumulated deficit | (6,268 | ) | | (3,787 | ) |
| Treasury stock, at cost; 101,580,045 and 102,140,814 shares at December 31, 2017 and 2016 | (2,386 | ) | | (2,399 | ) |
| Accumulated other comprehensive loss | (72 | ) | | (135 | ) |
| Noncontrolling interest | 2,314 |
| | 2,405 |
|
| Total Stockholders' Equity | 1,968 |
| | 4,446 |
|
| Total Liabilities and Stockholders' Equity | $ | 23,318 |
| | $ | 30,682 |
|
| | | | | | | | | | | |
| | As of December 31, |
| (In millions, except share data) | 2023 | | 2022 |
| LIABILITIES AND STOCKHOLDERS' EQUITY | | | |
| Current Liabilities | | | |
| Current portion of long-term debt and finance leases | $ | 620 | | | $ | 63 | |
| Current portion of operating lease liabilities | 90 | | | 83 | |
| Accounts payable | 2,325 | | | 3,643 | |
| | | |
| Derivative instruments | 4,019 | | | 6,195 | |
| Cash collateral received in support of energy risk management activities | 84 | | | 1,708 | |
| Deferred revenue current | 720 | | | 176 | |
| Accrued expenses and other current liabilities | 1,642 | | | 1,114 | |
| | | |
| | | |
| | | |
| Total current liabilities | 9,500 | | | 12,982 | |
| Other Liabilities | | | |
| Long-term debt and finance leases | 10,133 | | | 7,976 | |
| Non-current operating lease liabilities | 128 | | | 180 | |
| Nuclear decommissioning reserve | — | | | 340 | |
| Nuclear decommissioning trust liability | — | | | 477 | |
| | | |
| Derivative instruments | 1,488 | | | 2,246 | |
| Deferred income taxes | 22 | | | 134 | |
| Deferred revenue non-current | 914 | | | 10 | |
| Other non-current liabilities | 947 | | | 973 | |
| | | |
| | | |
| Total other liabilities | 13,632 | | | 12,336 | |
| Total Liabilities | 23,132 | | | 25,318 | |
| | | |
| Commitments and Contingencies | | | |
| Stockholders' Equity | | | |
| Preferred stock; 10,000,000 shares authorized; 650,000 Series A shares issued and outstanding at December 31, 2023 (aggregate liquidation preference $650); 0 shares issued and outstanding at December 31, 2022 | 650 | | | — | |
| Common stock; $0.01 par value; 500,000,000 shares authorized; 267,330,470 and 423,897,001 shares issued; and 208,130,950 and 229,561,030 shares outstanding at December 31, 2023 and 2022, respectively | 3 | | | 4 | |
| Additional paid-in capital | 3,416 | | | 8,457 | |
| Retained earnings | 820 | | | 1,408 | |
| Treasury stock, at cost; 59,199,520 and 194,335,971 shares at December 31, 2023 and 2022, respectively | (1,892) | | | (5,864) | |
| Accumulated other comprehensive loss | (91) | | | (177) | |
| Total Stockholders' Equity | 2,906 | | | 3,828 | |
| Total Liabilities and Stockholders' Equity | $ | 26,038 | | | $ | 29,146 | |
See notes to Consolidated Financial Statements.Statements
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS | | | | | | | | | | | | | | | | | |
| | For the Year Ended December 31, |
| (In millions) | 2023 | | 2022 | | 2021 |
| Cash Flows from Operating Activities | | | | | |
| Net (loss)/income | $ | (202) | | | $ | 1,221 | | | $ | 2,187 | |
| | | | | |
| | | | | |
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| Equity in and distributions from (earnings)/losses of unconsolidated affiliates | (6) | | | 7 | | | 20 | |
| Depreciation and amortization | 1,127 | | | 634 | | | 785 | |
| Accretion of asset retirement obligations | 27 | | | 55 | | | 30 | |
| Provision for credit losses | 251 | | | 11 | | | 698 | |
| Amortization of nuclear fuel | 47 | | | 54 | | | 51 | |
| Amortization of financing costs and debt discounts | 52 | | | 23 | | | 39 | |
| (Gain)/Loss on debt extinguishment | (109) | | | — | | | 77 | |
| Amortization of in-the-money contracts and emissions allowances | 137 | | | 158 | | | 106 | |
| Amortization of unearned equity compensation | 101 | | | 28 | | | 21 | |
| Net gain on sale of assets and disposal of assets | (1,559) | | | (102) | | | (261) | |
| | | | | |
| Impairment losses | 128 | | | 206 | | | 544 | |
| Changes in derivative instruments | 2,455 | | | (3,221) | | | (3,626) | |
| Changes in deferred income taxes and liability for uncertain tax benefits | (92) | | | 382 | | | 604 | |
| | | | | |
| Changes in collateral deposits in support of risk management activities | (1,806) | | | 896 | | | 797 | |
| | | | | |
| Changes in nuclear decommissioning trust liability | — | | | 9 | | | 40 | |
| | | | | |
| Uplift securitization proceeds received/(receivable) from ERCOT | — | | | 689 | | | (689) | |
| | | | | |
| | | | | |
| Cash (used)/provided by changes in other working capital, net of acquisition and disposition effects: | | | | | |
| Accounts receivable - trade | 840 | | | (1,560) | | | (1,232) | |
| Inventory | 189 | | | (252) | | | (61) | |
| Prepayments and other current assets | (233) | | | 17 | | | 31 | |
| Accounts payable | (1,455) | | | 1,295 | | | 476 | |
| Accrued expenses and other current liabilities | 360 | | | (29) | | | (55) | |
| Other assets and liabilities | (473) | | | (161) | | | (89) | |
| Cash (used)/provided by operating activities | $ | (221) | | | $ | 360 | | | $ | 493 | |
| | | | | |
| | | | | |
| Cash Flows from Investing Activities | | | | | |
| Payments for acquisitions of businesses and assets, net of cash acquired | $ | (2,523) | | | $ | (62) | | | $ | (3,559) | |
| Capital expenditures | (598) | | | (367) | | | (269) | |
| | | | | |
| | | | | |
| Net purchases of emissions allowances | (24) | | | (6) | | | — | |
| Investments in nuclear decommissioning trust fund securities | (367) | | | (454) | | | (751) | |
| Proceeds from sales of nuclear decommissioning trust fund securities | 355 | | | 448 | | | 710 | |
| Proceeds from sale of assets, net of cash disposed | 2,007 | | | 109 | | | 830 | |
| Proceeds from insurance recoveries for property, plant and equipment, net | 240 | | | — | | | — | |
| | | | | |
| | | | | |
| | | | | |
| Cash used by investing activities | $ | (910) | | | $ | (332) | | | $ | (3,039) | |
| | | | | |
| | | | | |
| | | | | |
|
| | | | | | | | | | | |
| | For the Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In millions) |
| Cash Flows from Operating Activities | | | | |
|
| Net loss | (2,337 | ) |
| (891 | ) |
| (6,436 | ) |
| (Loss)/income from discontinued operations, net of income tax | (789 | ) |
| 92 |
|
| (105 | ) |
| Loss from continuing operations | $ | (1,548 | ) |
| $ | (983 | ) |
| $ | (6,331 | ) |
| Adjustments to reconcile net income/(loss) to net cash provided by operating activities: | | | | | |
| Equity in earnings and distribution of unconsolidated affiliates | 55 |
|
| 54 |
| | 37 |
|
| Depreciation and amortization | 1,056 |
| | 1,172 |
| | 1,351 |
|
| Provision for bad debts | 68 |
| | 48 |
| | 64 |
|
| Amortization of nuclear fuel | 51 |
| | 49 |
| | 45 |
|
| Amortization of financing costs and debt discount/premiums | 60 |
| | 55 |
| | 47 |
|
| Adjustment for debt extinguishment | 53 |
| | 142 |
| | (10 | ) |
| Amortization of intangibles and out-of-market contracts | 108 |
| | 167 |
| | 151 |
|
| Amortization of unearned equity compensation | 35 |
| | 10 |
| | 39 |
|
| Net (gain)/loss on sale of assets and equity method investments | (34 | ) | | 70 |
| | 14 |
|
| Gain on post retirement benefits curtailment | — |
|
| — |
|
| (21 | ) |
| Impairment losses | 1,788 |
| | 972 |
| | 4,916 |
|
| Changes in derivative instruments | (171 | ) | | 32 |
| | 235 |
|
| Changes in deferred income taxes and liability for uncertain tax benefits | 91 |
| | (43 | ) | | 1,326 |
|
| Changes in collateral deposits in support of risk management activities | (80 | ) | | 398 |
| | (334 | ) |
| Proceeds from sale of emission allowances | 25 |
|
| 34 |
|
| (24 | ) |
| Changes in nuclear decommissioning trust liability | 11 |
| | 41 |
| | (2 | ) |
| Cash provided/(used) by changes in other working capital, net of acquisition and disposition effects: | | | | | |
| Accounts receivable - trade | (99 | ) | | (7 | ) | | 113 |
|
| Inventory | 143 |
| | 71 |
| | (59 | ) |
| Prepayments and other current assets | 12 |
| | (44 | ) | | (21 | ) |
| Accounts payable | 77 |
| | (39 | ) | | (180 | ) |
| Accrued expenses and other current liabilities | (60 | ) | | (35 | ) | | (29 | ) |
| Other assets and liabilities | (216 | ) | | 43 |
| | (40 | ) |
| Cash provided by continuing operations | 1,425 |
|
| 2,207 |
|
| 1,287 |
|
| Cash (used)/provided by discontinued operations | (38 | ) |
| (119 | ) |
| 62 |
|
| Net Cash Provided by Operating Activities | 1,387 |
| | 2,088 |
| | 1,349 |
|
| Cash Flows from Investing Activities |
| | | | |
| Acquisition of businesses, net of cash acquired | (41 | ) | | (209 | ) | | (31 | ) |
| Capital expenditures | (1,111 | ) | | (976 | ) | | (1,029 | ) |
| Net cash proceeds from notes receivable | 17 |
| | 17 |
| | 18 |
|
| Proceeds from renewable energy grants | 8 |
| | 36 |
| | 82 |
|
| Proceeds from/(purchases) of emission allowances, net of purchases | 66 |
| | (1 | ) | | 41 |
|
| Investments in nuclear decommissioning trust fund securities | (512 | ) | | (551 | ) | | (629 | ) |
| Proceeds from sales of nuclear decommissioning trust fund securities | 501 |
| | 510 |
| | 631 |
|
| Proceeds from sale of assets, net | 87 |
| | 73 |
| | 27 |
|
| Investments in unconsolidated affiliates | (40 | ) | | (23 | ) | | (395 | ) |
| Other | 12 |
| | 35 |
| | 16 |
|
| Cash used by continuing operations | (1,013 | ) |
| (1,089 | ) |
| (1,269 | ) |
| Cash (used)/provided by discontinued operations | (53 | ) |
| 297 |
|
| (259 | ) |
| Net Cash Used by Investing Activities | (1,066 | ) |
| (792 | ) |
| (1,528 | ) |
| Cash Flows from Financing Activities | | | | | |
| Payments of dividends to preferred and common stockholders | (38 | ) | | (76 | ) | | (201 | ) |
| Net receipts from settlement of acquired derivatives that include financing elements | 2 |
| | 6 |
| | 14 |
|
| Payments for treasury stock | — |
| | — |
| | (437 | ) |
| Payments for preferred shares | — |
|
| (226 | ) |
| — |
|
| Payments for debt extinguishment costs | (42 | ) |
| (121 | ) |
| — |
|
| Distributions to, net of contributions from, noncontrolling interests in subsidiaries | 95 |
| | (156 | ) | | 47 |
|
| Proceeds from sale of noncontrolling interests in subsidiaries | — |
|
| — |
|
| 600 |
|
| (Payments)/Proceeds from issuance of common stock | (2 | ) | | 1 |
| | 1 |
|
| Proceeds from issuance of long-term debt | 2,270 |
| | 5,527 |
| | 1,004 |
|
| Payments of debt issuance and hedging costs | (63 | ) | | (89 | ) | | (21 | ) |
| Payments for short and long-term debt | (2,348 | ) | | (5,908 | ) | | (1,362 | ) |
| Receivable from affiliate | (125 | ) |
| — |
|
| — |
|
| Other | (10 | ) | | (13 | ) | | (22 | ) |
| Cash used by continuing operations | (261 | ) |
| (1,055 | ) |
| (377 | ) |
| Cash (used)/provided by discontinued operations | (224 | ) |
| 140 |
|
| (55 | ) |
| Net Cash Used by Financing Activities | (485 | ) |
| (915 | ) |
| (432 | ) |
| Effect of exchange rate changes on cash and cash equivalents | (1 | ) | | 1 |
| | 10 |
|
| Change in Cash from discontinued operations | (315 | ) |
| 318 |
|
| (252 | ) |
| Net Increase/(Decrease) in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash | 150 |
|
| 64 |
|
| (349 | ) |
| Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period | 1,386 |
|
| 1,322 |
|
| 1,671 |
|
| Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period | $ | 1,536 |
|
| $ | 1,386 |
|
| $ | 1,322 |
|
| | | | | | | | | | | | | | | | | |
| | For the Year Ended December 31, |
| (In millions) | 2023 | | 2022 | | 2021 |
| Cash Flows from Financing Activities | | | | | |
| Proceeds from issuance of preferred stock, net of fees | $ | 635 | | | $ | — | | | $ | — | |
| Net receipts from settlement of acquired derivatives that include financing elements | 342 | | | 1,995 | | | 938 | |
Payments for share repurchase activity(a) | (1,172) | | | (606) | | | (48) | |
| Payments of dividends to preferred and common stockholders | (381) | | | (332) | | | (319) | |
| Proceeds from issuance of long-term debt | 731 | | | — | | | 1,100 | |
| Payments for short and long-term debt | (523) | | | (5) | | | (1,861) | |
| | | | | |
| Payments for debt extinguishment costs | — | | | — | | | (65) | |
| Payments of debt issuance costs | (32) | | | (9) | | | (18) | |
| Proceeds from issuance of common stock | — | | | — | | | 1 | |
| Proceeds from credit facilities | 3,020 | | | — | | | 1,415 | |
| Repayments to credit facilities | (3,020) | | | — | | | (1,415) | |
| | | | | |
| | | | | |
| Cash (used)/provided by financing activities | $ | (400) | | | $ | 1,043 | | | $ | (272) | |
| | | | | |
| | | | | |
| Effect of exchange rate changes on cash and cash equivalents | 2 | | | (3) | | | (2) | |
| | | | | |
| Net (Decrease)/Increase in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash | (1,529) | | | 1,068 | | | (2,820) | |
| Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period | 2,178 | | | 1,110 | | | 3,930 | |
| Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period | $ | 649 | | | $ | 2,178 | | | $ | 1,110 | |
(a)Includes $(22) million, $(6) million and $(9) million of equivalent shares purchased in lieu of tax withholdings on equity compensation issuances for the years ended December 31, 2023, 2022 and 2021, respectively
For further discussion of supplemental cash flow information see Note 26, Cash Flow Information
See notes to Consolidated Financial Statements.Statements
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTSTATEMENTS OF STOCKHOLDERS' EQUITY | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Preferred Stock | | Common
Stock | | Additional
Paid-In
Capital | | (Accumulated Deficit)/Retained Earnings | | Treasury
Stock | | Accumulated
Other
Comprehensive
Loss | | Total
Stock-holders'
Equity |
| | | | | | | | | | | | | |
| Balance at December 31, 2020 | $ | — | | | $ | 4 | | | $ | 8,517 | | | $ | (1,403) | | | $ | (5,232) | | | $ | (206) | | | $ | 1,680 | |
| Net income | | | | | | | 2,187 | | | | | | | 2,187 | |
| Other comprehensive income | | | | | | | | | | | 80 | | | 80 | |
| | | | | | | | | | | | | |
| Shares reissuance for ESPP | | | | | 1 | | | | | 3 | | | | | 4 | |
| Share repurchases | | | | | | | | | (44) | | | | | (44) | |
Equity-based awards activity, net(a) | | | | | 12 | | | | | | | | | 12 | |
| Issuance of common stock | | | | | 1 | | | | | | | | | 1 | |
Common stock dividends and dividend equivalents declared(b) | | | | | | | (320) | | | | | | | (320) | |
| Balance at December 31, 2021 | $ | — | | | $ | 4 | | | $ | 8,531 | | | $ | 464 | | | $ | (5,273) | | | $ | (126) | | | $ | 3,600 | |
| Net income | | | | | | | 1,221 | | | | | | | 1,221 | |
| Other comprehensive loss | | | | | | | | | | | (51) | | | (51) | |
| | | | | | | | | | | | | |
| Shares reissuance for ESPP | | | | | 2 | | | | | 4 | | | | | 6 | |
| Share repurchases | | | | | | | | | (595) | | | | | (595) | |
Equity-based awards activity, net(a) | | | | | 24 | | | | | | | | | 24 | |
| | | | | | | | | | | | | |
Common stock dividends and dividend equivalents declared(b) | | | | | | | (334) | | | | | | | (334) | |
Adoption of ASU 2020-06 | | | | | $ | (100) | | | 57 | | | | | | | (43) | |
| Balance at December 31, 2022 | $ | — | | | $ | 4 | | | $ | 8,457 | | | $ | 1,408 | | | $ | (5,864) | | | $ | (177) | | | $ | 3,828 | |
| Net loss | | | | | | | (202) | | | | | | | (202) | |
| Issuance of Series A Preferred Stock | 650 | | | | | (15) | | | | | | | | | 635 | |
| Other comprehensive income | | | | | | | | | | | 39 | | | 39 | |
| Shares reissuance for ESPP | | | | | 2 | | | | | 6 | | | | | 8 | |
Share repurchases(c) | | | | | (117) | | | | | (1,043) | | | | | (1,160) | |
| Retirement of treasury stock | | | (1) | | | (5,008) | | | | | 5,009 | | | | | — | |
Equity-based awards activity, net(a) | | | | | 97 | | | | | | | | | 97 | |
Common stock dividends and dividend equivalents declared(b) | | | | | | | (352) | | | | | | | (352) | |
Series A Preferred Stock dividends(d) | | | | | | | (34) | | | | | | | (34) | |
| Sale of the 44% equity interest in STP | | | | | | | | | | | 47 | | | 47 | |
| Balance at December 31, 2023 | $ | 650 | | | $ | 3 | | | $ | 3,416 | | | $ | 820 | | | $ | (1,892) | | | $ | (91) | | | $ | 2,906 | |
(a)Includes $(22) million, $(6) million and $(9) million of equivalent shares purchased in lieu of tax withholding on equity compensation issuances for the years ended December 31, 2023, 2022 and 2021, respectively |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Common Stock | | Additional Paid-In Capital | | Retained Earnings/ (Accumu-lated Deficit) | | Treasury Stock | | Accumulated Other Comprehensive Income/(Loss) | | Noncon- trolling Interest | | Total Stock-holders' Equity |
| | (In millions) |
| Balances at December 31, 2014 | $ | 4 |
| | $ | 8,327 |
| | $ | 3,588 |
| | $ | (1,983 | ) | | $ | (174 | ) | | $ | 1,914 |
| | 11,676 |
|
| Net loss | | | | | (6,382 | ) | | | | | | (37 | ) | | (6,419 | ) |
| Other comprehensive income/(loss) | | | | | | | | | 1 |
| | (4 | ) | | (3 | ) |
| Sale of assets to NRG Yield, Inc. | | | (56 | ) | | | | | | | | 83 |
| | 27 |
|
| ESPP share purchases | | | (1 | ) | | | | 7 |
| | | | | | 6 |
|
| Equity-based compensation | | | 26 |
| | (2 | ) | | | | | | | | 24 |
|
| Purchase of treasury stock | | | | | | | (437 | ) | | | | | | (437 | ) |
| Common stock dividends | | | | | (191 | ) | | | | | | | | (191 | ) |
| Preferred stock dividends | | | | | (20 | ) | | | | | | | | (20 | ) |
| Distributions to noncontrolling interests | | | | | | | | | | | (159 | ) | | (159 | ) |
| Contributions from noncontrolling interests | | | | |
|
| |
|
| | | | 234 |
| | 234 |
|
| Acquisition of noncontrolling interests by NRG Yield, Inc. | | |
|
| | | | | | | | 74 |
| | 74 |
|
| Impact of NRG Yield, Inc. public offering | | | | |
|
| | | | | | 599 |
| | 599 |
|
| Equity component of NRG Yield, Inc. convertible notes | | | | | | | | | | | 23 |
| | 23 |
|
| Balances at December 31, 2015 | $ | 4 |
| | $ | 8,296 |
| | $ | (3,007 | ) | | $ | (2,413 | ) | | $ | (173 | ) | | $ | 2,727 |
| | $ | 5,434 |
|
| Net loss | | | | | (774 | ) | | | | | | (79 | ) | | (853 | ) |
| Other comprehensive income | | | | | | | | | 38 |
| | | | 38 |
|
| Sale of assets to NRG Yield, Inc. | | | 59 |
| | | | | | | | (16 | ) | | 43 |
|
| ESPP share purchases | | | (2 | ) | | (6 | ) | | 14 |
| | | | | | 6 |
|
| Equity-based compensation | | | 5 |
| | 1 |
| | | | | | | | 6 |
|
| Common stock dividends | | | | | (74 | ) | | | | | | | | (74 | ) |
| Dividend for preferred shares | | | | | (5 | ) | | | | | | | | (5 | ) |
| Gain on redemption of preferred shares | | | | | 78 |
| | | | | | | | 78 |
|
| Distributions to noncontrolling interests | | | | | | | | | | | (158 | ) | | (158 | ) |
| Dividends paid to NRG Yield, Inc. | | | | | | | | | | | (92 | ) | | (92 | ) |
| Contributions from noncontrolling interests | | | | | | | | | | | 30 |
| | 30 |
|
| Redemption of noncontrolling interests | | | | | | | | | | | (7 | ) | | (7 | ) |
| Balances at December 31, 2016 | $ | 4 |
| | $ | 8,358 |
| | $ | (3,787 | ) | | $ | (2,399 | ) | | $ | (135 | ) | | $ | 2,405 |
| | $ | 4,446 |
|
| Net loss | | | | | (2,153 | ) | | | | | | (98 | ) | | (2,251 | ) |
| Other comprehensive income | | | | | | | | | 51 |
| |
|
| | 51 |
|
| Sale of assets to NRG Yield, Inc. | | | (25 | ) | | | | | | | | 20 |
| | (5 | ) |
| ESPP share purchases | | | (3 | ) | | (4 | ) | | 13 |
| | | | | | 6 |
|
| Equity-based compensation | | | 29 |
| |
|
| | | | | | | | 29 |
|
| Common stock dividends | | | | | (38 | ) | | | | | | | | (38 | ) |
| Distributions to noncontrolling interests | | | | | | | | | | | (65 | ) | | (65 | ) |
| Dividends paid to NRG Yield, Inc. | | | | | | | | | | | (108 | ) | | (108 | ) |
| Contributions from noncontrolling interests | | | | | | | | | | | 160 |
| | 160 |
|
| Early adoption of new accounting standards | | | 17 |
| | (286 | ) | | | | 12 |
| | | | (257 | ) |
| Balances at December 31, 2017 | $ | 4 |
|
| $ | 8,376 |
|
| $ | (6,268 | ) |
| $ | (2,386 | ) |
| $ | (72 | ) |
| $ | 2,314 |
|
| $ | 1,968 |
|
(c)Includes excise tax accrued of $10 million as of December 31, 2023
(d)Dividend per Series A Preferred Stock was $52.96
See notes to Consolidated Financial Statements.Statements
NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 — Nature of Business
General
NRG Energy, Inc., or NRG or the Company, sits at the intersection of energy and home services. NRG is a leading integrated powerenergy and home 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 the brand names such as NRG, Reliant, Direct Energy, Green Mountain Energy and Vivint, while also advocating for competitive energy markets and customer choice. The Company has a customer base that includes approximately 8 million residential consumers in addition to commercial, industrial, and wholesale customers, supported by approximately 13 GW of 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 aimsmarket operations in Texas, other than Cottonwood;
•East, which includes all activity related to create a sustainable energy future by producing, sellingcustomer, plant and delivering electricity and related products and services in major competitive power marketsmarket operations in the U.S. in a manner that delivers valueEast;
•West/Services/Other, which includes the following assets and activities: (i) all activity related to all of NRG's stakeholders. The Company ownscustomer, plant and operates approximately 30,000 MW of generation; engagesmarket operations in the trading of wholesale energy, capacityWest and Canada, (ii) the Services businesses (iii) activity 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"Cottonwood facility and other retail brand names owned by NRG.investments;
Generation consists of the Company’s wholesale operations, commercial operations, EPC operations, energy services•Vivint Smart Home; and other critical related functions. NRG has traditionally referred to this business as its wholesale power generation business. In addition to the traditional functions from NRG’s wholesale power generation business, Generation also includes NRG’s business solutions, which include demand response, commodity sales, energy efficiency and energy management services, and NRG’s conventional distributed generation business, consisting of reliability, combined heat and power, thermal and district heating and cooling and large-scale distributed generation.
Retail is a consumer facing business that includes the Company’s residential retail and C&I business. Products and services range from retail energy, portable solar and battery products home services, and a variety of bundled products which combine energy with protection products, energy efficiency and renewable energy solutions as well as other distributed and reliability products.•Corporate activities.
Renewables operates the Company’s existing renewables business, including operation of the NRG Yield renewable assets. Renewables is also one of the largest solar and wind power developers and owner-operators in the U.S., having developed, constructed and financed a full range of solutions for utilities, schools, municipalities and commercial market segments.
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 has 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, Acquisitions and Dispositions, for more information.
Prior to the GenOn Entities' filing the Chapter 11 Cases, on June 12, 2017, NRG entered into a restructuring support and lock-up agreement, or the Restructuring Support Agreement, with the GenOn Entities and certain holders of the GenOn and GenOn Americas Generation Senior Notes, that provides for a restructuring and recapitalization of the GenOn Entities through a prearranged plan of reorganization. On December 12, 2017, the Bankruptcy Court entered an order confirming the plan of reorganization. There is no assurance that the GenOn Entities' plan will be successfully implemented. The principal terms of the Restructuring Support Agreement and further information regarding the Chapter 11 Cases are described further in Note 3, Discontinued Operations, Acquisitions and Dispositions.
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 $3.2 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 $5.3 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 working capital improvements through 2020 and (ii) approximately $290 million, one-time costs to achieve.
NRG Yield, Inc. Ownership
In 2013, the Company formed NRG Yield, Inc. to own and operate a portfolio of contracted generation assets and thermal infrastructure assets that have historically been owned and/or operated by NRG and its subsidiaries. In 2013 and 2014, NRG Yield, Inc. issued Class A common stock to its public shareholders and utilized the proceeds to acquire a controlling interest in NRG Yield LLC, through its ownership of Class A units. At that time, the Company owned the Class B common stock of NRG Yield, Inc. and the Class B units of NRG Yield LLC. On May 14, 2015, NRG Yield, Inc. completed a stock split in connection with which each outstanding share of Class A common stock was split into one share of Class A common stock and one share of Class C common stock, and each outstanding share of Class B common stock was split into one share of Class B common stock and one share of Class D common stock. A similar split was effected at NRG Yield LLC with respect to its member units. The Company consolidates NRG Yield, Inc. for financial reporting purposes as it maintains a controlling voting interest, and presents the public ownership of the Class A and Class C common stock as noncontrolling interest. The Company receives distributions from NRG Yield LLC, through its ownership of Class B and Class D units.
The following table represents the structure of NRG Yield, Inc. as of December 31, 2017:
Note 2 — Summary of Significant Accounting Policies
Basis of Presentation and Principles of Consolidation
The Company's consolidated financial statements have been prepared in accordance with U.S. GAAP. The ASC, established by the FASB, is the source of authoritative U.S. GAAP to be applied by nongovernmental entities. In addition, the rules and interpretative releases of the SEC under authority of federal securities laws are also sources of authoritative U.S. GAAP for SEC registrants.
The consolidated financial statements include NRG's accounts and operations and those of its subsidiaries in which the Company has a controlling interest. All significant intercompany transactions and balances have been eliminated in consolidation. The usual condition for a controlling financial interest is ownership of a majority of the voting interests of an entity. However, a controlling financial interest may also exist through arrangements that do not involve controlling voting interests. As such, NRG applies the guidance of ASC 810, Consolidations, or ASC 810, to determine when an entity that is insufficiently capitalized or not controlled through its voting interests, referred to as a VIE, should be consolidated.
Segment Reporting
The Company's businesses are segregated as follows: Generation, which includes generation, international and BETM; Retail, which includes Mass customers, and Business Solutions, which includes C&I customers and other distributed and reliability products; Renewables, which includes solar and wind assets, excluding thoseCompany identified an error in NRG Yield; NRG Yield; and corporate activities. On June 14, 2017, as described in Note 3, Discontinued Operations, Acquisitions and Dispositions, NRG deconsolidated GenOnthe previously issued consolidated financial statements for financial reporting purposes. The financial information for all historical periods has been recastthe year ended December 31, 2021 related to reflect the presentation of GenOn as discontinued operations withincash flows associated with certain borrowings and repayments related to the corporate segment.Revolving Credit Facility. The Company's segment structurestatement of cash flows for the year ended December 31, 2021 has been adjusted to present on a gross basis the borrowings from the Revolving Credit Facility of $1.4 billion and its allocationthe related repayments of corporate expenses$1.4 billion. The change had no impact to the total cash used by financing activities for the year ended December 31, 2021. We evaluated the materiality of this error both qualitatively and quantitatively and have concluded it is immaterial to the impacted period.
Winter Storm Uri Uplift Securitization Proceeds
The Texas Legislature passed HB 4492 in May 2021 for ERCOT to mitigate exceptionally high price adders and ancillary service costs incurred by LSEs during Winter Storm Uri. HB 4492 authorized ERCOT to obtain $2.1 billion of financing to distribute to LSEs that were updatedcharged and paid to reflect how management makes financial decisionsERCOT those highly priced ancillary service and allocates resources.ORDPA during Winter Storm Uri.
In December 2021, ERCOT filed with the PUCT a calculation of each LSE’s share of proceeds based on the settlement methodology. The Company has recast data from prior periods to reflect this change in reportable segments to conformaccounted for the proceeds by analogy to the current year presentation.contribution model within ASC 958-605, Not-for-Profit Entities- Revenue Recognition and the grant model within IAS 20, Accounting for Government Grants and Disclosure of Government Assistance, as a reduction to expenses in the consolidated statements of operations in the 2021 annual period for which the proceeds were intended to compensate. The Company received proceeds of $689 million from ERCOT in June 2022.
Credit Losses
In accordance with ASU No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, or ASU No. 2016-13, 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 on the consolidated balance sheet. The Company accrues an allowance for current expected credit losses based on (i) estimates of uncollectible revenues by analyzing accounts receivable aging and current and reasonable forecasts of expected economic factors including, but not limited to, unemployment rates and weather-related events, (ii) historical collections and delinquencies, and (iii) counterparty credit ratings for commercial and industrial customers. The Company writes off customer contract receivable balances against the allowance for credit losses when it is determined a receivable is uncollectible.
The following table represents the activity in the allowance for credit losses for the years ended December 31, 2023, 2022, and 2021:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| (In millions) | 2023 | | 2022 | | 2021 |
| Beginning balance | $ | 133 | | | $ | 683 | | | $ | 67 | |
| Acquired balance from Vivint Smart Home | 22 | | | — | | | — | |
| Acquired balance from Direct Energy | — | | | — | | | 112 | |
Provision for credit losses(a) | 251 | | | 11 | | | 698 | |
| Write-offs | (313) | | | (593) | | | (224) | |
| Recoveries collected | 39 | | | 32 | | | 30 | |
| Other | 13 | | | — | | | — | |
Ending balance(a) | $ | 145 | | | $ | 133 | | | $ | 683 | |
(a)Includes bilateral finance hedging risk of $(70) million and $403 million accounted for under ASC 815 for the years endedDecember 31, 2022 and December 31, 2021, respectively
During the year ended December 31, 2022, the provision for credit losses included the Company's loss mitigation efforts recognized as income of $126 million related to Winter Storm Uri. During the year ended December 31, 2021, the provision for credit losses included $596 million of expense due to the impacts of Winter Storm Uri. The increase in write-offs for the periods ended December 31, 2022 and 2021 were primarily due to the resolution of credit losses that occurred during Winter Storm Uri.
Cash and Cash Equivalents
Cash and cash equivalents include highly liquid investments with an original maturity of three months or less at the time of purchase.
Funds Deposited by Counterparties
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
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.
| | | | | | | | | | Year Ended December 31, |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In millions) |
| (In millions) | | (In millions) | 2023 | | 2022 | | 2021 |
| Cash and cash equivalents | $ | 991 |
| | $ | 938 |
| | $ | 853 |
|
| Funds deposited by counterparties | 37 |
| | 2 |
| | 55 |
|
| Restricted cash | 508 |
| | 446 |
| | 414 |
|
| Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows | $ | 1,536 |
| | $ | 1,386 |
| | $ | 1,322 |
|
| Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statements of cash flows | |
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. Of these funds, as of December 31, 2017, approximately $51 million is designated for current debt service payments, $65 million is designated to fund operating expenses, and $57 million is designated to fund distributions, with the remaining $335 million restricted for reserves including debt service, performance obligations and other reserves, as well as capital expenditures.
Trade Receivables and Allowance for Doubtful Accounts
Trade receivables are reported in the balance sheet at outstanding principal adjusted for any write-offs and the allowance for doubtful accounts. For its retail business, the Company accrues an allowance for doubtful accounts based on estimates of uncollectible revenues by analyzing counterparty credit ratings (for commercial and industrial customers), historical collections, accounts receivable aging and other factors. The retail business writes-off accounts receivable balances against the allowance for doubtful accounts when it determines a receivable is uncollectible. In addition, the Company considers a reserve for doubtful accounts based on the credit worthiness of the customers and continually reviews and adjusts for current economic trends that might impact the level of future credit losses. The reserve represents management's best estimate of uncollectible amounts. As of December 31, 2017 and 2016, the allowance for doubtful accounts was $28 million and $29 million, respectively.
Inventory
Inventory is valued at the lower of weighted average cost or market, and consists principally of natural gas, fuel oil, coal, spare parts and raw materials used to generate electricity or steam.finished goods. The Company removes these inventoriesnatural gas inventory as goods are delivered to customers and as they are used in the production of electricity or steam. Spare parts inventory is valued at weighted average cost. The Company removes thesefuel oil and coal inventories as they are used in the production of electricity. The Company removes spare parts inventories when they are used for repairs, maintenance or capital projects. The Company expects to recover the natural gas, fuel oil, coal raw materials, and spare parts costs in the ordinary course of business. Finished goods inventoryInventory is valued at the lower of cost or net realizable value with cost being determined on a first-in first-out basis.first in first out basis for finished goods and weighted average cost method for all other inventories. The Company removes thesefinished goods inventories as they are sold to customers. Inventories sold to customers as part of a smart home system are generally capitalized as contract costs. Sales of inventory are classified as an operating activity in the consolidated statements of cash flows.
Property, Plant and Equipment
Property, plant and equipment are stated at cost or, in the case of business acquisitions, fair value; however, impairment adjustments are recorded whenever events or changes in circumstances indicate that their carrying values may not be recoverable. See Note 3, Discontinued Operations, Acquisitions and Dispositions, for more information on acquired property, plant and equipment. NRG also classifies nuclear fuel related to the Company's 44% ownership interest in STP as part of the Company's property, plant, and equipment. Significant additions or improvements extending asset lives are capitalized as incurred, while repairs and maintenance that do not improve or extend the life of the respective asset are charged to expense as incurred. Depreciation, other than nuclear fuel, is computed using the straight-line method, while nuclear fuel iswas amortized based on units of production over the estimated useful lives. Certain assets and their related accumulated depreciation amounts are adjusted for asset retirements and disposals with the resulting gain or loss included in cost of operations in the consolidated statements of operations. For further discussion, see Note 9, Property, Plant and Equipment.
Business Interruption Insurance
The Company carries insurance policies to cover insurable risks including, but not limited to, business interruption. As a result of damage at the Limestone 1 and W.A. Parish 8 units, the Company recorded business interruption insurance settlements of $7 million and $81 million during the year ended December 31, 2023 and December 31, 2022, respectively. Business interruption insurance is recorded to cost of operations in the consolidated statements of operations and cash provided by operating activities in the consolidated statement of cash flows.
Asset Impairments
Long-lived assets that are held and used are reviewed for impairment whenever events or changes in circumstances indicate carrying values may not be recoverable. Such reviews are performed in accordance with ASC 360. An impairment loss is indicated if the total future estimated undiscounted cash flows expected from an asset are less than its carrying value. An impairment charge is measured by the difference between an asset's carrying amount and fair value with the difference recorded in operating costs and expenses in the consolidated statements of operations. Fair values are determined by a variety of valuation methods, including third-party appraisals, sales prices of similar assets and present value techniques.
Investments accounted for by the equity method are reviewed for impairment in accordance with ASC 323, Investments-Equity Method and Joint Ventures, or ASC 323, which requires that a loss in value of an investment that is an other-than-temporary decline should be recognized. The Company identifies and measures losses in the value of equity method investments based upon a comparison of fair value to carrying value.
For further discussion of these matters, refer to Note 10, 11, Asset Impairments.
Development Costs and Capitalized Interest
Development costs include project development costs, which are expensed in the preliminary stages of a project and capitalized when the project is deemed to be commercially viable. Commercial viability is determined by one or a series of actions including, among others, Board of Director approval pursuant to a formal project plan that subjects the Company to significant future obligations that can only be discharged by the use of a Company asset. When a project is available for operations, capitalized interest and capitalized project development costs are reclassified to property, plant and equipment and depreciated on a straight-line basis over the estimated useful life of the project's related assets. Capitalized costs are charged to expense if a project is abandoned or management otherwise determines the costs to be unrecoverable.Interest incurred on funds borrowed to finance capital projects is capitalized until the project under construction is ready for its intended use. The amount of interest capitalized for the years ended December 31, 2017, 2016, and 2015, was $34 million, $30 million, and $25 million, respectively.
Debt Issuance Costs
Debt issuance costs are capitalized and amortized as interest expense on a basis whichthat approximates the effective interest method over the term of the related debt. Debt issuance costs are presented as a direct deduction from the carrying amount of the related debt.debt, or as an asset if the issuance costs relate to revolving debt agreements or certain other financing arrangements.
Intangible Assets
Intangible assets represent contractual rights held by the Company. The Company recognizes specifically identifiable intangible assets including emissions allowances, customer and supply contracts, customer relationships, energy supply contracts, marketing partnerships, power purchase agreements,technologies, trade names emission allowances, and fuel contracts when specific rights and contracts are acquired. In addition, the Company also established values for emission allowances and power contracts upon adoption of Fresh Start reporting. These intangible assets are amortized based on expected volumes, expected delivery, expected discounted future net cash flows, straight line or units of production basis. As of December 31, 20172023 and 2016,2022, the Company had accumulated amortization related to its intangible assets of $1.8$3.0 billion and $1.7$2.1 billion, respectively.
Intangible assets determined to have indefinite lives are not amortized, but rather are tested for impairment at least annually or more frequently if events or changes in circumstances indicate that such acquired intangible assets have been determined to have finite lives and should now be amortized over their useful lives.
Emission allowances held-for-sale, which are included in other non-current assets on the Company's consolidated balance sheet, are not amortized; they are carried at the lower of cost or fair value and reviewed for impairment in accordance with ASC 360.
For further discussion, see Note 12, Goodwill and Other Intangibles.
Goodwill
In accordance with ASC 350, Intangibles-Goodwill and Other, or ASC 350, the Company recognizes goodwill for the excess cost of an acquired entity over the net value assigned to assets acquired and liabilities assumed. NRG performs goodwill impairment tests annually, during the fourth quarter, and when events or changes in circumstances indicate that the carrying value may not be recoverable.
The Company may first assesses qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. The more-likely-than-not threshold is defined as having a likelihood of more than 50 percent. If it is not more likely than notmore-likely-than-not that the fair value of a reporting unit is less than its carrying amount, there is no goodwill impairment.
In the absence of sufficient qualitative factors indicating that it is more-likely-than-not that no impairment occurred, the Company performs a quantitative assessment by determining the fair value of the reporting unit and comparing the fair value to its book value. If the fair value of the reporting unit exceeds its book value, goodwill of the reporting unit is not considered impaired. If the book value exceeds fair value, the Company recognizes an impairment loss equal to the difference between book value and fair value.
For further discussion of goodwill and goodwill impairment losses recognized during 2017 and 2016, refer to Note 11, GoodwillAsset Impairments.
Capitalized Contract Costs
Capitalized contract costs represent the costs directly related and Other Intangibles.incremental to the origination of new contracts, modification of existing contracts or to the fulfillment of the related subscriber contracts. These costs include installed products, commissions, other compensation and the cost of installation of new or upgraded customer contracts. The Company calculates amortization by accumulating all deferred contract costs into separate portfolios based on the initial month of service and amortizes those deferred contract costs on a straight-line basis over the expected period of benefit, consistent with the pattern in which the Company provides services to its customers. The expected period of benefit for customers is approximately five years. The Company updates its estimate of the expected period of benefit periodically and whenever events or circumstances indicate that the expected period of benefit could change significantly. Such changes, if any, are accounted for prospectively as a change in estimate. Amortization of capitalized contract costs related to fulfillment are included in cost of operations and amortization of capitalized contract costs related to customer acquisition are included in selling, general and administrative costs in the consolidated statements of operations. Contract costs not directly related and incremental to the origination of new contracts, modification of existing contracts or to the fulfillment of the related subscriber contracts are expensed as incurred.
Income Taxes
The Company accounts for income taxes using the liability method in accordance with ASC 740, Income Taxes, or ASC 740, which requires that the Company use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences.
The Company has two categories of income tax expense or benefit — current and deferred, as follows:
•Current income tax expense or benefit consists solely of current taxes payable less applicable tax credits, and
•Deferred income tax expense or benefit is the change in the net deferred income tax asset or liability, excluding amounts charged or credited to accumulated other comprehensive income.income
The Company reports some of its revenues and expenses differently for financial statement purposes than for income tax return purposes, resulting in temporary and permanent differences between the Company's financial statements and income tax returns. The tax effects of such temporary differences are recorded as either deferred income tax assets or deferred income tax liabilities in the Company's consolidated balance sheets. The Company measures its deferred income tax assets and deferred income tax liabilities using income tax rates that are currentlyexpected to be in effect. The Company believes it is more likely than not thateffect when the results of future operations will generate sufficient taxable income which includes the future reversal of existing taxable temporary differences to realize deferred tax assets, net of valuation allowances. In arriving at this conclusion to utilize projections of future profit before tax in its estimate of future taxable income, including the potential impact of the Tax Cuts and Jobs Act legislation, or the Tax Act, the Company considered the profit before tax generated in recent years. A valuation allowance is recorded to reduce the Company's net deferred tax assets to an amount that is more-likely-than-not to be realized.
The Company reduces its current income tax expense in the consolidated statement of operations for any investment tax credits, or ITCs, that are not convertible into cash grants, as well as other tax credits, in the period the tax credit is generated. ITCs that are convertible into cash grants, as well as the deferred income tax benefit generated by the difference in the financial statement and tax basis of the related assets, are recorded as a reduction to the carrying value of the underlying property and subsequently amortized to earnings on a straight-line basis over the useful life of each underlying property.
The Company accounts for uncertain tax positions in accordance with ASC 740, which applies to all tax positions related to income taxes. Under ASC 740, tax benefits are recognized when it is more-likely-than-not that a tax position will be sustained upon examination by the authorities. The benefit recognized from a position is the amount of benefit that has surpassed the more-likely-than-not threshold, is the largest amount of benefit thatas it is more than 50% likely to be realized upon settlement. The Company recognizes interest and penalties accrued related to uncertain tax benefits as a component of income tax expense.
In accordance with ASC 805740 and as discussed further in Note 19, 20, Income Taxes, changes to existing net deferred tax assets or valuation allowances or changes to uncertain tax benefits, are recorded to income tax (benefit)/expense.
Contract and Emission Credit Amortization
Revenue Recognition
Energy — Both physical and financial transactions are entered into to optimize the financial performance of the Company's generating facilities. Electric energy revenue is recognized upon transmission to the customer. Physical transactions, or the sale of generated electricity to meet supply and demand, are recorded on a gross basis in the Company's consolidated statements of operations. Financial transactions, or the buying and selling of energy for trading purposes, are recorded net within operating revenues in the consolidated statements of operations in accordance with ASC 815.
Capacity — Capacity revenues are recognized when contractually earned, and consist of revenues billed to a third party at either the market or a negotiated contract price for making installed generation capacity available in order to satisfy system integrity and reliability requirements.
Sale of Emission Allowances — The Company records its bank of emission allowances as part of intangible assets. From time to time, management may authorize the transfer of emission allowances in excess of usage from the Company's emission bank to intangible assets held-for-sale for trading purposes. The Company records the sale of emission allowances on a net basis within operating revenue in the Company's consolidated statements of operations.
Contract Amortization — Assets and liabilities recognized from power sales agreements assumed at Fresh Start and through acquisitions related to the purchase and sale of electric capacityenergy and energyenergy-related products in future periods for which the fair value has been determined to be significantly less (more)or more than market are amortized to revenuerevenues or cost of operations over the term of each underlying contract based on actual generation and/or contracted volumes.
Retail revenues — Gross revenues for energy sales and services to retail customers are recognized upon delivery under the accrual method. Energy sales and services that have been delivered but not billed by period end are estimated. Gross revenues also includes energy revenues from resales of purchased power, which were $187 million, $154 million and $165 million for the years ended December 31, 2017, 2016, and 2015, respectively. These revenuesEmission credits represent the saleright to emit a specified amount of excess supplycertain pollutants, including sulfur dioxide, nitrogen oxides and carbon dioxide, over a compliance period. Emission credits held for use are amortized to third parties in the market.
Accrued unbilled revenues arecost of operations based on estimates of customer usage since the dateweighted average cost of the last meter reading provided by the independent system operators or electric distribution companies. Volume estimates are based on daily forecasted volumes and estimated customer usage by class. Unbilled revenues are calculated by multiplying these volume estimates by the applicable rate by customer class. Estimated amounts are adjusted when actual usage is known and billed. The Company recorded receivables for unbilled revenues of $376 million, $321 million and $307 million as of December 31, 2017, 2016, and 2015, respectively, for retail energy sales and services.
Consumer product revenues are recognized when title and risk of loss pass to the retailer, distributor, or end-customer and when all of the following have occurred: a firm sales agreement is in place, delivery has occurred, pricing is fixed and determinable, and collection is reasonably assured. Revenue is recognized as the net amount expected to be received after deducting estimated amounts for product returns, discounts, and allowances based on historical return rates and reasonable judgment.held.
Lessor Accounting
Certain of the Company’s revenues are obtained through PPAs or other contractual agreements. Many of these agreements are accounted for as operating leases under ASC 840 Leases.
Certain of these leases have no minimum lease payments and all of the rent is recorded as contingent rent on an actual basis when the electricity is delivered. Judgment is required by management in determining the economic life of each generating facility, in evaluating whether certain lease provisions constitute minimum payments or represent contingent rent and other factors in determining whether a contract contains a lease and whether the lease is an operating lease or capital lease. Contingent rental income recognized in the years ended December 31, 2017, 2016, and 2015 was $879 million, $912 million, and $753 million, respectively.
Gross Receipts and Sales Taxes
In connection with its retail business,sales, the Company records gross receipts taxes on a gross basis in revenues and cost of operations in its consolidated statements of operations. During the years ended December 31, 2017, 2016,2023, 2022, and 2015,2021, the Company's revenues and cost of operations included gross receipts taxes of $92$212 million,, $101 $218 million, and $110$184 million,, respectively. Additionally, the retail businessCompany records sales taxes collected from its taxable retail customers and remitted to the various governmental entities on a net basis; thus, there is no impact on the Company's consolidated statement of operations.
Cost of Energy for Retail Operations
Cost of operations includes cost of fuel, purchased energy and other costs of sales, mark-to-market for economic hedging activities, contract and emission credit amortization, operations and maintenance, and other cost of operations.
Cost of Fuel, Purchased Energy and Other Cost of Sales
Cost of fuel is primarily the costs associated with procurement, transportation and storage of natural gas, nuclear fuel, oil and coal to operate the generation portfolio, which is expensed as the fuel is consumed. Purchased energy primarily relates to purchases to supply the Company's customer base, which includes spot market purchases, as well as contracts of various quantities and durations, including Renewable PPAs with third-party developers, which are primarily accounted for as NPNS (see further discussion in Derivative Instruments below). Other cost of sales primarily consists of TDSP expenses.
The cost of fuel is based on actual and estimated fuel usage for the applicable reporting period. The cost to deliver energy for electricity sales and related services to retail customers is included in cost of operations and is based on actual and estimated supply volumes for the applicable reporting period. A portion of the cost of energy, ($107$240 million,, $90 $202 million, and $85$189 million as of December 31, 2017, 2016,2023, 2022, and 2015, respectively)2021, respectively, was accrued and consisted of estimated transmission and distribution charges not yet billed by the transmission and distribution utilities.
In estimating supply volumes, the Company considers the effects of historical customer volumes, weather factors and usage by customer class. Transmission and distribution delivery fees are estimated using the same method used for electricity sales and services to retail customers. In addition, ISO fees are estimated based on historical trends, estimated supply volumes and initial ERCOT ISO settlements. Volume estimates are then multiplied by the supply rate and recorded as cost of operations in the applicable reporting period.
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 services (smart home and security). The subscriber has the ability to pay for Vivint Smart Home products in the following three ways: (i) qualified subscribers may finance the purchase through third-party financing providers ("Consumer Financing Program" or “CFP”), (ii) Vivint Smart Home generally offers a limited number of subscribers not eligible for the CFP, but who qualify under Vivint Smart Home underwriting criteria, the option to enter into a retail installment contract directly with Vivint Smart Home or (iii) subscribers may conduct purchases by check, automatic clearing house payments, credit or debit card or by obtaining short term financing (generally no more than six-month installment terms) through Vivint Smart Home.
Although subscribers pay separately for products and services under Flex Pay, the Company has determined that the sale of products and services are one single performance obligation resulting in deferred revenue for the gross amount of products sold. For products financed through the CFP, gross deferred revenues are reduced by (i) any fees the third-party financing provider (“Financing Provider”) is contractually entitled to receive at the time of loan origination, and (ii) the present value of expected future payments due to the Financing Providers. Loans are issued on either an installment or revolving basis with repayment terms ranging from 6 to 60 months.
For certain Financing Provider loans:
•Vivint Smart Home pays a monthly fee based on either the average daily outstanding balance of the installment loans, or the number of outstanding loans.
•Vivint Smart Home incurs fees at the time of the loan origination and receives proceeds that are net of these fees.
•Vivint Smart Home also shares liability for credit losses, with Vivint Smart Home being responsible for between 2.6% and 100% of lost principal balances.
Due to the nature of these provisions, the Company records a derivative liability ("CFP Derivative") 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 6, Accounting for Derivative Instruments and Hedging Activities.
Derivative Financial Instruments
The Company accounts for derivative financial instruments under ASC 815, which requires the Company to record all derivatives on the balance sheet at fair value and changes in fair value in earnings, unless they qualify for athe NPNS exception. Changes in the fair value of non-hedge derivatives are immediately recognized in earnings. Changes in the fair value of derivatives accounted for as cash flow hedges, if elected for hedge accounting, are deferred and recorded as a component of accumulated OCI until the hedged transactions occur and are recognized in earnings.
The Company's primary derivative instruments are power and natural gas purchase or sales contracts, fuels purchase contracts, the CFP and other energy related commodities and interest rate instruments used to mitigate variability in earnings due to fluctuationsfluctuation in market prices andprices. In order to mitigate interest rates. On an ongoing basis,rate risk associated with the Company assessesissuance of the effectiveness of all derivatives that are designated as hedges for accounting purposesCompany's variable rate debt, NRG enters into interest rate swap agreements. In addition, in order to determinemitigate foreign exchange risk associated with the purchase of USD denominated natural gas for the Company's Canadian business, NRG enters into foreign exchange contract agreements.
As of December 31, 2023 and 2022 the Company did not have derivative instruments that each derivative continues to be highly effective in offsetting changes in fair values or cash flows of hedged items. Internal analyses that measure the statistical correlation between the derivative and the associated hedged item determine the effectiveness of such a contractwere designated as a hedge. If it is determined that the derivative instrument is not highly effective as a hedge, hedge accounting will be discontinued prospectively. In this case, the gaincash flow or loss previously deferred in accumulated OCI would be frozen until the underlying hedged instrument is delivered unless the transactions being hedged are no longer probable of occurring in which case the amount in OCI would be immediately reclassified into earnings. If the derivative instrument is terminated, the effective portion of this derivative deferred in accumulated OCI will be frozen until the underlying hedged item is delivered.fair value hedges.
Revenues and expenses on contracts that qualify for the NPNS exception are recognized when the underlying physical transaction is delivered. While these contracts are considered derivative financial instruments under ASC 815, they are not recorded at fair value, but on an accrual basis of accounting. If it is determined that a transaction designated as NPNS no longer meets the scope exception, the fair value of the related contract is recorded on the balance sheet and immediately recognized through earnings.
NRG's trading activities are subject to limits in accordance with the Company's Risk Management Policy. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings.
Mark-to-Market for Economic Hedging Activities
NRG enters into derivative instruments to manage price and delivery risk, optimize physical and contractual assets in the portfolio and manage working capital requirements. The mark-to-market for economic hedging activities are recognized to revenues or cost of operations during the reporting period.
Operations and Maintenance and Other Cost of Operations
Operations and maintenance costs include major and other routine preventative (planned outage) and corrective (forced outage) maintenance activities to ensure the safe and reliable operation of the Company's generation portfolio in compliance
with all local, state and federal requirements. Operations and maintenance costs are also costs associated with retaining and maintaining the Company's customer base, such as call center support, portfolio maintenance and data analytics. Other cost of operations primarily includes gross receipts taxes, insurance, property taxes and asset retirement obligation expense.
Foreign Currency Translation and Transaction Gains and Losses
The local currencies are generally the functional currency of NRG's foreign operations. Foreign currency denominated assets and liabilities are translated at end-of-period rates of exchange. Revenues, expenses, and cash flows are translated at the weighted-average rates of exchange for the period. The resulting currency translation adjustments are not included in the Company's consolidated statements of operations for the period, but are accumulated and reported as a separate component of stockholders' equity until sale or complete or substantially complete liquidation of the net investment in the foreign entity takes place. Foreign currency transaction gains or losses are reported within other income/(expense)income, net in the Company's consolidated statements of operations. For the years ended December 31, 2017, 2016,2023, 2022 and 2015,2021, amounts recognized as foreign currency transaction gains gains/(losses) were immaterial. The Company's cumulative translation adjustment balances as of December 31, 2017, 2016,2023, 2022, and 20152021 were $(2)$(43) million,, $(11) $(55) million, and $(10)$(8) million, respectively.
Concentrations of Credit Risk
Financial instruments whichthat potentially subject the Company to concentrations of credit risk consist primarily of trust funds, accounts receivable, notes receivable, derivatives and investments in debt securities. Trust funds are held in accounts managed by experienced investment advisors. Certain accounts receivable, notes receivable, and derivative instruments are concentrated within entities engaged in the energy industry. These industry concentrations may impact the Company's overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. Receivables and other contractual arrangements are subject to collateral requirements under the terms of enabling agreements. However, the Company believes that the credit risk posed by industry concentration is offset by the diversification and creditworthiness of its customer base. See Note 4, 5, Fair Value of Financial Instruments,, for a further discussion of derivative concentrations.
Fair Value of Financial Instruments
The carrying amount of cash and cash equivalents, funds deposited by counterparties, receivables, accounts payable, and accrued liabilities approximate fair value because of the short-term maturity of these instruments. See Note 4, Fair Value of Financial Instruments, for a further discussion of fair value of financial instruments.
Asset Retirement Obligations
The Company accounts for AROs in accordance with ASC 410-20, Asset Retirement Obligations, or ASC 410-20. Retirement obligations associated with long-lived assets included within the scope of ASC 410-20 are those for which a legal obligation exists under enacted laws, statutes, and written or oral contracts, including obligations arising under the doctrine of promissory estoppel, and for which the timing and/or method of settlement may be conditional on a future event. ASC 410-20 requires an entity to recognize the fair value of a liability for an ARO in the period in which it is incurred and a reasonable estimate of fair value can be made.
Upon initial recognition of a liability for an ARO, the Company capitalizes the asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount. Over time, the liability is accreted to its future value, while the capitalized cost is depreciated over the useful life of the related asset. See Note 13, 14, Asset Retirement Obligations,, for a further discussion of AROs.
Pensions and Other Postretirement Benefits
The Company offers pension benefits through a defined benefit pension plan. In addition, the Company provides postretirement health and welfare benefits for certain groups of employees. The Company accounts for pension and other postretirement benefits in accordance with ASC 715, Compensation — Retirement Benefits.Benefits, or ASC 715. The Company recognizes the funded status of the Company's defined benefit plans in the statement of financial position and records an offset for gains and losses as well as all prior service costs that have not been included as part of the Company's net periodic benefit cost to other comprehensive income. The determination of the Company's obligation and expenses for pension benefits is dependent on the selection of certain assumptions. These assumptions determined by management include the discount rate, the expected rate of return on plan assets and the rate of future compensation increases. The Company's actuarial consultants determineassist in determining assumptions for such items as retirement age. The assumptions used may differ materially from actual results, which may result in a significant impact to the amount of pension obligation or expense recorded by the Company.
The Company measures the fair value of its pension assets in accordance with ASC 820, Fair Value Measurements and Disclosures, or ASC 820. For further discussion, see Note 15, Benefit Plans and Other Postretirement Benefits.
Stock-Based Compensation
The Company accounts for its stock-based compensation in accordance with ASC 718, Compensation — Stock Compensation, or ASC 718. The fair value of the Company's non-qualified stock options and marketperformance stock units areis estimated on the date of grant using the Black-Scholes option-pricing model and thea Monte Carlo valuation model, respectively.model. NRG uses the Company's common stock price on the date of grant as the fair value of the Company's restricted stock units and deferred stock units. Forfeiture rates are estimated based on an analysis of the Company's historical forfeitures, employment turnover, and expected future behavior. The Company recognizes compensation expense for both graded and cliff
vesting awards on a straight-line basis over the requisite service period for the entire award.
For further discussion, see Note 21, Stock-Based Compensation.
Investments Accounted for by the Equity Method
The Company has investments in various domestic energy projects, as well as one Australian project. The equity method of accounting is applied to such investments in affiliates, which include joint ventures and partnerships, because the ownership structure prevents the Company from exercising a controlling influence over the operating and financial policies of the projects. Under this method, equity in pre-tax income or losses of domestic partnerships and, generally, in the net income or losses of its Australian project, are reflected as equity in earnings of unconsolidated affiliates. For certain investments that relate to tax equity arrangements, equity earnings are allocated using the hypothetical liquidation at book value, or HLBV, method which is described below. Distributions from equity method investments that represent earnings on the Company's investment are included within cash flows from operating activities and distributions from equity method investments that represent a return of the Company's investment are included within cash flows from investing activities.
Tax Equity Arrangements
The Company’s redeemable noncontrolling interest in subsidiaries and certain amounts within noncontrolling interest, included in stockholders' equity, represent third-party interests in the net assets under certain tax equity arrangements, which are consolidated For further discussion, see Note 17, Investments Accounted for by the Company, that have been entered into to finance the cost of solar energy systems under operating leasesEquity Method and wind facilities eligible for certain tax credits. The Company has determined that the provisions in the contractual agreements of these structures represent substantive profit sharing arrangements. Further, the Company has determined that the appropriate methodology for calculating the noncontrolling interest and redeemable noncontrolling interest that reflects the substantive profit sharing arrangements is a balance sheet approach utilizing the HLBV method. Under the HLBV method, the amounts reported as noncontrolling interest and redeemable noncontrolling interests represent the amounts the investors that are party to the tax equity arrangements would hypothetically receive at each balance sheet date under the liquidation provisions of the contractual agreements, assuming the net assets of the funding structures were liquidated at their recorded amounts determined in accordance with GAAP. The investors’ interests in the results of operations of the funding structures are determined as the difference in noncontrolling interest and redeemable noncontrolling interests at the start and end of each reporting period, after taking into account any capital transactions between the structures and the funds’ investors. The calculations utilized to apply the HLBV method include estimated calculations of taxable income or losses for each reporting period.
Redeemable NoncontrollingVariable Interest
To the extent that the third-party has the right to redeem their interests for cash or other assets, the Company has included the noncontrolling interest attributable to the third party as a component of temporary equity in the mezzanine section of the consolidated balance sheet. The following table reflects the changes in the Company's redeemable noncontrolling interest balance for the years ended December 31, 2017, 2016, and 2015.
|
| | | |
| | (In millions) |
| Balance as of December 31, 2014 | $ | 19 |
|
| Cash contributions from redeemable noncontrolling interest | 27 |
|
| Comprehensive loss attributable to redeemable noncontrolling interest | (17 | ) |
| Balance as of December 31, 2015 | 29 |
|
| Distributions to redeemable noncontrolling interest | (1 | ) |
| Contributions from redeemable noncontrolling interest | 33 |
|
| Non-cash adjustments to redeemable noncontrolling interest | 23 |
|
| Comprehensive loss attributable to redeemable noncontrolling interest | (38 | ) |
| Balance as of December 31, 2016 | 46 |
|
| Distributions to redeemable noncontrolling interest | (2 | ) |
| Contributions from redeemable noncontrolling interest | 99 |
|
| Non-cash adjustments to redeemable noncontrolling interest | 7 |
|
| Comprehensive loss attributable to redeemable noncontrolling interest | (72 | ) |
| Balance as of December 31, 2017 | $ | 78 |
|
Entities.
Sale-Leaseback Arrangements
NRG is party to sale-leaseback arrangements that provide for the sale of certain assets to a third partythird-party and simultaneous leasebacksimultaneously leases back the same asset to the Company. In accordance with ASC 840-40, Sale-Leaseback Transactions, ifIf the seller-lessee retains, through the leaseback, substantially alltransfers control of the benefits and risks incidentunderlying assets to the ownership ofbuyer-lessor, the property sold, the sale-leaseback transactionarrangement is accounted for under ASC 842-40, Sale-Leaseback Transactions. These arrangements are classified as a financing arrangement. An example of this type of continuing involvement would include an option to repurchase the assets or the buyer-lessor having the option to sell the assets back to the Company. This provision is included in most of the Company’s sale-leaseback arrangements. As such, the Company accounts for these arrangements as financings.
Under the financing method, the Company does not recognize as income any of the sale proceeds received from the lessor that contractually constitutes payment to acquire the assets subject to these arrangements. Instead, the sale proceeds received are accounted for as financing obligations and leaseback payments made by the Company are allocated between interest expense and as a reduction to the financing obligation. Interestoperating leases on the financing obligation is calculated using the Company’s incremental borrowing rate at the inception of the arrangement on the outstanding financing obligation. Judgment is required to determine the appropriate borrowing rate for the arrangement and in determining any gain or loss on the transaction that would be recorded either at the end of or over the lease term.Company's consolidated balance sheets.
Marketing and Advertising Costs
The Company expenses its marketing and advertising costs as incurred and which are includedincludes them within selling, general and administrative expenses. Marketing and advertising expenses for the years ended December 31, 2017, 2016, and 2015 were $184 million, $247 million, and $309 million, respectively.costs. The costs of tangible assets used in advertising campaigns are recorded as fixed assets or deferred advertising costs and amortized as advertising costs over the shorter of the useful life of the asset or the advertising campaign. The Company has several long-term sponsorship arrangements. Payments related to these arrangements are deferred and expensed over the term of the arrangement. Advertising expenses for the years ended December 31, 2017, 2016,2023, 2022, and 20152021 were $42$185 million, $53$82 million, and $135$109 million, respectively.
Reorganization Costs
Reorganization costs include costs incurred by the Company related to the Transformation Plan implementation and primarily reflect personnel costs related to cost savings initiatives. As of December 31, 2017, $44 million has been incurred.
Business Combinations
The Company accounts for its business combinations in accordance with ASC 805, Business Combinations, or ASC 805. ASC 805, which requires an acquirer to recognize and measure in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at fair value at the acquisition date. ItThe Company also recognizes and measures the goodwill acquired or a gain from a bargain purchase in the business combination and determines what information to disclose to enable users of an entity's financial statements to evaluate the nature and financial effects of the business combination. In addition, transaction costs are expensed as incurred.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States 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.
In recording transactions and balances resulting from business operations, the Company uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, tax provisions, uncollectible accounts, actuarially determined benefit costs, the valuation of energy commodity contracts, environmental liabilities, legal costs incurred in connection with recorded loss contingencies, and assets acquired and liabilities assumed in business combinations, among others. In addition, estimates are used to test long-lived assets and goodwill for impairment and to determine the fair value of impaired assets. As better information becomes available or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.
Reclassifications
Certain prior-yearprior period amounts have been reclassified for comparative purposes. The reclassifications did not affect results from operations, net assets or cash flows.
Recent Accounting Developments - Guidance Adopted in 20172023
ASU 2018-022021-08 — In February 2018,October 2021, the FASB issued ASU No. 2018-02, Income Statement - Reporting Comprehensive Income2021-08, Business Combinations (Topic 220), Reclassification of Certain Tax Effects805): Accounting for Contract Assets and Contract Liabilities from Accumulated Other Comprehensive Income,Contracts with Customers, or ASU No. 2018-02. Prior to ASU No. 2018-02, GAAP required the remeasurement of deferred tax2021-08, which requires that an entity recognize and measure contract assets and contract liabilities acquired in a business combination as a result of a changeif it had originated the contracts in tax laws or rates to be presented in net incomeaccordance with ASC 606, Revenue from continuing operations, even in situations in which the related income tax effects of items in accumulated other comprehensive income were originally recognized in other comprehensive income.Contracts with Customers. As a result, an acquirer should recognize and measuring 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, such items, referredas refund liabilities and upfront payments to customers. Assets and liabilities under related Topics, such as stranded tax effects, diddeferred costs under Subtopic 340-40, Other Assets and Deferred Costs — Contracts with Customers, are not reflectwithin the appropriate tax rate. Underscope of amendments per ASU No. 2018-02, entities are permitted, but not required, to reclassify from accumulated other comprehensive income to retained earnings those stranded tax effects resulting from the Tax Act. ASU No. 2018-02 is effective for all entities for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted.2021-08. The Company adopted the new standard effective December 31, 2017. As a result of the adoption, the Company reclassified $13 million from accumulated other comprehensive loss to retained earnings in the consolidated balance sheet as of December 31, 2017.
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 Company adopted the guidance in ASU No. 2017-12 during the fourth quarter of 2017, with no material adjustments recorded to the consolidated results of operations, cash flows, and statement of financial position.
ASU 2016-18 — In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230), Restricted Cash, or ASU No. 2016-18. The amendments of ASU No. 2016-18 require an entity to include amounts generally described as restricted cash and restricted cash equivalents, including funds deposited by counterparties with cash 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 guidance 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)/increase in cash flows from operations of $(53) million and $37 million and an increase/(decrease) in cash flows from investing of $32 million and $(43) million on the statement of cash flows for the years ended December 31, 2016 and 2015, respectively.
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. Previous GAAP prohibited 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 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. 2016-162021-08 prospectively effective January 1, 2017. In connection with2023 and applied 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 as of December 31, 2017.
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 indicatedamended requirements to the FASB that a diversity in practice existed in how entities were presenting and classifying these items in the statementacquisition 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 from 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 guidance in ASU No. 2016-15 effective January 1, 2017. In connection with the adoption of the standard, the Company has applied the guidance retrospectively which resulted in an increase in cash flows from operations of $121 million and a decrease in cash flows from financing of $121 million on the statement of cash flows for the year ended December 31, 2016. There was no impact to the statement of cash flows for the year ended December 31, 2015, as a result of adoption.Vivint Smart Home.
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 Company's consolidated financial statements.
Recent Accounting Developments - Guidance Not Yet Adopted
ASU 2017-07 —2023-07 – In March 2017,November 2023, the FASB issued ASU No. 2017-07, Compensation - Retirement Benefits2023-07, Segment Reporting (Topic 715)280) – Improvements to Reportable Segment Disclosures, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, or ASU No. 2017-07. Current GAAP does not indicate where2023-07. The guidance in ASU 2023-07 enhances reportable segment disclosure requirements by requiring disclosure of significant segment expenses that are regularly provided to the chief operating decision maker and included within each reported measure of segment profit and loss, an amount and description of net benefit cost should be presented in an entity’s income statementits composition for other segment items and does not require entities to disclose the amountinterim disclosures of net benefit cost that is included in the income statement.a reportable segment’s profit or loss and assets. The amendments of ASU No. 2017-07 require an entity to report the service cost component of net benefit costs2023-07 are effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted and should be applied retrospectively for all prior periods presented in the same line item as other compensation costs arising from services rendered by the related employees during the applicable service period.financial statements. 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 Company adopted the amendments of ASU No. 2017-07 effective January 1, 2018. The adoption of ASU No. 2017-07 will not have a material impact on the Company's 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 will adopt the standard effective January 1, 2019, and 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 haveof adopting ASU 2023-07 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. The Company is continuing to monitor potential changes to Topic 842 that have been proposed by the FASB and will assess any necessary changes to the implementation process as the guidance is updated.disclosures.
ASU 2014-09 —2023-09 – In May 2014,December 2023, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers2023-09, Income Taxes (Topic 606)740) – Improvements to Income Tax Disclosures, or Topic 606, which was further amended through various updates issuedASU 2023-09. The guidance in ASU 2023-09 enhances income tax disclosures by requiring disclosure of specific categories in the FASB thereafter.effective tax rate reconciliation and additional information for reconciling items that meet a quantitative threshold. Further the amendments of ASU 2023-09 require certain disclosures on income tax expense and income taxes paid. ASU 2023-09 is effective for annual periods beginning after December 15, 2024, with early adoption permitted. The amendments of Topic 606 completedASU 2023-09 may be applied on a prospective or retrospective basis. The Company is currently evaluating the joint effort betweenimpact of adopting ASU 2023-09 on its disclosures.
Note 3— Revenue Recognition
The Company's policies with respect to its various revenue streams are detailed below. The Company generally applies the FASB and the IASB,invoicing practical expedient 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 for the revenue streams detailed below, except in circumstances where the invoiced amount does not represent the value transferred to depict the transfer of goods orcustomer.
Retail Revenue
Gross revenues for energy sales and services to retail customers in an amount that reflectsare recognized as the Company transfers the promised goods and services to the customer. Payment terms are generally 15 to 60 days. For the majority of its electricity and natural gas contracts, the Company’s performance obligation with the customer is satisfied over time and performance obligations for its electricity and natural gas products are recognized as the customer takes possession of the product. The Company also allocates the contract consideration to distinct performance obligations in a contract for which the entity expectstiming of the revenue recognized is different. Additionally, customer discounts and incentives reduce the contract consideration and are recognized over the term of the contract.
Energy sales and services that have been delivered but not billed by period end are estimated. Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter reading provided by the independent system operators, utilities, or electric distribution companies. Volume estimates are based on daily forecasted volumes and estimated customer usage by class. Unbilled revenues are calculated by multiplying these volume estimates by the applicable rate by customer class. Estimated amounts are adjusted when actual usage is known and billed.
As contracts for retail electricity and natural gas can be for multi-year periods, the Company has performance obligations under these contracts that have not yet been satisfied. These performance obligations have transaction prices that are both fixed and variable, and that vary based on the contract duration, customer type, inception date and other contract-specific factors. For the fixed price contracts, the amount of any unsatisfied performance obligations will vary based on customer usage, which will depend on factors such as weather and customer activity and therefore it is not practicable to be entitledestimate such amounts.
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 exchangethe 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 goods or services providedsubscriber are generally not distinct within the context of the contract and, establishestherefore, constitute a five step modelsingle, 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 be applied by an entity in evaluating its contracts with customers.the contract have enforceable rights and obligations. The Company has also electeddetermined that certain contracts that do not require a long-term commitment for monitoring services by the subscriber contain a material right to renew the contract,
because the subscriber does not have to purchase the products upon renewal. Proceeds allocated to the material right are recognized over the expected period of benefit. The majority of Vivint Smart Home's subscription contracts are five years and are generally non-cancelable. These contracts generally convert into month-to-month agreements at the end of the initial term, while some subscribers are month-to-month from inception. Payment for Vivint Smart Home services is generally due in advance on a monthly basis, with payment terms up to 30 days. Product sales and other one-time fees are invoiced to subscribers at time of sale. Revenues for any products or services that are considered separate performance obligations are recognized upon delivery. Payments received or billed in advance are reported as deferred revenues.
Energy Revenue
Both physical and financial transactions consist of revenues billed to a third-party at either market or negotiated contract terms to optimize the financial performance of the Company's generating facilities. Payment terms vary from 5 to 55 days. Electric energy revenue is recognized upon transmission to the customer over time, using the output method for measuring progress of satisfaction of performance obligations. Physical transactions, or the sale of generated electricity to meet supply and demand, are recorded on a gross basis in the Company's consolidated statements of operations. The Company applies the invoicing practical expedient in recognizing energy revenue. Under the practical expedient, available under Topic 606 for measuring progress toward complete satisfaction of a performance obligation and for disclosure requirements of remaining performance obligations. The practical expedient allows an entityrevenue is recognized based on the invoiced amount which is equal to recognize revenue in the amount to which the entity has the right to invoice such that the entity has a right to the consideration in an amount that corresponds directly with the value to the customer forof NRG’s performance obligation completed to date bydate. Financial transactions used to hedge the entity.sale of electricity are recorded net within revenues in the consolidated statements of operations in accordance with ASC 815.
Ancillary revenues, included in Other revenue, are recognized over time as the obligation is fulfilled, using the output method for measuring progress of satisfaction of performance obligations.
CapacityRevenue
The Company's largest sources of capacity revenues are capacity auctions in PJM and NYISO. Capacity revenues also include revenues billed to a third-party at either market or negotiated contract terms for making installed generation and demand response capacity available in order to satisfy system integrity and reliability requirements. Payment terms vary from 15 to 55 days. Capacity revenues are recognized over time, using the output method for measuring progress of satisfaction of performance obligations. The Company adoptedapplies the standard effective January 1, 2018.invoicing practical expedient in recognizing capacity revenue. Under the practical expedient, revenue is recognized based on the invoiced amount which is equal to the value to the customer of NRG’s performance obligation completed to date.
Performance Obligations
As of December 31, 2023, estimated future fixed fee performance obligations are $1.4 billion, $1.0 billion, $756 million, $468 million and $176 million for fiscal years 2024, 2025, 2026, 2027 and 2028, respectively. These performance obligations include Vivint Smart Home products and services as well as cleared auction MWs in the PJM, NYISO and MISO capacity auctions. The adoptioncleared auction MWs are subject to penalties for non-performance.
Disaggregated Revenue
The following tables represent the Company’s disaggregation of Topic 606revenue from contracts with customers for the years ended December 31, 2023, 2022, and 2021:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2023 |
| (In millions) | Texas | | East | | West/Services/Other | | Vivint Smart Home(a) | | Corporate/Eliminations | | Total |
| Retail revenue | | | | | | | | | | | |
Home(b) | $ | 6,538 | | | $ | 2,195 | | | $ | 1,890 | | | $ | 1,549 | | | $ | (1) | | | $ | 12,171 | |
| Business | 3,492 | | | 9,751 | | | 2,053 | | | — | | | — | | | 15,296 | |
Total retail revenue(b) | 10,030 | | | 11,946 | | | 3,943 | | | 1,549 | | | (1) | | | 27,467 | |
Energy revenue(c) | 77 | | | 291 | | | 185 | | | — | | | — | | | 553 | |
Capacity revenue(c) | — | | | 197 | | | 2 | | | — | | | (2) | | | 197 | |
Mark-to-market for economic hedging activities(d) | — | | | 57 | | | 103 | | | — | | | (16) | | | 144 | |
| Contract amortization | — | | | (32) | | | — | | | — | | | — | | | (32) | |
Other revenue(c) | 369 | | | 88 | | | 48 | | | — | | | (11) | | | 494 | |
| Total revenue | 10,476 | | | 12,547 | | | 4,281 | | | 1,549 | | | (30) | | | 28,823 | |
| Less: Revenues accounted for under topics other than ASC 606 and ASC 815 | — | | | 17 | | | 35 | | | — | | | — | | | 52 | |
| Less: Realized and unrealized ASC 815 revenue | 29 | | | 364 | | | 138 | | | — | | | (16) | | | 515 | |
| Total revenue from contracts with customers | $ | 10,447 | | | $ | 12,166 | | | $ | 4,108 | | | $ | 1,549 | | | $ | (14) | | | $ | 28,256 | |
| (a) Includes results of operations following the acquisition date of March 10, 2023 |
| (b) Home includes Services and Vivint Smart Home |
| (c) The following amounts of retail, energy, capacity and other revenue relate to derivative instruments and are accounted for under ASC 815: |
| (In millions) | Texas | | East | | West/Services/Other | | Vivint Smart Home | | Corporate/Eliminations | | Total |
| Retail revenue | $ | — | | | $ | 74 | | | $ | — | | | $ | — | | | $ | — | | | $ | 74 | |
| Energy revenue | — | | | 162 | | | 13 | | | — | | | 1 | | | 176 | |
| Capacity revenue | — | | | 73 | | | — | | | — | | | — | | | 73 | |
| Other revenue | 29 | | | (2) | | | 22 | | | — | | | (1) | | | 48 | |
| (d) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2022 |
| (In millions) | Texas | | East | | West/Services/Other | | | | Corporate/Eliminations | | Total |
| Retail revenue | | | | | | | | | | | |
Home(a) | $ | 6,388 | | | $ | 2,088 | | | $ | 2,286 | | | | | $ | (1) | | | $ | 10,761 | |
| Business | 3,229 | | | 13,768 | | | 1,964 | | | | | — | | | 18,961 | |
Total retail revenue(b) | 9,617 | | | 15,856 | | | 4,250 | | | | | (1) | | | 29,722 | |
Energy revenue(b) | 111 | | | 641 | | | 466 | | | | | 32 | | | 1,250 | |
Capacity revenue(b) | — | | | 232 | | | 40 | | | | | — | | | 272 | |
Mark-to-market for economic hedging activities(c) | 2 | | | (30) | | | (56) | | | | | 1 | | | (83) | |
| Contract amortization | — | | | (40) | | | 1 | | | | | — | | | (39) | |
Other revenue(b) | 327 | | | 104 | | | 5 | | | | | (15) | | | 421 | |
| Total revenue | 10,057 | | | 16,763 | | | 4,706 | | | | | 17 | | | 31,543 | |
| Less: Revenues accounted for under topics other than ASC 606 and ASC 815 | — | | | (7) | | | 41 | | | | | 1 | | | 35 | |
| Less: Realized and unrealized ASC 815 revenue | (2) | | | 84 | | | (93) | | | | | 31 | | | 20 | |
| Total revenue from contracts with customers | $ | 10,059 | | | $ | 16,686 | | | $ | 4,758 | | | | | $ | (15) | | | $ | 31,488 | |
| (a) Home includes Services |
| (b) The following amounts of energy, capacity and other revenue relate to derivative instruments and are accounted for under ASC 815: |
| (In millions) | Texas | | East | | West/Services/Other | | | | Corporate/Eliminations | | Total |
| Retail revenue | $ | — | | | $ | 110 | | | $ | — | | | | | $ | — | | | $ | 110 | |
| Energy revenue | — | | | (31) | | | (8) | | | | | 31 | | | (8) | |
| Capacity revenue | — | | | 33 | | | — | | | | | — | | | 33 | |
| Other revenue | (4) | | | 2 | | | (29) | | | | | (1) | | | (32) | |
| (c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2021 |
| (In millions) | Texas | | East | | West/Services/Other | | | | Corporate/Eliminations | | Total |
| Retail revenue | | | | | | | | | | | |
Home(a) | $ | 5,659 | | | $ | 1,832 | | | $ | 2,059 | | | | | $ | (1) | | | $ | 9,549 | |
| Business | 2,745 | | | 10,030 | | | 1,237 | | | | | — | | | 14,012 | |
| Total retail revenue | 8,404 | | | 11,862 | | | 3,296 | | | | | (1) | | | 23,561 | |
Energy revenue(c) | 329 | | | 508 | | | 371 | | | | | 7 | | | 1,215 | |
Capacity revenue(c) | — | | | 718 | | | 57 | | | | | — | | | 775 | |
Mark-to-market for economic hedging activities(d) | (3) | | | (88) | | | (86) | | | | | 13 | | | (164) | |
| Contract amortization | — | | | (26) | | | (4) | | | | | — | | | (30) | |
Other revenue(b)(c) | 1,565 | | | 51 | | | 25 | | | | | (9) | | | 1,632 | |
| Total revenue | 10,295 | | | 13,025 | | | 3,659 | | | | | 10 | | | 26,989 | |
| Less: Revenues accounted for under topics other than ASC 606 and ASC 815 | — | | | (25) | | | 3 | | | | | — | | | (22) | |
| Less: Realized and unrealized ASC 815 revenue | 130 | | | 184 | | | (96) | | | | | 16 | | | 234 | |
| Total revenue from contracts with customers | $ | 10,165 | | | $ | 12,866 | | | $ | 3,752 | | | | | $ | (6) | | | $ | 26,777 | |
| (a) Home includes Services |
| (b) Other Revenue in Texas includes ancillary revenues of $1.3 billion driven by high pricing during Winter Storm Uri |
| (c) The following amounts of energy, capacity and other revenue relate to derivative instruments and are accounted for under ASC 815: |
| (In millions) | Texas | | East | | West/Services/Other | | | | Corporate/Eliminations | | Total |
| Energy revenue | $ | — | | | $ | 131 | | | $ | 2 | | | | | $ | 3 | | | $ | 136 | |
| Capacity revenue | — | | | 149 | | | — | | | | | — | | | 149 | |
| Other revenue | 133 | | | (8) | | | (12) | | | | | — | | | 113 | |
| (d) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815 |
ContractBalances
The following table reflects the contract assets and liabilities included in the Company's balance sheet as of December 31, 2023 and 2022:
| | | | | | | | | | | | | | |
| (In millions) | | December 31, 2023 | | December 31, 2022 |
Capitalized contract costs(a) | | $ | 706 | | | $ | 126 | |
| | | | |
| Accounts receivable, net - Contracts with customers | | 3,395 | | | 4,704 | |
| Accounts receivable, net - Accounted for under topics other than ASC 606 | | 136 | | | 64 | |
| Accounts receivable, net - Affiliate | | 11 | | | 5 | |
| Total accounts receivable, net | | $ | 3,542 | | | $ | 4,773 | |
| | | | |
| Unbilled revenues (included within Accounts receivable, net - Contracts with customers) | | $ | 1,493 | | | $ | 1,952 | |
Deferred revenues (b) | | $ | 1,634 | | | $ | 186 | |
(a)Amortization of capitalized contract costs for the years ended December 31, 2023, 2022 and 2021 were $168 million, $86 million and $95 million, respectively
(b)Deferred revenues from contracts with customers for the years ended December 31, 2023 and 2022 were approximately $1.6 billion and $175 million, respectively. The increase in deferred revenue balances from December 31, 2023 to 2022 was primarily due to the acquisition of Vivint Smart Home
The revenue recognized from contracts with customers during the years ended December 31, 2023 and 2022 relating to the deferred revenue balance at the datebeginning of initial application, as prescribed under the modified retrospective transition method, will not have a material impact on the Company's financial statements.each period was $168 million and $184 million, respectively. The adoption of Topic 606 also includes additional disclosure requirements beginningchange in the first quarterrevenue recognized from contracts with customers relating to the deferred revenue balances at the beginning of 2018. Manythe years ended December 31, 2023 and 2022 was primarily due to the timing difference of these disclosures are not substantially different thanwhen consideration was received and when the performance obligation was transferred.
The Company's existing disclosures. Topic 606 requires disclosurecapitalized contract costs consist of disaggregated revenue amounts,commission payments, broker fees and other costs that represent incremental costs of obtaining the contract with customers for which the Company expects to recover. Capitalized contract costs are amortized on a straight-line basis over the expected period of benefit of five years. As a practical expedient, the Company expenses the incremental costs of obtaining a contract if the amortization period of the asset would include typeshave been one year or less.
When the Company receives consideration from the customer that is in excess of operating revenues by business.the amount due, such consideration is reclassified to deferred revenue, which represents a contract liability. Smart home products and services performance obligations are recognized over the customer's contract term, which is generally three to five years. Energy contract liabilities are generally recognized to revenue in the next period as the Company satisfies its performance obligations.
Note 34 —Discontinued Operations, Acquisitions and Dispositions
Discontinued OperationsAcquisitions
As described in Note 1, Nature2023 Acquisitions
Vivint Smart Home Acquisition
On March 10, 2023 (the "Acquisition Closing Date"), the Company completed the acquisition of BusinessVivint Smart Home, Inc., onpursuant to the Petition Date,Agreement and Plan of Merger, dated as of December 6, 2022, by and among the GenOn Entities filed voluntary petitions for relief under Chapter 11Company, Vivint Smart Home, Inc. and Jetson Merger Sub, Inc., a wholly-owned subsidiary of the Bankruptcy CodeCompany (“Merger Sub”) pursuant to which Merger Sub merged with and into Vivint Smart Home, Inc., with Vivint Smart Home, Inc. surviving the merger as a wholly-owned subsidiary of the Company. Dedicated to redefining the home experience with intelligent products and services, Vivint Smart Home brought approximately two million subscribers to NRG. Vivint Smart Home's single, expandable platform incorporates artificial intelligence and machine learning into its operating system and its vertically integrated business model includes hardware, software, sales, installation, customer service and technical support and professional monitoring, enabling superior subscriber experiences and a complete end-to-end smart home experience. The acquisition accelerated the realization of NRG's consumer-focused growth strategy and 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 approximately $2.6 billion in cash. The Company funded the acquisition using:
•proceeds of $724 million from newly issued $740 million 7.000% Senior Secured First Lien Notes due 2033, net of issuance costs and discount;
•proceeds of $635 million from newly issued $650 million 10.25% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock, net of issuance costs;
•proceeds of approximately $900 million drawn from its Revolving Credit Facility and Receivables Securitization Facilities; and
•cash on hand.
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 13, Long-term Debt and Finance Leases.
Acquisition costs of $38 million and $17 million for the years ended December 31, 2023 and 2022, respectively, are included in acquisition-related transaction and integration costs in the Bankruptcy Court. AsCompany's consolidated statement of operations.
The acquisition has been recorded as a resultbusiness combination under ASC 805, with identifiable assets and liabilities acquired recorded at their estimated Acquisition Closing Date fair value. The total consideration of $2.623 billion includes:
| | | | | | | | |
| | (In millions) |
| Vivint Smart Home, Inc. common shares outstanding as of March 10, 2023 of 216,901,639 at $12.00 per share | | $ | 2,603 | |
| Other Vivint Smart Home, Inc. equity instruments (Cash out RSUs and PSUs, Stock Appreciation Rights, Private Placement Warrants) | | 6 | |
| Total Cash Consideration | | $ | 2,609 | |
| Fair value of acquired Vivint Smart Home, Inc. equity awards attributable to pre-combination service | | 14 | |
| Total Consideration | | $ | 2,623 | |
The purchase price was allocated as follows as of December 31, 2023:
| | | | | |
| (In millions) |
| Current Assets | |
| Cash and cash equivalents | $ | 120 | |
| Accounts receivable, net | 60 | |
| Inventory | 113 | |
| Prepayments and other current assets | 37 | |
| Total current assets | 330 | |
| Property, plant and equipment, net | 49 | |
| Other Assets | |
| Operating lease right-of-use assets, net | 35 | |
Goodwill(a) | 3,494 | |
Intangible assets, net(b): | |
| Customer relationships | 1,740 | |
| Technology | 860 | |
| Trade names | 160 | |
| Sales channel contract | 10 | |
| Intangible assets, net | 2,770 | |
| Deferred income taxes | 382 | |
| Other non-current assets | 14 | |
| Total other assets | 6,695 | |
| Total Assets | $ | 7,074 | |
| |
| Current Liabilities | |
| Current portion of long-term debt and finance leases | $ | 14 | |
| Current portion of operating lease liabilities | 13 | |
| Accounts payable | 109 | |
| Derivative instruments | 80 | |
| Deferred revenue current | 518 | |
| Accrued expenses and other current liabilities | 207 | |
| Total current liabilities | 941 | |
| Other Liabilities | |
| Long-term debt and finance leases | 2,572 | |
| Non-current operating lease liabilities | 28 | |
| Derivative instruments | 32 | |
| Deferred income taxes | 18 | |
| Deferred revenue non-current | 837 | |
| Other non-current liabilities | 23 | |
| Total other liabilities | 3,510 | |
| Total Liabilities | $ | 4,451 | |
| |
| Vivint Smart Home Purchase Price | $ | 2,623 | |
(a)Goodwill arising from the acquisition is attributed to the value of the bankruptcy filings, NRG concluded that it no longer controls GenOn as it is subject toplatform acquired, cross-selling opportunities, subscriber growth and the controlsynergies expected from combining the operations of Vivint Smart Home with NRG's existing businesses. None of the Bankruptcy Court;goodwill recorded will be deductible for tax purposes
(b)The weighted average amortization period for total amortizable intangible assets is approximately ten years
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 accordingly, NRG no longer consolidates GenOn for financial reporting purposes.
By eliminating a large portion of its operationsunobservable in the PJM market with 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.
Summarized results of discontinued operationsand 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 classified as Level 3. Under this approach, the Company estimated the present value of expected future cash flows resulting from existing subscriber relationships, considering attrition and charges for contributory assets (such as net working capital, fixed assets, workforce, trade names and technology) utilized in the business, discounted based on the required rate of return on the acquired intangible asset. The subscriber relationships are amortized to depreciation and amortization, ratably based on discounted future cash flows. The weighted average amortization period is twelve years. |
| | | | | | | |
| | Year ended December 31, |
| (In millions) | 2017 | | 2016 |
| Operating revenues | $ | 646 |
| | $ | 1,862 |
|
| Operating costs and expenses | (702 | ) | | (1,896 | ) |
| Gain on sale of assets | — |
| | 294 |
|
| Other expenses | (98 | ) | | (168 | ) |
| (Loss)/Income from operations of discontinued components, before tax | (154 | ) | | 92 |
|
| Income tax expense | 9 |
| | 11 |
|
| (Loss)/Income from operations of discontinued components | (163 | ) | | 81 |
|
| Interest income - affiliate | 8 |
| | 11 |
|
| (Loss)/Income from operations of discontinued components, net of tax | (155 | ) | | 92 |
|
| Pre-tax loss on deconsolidation | (208 | ) | | — |
|
| Settlement consideration and services credit | (289 | ) | | — |
|
| Pension and post-retirement liability assumption | (131 | ) | | — |
|
| Other | (6 | ) | | — |
|
| Loss on disposal of discontinued components, net of tax | (634 | ) | | — |
|
| (Loss)/Income from discontinued operations, net of tax | $ | (789 | ) | | $ | 92 |
|
Trade names – Trade names were 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 names considered the expected probable use of the asset and was discounted based on the required rate of return on the acquired intangible asset. The trade names are 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 aggregate principal of Vivint Smart Home’s 2027 Senior Secured Notes, 2029 Senior notes and 2028 Senior Secured Term Loan (together, the "Acquired Vivint Smart Home Debt") which were recorded at fair value as of the Acquisition Closing Date. The difference between the fair value at the Acquisition Closing Date and the principal outstanding of the Acquired Vivint Smart Home Debt, of $152 million, is being amortized through interest expense over the remaining term of the debt. The Acquired Vivint Smart Home Debt is classified as Level 2 and were measured at fair value using observable market inputs based on interest rates at the Acquisition Closing Date. For additional discussion, seeNote 13, Long-term Debt and Finance Leases.
Fair Value Measurement of Derivatives Liabilities
The derivative liabilities are recorded in connection with the contractual future payment obligations with the financing providers under Vivint Smart Home’s Consumer Financing Program. The fair values of the derivatives liabilities as of the Acquisition Closing Date were valued using a discounted cash flow model, with inputs consisting of available market data, such as market yield discount rates, as well as unobservable internally derived assumptions, such as collateral prepayment rates, collateral default rates and credit loss rates. These derivatives are classified as Level 3 and changes to the fair value are recorded through other income, net in the consolidated statement of operations. For additional discussion, see Note 6, Accounting for Derivative Instruments and Hedging Activities.
Supplemental Pro Forma Financial Information
The following table summarizesprovides unaudited pro forma combined financial information of NRG and Vivint Smart Home, after giving effect to the major classesVivint Smart Home acquisition and related financing transactions as if they had occurred on January 1, 2021. The pro forma financial information has been prepared for illustrative and informational purposes only, and is not intended to project future operating results or be indicative of what the Company's financial performance would have been had the transactions occurred on the date indicated. No effect has been given to prospective operating synergies.
| | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, |
| (In millions) | 2023 | | 2022 | | 2021 |
| Total operating revenues | $ | 29,109 | | | $ | 33,225 | | | $ | 28,468 | |
| Net (loss)/income | (3) | | | 1,136 | | | 1,574 | |
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 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 year ended December 31, 2021.
(iv)Interest expense assumes the financing transactions directly attributable to the Vivint Smart Home acquisition occurred on January 1, 2021.
(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 year ended December 31, 2021 instead of the year ended December 31, 2023.
(vii) Income tax effect of the acquisition accounting adjustments and financing adjustments (adjusted for permanent book/tax differences) based on combined blended federal/state tax rate for all periods presented.
2021 Acquisitions
Direct Energy Acquisition
On January 5, 2021, the Company acquired all of the issued and outstanding common shares of Direct Energy, which had been a North American subsidiary of Centrica plc. Direct Energy is a leading retail provider of electricity, natural gas, and home and business energy related products and services in North America, with operations in all 50 U.S. states and 8 Canadian provinces. The acquisition increased NRG's retail portfolio by over 3 million customers and strengthened its integrated model. It also broadened the Company's presence in the Northeast and into states and locales where it did not previously operate, supporting NRG's objective to diversify its business.
The Company paid an aggregate purchase price of $3.625 billion in cash and total purchase price adjustment of $99 million, resulting in an adjusted purchase price of $3.724 billion.
Acquisition costs of $25 million for the year ended December 31, 2021 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 acquired and liabilities classifiedassumed recorded at their estimated fair values on the acquisition date. The purchase price was allocated as discontinued operationsfollows as of December 31, 2016. 2021:
| | | | | |
| (In millions) |
| Current Assets | |
| Cash and cash equivalents | $ | 152 | |
| Funds deposited by counterparties | 21 | |
| Restricted cash | 9 | |
| Accounts receivable, net | 1,802 | |
| Inventory | 106 | |
| Derivative instruments | 1,014 | |
| Cash collateral paid in support of energy risk management activities | 233 | |
| Prepayments and other current assets | 173 | |
| Total current assets | 3,510 | |
| Property, plant and equipment, net | 151 | |
| Other Assets | |
Goodwill(a) | 1,250 | |
| Intangible assets, net: | |
Customer relationships(b) | 1,277 | |
Customer and supply contracts(b) | 610 | |
Trade names(b) | 310 | |
| Renewable energy credits | 124 | |
| Total intangible assets, net | 2,321 | |
| Derivative instruments | 531 | |
| Other non-current assets | 31 | |
| Total other assets | 4,133 | |
| Total Assets | $ | 7,794 | |
| |
| Current Liabilities | |
| Accounts payable | $ | 1,116 | |
| Derivative instruments | 1,266 | |
| Cash collateral received in support of energy risk management activities | 21 | |
| Accrued expenses and other current liabilities | 670 | |
| Total current liabilities | 3,073 | |
| Other Liabilities | |
| Derivative instruments | 562 | |
| Deferred income taxes | 320 | |
| Other non-current liabilities | 115 | |
| Total other liabilities | 997 | |
| Total Liabilities | $ | 4,070 | |
| |
| Direct Energy Purchase Price | $ | 3,724 | |
(a)Goodwill arising from the acquisition was attributed to the value of the platform acquired and the synergies expected from combining the operations of Direct Energy with NRG's existing businesses. Goodwill was allocated to the Texas, East, and West/Services/Other segments of $427 million, $648 million and $175 million, respectively. Goodwill deductible for tax purposes was $322 million
(b)As of June 14, 2017, NRG no longer consolidates GenOnJanuary 5, 2021, the weighted average amortization period for financial reporting purposes.total amortizable intangible assets was 12 years
|
| | | | |
| (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 |
|
Chapter 11 CasesDispositions
Prior2023 Dispositions
Sale of the 44% equity interest in STP
On November 1, 2023, the Company closed on the sale of its 44% equity interest in STP to Constellation Energy Generation ("Constellation"). Proceeds of $1.75 billion were reduced by working capital and other adjustments of $96 million, resulting in net proceeds of $1.654 billion. The Company recorded a gain on the sale of $1.2 billion within the Texas region of operations. For discussion of the litigation matter related to the GenOn Entities' filingtransaction, see Note 23, Commitments and Contingencies.
The Company recorded income before income taxes from its 44% equity interest in STP as follows:
| | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, |
| (In millions) | 2023 | | 2022 | | 2021 |
Income before income taxes(a) | $ | 206 | | | $ | 362 | | | $ | 829 | |
(a)Excludes the Chapter 11 Cases,impact of the Company's hedges at the portfolio level
Sale of Gregory
On October 2, 2023, the Company closed on the sale of its 100% ownership in the Gregory natural gas generating facility in Texas for $102 million. The Company recorded a gain on the sale of $82 million.
Sale of Astoria
On January 6, 2023, the Company closed on the sale of land and related generation assets from the Astoria site, within the East region of operations, for proceeds of $212 million, subject to transaction fees of $3 million and certain indemnifications, resulting in a $199 million gain. As part of the transaction, NRG entered into an agreement to lease the land back for the purpose of operating the Astoria gas turbines. Decommissioning was completed in December 2023 and the lease agreement has been terminated.
2022 Dispositions
Sale of Watson
On June 12, 2017,1, 2022, the Company closed on the sale of its 49% ownership in the Watson natural gas generating facility for $59 million. The Company recorded a gain on the sale of $46 million.
2021 Dispositions
Sale of 4,850 MW of Fossil generating assets
On December 1, 2021, the Company closed the previously announced sale of approximately 4,850 MWs of fossil generating assets from its East and West regions to Generation Bridge, an affiliate of ArcLight Capital Partners. Proceeds of $760 million were reduced by working capital and other adjustments of $140 million, resulting in net proceeds of $620 million. The Company recorded a gain of $207 million from the sale, which includes the $39 million indemnification liability recorded as discussed below. As part of the transaction, NRG entered into a restructuring support and lock-uptolling agreement orfor the Restructuring Support Agreement, with the GenOn Entities and certain holders866 MW Arthur Kill plant in New York City through April 2025.
As part of the GenOn and GenOn Americas Generation Senior Notes, that provides for a restructuring and recapitalization ofagreement to sell the GenOn Entities through a prearranged plan of reorganization. There is no assurance that the GenOn Entities' plan will be successfully implemented. The principal terms of the Restructuring Support Agreement are described further below.
On September 18, 2017, and October 2, 2017, the GenOn Entities filed amendments to the plan of reorganization and the disclosure statement which primarily provided the GenOn Entities with the flexibility to complete sales of certainfossil generating assets, pursuant to the amended plan of reorganization and removed the GenOn Entities' requirement to conduct a rights offering in connection with the GenOn Entities' exit financing.
On October 31, 2017, the GenOn Entities announced that they entered into a Consent Agreement with certain holders of GenOn’s Senior Notes and GenOn Americas Generation's Senior Notes, collectively, the Consenting Holders, whereby the GenOn Entities and the Consenting HoldersNRG has agreed to extend the milestones in the Restructuring Support Agreement, by which the plan of reorganization must become effective, or the Effective Date. Specifically, the Consent Agreement extended the Effective Date milestoneindemnify Generation Bridge for certain future environmental compliance costs up to June 30, 2018, or September 30, 2018, if regulatory approvals are still pending, or the Extended Effective Dates.
On$39 million. The indemnity term will expire on December 12, 2017, the Bankruptcy Court entered an order confirming the plan of reorganization, and effective December 12, 2017, GenOn and NRG entered into agreements concerning (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 and releases, consistent with the Restructuring Support Agreement, which among other things, provide for the transition of GenOn to a standalone enterprise, the resolution of substantial intercompany claims between GenOn and NRG, and the allocation of certain costs and liabilities between GenOn and NRG. On December 12, 2017, the Bankruptcy Court also entered an order giving effect to the Consent Agreement.
Forms of certain of the definitive documents that make up the plan supplement were filed with the Bankruptcy Court by the GenOn Entities and approved by the Bankruptcy Court in connection with the confirmation of the plan of reorganization. It is a condition precedent to the occurrence of the effective date of the plan of reorganization that the final version of the plan supplement be consistent with the Restructuring Support Agreement, in all material respects.
Restructuring Support Agreement
As described in Note 1, Nature of Business, NRG, GenOn and certain holders representing greater than 93% in aggregate principal amount of GenOn’s Senior Notes and certain holders representing greater than 93% in aggregate principal amount of GenOn Americas Generation’s Senior Notes entered into a Restructuring Support Agreement that provides for a restructuring and recapitalization of the GenOn Entities through a prearranged plan of reorganization that was approved by the Bankruptcy Court pursuant to an order of confirmation. Completion of the agreed upon terms is contingent upon certain milestones in the Restructuring Support Agreement and the satisfaction or waiver or certain conditions precedent. Certain principal terms of the Restructuring Support Agreement and the plan of reorganization are detailed below:
| |
1) | The dismissal of litigation and full releases from GenOn and GenOn Americas Generation in favor of NRG upon the earlier of the consummation of the GenOn Entities' plan of reorganization or the Settlement Agreement; a condition precedent to the consummation of the Settlement Agreement is a full release or indemnification in favor of NRG from any claims of GenOn Mid-Atlantic and REMA. |
| |
2) | NRG will provide settlement cash consideration to GenOn of $261.3 million, which will be paid in cash less any amounts owed to NRG under the intercompany secured revolving credit facility. As of December 31, 2017, GenOn owed NRG approximately $125 million under the intercompany secured revolving credit facility. See Note 21, Related Party Transactions, for further discussion of the intercompany secured revolving credit facility.
|
| |
3) | NRG will consent to the cancellation of its interests in the equity of GenOn and be entitled to a worthless stock deduction, as further described in the tax matters agreement. 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 in September 2017. GenOn’s pension liability as of December 31, 2017, was approximately $92 million. NRG will also retain the liability for GenOn’s post-employment and retiree health and welfare benefits, in an amount up to $25 million. |
| |
5) | The shared services agreement between NRG and GenOn was terminated and replaced as of the plan confirmation date with a transition services agreement. Under the transition services agreement, NRG will continue to provide the shared services and other separation services at an annualized rate of $84 million, subject to certain credits and adjustments. See Note 21, Related Party Transactions, for further discussion of the Services Agreement.
|
| |
6) | NRG will provide a credit of $28 million to GenOn to apply against amounts owed under the transition services agreement. 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 21, 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. Pursuant to this, GenOn made a one-time payment in the amount of $15 million to NRG in December 2017 as compensation for a purchase option with respect to the Canal 3 project. |
Settlement Consideration
NRG has determined that the payment of the settlement consideration is probable and2028. The Company has recorded athe liability for the amount due of $261.3 million inwithin accrued expenses and other current liabilities - affiliate with a corresponding loss from discontinued operations. NRG expects to pay this amount net of amounts due from GenOn under the intercompany secured revolving credit facility, which is further described in Note 21, 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 has recorded the estimated accumulated pension benefit obligation as of December 31, 2017 of $92 million in other non-current liabilities with a corresponding loss from discontinued operations. NRG's obligation for this liability will be revalued through and at GenOn's emergence from bankruptcy.liabilities.
Services AgreementSale of Agua Caliente
In December 2017, in conjunction with the confirmation of the GenOn Entities' plan of reorganization, the Services Agreement was terminated and replaced by the transition services agreement. Under the transition services agreement, NRG will continue to provide shared services and other separation services to GenOn at an annualized rate of $84 million until June 30, 2018, which may be extended by GenOn through September 30, 2018. NRG may provide additional separation services that are necessary for or reasonably related to the operation of GenOn's business after such date, subject to NRG's prior written consent, not to be unreasonably withheld.
Beginning on June 14, 2017, and through December 2017, NRG recorded amounts earned for shared services of approximately $5 million per month. In December 2017, NRG provided GenOn with a $3.5 million credit for services provided under the transition services agreement and began recording amounts earned for shared services of approximately $7 million per month. NRG has also agreed to provide GenOn with a credit of $28 million against amounts owed under the transition services agreement. Any unused amount can be paid in cash at GenOn’s request, subject to the terms and conditions of the transition services agreement. As a result, NRG has concluded that the liability for this credit is probable and has recorded a payable to GenOn for $28 million in accrued expenses and other current liabilities - affiliate with a corresponding loss from discontinued operations.
Commercial Operations
For pre-disposal periods, NRG provided GenOn with services as described in Note 21, 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. 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. 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 filing of the Chapter 11 Cases constitutes an event 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 dueOn February 3, 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). |
Dispositions
2016 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 retained 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 EVgo will be directly reimbursed by NRG for the costs. As a result of the sale, the Company recorded a loss on sale of $78 million during the second quarter of 2016, which reflects the loss on the sale of the equity interest of $27 million and the accrual of NRG's remaining obligation under its agreement with the CPUC of $56 million, of which $25 million remains as of December 31, 2017. 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. As of December 31, 2017, the Company's remaining 35% interest in EVgo of $1 million was accounted for as an equity method investment.
2016 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 reduce the carrying amount of the assets held for sale to the fair market value. On July 12, 2016, the Company completed the sale of Rockford for cash proceeds of $56 million, including $1 million in adjustments for the PJM base residual auction results. For further discussion on this impairment, refer to Note 10, Asset Impairments.
2015 Disposition of Altenex
On December 31, 2015, the Company completed the sale of its 32% interest in Altenex, LLC to Edison Energy, LLC and Edison Energy NewCo 2, LLC for cash consideration of $26 million. The Company had accounted for its investment in Altenex as an equity method investment and recognized a loss of $14 million as a result of the transactions within the Company's consolidated statements of operations.
Acquisitions
2016 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 million. The Company also borrowed additional amounts of $65 million during the fourth quarter of 2016, as described in Note 12, Debt and Capital Leases, 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 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 PacifiCorp.
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 $20 million was paid as of December 31, 2017.
2016 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 these assets into a tax-equity financed portfolio within the DGPV Holdco partnership between NRG and NRG Yield, Inc. The purchase price was allocated to $47 million in construction in progress and $15 million in intangible assets.
2015 Acquisition of Desert Sunlight
On June 29, 2015, NRG Yield, Inc., through its subsidiary NRG Yield Operating LLC, acquired 25% of the membership interest in Desert Sunlight Investment Holdings, LLC, which owns two solar photovoltaic facilities that total 550 MW located in Desert Center, California from EFS Desert Sun, LLC, an affiliate of GE Energy Financial Services, for a purchase price of $285 million. The Company accounts for its 25% investment as an equity method investment.
Transfers of Assets under Common Control
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 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% interest35% 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.to Clearway Energy, Inc. for $202 million. 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 completedrecognized a gain on the sale of its remaining 51.05% interest in the CVSR project to NRG Yield, Inc. for total cash consideration of $78.5 million, plus an immaterial working capital adjustment. In addition, NRG Yield, Inc. assumed non-recourse project level debt of $496 million.
On November 3, 2015, the Company sold 75% of the Class B interests of NRG Wind TE Holdco, which owns a portfolio of 12 wind facilities totaling 814 net MW, to NRG Yield, Inc. NRG Yield, Inc. paid total cash consideration of $209 million, subject to working capital adjustments. NRG Yield, Inc. is responsible for its pro-rata share of non-recourse project debt of $193 million and noncontrolling interest associated with a tax equity structure of $159 million (as of the acquisition date). In February 2016, the Company made a final working capital payment of $2 million to NRG Yield, Inc. reducing total cash consideration to $207 million.
On January 2, 2015, the Company sold the following facilities to NRG Yield, Inc.: Walnut Creek, the Tapestry projects (Buffalo Bear, Pinnacle and Taloga) and Laredo Ridge. NRG Yield, Inc. paid total cash consideration of $489$17 million, including $9 millioncash disposed of working capital adjustments, plus assumed project level debt of $737$7 million.
The above sales were recorded as transfers of entities under common control and the related assets were transferred at their carrying value.
Note 45 — Fair Value of Financial Instruments
For cash and cash equivalents, funds deposited by counterparties, restricted cash, accounts and other receivables, accounts payable restricted cash, and cash collateral postedpaid and received in support of energy risk management activities, the carrying amount approximates fair value because of the short-term maturity of those instruments and are classified as Level 1 within the fair value hierarchy.
The estimated carrying valuesvalue and fair valuesvalue of the Company's recorded financial instruments not carried at fair market value arelong-term debt, including current portion, is as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| | As of December 31, |
| 2023 | | 2022 |
| (In millions) | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Convertible Senior Notes | $ | 575 | | | $ | 739 | | | $ | 575 | | | $ | 576 | |
| Other long-term debt, including current portion | 10,219 | | | 9,835 | | | 7,523 | | | 6,432 | |
Total long-term debt, including current portion(a) | $ | 10,794 | | | $ | 10,574 | | | $ | 8,098 | | | $ | 7,008 | |
|
| | | | | | | | | | | | | | | |
| | As of December 31, |
| | 2017 | | 2016 |
| | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
| | (In millions) |
| Assets | | | | | | | |
Notes receivable (a) | $ | 16 |
| | $ | 15 |
| | $ | 34 |
| | $ | 34 |
|
| Liabilities | | | | | | | |
Long-term debt, including current portion (b) | $ | 16,603 |
| | $ | 16,894 |
| | $ | 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 on the Company's consolidated balance sheets.sheets
The fair value of the Company's publicly-traded long-term debt isand the Vivint Smart Home Senior Secured Term Loan are based on quoted market prices and isare classified as Level 2 within the fair value hierarchy. The fair value of debt securities, non-publicly traded long-term debt, and certain notes receivable of the Company are based on expected future cash flows discounted at market interest rates or current interest rates for similar instruments with equivalent credit quality and are classified as Level 3 within the fair value hierarchy. The following table presents the level within the fair value hierarchy for long-term debt, including current portion as of December 31, 2017 and 2016:
|
| | | | | | | | | | | | | | | |
| | As of December 31, 2017 | | As of December 31, 2016 |
| | Level 2 | | Level 3 | | Level 2 | | Level 3 |
| | (In millions) |
| Long-term debt, including current portion | $ | 8,934 |
| | $ | 7,960 |
| | $ | 9,205 |
| | $ | 7,415 |
|
Fair Value Accounting under ASC 820
ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:
•Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Company has the ability to access as of the measurement date. NRG's financial assets and liabilities utilizing Level 1 inputs include active exchange-traded securities, energy derivatives, and trust fund investments.
•Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data. NRG's financial assets and liabilities utilizing Level 2 inputs include fixed income securities, exchange-based derivatives, and over the counter derivatives such as swaps, options and forward contracts.
•Level 3 — unobservable inputs for the asset or liability only used when there is little, if any, market activity for the asset or liability at the measurement date. NRG's financial assets and liabilities utilizing Level 3 inputs include infrequently-traded, non-exchange-based derivatives and commingled investment funds, and are measured using present value pricing models.
In accordance with ASC 820, the Company determines the level in the fair value hierarchy within which each fair value measurement in its entirety falls, based on the lowest level input that is significant to the fair value measurement in its entirety.
Recurring Fair Value Measurements
DebtDerivative assets and liabilities, debt securities, equity securities and trust fund investments, which arewere 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 consolidated balance sheets on a recurring basis and their level within the fair value hierarchy:
| | | | | | | | | | | | | | | | | | | | | | | |
| | As of December 31, 2023 |
| | Fair Value |
| (In millions) | Total | | Level 1 | | Level 2 | | Level 3 |
| Investments in securities (classified within other current and non-current assets) | $ | 21 | | | $ | — | | | $ | 21 | | | $ | — | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Derivative assets: | | | | | | | |
| Interest rate contracts | 12 | | | — | | | 12 | | | — | |
| Foreign exchange contracts | 5 | | | — | | | 5 | | | — | |
| Commodity contracts | 6,138 | | | 1,334 | | | 4,470 | | | 334 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Equity securities measured using net asset value practical expedient (classified within other non-current assets) | 6 | | | | | | | |
| Total assets | $ | 6,182 | | | $ | 1,334 | | | $ | 4,508 | | | $ | 334 | |
| Derivative liabilities: | | | | | | | |
| Interest rate contracts | $ | 8 | | | $ | — | | | $ | 8 | | | $ | — | |
| Foreign exchange contracts | 9 | | | — | | | 9 | | | — | |
| Commodity contracts | 5,356 | | | 1,413 | | | 3,728 | | | 215 | |
| Consumer Financing Program | 134 | | | — | | | — | | | 134 | |
| Total liabilities | $ | 5,507 | | | $ | 1,413 | | | $ | 3,745 | | | $ | 349 | |
| | | | | | | | | | | | As of December 31, 2022 |
| | As of December 31, 2017 | | Fair Value |
| | Fair Value |
| | Total | | Level 1 | | Level 2 | | Level 3 |
| | (In millions) |
| Investments in securities (classified within other non-current assets): | | | | | | | |
| Debt securities | $ | 19 |
| | $ | — |
| | $ | — |
| | $ | 19 |
|
| Available-for-sale securities | 3 |
| | 3 |
| | — |
| | — |
|
| (In millions) | | (In millions) | Total | | Level 1 | | Level 2 | | Level 3 |
| Investments in securities (classified within other current and non-current assets) | |
| Nuclear trust fund investments: | | | | | | | |
| Cash and cash equivalents | |
| Cash and cash equivalents | |
| Cash and cash equivalents | 47 |
| | 45 |
| | 2 |
| | — |
|
| U.S. government and federal agency obligations | 43 |
| | 42 |
| | 1 |
| | — |
|
| Federal agency mortgage-backed securities | 82 |
| | — |
| | 82 |
| | — |
|
| Commercial mortgage-backed securities | 14 |
| | — |
| | 14 |
| | — |
|
| Corporate debt securities | 99 |
| | — |
| | 99 |
| | — |
|
| Equity securities | 334 |
| | 334 |
| | — |
| | — |
|
| Foreign government fixed income securities | 5 |
| | — |
| | 5 |
| | — |
|
| Other trust fund investments: | | | | | | | |
| Other trust fund investments (classified within other non-current assets): | |
| U.S. government and federal agency obligations | |
| U.S. government and federal agency obligations | |
| U.S. government and federal agency obligations | 1 |
| | 1 |
| | — |
| | — |
|
| Derivative assets: | | | | | | | |
| Foreign exchange contracts | |
| Foreign exchange contracts | |
| Foreign exchange contracts | |
| Commodity contracts | 745 |
| | 191 |
| | 509 |
| | 45 |
|
| Interest rate contracts | 53 |
| | — |
| | 53 |
| | — |
|
| | Measured using net asset value practical expedient: | | | | | | | |
| Equity securities | 68 |
| | | | | | |
| | Measured using net asset value practical expedient: | |
| | Measured using net asset value practical expedient: | |
| Equity securities - nuclear trust fund investments | |
| Equity securities - nuclear trust fund investments | |
| Equity securities - nuclear trust fund investments | |
| Equity securities (classified within other non-current assets) | |
| Equity securities (classified within other non-current assets) | |
| Equity securities (classified within other non-current assets) | |
| Total assets | |
| Total assets | |
| Total assets | $ | 1,513 |
| | $ | 616 |
| | $ | 765 |
| | $ | 64 |
|
| Derivative liabilities: | | | | | | | |
| Foreign exchange contracts | |
| Foreign exchange contracts | |
| Foreign exchange contracts | |
| Commodity contracts | $ | 693 |
| | $ | 257 |
| | $ | 359 |
| | $ | 77 |
|
| Interest rate contracts | 59 |
| | — |
| | 59 |
| | — |
|
| | Total liabilities | $ | 752 |
| | $ | 257 |
| | $ | 418 |
| | $ | 77 |
|
| Total liabilities | |
| Total liabilities | |
|
| | | | | | | | | | | | | | | |
| | As of December 31, 2016 |
| | Fair Value |
| | Total | | Level 1 | | Level 2 | | Level 3 |
| | | | | | | | |
| Investments in securities (classified within other non-current assets): |
| | | | | | |
| Debt securities | $ | 17 |
| | $ | — |
| | $ | — |
| | $ | 17 |
|
| Available-for-sale securities | 10 |
| | 10 |
| | — |
| | — |
|
| Nuclear trust fund investments: |
|
| | | | | | |
| Cash and cash equivalents | 25 |
| | 25 |
| | — |
| | — |
|
| U.S. government and federal agency obligations | 73 |
| | 72 |
| | 1 |
| | — |
|
| Federal agency mortgage-backed securities | 62 |
| | — |
| | 62 |
| | — |
|
| Commercial mortgage-backed securities | 17 |
| | — |
| | 17 |
| | — |
|
| Corporate debt securities | 84 |
| | — |
| | 84 |
| | — |
|
| Equity securities | 292 |
| | 292 |
| | — |
| | — |
|
| Foreign government fixed income securities | 3 |
| | — |
| | 3 |
| | — |
|
| Other trust fund investments: | | | | | | | |
| U.S. government and federal agency obligations | 1 |
| | 1 |
| | — |
| | — |
|
| Derivative assets: | | | | | | | |
| Commodity contracts | 1,199 |
| | 560 |
| | 549 |
| | 90 |
|
| Interest rate contracts | 49 |
| | — |
| | 49 |
| | — |
|
| Measured using net asset value practical expedient: | | | | | | | |
| Equity securities | 54 |
| | | | | | |
| Total assets | $ | 1,886 |
| | $ | 960 |
| | $ | 765 |
| | $ | 107 |
|
| Derivative liabilities: |
|
| | | | | | |
| Commodity contracts | $ | 1,288 |
| | $ | 494 |
| | $ | 636 |
| | $ | 158 |
|
| Interest rate contracts | 88 |
| | — |
| | 88 |
| | — |
|
| Total liabilities | $ | 1,376 |
| | $ | 494 |
| | $ | 724 |
| | $ | 158 |
|
There have been no transfers during the year ended December 31, 2017 between Levels 1 and 2. The following tables reconcile,table reconciles, for the years ended December 31, 20172023 and 2016,2022, the beginning and ending balances for financial instruments that are recognized at fair value in the consolidated financial statements at least annually using significant unobservable inputs:inputs, for commodity derivatives:
| | | | | | | | | | | | | | |
| | | Fair Value Measurement Using Significant Unobservable Inputs (Level 3) |
| | Commodity Derivatives (a) |
| | For the Year Ended December 31, |
| (In millions) | | 2023 | | 2022 |
| Beginning balance | | $ | 505 | | | $ | 293 | |
| | | | |
| Total (losses)/gains realized/unrealized included in earnings | | (164) | | | 53 | |
| | | | |
| Purchases | | 42 | | | (110) | |
| | | | |
Transfers into Level 3(b) | | 78 | | | 264 | |
Transfers out of Level 3(b)(c) | | (342) | | | 5 | |
| Ending balance | | $ | 119 | | | $ | 505 | |
| (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 year-end | | $ | (46) | | | $ | 204 | |
|
| | | | | | | | | | | |
| | For the Year Ended December 31, 2017 |
| | Fair Value Measurement Using Significant Unobservable Inputs (Level 3) |
| | Debt Securities | | Derivatives (a) | | Total |
| | (In millions) |
| Beginning balance as of January 1, 2017 | $ | 17 |
| | $ | (68 | ) | | $ | (51 | ) |
| Total gains/(losses) realized/unrealized: | | | | | |
| Included in earnings | 2 |
| | 43 |
| | 45 |
|
| Included in nuclear decommissioning obligations | — |
| | — |
| | — |
|
| Purchases | — |
| | (23 | ) | | (23 | ) |
| Contracts reclassified to held-for-sale | — |
| | 4 |
| | 4 |
|
Transfers into Level 3 (b) | — |
| | (1 | ) | | (1 | ) |
Transfers out of Level 3 (b) | — |
| | 13 |
| | 13 |
|
| Ending balance as of December 31, 2017 | $ | 19 |
| | $ | (32 | ) | | $ | (13 | ) |
| 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 December 31, 2017 | $ | 2 |
| | $ | 6 |
| | $ | 8 |
|
| |
(a) | Consists of derivatives 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 into/out of Level 3 are from/to Level 2. |
(a)Consists of derivatives assets and liabilities, net, excluding derivative 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 consensus pricing and external broker quotes, and are valued as of the end of the reporting period. All transfers into/out of Level 3 are from/to Level 2
(c)For the year ended December 31, 2023, due to the change to use consensus pricing, there was a decrease in the number of contracts valued with prices provided by models and other valuation techniques, which resulted in a large transfer out of Level 3 |
| | | | | | | | | | | | | | | |
| | For the Year Ended December 31, 2016 |
| | Fair Value Measurement Using Significant Unobservable Inputs (Level 3) |
| | Debt Securities | | Trust Fund Investments (c) | | Derivatives (a) | | Total |
| | (In millions) |
| Beginning balance as of January 1, 2016 | $ | 17 |
| | $ | 54 |
| | $ | (22 | ) | | $ | 49 |
|
| Total gains/(losses) realized/unrealized: | | | | | | | |
| Included in earnings | — |
| | — |
| | 2 |
| | 2 |
|
| Included in nuclear decommissioning obligations | — |
| | (1 | ) | | — |
| | (1 | ) |
| Purchases | — |
| | 1 |
| | (29 | ) | | (28 | ) |
Transfers into Level 3 (b) | — |
| | — |
| | (18 | ) | | (18 | ) |
Transfer out of Level 3 (b) | — |
| | (54 | ) | | (1 | ) | | (55 | ) |
| Ending balance as of December 31, 2016 | $ | 17 |
| | $ | — |
| | $ | (68 | ) | | $ | (51 | ) |
| 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 December 31, 2016 | $ | — |
| | $ | — |
| | $ | (13 | ) | | $ | (13 | ) |
| |
(a) | Consists of derivatives 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 into/out of Level 3 are from/to Level 2. |
| |
(c) | All Trust Fund Investments were considered transferred out of Level 3 as these investments are measured using net asset value as a practical expedient and are thus classified outside of the fair value hierarchy as of December 31, 2016. |
Realized and unrealized gains and losses included in earnings that are related to the energycommodity derivatives are recorded in operating revenues and cost of operations.
The following table reconciles, for the year ended December 31, 2023, the beginning and ending balances of the contractual obligations from the Consumer Financing Program that are recognized at fair value in the condensed consolidated financial statements, using significant unobservable inputs:
| | | | | | | |
| | | Fair Value Measurement Using Significant Unobservable Inputs (Level 3) |
| | | Consumer Financing Program |
| (In millions) | | | For the Year Ended December 31, 2023 |
| Beginning balance | | | $ | — | |
| Contractual obligations added from the acquisition of Vivint Smart Home | | | (112) | |
| New contractual obligations | | | (68) | |
| Settlements | | | 62 | |
| Total losses included in earnings | | | (16) | |
| Ending balance | | | $ | (134) | |
Gains and losses that are related to the Consumer Financing Program derivative are recorded in other income, net.
Non-derivative fair value measurements
NRG's investments in debt securities are classified as Level 3For the year ended December 31, 2022 and consistthrough the sale of non-traded debt instruments that are valued basedSTP on third-party market value assessments.
TheNovember 1, 2023, the trust fund investments arewere held primarily to satisfy NRG's nuclear decommissioning obligations. These trust fund investments holdheld debt and equity securities directly and equity securities indirectly through commingled funds. The fair values of equity securities held directly by the trust funds arewere based on quoted prices in active markets and arewere categorized in Level 1. In addition, U.S. government and federal agency obligations arewere categorized as Level 1 because they tradetraded in a highly liquid and transparent market. The fair values of corporate debt securities arewere based on evaluated prices that reflectreflected observable market information, such as actual trade information of similar securities, adjusted for observable differences and arewere categorized in Level 2. Certain equity securities, classified as commingled funds, arewere analogous to mutual funds, arewere maintained by investment companies, and holdheld certain investments in accordance with a stated set of fund objectives. The fair value of the equity securities classified as commingled funds arewere based on net asset values per fund share (the unit of account), derived from the quoted prices in active markets of the underlying equity securities. However, because the shares in the commingled funds arewere not publicly quoted and not traded in an active market, and are subject to certain restrictions regarding their purchase and sale, the commingled funds are categorized in Level 3.were measured using net asset value practical expedient. See also Note 6, 7, Nuclear Decommissioning Trust Fund.
Fund.
Derivative fair value measurements
A portion of theThe Company's contracts are exchange-traded contracts with readily available quoted market prices. A majorityconsist of NRG's contracts are non-exchange-traded contracts valued using prices provided by external sources primarilyand exchange-traded contracts with readily available quoted market prices. Beginning in of the fourth quarter of 2023 and as of December 31, 2023, the fair value of non-exchange traded contracts were based on consensus pricing provided by independent pricing services. The pricing data was compiled from market makers with longer dated tenors as compared to broker quotes, enhancing reliability and increasing transparency.
Prior to the fourth quarter of 2023, the Company valued derivatives based on price quotations available throughquotes from brokers or over-the-counter and on-line exchanges.in active markets who regularly facilitate those transactions. For the majority of markets that NRG markets,participates in, the Company receiveswould receive broker quotes from multiple sources. To the extent that NRG receives multiple quotes, the Company's prices reflectsources and reflected the average of the bid-ask mid-point prices obtained from all sources that NRG believes provide the most liquid market for the commodity. If the Company receives one quote, then the mid-point of the bid-ask spread for that quote is used.prices. The terms for which such price information is available vary by commodity, region and product. A significant portion of the fair value of the Company's derivative portfolio is based on price quotes from brokers in active markets who regularly facilitate those transactions and theThe Company believes suchboth sources of price quotes are executable. The Company does not use third party sources that derive price based on proprietary models or market surveys.
The remainder of the assets and liabilities represents contracts for which external sources or observable market quotes are not available. These contracts are valued based on various valuation techniques including but not limited to internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. ContractsAs of December 31, 2023, contracts valued with prices provided by models and other valuation techniques make up 6%5% of derivative assets and 10%6% of derivative liabilities. As a result of NRG switching to consensus pricing as of December 31, 2023, there was a significant decrease in the number of contracts valued with prices provided by models and other valuation techniques. 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 for foreign exchange contracts and interest rate swaps is calculated utilizing the bilateral method based on published default probabilities. For commodities, to the extent that NRG's net exposure under a specific master agreement is an asset, the Company uses the counterparty's default swap rate. If the exposure under a specific master agreement is a liability, the Company uses NRG's default swap rate. For foreign exchange contracts, interest rate swaps, and commodities, the credit reserve is added to the discounted fair value to reflect the exit price that a market participant would be willing to receive to assume NRG's liabilities or that a market participant would be willing to pay for NRG's assets. As of December 31, 2017,2023, the credit reserve resulted in no change in fair value in operating revenue anda $18 million decrease primarily within cost of operations. As of December 31, 20162022, the credit reserve resulted in a $10$9 million decrease in fair value in operating revenue andprimarily within cost of operations.
The fair values in each category reflect the level of forward prices and volatility factors as of December 31, 2017,2023 and may change as a result of changes in these factors. Management uses its best estimates to determine the fair value of commodity and derivative contracts NRG holds and sells. These estimates consider various factors including closing exchange, consensus and over-the-counter price quotations, time value, volatility factors and credit exposure. It is possible, however, that future market prices could vary from those used in recording assets and liabilities from energy marketing and trading activities and such variations could be material.
NRG's significant positions classified as Level 3 include physical and financial natural gas, power, capacity contracts and renewable energy certificates executed in illiquid markets as well as financial transmission rights or FTRs.("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. Forward capacity prices are based on market information, forecasted future electricity demand and supply, past auctions and internally developed pricing models. Renewable energy certificate prices are based on market information and internally developed pricing models. For FTRs, NRG uses the most recent auction prices to derive the fair value. The Consumer Financing Program derivatives are valued using a discounted cash flow model, with inputs consisting of available market data, such as market yield discount rates, as well as unobservable internally derived assumptions, such as collateral prepayment rates, collateral default rates and credit loss rates.
The following tables quantify the significant unobservable inputs used in developing the fair value of the Company's Level 3 positions as of December 31, 20172023 and 2016:2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Significant Unobservable Inputs |
| December 31, 2023 |
| Fair Value | | | | Input/Range |
| (in millions, except as noted) | Assets | | Liabilities | | Valuation Technique | | Significant Unobservable Input | | Low | | High | | Weighted Average |
| Natural Gas Contracts | $ | 39 | | | $ | 65 | | | Discounted Cash Flow | | Forward Market Price ($ per MMBtu) | | $ | 1 | | | $ | 15 | | | $ | 3 | |
| Power Contracts | 197 | | | 66 | | | Discounted Cash Flow | | Forward Market Price ($ per MWh) | | 1 | | | 210 | | | 47 | |
| Capacity Contracts | 21 | | | 33 | | | Discounted Cash Flow | | Forward Market Price ($ per MW/Day) | | 49 | | | 658 | | | 285 | |
| Renewable Energy Certificates | 58 | | | 14 | | | Discounted Cash Flow | | Forward Market Price ($ per Certificate) | | 2 | | | 320 | | | 15 | |
| FTRs | 19 | | | 37 | | | Discounted Cash Flow | | Auction Prices ($ per MWh) | | (58) | | | 252 | | | 0 | |
| Consumer Financing Program | — | | | 134 | | | Discounted Cash Flow | | Collateral Default Rates | | 0.43 | % | | 93.30 | % | | 8.12 | % |
| | | | | Discounted Cash Flow | | Collateral Prepayment Rates | | 2.00 | % | | 3.00 | % | | 2.95 | % |
| | | | | Discounted Cash Flow | | Credit Loss Rates | | 6.00 | % | | 60.00 | % | | 12.57 | % |
| $ | 334 | | | $ | 349 | | | | | | | | | | | |
| | | | Significant Unobservable Inputs |
| | December 31, 2017 |
| | Fair Value | | Input/Range |
| | Assets | | Liabilities | | Valuation Technique | | Significant Unobservable Input | | Low | | High | | Weighted Average |
| | (In millions) | | | | | | |
| Significant Unobservable Inputs | | | Significant Unobservable Inputs |
| December 31, 2022 | | | December 31, 2022 |
| Fair Value | | | Fair Value | | | | Input/Range |
| (in millions, except as noted) | | (in millions, except as noted) | Assets | | Liabilities | | Valuation Technique | | Significant Unobservable Input | | Low | | High | | Weighted Average |
| Natural Gas Contracts | |
| Power Contracts | $ | 34 |
| | $ | 65 |
| | Discounted Cash Flow | | Forward Market Price (per MWh) | | $ | 10 |
| | $ | 142 |
| | $ | 33 |
|
| FTRs | 11 |
| | 12 |
| | Discounted Cash Flow | | Auction Prices (per MWh) | | (28 | ) | | 46 |
| | — |
|
| $ | |
| | $ | 45 |
| | $ | 77 |
| | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | 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 |
|
| FTRs | 51 |
| | 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 December 31, 20172023 and 2016:
2022: | | | | | | | | | | | | | | | | | | | | |
| | | | | | |
| Significant Unobservable Input | | Position | | Position | Change In Input | | Impact on Fair Value Measurement |
Forward Market Price PowerNatural Gas/Power/Capacity/Renewable Energy Certificates | | Buy | | BuyIncrease/(Decrease) | | Increase/(Decrease) | | Higher/(Lower) |
Forward Market Price PowerNatural Gas/Power/Capacity/Renewable Energy Certificates | | Sell | | SellIncrease/(Decrease) | | Increase/(Decrease) | | Lower/(Higher) |
| FTR Prices | | Buy | | BuyIncrease/(Decrease) | | Increase/(Decrease) | | Higher/(Lower) |
| FTR Prices | | Sell | | SellIncrease/(Decrease) | | Lower/(Higher) |
| Collateral Default Rates | | n/a | | Increase/(Decrease) | | Higher/(Lower) |
| Collateral Prepayment Rates | | n/a | | Increase/(Decrease) | | Lower/(Higher) |
| Credit Loss Rates | | n/a | | Increase/(Decrease) | | Higher/(Lower) |
Under the guidance of ASC 815, entities may choose to offset cash collateral posted or received against the fair value of derivative positions executed with the same counterparties under the same master netting agreements. The Company has chosen not to offset positions as defined in ASC 815. As of December 31, 2017,2023, the Company recorded $171$441 million of cash collateral posted and $37$84 million of cash collateral received on its balance sheet.
ConcentrationEnergy-Related Commodities
As of Credit Risk
In additionDecember 31, 2023, for purposes of measuring the fair value of derivative instruments, the Company primarily uses quoted exchange prices and consensus pricing. Consensus pricing is provided by independent pricing services which are compiled from market makers with longer dated tenors as compared to broker quotes. Prior to the fourth quarter of 2023, the Company valued derivatives based on price quotes from brokers in active markets who regularly facilitate those transactions. The Company started using consensus pricing as it offers data from more market makers and for longer dated tenors as compared to broker quotes, enhances data integrity, and increases transparency. When external prices are not available, NRG uses internal models to determine the fair value. These internal models include assumptions of the future prices of energy commodities based on the specific market in which the energy commodity is being purchased or sold, using externally available forward market pricing curves for all periods possible under the pricing model. These estimations are considered to be critical accounting estimates.
Interest Rate Swaps
NRG is exposed to changes in interest rate through the Company's issuance of variable rate debt. To manage the Company's interest rate risk, NRG enters into interest rate swap agreements. In order to qualify the derivative instruments for hedged transactions, NRG estimates the forecasted borrowings for interest rate swaps occurring within a specified time period.
Foreign Exchange Contracts
In order to mitigate foreign exchange risk primarily associated with the purchase of USD denominated natural gas for the Company's Canadian business, the Company enters into foreign exchange contract agreements.
Consumer Financing Program
The derivative positions for the Company's Consumer Financing Program are valued using a discounted cash flow model, with inputs consisting of available market data, such as market yield discount rates, as well as unobservable internally derived assumptions, such as collateral prepayment rates, collateral default rates and credit loss rates. In summary, the fair value represents an estimate of the present value of the cash flows Vivint Smart Home will be obligated to pay to the third-party financing provider for each component of the derivative.
Certain derivative instruments that meet the criteria for derivative accounting treatment also qualify for a scope exception to derivative accounting, as they are considered to be NPNS. The availability of this exception is based upon the assumption that the Company has the ability and it is probable to deliver or take delivery of the underlying item. These assumptions are based on expected load requirements, internal forecasts of sales and generation and historical physical delivery on contracts. Derivatives that are considered to be NPNS are exempt from derivative accounting treatment and are accounted for under accrual accounting. If it is determined that a transaction designated as NPNS no longer meets the scope exception due to changes in estimates, the related contract would be recorded on the balance sheet at fair value combined with the immediate recognition through earnings.
Income Taxes and Valuation Allowance for Deferred Tax Assets
As of December 31, 2023, NRG’s deferred tax assets were primarily the result of U.S. federal and state NOLs, the difference between book and tax basis in property, plant, and equipment, deferred revenues and tax credit carryforwards. The realization of deferred tax assets is dependent upon the Company's ability to generate sufficient future taxable income during the periods in which those temporary differences become deductible, prior to the expiration of the tax attributes. The evaluation of deferred tax assets requires judgment in assessing the likely future tax consequences of events that have been recognized in the Company's financial statements or tax returns and forecasting future profitability by tax jurisdiction.
The Company evaluates its deferred tax assets quarterly on a jurisdictional basis to determine whether adjustments to the valuation allowance are appropriate considering changes in facts or circumstances. As of each reporting date, management considers new evidence, both positive and negative, when determining the future realization of the Company’s deferred tax assets. Given the Company’s current level of pre-tax earnings and forecasted future pre-tax earnings, the Company expects to generate income before taxes in the U.S. in future periods at a level that would fully utilize its U.S. federal NOL carryforwards and the majority of its state NOL carryforwards prior to their expiration.
The Company continues to maintain a valuation allowance of $275 million as of December 31, 2023 against deferred tax assets consisting of state NOL carryforwards and foreign NOL carryforwards in jurisdictions where the Company does not currently believe that the realization of deferred tax assets is more likely than not. As of December 31, 2022, the Company's valuation allowance balance was $224 million.
Considerable judgment is required to determine the tax treatment of a particular item that involves interpretations of complex tax laws. The Company is subject to examination by taxing authorities for income tax returns filed in the U.S. federal jurisdiction and various state and foreign jurisdictions, including operations located in Australia and Canada.The Company continues to be under audit for multiple years by taxing authorities in various jurisdictions.
The Company is no longer subject to U.S. federal income tax examinations for years prior to 2020.With few exceptions, state and Canadian income tax examinations are no longer open for years before 2015.
NRG does not intend, nor currently foresee a need, to repatriate funds held at its international operations into the U.S. These funds are deemed to be indefinitely reinvested in its foreign operations and the Company has not changed its assertion with respect to distributions of funds that would require the accrual of U.S. income tax.
Evaluation of Assets for Impairment
In accordance with ASC 360, Property, Plant, and Equipment ("ASC 360"), the Company evaluates property, plant and equipment and certain intangible assets for impairment whenever indicators of impairment exist. Examples of such indicators or events include:
•Significant decrease in the market price of a long-lived asset;
•Significant adverse change in the manner an asset is being used or its physical condition;
•Adverse business climate;
•Accumulation of costs significantly in excess of the amounts originally expected for the construction or acquisition of an asset;
•Current period loss combined with a history of losses or the projection of future losses; and
•Change in the Company's intent about an asset from an intent to hold to a greater than 50% likelihood that an asset will be sold, or disposed of before the end of its previously estimated useful life.
Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the assets to the future net cash flows expected to be generated by the asset, through considering project specific assumptions for long-term power and natural gas prices, escalated future project operating costs and expected plant operations. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets by factoring in the different courses of action available to the Company. Generally, fair value will be determined using valuation techniques, such as the present value of expected future cash flows. NRG uses its best estimates in making these evaluations and considers various factors, including forward price curves for energy, fuel and operating costs. However, actual future market prices and project costs could vary from the assumptions used in the Company's estimates and the impact of such variations could be material.
For assets to be held and used, if the Company determines that the undiscounted cash flows from the asset are less than the carrying amount of the asset, NRG must estimate fair value to determine the amount of any impairment loss. Assets held-for-sale are reported at the lower of the carrying amount or fair value less the cost to sell. The estimation of fair value, whether in conjunction with an asset to be held and used or with an asset held-for-sale, and the evaluation of asset impairment are, by their nature, subjective. The Company considers quoted market prices in active markets to the extent they are available. In the absence of such information, NRG may consider prices of similar assets, consult with brokers or employ other valuation techniques. The Company will also discount the estimated future cash flows associated with the asset using a single interest rate representative of the risk involved with such an investment or asset. The use of these methods involves the same inherent uncertainty of future cash flows as previously discussed with respect to undiscounted cash flows. Actual future market prices and project costs could vary from those used in NRG's estimates and the impact of such variations could be material.
Annually, during the fourth quarter, the Company revises its views of power and fuel prices including the Company's fundamental view for long-term prices, forecasted generation and operating and capital expenditures, in connection with the preparation of its annual budget. Changes to the Company's views of long-term power and fuel prices impact the Company’s projections of profitability, based on management's estimate of supply and demand within the sub-markets for its operations and the physical and economic characteristics of each of its businesses.
For further discussion, see Item 15 — Note 11, Asset Impairments.
Goodwill and Other Intangible Assets
At December 31, 2023, the Company reported goodwill of $5.1 billion, consisting of $3.5 billion from the acquisition of Vivint in 2023, $1.3 billion from the acquisition of Direct Energy in 2021 and $0.3 billion from other retail acquisitions.
The Company applies ASC 805, Business Combinations ("ASC 805"), and ASC 350, Intangibles-Goodwill and Other ("ASC 350") to account for its goodwill and intangible assets. Under these standards, the Company amortizes all finite-lived intangible assets over their respective estimated weighted-average useful lives, while goodwill has an indefinite life and is not amortized. Goodwill is tested for impairment at least annually, or more frequently whenever an event or change in circumstances occurs that would more likely than not reduce the fair value of a reporting unit below its carrying amount. The Company tests goodwill for impairment at the reporting unit level, which is identified by assessing whether the components of the Company's operating segments constitute businesses for which discrete financial information is available and whether segment management regularly reviews the operating results of those components. The Company performs the annual goodwill impairment assessment as disclosedof December 31 or when events or changes in circumstances indicate that the fair value of the reporting unit may be below the carrying amount. The Company may first assess qualitative factors to determine whether it is more likely than not that an impairment has occurred. In the absence of sufficient qualitative factors, the Company performs a quantitative assessment by determining the fair value of the reporting unit and comparing to its book value. If it is determined that the fair value of a reporting unit is below its carrying amount, the Company's goodwill will be impaired at that time.
Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. As a result, there can be no assurance that the estimates and assumptions made for purposes of the annual goodwill impairment test will prove to be accurate predictions of the future.
For further discussion, see Evaluation of Assets for Impairment caption above, and Item 15 — Note 11, Asset Impairments.
Business Combinations
NRG accounts for business acquisitions using the acquisition method of accounting prescribed under ASC 805. Under this method, the Company is required to record on its Consolidated Balance Sheets the estimated fair values of the acquired company’s assets and liabilities assumed at the acquisition date. The excess of the consideration transferred over the fair value of the net identifiable assets acquired and liabilities assumed is recorded as goodwill. Determining fair values of assets acquired and liabilities assumed requires significant estimates and judgments. Fair value is determined based on the estimated price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The acquired assets and assumed liabilities from the Vivint Smart Home acquisition that involved the most subjectivity in determining fair value consisted of customer relationships, developed technology, trade names, acquired debt and derivative instruments. NRG describes in detail its acquisitions in Item 15 — Note 4, Acquisitions and Dispositions, to the Consolidated Financial Statements.
The fair value of the customer relationships, technology and trade names are measured using income-based valuation methodologies, which include certain assumptions such as forecasted future cash flows, customer attrition rates, royalty rates and discount rates. Customer relationships and technology are amortized to depreciation and amortization, ratably based on discounted future cash flows. Trade names are amortized to depreciation and amortization, on a straight line basis.
The acquired Vivint Smart Home debt was measured at fair value using observable market inputs based on interest rates at the acquisition closing date. The difference between the fair value at the acquisition closing date and the principal outstanding is being amortized through interest expense over the remaining term of the debt.
The derivative liabilities in connection with the contractual future payment obligations with the financing providers under Vivint Smart Home’s Consumer Financing Program were measured at fair value at the acquisition closing date using a discounted cash flow model, with inputs consisting of available market data, such as market yield discount rates, as well as unobservable internally derived assumptions, such as collateral prepayment rates, collateral default rates and credit loss rates. Changes to the fair value are recorded each period through other income, net in the consolidated statement of operations.
Contingencies
NRG records reserves 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. Gain contingencies are not recorded until management determines it is certain that the future event will become or does become a reality. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events, and estimates of the financial impacts of such events. NRG describes in detail its contingencies in Item 15 — Note 23, Commitments and Contingencies, to the Consolidated Financial Statements.
Recent Accounting Developments
See Item 15 — Note 2,, Summary of Significant Accounting Policies,, to the following item isConsolidated Financial Statements for a discussion of recent accounting developments.
Item 7A — Quantitative and Qualitative Disclosures About Market Risk
NRG is exposed to several market risks in the concentrationCompany'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 transactions. The types of market risks the Company is exposed to are commodity price risk, credit risk, liquidity risk, interest rate risk and currency exchange risk. In order to manage these risks, the Company uses various fixed-price forward purchase and sales contracts, futures and option contracts traded on NYMEX and other exchanges, and swaps and options traded in the over-the-counter financial markets to:
•Manage and hedge fixed-price purchase and sales commitments;
•Reduce exposure to the volatility of cash market prices, and
•Hedge fuel requirements for the Company's generating facilities.
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 servicing obligations and merchant generation operations by entering into various derivative or non-derivative instruments to hedge the variability in future cash flows from forecasted sales and purchases of power 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 instruments. transactions, based on historical and forward values for factors such as customer demand, weather, commodity availability and commodity prices. The Company's VaR model is based on a one-day holding period at a 95% confidence interval for the forward 36 months, not including the spot month. The VaR model is not a complete picture of all risks that may affect the Company's results. Certain events such as counterparty defaults, regulatory changes, and extreme weather and prices that deviate significantly from historically observed values are not reflected in the model.
The following table summarizes average, maximum and minimum VaR for NRG's commodity portfolio, calculated using the VaR model for the years ended December 31, 2023 and 2022:
| | | | | | | | | | | |
| (In millions) | 2023 | | 2022 |
| VaR as of December 31, | $ | 51 | | | $ | 74 | |
| For the year ended December 31, | | | |
| Average | $ | 62 | | | $ | 51 | |
| Maximum | 82 | | | 86 | |
| Minimum | 41 | | | 26 | |
The Company also uses VaR to estimate the potential loss of derivative financial instruments that are subject to mark-to-market accounting. These derivative instruments include transactions that were entered into for both asset management and trading purposes. The VaR for the derivative financial instruments calculated using the diversified VaR model for the entire term of these instruments entered into for both asset management and trading was $185 million as of December 31, 2023, primarily driven by asset-backed 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 6, Accounting for Derivative Instruments and Hedging Activities, to this Form 10-K for discussion regarding credit risk contingent features.
Counterparty 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. The Company monitors and manages credit risk through credit policies that include: (i) an established credit approval process; (ii) a daily monitoring of counterparties' credit limits; (iii) the use of credit mitigation measures such as margin, collateral, prepayment arrangements, or volumetric limits; (iv) the use of payment netting agreements; and (v) the use of master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with a single counterparty. Risks surrounding counterparty performance and credit could ultimately impact the amount and timing of expected cash flows. The Company seeks to mitigate counterparty risk by having a diversified portfolio of counterparties. The Company also has credit protection within various agreements to call on additional collateral support if and when necessary. Cash margin is collected and held at the Company to cover the credit risk of the counterparty until positions settle.
Counterparty Credit Risk
As of December 31, 2017,2023, counterparty credit exposure, excluding credit exposure from RTOs, ISOs, and registered commodity exchanges and certain long-term agreements, was $220 million and NRG$1.6 billion, of which the Company held collateral (cash and letters of credit) against those positions of $30$426 million, resulting in a net exposure of $196 million.$1.2 billion. NRG periodically receives collateral from counterparties in excess of their exposure. Collateral amounts shown include such excess while net exposure shown excludes excess collateral received. Approximately 73%63% of the Company's exposure before collateral is expected to roll off by the end of 2019. Counterparty credit exposure is valued through observable market quotes and discounted at a risk free interest rate.2025. The following tables highlighttable highlights the 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. TheAs of December 31, 2023, the aggregate credit exposure is shown net of collateral held, and includes amounts net of receivables or payables.
| | | | | |
| | |
| Category | Net Exposure (a) (b) (% of Total) |
Financial institutions | 14 | % |
| Utilities, energy merchants, marketers and other | 8680 |
% |
| Financial institutions | 20 | |
| |
| |
| Total | 100 | % |
| | | | | |
| | |
| Category | Net Exposure(a) (b) (% of Total) |
| Investment grade | 6944 | % |
| Non-Investment grade/Non-Rated | 3156 | |
| |
| Total | 100 | % |
| |
(a) | (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 has exposure to one wholesale counterparty in excess of 10% 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 risk exposure to certain counterparties, each of which represent more than 10% of total net exposure discussed above. The aggregate of such counterparties' exposure was $37 millionabove as of December 31, 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 subject 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, wind andlong-term contracts, primarily solar under Renewable PPAs. As external sources or observable market quotes are not available to estimate such exposure, the Company values these contracts based on various techniques including, but not limited to, internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. Based on these valuation techniques, as of December 31, 2017,2023, aggregate credit risk exposure managed by NRG to these counterparties was approximately $4.1 billion, including $2.6 billion related to assets of NRG Yield, Inc.,$882 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, which NRG is unable to predict.
Retail Customer Credit Risk
The CompanyNRG is exposed to retail credit risk through the Company's retail electricity and gas providers which serve C&I customers and the Mass market.as well as through Vivint Smart Home. Retail credit risk results in losses when a customer fails to pay for services rendered. The losses may result from both nonpayment 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, thatwhich include monitoring of the portfolio and the use of credit mitigation measures such as deposits or prepayment arrangements.
As of December 31, 2017,2023, the Company's retail customer credit exposure to C&IHome and MassBusiness customers was diversified across many customers and various industries, as well as government entities. The Company is also subject to risk with respect to its residential solar customers. The Company's bad debt expense was $68 million, $48 million, and $64 million for the years ending December 31, 2017, 2016, and 2015, respectively. 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 badcredit losses. The Company's provision for credit losses resulting from credit risk was $251 million, $11 million and $698 million for the years ended December 31, 2023, 2022 and 2021, respectively. During the year ended December 31, 2022, the provision for credit losses included the Company's loss mitigation efforts recognized as income of $126 million related to Winter Storm Uri. During the year ended December 31, 2021, the provision for credit losses included $596 million of expenses due to the impacts of Winter Storm Uri.
Liquidity Risk
Liquidity risk arises from the general funding needs of the Company's activities and 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 December 31, 2023, a $0.50 per MMBtu decrease in natural gas prices across the term of the marginable contracts would cause an increase in margin collateral posted of approximately $1.5 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 $350 million. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of December 31, 2023.
Interest Rate Risk
NRG is exposed to fluctuations in interest rates through its issuance of variable rate debt. Exposures to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, caps, collars and put or call options. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt expense.obligations when taking into account the combinations 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. 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, in the first quarter of 2023, the Company had entered into interest rate swaps to hedge the floating rate on the Revolving Credit Facility extending through 2024, which was fully terminated in conjunction with the pay down of the Revolving Credit Facility.
As of December 31, 2023, the Company's debt fair value was $10.6 billion and carrying value was $10.8 billion. NRG estimates that a 1% decrease in market interest rates would have increased the fair value of the Company's long-term debt by $602 million. Currency Exchange Risk
NRG is subject to transactional exchange rate risk from transactions with customers in countries outside of the U.S., primarily within Canada, as well as from intercompany transactions between affiliates. Transactional exchange rate risk arises from the purchase and sale of goods and services in currencies other than the Company's functional currency or the functional currency of an applicable subsidiary. NRG hedges a portion of its forecasted currency transactions with foreign exchange forward contracts. As of December 31, 2023, NRG is exposed to changes in foreign currency primarily associated with the purchase of U.S. dollar denominated natural gas for its Canadian business and entered into foreign exchange contracts with a notional amount of $548 million.
The Company is subject to translation exchange rate risk related to the translation of the financial statements of its foreign operations into U.S. dollars. Costs incurred and sales recorded by subsidiaries operating outside of the U.S. are translated into U.S. dollars using exchange rates effective during the respective period. As a result, the Company is exposed to movements in the exchange rates of various currencies against the U.S. dollar, primarily the Canadian and Australian dollars. A hypothetical 10% appreciation in major currencies relative to the U.S. dollar as of December 31, 2023, would have resulted in a decrease of $36 million to net income within the Consolidated Statement of Operations.
Item 8 — Financial Statements and Supplementary Data
The financial statements and schedules are included in Part IV, Item 15 of this Form 10-K.
Item 9 — Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
Item 9A — Controls and Procedures
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures and Internal Control Over Financial Reporting
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 Annual Report on Form 10-K. Management's report on the Company's internal control over financial reporting and the report of the Company's independent registered public accounting firm are incorporated under the caption "Management's Report on Internal Control over Financial Reporting" and under the caption "Report of Independent Registered Public Accounting Firm" in this Annual Report on Form 10-K for the fiscal year ended December 31, 2023.
Changes in Internal Control over Financial Reporting
During the year ended December 31, 2023, the Company completed its acquisition of Vivint Smart Home, Inc. As part of integration, the Company designed and implemented a control structure over Vivint Smart Home's operations. Other than the Vivint Smart Home acquisition, there were no changes in NRG’s internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred in the fourth quarter of 2023 that materially affected, or are reasonably likely to materially affect, NRG’s internal control over financial reporting.
Inherent Limitations over Internal Controls
NRG's internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with GAAP. The Company's internal control over financial reporting includes those policies and procedures that:
1.Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the Company's assets;
2.Provide reasonable assurance that transactions are recorded as necessary to permit preparation of consolidated financial statements in accordance with GAAP, and that the Company's receipts and expenditures are being made only in accordance with authorizations of its management and directors; and
3.Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the consolidated financial statements.
Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations, including the possibility of human error and circumvention by collusion or overriding of controls. Accordingly, even an effective internal control system may not prevent or detect material misstatements on a timely basis. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
Management's Report on Internal Control over Financial Reporting
The Company's management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of the Company's management, including its principal executive officer, principal financial officer and principal accounting officer, the Company conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Company's evaluation under the framework in Internal Control — Integrated Framework (2013), the Company's management concluded that its internal control over financial reporting was effective as of December 31, 2023.
On March 10, 2023, NRG acquired Vivint Smart Home, Inc., and management excluded from its assessment of the effectiveness of the Company's internal control over financial reporting as of December 31, 2023, Vivint Smart Home, Inc.'s internal control over financial reporting associated with total assets (excluding acquired goodwill and intangible assets) of 5% and total revenues of 5% included in the consolidated financial statements of the Company as of and for the year ended December 31, 2023.
The effectiveness of the Company's internal control over financial reporting as of December 31, 2023 has been audited by KPMG LLP, the Company's independent registered public accounting firm, as stated in its report which is included in this Annual Report on Form 10-K.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
NRG Energy, Inc.:
Opinion on Internal Control Over Financial Reporting
We have audited NRG Energy, Inc. and subsidiaries' (the Company) internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2023 and 2022, the related consolidated statements of operations, comprehensive (loss)/income, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2023, and the related notes and financial statement schedule II (collectively, the consolidated financial statements), and our report dated February 28, 2024 expressed an unqualified opinion on those consolidated financial statements.
The Company acquired Vivint Smart Home, Inc. during 2023, and management excluded from its assessment of the effectiveness of the Company's internal control over financial reporting as of December 31, 2023, Vivint Smart Home, Inc.'s internal control over financial reporting associated with total assets (excluding acquired goodwill and intangible assets) of 5% and total revenues of 5% included in the consolidated financial statements of the Company as of and for the year ended December 31, 2023. Our audit of internal control over financial reporting of the Company also excluded an evaluation of the internal control over financial reporting of Vivint Smart Home, Inc.
Basis for Opinion
The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ KPMG LLP
Philadelphia, Pennsylvania
February 28, 2024
Item 9B — Other Information
Director and Officer Trading Arrangements
During the three months ended December 31, 2023, the following directors or officers of the Company adopted or terminated a 'Rule 10b5-1 trading arrangement' or 'non-Rule 10b5-1 trading arrangement,' as each term is defined in Item 408(a) of Regulation S-K, as described in the table below:
| | | | | | | | | | | | | | | | | | | | |
| Name | Title | Date Adopted | Character of Trading Arrangement | Aggregate Number of Shares of Common Stock to be Purchased or Sold Pursuant to Trading Arrangement(a) | Duration | Date Terminated |
| Elizabeth Killinger | Executive Vice President | 12/15/2023 | Rule 10b5-1 Trading Arrangement | 65,583 shares to be Sold(b) | 3/15/2024-1/31/2025 | N/A |
| Rasesh Patel | Executive Vice President, Smart Home | 12/15/2023 | Rule 10b5-1 Trading Arrangement | Up to 73,638 shares to be Sold | 3/14/2024-11/01/2024 | N/A |
(a)Potential sales may be subject to certain price limitations set forth in the 10b5-1 plans and therefore actual number of shares sold could vary if certain minimum stock prices are not met
(b)Represents approximate number of shares to be sold based on outstanding awards expected to vest during the period, where any underlying performance share awards are being calculated at target. Actual number of shares to be sold will depend on actual vesting, the number of shares withheld by NRG to satisfy tax withholding obligations and vesting of dividend equivalent rights
Item 9C — Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable.
PART III
Item 10 — Directors, Executive Officers and Corporate Governance
Directors and Executive Officers
Information required by this Item is incorporated by reference to the similarly named section of NRG's Definitive Proxy Statement for its 2024 Annual Meeting of Stockholders.
Code of Ethics
NRG has adopted a code of ethics entitled "NRG Code of Conduct" that applies to directors, officers and employees, including the chief executive officer and senior financial officers of NRG. It may be accessed through the "Governance" section of the Company's website at www.nrg.com. NRG also elects to disclose the information required by Form 8-K, Item 5.05, "Amendments to the Registrant's Code of Ethics, or Waiver of a Provision of the Code of Ethics," through the Company's website, and such information will remain available on this website for at least a 12-month period. A copy of the "NRG Code of Conduct" is available in print to any stockholder who requests it.
Other information required by this Item is incorporated by reference to the similarly named section of NRG's Definitive Proxy Statement for its 2024 Annual Meeting of Stockholders.
Item 11 — Executive Compensation
Information required by this Item is incorporated by reference to the similarly named section of NRG's Definitive Proxy Statement for its 2024 Annual Meeting of Stockholders.
Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Securities Authorized for Issuance under Equity Compensation Plans
| | | | | | | | | | | | | | | | | | | | |
| Plan Category | (a)
Number of Securities
to be Issued Upon
Exercise of
Outstanding Options,
Warrants and Rights | | (b)
Weighted-Average Exercise
Price of Outstanding
Options, Warrants and
Rights | | (c)
Number of Securities
Remaining Available
for Future Issuance
Under Equity Compensation
Plans (Excluding
Securities Reflected
in Column (a)) | |
| Equity compensation plans approved by security holders | 2,997,640 | | (1) | $ | — | | | 14,419,264 | | |
| Equity compensation plans not approved by security holders | 3,970,872 | | (2) | $ | — | | | 12,749,736 | | |
| Total | 6,968,512 | | | $ | — | | | 27,169,000 | | (3) |
(1)Consists of shares issuable under the NRG LTIP and the ESPP. On April 27, 2023, NRG stockholders approved an increase of 4,400,000 shares available for issuance under the ESPP. As of December 31, 2023, there were 6,702,125 shares reserved from the Company's treasury shares for the ESPP
(2)Consists of shares issuable under the Vivint LTIP. On March 10, 2023, in connection with the Acquisition, NRG assumed the Vivint Smart Home, Inc. 2020 Omnibus Incentive Plan. While the Vivint Smart Home, Inc. 2020 Omnibus Incentive Plan was previously approved by stockholders of Vivint Smart Home, Inc., the plan is listed as "not approved" because it was assumed as part of the Acquisition and not subject to approval by NRG stockholders. The Company intends to make subsequent grants under the Vivint LTIP. See Note 521, Stock-Based Compensation for a discussion of the Vivint LTIP
(3)Consists of 7,717,139 shares of common stock under the NRG LTIP, 12,749,736 shares of common stock under the Vivint LTIP and 6,702,125 shares of treasury stock reserved for issuance under the ESPP
The NRG LTIP currently provides for grants of restricted stock units, relative performance stock units, deferred stock units and dividend equivalent rights. The Vivint LTIP currently provides for grants of restricted stock units and performance stock units. The Company's directors, officers and employees, as well as other individuals performing services for, or to whom an offer of employment has been extended by the Company, are eligible to receive grants under the LTIPs. The purpose of the LTIPs is to promote the Company's long-term growth and profitability by providing these individuals with incentives to maximize stockholder value and otherwise contribute to the Company's success and to enable the Company to attract, retain and reward the best available persons for positions of responsibility. The Compensation Committee of the Board of Directors administers the LTIPs.
Other information required by this Item is incorporated by reference to the similarly named section of NRG's Definitive Proxy Statement for its 2024 Annual Meeting of Stockholders.
Item 13 — Certain Relationships and Related Transactions, and Director Independence
Information required by this Item is incorporated by reference to the similarly named section of NRG's Definitive Proxy Statement for its 2024 Annual Meeting of Stockholders.
Item 14 — Principal Accounting Fees and Services
Information required by this Item is incorporated by reference to the similarly named section of NRG's Definitive Proxy Statement for its 2024 Annual Meeting of Stockholders.
PART IV
Item 15 — Exhibits, Financial Statement Schedules
(a)(1) Financial Statements
The following consolidated financial statements of NRG Energy, Inc. and related notes thereto, together with the reports thereon of KPMG LLP, Philadelphia, PA, Auditor Firm ID: 185, are included herein:
Consolidated Statements of Operations — Years ended December 31, 2023, 2022, and 2021
Consolidated Statements of Comprehensive (Loss)/Income — Years ended December 31, 2023, 2022, and 2021
Consolidated Balance Sheets — As of December 31, 2023 and 2022
Consolidated Statements of Cash Flows — Years ended December 31, 2023, 2022, and 2021
Consolidated Statements of Stockholders' Equity — Years ended December 31, 2023, 2022, and 2021
Notes to Consolidated Financial Statements
(a)(2) Financial Statement Schedule
The following Consolidated Financial Statement Schedule of NRG Energy, Inc. is filed as part of Item 15 of this report and should be read in conjunction with the Consolidated Financial Statements.
Schedule II — Valuation and Qualifying Accounts
All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions or are inapplicable, and therefore, have been omitted.
(a)(3) Exhibits: See Exhibit Index submitted as a separate section of this report.
(b) Exhibits
See Exhibit Index submitted as a separate section of this report.
(c) Not applicable
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
NRG Energy, Inc.:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of NRG Energy, Inc. and subsidiaries (the Company) as of December 31, 2023 and 2022, the related consolidated statements of operations, comprehensive (loss)/income, stockholders' equity, and cash flows for each of the years in the three-year period ended December 31, 2023, and the related notes and financial statement schedule II (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2023, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 28, 2024 expressed an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Evaluation of the sufficiency of audit evidence over revenues
As discussed in Note 3 to the consolidated financial statements, the Company had $28,823 million of revenues. Revenue is derived from various revenue streams in different geographic markets and the Company’s processes and related information technology (IT) systems used to record revenue differ for each of these revenue streams.
We identified the evaluation of the sufficiency of audit evidence over revenues as a critical audit matter which required a high degree of auditor judgment due to the number of revenue streams and IT systems involved in the revenue recognition process. This included determining the revenue streams over which procedures were to be performed and evaluating the nature and extent of evidence obtained over the individual revenue streams as well as revenue in the aggregate. It also included the involvement of IT professionals with specialized skills and knowledge to assist in the performance of certain procedures.
The following are the primary procedures we performed to address this critical audit matter. We, with the assistance of IT professionals, applied auditor judgment to determine the revenue streams over which procedures were performed as well as the nature and extent of such procedures. For certain revenue streams over which procedures were performed,
we evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s revenue recognition processes. For certain revenue streams, we involved IT professionals, who assisted in testing certain IT applications used by the Company in its revenue recognition processes. In addition, we assessed recorded revenue for a selection of transactions by comparing the amounts recognized to underlying documentation, including contracts with customers, and for certain revenue streams, we performed a software-assisted data analysis to assess certain relationships among revenue transactions. In addition, we evaluated the sufficiency of audit evidence obtained over revenues by assessing the results of procedures performed, including the appropriateness of such evidence.
Fair value of certain acquired intangible assets
As discussed in Note 4 to the consolidated financial statements, the Company acquired Vivint Smart Home, Inc. on March 10, 2023 for total consideration of $2,623 million. In connection with the business combination, the Company recorded various intangible assets, which included customer relationships and technology intangible assets with an acquisition-date fair value of $1,740 million and $860 million, respectively.
We identified the evaluation of the acquisition-date fair value of the customer relationships and technology intangible assets as a critical audit matter. A high degree of subjective and complex auditor judgment was required to evaluate key assumptions used to value these acquired intangible assets. We performed sensitivity analyses to determine the key assumptions used to value the intangible assets acquired which required challenging auditor judgment. Specifically, key assumptions included the customer attrition for the customer relationships intangible asset and the discount rate for the customer relationships and technology intangible assets. Changes to these assumptions could have had a significant impact on the fair value of such assets. In addition, valuation professionals with specialized skills and knowledge were needed to assist in the evaluation of the discount rate.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the Company’s acquisition-date valuation process, including controls related to the selection of the customer attrition used in the customer relationships intangible asset and the discount rate used in the customer relationships and technology intangible assets. We evaluated the customer attrition used by the Company by comparing it to historical attrition experienced by the acquired company and comparable company attrition. We involved valuation professionals with specialized skills and knowledge, who assisted in evaluating the discount rate by assessing the relative risk profile of the customer relationships and technology intangible assets compared to the required rate of return of all acquired assets in the business combination.
/s/ KPMG LLP
We have served as the Company's auditor since 2004.
Philadelphia, Pennsylvania
February 28, 2024
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS | | | | | | | | | | | | | | | | | |
| | For the Year Ended December 31, |
| (In millions, except per share amounts) | 2023 | | 2022 | | 2021 |
| Revenue | | | | | |
| Revenue | $ | 28,823 | | | $ | 31,543 | | | $ | 26,989 | |
| Operating Costs and Expenses | | | | | |
| Cost of operations (excluding depreciation and amortization shown below) | 26,526 | | | 27,446 | | | 20,482 | |
| Depreciation and amortization | 1,127 | | | 634 | | | 785 | |
| Impairment losses | 26 | | | 206 | | | 544 | |
| Selling, general and administrative costs | 1,968 | | | 1,228 | | | 1,293 | |
| Provision for credit losses | 251 | | | 11 | | | 698 | |
| Acquisition-related transaction and integration costs | 119 | | | 52 | | | 93 | |
| Total operating costs and expenses | 30,017 | | | 29,577 | | | 23,895 | |
| | | | | |
| Gain on sale of assets | 1,578 | | | 52 | | | 247 | |
| Operating Income | 384 | | | 2,018 | | | 3,341 | |
| Other Income/(Expense) | | | | | |
| Equity in earnings of unconsolidated affiliates | 16 | | | 6 | | | 17 | |
| Impairment losses on investments | (102) | | | — | | | — | |
| Other income, net | 47 | | | 56 | | | 63 | |
| | | | | |
| Gain/(Loss) on debt extinguishment | 109 | | | — | | | (77) | |
| Interest expense | (667) | | | (417) | | | (485) | |
| Total other expense | (597) | | | (355) | | | (482) | |
| (Loss)/Income Before Income Taxes | (213) | | | 1,663 | | | 2,859 | |
| Income tax (benefit)/expense | (11) | | | 442 | | | 672 | |
| | | | | |
| | | | | |
| Net (Loss)/Income | (202) | | | 1,221 | | | 2,187 | |
| Less: Cumulative dividends attributable to Series A Preferred Stock | 54 | | | — | | | — | |
| Net (Loss)/Income Available for Common Stockholders | $ | (256) | | | $ | 1,221 | | | $ | 2,187 | |
| (Loss)/Income Per Share | | | | | |
| Weighted average number of common shares outstanding — basic and diluted | 228 | | | 236 | | | 245 | |
| | | | | |
| | | | | |
| (Loss)/Income per Weighted Average Common Share — Basic and Diluted | $ | (1.12) | | | $ | 5.17 | | | $ | 8.93 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
See notes to Consolidated Financial Statements
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS)/INCOME | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, |
| (In millions) | 2023 | | 2022 | | 2021 |
| Net (Loss)/Income | $ | (202) | | | $ | 1,221 | | | $ | 2,187 | |
| Other Comprehensive Income/(Loss), net of tax | | | | | |
| | | | | |
| Foreign currency translation adjustments | 9 | | | (35) | | | (5) | |
| | | | | |
| Defined benefit plans | 30 | | | (16) | | | 85 | |
| Other comprehensive income/(loss) | 39 | | | (51) | | | 80 | |
| Comprehensive (Loss)/Income | $ | (163) | | | $ | 1,170 | | | $ | 2,267 | |
| | | | | |
| | | | | |
See notes to Consolidated Financial Statements
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS | | | | | | | | | | | |
| | As of December 31, |
| (In millions) | 2023 | | 2022 |
| ASSETS | | | |
| Current Assets | | | |
| Cash and cash equivalents | $ | 541 | | | $ | 430 | |
| Funds deposited by counterparties | 84 | | | 1,708 | |
| Restricted cash | 24 | | | 40 | |
| Accounts receivable, net | 3,542 | | | 4,773 | |
| | | |
| Inventory | 607 | | | 751 | |
| Derivative instruments | 3,862 | | | 7,886 | |
| Cash collateral paid in support of energy risk management activities | 441 | | | 260 | |
| | | |
| Prepayments and other current assets | 626 | | | 383 | |
| | | |
| | | |
| Total current assets | 9,727 | | | 16,231 | |
| Property, plant and equipment, net | 1,763 | | | 1,692 | |
| Other Assets | | | |
| Equity investments in affiliates | 42 | | | 133 | |
| Operating lease right-of-use assets, net | 179 | | | 225 | |
| | | |
| Goodwill | 5,079 | | | 1,650 | |
| Customer relationships, net | 2,164 | | | 943 | |
| Other intangible assets, net | 1,763 | | | 1,189 | |
| Nuclear decommissioning trust fund | — | | | 838 | |
| Derivative instruments | 2,293 | | | 4,108 | |
| Deferred income taxes | 2,251 | | | 1,881 | |
| Other non-current assets | 777 | | | 256 | |
| | | |
| | | |
| Total other assets | 14,548 | | | 11,223 | |
| Total Assets | $ | 26,038 | | | $ | 29,146 | |
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Continued) | | | | | | | | | | | |
| | As of December 31, |
| (In millions, except share data) | 2023 | | 2022 |
| LIABILITIES AND STOCKHOLDERS' EQUITY | | | |
| Current Liabilities | | | |
| Current portion of long-term debt and finance leases | $ | 620 | | | $ | 63 | |
| Current portion of operating lease liabilities | 90 | | | 83 | |
| Accounts payable | 2,325 | | | 3,643 | |
| | | |
| Derivative instruments | 4,019 | | | 6,195 | |
| Cash collateral received in support of energy risk management activities | 84 | | | 1,708 | |
| Deferred revenue current | 720 | | | 176 | |
| Accrued expenses and other current liabilities | 1,642 | | | 1,114 | |
| | | |
| | | |
| | | |
| Total current liabilities | 9,500 | | | 12,982 | |
| Other Liabilities | | | |
| Long-term debt and finance leases | 10,133 | | | 7,976 | |
| Non-current operating lease liabilities | 128 | | | 180 | |
| Nuclear decommissioning reserve | — | | | 340 | |
| Nuclear decommissioning trust liability | — | | | 477 | |
| | | |
| Derivative instruments | 1,488 | | | 2,246 | |
| Deferred income taxes | 22 | | | 134 | |
| Deferred revenue non-current | 914 | | | 10 | |
| Other non-current liabilities | 947 | | | 973 | |
| | | |
| | | |
| Total other liabilities | 13,632 | | | 12,336 | |
| Total Liabilities | 23,132 | | | 25,318 | |
| | | |
| Commitments and Contingencies | | | |
| Stockholders' Equity | | | |
| Preferred stock; 10,000,000 shares authorized; 650,000 Series A shares issued and outstanding at December 31, 2023 (aggregate liquidation preference $650); 0 shares issued and outstanding at December 31, 2022 | 650 | | | — | |
| Common stock; $0.01 par value; 500,000,000 shares authorized; 267,330,470 and 423,897,001 shares issued; and 208,130,950 and 229,561,030 shares outstanding at December 31, 2023 and 2022, respectively | 3 | | | 4 | |
| Additional paid-in capital | 3,416 | | | 8,457 | |
| Retained earnings | 820 | | | 1,408 | |
| Treasury stock, at cost; 59,199,520 and 194,335,971 shares at December 31, 2023 and 2022, respectively | (1,892) | | | (5,864) | |
| Accumulated other comprehensive loss | (91) | | | (177) | |
| Total Stockholders' Equity | 2,906 | | | 3,828 | |
| Total Liabilities and Stockholders' Equity | $ | 26,038 | | | $ | 29,146 | |
See notes to Consolidated Financial Statements
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS | | | | | | | | | | | | | | | | | |
| | For the Year Ended December 31, |
| (In millions) | 2023 | | 2022 | | 2021 |
| Cash Flows from Operating Activities | | | | | |
| Net (loss)/income | $ | (202) | | | $ | 1,221 | | | $ | 2,187 | |
| | | | | |
| | | | | |
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| Equity in and distributions from (earnings)/losses of unconsolidated affiliates | (6) | | | 7 | | | 20 | |
| Depreciation and amortization | 1,127 | | | 634 | | | 785 | |
| Accretion of asset retirement obligations | 27 | | | 55 | | | 30 | |
| Provision for credit losses | 251 | | | 11 | | | 698 | |
| Amortization of nuclear fuel | 47 | | | 54 | | | 51 | |
| Amortization of financing costs and debt discounts | 52 | | | 23 | | | 39 | |
| (Gain)/Loss on debt extinguishment | (109) | | | — | | | 77 | |
| Amortization of in-the-money contracts and emissions allowances | 137 | | | 158 | | | 106 | |
| Amortization of unearned equity compensation | 101 | | | 28 | | | 21 | |
| Net gain on sale of assets and disposal of assets | (1,559) | | | (102) | | | (261) | |
| | | | | |
| Impairment losses | 128 | | | 206 | | | 544 | |
| Changes in derivative instruments | 2,455 | | | (3,221) | | | (3,626) | |
| Changes in deferred income taxes and liability for uncertain tax benefits | (92) | | | 382 | | | 604 | |
| | | | | |
| Changes in collateral deposits in support of risk management activities | (1,806) | | | 896 | | | 797 | |
| | | | | |
| Changes in nuclear decommissioning trust liability | — | | | 9 | | | 40 | |
| | | | | |
| Uplift securitization proceeds received/(receivable) from ERCOT | — | | | 689 | | | (689) | |
| | | | | |
| | | | | |
| Cash (used)/provided by changes in other working capital, net of acquisition and disposition effects: | | | | | |
| Accounts receivable - trade | 840 | | | (1,560) | | | (1,232) | |
| Inventory | 189 | | | (252) | | | (61) | |
| Prepayments and other current assets | (233) | | | 17 | | | 31 | |
| Accounts payable | (1,455) | | | 1,295 | | | 476 | |
| Accrued expenses and other current liabilities | 360 | | | (29) | | | (55) | |
| Other assets and liabilities | (473) | | | (161) | | | (89) | |
| Cash (used)/provided by operating activities | $ | (221) | | | $ | 360 | | | $ | 493 | |
| | | | | |
| | | | | |
| Cash Flows from Investing Activities | | | | | |
| Payments for acquisitions of businesses and assets, net of cash acquired | $ | (2,523) | | | $ | (62) | | | $ | (3,559) | |
| Capital expenditures | (598) | | | (367) | | | (269) | |
| | | | | |
| | | | | |
| Net purchases of emissions allowances | (24) | | | (6) | | | — | |
| Investments in nuclear decommissioning trust fund securities | (367) | | | (454) | | | (751) | |
| Proceeds from sales of nuclear decommissioning trust fund securities | 355 | | | 448 | | | 710 | |
| Proceeds from sale of assets, net of cash disposed | 2,007 | | | 109 | | | 830 | |
| Proceeds from insurance recoveries for property, plant and equipment, net | 240 | | | — | | | — | |
| | | | | |
| | | | | |
| | | | | |
| Cash used by investing activities | $ | (910) | | | $ | (332) | | | $ | (3,039) | |
| | | | | |
| | | | | |
| | | | | |
| | | | | | | | | | | | | | | | | |
| | For the Year Ended December 31, |
| (In millions) | 2023 | | 2022 | | 2021 |
| Cash Flows from Financing Activities | | | | | |
| Proceeds from issuance of preferred stock, net of fees | $ | 635 | | | $ | — | | | $ | — | |
| Net receipts from settlement of acquired derivatives that include financing elements | 342 | | | 1,995 | | | 938 | |
Payments for share repurchase activity(a) | (1,172) | | | (606) | | | (48) | |
| Payments of dividends to preferred and common stockholders | (381) | | | (332) | | | (319) | |
| Proceeds from issuance of long-term debt | 731 | | | — | | | 1,100 | |
| Payments for short and long-term debt | (523) | | | (5) | | | (1,861) | |
| | | | | |
| Payments for debt extinguishment costs | — | | | — | | | (65) | |
| Payments of debt issuance costs | (32) | | | (9) | | | (18) | |
| Proceeds from issuance of common stock | — | | | — | | | 1 | |
| Proceeds from credit facilities | 3,020 | | | — | | | 1,415 | |
| Repayments to credit facilities | (3,020) | | | — | | | (1,415) | |
| | | | | |
| | | | | |
| Cash (used)/provided by financing activities | $ | (400) | | | $ | 1,043 | | | $ | (272) | |
| | | | | |
| | | | | |
| Effect of exchange rate changes on cash and cash equivalents | 2 | | | (3) | | | (2) | |
| | | | | |
| Net (Decrease)/Increase in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash | (1,529) | | | 1,068 | | | (2,820) | |
| Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period | 2,178 | | | 1,110 | | | 3,930 | |
| Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period | $ | 649 | | | $ | 2,178 | | | $ | 1,110 | |
(a)Includes $(22) million, $(6) million and $(9) million of equivalent shares purchased in lieu of tax withholdings on equity compensation issuances for the years ended December 31, 2023, 2022 and 2021, respectively
For further discussion of supplemental cash flow information see Note 26, Cash Flow Information
See notes to Consolidated Financial Statements
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Preferred Stock | | Common
Stock | | Additional
Paid-In
Capital | | (Accumulated Deficit)/Retained Earnings | | Treasury
Stock | | Accumulated
Other
Comprehensive
Loss | | Total
Stock-holders'
Equity |
| | | | | | | | | | | | | |
| Balance at December 31, 2020 | $ | — | | | $ | 4 | | | $ | 8,517 | | | $ | (1,403) | | | $ | (5,232) | | | $ | (206) | | | $ | 1,680 | |
| Net income | | | | | | | 2,187 | | | | | | | 2,187 | |
| Other comprehensive income | | | | | | | | | | | 80 | | | 80 | |
| | | | | | | | | | | | | |
| Shares reissuance for ESPP | | | | | 1 | | | | | 3 | | | | | 4 | |
| Share repurchases | | | | | | | | | (44) | | | | | (44) | |
Equity-based awards activity, net(a) | | | | | 12 | | | | | | | | | 12 | |
| Issuance of common stock | | | | | 1 | | | | | | | | | 1 | |
Common stock dividends and dividend equivalents declared(b) | | | | | | | (320) | | | | | | | (320) | |
| Balance at December 31, 2021 | $ | — | | | $ | 4 | | | $ | 8,531 | | | $ | 464 | | | $ | (5,273) | | | $ | (126) | | | $ | 3,600 | |
| Net income | | | | | | | 1,221 | | | | | | | 1,221 | |
| Other comprehensive loss | | | | | | | | | | | (51) | | | (51) | |
| | | | | | | | | | | | | |
| Shares reissuance for ESPP | | | | | 2 | | | | | 4 | | | | | 6 | |
| Share repurchases | | | | | | | | | (595) | | | | | (595) | |
Equity-based awards activity, net(a) | | | | | 24 | | | | | | | | | 24 | |
| | | | | | | | | | | | | |
Common stock dividends and dividend equivalents declared(b) | | | | | | | (334) | | | | | | | (334) | |
Adoption of ASU 2020-06 | | | | | $ | (100) | | | 57 | | | | | | | (43) | |
| Balance at December 31, 2022 | $ | — | | | $ | 4 | | | $ | 8,457 | | | $ | 1,408 | | | $ | (5,864) | | | $ | (177) | | | $ | 3,828 | |
| Net loss | | | | | | | (202) | | | | | | | (202) | |
| Issuance of Series A Preferred Stock | 650 | | | | | (15) | | | | | | | | | 635 | |
| Other comprehensive income | | | | | | | | | | | 39 | | | 39 | |
| Shares reissuance for ESPP | | | | | 2 | | | | | 6 | | | | | 8 | |
Share repurchases(c) | | | | | (117) | | | | | (1,043) | | | | | (1,160) | |
| Retirement of treasury stock | | | (1) | | | (5,008) | | | | | 5,009 | | | | | — | |
Equity-based awards activity, net(a) | | | | | 97 | | | | | | | | | 97 | |
Common stock dividends and dividend equivalents declared(b) | | | | | | | (352) | | | | | | | (352) | |
Series A Preferred Stock dividends(d) | | | | | | | (34) | | | | | | | (34) | |
| Sale of the 44% equity interest in STP | | | | | | | | | | | 47 | | | 47 | |
| Balance at December 31, 2023 | $ | 650 | | | $ | 3 | | | $ | 3,416 | | | $ | 820 | | | $ | (1,892) | | | $ | (91) | | | $ | 2,906 | |
(a)Includes $(22) million, $(6) million and $(9) million of equivalent shares purchased in lieu of tax withholding on equity compensation issuances for the years ended December 31, 2023, 2022 and 2021, respectively
(b)Dividends per common share were $1.51, $1.40 and $1.30 for each of the years ended December 31, 2023, 2022 and 2021, respectively
(c)Includes excise tax accrued of $10 million as of December 31, 2023
(d)Dividend per Series A Preferred Stock was $52.96
See notes to Consolidated Financial Statements
NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 — Nature of Business
General
NRG Energy, Inc., or NRG or the Company, sits at the intersection of energy and home services. NRG is a leading energy and home services company fueled by market-leading brands, proprietary technologies, and complementary sales channels. Across the United States and Canada, NRG delivers innovative, sustainable solutions, predominately under the brand names such as NRG, Reliant, Direct Energy, Green Mountain Energy and Vivint, while also advocating for competitive energy markets and customer choice. The Company has a customer base that includes approximately 8 million residential consumers in addition to commercial, industrial, and wholesale customers, supported by approximately 13 GW of generation.
The Company's business is segmented as follows:
•Texas, which includes all activity related to customer, plant and market operations in Texas, other than Cottonwood;
•East, which includes all activity related to customer, plant and market operations in the East;
•West/Services/Other, which includes the following assets and activities: (i) all activity related to customer, plant and market operations in the West and Canada, (ii) the Services businesses (iii) activity related to the Cottonwood facility and other investments;
•Vivint Smart Home; and
•Corporate activities.
Note 2 — Summary of Significant Accounting Policies
Basis of Presentation and Principles of Consolidation
The Company's consolidated financial statements have been prepared in accordance with U.S. GAAP. The ASC, established by the FASB, is the source of authoritative U.S. GAAP to be applied by nongovernmental entities. In addition, the rules and interpretative releases of the SEC under authority of federal securities laws are also sources of authoritative U.S. GAAP for SEC registrants.
The consolidated financial statements include NRG's accounts and operations and those of its subsidiaries in which the Company has a controlling interest. All significant intercompany transactions and balances have been eliminated in consolidation. The usual condition for a controlling financial interest is ownership of a majority of the voting interests of an entity. However, a controlling financial interest may also exist through arrangements that do not involve controlling voting interests. As such, NRG applies the guidance of ASC 810, Consolidations, or ASC 810, to determine when an entity that is insufficiently capitalized or not controlled through its voting interests, referred to as a VIE, should be consolidated.
The Company identified an error in the previously issued consolidated financial statements for the year ended December 31, 2021 related to the presentation of cash flows associated with certain borrowings and repayments related to the Revolving Credit Facility. The statement of cash flows for the year ended December 31, 2021 has been adjusted to present on a gross basis the borrowings from the Revolving Credit Facility of $1.4 billion and the related repayments of $1.4 billion. The change had no impact to the total cash used by financing activities for the year ended December 31, 2021. We evaluated the materiality of this error both qualitatively and quantitatively and have concluded it is immaterial to the impacted period.
Winter Storm Uri Uplift Securitization Proceeds
The Texas Legislature passed HB 4492 in May 2021 for ERCOT to mitigate exceptionally high price adders and ancillary service costs incurred by LSEs during Winter Storm Uri. HB 4492 authorized ERCOT to obtain $2.1 billion of financing to distribute to LSEs that were charged and paid to ERCOT those highly priced ancillary service and ORDPA during Winter Storm Uri.
In December 2021, ERCOT filed with the PUCT a calculation of each LSE’s share of proceeds based on the settlement methodology. The Company accounted for the proceeds by analogy to the contribution model within ASC 958-605, Not-for-Profit Entities- Revenue Recognition and the grant model within IAS 20, Accounting for Government Grants and Disclosure of Government Assistance, as a reduction to expenses in the consolidated statements of operations in the 2021 annual period for which the proceeds were intended to compensate. The Company received proceeds of $689 million from ERCOT in June 2022.
Credit Losses
In accordance with ASU No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, or ASU No. 2016-13, 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 on the consolidated balance sheet. The Company accrues an allowance for current expected credit losses based on (i) estimates of uncollectible revenues by analyzing accounts receivable aging and current and reasonable forecasts of expected economic factors including, but not limited to, unemployment rates and weather-related events, (ii) historical collections and delinquencies, and (iii) counterparty credit ratings for commercial and industrial customers. The Company writes off customer contract receivable balances against the allowance for credit losses when it is determined a receivable is uncollectible.
The following table represents the activity in the allowance for credit losses for the years ended December 31, 2023, 2022, and 2021:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| (In millions) | 2023 | | 2022 | | 2021 |
| Beginning balance | $ | 133 | | | $ | 683 | | | $ | 67 | |
| Acquired balance from Vivint Smart Home | 22 | | | — | | | — | |
| Acquired balance from Direct Energy | — | | | — | | | 112 | |
Provision for credit losses(a) | 251 | | | 11 | | | 698 | |
| Write-offs | (313) | | | (593) | | | (224) | |
| Recoveries collected | 39 | | | 32 | | | 30 | |
| Other | 13 | | | — | | | — | |
Ending balance(a) | $ | 145 | | | $ | 133 | | | $ | 683 | |
(a)Includes bilateral finance hedging risk of $(70) million and $403 million accounted for under ASC 815 for the years endedDecember 31, 2022 and December 31, 2021, respectively
During the year ended December 31, 2022, the provision for credit losses included the Company's loss mitigation efforts recognized as income of $126 million related to Winter Storm Uri. During the year ended December 31, 2021, the provision for credit losses included $596 million of expense due to the impacts of Winter Storm Uri. The increase in write-offs for the periods ended December 31, 2022 and 2021 were primarily due to the resolution of credit losses that occurred during Winter Storm Uri.
Cash and Cash Equivalents
Cash and cash equivalents include highly liquid investments with an original maturity of three months or less at the time of purchase.
Funds Deposited by Counterparties
Funds deposited by counterparties consist of cash held by the Company as a result of collateral posting obligations from its counterparties related to NRG's hedging program. The 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, not all funds are contractually restricted. Based on the Company's intention, these funds are not available for the payment of general corporate obligations; however, they are available for liquidity management. Depending on market fluctuations and the settlement of the underlying contracts, the Company will refund this collateral to the hedge counterparties pursuant to the terms and conditions of the underlying trades. Since collateral requirements fluctuate daily and the Company cannot predict if any collateral will be held for more than twelve months, the funds deposited by counterparties are classified as a current asset on the Company's balance sheet, with an offsetting liability for this cash collateral received within current liabilities.
Restricted Cash
The following table provides a reconciliation of cash and cash equivalents, restricted cash and funds deposited by counterparties reported within the consolidated balance sheets that sum to the total of the same such amounts shown in the statements of cash flows.
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| (In millions) | 2023 | | 2022 | | 2021 |
| Cash and cash equivalents | $ | 541 | | | $ | 430 | | | $ | 250 | |
| Funds deposited by counterparties | 84 | | | 1,708 | | | 845 | |
| Restricted cash | 24 | | | 40 | | | 15 | |
| Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statements of cash flows | $ | 649 | | | $ | 2,178 | | | $ | 1,110 | |
Restricted cash consists primarily of funds held to satisfy the requirements of certain financing agreements and funds held within the Company's projects that are restricted in their use.
Inventory
Inventory is valued at the lower of weighted average cost or market, and consists principally of natural gas, fuel oil, coal, spare parts and finished goods. The Company removes natural gas inventory as goods are delivered to customers and as they are used in the production of electricity or steam. The Company removes fuel oil and coal inventories as they are used in the production of electricity. The Company removes spare parts inventories when they are used for repairs, maintenance or capital projects. The Company expects to recover the natural gas, fuel oil, coal and spare parts costs in the ordinary course of business. Inventory is valued at the lower of cost or net realizable value with cost being determined on a first in first out basis for finished goods and weighted average cost method for all other inventories. The Company removes finished goods inventories as they are sold to customers. Inventories sold to customers as part of a smart home system are generally capitalized as contract costs. Sales of inventory are classified as an operating activity in the consolidated statements of cash flows.
Property, Plant and Equipment
Property, plant and equipment are stated at cost or, in the case of business acquisitions, fair value; however, impairment adjustments are recorded whenever events or changes in circumstances indicate that their carrying values may not be recoverable. Significant additions or improvements extending asset lives are capitalized as incurred, while repairs and maintenance that do not improve or extend the life of the respective asset are charged to expense as incurred. Depreciation, other than nuclear fuel, is computed using the straight-line method, while nuclear fuel was amortized based on units of production over the estimated useful lives. Certain assets and their related accumulated depreciation amounts are adjusted for asset retirements and disposals with the resulting gain or loss included in cost of operations in the consolidated statements of operations. For further discussion, see Note 9, Property, Plant and Equipment.
Business Interruption Insurance
The Company carries insurance policies to cover insurable risks including, but not limited to, business interruption. As a result of damage at the Limestone 1 and W.A. Parish 8 units, the Company recorded business interruption insurance settlements of $7 million and $81 million during the year ended December 31, 2023 and December 31, 2022, respectively. Business interruption insurance is recorded to cost of operations in the consolidated statements of operations and cash provided by operating activities in the consolidated statement of cash flows.
Asset Impairments
Long-lived assets that are held and used are reviewed for impairment whenever events or changes in circumstances indicate carrying values may not be recoverable. Such reviews are performed in accordance with ASC 360. An impairment loss is indicated if the total future estimated undiscounted cash flows expected from an asset are less than its carrying value. An impairment charge is measured by the difference between an asset's carrying amount and fair value with the difference recorded in operating costs and expenses in the consolidated statements of operations. Fair values are determined by a variety of valuation methods, including third-party appraisals, sales prices of similar assets and present value techniques.
Investments accounted for by the equity method are reviewed for impairment in accordance with ASC 323, Investments-Equity Method and Joint Ventures, or ASC 323, which requires that a loss in value of an investment that is an other-than-temporary decline should be recognized. The Company identifies and measures losses in the value of equity method investments based upon a comparison of fair value to carrying value. For further discussion of these matters, refer to Note 11, Asset Impairments.
Debt Issuance Costs
Debt issuance costs are capitalized and amortized as interest expense on a basis that approximates the effective interest method over the term of the related debt. Debt issuance costs are presented as a direct deduction from the carrying amount of the related debt, or as an asset if the issuance costs relate to revolving debt agreements or certain other financing arrangements.
Intangible Assets
Intangible assets represent contractual rights held by the Company. The Company recognizes specifically identifiable intangible assets including emissions allowances, customer and supply contracts, customer relationships, marketing partnerships, technologies, trade names and fuel contracts when specific rights and contracts are acquired. These intangible assets are amortized based on expected volumes, expected delivery, expected discounted future net cash flows, straight line or units of production basis. As of December 31, 2023 and 2022, the Company had accumulated amortization related to its intangible assets of $3.0 billion and $2.1 billion, respectively.
Emission allowances held-for-sale, which are included in other non-current assets on the Company's consolidated balance sheet, are not amortized; they are carried at the lower of cost or fair value and reviewed for impairment in accordance with ASC 360.
For further discussion, see Note 12, Goodwill and Other Intangibles.
Goodwill
In accordance with ASC 350, Intangibles-Goodwill and Other, or ASC 350, the Company recognizes goodwill for the excess cost of an acquired entity over the net value assigned to assets acquired and liabilities assumed. NRG performs goodwill impairment tests annually, during the fourth quarter, and when events or changes in circumstances indicate that the carrying value may not be recoverable.
The Company may first assesses qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. The more-likely-than-not threshold is defined as having a likelihood of more than 50 percent. If it is not more-likely-than-not that the fair value of a reporting unit is less than its carrying amount, there is no goodwill impairment.
In the absence of sufficient qualitative factors indicating that it is more-likely-than-not that no impairment occurred, the Company performs a quantitative assessment by determining the fair value of the reporting unit and comparing the fair value to its book value. If the fair value of the reporting unit exceeds its book value, goodwill of the reporting unit is not considered impaired. If the book value exceeds fair value, the Company recognizes an impairment loss equal to the difference between book value and fair value.
For further discussion of goodwill impairment losses recognized refer to Note 11, Asset Impairments.
Capitalized Contract Costs
Capitalized contract costs represent the costs directly related and incremental to the origination of new contracts, modification of existing contracts or to the fulfillment of the related subscriber contracts. These costs include installed products, commissions, other compensation and the cost of installation of new or upgraded customer contracts. The Company calculates amortization by accumulating all deferred contract costs into separate portfolios based on the initial month of service and amortizes those deferred contract costs on a straight-line basis over the expected period of benefit, consistent with the pattern in which the Company provides services to its customers. The expected period of benefit for customers is approximately five years. The Company updates its estimate of the expected period of benefit periodically and whenever events or circumstances indicate that the expected period of benefit could change significantly. Such changes, if any, are accounted for prospectively as a change in estimate. Amortization of capitalized contract costs related to fulfillment are included in cost of operations and amortization of capitalized contract costs related to customer acquisition are included in selling, general and administrative costs in the consolidated statements of operations. Contract costs not directly related and incremental to the origination of new contracts, modification of existing contracts or to the fulfillment of the related subscriber contracts are expensed as incurred.
Income Taxes
The Company accounts for income taxes using the liability method in accordance with ASC 740, Income Taxes, or ASC 740, which requires that the Company use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences.
The Company has two categories of income tax expense or benefit — current and deferred, as follows:
•Current income tax expense or benefit consists solely of current taxes payable less applicable tax credits, and
•Deferred income tax expense or benefit is the change in the net deferred income tax asset or liability, excluding amounts charged or credited to accumulated other comprehensive income
The Company reports some of its revenues and expenses differently for financial statement purposes than for income tax return purposes, resulting in temporary and permanent differences between the Company's financial statements and income tax returns. The tax effects of such temporary differences are recorded as either deferred income tax assets or deferred income tax liabilities in the Company's consolidated balance sheets. The Company measures its deferred income tax assets and deferred income tax liabilities using income tax rates that are expected to be in effect when the deferred tax is realized.
The Company accounts for uncertain tax positions in accordance with ASC 740, which applies to all tax positions related to income taxes. Under ASC 740, tax benefits are recognized when it is more-likely-than-not that a tax position will be sustained upon examination by the authorities. The benefit recognized from a position is the amount of benefit that has surpassed the more-likely-than-not threshold, as it is more than 50% likely to be realized upon settlement. The Company recognizes interest and penalties accrued related to uncertain tax benefits as a component of income tax expense.
In accordance with ASC 740 and as discussed further in Note 20, Income Taxes, changes to existing net deferred tax assets or valuation allowances or changes to uncertain tax benefits, are recorded to income tax (benefit)/expense.
Contract and Emission Credit Amortization
Assets and liabilities recognized through acquisitions related to the purchase and sale of energy and energy-related products in future periods for which the fair value has been determined to be significantly less or more than market are amortized to revenues or cost of operations over the term of each underlying contract based on actual generation and/or contracted volumes.
Emission credits represent the right to emit a specified amount of certain pollutants, including sulfur dioxide, nitrogen oxides and carbon dioxide, over a compliance period. Emission credits held for use are amortized to cost of operations based on the weighted average cost of the allowances held.
Gross Receipts and Sales Taxes
In connection with its retail sales, the Company records gross receipts taxes on a gross basis in revenues and cost of operations in its consolidated statements of operations. During the years ended December 31, 2023, 2022, and 2021, the Company's revenues and cost of operations included gross receipts taxes of $212 million, $218 million, and $184 million, respectively. Additionally, the Company records sales taxes collected from its taxable retail customers and remitted to the various governmental entities on a net basis; thus, there is no impact on the Company's consolidated statement of operations.
Cost of Operations
Cost of operations includes cost of fuel, purchased energy and other costs of sales, mark-to-market for economic hedging activities, contract and emission credit amortization, operations and maintenance, and other cost of operations.
Cost of Fuel, Purchased Energy and Other Cost of Sales
Cost of fuel is primarily the costs associated with procurement, transportation and storage of natural gas, nuclear fuel, oil and coal to operate the generation portfolio, which is expensed as the fuel is consumed. Purchased energy primarily relates to purchases to supply the Company's customer base, which includes spot market purchases, as well as contracts of various quantities and durations, including Renewable PPAs with third-party developers, which are primarily accounted for as NPNS (see further discussion in Derivative Instruments below). Other cost of sales primarily consists of TDSP expenses.
The cost of fuel is based on actual and estimated fuel usage for the applicable reporting period. The cost to deliver energy and related services to customers is based on actual and estimated supply volumes for the applicable reporting period. A portion of the cost of energy, $240 million, $202 million, and $189 million as of December 31, 2023, 2022, and 2021, respectively, was accrued and consisted of estimated transmission and distribution charges not yet billed by the transmission and distribution utilities.
In estimating supply volumes, the Company considers the effects of historical customer volumes, weather factors and usage by customer class. Transmission and distribution delivery fees are estimated using the same method used for electricity sales and services to retail customers. In addition, ISO fees are estimated based on historical trends, estimated supply volumes and initial ISO settlements. Volume estimates are then multiplied by the supply rate and recorded as cost of operations in the applicable reporting period.
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 services (smart home and security). The subscriber has the ability to pay for Vivint Smart Home products in the following three ways: (i) qualified subscribers may finance the purchase through third-party financing providers ("Consumer Financing Program" or “CFP”), (ii) Vivint Smart Home generally offers a limited number of subscribers not eligible for the CFP, but who qualify under Vivint Smart Home underwriting criteria, the option to enter into a retail installment contract directly with Vivint Smart Home or (iii) subscribers may conduct purchases by check, automatic clearing house payments, credit or debit card or by obtaining short term financing (generally no more than six-month installment terms) through Vivint Smart Home.
Although subscribers pay separately for products and services under Flex Pay, the Company has determined that the sale of products and services are one single performance obligation resulting in deferred revenue for the gross amount of products sold. For products financed through the CFP, gross deferred revenues are reduced by (i) any fees the third-party financing provider (“Financing Provider”) is contractually entitled to receive at the time of loan origination, and (ii) the present value of expected future payments due to the Financing Providers. Loans are issued on either an installment or revolving basis with repayment terms ranging from 6 to 60 months.
For certain Financing Provider loans:
•Vivint Smart Home pays a monthly fee based on either the average daily outstanding balance of the installment loans, or the number of outstanding loans.
•Vivint Smart Home incurs fees at the time of the loan origination and receives proceeds that are net of these fees.
•Vivint Smart Home also shares liability for credit losses, with Vivint Smart Home being responsible for between 2.6% and 100% of lost principal balances.
Due to the nature of these provisions, the Company records a derivative liability ("CFP Derivative") 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 6, Accounting for Derivative Instruments and Hedging Activities.
Derivative Instruments
The Company accounts for derivative instruments under ASC 815, which requires the Company to recognizerecord all derivative instrumentsderivatives on the balance sheet as either assets or liabilities and to measure them at fair value each reporting periodand changes in fair value in earnings, unless they qualify for athe NPNS exception. The Company's primary derivative instruments are power and natural gas purchase or sales contracts, fuels purchase contracts, the CFP and other energy related commodities used to mitigate variability in earnings due to fluctuation in market prices. In order to mitigate interest rate risk associated with the issuance of the Company's variable rate debt, NRG enters into interest rate swap agreements. In addition, in order to mitigate foreign exchange risk associated with the purchase of USD denominated natural gas for the Company's Canadian business, NRG enters into foreign exchange contract agreements.
As of December 31, 2023 and 2022 the Company may elect to designate certain derivativesdid not have derivative instruments that were designated as cash flow hedges,or fair value hedges.
Revenues and expenses on contracts that qualify for the NPNS exception are recognized when the underlying physical transaction is delivered. While these contracts are considered derivative instruments under ASC 815, they are not recorded at fair value, but on an accrual basis of accounting. If it is determined that a transaction designated as NPNS no longer meets the scope exception, the fair value of the related contract is recorded on the balance sheet and immediately recognized through earnings.
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 instruments are recognized in earnings.
Mark-to-Market for Economic Hedging Activities
NRG enters into derivative instruments to manage price and delivery risk, optimize physical and contractual assets in the portfolio and manage working capital requirements. The mark-to-market for economic hedging activities are recognized to revenues or cost of operations during the reporting period.
Operations and Maintenance and Other Cost of Operations
Operations and maintenance costs include major and other routine preventative (planned outage) and corrective (forced outage) maintenance activities to ensure the safe and reliable operation of the Company's generation portfolio in compliance
with all local, state and federal requirements. Operations and maintenance costs are also costs associated with retaining and maintaining the Company's customer base, such as call center support, portfolio maintenance and data analytics. Other cost of operations primarily includes gross receipts taxes, insurance, property taxes and asset retirement obligation expense.
Foreign Currency Translation and Transaction Gains and Losses
The local currencies are generally the functional currency of NRG's foreign operations. Foreign currency denominated assets and liabilities are translated at end-of-period rates of exchange. Revenues, expenses, and cash flows are translated at the weighted-average rates of exchange for the period. The resulting currency translation adjustments are not included in the Company's consolidated statements of operations for the period, but are accumulated and reported as a separate component of stockholders' equity until sale or complete or substantially complete liquidation of the net investment in the foreign entity takes place. Foreign currency transaction gains or losses are reported within other income, net in the Company's consolidated statements of operations. For the years ended December 31, 2023, 2022 and 2021, amounts recognized as foreign currency transaction gains/(losses) were immaterial. The Company's cumulative translation adjustment balances as of December 31, 2023, 2022, and 2021 were $(43) million, $(55) million, and $(8) million, respectively.
Concentrations of Credit Risk
Financial instruments that potentially subject the Company to concentrations of credit risk consist primarily of trust funds, accounts receivable, notes receivable, derivatives and investments in debt securities. Trust funds are held in accounts managed by experienced investment advisors. Certain accounts receivable, notes receivable, and derivative instruments are concentrated within entities engaged in the energy industry. These industry concentrations may impact the Company's overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. Receivables and other contractual arrangements are subject to collateral requirements under the terms of enabling agreements. However, the Company believes that the credit risk posed by industry concentration is offset by the diversification and creditworthiness of its customer base. See Note 5, Fair Value of Financial Instruments, for a further discussion of derivative concentrations.
Asset Retirement Obligations
The Company accounts for AROs in accordance with ASC 410-20, Asset Retirement Obligations, or ASC 410-20. Retirement obligations associated with long-lived assets included within the scope of ASC 410-20 are those for which a legal obligation exists under enacted laws, statutes, and written or oral contracts, including obligations arising under the doctrine of promissory estoppel, and for which the timing and/or method of settlement may be conditional on a future event. ASC 410-20 requires an entity to recognize the fair value of a liability for an ARO in the period in which it is incurred and a reasonable estimate of fair value can be made.
Upon initial recognition of a liability for an ARO, the Company capitalizes the asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount. Over time, the liability is accreted to its future value, while the capitalized cost is depreciated over the useful life of the related asset. See Note 14, Asset Retirement Obligations, for a further discussion of AROs.
Pensions and Other Postretirement Benefits
The Company offers pension benefits through a defined benefit pension plan. In addition, the Company provides postretirement health and welfare benefits for certain groups of employees. The Company accounts for pension and other postretirement benefits in accordance with ASC 715, Compensation — Retirement Benefits, or ASC 715. The Company recognizes the funded status of the Company's defined benefit plans in the statement of financial position and records an offset for gains and losses as well as all prior service costs that have not been included as part of the Company's net periodic benefit cost to other comprehensive income. The determination of the Company's obligation and expenses for pension benefits is dependent on the selection of certain assumptions. These assumptions determined by management include the discount rate, the expected rate of return on plan assets and the rate of future compensation increases. The Company's actuarial consultants assist in determining assumptions for such items as retirement age. The assumptions used may differ materially from actual results, which may result in a significant impact to the amount of pension obligation or expense recorded by the Company.
The Company measures the fair value of its pension assets in accordance with ASC 820, Fair Value Measurements and Disclosures, or ASC 820. For further discussion, see Note 15, Benefit Plans and Other Postretirement Benefits.
Stock-Based Compensation
The Company accounts for its stock-based compensation in accordance with ASC 718, Compensation — Stock Compensation, or ASC 718. The fair value of the Company's performance stock units is estimated on the date of grant using a Monte Carlo valuation model. NRG uses the Company's common stock price on the date of grant as the fair value of the Company's deferred stock units. Forfeiture rates are estimated based on an analysis of the Company's historical forfeitures, employment turnover, and expected future behavior. The Company recognizes compensation expense for both graded and cliff
vesting awards on a straight-line basis over the requisite service period for the entire award. For further discussion, see Note 21, Stock-Based Compensation.
Investments Accounted for by the Equity Method
The Company has investments in various domestic energy projects, as well as one Australian project. The equity method of accounting is applied to such investments in affiliates, which include joint ventures and partnerships, because the ownership structure prevents the Company from exercising a controlling influence over the operating and financial policies of the projects. Under this method, equity in pre-tax income or losses of domestic partnerships and, generally, in the net income or losses of its Australian project, are reflected as equity in earnings of unconsolidated affiliates. Distributions from equity method investments that represent earnings on the Company's investment are included within cash flows from operating activities and distributions from equity method investments that represent a return of the Company's investment are included within cash flows from investing activities. For further discussion, see Note 17, Investments Accounted for by the Equity Method and Variable Interest Entities.
Sale-Leaseback Arrangements
NRG is party to sale-leaseback arrangements that provide for the sale of certain assets to a third-party and simultaneously leases back the same asset to the Company. If the seller-lessee transfers control of the underlying assets to the buyer-lessor, the arrangement is accounted for under ASC 842-40, Sale-Leaseback Transactions. These arrangements are classified as operating leases on the Company's consolidated balance sheets.
Marketing and Advertising Costs
The Company expenses its marketing and advertising costs as incurred and includes them within selling, general and administrative costs. The costs of tangible assets used in advertising campaigns are recorded as fixed assets or deferred advertising costs and amortized as advertising costs over the shorter of the useful life of the asset or the advertising campaign. The Company has several long-term sponsorship arrangements. Payments related to these arrangements are deferred and expensed over the term of the arrangement. Advertising expenses for the years ended December 31, 2023, 2022, and 2021 were $185 million, $82 million, and $109 million, respectively.
Business Combinations
The Company accounts for its business combinations in accordance with ASC 805, Business Combinations, or ASC 805, which requires an acquirer to recognize and measure in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at fair value at the acquisition date. The Company also recognizes and measures the goodwill acquired or a gain from a bargain purchase in the business combination. In addition, transaction costs are expensed as incurred.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States 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.
In recording transactions and balances resulting from business operations, the Company uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, tax provisions, uncollectible accounts, actuarially determined benefit costs, the valuation of energy commodity contracts, environmental liabilities, legal costs incurred in connection with recorded loss contingencies, and assets acquired and liabilities assumed in business combinations, among others. In addition, estimates are used to test long-lived assets and goodwill for impairment and to determine the fair value of impaired assets. As better information becomes available or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.
Reclassifications
Certain prior period amounts have been reclassified for comparative purposes. The reclassifications did not affect results from operations, net assets or cash flows.
Recent Accounting Developments - Guidance Adopted in 2023
ASU 2021-08 — In October 2021, the FASB issued ASU No. 2021-08, Business Combinations (Topic 805): Accounting for Contract Assets and Contract Liabilities from Contracts with Customers, or ASU 2021-08, which requires that an entity recognize and measure contract assets and contract liabilities acquired in a business combination as if it had originated the contracts in accordance with ASC 606, Revenue from Contracts with Customers. As a result, an acquirer should recognize and measuring 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, such as refund liabilities and upfront payments to customers. Assets and liabilities under related Topics, such as deferred costs under Subtopic 340-40, Other Assets and Deferred Costs — Contracts with Customers, are not within the scope of amendments per ASU 2021-08. The Company adopted ASU 2021-08 prospectively effective January 1, 2023 and applied the amended requirements to the acquisition of Vivint Smart Home.
Recent Accounting Developments - Guidance Not Yet Adopted
ASU 2023-07 – In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280) – Improvements to Reportable Segment Disclosures, or ASU 2023-07. The guidance in ASU 2023-07 enhances reportable segment disclosure requirements by requiring disclosure of significant segment expenses that are regularly provided to the chief operating decision maker and included within each reported measure of segment profit and loss, an amount and description of its composition for other segment items and interim disclosures of a reportable segment’s profit or loss and assets. The amendments of ASU 2023-07 are effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted and should be applied retrospectively for all prior periods presented in the financial statements. The Company is currently evaluating the impact of adopting ASU 2023-07 on its disclosures.
ASU 2023-09 – In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740) – Improvements to Income Tax Disclosures, or ASU 2023-09. The guidance in ASU 2023-09 enhances income tax disclosures by requiring disclosure of specific categories in the effective tax rate reconciliation and additional information for reconciling items that meet a quantitative threshold. Further the amendments of ASU 2023-09 require certain conditionsdisclosures on income tax expense and income taxes paid. ASU 2023-09 is effective for annual periods beginning after December 15, 2024, with early adoption permitted. The amendments of ASU 2023-09 may be applied on a prospective or retrospective basis. The Company is currently evaluating the impact of adopting ASU 2023-09 on its disclosures.
Note 3— Revenue Recognition
The Company's policies with respect to its various revenue streams are met,detailed below. The Company generally applies the invoicing practical expedient to recognize revenue for the revenue streams detailed below, except in circumstances where the invoiced amount does not represent the value transferred to the customer.
Retail Revenue
Gross revenues for energy sales and deferservices to retail customers are recognized as the Company transfers the promised goods and services to the customer. Payment terms are generally 15 to 60 days. For the majority of its electricity and natural gas contracts, the Company’s performance obligation with the customer is satisfied over time and performance obligations for its electricity and natural gas products are recognized as the customer takes possession of the product. The Company also allocates the contract consideration to distinct performance obligations in a contract for which the timing of the revenue recognized is different. Additionally, customer discounts and incentives reduce the contract consideration and are recognized over the term of the contract.
Energy sales and services that have been delivered but not billed by period end are estimated. Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter reading provided by the independent system operators, utilities, or electric distribution companies. Volume estimates are based on daily forecasted volumes and estimated customer usage by class. Unbilled revenues are calculated by multiplying these volume estimates by the applicable rate by customer class. Estimated amounts are adjusted when actual usage is known and billed.
As contracts for retail electricity and natural gas can be for multi-year periods, the Company has performance obligations under these contracts that have not yet been satisfied. These performance obligations have transaction prices that are both fixed and variable, and that vary based on the contract duration, customer type, inception date and other contract-specific factors. For the fixed price contracts, the amount of any unsatisfied performance obligations will vary based on customer usage, which will depend on factors such as weather and customer activity and therefore it is not practicable to estimate such amounts.
Vivint Smart Home Retail Revenue
Vivint Smart Home offers its subscribers combinations of smart home products and services, which together create an integrated smart home system that allows the Company's subscribers to monitor, control and protect their homes. As the products and services included in the subscriber's contract are integrated and highly interdependent, and because the products (including installation) and services must work together to deliver the monitoring, controlling and protection of their home, the Company has concluded that the products and services contracted for by the subscriber are generally not distinct within the context of the contract and, therefore, constitute a single, combined performance obligation. Revenues for this single, combined performance obligation are recognized on a straight-line basis over the subscriber's contract term, which is the period in which the parties to the contract have enforceable rights and obligations. The Company has determined that certain contracts that do not require a long-term commitment for monitoring services by the subscriber contain a material right to renew the contract,
because the subscriber does not have to purchase the products upon renewal. Proceeds allocated to the material right are recognized over the expected period of benefit. The majority of Vivint Smart Home's subscription contracts are five years and are generally non-cancelable. These contracts generally convert into month-to-month agreements at the end of the initial term, while some subscribers are month-to-month from inception. Payment for Vivint Smart Home services is generally due in advance on a monthly basis, with payment terms up to 30 days. Product sales and other one-time fees are invoiced to subscribers at time of sale. Revenues for any products or services that are considered separate performance obligations are recognized upon delivery. Payments received or billed in advance are reported as deferred revenues.
Energy Revenue
Both physical and financial transactions consist of revenues billed to a third-party at either market or negotiated contract terms to optimize the financial performance of the Company's generating facilities. Payment terms vary from 5 to 55 days. Electric energy revenue is recognized upon transmission to the customer over time, using the output method for measuring progress of satisfaction of performance obligations. Physical transactions, or the sale of generated electricity to meet supply and demand, are recorded on a gross basis in the Company's consolidated statements of operations. The Company applies the invoicing practical expedient in recognizing energy revenue. Under the practical expedient, revenue is recognized based on the invoiced amount which is equal to the value to the customer of NRG’s performance obligation completed to date. Financial transactions used to hedge the sale of electricity are recorded net within revenues in the consolidated statements of operations in accordance with ASC 815.
Ancillary revenues, included in Other revenue, are recognized over time as the obligation is fulfilled, using the output method for measuring progress of satisfaction of performance obligations.
CapacityRevenue
The Company's largest sources of capacity revenues are capacity auctions in PJM and NYISO. Capacity revenues also include revenues billed to a third-party at either market or negotiated contract terms for making installed generation and demand response capacity available in order to satisfy system integrity and reliability requirements. Payment terms vary from 15 to 55 days. Capacity revenues are recognized over time, using the output method for measuring progress of satisfaction of performance obligations. The Company applies the invoicing practical expedient in recognizing capacity revenue. Under the practical expedient, revenue is recognized based on the invoiced amount which is equal to the value to the customer of NRG’s performance obligation completed to date.
Performance Obligations
As of December 31, 2023, estimated future fixed fee performance obligations are $1.4 billion, $1.0 billion, $756 million, $468 million and $176 million for fiscal years 2024, 2025, 2026, 2027 and 2028, respectively. These performance obligations include Vivint Smart Home products and services as well as cleared auction MWs in the PJM, NYISO and MISO capacity auctions. The cleared auction MWs are subject to penalties for non-performance.
Disaggregated Revenue
The following tables represent the Company’s disaggregation of revenue from contracts with customers for the years ended December 31, 2023, 2022, and 2021:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2023 |
| (In millions) | Texas | | East | | West/Services/Other | | Vivint Smart Home(a) | | Corporate/Eliminations | | Total |
| Retail revenue | | | | | | | | | | | |
Home(b) | $ | 6,538 | | | $ | 2,195 | | | $ | 1,890 | | | $ | 1,549 | | | $ | (1) | | | $ | 12,171 | |
| Business | 3,492 | | | 9,751 | | | 2,053 | | | — | | | — | | | 15,296 | |
Total retail revenue(b) | 10,030 | | | 11,946 | | | 3,943 | | | 1,549 | | | (1) | | | 27,467 | |
Energy revenue(c) | 77 | | | 291 | | | 185 | | | — | | | — | | | 553 | |
Capacity revenue(c) | — | | | 197 | | | 2 | | | — | | | (2) | | | 197 | |
Mark-to-market for economic hedging activities(d) | — | | | 57 | | | 103 | | | — | | | (16) | | | 144 | |
| Contract amortization | — | | | (32) | | | — | | | — | | | — | | | (32) | |
Other revenue(c) | 369 | | | 88 | | | 48 | | | — | | | (11) | | | 494 | |
| Total revenue | 10,476 | | | 12,547 | | | 4,281 | | | 1,549 | | | (30) | | | 28,823 | |
| Less: Revenues accounted for under topics other than ASC 606 and ASC 815 | — | | | 17 | | | 35 | | | — | | | — | | | 52 | |
| Less: Realized and unrealized ASC 815 revenue | 29 | | | 364 | | | 138 | | | — | | | (16) | | | 515 | |
| Total revenue from contracts with customers | $ | 10,447 | | | $ | 12,166 | | | $ | 4,108 | | | $ | 1,549 | | | $ | (14) | | | $ | 28,256 | |
| (a) Includes results of operations following the acquisition date of March 10, 2023 |
| (b) Home includes Services and Vivint Smart Home |
| (c) The following amounts of retail, energy, capacity and other revenue relate to derivative instruments and are accounted for under ASC 815: |
| (In millions) | Texas | | East | | West/Services/Other | | Vivint Smart Home | | Corporate/Eliminations | | Total |
| Retail revenue | $ | — | | | $ | 74 | | | $ | — | | | $ | — | | | $ | — | | | $ | 74 | |
| Energy revenue | — | | | 162 | | | 13 | | | — | | | 1 | | | 176 | |
| Capacity revenue | — | | | 73 | | | — | | | — | | | — | | | 73 | |
| Other revenue | 29 | | | (2) | | | 22 | | | — | | | (1) | | | 48 | |
| (d) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2022 |
| (In millions) | Texas | | East | | West/Services/Other | | | | Corporate/Eliminations | | Total |
| Retail revenue | | | | | | | | | | | |
Home(a) | $ | 6,388 | | | $ | 2,088 | | | $ | 2,286 | | | | | $ | (1) | | | $ | 10,761 | |
| Business | 3,229 | | | 13,768 | | | 1,964 | | | | | — | | | 18,961 | |
Total retail revenue(b) | 9,617 | | | 15,856 | | | 4,250 | | | | | (1) | | | 29,722 | |
Energy revenue(b) | 111 | | | 641 | | | 466 | | | | | 32 | | | 1,250 | |
Capacity revenue(b) | — | | | 232 | | | 40 | | | | | — | | | 272 | |
Mark-to-market for economic hedging activities(c) | 2 | | | (30) | | | (56) | | | | | 1 | | | (83) | |
| Contract amortization | — | | | (40) | | | 1 | | | | | — | | | (39) | |
Other revenue(b) | 327 | | | 104 | | | 5 | | | | | (15) | | | 421 | |
| Total revenue | 10,057 | | | 16,763 | | | 4,706 | | | | | 17 | | | 31,543 | |
| Less: Revenues accounted for under topics other than ASC 606 and ASC 815 | — | | | (7) | | | 41 | | | | | 1 | | | 35 | |
| Less: Realized and unrealized ASC 815 revenue | (2) | | | 84 | | | (93) | | | | | 31 | | | 20 | |
| Total revenue from contracts with customers | $ | 10,059 | | | $ | 16,686 | | | $ | 4,758 | | | | | $ | (15) | | | $ | 31,488 | |
| (a) Home includes Services |
| (b) The following amounts of energy, capacity and other revenue relate to derivative instruments and are accounted for under ASC 815: |
| (In millions) | Texas | | East | | West/Services/Other | | | | Corporate/Eliminations | | Total |
| Retail revenue | $ | — | | | $ | 110 | | | $ | — | | | | | $ | — | | | $ | 110 | |
| Energy revenue | — | | | (31) | | | (8) | | | | | 31 | | | (8) | |
| Capacity revenue | — | | | 33 | | | — | | | | | — | | | 33 | |
| Other revenue | (4) | | | 2 | | | (29) | | | | | (1) | | | (32) | |
| (c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2021 |
| (In millions) | Texas | | East | | West/Services/Other | | | | Corporate/Eliminations | | Total |
| Retail revenue | | | | | | | | | | | |
Home(a) | $ | 5,659 | | | $ | 1,832 | | | $ | 2,059 | | | | | $ | (1) | | | $ | 9,549 | |
| Business | 2,745 | | | 10,030 | | | 1,237 | | | | | — | | | 14,012 | |
| Total retail revenue | 8,404 | | | 11,862 | | | 3,296 | | | | | (1) | | | 23,561 | |
Energy revenue(c) | 329 | | | 508 | | | 371 | | | | | 7 | | | 1,215 | |
Capacity revenue(c) | — | | | 718 | | | 57 | | | | | — | | | 775 | |
Mark-to-market for economic hedging activities(d) | (3) | | | (88) | | | (86) | | | | | 13 | | | (164) | |
| Contract amortization | — | | | (26) | | | (4) | | | | | — | | | (30) | |
Other revenue(b)(c) | 1,565 | | | 51 | | | 25 | | | | | (9) | | | 1,632 | |
| Total revenue | 10,295 | | | 13,025 | | | 3,659 | | | | | 10 | | | 26,989 | |
| Less: Revenues accounted for under topics other than ASC 606 and ASC 815 | — | | | (25) | | | 3 | | | | | — | | | (22) | |
| Less: Realized and unrealized ASC 815 revenue | 130 | | | 184 | | | (96) | | | | | 16 | | | 234 | |
| Total revenue from contracts with customers | $ | 10,165 | | | $ | 12,866 | | | $ | 3,752 | | | | | $ | (6) | | | $ | 26,777 | |
| (a) Home includes Services |
| (b) Other Revenue in Texas includes ancillary revenues of $1.3 billion driven by high pricing during Winter Storm Uri |
| (c) The following amounts of energy, capacity and other revenue relate to derivative instruments and are accounted for under ASC 815: |
| (In millions) | Texas | | East | | West/Services/Other | | | | Corporate/Eliminations | | Total |
| Energy revenue | $ | — | | | $ | 131 | | | $ | 2 | | | | | $ | 3 | | | $ | 136 | |
| Capacity revenue | — | | | 149 | | | — | | | | | — | | | 149 | |
| Other revenue | 133 | | | (8) | | | (12) | | | | | — | | | 113 | |
| (d) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815 |
ContractBalances
The following table reflects the contract assets and liabilities included in the Company's balance sheet as of December 31, 2023 and 2022:
| | | | | | | | | | | | | | |
| (In millions) | | December 31, 2023 | | December 31, 2022 |
Capitalized contract costs(a) | | $ | 706 | | | $ | 126 | |
| | | | |
| Accounts receivable, net - Contracts with customers | | 3,395 | | | 4,704 | |
| Accounts receivable, net - Accounted for under topics other than ASC 606 | | 136 | | | 64 | |
| Accounts receivable, net - Affiliate | | 11 | | | 5 | |
| Total accounts receivable, net | | $ | 3,542 | | | $ | 4,773 | |
| | | | |
| Unbilled revenues (included within Accounts receivable, net - Contracts with customers) | | $ | 1,493 | | | $ | 1,952 | |
Deferred revenues (b) | | $ | 1,634 | | | $ | 186 | |
(a)Amortization of capitalized contract costs for the years ended December 31, 2023, 2022 and 2021 were $168 million, $86 million and $95 million, respectively
(b)Deferred revenues from contracts with customers for the years ended December 31, 2023 and 2022 were approximately $1.6 billion and $175 million, respectively. The increase in deferred revenue balances from December 31, 2023 to 2022 was primarily due to the acquisition of Vivint Smart Home
The revenue recognized from contracts with customers during the years ended December 31, 2023 and 2022 relating to the deferred revenue balance at the beginning of each period was $168 million and $184 million, respectively. The change in the revenue recognized from contracts with customers relating to the deferred revenue balances at the beginning of the years ended December 31, 2023 and 2022 was primarily due to the timing difference of when consideration was received and when the performance obligation was transferred.
The Company's capitalized contract costs consist of commission payments, broker fees and other costs that represent incremental costs of obtaining the contract with customers for which the Company expects to recover. Capitalized contract costs are amortized on a straight-line basis over the expected period of benefit of five years. As a practical expedient, the Company expenses the incremental costs of obtaining a contract if the amortization period of the asset would have been one year or less.
When the Company receives consideration from the customer that is in excess of the amount due, such consideration is reclassified to deferred revenue, which represents a contract liability. Smart home products and services performance obligations are recognized over the customer's contract term, which is generally three to five years. Energy contract liabilities are generally recognized to revenue in the next period as the Company satisfies its performance obligations.
Note 4 —Acquisitions and Dispositions
Acquisitions
2023 Acquisitions
Vivint Smart Home Acquisition
On March 10, 2023 (the "Acquisition Closing Date"), the Company completed the acquisition of Vivint Smart Home, Inc., pursuant to the Agreement and Plan of Merger, dated as of December 6, 2022, by and among the Company, Vivint Smart Home, Inc. and Jetson Merger Sub, Inc., a wholly-owned subsidiary of the Company (“Merger Sub”) pursuant to which Merger Sub merged with and into Vivint Smart Home, Inc., with Vivint Smart Home, Inc. surviving the merger as a wholly-owned subsidiary of the Company. Dedicated to redefining the home experience with intelligent products and services, Vivint Smart Home brought approximately two million subscribers to NRG. Vivint Smart Home's single, expandable platform incorporates artificial intelligence and machine learning into its operating system and its vertically integrated business model includes hardware, software, sales, installation, customer service and technical support and professional monitoring, enabling superior subscriber experiences and a complete end-to-end smart home experience. The acquisition accelerated the realization of NRG's consumer-focused growth strategy and 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 approximately $2.6 billion in cash. The Company funded the acquisition using:
•proceeds of $724 million from newly issued $740 million 7.000% Senior Secured First Lien Notes due 2033, net of issuance costs and discount;
•proceeds of $635 million from newly issued $650 million 10.25% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock, net of issuance costs;
•proceeds of approximately $900 million drawn from its Revolving Credit Facility and Receivables Securitization Facilities; and
•cash on hand.
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 13, Long-term Debt and Finance Leases.
Acquisition costs of $38 million and $17 million for the years ended December 31, 2023 and 2022, 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 recorded at their estimated Acquisition Closing Date fair value. The total consideration of $2.623 billion includes:
| | | | | | | | |
| | (In millions) |
| Vivint Smart Home, Inc. common shares outstanding as of March 10, 2023 of 216,901,639 at $12.00 per share | | $ | 2,603 | |
| Other Vivint Smart Home, Inc. equity instruments (Cash out RSUs and PSUs, Stock Appreciation Rights, Private Placement Warrants) | | 6 | |
| Total Cash Consideration | | $ | 2,609 | |
| Fair value of acquired Vivint Smart Home, Inc. equity awards attributable to pre-combination service | | 14 | |
| Total Consideration | | $ | 2,623 | |
The purchase price was allocated as follows as of December 31, 2023:
| | | | | |
| (In millions) |
| Current Assets | |
| Cash and cash equivalents | $ | 120 | |
| Accounts receivable, net | 60 | |
| Inventory | 113 | |
| Prepayments and other current assets | 37 | |
| Total current assets | 330 | |
| Property, plant and equipment, net | 49 | |
| Other Assets | |
| Operating lease right-of-use assets, net | 35 | |
Goodwill(a) | 3,494 | |
Intangible assets, net(b): | |
| Customer relationships | 1,740 | |
| Technology | 860 | |
| Trade names | 160 | |
| Sales channel contract | 10 | |
| Intangible assets, net | 2,770 | |
| Deferred income taxes | 382 | |
| Other non-current assets | 14 | |
| Total other assets | 6,695 | |
| Total Assets | $ | 7,074 | |
| |
| Current Liabilities | |
| Current portion of long-term debt and finance leases | $ | 14 | |
| Current portion of operating lease liabilities | 13 | |
| Accounts payable | 109 | |
| Derivative instruments | 80 | |
| Deferred revenue current | 518 | |
| Accrued expenses and other current liabilities | 207 | |
| Total current liabilities | 941 | |
| Other Liabilities | |
| Long-term debt and finance leases | 2,572 | |
| Non-current operating lease liabilities | 28 | |
| Derivative instruments | 32 | |
| Deferred income taxes | 18 | |
| Deferred revenue non-current | 837 | |
| Other non-current liabilities | 23 | |
| Total other liabilities | 3,510 | |
| Total Liabilities | $ | 4,451 | |
| |
| Vivint Smart Home Purchase Price | $ | 2,623 | |
(a)Goodwill arising from the acquisition is attributed to the value of the platform acquired, cross-selling opportunities, subscriber growth and the synergies expected from combining the operations of Vivint Smart Home with NRG's existing businesses. None of the goodwill recorded will be deductible for tax purposes
(b)The weighted average amortization period for total amortizable intangible assets is approximately ten years
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 classified as Level 3. Under this approach, the Company estimated the present value of expected future cash flows resulting from existing subscriber relationships, considering attrition and charges for contributory assets (such as net working capital, fixed assets, workforce, trade names and technology) utilized in the business, discounted based on the required rate of return on the acquired intangible asset. The subscriber relationships are amortized to depreciation and amortization, ratably based on discounted future cash flows. The weighted average amortization period is twelve years.
Technology – Developed technology was valued using a "relief from royalty" method of the income approach, and is classified as Level 3. Under this approach, the fair value was estimated to be the present value of royalties saved which assumed the value of the asset based on discounted cash flows of the amount that would be paid by a hypothetical market participant had they not 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 based on the required rate of return on the acquired intangible asset. 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 names – Trade names were 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 names considered the expected probable use of the asset and was discounted based on the required rate of return on the acquired intangible asset. The trade names are 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 aggregate principal of Vivint Smart Home’s 2027 Senior Secured Notes, 2029 Senior notes and 2028 Senior Secured Term Loan (together, the "Acquired Vivint Smart Home Debt") which were recorded at fair value as of the Acquisition Closing Date. The difference between the fair value at the Acquisition Closing Date and the principal outstanding of the Acquired Vivint Smart Home Debt, of $152 million, is being amortized through interest expense over the remaining term of the debt. The Acquired Vivint Smart Home Debt is classified as Level 2 and were measured at fair value using observable market inputs based on interest rates at the Acquisition Closing Date. For additional discussion, seeNote 13, Long-term Debt and Finance Leases.
Fair Value Measurement of Derivatives Liabilities
The derivative liabilities are recorded in connection with the contractual future payment obligations with the financing providers under Vivint Smart Home’s Consumer Financing Program. The fair values of the derivatives liabilities as of the Acquisition Closing Date were valued using a discounted cash flow model, with inputs consisting of available market data, such as market yield discount rates, as well as unobservable internally derived assumptions, such as collateral prepayment rates, collateral default rates and credit loss rates. These derivatives are classified as Level 3 and changes to the fair value are recorded through other income, net in the consolidated statement of operations. For additional discussion, see Note 6, Accounting for Derivative Instruments and Hedging Activities.
Supplemental Pro Forma Financial Information
The following table provides unaudited 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, 2021. The pro forma financial information has been prepared for illustrative and informational purposes only, and is not intended to project future operating results or be indicative of what the Company's financial performance would have been had the transactions occurred on the date indicated. No effect has been given to prospective operating synergies.
| | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, |
| (In millions) | 2023 | | 2022 | | 2021 |
| Total operating revenues | $ | 29,109 | | | $ | 33,225 | | | $ | 28,468 | |
| Net (loss)/income | (3) | | | 1,136 | | | 1,574 | |
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 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 derivativeswarrants are assumed to accumulated OCI, untilbe cashed out upon the hedgedAcquisition Closing Date.
(ii)One-time expenses directly related to the acquisition.
(iii)Adjustments to reflect all acquisition and related transactions occurcosts in the year ended December 31, 2021.
(iv)Interest expense assumes the financing transactions directly attributable to the Vivint Smart Home acquisition occurred on January 1, 2021.
(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 year ended December 31, 2021 instead of the year ended December 31, 2023.
(vii) Income tax effect of the acquisition accounting adjustments and financing adjustments (adjusted for permanent book/tax differences) based on combined blended federal/state tax rate for all periods presented.
2021 Acquisitions
Direct Energy Acquisition
On January 5, 2021, the Company acquired all of the issued and outstanding common shares of Direct Energy, which had been a North American subsidiary of Centrica plc. Direct Energy is a leading retail provider of electricity, natural gas, and home and business energy related products and services in North America, with operations in all 50 U.S. states and 8 Canadian provinces. The acquisition increased NRG's retail portfolio by over 3 million customers and strengthened its integrated model. It also broadened the Company's presence in the Northeast and into states and locales where it did not previously operate, supporting NRG's objective to diversify its business.
The Company paid an aggregate purchase price of $3.625 billion in cash and total purchase price adjustment of $99 million, resulting in an adjusted purchase price of $3.724 billion.
Acquisition costs of $25 million for the year ended December 31, 2021 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 acquired and liabilities assumed recorded at their estimated fair values on the acquisition date. The purchase price was allocated as follows as of December 31, 2021:
| | | | | |
| (In millions) |
| Current Assets | |
| Cash and cash equivalents | $ | 152 | |
| Funds deposited by counterparties | 21 | |
| Restricted cash | 9 | |
| Accounts receivable, net | 1,802 | |
| Inventory | 106 | |
| Derivative instruments | 1,014 | |
| Cash collateral paid in support of energy risk management activities | 233 | |
| Prepayments and other current assets | 173 | |
| Total current assets | 3,510 | |
| Property, plant and equipment, net | 151 | |
| Other Assets | |
Goodwill(a) | 1,250 | |
| Intangible assets, net: | |
Customer relationships(b) | 1,277 | |
Customer and supply contracts(b) | 610 | |
Trade names(b) | 310 | |
| Renewable energy credits | 124 | |
| Total intangible assets, net | 2,321 | |
| Derivative instruments | 531 | |
| Other non-current assets | 31 | |
| Total other assets | 4,133 | |
| Total Assets | $ | 7,794 | |
| |
| Current Liabilities | |
| Accounts payable | $ | 1,116 | |
| Derivative instruments | 1,266 | |
| Cash collateral received in support of energy risk management activities | 21 | |
| Accrued expenses and other current liabilities | 670 | |
| Total current liabilities | 3,073 | |
| Other Liabilities | |
| Derivative instruments | 562 | |
| Deferred income taxes | 320 | |
| Other non-current liabilities | 115 | |
| Total other liabilities | 997 | |
| Total Liabilities | $ | 4,070 | |
| |
| Direct Energy Purchase Price | $ | 3,724 | |
(a)Goodwill arising from the acquisition was attributed to the value of the platform acquired and the synergies expected from combining the operations of Direct Energy with NRG's existing businesses. Goodwill was allocated to the Texas, East, and West/Services/Other segments of $427 million, $648 million and $175 million, respectively. Goodwill deductible for tax purposes was $322 million
(b)As of January 5, 2021, the weighted average amortization period for total amortizable intangible assets was 12 years
Dispositions
2023 Dispositions
Sale of the 44% equity interest in STP
On November 1, 2023, the Company closed on the sale of its 44% equity interest in STP to Constellation Energy Generation ("Constellation"). Proceeds of $1.75 billion were reduced by working capital and other adjustments of $96 million, resulting in net proceeds of $1.654 billion. The Company recorded a gain on the sale of $1.2 billion within the Texas region of operations. For discussion of the litigation matter related to the transaction, see Note 23, Commitments and Contingencies.
The Company recorded income before income taxes from its 44% equity interest in STP as follows:
| | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, |
| (In millions) | 2023 | | 2022 | | 2021 |
Income before income taxes(a) | $ | 206 | | | $ | 362 | | | $ | 829 | |
(a)Excludes the impact of the Company's hedges at the portfolio level
Sale of Gregory
On October 2, 2023, the Company closed on the sale of its 100% ownership in the Gregory natural gas generating facility in Texas for $102 million. The Company recorded a gain on the sale of $82 million.
Sale of Astoria
On January 6, 2023, the Company closed on the sale of land and related generation assets from the Astoria site, within the East region of operations, for proceeds of $212 million, subject to transaction fees of $3 million and certain indemnifications, resulting in a $199 million gain. As part of the transaction, NRG entered into an agreement to lease the land back for the purpose of operating the Astoria gas turbines. Decommissioning was completed in December 2023 and the lease agreement has been terminated.
2022 Dispositions
Sale of Watson
On June 1, 2022, the Company closed on the sale of its 49% ownership in the Watson natural gas generating facility for $59 million. The Company recorded a gain on the sale of $46 million.
2021 Dispositions
Sale of 4,850 MW of Fossil generating assets
On December 1, 2021, the Company closed the previously announced sale of approximately 4,850 MWs of fossil generating assets from its East and West regions to Generation Bridge, an affiliate of ArcLight Capital Partners. Proceeds of $760 million were reduced by working capital and other adjustments of $140 million, resulting in net proceeds of $620 million. The Company recorded a gain of $207 million from the sale, which includes the $39 million indemnification liability recorded as discussed below. As part of the transaction, NRG entered into a tolling agreement for the 866 MW Arthur Kill plant in New York City through April 2025.
As part of the agreement to sell the fossil generating assets, NRG has agreed to indemnify Generation Bridge for certain future environmental compliance costs up to $39 million. The indemnity term will expire on December 1, 2028. The Company has recorded the liability within accrued expenses and other current liabilities and other non-current liabilities.
Sale of Agua Caliente
On February 3, 2021, the Company closed on the sale of its 35% ownership in the Agua Caliente solar project to Clearway Energy, Inc. for $202 million. NRG recognized a gain on the sale of $17 million, including cash disposed of $7 million.
Note 5 — Fair Value of Financial Instruments
For cash and cash equivalents, funds deposited by counterparties, restricted cash, accounts and other receivables, accounts payable and cash collateral paid and received in support of energy risk management activities, the carrying amount approximates fair value because of the short-term maturity of those instruments and are recognizedclassified as Level 1 within the fair value hierarchy.
The estimated carrying value and fair value of the Company's long-term debt, including current portion, is as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| | As of December 31, |
| 2023 | | 2022 |
| (In millions) | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Convertible Senior Notes | $ | 575 | | | $ | 739 | | | $ | 575 | | | $ | 576 | |
| Other long-term debt, including current portion | 10,219 | | | 9,835 | | | 7,523 | | | 6,432 | |
Total long-term debt, including current portion(a) | $ | 10,794 | | | $ | 10,574 | | | $ | 8,098 | | | $ | 7,008 | |
(a)Excludes deferred financing costs, which are recorded as a reduction to long-term debt on the Company's consolidated balance sheets
The fair value of the Company's publicly-traded long-term debt and the Vivint Smart Home Senior Secured Term Loan are based on quoted market prices and are classified as Level 2 within the fair value hierarchy.
Fair Value Accounting under ASC 820
ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:
•Level 1 — quoted prices (unadjusted) in earnings.active markets for identical assets or liabilities that the Company has the ability to access as of the measurement date. NRG's financial assets and liabilities utilizing Level 1 inputs include active exchange-traded securities, energy derivatives, and trust fund investments.
For derivatives•Level 2 — inputs other than quoted prices included within Level 1 that are not designateddirectly observable for the asset or liability or indirectly observable through corroboration with observable market data. NRG's financial assets and liabilities utilizing Level 2 inputs include fixed income securities, exchange-based derivatives, and over the counter derivatives such as cash flow hedgesswaps, options and forward contracts.
•Level 3 — unobservable inputs for the asset or do not qualifyliability only used when there is little, if any, market activity for hedge accounting treatment, the changesasset or liability at the measurement date. NRG's financial assets and liabilities utilizing Level 3 inputs include infrequently-traded, non-exchange-based derivatives and commingled investment funds, and are measured using present value pricing models.
In accordance with ASC 820, the Company determines the level in the fair value will be immediately recognizedhierarchy within which each fair value measurement in earnings. Certain derivative instruments may qualifyits entirety falls, based on the lowest level input that is significant to the fair value measurement in its entirety.
Recurring Fair Value Measurements
Derivative assets and liabilities, debt securities, equity securities and trust fund investments, which were comprised of various U.S. debt and equity securities, are carried at fair market value.
The following tables present assets and liabilities measured and recorded at fair value on the Company's consolidated balance sheets on a recurring basis and their level within the fair value hierarchy:
| | | | | | | | | | | | | | | | | | | | | | | |
| | As of December 31, 2023 |
| | Fair Value |
| (In millions) | Total | | Level 1 | | Level 2 | | Level 3 |
| Investments in securities (classified within other current and non-current assets) | $ | 21 | | | $ | — | | | $ | 21 | | | $ | — | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Derivative assets: | | | | | | | |
| Interest rate contracts | 12 | | | — | | | 12 | | | — | |
| Foreign exchange contracts | 5 | | | — | | | 5 | | | — | |
| Commodity contracts | 6,138 | | | 1,334 | | | 4,470 | | | 334 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Equity securities measured using net asset value practical expedient (classified within other non-current assets) | 6 | | | | | | | |
| Total assets | $ | 6,182 | | | $ | 1,334 | | | $ | 4,508 | | | $ | 334 | |
| Derivative liabilities: | | | | | | | |
| Interest rate contracts | $ | 8 | | | $ | — | | | $ | 8 | | | $ | — | |
| Foreign exchange contracts | 9 | | | — | | | 9 | | | — | |
| Commodity contracts | 5,356 | | | 1,413 | | | 3,728 | | | 215 | |
| Consumer Financing Program | 134 | | | — | | | — | | | 134 | |
| Total liabilities | $ | 5,507 | | | $ | 1,413 | | | $ | 3,745 | | | $ | 349 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | As of December 31, 2022 |
| | Fair Value |
| (In millions) | Total | | Level 1 | | Level 2 | | Level 3 |
| Investments in securities (classified within other current and non-current assets) | $ | 19 | | | $ | — | | | $ | 19 | | | $ | — | |
| Nuclear trust fund investments: | | | | | | | |
| Cash and cash equivalents | 15 | | | 15 | | | — | | | — | |
| U.S. government and federal agency obligations | 86 | | | 84 | | | 2 | | | — | |
| Federal agency mortgage-backed securities | 101 | | | — | | | 101 | | | — | |
| Commercial mortgage-backed securities | 35 | | | — | | | 35 | | | — | |
| Corporate debt securities | 114 | | | — | | | 114 | | | — | |
| Equity securities | 403 | | | 403 | | | — | | | — | |
| Foreign government fixed income securities | 1 | | | — | | | 1 | | | — | |
| Other trust fund investments (classified within other non-current assets): | | | | | | | |
| U.S. government and federal agency obligations | 1 | | | 1 | | | — | | | — | |
| Derivative assets: | | | | | | | |
| Foreign exchange contracts | 18 | | | — | | | 18 | | | — | |
| Commodity contracts | 11,976 | | | 1,929 | | | 8,796 | | | 1,251 | |
| | | | | | | |
| | | | | | | |
| Measured using net asset value practical expedient: | | | | | | | |
| Equity securities - nuclear trust fund investments | 83 | | | | | | | |
| Equity securities (classified within other non-current assets) | 6 | | | | | | | |
| Total assets | $ | 12,858 | | | $ | 2,432 | | | $ | 9,086 | | | $ | 1,251 | |
| Derivative liabilities: | | | | | | | |
| Foreign exchange contracts | $ | 2 | | | $ | — | | | $ | 2 | | | $ | — | |
| Commodity contracts | 8,439 | | | 1,244 | | | 6,449 | | | 746 | |
| | | | | | | |
| Total liabilities | $ | 8,441 | | | $ | 1,244 | | | $ | 6,451 | | | $ | 746 | |
The following table reconciles, for the NPNS exceptionyears ended December 31, 2023 and 2022, the beginning and ending balances for financial instruments that are recognized at fair value in the consolidated financial statements using significant unobservable inputs, for commodity derivatives:
| | | | | | | | | | | | | | |
| | | Fair Value Measurement Using Significant Unobservable Inputs (Level 3) |
| | Commodity Derivatives (a) |
| | For the Year Ended December 31, |
| (In millions) | | 2023 | | 2022 |
| Beginning balance | | $ | 505 | | | $ | 293 | |
| | | | |
| Total (losses)/gains realized/unrealized included in earnings | | (164) | | | 53 | |
| | | | |
| Purchases | | 42 | | | (110) | |
| | | | |
Transfers into Level 3(b) | | 78 | | | 264 | |
Transfers out of Level 3(b)(c) | | (342) | | | 5 | |
| Ending balance | | $ | 119 | | | $ | 505 | |
| (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 year-end | | $ | (46) | | | $ | 204 | |
(a)Consists of derivatives assets and liabilities, net, excluding derivative 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 consensus pricing and external broker quotes, and are therefore exemptvalued as of the end of the reporting period. All transfers into/out of Level 3 are from/to Level 2
(c)For the year ended December 31, 2023, due to the change to use consensus pricing, there was a decrease in the number of contracts valued with prices provided by models and other valuation techniques, which resulted in a large transfer out of Level 3
Realized and unrealized gains and losses included in earnings that are related to the commodity derivatives are recorded in revenues and cost of operations.
The following table reconciles, for the year ended December 31, 2023, the beginning and ending balances of the contractual obligations from the Consumer Financing Program that are recognized at fair value accounting treatment. ASC 815in the condensed consolidated financial statements, using significant unobservable inputs:
| | | | | | | |
| | | Fair Value Measurement Using Significant Unobservable Inputs (Level 3) |
| | | Consumer Financing Program |
| (In millions) | | | For the Year Ended December 31, 2023 |
| Beginning balance | | | $ | — | |
| Contractual obligations added from the acquisition of Vivint Smart Home | | | (112) | |
| New contractual obligations | | | (68) | |
| Settlements | | | 62 | |
| Total losses included in earnings | | | (16) | |
| Ending balance | | | $ | (134) | |
Gains and losses that are related to the Consumer Financing Program derivative are recorded in other income, net.
Non-derivative fair value measurements
For the year ended December 31, 2022 and through the sale of STP on November 1, 2023, the trust fund investments were held primarily to satisfy NRG's nuclear decommissioning obligations. These trust fund investments held debt and equity securities directly and equity securities indirectly through commingled funds. The fair values of equity securities held directly by the trust funds were based on quoted prices in active markets and were categorized in Level 1. In addition, U.S. government and federal agency obligations were categorized as Level 1 because they traded in a highly liquid and transparent market. The fair values of corporate debt securities were based on evaluated prices that reflected observable market information, such as actual trade information of similar securities, adjusted for observable differences and were categorized in Level 2. Certain equity securities, classified as commingled funds, were analogous to mutual funds, were maintained by investment companies, and held certain investments in accordance with a stated set of fund objectives. The fair value of the equity securities classified as commingled funds were based on net asset values per fund share (the unit of account), derived from the quoted prices in active markets of the underlying equity securities. However, because the shares in the commingled funds were not publicly quoted and not traded in an active market, the commingled funds were measured using net asset value practical expedient. See also Note 7, Nuclear Decommissioning Trust Fund.
Derivative fair value measurements
The Company's contracts consist of non-exchange-traded contracts valued using prices provided by external sources and exchange-traded contracts with readily available quoted market prices. Beginning in of the fourth quarter of 2023 and as of December 31, 2023, the fair value of non-exchange traded contracts were based on consensus pricing provided by independent pricing services. The pricing data was compiled from market makers with longer dated tenors as compared to broker quotes, enhancing reliability and increasing transparency.
Prior to the fourth quarter of 2023, the Company valued derivatives based on price quotes from brokers in active markets who regularly facilitate those transactions. For the majority of markets that NRG participates in, the Company would receive broker quotes from multiple sources and reflected the average of the bid-ask mid-point prices. The terms for which such price information is available vary by commodity, region and product. The Company believes both sources of price quotes are executable.
The remainder of the assets and liabilities represents contracts for which external sources or observable market quotes are not available. These contracts are valued based on various valuation techniques including but not limited to internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. As of December 31, 2023, contracts valued with prices provided by models and other valuation techniques make up 5% of derivative assets and 6% of derivative liabilities. As a result of NRG switching to consensus pricing as of December 31, 2023, there was a significant decrease in the number of contracts valued with prices provided by models and other valuation techniques. 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 for foreign exchange contracts and interest rate swaps is calculated utilizing the bilateral method based on published default probabilities. For commodities, to the extent that NRG's energy related commoditynet exposure under a specific master agreement is an asset, the Company uses the counterparty's default swap rate. If the exposure under a specific master agreement is a liability, the Company uses NRG's default swap rate. For foreign exchange contracts, interest rate swaps, and equity contracts.commodities, the credit reserve is added to the discounted fair value to reflect the exit price that a market participant would be willing to receive to assume NRG's liabilities or that a market participant would be willing to pay for NRG's assets. As of December 31, 2023, the credit reserve resulted in a $18 million decrease primarily within cost of operations. As of December 31, 2022, the credit reserve resulted in $9 million decrease primarily within cost of operations.
The fair values in each category reflect the Company engages principallylevel of forward prices and volatility factors as of December 31, 2023 and may change as a result of changes in these factors. Management uses its best estimates to determine the tradingfair value of commodity and marketing of its generationderivative contracts NRG holds and sells. These estimates consider various factors including closing exchange, consensus and over-the-counter price quotations, time value, volatility factors and credit exposure. It is possible, however, that future market prices could vary from those used in recording assets and retail businesses, some of NRG's commercial activities qualify for hedge accounting. In order for the generation assets to qualify, the physical generation and sale of electricity should be highly probable at inception of the trade and throughout the period it is held, as is the case with the Company's baseload plants. For this reason, trades in support of NRG's baseload units may qualify for NPNS or cash flow hedge accounting treatment, and trades in support of NRG's peaking units' asset optimization will generally not qualify for hedge accounting treatment, with any changes in fair value likely to be reflected on a mark-to-market basis in the statement of operations. Most of the retail load contracts either qualify for the NPNS exception or fail to meet the criteria for a derivative and the majority of the retail supply and fuels supply contracts are recorded under mark-to-market accounting. All of NRG's hedgingliabilities from energy marketing and trading activities and such variations could be material.
NRG's significant positions classified as Level 3 include physical and financial natural gas, power, capacity contracts and renewable energy certificates executed in illiquid markets as well as financial transmission rights ("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. Forward capacity prices are subjectbased on market information, forecasted future electricity demand and supply, past auctions and internally developed pricing models. Renewable energy certificate prices are based on market information and internally developed pricing models. For FTRs, NRG uses the most recent auction prices to limits withinderive the fair value. The Consumer Financing Program derivatives are valued using a discounted cash flow model, with inputs consisting of available market data, such as market yield discount rates, as well as unobservable internally derived assumptions, such as collateral prepayment rates, collateral default rates and credit loss rates.
The following tables quantify the significant unobservable inputs used in developing the fair value of the Company's Risk Management Policy.Level 3 positions as of December 31, 2023 and 2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Significant Unobservable Inputs |
| December 31, 2023 |
| Fair Value | | | | Input/Range |
| (in millions, except as noted) | Assets | | Liabilities | | Valuation Technique | | Significant Unobservable Input | | Low | | High | | Weighted Average |
| Natural Gas Contracts | $ | 39 | | | $ | 65 | | | Discounted Cash Flow | | Forward Market Price ($ per MMBtu) | | $ | 1 | | | $ | 15 | | | $ | 3 | |
| Power Contracts | 197 | | | 66 | | | Discounted Cash Flow | | Forward Market Price ($ per MWh) | | 1 | | | 210 | | | 47 | |
| Capacity Contracts | 21 | | | 33 | | | Discounted Cash Flow | | Forward Market Price ($ per MW/Day) | | 49 | | | 658 | | | 285 | |
| Renewable Energy Certificates | 58 | | | 14 | | | Discounted Cash Flow | | Forward Market Price ($ per Certificate) | | 2 | | | 320 | | | 15 | |
| FTRs | 19 | | | 37 | | | Discounted Cash Flow | | Auction Prices ($ per MWh) | | (58) | | | 252 | | | 0 | |
| Consumer Financing Program | — | | | 134 | | | Discounted Cash Flow | | Collateral Default Rates | | 0.43 | % | | 93.30 | % | | 8.12 | % |
| | | | | Discounted Cash Flow | | Collateral Prepayment Rates | | 2.00 | % | | 3.00 | % | | 2.95 | % |
| | | | | Discounted Cash Flow | | Credit Loss Rates | | 6.00 | % | | 60.00 | % | | 12.57 | % |
| $ | 334 | | | $ | 349 | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Significant Unobservable Inputs |
| December 31, 2022 |
| Fair Value | | | | Input/Range |
| (in millions, except as noted) | Assets | | Liabilities | | Valuation Technique | | Significant Unobservable Input | | Low | | High | | Weighted Average |
| Natural Gas Contracts | $ | 340 | | | $ | 448 | | | Discounted Cash Flow | | Forward Market Price ($ per MMBtu) | | $ | 2 | | | $ | 48 | | | $ | 6 | |
| Power Contracts | 843 | | | 216 | | | Discounted Cash Flow | | Forward Market Price ($ per MWh) | | 3 | | | 431 | | | 48 | |
| FTRs | 68 | | | 82 | | | Discounted Cash Flow | | Auction Prices ($ per MWh) | | (32) | | | 610 | | | 0 | |
| $ | 1,251 | | | $ | 746 | | | | | | | | | | | |
| | | | | | | | | | | | | |
The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable inputs as of December 31, 2023 and 2022: | | | | | | | | | | | | | | | | | | | | |
| Significant Unobservable Input | | Position | | Change In Input | | Impact on Fair Value Measurement |
| Forward Market Price Natural Gas/Power/Capacity/Renewable Energy Certificates | | Buy | | Increase/(Decrease) | | Higher/(Lower) |
| Forward Market Price Natural Gas/Power/Capacity/Renewable Energy Certificates | | Sell | | Increase/(Decrease) | | Lower/(Higher) |
| FTR Prices | | Buy | | Increase/(Decrease) | | Higher/(Lower) |
| FTR Prices | | Sell | | Increase/(Decrease) | | Lower/(Higher) |
| Collateral Default Rates | | n/a | | Increase/(Decrease) | | Higher/(Lower) |
| Collateral Prepayment Rates | | n/a | | Increase/(Decrease) | | Lower/(Higher) |
| Credit Loss Rates | | n/a | | Increase/(Decrease) | | Higher/(Lower) |
Under the guidance of ASC 815, entities may choose to offset cash collateral posted or received against the fair value of derivative positions executed with the same counterparties under the same master netting agreements. The Company has chosen not to offset positions as defined in ASC 815. As of December 31, 2023, the Company recorded $441 million of cash collateral posted and $84 million of cash collateral received on its balance sheet.
Energy-Related Commodities
As of December 31, 2023, for purposes of measuring the fair value of derivative instruments, the Company primarily uses quoted exchange prices and consensus pricing. Consensus pricing is provided by independent pricing services which are compiled from market makers with longer dated tenors as compared to broker quotes. Prior to the fourth quarter of 2023, the Company valued derivatives based on price quotes from brokers in active markets who regularly facilitate those transactions. The Company started using consensus pricing as it offers data from more market makers and for longer dated tenors as compared to broker quotes, enhances data integrity, and increases transparency. When external prices are not available, NRG uses internal models to determine the fair value. These internal models include assumptions of the future prices of energy commodities based on the specific market in which the energy commodity is being purchased or sold, using externally available forward market pricing curves for all periods possible under the pricing model. These estimations are considered to be critical accounting estimates.
Interest Rate Swaps
NRG is exposed to changes in interest rate through the Company's issuance of variable rate debt. To manage the Company's interest rate risk, NRG enters into interest rate swap agreements. In order to qualify the derivative instruments for hedged transactions, NRG estimates the forecasted borrowings for interest rate swaps occurring within a specified time period.
Foreign Exchange Contracts
In order to mitigate foreign exchange risk primarily associated with the purchase of USD denominated natural gas for the Company's Canadian business, the Company enters into foreign exchange contract agreements.
Consumer Financing Program
The derivative positions for the Company's Consumer Financing Program are valued using a discounted cash flow model, with inputs consisting of available market data, such as market yield discount rates, as well as unobservable internally derived assumptions, such as collateral prepayment rates, collateral default rates and credit loss rates. In summary, the fair value represents an estimate of the present value of the cash flows Vivint Smart Home will be obligated to pay to the third-party financing provider for each component of the derivative.
Certain derivative instruments that meet the criteria for derivative accounting treatment also qualify for a scope exception to derivative accounting, as they are considered to be NPNS. The availability of this exception is based upon the assumption that the Company has the ability and it is probable to deliver or take delivery of the underlying item. These assumptions are based on expected load requirements, internal forecasts of sales and generation and historical physical delivery on contracts. Derivatives that are considered to be NPNS are exempt from derivative accounting treatment and are accounted for under accrual accounting. If it is determined that a transaction designated as NPNS no longer meets the scope exception due to changes in estimates, the related contract would be recorded on the balance sheet at fair value combined with the immediate recognition through earnings.
Income Taxes and Valuation Allowance for Deferred Tax Assets
As of December 31, 2023, NRG’s deferred tax assets were primarily the result of U.S. federal and state NOLs, the difference between book and tax basis in property, plant, and equipment, deferred revenues and tax credit carryforwards. The realization of deferred tax assets is dependent upon the Company's ability to generate sufficient future taxable income during the periods in which those temporary differences become deductible, prior to the expiration of the tax attributes. The evaluation of deferred tax assets requires judgment in assessing the likely future tax consequences of events that have been recognized in the Company's financial statements or tax returns and forecasting future profitability by tax jurisdiction.
The Company evaluates its deferred tax assets quarterly on a jurisdictional basis to determine whether adjustments to the valuation allowance are appropriate considering changes in facts or circumstances. As of each reporting date, management considers new evidence, both positive and negative, when determining the future realization of the Company’s deferred tax assets. Given the Company’s current level of pre-tax earnings and forecasted future pre-tax earnings, the Company expects to generate income before taxes in the U.S. in future periods at a level that would fully utilize its U.S. federal NOL carryforwards and the majority of its state NOL carryforwards prior to their expiration.
The Company continues to maintain a valuation allowance of $275 million as of December 31, 2023 against deferred tax assets consisting of state NOL carryforwards and foreign NOL carryforwards in jurisdictions where the Company does not currently believe that the realization of deferred tax assets is more likely than not. As of December 31, 2022, the Company's valuation allowance balance was $224 million.
Considerable judgment is required to determine the tax treatment of a particular item that involves interpretations of complex tax laws. The Company is subject to examination by taxing authorities for income tax returns filed in the U.S. federal jurisdiction and various state and foreign jurisdictions, including operations located in Australia and Canada.The Company continues to be under audit for multiple years by taxing authorities in various jurisdictions.
The Company is no longer subject to U.S. federal income tax examinations for years prior to 2020.With few exceptions, state and Canadian income tax examinations are no longer open for years before 2015.
NRG does not intend, nor currently foresee a need, to repatriate funds held at its international operations into the U.S. These funds are deemed to be indefinitely reinvested in its foreign operations and the Company has not changed its assertion with respect to distributions of funds that would require the accrual of U.S. income tax.
Evaluation of Assets for Impairment
In accordance with ASC 360, Property, Plant, and Equipment ("ASC 360"), the Company evaluates property, plant and equipment and certain intangible assets for impairment whenever indicators of impairment exist. Examples of such indicators or events include:
•Significant decrease in the market price of a long-lived asset;
•Significant adverse change in the manner an asset is being used or its physical condition;
•Adverse business climate;
•Accumulation of costs significantly in excess of the amounts originally expected for the construction or acquisition of an asset;
•Current period loss combined with a history of losses or the projection of future losses; and
•Change in the Company's intent about an asset from an intent to hold to a greater than 50% likelihood that an asset will be sold, or disposed of before the end of its previously estimated useful life.
Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the assets to the future net cash flows expected to be generated by the asset, through considering project specific assumptions for long-term power and natural gas prices, escalated future project operating costs and expected plant operations. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets by factoring in the different courses of action available to the Company. Generally, fair value will be determined using valuation techniques, such as the present value of expected future cash flows. NRG uses its best estimates in making these evaluations and considers various factors, including forward price curves for energy, fuel and operating costs. However, actual future market prices and project costs could vary from the assumptions used in the Company's estimates and the impact of such variations could be material.
For assets to be held and used, if the Company determines that the undiscounted cash flows from the asset are less than the carrying amount of the asset, NRG must estimate fair value to determine the amount of any impairment loss. Assets held-for-sale are reported at the lower of the carrying amount or fair value less the cost to sell. The estimation of fair value, whether in conjunction with an asset to be held and used or with an asset held-for-sale, and the evaluation of asset impairment are, by their nature, subjective. The Company considers quoted market prices in active markets to the extent they are available. In the absence of such information, NRG may consider prices of similar assets, consult with brokers or employ other valuation techniques. The Company will also discount the estimated future cash flows associated with the asset using a single interest rate representative of the risk involved with such an investment or asset. The use of these methods involves the same inherent uncertainty of future cash flows as previously discussed with respect to undiscounted cash flows. Actual future market prices and project costs could vary from those used in NRG's estimates and the impact of such variations could be material.
Annually, during the fourth quarter, the Company revises its views of power and fuel prices including the Company's fundamental view for long-term prices, forecasted generation and operating and capital expenditures, in connection with the preparation of its annual budget. Changes to the Company's views of long-term power and fuel prices impact the Company’s projections of profitability, based on management's estimate of supply and demand within the sub-markets for its operations and the physical and economic characteristics of each of its businesses.
For further discussion, see Item 15 — Note 11, Asset Impairments.
Goodwill and Other Intangible Assets
At December 31, 2023, the Company reported goodwill of $5.1 billion, consisting of $3.5 billion from the acquisition of Vivint in 2023, $1.3 billion from the acquisition of Direct Energy in 2021 and $0.3 billion from other retail acquisitions.
The Company applies ASC 805, Business Combinations ("ASC 805"), and ASC 350, Intangibles-Goodwill and Other ("ASC 350") to account for its goodwill and intangible assets. Under these standards, the Company amortizes all finite-lived intangible assets over their respective estimated weighted-average useful lives, while goodwill has an indefinite life and is not amortized. Goodwill is tested for impairment at least annually, or more frequently whenever an event or change in circumstances occurs that would more likely than not reduce the fair value of a reporting unit below its carrying amount. The Company tests goodwill for impairment at the reporting unit level, which is identified by assessing whether the components of the Company's operating segments constitute businesses for which discrete financial information is available and whether segment management regularly reviews the operating results of those components. The Company performs the annual goodwill impairment assessment as of December 31 or when events or changes in circumstances indicate that the fair value of the reporting unit may be below the carrying amount. The Company may first assess qualitative factors to determine whether it is more likely than not that an impairment has occurred. In the absence of sufficient qualitative factors, the Company performs a quantitative assessment by determining the fair value of the reporting unit and comparing to its book value. If it is determined that the fair value of a reporting unit is below its carrying amount, the Company's goodwill will be impaired at that time.
Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. As a result, there can be no assurance that the estimates and assumptions made for purposes of the annual goodwill impairment test will prove to be accurate predictions of the future.
For further discussion, see Evaluation of Assets for Impairment caption above, and Item 15 — Note 11, Asset Impairments.
Business Combinations
NRG accounts for business acquisitions using the acquisition method of accounting prescribed under ASC 805. Under this method, the Company is required to record on its Consolidated Balance Sheets the estimated fair values of the acquired company’s assets and liabilities assumed at the acquisition date. The excess of the consideration transferred over the fair value of the net identifiable assets acquired and liabilities assumed is recorded as goodwill. Determining fair values of assets acquired and liabilities assumed requires significant estimates and judgments. Fair value is determined based on the estimated price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The acquired assets and assumed liabilities from the Vivint Smart Home acquisition that involved the most subjectivity in determining fair value consisted of customer relationships, developed technology, trade names, acquired debt and derivative instruments. NRG describes in detail its acquisitions in Item 15 — Note 4, Acquisitions and Dispositions, to the Consolidated Financial Statements.
The fair value of the customer relationships, technology and trade names are measured using income-based valuation methodologies, which include certain assumptions such as forecasted future cash flows, customer attrition rates, royalty rates and discount rates. Customer relationships and technology are amortized to depreciation and amortization, ratably based on discounted future cash flows. Trade names are amortized to depreciation and amortization, on a straight line basis.
The acquired Vivint Smart Home debt was measured at fair value using observable market inputs based on interest rates at the acquisition closing date. The difference between the fair value at the acquisition closing date and the principal outstanding is being amortized through interest expense over the remaining term of the debt.
The derivative liabilities in connection with the contractual future payment obligations with the financing providers under Vivint Smart Home’s Consumer Financing Program were measured at fair value at the acquisition closing date using a discounted cash flow model, with inputs consisting of available market data, such as market yield discount rates, as well as unobservable internally derived assumptions, such as collateral prepayment rates, collateral default rates and credit loss rates. Changes to the fair value are recorded each period through other income, net in the consolidated statement of operations.
Contingencies
NRG records reserves 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. Gain contingencies are not recorded until management determines it is certain that the future event will become or does become a reality. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events, and estimates of the financial impacts of such events. NRG describes in detail its contingencies in Item 15 — Note 23, Commitments and Contingencies, to the Consolidated Financial Statements.
Recent Accounting Developments
See Item 15 — Note 2, Summary of Significant Accounting Policies, to the Consolidated Financial Statements for a discussion of recent accounting developments.
Item 7A — 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 transactions. The types of market risks the Company is exposed to are commodity price risk, credit risk, liquidity risk, interest rate risk and currency exchange risk. In order to manage these risks, the Company uses various fixed-price forward purchase and sales contracts, futures and option contracts traded on NYMEX and other exchanges, and swaps and options traded in the over-the-counter financial markets to:
•Manage and hedge fixed-price purchase and sales commitments;
•Reduce exposure to the volatility of cash market prices, and
•Hedge fuel requirements for the Company's generating facilities.
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 servicing obligations and merchant generation operations by entering into various derivative or non-derivative instruments to hedge the variability in future cash flows from forecasted sales and purchases of power and fuel. NRG measures the risk of the Company's portfolio using several analytical methods, including sensitivity tests, scenario tests, stress tests, position reports and VaR. NRG uses a Monte Carlo simulation based VaR model to estimate the potential loss in the fair value of its energy assets and liabilities, which includes generation assets, gas transportation and storage assets, load obligations and bilateral physical and financial transactions, based on historical and forward values for factors such as customer demand, weather, commodity availability and commodity prices. The Company's VaR model is based on a one-day holding period at a 95% confidence interval for the forward 36 months, not including the spot month. The VaR model is not a complete picture of all risks that may affect the Company's results. Certain events such as counterparty defaults, regulatory changes, and extreme weather and prices that deviate significantly from historically observed values are not reflected in the model.
The following table summarizes average, maximum and minimum VaR for NRG's commodity portfolio, calculated using the VaR model for the years ended December 31, 2023 and 2022:
| | | | | | | | | | | |
| (In millions) | 2023 | | 2022 |
| VaR as of December 31, | $ | 51 | | | $ | 74 | |
| For the year ended December 31, | | | |
| Average | $ | 62 | | | $ | 51 | |
| Maximum | 82 | | | 86 | |
| Minimum | 41 | | | 26 | |
The Company also uses VaR to estimate the potential loss of derivative financial instruments that are subject to mark-to-market accounting. These derivative instruments include transactions that were entered into for both asset management and trading purposes. The VaR for the derivative financial instruments calculated using the diversified VaR model for the entire term of these instruments entered into for both asset management and trading was $185 million as of December 31, 2023, primarily driven by asset-backed 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 6, Accounting for Derivative Instruments and Hedging Activities, to this Form 10-K for discussion regarding credit risk contingent features.
Counterparty 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. The Company monitors and manages credit risk through credit policies that include: (i) an established credit approval process; (ii) a daily monitoring of counterparties' credit limits; (iii) the use of credit mitigation measures such as margin, collateral, prepayment arrangements, or volumetric limits; (iv) the use of payment netting agreements; and (v) the use of master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with a single counterparty. Risks surrounding counterparty performance and credit could ultimately impact the amount and timing of expected cash flows. The Company seeks to mitigate counterparty risk by having a diversified portfolio of counterparties. The Company also has credit protection within various agreements to call on additional collateral support if and when necessary. Cash margin is collected and held at the Company to cover the credit risk of the counterparty until positions settle.
As of December 31, 2023, counterparty credit exposure, excluding credit exposure from RTOs, ISOs, registered commodity exchanges and certain long-term agreements, was $1.6 billion, of which the Company held collateral (cash and letters of credit) against those positions of $426 million resulting in a net exposure of $1.2 billion. NRG periodically receives collateral from counterparties in excess of their exposure. Collateral amounts shown include such excess while net exposure shown excludes excess collateral received. Approximately 63% of the Company's exposure before collateral is expected to roll off by the end of 2025. The following table highlights the 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, NPNS, and non-derivative transactions. As of December 31, 2023, the aggregate credit exposure is shown net of collateral held, and includes amounts net of receivables or payables.
| | | | | |
| Category | Net Exposure (a) (b) (% of Total) |
| Utilities, energy merchants, marketers and other | 80 | % |
| Financial institutions | 20 | |
| |
| |
| Total | 100 | % |
| | | | | |
| Category | Net Exposure (a) (b) (% of Total) |
| Investment grade | 44 | % |
| Non-Investment grade/Non-Rated | 56 | |
| |
| Total | 100 | % |
(a)Counterparty credit exposure excludes coal transportation contracts because of the unavailability of market prices
(b)The figures in the tables above exclude potential counterparty credit exposure related to RTOs, ISOs, registered commodity exchanges and certain long-term contracts
The Company has exposure to one wholesale counterparty in excess of 10% of the total net exposure discussed above as of December 31, 2023. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration.
RTOs and ISOs
The Company participates in the organized markets of CAISO, ERCOT, AESO, IESO, ISO-NE, MISO, NYISO and PJM, known as RTOs or ISOs. Trading in the majority of these markets is approved by FERC, whereas in the case of ERCOT, it is approved by the PUCT, and whereas in the case of AESO and IESO, both exist provincially with AESO primarily subject to Alberta Utilities Commission and the IESO subject 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 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 December 31, 2023, aggregate credit risk exposure managed by NRG to these counterparties was approximately $882 million for the next five years.
Retail Customer Credit Risk
NRG is exposed to retail credit risk through the Company's retail electricity and gas providers as well as through Vivint Smart Home. Retail credit risk results in losses when a customer fails to pay for services rendered. The losses may result from both nonpayment 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 December 31, 2023, the Company's retail customer credit exposure to Home and Business customers was diversified across many customers and various industries, as well as government entities. Current economic conditions may affect the Company's customers' ability to pay bills in a timely manner, which could increase customer delinquencies and may lead to an increase in credit losses. The Company's provision for credit losses resulting from credit risk was $251 million, $11 million and $698 million for the years ended December 31, 2023, 2022 and 2021, respectively. During the year ended December 31, 2022, the provision for credit losses included the Company's loss mitigation efforts recognized as income of $126 million related to Winter Storm Uri. During the year ended December 31, 2021, the provision for credit losses included $596 million of expenses due to the impacts of Winter Storm Uri.
Liquidity Risk
Liquidity risk arises from the general funding needs of the Company's activities and 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 December 31, 2023, a $0.50 per MMBtu decrease in natural gas prices across the term of the marginable contracts would cause an increase in margin collateral posted of approximately $1.5 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 $350 million. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of December 31, 2023.
Interest Rate Risk
NRG is exposed to fluctuations in interest rates through its issuance of variable rate debt. Exposures to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, caps, collars and put or call options. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt obligations when taking into account the combinations 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. 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, in the first quarter of 2023, the Company had entered into interest rate swaps to hedge the floating rate on the Revolving Credit Facility extending through 2024, which was fully terminated in conjunction with the pay down of the Revolving Credit Facility.
As of December 31, 2023, the Company's debt fair value was $10.6 billion and carrying value was $10.8 billion. NRG estimates that a 1% decrease in market interest rates would have increased the fair value of the Company's long-term debt by $602 million.
Currency Exchange Risk
NRG is subject to transactional exchange rate risk from transactions with customers in countries outside of the U.S., primarily within Canada, as well as from intercompany transactions between affiliates. Transactional exchange rate risk arises from the purchase and sale of goods and services in currencies other than the Company's functional currency or the functional currency of an applicable subsidiary. NRG hedges a portion of its forecasted currency transactions with foreign exchange forward contracts. As of December 31, 2023, NRG is exposed to changes in foreign currency primarily associated with the purchase of U.S. dollar denominated natural gas for its Canadian business and entered into foreign exchange contracts with a notional amount of $548 million.
The Company is subject to translation exchange rate risk related to the translation of the financial statements of its foreign operations into U.S. dollars. Costs incurred and sales recorded by subsidiaries operating outside of the U.S. are translated into U.S. dollars using exchange rates effective during the respective period. As a result, the Company is exposed to movements in the exchange rates of various currencies against the U.S. dollar, primarily the Canadian and Australian dollars. A hypothetical 10% appreciation in major currencies relative to the U.S. dollar as of December 31, 2023, would have resulted in a decrease of $36 million to net income within the Consolidated Statement of Operations.
Item 8 — Financial Statements and Supplementary Data
The financial statements and schedules are included in Part IV, Item 15 of this Form 10-K.
Item 9 — Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
Item 9A — Controls and Procedures
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures and Internal Control Over Financial Reporting
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 Annual Report on Form 10-K. Management's report on the Company's internal control over financial reporting and the report of the Company's independent registered public accounting firm are incorporated under the caption "Management's Report on Internal Control over Financial Reporting" and under the caption "Report of Independent Registered Public Accounting Firm" in this Annual Report on Form 10-K for the fiscal year ended December 31, 2023.
Changes in Internal Control over Financial Reporting
During the year ended December 31, 2023, the Company completed its acquisition of Vivint Smart Home, Inc. As part of integration, the Company designed and implemented a control structure over Vivint Smart Home's operations. Other than the Vivint Smart Home acquisition, there were no changes in NRG’s internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred in the fourth quarter of 2023 that materially affected, or are reasonably likely to materially affect, NRG’s internal control over financial reporting.
Inherent Limitations over Internal Controls
NRG's internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with GAAP. The Company's internal control over financial reporting includes those policies and procedures that:
1.Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the Company's assets;
2.Provide reasonable assurance that transactions are recorded as necessary to permit preparation of consolidated financial statements in accordance with GAAP, and that the Company's receipts and expenditures are being made only in accordance with authorizations of its management and directors; and
3.Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the consolidated financial statements.
Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations, including the possibility of human error and circumvention by collusion or overriding of controls. Accordingly, even an effective internal control system may not prevent or detect material misstatements on a timely basis. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
Management's Report on Internal Control over Financial Reporting
The Company's management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of the Company's management, including its principal executive officer, principal financial officer and principal accounting officer, the Company conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Company's evaluation under the framework in Internal Control — Integrated Framework (2013), the Company's management concluded that its internal control over financial reporting was effective as of December 31, 2023.
On March 10, 2023, NRG acquired Vivint Smart Home, Inc., and management excluded from its assessment of the effectiveness of the Company's internal control over financial reporting as of December 31, 2023, Vivint Smart Home, Inc.'s internal control over financial reporting associated with total assets (excluding acquired goodwill and intangible assets) of 5% and total revenues of 5% included in the consolidated financial statements of the Company as of and for the year ended December 31, 2023.
The effectiveness of the Company's internal control over financial reporting as of December 31, 2023 has been audited by KPMG LLP, the Company's independent registered public accounting firm, as stated in its report which is included in this Annual Report on Form 10-K.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
NRG Energy, Inc.:
Opinion on Internal Control Over Financial Reporting
We have audited NRG Energy, Inc. and subsidiaries' (the Company) internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2023 and 2022, the related consolidated statements of operations, comprehensive (loss)/income, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2023, and the related notes and financial statement schedule II (collectively, the consolidated financial statements), and our report dated February 28, 2024 expressed an unqualified opinion on those consolidated financial statements.
The Company acquired Vivint Smart Home, Inc. during 2023, and management excluded from its assessment of the effectiveness of the Company's internal control over financial reporting as of December 31, 2023, Vivint Smart Home, Inc.'s internal control over financial reporting associated with total assets (excluding acquired goodwill and intangible assets) of 5% and total revenues of 5% included in the consolidated financial statements of the Company as of and for the year ended December 31, 2023. Our audit of internal control over financial reporting of the Company also excluded an evaluation of the internal control over financial reporting of Vivint Smart Home, Inc.
Basis for Opinion
The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ KPMG LLP
Philadelphia, Pennsylvania
February 28, 2024
Item 9B — Other Information
Director and Officer Trading Arrangements
During the three months ended December 31, 2023, the following directors or officers of the Company adopted or terminated a 'Rule 10b5-1 trading arrangement' or 'non-Rule 10b5-1 trading arrangement,' as each term is defined in Item 408(a) of Regulation S-K, as described in the table below:
| | | | | | | | | | | | | | | | | | | | |
| Name | Title | Date Adopted | Character of Trading Arrangement | Aggregate Number of Shares of Common Stock to be Purchased or Sold Pursuant to Trading Arrangement(a) | Duration | Date Terminated |
| Elizabeth Killinger | Executive Vice President | 12/15/2023 | Rule 10b5-1 Trading Arrangement | 65,583 shares to be Sold(b) | 3/15/2024-1/31/2025 | N/A |
| Rasesh Patel | Executive Vice President, Smart Home | 12/15/2023 | Rule 10b5-1 Trading Arrangement | Up to 73,638 shares to be Sold | 3/14/2024-11/01/2024 | N/A |
(a)Potential sales may be subject to certain price limitations set forth in the 10b5-1 plans and therefore actual number of shares sold could vary if certain minimum stock prices are not met
(b)Represents approximate number of shares to be sold based on outstanding awards expected to vest during the period, where any underlying performance share awards are being calculated at target. Actual number of shares to be sold will depend on actual vesting, the number of shares withheld by NRG to satisfy tax withholding obligations and vesting of dividend equivalent rights
Item 9C — Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable.
PART III
Item 10 — Directors, Executive Officers and Corporate Governance
Directors and Executive Officers
Information required by this Item is incorporated by reference to the similarly named section of NRG's Definitive Proxy Statement for its 2024 Annual Meeting of Stockholders.
Code of Ethics
NRG has adopted a code of ethics entitled "NRG Code of Conduct" that applies to directors, officers and employees, including the chief executive officer and senior financial officers of NRG. It may be accessed through the "Governance" section of the Company's website at www.nrg.com. NRG also elects to disclose the information required by Form 8-K, Item 5.05, "Amendments to the Registrant's Code of Ethics, or Waiver of a Provision of the Code of Ethics," through the Company's website, and such information will remain available on this website for at least a 12-month period. A copy of the "NRG Code of Conduct" is available in print to any stockholder who requests it.
Other information required by this Item is incorporated by reference to the similarly named section of NRG's Definitive Proxy Statement for its 2024 Annual Meeting of Stockholders.
Item 11 — Executive Compensation
Information required by this Item is incorporated by reference to the similarly named section of NRG's Definitive Proxy Statement for its 2024 Annual Meeting of Stockholders.
Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Securities Authorized for Issuance under Equity Compensation Plans
| | | | | | | | | | | | | | | | | | | | |
| Plan Category | (a)
Number of Securities
to be Issued Upon
Exercise of
Outstanding Options,
Warrants and Rights | | (b)
Weighted-Average Exercise
Price of Outstanding
Options, Warrants and
Rights | | (c)
Number of Securities
Remaining Available
for Future Issuance
Under Equity Compensation
Plans (Excluding
Securities Reflected
in Column (a)) | |
| Equity compensation plans approved by security holders | 2,997,640 | | (1) | $ | — | | | 14,419,264 | | |
| Equity compensation plans not approved by security holders | 3,970,872 | | (2) | $ | — | | | 12,749,736 | | |
| Total | 6,968,512 | | | $ | — | | | 27,169,000 | | (3) |
(1)Consists of shares issuable under the NRG LTIP and the ESPP. On April 27, 2023, NRG stockholders approved an increase of 4,400,000 shares available for issuance under the ESPP. As of December 31, 2023, there were 6,702,125 shares reserved from the Company's treasury shares for the ESPP
(2)Consists of shares issuable under the Vivint LTIP. On March 10, 2023, in connection with the Acquisition, NRG assumed the Vivint Smart Home, Inc. 2020 Omnibus Incentive Plan. While the Vivint Smart Home, Inc. 2020 Omnibus Incentive Plan was previously approved by stockholders of Vivint Smart Home, Inc., the plan is listed as "not approved" because it was assumed as part of the Acquisition and not subject to approval by NRG stockholders. The Company intends to make subsequent grants under the Vivint LTIP. See Note 21, Stock-Based Compensation for a discussion of the Vivint LTIP
(3)Consists of 7,717,139 shares of common stock under the NRG LTIP, 12,749,736 shares of common stock under the Vivint LTIP and 6,702,125 shares of treasury stock reserved for issuance under the ESPP
The NRG LTIP currently provides for grants of restricted stock units, relative performance stock units, deferred stock units and dividend equivalent rights. The Vivint LTIP currently provides for grants of restricted stock units and performance stock units. The Company's directors, officers and employees, as well as other individuals performing services for, or to whom an offer of employment has been extended by the Company, are eligible to receive grants under the LTIPs. The purpose of the LTIPs is to promote the Company's long-term growth and profitability by providing these individuals with incentives to maximize stockholder value and otherwise contribute to the Company's success and to enable the Company to attract, retain and reward the best available persons for positions of responsibility. The Compensation Committee of the Board of Directors administers the LTIPs.
Other information required by this Item is incorporated by reference to the similarly named section of NRG's Definitive Proxy Statement for its 2024 Annual Meeting of Stockholders.
Item 13 — Certain Relationships and Related Transactions, and Director Independence
Information required by this Item is incorporated by reference to the similarly named section of NRG's Definitive Proxy Statement for its 2024 Annual Meeting of Stockholders.
Item 14 — Principal Accounting Fees and Services
Information required by this Item is incorporated by reference to the similarly named section of NRG's Definitive Proxy Statement for its 2024 Annual Meeting of Stockholders.
PART IV
Item 15 — Exhibits, Financial Statement Schedules
(a)(1) Financial Statements
The following consolidated financial statements of NRG Energy, Inc. and related notes thereto, together with the reports thereon of KPMG LLP, Philadelphia, PA, Auditor Firm ID: 185, are included herein:
Consolidated Statements of Operations — Years ended December 31, 2023, 2022, and 2021
Consolidated Statements of Comprehensive (Loss)/Income — Years ended December 31, 2023, 2022, and 2021
Consolidated Balance Sheets — As of December 31, 2023 and 2022
Consolidated Statements of Cash Flows — Years ended December 31, 2023, 2022, and 2021
Consolidated Statements of Stockholders' Equity — Years ended December 31, 2023, 2022, and 2021
Notes to Consolidated Financial Statements
(a)(2) Financial Statement Schedule
The following Consolidated Financial Statement Schedule of NRG Energy, Inc. is filed as part of Item 15 of this report and should be read in conjunction with the Consolidated Financial Statements.
Schedule II — Valuation and Qualifying Accounts
All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions or are inapplicable, and therefore, have been omitted.
(a)(3) Exhibits: See Exhibit Index submitted as a separate section of this report.
(b) Exhibits
See Exhibit Index submitted as a separate section of this report.
(c) Not applicable
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
NRG Energy, Inc.:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of NRG Energy, Inc. and subsidiaries (the Company) as of December 31, 2023 and 2022, the related consolidated statements of operations, comprehensive (loss)/income, stockholders' equity, and cash flows for each of the years in the three-year period ended December 31, 2023, and the related notes and financial statement schedule II (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2023, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 28, 2024 expressed an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Evaluation of the sufficiency of audit evidence over revenues
As discussed in Note 3 to the consolidated financial statements, the Company had $28,823 million of revenues. Revenue is derived from various revenue streams in different geographic markets and the Company’s processes and related information technology (IT) systems used to record revenue differ for each of these revenue streams.
We identified the evaluation of the sufficiency of audit evidence over revenues as a critical audit matter which required a high degree of auditor judgment due to the number of revenue streams and IT systems involved in the revenue recognition process. This included determining the revenue streams over which procedures were to be performed and evaluating the nature and extent of evidence obtained over the individual revenue streams as well as revenue in the aggregate. It also included the involvement of IT professionals with specialized skills and knowledge to assist in the performance of certain procedures.
The following are the primary procedures we performed to address this critical audit matter. We, with the assistance of IT professionals, applied auditor judgment to determine the revenue streams over which procedures were performed as well as the nature and extent of such procedures. For certain revenue streams over which procedures were performed,
we evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s revenue recognition processes. For certain revenue streams, we involved IT professionals, who assisted in testing certain IT applications used by the Company in its revenue recognition processes. In addition, we assessed recorded revenue for a selection of transactions by comparing the amounts recognized to underlying documentation, including contracts with customers, and for certain revenue streams, we performed a software-assisted data analysis to assess certain relationships among revenue transactions. In addition, we evaluated the sufficiency of audit evidence obtained over revenues by assessing the results of procedures performed, including the appropriateness of such evidence.
Fair value of certain acquired intangible assets
As discussed in Note 4 to the consolidated financial statements, the Company acquired Vivint Smart Home, Inc. on March 10, 2023 for total consideration of $2,623 million. In connection with the business combination, the Company recorded various intangible assets, which included customer relationships and technology intangible assets with an acquisition-date fair value of $1,740 million and $860 million, respectively.
We identified the evaluation of the acquisition-date fair value of the customer relationships and technology intangible assets as a critical audit matter. A high degree of subjective and complex auditor judgment was required to evaluate key assumptions used to value these acquired intangible assets. We performed sensitivity analyses to determine the key assumptions used to value the intangible assets acquired which required challenging auditor judgment. Specifically, key assumptions included the customer attrition for the customer relationships intangible asset and the discount rate for the customer relationships and technology intangible assets. Changes to these assumptions could have had a significant impact on the fair value of such assets. In addition, valuation professionals with specialized skills and knowledge were needed to assist in the evaluation of the discount rate.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the Company’s acquisition-date valuation process, including controls related to the selection of the customer attrition used in the customer relationships intangible asset and the discount rate used in the customer relationships and technology intangible assets. We evaluated the customer attrition used by the Company by comparing it to historical attrition experienced by the acquired company and comparable company attrition. We involved valuation professionals with specialized skills and knowledge, who assisted in evaluating the discount rate by assessing the relative risk profile of the customer relationships and technology intangible assets compared to the required rate of return of all acquired assets in the business combination.
/s/ KPMG LLP
We have served as the Company's auditor since 2004.
Philadelphia, Pennsylvania
February 28, 2024
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS | | | | | | | | | | | | | | | | | |
| | For the Year Ended December 31, |
| (In millions, except per share amounts) | 2023 | | 2022 | | 2021 |
| Revenue | | | | | |
| Revenue | $ | 28,823 | | | $ | 31,543 | | | $ | 26,989 | |
| Operating Costs and Expenses | | | | | |
| Cost of operations (excluding depreciation and amortization shown below) | 26,526 | | | 27,446 | | | 20,482 | |
| Depreciation and amortization | 1,127 | | | 634 | | | 785 | |
| Impairment losses | 26 | | | 206 | | | 544 | |
| Selling, general and administrative costs | 1,968 | | | 1,228 | | | 1,293 | |
| Provision for credit losses | 251 | | | 11 | | | 698 | |
| Acquisition-related transaction and integration costs | 119 | | | 52 | | | 93 | |
| Total operating costs and expenses | 30,017 | | | 29,577 | | | 23,895 | |
| | | | | |
| Gain on sale of assets | 1,578 | | | 52 | | | 247 | |
| Operating Income | 384 | | | 2,018 | | | 3,341 | |
| Other Income/(Expense) | | | | | |
| Equity in earnings of unconsolidated affiliates | 16 | | | 6 | | | 17 | |
| Impairment losses on investments | (102) | | | — | | | — | |
| Other income, net | 47 | | | 56 | | | 63 | |
| | | | | |
| Gain/(Loss) on debt extinguishment | 109 | | | — | | | (77) | |
| Interest expense | (667) | | | (417) | | | (485) | |
| Total other expense | (597) | | | (355) | | | (482) | |
| (Loss)/Income Before Income Taxes | (213) | | | 1,663 | | | 2,859 | |
| Income tax (benefit)/expense | (11) | | | 442 | | | 672 | |
| | | | | |
| | | | | |
| Net (Loss)/Income | (202) | | | 1,221 | | | 2,187 | |
| Less: Cumulative dividends attributable to Series A Preferred Stock | 54 | | | — | | | — | |
| Net (Loss)/Income Available for Common Stockholders | $ | (256) | | | $ | 1,221 | | | $ | 2,187 | |
| (Loss)/Income Per Share | | | | | |
| Weighted average number of common shares outstanding — basic and diluted | 228 | | | 236 | | | 245 | |
| | | | | |
| | | | | |
| (Loss)/Income per Weighted Average Common Share — Basic and Diluted | $ | (1.12) | | | $ | 5.17 | | | $ | 8.93 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
See notes to Consolidated Financial Statements
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS)/INCOME | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, |
| (In millions) | 2023 | | 2022 | | 2021 |
| Net (Loss)/Income | $ | (202) | | | $ | 1,221 | | | $ | 2,187 | |
| Other Comprehensive Income/(Loss), net of tax | | | | | |
| | | | | |
| Foreign currency translation adjustments | 9 | | | (35) | | | (5) | |
| | | | | |
| Defined benefit plans | 30 | | | (16) | | | 85 | |
| Other comprehensive income/(loss) | 39 | | | (51) | | | 80 | |
| Comprehensive (Loss)/Income | $ | (163) | | | $ | 1,170 | | | $ | 2,267 | |
| | | | | |
| | | | | |
See notes to Consolidated Financial Statements
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS | | | | | | | | | | | |
| | As of December 31, |
| (In millions) | 2023 | | 2022 |
| ASSETS | | | |
| Current Assets | | | |
| Cash and cash equivalents | $ | 541 | | | $ | 430 | |
| Funds deposited by counterparties | 84 | | | 1,708 | |
| Restricted cash | 24 | | | 40 | |
| Accounts receivable, net | 3,542 | | | 4,773 | |
| | | |
| Inventory | 607 | | | 751 | |
| Derivative instruments | 3,862 | | | 7,886 | |
| Cash collateral paid in support of energy risk management activities | 441 | | | 260 | |
| | | |
| Prepayments and other current assets | 626 | | | 383 | |
| | | |
| | | |
| Total current assets | 9,727 | | | 16,231 | |
| Property, plant and equipment, net | 1,763 | | | 1,692 | |
| Other Assets | | | |
| Equity investments in affiliates | 42 | | | 133 | |
| Operating lease right-of-use assets, net | 179 | | | 225 | |
| | | |
| Goodwill | 5,079 | | | 1,650 | |
| Customer relationships, net | 2,164 | | | 943 | |
| Other intangible assets, net | 1,763 | | | 1,189 | |
| Nuclear decommissioning trust fund | — | | | 838 | |
| Derivative instruments | 2,293 | | | 4,108 | |
| Deferred income taxes | 2,251 | | | 1,881 | |
| Other non-current assets | 777 | | | 256 | |
| | | |
| | | |
| Total other assets | 14,548 | | | 11,223 | |
| Total Assets | $ | 26,038 | | | $ | 29,146 | |
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Continued) | | | | | | | | | | | |
| | As of December 31, |
| (In millions, except share data) | 2023 | | 2022 |
| LIABILITIES AND STOCKHOLDERS' EQUITY | | | |
| Current Liabilities | | | |
| Current portion of long-term debt and finance leases | $ | 620 | | | $ | 63 | |
| Current portion of operating lease liabilities | 90 | | | 83 | |
| Accounts payable | 2,325 | | | 3,643 | |
| | | |
| Derivative instruments | 4,019 | | | 6,195 | |
| Cash collateral received in support of energy risk management activities | 84 | | | 1,708 | |
| Deferred revenue current | 720 | | | 176 | |
| Accrued expenses and other current liabilities | 1,642 | | | 1,114 | |
| | | |
| | | |
| | | |
| Total current liabilities | 9,500 | | | 12,982 | |
| Other Liabilities | | | |
| Long-term debt and finance leases | 10,133 | | | 7,976 | |
| Non-current operating lease liabilities | 128 | | | 180 | |
| Nuclear decommissioning reserve | — | | | 340 | |
| Nuclear decommissioning trust liability | — | | | 477 | |
| | | |
| Derivative instruments | 1,488 | | | 2,246 | |
| Deferred income taxes | 22 | | | 134 | |
| Deferred revenue non-current | 914 | | | 10 | |
| Other non-current liabilities | 947 | | | 973 | |
| | | |
| | | |
| Total other liabilities | 13,632 | | | 12,336 | |
| Total Liabilities | 23,132 | | | 25,318 | |
| | | |
| Commitments and Contingencies | | | |
| Stockholders' Equity | | | |
| Preferred stock; 10,000,000 shares authorized; 650,000 Series A shares issued and outstanding at December 31, 2023 (aggregate liquidation preference $650); 0 shares issued and outstanding at December 31, 2022 | 650 | | | — | |
| Common stock; $0.01 par value; 500,000,000 shares authorized; 267,330,470 and 423,897,001 shares issued; and 208,130,950 and 229,561,030 shares outstanding at December 31, 2023 and 2022, respectively | 3 | | | 4 | |
| Additional paid-in capital | 3,416 | | | 8,457 | |
| Retained earnings | 820 | | | 1,408 | |
| Treasury stock, at cost; 59,199,520 and 194,335,971 shares at December 31, 2023 and 2022, respectively | (1,892) | | | (5,864) | |
| Accumulated other comprehensive loss | (91) | | | (177) | |
| Total Stockholders' Equity | 2,906 | | | 3,828 | |
| Total Liabilities and Stockholders' Equity | $ | 26,038 | | | $ | 29,146 | |
See notes to Consolidated Financial Statements
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS | | | | | | | | | | | | | | | | | |
| | For the Year Ended December 31, |
| (In millions) | 2023 | | 2022 | | 2021 |
| Cash Flows from Operating Activities | | | | | |
| Net (loss)/income | $ | (202) | | | $ | 1,221 | | | $ | 2,187 | |
| | | | | |
| | | | | |
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| Equity in and distributions from (earnings)/losses of unconsolidated affiliates | (6) | | | 7 | | | 20 | |
| Depreciation and amortization | 1,127 | | | 634 | | | 785 | |
| Accretion of asset retirement obligations | 27 | | | 55 | | | 30 | |
| Provision for credit losses | 251 | | | 11 | | | 698 | |
| Amortization of nuclear fuel | 47 | | | 54 | | | 51 | |
| Amortization of financing costs and debt discounts | 52 | | | 23 | | | 39 | |
| (Gain)/Loss on debt extinguishment | (109) | | | — | | | 77 | |
| Amortization of in-the-money contracts and emissions allowances | 137 | | | 158 | | | 106 | |
| Amortization of unearned equity compensation | 101 | | | 28 | | | 21 | |
| Net gain on sale of assets and disposal of assets | (1,559) | | | (102) | | | (261) | |
| | | | | |
| Impairment losses | 128 | | | 206 | | | 544 | |
| Changes in derivative instruments | 2,455 | | | (3,221) | | | (3,626) | |
| Changes in deferred income taxes and liability for uncertain tax benefits | (92) | | | 382 | | | 604 | |
| | | | | |
| Changes in collateral deposits in support of risk management activities | (1,806) | | | 896 | | | 797 | |
| | | | | |
| Changes in nuclear decommissioning trust liability | — | | | 9 | | | 40 | |
| | | | | |
| Uplift securitization proceeds received/(receivable) from ERCOT | — | | | 689 | | | (689) | |
| | | | | |
| | | | | |
| Cash (used)/provided by changes in other working capital, net of acquisition and disposition effects: | | | | | |
| Accounts receivable - trade | 840 | | | (1,560) | | | (1,232) | |
| Inventory | 189 | | | (252) | | | (61) | |
| Prepayments and other current assets | (233) | | | 17 | | | 31 | |
| Accounts payable | (1,455) | | | 1,295 | | | 476 | |
| Accrued expenses and other current liabilities | 360 | | | (29) | | | (55) | |
| Other assets and liabilities | (473) | | | (161) | | | (89) | |
| Cash (used)/provided by operating activities | $ | (221) | | | $ | 360 | | | $ | 493 | |
| | | | | |
| | | | | |
| Cash Flows from Investing Activities | | | | | |
| Payments for acquisitions of businesses and assets, net of cash acquired | $ | (2,523) | | | $ | (62) | | | $ | (3,559) | |
| Capital expenditures | (598) | | | (367) | | | (269) | |
| | | | | |
| | | | | |
| Net purchases of emissions allowances | (24) | | | (6) | | | — | |
| Investments in nuclear decommissioning trust fund securities | (367) | | | (454) | | | (751) | |
| Proceeds from sales of nuclear decommissioning trust fund securities | 355 | | | 448 | | | 710 | |
| Proceeds from sale of assets, net of cash disposed | 2,007 | | | 109 | | | 830 | |
| Proceeds from insurance recoveries for property, plant and equipment, net | 240 | | | — | | | — | |
| | | | | |
| | | | | |
| | | | | |
| Cash used by investing activities | $ | (910) | | | $ | (332) | | | $ | (3,039) | |
| | | | | |
| | | | | |
| | | | | |
| | | | | | | | | | | | | | | | | |
| | For the Year Ended December 31, |
| (In millions) | 2023 | | 2022 | | 2021 |
| Cash Flows from Financing Activities | | | | | |
| Proceeds from issuance of preferred stock, net of fees | $ | 635 | | | $ | — | | | $ | — | |
| Net receipts from settlement of acquired derivatives that include financing elements | 342 | | | 1,995 | | | 938 | |
Payments for share repurchase activity(a) | (1,172) | | | (606) | | | (48) | |
| Payments of dividends to preferred and common stockholders | (381) | | | (332) | | | (319) | |
| Proceeds from issuance of long-term debt | 731 | | | — | | | 1,100 | |
| Payments for short and long-term debt | (523) | | | (5) | | | (1,861) | |
| | | | | |
| Payments for debt extinguishment costs | — | | | — | | | (65) | |
| Payments of debt issuance costs | (32) | | | (9) | | | (18) | |
| Proceeds from issuance of common stock | — | | | — | | | 1 | |
| Proceeds from credit facilities | 3,020 | | | — | | | 1,415 | |
| Repayments to credit facilities | (3,020) | | | — | | | (1,415) | |
| | | | | |
| | | | | |
| Cash (used)/provided by financing activities | $ | (400) | | | $ | 1,043 | | | $ | (272) | |
| | | | | |
| | | | | |
| Effect of exchange rate changes on cash and cash equivalents | 2 | | | (3) | | | (2) | |
| | | | | |
| Net (Decrease)/Increase in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash | (1,529) | | | 1,068 | | | (2,820) | |
| Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period | 2,178 | | | 1,110 | | | 3,930 | |
| Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period | $ | 649 | | | $ | 2,178 | | | $ | 1,110 | |
(a)Includes $(22) million, $(6) million and $(9) million of equivalent shares purchased in lieu of tax withholdings on equity compensation issuances for the years ended December 31, 2023, 2022 and 2021, respectively
For further discussion of supplemental cash flow information see Note 26, Cash Flow Information
See notes to Consolidated Financial Statements
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Preferred Stock | | Common
Stock | | Additional
Paid-In
Capital | | (Accumulated Deficit)/Retained Earnings | | Treasury
Stock | | Accumulated
Other
Comprehensive
Loss | | Total
Stock-holders'
Equity |
| | | | | | | | | | | | | |
| Balance at December 31, 2020 | $ | — | | | $ | 4 | | | $ | 8,517 | | | $ | (1,403) | | | $ | (5,232) | | | $ | (206) | | | $ | 1,680 | |
| Net income | | | | | | | 2,187 | | | | | | | 2,187 | |
| Other comprehensive income | | | | | | | | | | | 80 | | | 80 | |
| | | | | | | | | | | | | |
| Shares reissuance for ESPP | | | | | 1 | | | | | 3 | | | | | 4 | |
| Share repurchases | | | | | | | | | (44) | | | | | (44) | |
Equity-based awards activity, net(a) | | | | | 12 | | | | | | | | | 12 | |
| Issuance of common stock | | | | | 1 | | | | | | | | | 1 | |
Common stock dividends and dividend equivalents declared(b) | | | | | | | (320) | | | | | | | (320) | |
| Balance at December 31, 2021 | $ | — | | | $ | 4 | | | $ | 8,531 | | | $ | 464 | | | $ | (5,273) | | | $ | (126) | | | $ | 3,600 | |
| Net income | | | | | | | 1,221 | | | | | | | 1,221 | |
| Other comprehensive loss | | | | | | | | | | | (51) | | | (51) | |
| | | | | | | | | | | | | |
| Shares reissuance for ESPP | | | | | 2 | | | | | 4 | | | | | 6 | |
| Share repurchases | | | | | | | | | (595) | | | | | (595) | |
Equity-based awards activity, net(a) | | | | | 24 | | | | | | | | | 24 | |
| | | | | | | | | | | | | |
Common stock dividends and dividend equivalents declared(b) | | | | | | | (334) | | | | | | | (334) | |
Adoption of ASU 2020-06 | | | | | $ | (100) | | | 57 | | | | | | | (43) | |
| Balance at December 31, 2022 | $ | — | | | $ | 4 | | | $ | 8,457 | | | $ | 1,408 | | | $ | (5,864) | | | $ | (177) | | | $ | 3,828 | |
| Net loss | | | | | | | (202) | | | | | | | (202) | |
| Issuance of Series A Preferred Stock | 650 | | | | | (15) | | | | | | | | | 635 | |
| Other comprehensive income | | | | | | | | | | | 39 | | | 39 | |
| Shares reissuance for ESPP | | | | | 2 | | | | | 6 | | | | | 8 | |
Share repurchases(c) | | | | | (117) | | | | | (1,043) | | | | | (1,160) | |
| Retirement of treasury stock | | | (1) | | | (5,008) | | | | | 5,009 | | | | | — | |
Equity-based awards activity, net(a) | | | | | 97 | | | | | | | | | 97 | |
Common stock dividends and dividend equivalents declared(b) | | | | | | | (352) | | | | | | | (352) | |
Series A Preferred Stock dividends(d) | | | | | | | (34) | | | | | | | (34) | |
| Sale of the 44% equity interest in STP | | | | | | | | | | | 47 | | | 47 | |
| Balance at December 31, 2023 | $ | 650 | | | $ | 3 | | | $ | 3,416 | | | $ | 820 | | | $ | (1,892) | | | $ | (91) | | | $ | 2,906 | |
(a)Includes $(22) million, $(6) million and $(9) million of equivalent shares purchased in lieu of tax withholding on equity compensation issuances for the years ended December 31, 2023, 2022 and 2021, respectively
(b)Dividends per common share were $1.51, $1.40 and $1.30 for each of the years ended December 31, 2023, 2022 and 2021, respectively
(c)Includes excise tax accrued of $10 million as of December 31, 2023
(d)Dividend per Series A Preferred Stock was $52.96
See notes to Consolidated Financial Statements
NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 — Nature of Business
General
NRG Energy, Inc., or NRG or the Company, sits at the intersection of energy and home services. NRG is a leading energy and home services company fueled by market-leading brands, proprietary technologies, and complementary sales channels. Across the United States and Canada, NRG delivers innovative, sustainable solutions, predominately under the brand names such as NRG, Reliant, Direct Energy, Green Mountain Energy and Vivint, while also advocating for competitive energy markets and customer choice. The Company has a customer base that includes approximately 8 million residential consumers in addition to commercial, industrial, and wholesale customers, supported by approximately 13 GW of generation.
The Company's business is segmented as follows:
•Texas, which includes all activity related to customer, plant and market operations in Texas, other than Cottonwood;
•East, which includes all activity related to customer, plant and market operations in the East;
•West/Services/Other, which includes the following assets and activities: (i) all activity related to customer, plant and market operations in the West and Canada, (ii) the Services businesses (iii) activity related to the Cottonwood facility and other investments;
•Vivint Smart Home; and
•Corporate activities.
Note 2 — Summary of Significant Accounting Policies
Basis of Presentation and Principles of Consolidation
The Company's consolidated financial statements have been prepared in accordance with U.S. GAAP. The ASC, established by the FASB, is the source of authoritative U.S. GAAP to be applied by nongovernmental entities. In addition, the rules and interpretative releases of the SEC under authority of federal securities laws are also sources of authoritative U.S. GAAP for SEC registrants.
The consolidated financial statements include NRG's accounts and operations and those of its subsidiaries in which the Company has a controlling interest. All significant intercompany transactions and balances have been eliminated in consolidation. The usual condition for a controlling financial interest is ownership of a majority of the voting interests of an entity. However, a controlling financial interest may also exist through arrangements that do not involve controlling voting interests. As such, NRG applies the guidance of ASC 810, Consolidations, or ASC 810, to determine when an entity that is insufficiently capitalized or not controlled through its voting interests, referred to as a VIE, should be consolidated.
The Company identified an error in the previously issued consolidated financial statements for the year ended December 31, 2021 related to the presentation of cash flows associated with certain borrowings and repayments related to the Revolving Credit Facility. The statement of cash flows for the year ended December 31, 2021 has been adjusted to present on a gross basis the borrowings from the Revolving Credit Facility of $1.4 billion and the related repayments of $1.4 billion. The change had no impact to the total cash used by financing activities for the year ended December 31, 2021. We evaluated the materiality of this error both qualitatively and quantitatively and have concluded it is immaterial to the impacted period.
Winter Storm Uri Uplift Securitization Proceeds
The Texas Legislature passed HB 4492 in May 2021 for ERCOT to mitigate exceptionally high price adders and ancillary service costs incurred by LSEs during Winter Storm Uri. HB 4492 authorized ERCOT to obtain $2.1 billion of financing to distribute to LSEs that were charged and paid to ERCOT those highly priced ancillary service and ORDPA during Winter Storm Uri.
In December 2021, ERCOT filed with the PUCT a calculation of each LSE’s share of proceeds based on the settlement methodology. The Company accounted for the proceeds by analogy to the contribution model within ASC 958-605, Not-for-Profit Entities- Revenue Recognition and the grant model within IAS 20, Accounting for Government Grants and Disclosure of Government Assistance, as a reduction to expenses in the consolidated statements of operations in the 2021 annual period for which the proceeds were intended to compensate. The Company received proceeds of $689 million from ERCOT in June 2022.
Credit Losses
In accordance with ASU No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, or ASU No. 2016-13, 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 on the consolidated balance sheet. The Company accrues an allowance for current expected credit losses based on (i) estimates of uncollectible revenues by analyzing accounts receivable aging and current and reasonable forecasts of expected economic factors including, but not limited to, unemployment rates and weather-related events, (ii) historical collections and delinquencies, and (iii) counterparty credit ratings for commercial and industrial customers. The Company writes off customer contract receivable balances against the allowance for credit losses when it is determined a receivable is uncollectible.
The following table represents the activity in the allowance for credit losses for the years ended December 31, 2023, 2022, and 2021:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| (In millions) | 2023 | | 2022 | | 2021 |
| Beginning balance | $ | 133 | | | $ | 683 | | | $ | 67 | |
| Acquired balance from Vivint Smart Home | 22 | | | — | | | — | |
| Acquired balance from Direct Energy | — | | | — | | | 112 | |
Provision for credit losses(a) | 251 | | | 11 | | | 698 | |
| Write-offs | (313) | | | (593) | | | (224) | |
| Recoveries collected | 39 | | | 32 | | | 30 | |
| Other | 13 | | | — | | | — | |
Ending balance(a) | $ | 145 | | | $ | 133 | | | $ | 683 | |
(a)Includes bilateral finance hedging risk of $(70) million and $403 million accounted for under ASC 815 for the years endedDecember 31, 2022 and December 31, 2021, respectively
During the year ended December 31, 2022, the provision for credit losses included the Company's loss mitigation efforts recognized as income of $126 million related to Winter Storm Uri. During the year ended December 31, 2021, the provision for credit losses included $596 million of expense due to the impacts of Winter Storm Uri. The increase in write-offs for the periods ended December 31, 2022 and 2021 were primarily due to the resolution of credit losses that occurred during Winter Storm Uri.
Cash and Cash Equivalents
Cash and cash equivalents include highly liquid investments with an original maturity of three months or less at the time of purchase.
Funds Deposited by Counterparties
Funds deposited by counterparties consist of cash held by the Company as a result of collateral posting obligations from its counterparties related to NRG's hedging program. The 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, not all funds are contractually restricted. Based on the Company's intention, these funds are not available for the payment of general corporate obligations; however, they are available for liquidity management. Depending on market fluctuations and the settlement of the underlying contracts, the Company will refund this collateral to the hedge counterparties pursuant to the terms and conditions of the underlying trades. Since collateral requirements fluctuate daily and the Company cannot predict if any collateral will be held for more than twelve months, the funds deposited by counterparties are classified as a current asset on the Company's balance sheet, with an offsetting liability for this cash collateral received within current liabilities.
Restricted Cash
The following table provides a reconciliation of cash and cash equivalents, restricted cash and funds deposited by counterparties reported within the consolidated balance sheets that sum to the total of the same such amounts shown in the statements of cash flows.
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| (In millions) | 2023 | | 2022 | | 2021 |
| Cash and cash equivalents | $ | 541 | | | $ | 430 | | | $ | 250 | |
| Funds deposited by counterparties | 84 | | | 1,708 | | | 845 | |
| Restricted cash | 24 | | | 40 | | | 15 | |
| Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statements of cash flows | $ | 649 | | | $ | 2,178 | | | $ | 1,110 | |
Restricted cash consists primarily of funds held to satisfy the requirements of certain financing agreements and funds held within the Company's projects that are restricted in their use.
Inventory
Inventory is valued at the lower of weighted average cost or market, and consists principally of natural gas, fuel oil, coal, spare parts and finished goods. The Company removes natural gas inventory as goods are delivered to customers and as they are used in the production of electricity or steam. The Company removes fuel oil and coal inventories as they are used in the production of electricity. The Company removes spare parts inventories when they are used for repairs, maintenance or capital projects. The Company expects to recover the natural gas, fuel oil, coal and spare parts costs in the ordinary course of business. Inventory is valued at the lower of cost or net realizable value with cost being determined on a first in first out basis for finished goods and weighted average cost method for all other inventories. The Company removes finished goods inventories as they are sold to customers. Inventories sold to customers as part of a smart home system are generally capitalized as contract costs. Sales of inventory are classified as an operating activity in the consolidated statements of cash flows.
Property, Plant and Equipment
Property, plant and equipment are stated at cost or, in the case of business acquisitions, fair value; however, impairment adjustments are recorded whenever events or changes in circumstances indicate that their carrying values may not be recoverable. Significant additions or improvements extending asset lives are capitalized as incurred, while repairs and maintenance that do not improve or extend the life of the respective asset are charged to expense as incurred. Depreciation, other than nuclear fuel, is computed using the straight-line method, while nuclear fuel was amortized based on units of production over the estimated useful lives. Certain assets and their related accumulated depreciation amounts are adjusted for asset retirements and disposals with the resulting gain or loss included in cost of operations in the consolidated statements of operations. For further discussion, see Note 9, Property, Plant and Equipment.
Business Interruption Insurance
The Company carries insurance policies to cover insurable risks including, but not limited to, business interruption. As a result of damage at the Limestone 1 and W.A. Parish 8 units, the Company recorded business interruption insurance settlements of $7 million and $81 million during the year ended December 31, 2023 and December 31, 2022, respectively. Business interruption insurance is recorded to cost of operations in the consolidated statements of operations and cash provided by operating activities in the consolidated statement of cash flows.
Asset Impairments
Long-lived assets that are held and used are reviewed for impairment whenever events or changes in circumstances indicate carrying values may not be recoverable. Such reviews are performed in accordance with ASC 360. An impairment loss is indicated if the total future estimated undiscounted cash flows expected from an asset are less than its carrying value. An impairment charge is measured by the difference between an asset's carrying amount and fair value with the difference recorded in operating costs and expenses in the consolidated statements of operations. Fair values are determined by a variety of valuation methods, including third-party appraisals, sales prices of similar assets and present value techniques.
Investments accounted for by the equity method are reviewed for impairment in accordance with ASC 323, Investments-Equity Method and Joint Ventures, or ASC 323, which requires that a loss in value of an investment that is an other-than-temporary decline should be recognized. The Company identifies and measures losses in the value of equity method investments based upon a comparison of fair value to carrying value. For further discussion of these matters, refer to Note 11, Asset Impairments.
Debt Issuance Costs
Debt issuance costs are capitalized and amortized as interest expense on a basis that approximates the effective interest method over the term of the related debt. Debt issuance costs are presented as a direct deduction from the carrying amount of the related debt, or as an asset if the issuance costs relate to revolving debt agreements or certain other financing arrangements.
Intangible Assets
Intangible assets represent contractual rights held by the Company. The Company recognizes specifically identifiable intangible assets including emissions allowances, customer and supply contracts, customer relationships, marketing partnerships, technologies, trade names and fuel contracts when specific rights and contracts are acquired. These intangible assets are amortized based on expected volumes, expected delivery, expected discounted future net cash flows, straight line or units of production basis. As of December 31, 2023 and 2022, the Company had accumulated amortization related to its intangible assets of $3.0 billion and $2.1 billion, respectively.
Emission allowances held-for-sale, which are included in other non-current assets on the Company's consolidated balance sheet, are not amortized; they are carried at the lower of cost or fair value and reviewed for impairment in accordance with ASC 360.
For further discussion, see Note 12, Goodwill and Other Intangibles.
Goodwill
In accordance with ASC 350, Intangibles-Goodwill and Other, or ASC 350, the Company recognizes goodwill for the excess cost of an acquired entity over the net value assigned to assets acquired and liabilities assumed. NRG performs goodwill impairment tests annually, during the fourth quarter, and when events or changes in circumstances indicate that the carrying value may not be recoverable.
The Company may first assesses qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. The more-likely-than-not threshold is defined as having a likelihood of more than 50 percent. If it is not more-likely-than-not that the fair value of a reporting unit is less than its carrying amount, there is no goodwill impairment.
In the absence of sufficient qualitative factors indicating that it is more-likely-than-not that no impairment occurred, the Company performs a quantitative assessment by determining the fair value of the reporting unit and comparing the fair value to its book value. If the fair value of the reporting unit exceeds its book value, goodwill of the reporting unit is not considered impaired. If the book value exceeds fair value, the Company recognizes an impairment loss equal to the difference between book value and fair value.
For further discussion of goodwill impairment losses recognized refer to Note 11, Asset Impairments.
Capitalized Contract Costs
Capitalized contract costs represent the costs directly related and incremental to the origination of new contracts, modification of existing contracts or to the fulfillment of the related subscriber contracts. These costs include installed products, commissions, other compensation and the cost of installation of new or upgraded customer contracts. The Company calculates amortization by accumulating all deferred contract costs into separate portfolios based on the initial month of service and amortizes those deferred contract costs on a straight-line basis over the expected period of benefit, consistent with the pattern in which the Company provides services to its customers. The expected period of benefit for customers is approximately five years. The Company updates its estimate of the expected period of benefit periodically and whenever events or circumstances indicate that the expected period of benefit could change significantly. Such changes, if any, are accounted for prospectively as a change in estimate. Amortization of capitalized contract costs related to fulfillment are included in cost of operations and amortization of capitalized contract costs related to customer acquisition are included in selling, general and administrative costs in the consolidated statements of operations. Contract costs not directly related and incremental to the origination of new contracts, modification of existing contracts or to the fulfillment of the related subscriber contracts are expensed as incurred.
Income Taxes
The Company accounts for income taxes using the liability method in accordance with ASC 740, Income Taxes, or ASC 740, which requires that the Company use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences.
The Company has two categories of income tax expense or benefit — current and deferred, as follows:
•Current income tax expense or benefit consists solely of current taxes payable less applicable tax credits, and
•Deferred income tax expense or benefit is the change in the net deferred income tax asset or liability, excluding amounts charged or credited to accumulated other comprehensive income
The Company reports some of its revenues and expenses differently for financial statement purposes than for income tax return purposes, resulting in temporary and permanent differences between the Company's financial statements and income tax returns. The tax effects of such temporary differences are recorded as either deferred income tax assets or deferred income tax liabilities in the Company's consolidated balance sheets. The Company measures its deferred income tax assets and deferred income tax liabilities using income tax rates that are expected to be in effect when the deferred tax is realized.
The Company accounts for uncertain tax positions in accordance with ASC 740, which applies to all tax positions related to income taxes. Under ASC 740, tax benefits are recognized when it is more-likely-than-not that a tax position will be sustained upon examination by the authorities. The benefit recognized from a position is the amount of benefit that has surpassed the more-likely-than-not threshold, as it is more than 50% likely to be realized upon settlement. The Company recognizes interest and penalties accrued related to uncertain tax benefits as a component of income tax expense.
In accordance with ASC 740 and as discussed further in Note 20, Income Taxes, changes to existing net deferred tax assets or valuation allowances or changes to uncertain tax benefits, are recorded to income tax (benefit)/expense.
Contract and Emission Credit Amortization
Assets and liabilities recognized through acquisitions related to the purchase and sale of energy and energy-related products in future periods for which the fair value has been determined to be significantly less or more than market are amortized to revenues or cost of operations over the term of each underlying contract based on actual generation and/or contracted volumes.
Emission credits represent the right to emit a specified amount of certain pollutants, including sulfur dioxide, nitrogen oxides and carbon dioxide, over a compliance period. Emission credits held for use are amortized to cost of operations based on the weighted average cost of the allowances held.
Gross Receipts and Sales Taxes
In connection with its retail sales, the Company records gross receipts taxes on a gross basis in revenues and cost of operations in its consolidated statements of operations. During the years ended December 31, 2023, 2022, and 2021, the Company's revenues and cost of operations included gross receipts taxes of $212 million, $218 million, and $184 million, respectively. Additionally, the Company records sales taxes collected from its taxable retail customers and remitted to the various governmental entities on a net basis; thus, there is no impact on the Company's consolidated statement of operations.
Cost of Operations
Cost of operations includes cost of fuel, purchased energy and other costs of sales, mark-to-market for economic hedging activities, contract and emission credit amortization, operations and maintenance, and other cost of operations.
Cost of Fuel, Purchased Energy and Other Cost of Sales
Cost of fuel is primarily the costs associated with procurement, transportation and storage of natural gas, nuclear fuel, oil and coal to operate the generation portfolio, which is expensed as the fuel is consumed. Purchased energy primarily relates to purchases to supply the Company's customer base, which includes spot market purchases, as well as contracts of various quantities and durations, including Renewable PPAs with third-party developers, which are primarily accounted for as NPNS (see further discussion in Derivative Instruments below). Other cost of sales primarily consists of TDSP expenses.
The cost of fuel is based on actual and estimated fuel usage for the applicable reporting period. The cost to deliver energy and related services to customers is based on actual and estimated supply volumes for the applicable reporting period. A portion of the cost of energy, $240 million, $202 million, and $189 million as of December 31, 2023, 2022, and 2021, respectively, was accrued and consisted of estimated transmission and distribution charges not yet billed by the transmission and distribution utilities.
In estimating supply volumes, the Company considers the effects of historical customer volumes, weather factors and usage by customer class. Transmission and distribution delivery fees are estimated using the same method used for electricity sales and services to retail customers. In addition, ISO fees are estimated based on historical trends, estimated supply volumes and initial ISO settlements. Volume estimates are then multiplied by the supply rate and recorded as cost of operations in the applicable reporting period.
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 services (smart home and security). The subscriber has the ability to pay for Vivint Smart Home products in the following three ways: (i) qualified subscribers may finance the purchase through third-party financing providers ("Consumer Financing Program" or “CFP”), (ii) Vivint Smart Home generally offers a limited number of subscribers not eligible for the CFP, but who qualify under Vivint Smart Home underwriting criteria, the option to enter into a retail installment contract directly with Vivint Smart Home or (iii) subscribers may conduct purchases by check, automatic clearing house payments, credit or debit card or by obtaining short term financing (generally no more than six-month installment terms) through Vivint Smart Home.
Although subscribers pay separately for products and services under Flex Pay, the Company has determined that the sale of products and services are one single performance obligation resulting in deferred revenue for the gross amount of products sold. For products financed through the CFP, gross deferred revenues are reduced by (i) any fees the third-party financing provider (“Financing Provider”) is contractually entitled to receive at the time of loan origination, and (ii) the present value of expected future payments due to the Financing Providers. Loans are issued on either an installment or revolving basis with repayment terms ranging from 6 to 60 months.
For certain Financing Provider loans:
•Vivint Smart Home pays a monthly fee based on either the average daily outstanding balance of the installment loans, or the number of outstanding loans.
•Vivint Smart Home incurs fees at the time of the loan origination and receives proceeds that are net of these fees.
•Vivint Smart Home also shares liability for credit losses, with Vivint Smart Home being responsible for between 2.6% and 100% of lost principal balances.
Due to the nature of these provisions, the Company records a derivative liability ("CFP Derivative") 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 6, Accounting for Derivative Instruments and Hedging Activities.
Derivative Instruments
The Company accounts for derivative instruments under ASC 815, which requires the Company to record all derivatives on the balance sheet at fair value and changes in fair value in earnings, unless they qualify for the NPNS exception. The Company's primary derivative instruments are power and natural gas purchase or sales contracts, fuels purchase contracts, the CFP and other energy related commodities used to mitigate variability in earnings due to fluctuation in market prices. In order to mitigate interest rate risk associated with the issuance of the Company's variable rate debt, NRG enters into interest rate swap agreements. In addition, in order to mitigate foreign exchange risk associated with the purchase of USD denominated natural gas for the Company's Canadian business, NRG enters into foreign exchange contract agreements.
As of December 31, 2023 and 2022 the Company did not have derivative instruments that were designated as cash flow or fair value hedges.
Revenues and expenses on contracts that qualify for the NPNS exception are recognized when the underlying physical transaction is delivered. While these contracts are considered derivative instruments under ASC 815, they are not recorded at fair value, but on an accrual basis of accounting. If it is determined that a transaction designated as NPNS no longer meets the scope exception, the fair value of the related contract is recorded on the balance sheet and immediately recognized through earnings.
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 instruments are recognized in earnings.
Mark-to-Market for Economic Hedging Activities
NRG enters into derivative instruments to manage price and delivery risk, optimize physical and contractual assets in the portfolio and manage working capital requirements. The mark-to-market for economic hedging activities are recognized to revenues or cost of operations during the reporting period.
Operations and Maintenance and Other Cost of Operations
Operations and maintenance costs include major and other routine preventative (planned outage) and corrective (forced outage) maintenance activities to ensure the safe and reliable operation of the Company's generation portfolio in compliance
with all local, state and federal requirements. Operations and maintenance costs are also costs associated with retaining and maintaining the Company's customer base, such as call center support, portfolio maintenance and data analytics. Other cost of operations primarily includes gross receipts taxes, insurance, property taxes and asset retirement obligation expense.
Foreign Currency Translation and Transaction Gains and Losses
The local currencies are generally the functional currency of NRG's foreign operations. Foreign currency denominated assets and liabilities are translated at end-of-period rates of exchange. Revenues, expenses, and cash flows are translated at the weighted-average rates of exchange for the period. The resulting currency translation adjustments are not included in the Company's consolidated statements of operations for the period, but are accumulated and reported as a separate component of stockholders' equity until sale or complete or substantially complete liquidation of the net investment in the foreign entity takes place. Foreign currency transaction gains or losses are reported within other income, net in the Company's consolidated statements of operations. For the years ended December 31, 2023, 2022 and 2021, amounts recognized as foreign currency transaction gains/(losses) were immaterial. The Company's cumulative translation adjustment balances as of December 31, 2023, 2022, and 2021 were $(43) million, $(55) million, and $(8) million, respectively.
Concentrations of Credit Risk
Financial instruments that potentially subject the Company to concentrations of credit risk consist primarily of trust funds, accounts receivable, notes receivable, derivatives and investments in debt securities. Trust funds are held in accounts managed by experienced investment advisors. Certain accounts receivable, notes receivable, and derivative instruments are concentrated within entities engaged in the energy industry. These industry concentrations may impact the Company's overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. Receivables and other contractual arrangements are subject to collateral requirements under the terms of enabling agreements. However, the Company believes that the credit risk posed by industry concentration is offset by the diversification and creditworthiness of its customer base. See Note 5, Fair Value of Financial Instruments, for a further discussion of derivative concentrations.
Asset Retirement Obligations
The Company accounts for AROs in accordance with ASC 410-20, Asset Retirement Obligations, or ASC 410-20. Retirement obligations associated with long-lived assets included within the scope of ASC 410-20 are those for which a legal obligation exists under enacted laws, statutes, and written or oral contracts, including obligations arising under the doctrine of promissory estoppel, and for which the timing and/or method of settlement may be conditional on a future event. ASC 410-20 requires an entity to recognize the fair value of a liability for an ARO in the period in which it is incurred and a reasonable estimate of fair value can be made.
Upon initial recognition of a liability for an ARO, the Company capitalizes the asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount. Over time, the liability is accreted to its future value, while the capitalized cost is depreciated over the useful life of the related asset. See Note 14, Asset Retirement Obligations, for a further discussion of AROs.
Pensions and Other Postretirement Benefits
The Company offers pension benefits through a defined benefit pension plan. In addition, the Company provides postretirement health and welfare benefits for certain groups of employees. The Company accounts for pension and other postretirement benefits in accordance with ASC 715, Compensation — Retirement Benefits, or ASC 715. The Company recognizes the funded status of the Company's defined benefit plans in the statement of financial position and records an offset for gains and losses as well as all prior service costs that have not been included as part of the Company's net periodic benefit cost to other comprehensive income. The determination of the Company's obligation and expenses for pension benefits is dependent on the selection of certain assumptions. These assumptions determined by management include the discount rate, the expected rate of return on plan assets and the rate of future compensation increases. The Company's actuarial consultants assist in determining assumptions for such items as retirement age. The assumptions used may differ materially from actual results, which may result in a significant impact to the amount of pension obligation or expense recorded by the Company.
The Company measures the fair value of its pension assets in accordance with ASC 820, Fair Value Measurements and Disclosures, or ASC 820. For further discussion, see Note 15, Benefit Plans and Other Postretirement Benefits.
Stock-Based Compensation
The Company accounts for its stock-based compensation in accordance with ASC 718, Compensation — Stock Compensation, or ASC 718. The fair value of the Company's performance stock units is estimated on the date of grant using a Monte Carlo valuation model. NRG uses the Company's common stock price on the date of grant as the fair value of the Company's deferred stock units. Forfeiture rates are estimated based on an analysis of the Company's historical forfeitures, employment turnover, and expected future behavior. The Company recognizes compensation expense for both graded and cliff
vesting awards on a straight-line basis over the requisite service period for the entire award. For further discussion, see Note 21, Stock-Based Compensation.
Investments Accounted for by the Equity Method
The Company has investments in various domestic energy projects, as well as one Australian project. The equity method of accounting is applied to such investments in affiliates, which include joint ventures and partnerships, because the ownership structure prevents the Company from exercising a controlling influence over the operating and financial policies of the projects. Under this method, equity in pre-tax income or losses of domestic partnerships and, generally, in the net income or losses of its Australian project, are reflected as equity in earnings of unconsolidated affiliates. Distributions from equity method investments that represent earnings on the Company's investment are included within cash flows from operating activities and distributions from equity method investments that represent a return of the Company's investment are included within cash flows from investing activities. For further discussion, see Note 17, Investments Accounted for by the Equity Method and Variable Interest Entities.
Sale-Leaseback Arrangements
NRG is party to sale-leaseback arrangements that provide for the sale of certain assets to a third-party and simultaneously leases back the same asset to the Company. If the seller-lessee transfers control of the underlying assets to the buyer-lessor, the arrangement is accounted for under ASC 842-40, Sale-Leaseback Transactions. These arrangements are classified as operating leases on the Company's consolidated balance sheets.
Marketing and Advertising Costs
The Company expenses its marketing and advertising costs as incurred and includes them within selling, general and administrative costs. The costs of tangible assets used in advertising campaigns are recorded as fixed assets or deferred advertising costs and amortized as advertising costs over the shorter of the useful life of the asset or the advertising campaign. The Company has several long-term sponsorship arrangements. Payments related to these arrangements are deferred and expensed over the term of the arrangement. Advertising expenses for the years ended December 31, 2023, 2022, and 2021 were $185 million, $82 million, and $109 million, respectively.
Business Combinations
The Company accounts for its business combinations in accordance with ASC 805, Business Combinations, or ASC 805, which requires an acquirer to recognize and measure in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at fair value at the acquisition date. The Company also recognizes and measures the goodwill acquired or a gain from a bargain purchase in the business combination. In addition, transaction costs are expensed as incurred.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States 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.
In recording transactions and balances resulting from business operations, the Company uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, tax provisions, uncollectible accounts, actuarially determined benefit costs, the valuation of energy commodity contracts, environmental liabilities, legal costs incurred in connection with recorded loss contingencies, and assets acquired and liabilities assumed in business combinations, among others. In addition, estimates are used to test long-lived assets and goodwill for impairment and to determine the fair value of impaired assets. As better information becomes available or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.
Reclassifications
Certain prior period amounts have been reclassified for comparative purposes. The reclassifications did not affect results from operations, net assets or cash flows.
Recent Accounting Developments - Guidance Adopted in 2023
ASU 2021-08 — In October 2021, the FASB issued ASU No. 2021-08, Business Combinations (Topic 805): Accounting for Contract Assets and Contract Liabilities from Contracts with Customers, or ASU 2021-08, which requires that an entity recognize and measure contract assets and contract liabilities acquired in a business combination as if it had originated the contracts in accordance with ASC 606, Revenue from Contracts with Customers. As a result, an acquirer should recognize and measuring 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, such as refund liabilities and upfront payments to customers. Assets and liabilities under related Topics, such as deferred costs under Subtopic 340-40, Other Assets and Deferred Costs — Contracts with Customers, are not within the scope of amendments per ASU 2021-08. The Company adopted ASU 2021-08 prospectively effective January 1, 2023 and applied the amended requirements to the acquisition of Vivint Smart Home.
Recent Accounting Developments - Guidance Not Yet Adopted
ASU 2023-07 – In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280) – Improvements to Reportable Segment Disclosures, or ASU 2023-07. The guidance in ASU 2023-07 enhances reportable segment disclosure requirements by requiring disclosure of significant segment expenses that are regularly provided to the chief operating decision maker and included within each reported measure of segment profit and loss, an amount and description of its composition for other segment items and interim disclosures of a reportable segment’s profit or loss and assets. The amendments of ASU 2023-07 are effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted and should be applied retrospectively for all prior periods presented in the financial statements. The Company is currently evaluating the impact of adopting ASU 2023-07 on its disclosures.
ASU 2023-09 – In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740) – Improvements to Income Tax Disclosures, or ASU 2023-09. The guidance in ASU 2023-09 enhances income tax disclosures by requiring disclosure of specific categories in the effective tax rate reconciliation and additional information for reconciling items that meet a quantitative threshold. Further the amendments of ASU 2023-09 require certain disclosures on income tax expense and income taxes paid. ASU 2023-09 is effective for annual periods beginning after December 15, 2024, with early adoption permitted. The amendments of ASU 2023-09 may be applied on a prospective or retrospective basis. The Company is currently evaluating the impact of adopting ASU 2023-09 on its disclosures.
Note 3— Revenue Recognition
The Company's policies with respect to its various revenue streams are detailed below. The Company generally applies the invoicing practical expedient to recognize revenue for the revenue streams detailed below, except in circumstances where the invoiced amount does not represent the value transferred to the customer.
Retail Revenue
Gross revenues for energy sales and services to retail customers are recognized as the Company transfers the promised goods and services to the customer. Payment terms are generally 15 to 60 days. For the majority of its electricity and natural gas contracts, the Company’s performance obligation with the customer is satisfied over time and performance obligations for its electricity and natural gas products are recognized as the customer takes possession of the product. The Company also allocates the contract consideration to distinct performance obligations in a contract for which the timing of the revenue recognized is different. Additionally, customer discounts and incentives reduce the contract consideration and are recognized over the term of the contract.
Energy sales and services that have been delivered but not billed by period end are estimated. Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter reading provided by the independent system operators, utilities, or electric distribution companies. Volume estimates are based on daily forecasted volumes and estimated customer usage by class. Unbilled revenues are calculated by multiplying these volume estimates by the applicable rate by customer class. Estimated amounts are adjusted when actual usage is known and billed.
As contracts for retail electricity and natural gas can be for multi-year periods, the Company has performance obligations under these contracts that have not yet been satisfied. These performance obligations have transaction prices that are both fixed and variable, and that vary based on the contract duration, customer type, inception date and other contract-specific factors. For the fixed price contracts, the amount of any unsatisfied performance obligations will vary based on customer usage, which will depend on factors such as weather and customer activity and therefore it is not practicable to estimate such amounts.
Vivint Smart Home Retail Revenue
Vivint Smart Home offers its subscribers combinations of smart home products and services, which together create an integrated smart home system that allows the Company's subscribers to monitor, control and protect their homes. As the products and services included in the subscriber's contract are integrated and highly interdependent, and because the products (including installation) and services must work together to deliver the monitoring, controlling and protection of their home, the Company has concluded that the products and services contracted for by the subscriber are generally not distinct within the context of the contract and, therefore, constitute a single, combined performance obligation. Revenues for this single, combined performance obligation are recognized on a straight-line basis over the subscriber's contract term, which is the period in which the parties to the contract have enforceable rights and obligations. The Company has determined that certain contracts that do not require a long-term commitment for monitoring services by the subscriber contain a material right to renew the contract,
because the subscriber does not have to purchase the products upon renewal. Proceeds allocated to the material right are recognized over the expected period of benefit. The majority of Vivint Smart Home's subscription contracts are five years and are generally non-cancelable. These contracts generally convert into month-to-month agreements at the end of the initial term, while some subscribers are month-to-month from inception. Payment for Vivint Smart Home services is generally due in advance on a monthly basis, with payment terms up to 30 days. Product sales and other one-time fees are invoiced to subscribers at time of sale. Revenues for any products or services that are considered separate performance obligations are recognized upon delivery. Payments received or billed in advance are reported as deferred revenues.
Energy Revenue
Both physical and financial transactions consist of revenues billed to a third-party at either market or negotiated contract terms to optimize the financial performance of the Company's generating facilities. Payment terms vary from 5 to 55 days. Electric energy revenue is recognized upon transmission to the customer over time, using the output method for measuring progress of satisfaction of performance obligations. Physical transactions, or the sale of generated electricity to meet supply and demand, are recorded on a gross basis in the Company's consolidated statements of operations. The Company applies the invoicing practical expedient in recognizing energy revenue. Under the practical expedient, revenue is recognized based on the invoiced amount which is equal to the value to the customer of NRG’s performance obligation completed to date. Financial transactions used to hedge the sale of electricity are recorded net within revenues in the consolidated statements of operations in accordance with ASC 815.
Ancillary revenues, included in Other revenue, are recognized over time as the obligation is fulfilled, using the output method for measuring progress of satisfaction of performance obligations.
CapacityRevenue
The Company's largest sources of capacity revenues are capacity auctions in PJM and NYISO. Capacity revenues also include revenues billed to a third-party at either market or negotiated contract terms for making installed generation and demand response capacity available in order to satisfy system integrity and reliability requirements. Payment terms vary from 15 to 55 days. Capacity revenues are recognized over time, using the output method for measuring progress of satisfaction of performance obligations. The Company applies the invoicing practical expedient in recognizing capacity revenue. Under the practical expedient, revenue is recognized based on the invoiced amount which is equal to the value to the customer of NRG’s performance obligation completed to date.
Performance Obligations
As of December 31, 2023, estimated future fixed fee performance obligations are $1.4 billion, $1.0 billion, $756 million, $468 million and $176 million for fiscal years 2024, 2025, 2026, 2027 and 2028, respectively. These performance obligations include Vivint Smart Home products and services as well as cleared auction MWs in the PJM, NYISO and MISO capacity auctions. The cleared auction MWs are subject to penalties for non-performance.
Disaggregated Revenue
The following tables represent the Company’s disaggregation of revenue from contracts with customers for the years ended December 31, 2023, 2022, and 2021:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2023 |
| (In millions) | Texas | | East | | West/Services/Other | | Vivint Smart Home(a) | | Corporate/Eliminations | | Total |
| Retail revenue | | | | | | | | | | | |
Home(b) | $ | 6,538 | | | $ | 2,195 | | | $ | 1,890 | | | $ | 1,549 | | | $ | (1) | | | $ | 12,171 | |
| Business | 3,492 | | | 9,751 | | | 2,053 | | | — | | | — | | | 15,296 | |
Total retail revenue(b) | 10,030 | | | 11,946 | | | 3,943 | | | 1,549 | | | (1) | | | 27,467 | |
Energy revenue(c) | 77 | | | 291 | | | 185 | | | — | | | — | | | 553 | |
Capacity revenue(c) | — | | | 197 | | | 2 | | | — | | | (2) | | | 197 | |
Mark-to-market for economic hedging activities(d) | — | | | 57 | | | 103 | | | — | | | (16) | | | 144 | |
| Contract amortization | — | | | (32) | | | — | | | — | | | — | | | (32) | |
Other revenue(c) | 369 | | | 88 | | | 48 | | | — | | | (11) | | | 494 | |
| Total revenue | 10,476 | | | 12,547 | | | 4,281 | | | 1,549 | | | (30) | | | 28,823 | |
| Less: Revenues accounted for under topics other than ASC 606 and ASC 815 | — | | | 17 | | | 35 | | | — | | | — | | | 52 | |
| Less: Realized and unrealized ASC 815 revenue | 29 | | | 364 | | | 138 | | | — | | | (16) | | | 515 | |
| Total revenue from contracts with customers | $ | 10,447 | | | $ | 12,166 | | | $ | 4,108 | | | $ | 1,549 | | | $ | (14) | | | $ | 28,256 | |
| (a) Includes results of operations following the acquisition date of March 10, 2023 |
| (b) Home includes Services and Vivint Smart Home |
| (c) The following amounts of retail, energy, capacity and other revenue relate to derivative instruments and are accounted for under ASC 815: |
| (In millions) | Texas | | East | | West/Services/Other | | Vivint Smart Home | | Corporate/Eliminations | | Total |
| Retail revenue | $ | — | | | $ | 74 | | | $ | — | | | $ | — | | | $ | — | | | $ | 74 | |
| Energy revenue | — | | | 162 | | | 13 | | | — | | | 1 | | | 176 | |
| Capacity revenue | — | | | 73 | | | — | | | — | | | — | | | 73 | |
| Other revenue | 29 | | | (2) | | | 22 | | | — | | | (1) | | | 48 | |
| (d) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2022 |
| (In millions) | Texas | | East | | West/Services/Other | | | | Corporate/Eliminations | | Total |
| Retail revenue | | | | | | | | | | | |
Home(a) | $ | 6,388 | | | $ | 2,088 | | | $ | 2,286 | | | | | $ | (1) | | | $ | 10,761 | |
| Business | 3,229 | | | 13,768 | | | 1,964 | | | | | — | | | 18,961 | |
Total retail revenue(b) | 9,617 | | | 15,856 | | | 4,250 | | | | | (1) | | | 29,722 | |
Energy revenue(b) | 111 | | | 641 | | | 466 | | | | | 32 | | | 1,250 | |
Capacity revenue(b) | — | | | 232 | | | 40 | | | | | — | | | 272 | |
Mark-to-market for economic hedging activities(c) | 2 | | | (30) | | | (56) | | | | | 1 | | | (83) | |
| Contract amortization | — | | | (40) | | | 1 | | | | | — | | | (39) | |
Other revenue(b) | 327 | | | 104 | | | 5 | | | | | (15) | | | 421 | |
| Total revenue | 10,057 | | | 16,763 | | | 4,706 | | | | | 17 | | | 31,543 | |
| Less: Revenues accounted for under topics other than ASC 606 and ASC 815 | — | | | (7) | | | 41 | | | | | 1 | | | 35 | |
| Less: Realized and unrealized ASC 815 revenue | (2) | | | 84 | | | (93) | | | | | 31 | | | 20 | |
| Total revenue from contracts with customers | $ | 10,059 | | | $ | 16,686 | | | $ | 4,758 | | | | | $ | (15) | | | $ | 31,488 | |
| (a) Home includes Services |
| (b) The following amounts of energy, capacity and other revenue relate to derivative instruments and are accounted for under ASC 815: |
| (In millions) | Texas | | East | | West/Services/Other | | | | Corporate/Eliminations | | Total |
| Retail revenue | $ | — | | | $ | 110 | | | $ | — | | | | | $ | — | | | $ | 110 | |
| Energy revenue | — | | | (31) | | | (8) | | | | | 31 | | | (8) | |
| Capacity revenue | — | | | 33 | | | — | | | | | — | | | 33 | |
| Other revenue | (4) | | | 2 | | | (29) | | | | | (1) | | | (32) | |
| (c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2021 |
| (In millions) | Texas | | East | | West/Services/Other | | | | Corporate/Eliminations | | Total |
| Retail revenue | | | | | | | | | | | |
Home(a) | $ | 5,659 | | | $ | 1,832 | | | $ | 2,059 | | | | | $ | (1) | | | $ | 9,549 | |
| Business | 2,745 | | | 10,030 | | | 1,237 | | | | | — | | | 14,012 | |
| Total retail revenue | 8,404 | | | 11,862 | | | 3,296 | | | | | (1) | | | 23,561 | |
Energy revenue(c) | 329 | | | 508 | | | 371 | | | | | 7 | | | 1,215 | |
Capacity revenue(c) | — | | | 718 | | | 57 | | | | | — | | | 775 | |
Mark-to-market for economic hedging activities(d) | (3) | | | (88) | | | (86) | | | | | 13 | | | (164) | |
| Contract amortization | — | | | (26) | | | (4) | | | | | — | | | (30) | |
Other revenue(b)(c) | 1,565 | | | 51 | | | 25 | | | | | (9) | | | 1,632 | |
| Total revenue | 10,295 | | | 13,025 | | | 3,659 | | | | | 10 | | | 26,989 | |
| Less: Revenues accounted for under topics other than ASC 606 and ASC 815 | — | | | (25) | | | 3 | | | | | — | | | (22) | |
| Less: Realized and unrealized ASC 815 revenue | 130 | | | 184 | | | (96) | | | | | 16 | | | 234 | |
| Total revenue from contracts with customers | $ | 10,165 | | | $ | 12,866 | | | $ | 3,752 | | | | | $ | (6) | | | $ | 26,777 | |
| (a) Home includes Services |
| (b) Other Revenue in Texas includes ancillary revenues of $1.3 billion driven by high pricing during Winter Storm Uri |
| (c) The following amounts of energy, capacity and other revenue relate to derivative instruments and are accounted for under ASC 815: |
| (In millions) | Texas | | East | | West/Services/Other | | | | Corporate/Eliminations | | Total |
| Energy revenue | $ | — | | | $ | 131 | | | $ | 2 | | | | | $ | 3 | | | $ | 136 | |
| Capacity revenue | — | | | 149 | | | — | | | | | — | | | 149 | |
| Other revenue | 133 | | | (8) | | | (12) | | | | | — | | | 113 | |
| (d) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815 |
ContractBalances
The following table reflects the contract assets and liabilities included in the Company's balance sheet as of December 31, 2023 and 2022:
| | | | | | | | | | | | | | |
| (In millions) | | December 31, 2023 | | December 31, 2022 |
Capitalized contract costs(a) | | $ | 706 | | | $ | 126 | |
| | | | |
| Accounts receivable, net - Contracts with customers | | 3,395 | | | 4,704 | |
| Accounts receivable, net - Accounted for under topics other than ASC 606 | | 136 | | | 64 | |
| Accounts receivable, net - Affiliate | | 11 | | | 5 | |
| Total accounts receivable, net | | $ | 3,542 | | | $ | 4,773 | |
| | | | |
| Unbilled revenues (included within Accounts receivable, net - Contracts with customers) | | $ | 1,493 | | | $ | 1,952 | |
Deferred revenues (b) | | $ | 1,634 | | | $ | 186 | |
(a)Amortization of capitalized contract costs for the years ended December 31, 2023, 2022 and 2021 were $168 million, $86 million and $95 million, respectively
(b)Deferred revenues from contracts with customers for the years ended December 31, 2023 and 2022 were approximately $1.6 billion and $175 million, respectively. The increase in deferred revenue balances from December 31, 2023 to 2022 was primarily due to the acquisition of Vivint Smart Home
The revenue recognized from contracts with customers during the years ended December 31, 2023 and 2022 relating to the deferred revenue balance at the beginning of each period was $168 million and $184 million, respectively. The change in the revenue recognized from contracts with customers relating to the deferred revenue balances at the beginning of the years ended December 31, 2023 and 2022 was primarily due to the timing difference of when consideration was received and when the performance obligation was transferred.
The Company's capitalized contract costs consist of commission payments, broker fees and other costs that represent incremental costs of obtaining the contract with customers for which the Company expects to recover. Capitalized contract costs are amortized on a straight-line basis over the expected period of benefit of five years. As a practical expedient, the Company expenses the incremental costs of obtaining a contract if the amortization period of the asset would have been one year or less.
When the Company receives consideration from the customer that is in excess of the amount due, such consideration is reclassified to deferred revenue, which represents a contract liability. Smart home products and services performance obligations are recognized over the customer's contract term, which is generally three to five years. Energy contract liabilities are generally recognized to revenue in the next period as the Company satisfies its performance obligations.
Note 4 —Acquisitions and Dispositions
Acquisitions
2023 Acquisitions
Vivint Smart Home Acquisition
On March 10, 2023 (the "Acquisition Closing Date"), the Company completed the acquisition of Vivint Smart Home, Inc., pursuant to the Agreement and Plan of Merger, dated as of December 6, 2022, by and among the Company, Vivint Smart Home, Inc. and Jetson Merger Sub, Inc., a wholly-owned subsidiary of the Company (“Merger Sub”) pursuant to which Merger Sub merged with and into Vivint Smart Home, Inc., with Vivint Smart Home, Inc. surviving the merger as a wholly-owned subsidiary of the Company. Dedicated to redefining the home experience with intelligent products and services, Vivint Smart Home brought approximately two million subscribers to NRG. Vivint Smart Home's single, expandable platform incorporates artificial intelligence and machine learning into its operating system and its vertically integrated business model includes hardware, software, sales, installation, customer service and technical support and professional monitoring, enabling superior subscriber experiences and a complete end-to-end smart home experience. The acquisition accelerated the realization of NRG's consumer-focused growth strategy and 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 approximately $2.6 billion in cash. The Company funded the acquisition using:
•proceeds of $724 million from newly issued $740 million 7.000% Senior Secured First Lien Notes due 2033, net of issuance costs and discount;
•proceeds of $635 million from newly issued $650 million 10.25% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock, net of issuance costs;
•proceeds of approximately $900 million drawn from its Revolving Credit Facility and Receivables Securitization Facilities; and
•cash on hand.
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 13, Long-term Debt and Finance Leases.
Acquisition costs of $38 million and $17 million for the years ended December 31, 2023 and 2022, 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 recorded at their estimated Acquisition Closing Date fair value. The total consideration of $2.623 billion includes:
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| | (In millions) |
| Vivint Smart Home, Inc. common shares outstanding as of March 10, 2023 of 216,901,639 at $12.00 per share | | $ | 2,603 | |
| Other Vivint Smart Home, Inc. equity instruments (Cash out RSUs and PSUs, Stock Appreciation Rights, Private Placement Warrants) | | 6 | |
| Total Cash Consideration | | $ | 2,609 | |
| Fair value of acquired Vivint Smart Home, Inc. equity awards attributable to pre-combination service | | 14 | |
| Total Consideration | | $ | 2,623 | |
The purchase price was allocated as follows as of December 31, 2023:
| | | | | |
| (In millions) |
| Current Assets | |
| Cash and cash equivalents | $ | 120 | |
| Accounts receivable, net | 60 | |
| Inventory | 113 | |
| Prepayments and other current assets | 37 | |
| Total current assets | 330 | |
| Property, plant and equipment, net | 49 | |
| Other Assets | |
| Operating lease right-of-use assets, net | 35 | |
Goodwill(a) | 3,494 | |
Intangible assets, net(b): | |
| Customer relationships | 1,740 | |
| Technology | 860 | |
| Trade names | 160 | |
| Sales channel contract | 10 | |
| Intangible assets, net | 2,770 | |
| Deferred income taxes | 382 | |
| Other non-current assets | 14 | |
| Total other assets | 6,695 | |
| Total Assets | $ | 7,074 | |
| |
| Current Liabilities | |
| Current portion of long-term debt and finance leases | $ | 14 | |
| Current portion of operating lease liabilities | 13 | |
| Accounts payable | 109 | |
| Derivative instruments | 80 | |
| Deferred revenue current | 518 | |
| Accrued expenses and other current liabilities | 207 | |
| Total current liabilities | 941 | |
| Other Liabilities | |
| Long-term debt and finance leases | 2,572 | |
| Non-current operating lease liabilities | 28 | |
| Derivative instruments | 32 | |
| Deferred income taxes | 18 | |
| Deferred revenue non-current | 837 | |
| Other non-current liabilities | 23 | |
| Total other liabilities | 3,510 | |
| Total Liabilities | $ | 4,451 | |
| |
| Vivint Smart Home Purchase Price | $ | 2,623 | |
(a)Goodwill arising from the acquisition is attributed to the value of the platform acquired, cross-selling opportunities, subscriber growth and the synergies expected from combining the operations of Vivint Smart Home with NRG's existing businesses. None of the goodwill recorded will be deductible for tax purposes
(b)The weighted average amortization period for total amortizable intangible assets is approximately ten years
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 classified as Level 3. Under this approach, the Company estimated the present value of expected future cash flows resulting from existing subscriber relationships, considering attrition and charges for contributory assets (such as net working capital, fixed assets, workforce, trade names and technology) utilized in the business, discounted based on the required rate of return on the acquired intangible asset. The subscriber relationships are amortized to depreciation and amortization, ratably based on discounted future cash flows. The weighted average amortization period is twelve years.
Technology – Developed technology was valued using a "relief from royalty" method of the income approach, and is classified as Level 3. Under this approach, the fair value was estimated to be the present value of royalties saved which assumed the value of the asset based on discounted cash flows of the amount that would be paid by a hypothetical market participant had they not 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 based on the required rate of return on the acquired intangible asset. 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 names – Trade names were 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 names considered the expected probable use of the asset and was discounted based on the required rate of return on the acquired intangible asset. The trade names are 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 aggregate principal of Vivint Smart Home’s 2027 Senior Secured Notes, 2029 Senior notes and 2028 Senior Secured Term Loan (together, the "Acquired Vivint Smart Home Debt") which were recorded at fair value as of the Acquisition Closing Date. The difference between the fair value at the Acquisition Closing Date and the principal outstanding of the Acquired Vivint Smart Home Debt, of $152 million, is being amortized through interest expense over the remaining term of the debt. The Acquired Vivint Smart Home Debt is classified as Level 2 and were measured at fair value using observable market inputs based on interest rates at the Acquisition Closing Date. For additional discussion, seeNote 13, Long-term Debt and Finance Leases.
Fair Value Measurement of Derivatives Liabilities
The derivative liabilities are recorded in connection with the contractual future payment obligations with the financing providers under Vivint Smart Home’s Consumer Financing Program. The fair values of the derivatives liabilities as of the Acquisition Closing Date were valued using a discounted cash flow model, with inputs consisting of available market data, such as market yield discount rates, as well as unobservable internally derived assumptions, such as collateral prepayment rates, collateral default rates and credit loss rates. These derivatives are classified as Level 3 and changes to the fair value are recorded through other income, net in the consolidated statement of operations. For additional discussion, see Note 6, Accounting for Derivative Instruments and Hedging Activities.
Supplemental Pro Forma Financial Information
The following table provides unaudited 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, 2021. The pro forma financial information has been prepared for illustrative and informational purposes only, and is not intended to project future operating results or be indicative of what the Company's financial performance would have been had the transactions occurred on the date indicated. No effect has been given to prospective operating synergies.
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| For the Year Ended December 31, |
| (In millions) | 2023 | | 2022 | | 2021 |
| Total operating revenues | $ | 29,109 | | | $ | 33,225 | | | $ | 28,468 | |
| Net (loss)/income | (3) | | | 1,136 | | | 1,574 | |
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 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 year ended December 31, 2021.
(iv)Interest expense assumes the financing transactions directly attributable to the Vivint Smart Home acquisition occurred on January 1, 2021.
(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 year ended December 31, 2021 instead of the year ended December 31, 2023.
(vii) Income tax effect of the acquisition accounting adjustments and financing adjustments (adjusted for permanent book/tax differences) based on combined blended federal/state tax rate for all periods presented.
2021 Acquisitions
Direct Energy Acquisition
On January 5, 2021, the Company acquired all of the issued and outstanding common shares of Direct Energy, which had been a North American subsidiary of Centrica plc. Direct Energy is a leading retail provider of electricity, natural gas, and home and business energy related products and services in North America, with operations in all 50 U.S. states and 8 Canadian provinces. The acquisition increased NRG's retail portfolio by over 3 million customers and strengthened its integrated model. It also broadened the Company's presence in the Northeast and into states and locales where it did not previously operate, supporting NRG's objective to diversify its business.
The Company paid an aggregate purchase price of $3.625 billion in cash and total purchase price adjustment of $99 million, resulting in an adjusted purchase price of $3.724 billion.
Acquisition costs of $25 million for the year ended December 31, 2021 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 acquired and liabilities assumed recorded at their estimated fair values on the acquisition date. The purchase price was allocated as follows as of December 31, 2021:
| | | | | |
| (In millions) |
| Current Assets | |
| Cash and cash equivalents | $ | 152 | |
| Funds deposited by counterparties | 21 | |
| Restricted cash | 9 | |
| Accounts receivable, net | 1,802 | |
| Inventory | 106 | |
| Derivative instruments | 1,014 | |
| Cash collateral paid in support of energy risk management activities | 233 | |
| Prepayments and other current assets | 173 | |
| Total current assets | 3,510 | |
| Property, plant and equipment, net | 151 | |
| Other Assets | |
Goodwill(a) | 1,250 | |
| Intangible assets, net: | |
Customer relationships(b) | 1,277 | |
Customer and supply contracts(b) | 610 | |
Trade names(b) | 310 | |
| Renewable energy credits | 124 | |
| Total intangible assets, net | 2,321 | |
| Derivative instruments | 531 | |
| Other non-current assets | 31 | |
| Total other assets | 4,133 | |
| Total Assets | $ | 7,794 | |
| |
| Current Liabilities | |
| Accounts payable | $ | 1,116 | |
| Derivative instruments | 1,266 | |
| Cash collateral received in support of energy risk management activities | 21 | |
| Accrued expenses and other current liabilities | 670 | |
| Total current liabilities | 3,073 | |
| Other Liabilities | |
| Derivative instruments | 562 | |
| Deferred income taxes | 320 | |
| Other non-current liabilities | 115 | |
| Total other liabilities | 997 | |
| Total Liabilities | $ | 4,070 | |
| |
| Direct Energy Purchase Price | $ | 3,724 | |
(a)Goodwill arising from the acquisition was attributed to the value of the platform acquired and the synergies expected from combining the operations of Direct Energy with NRG's existing businesses. Goodwill was allocated to the Texas, East, and West/Services/Other segments of $427 million, $648 million and $175 million, respectively. Goodwill deductible for tax purposes was $322 million
(b)As of January 5, 2021, the weighted average amortization period for total amortizable intangible assets was 12 years
Dispositions
2023 Dispositions
Sale of the 44% equity interest in STP
On November 1, 2023, the Company closed on the sale of its 44% equity interest in STP to Constellation Energy Generation ("Constellation"). Proceeds of $1.75 billion were reduced by working capital and other adjustments of $96 million, resulting in net proceeds of $1.654 billion. The Company recorded a gain on the sale of $1.2 billion within the Texas region of operations. For discussion of the litigation matter related to the transaction, see Note 23, Commitments and Contingencies.
The Company recorded income before income taxes from its 44% equity interest in STP as follows:
| | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, |
| (In millions) | 2023 | | 2022 | | 2021 |
Income before income taxes(a) | $ | 206 | | | $ | 362 | | | $ | 829 | |
(a)Excludes the impact of the Company's hedges at the portfolio level
Sale of Gregory
On October 2, 2023, the Company closed on the sale of its 100% ownership in the Gregory natural gas generating facility in Texas for $102 million. The Company recorded a gain on the sale of $82 million.
Sale of Astoria
On January 6, 2023, the Company closed on the sale of land and related generation assets from the Astoria site, within the East region of operations, for proceeds of $212 million, subject to transaction fees of $3 million and certain indemnifications, resulting in a $199 million gain. As part of the transaction, NRG entered into an agreement to lease the land back for the purpose of operating the Astoria gas turbines. Decommissioning was completed in December 2023 and the lease agreement has been terminated.
2022 Dispositions
Sale of Watson
On June 1, 2022, the Company closed on the sale of its 49% ownership in the Watson natural gas generating facility for $59 million. The Company recorded a gain on the sale of $46 million.
2021 Dispositions
Sale of 4,850 MW of Fossil generating assets
On December 1, 2021, the Company closed the previously announced sale of approximately 4,850 MWs of fossil generating assets from its East and West regions to Generation Bridge, an affiliate of ArcLight Capital Partners. Proceeds of $760 million were reduced by working capital and other adjustments of $140 million, resulting in net proceeds of $620 million. The Company recorded a gain of $207 million from the sale, which includes the $39 million indemnification liability recorded as discussed below. As part of the transaction, NRG entered into a tolling agreement for the 866 MW Arthur Kill plant in New York City through April 2025.
As part of the agreement to sell the fossil generating assets, NRG has agreed to indemnify Generation Bridge for certain future environmental compliance costs up to $39 million. The indemnity term will expire on December 1, 2028. The Company has recorded the liability within accrued expenses and other current liabilities and other non-current liabilities.
Sale of Agua Caliente
On February 3, 2021, the Company closed on the sale of its 35% ownership in the Agua Caliente solar project to Clearway Energy, Inc. for $202 million. NRG recognized a gain on the sale of $17 million, including cash disposed of $7 million.
Note 5 — Fair Value of Financial Instruments
For cash and cash equivalents, funds deposited by counterparties, restricted cash, accounts and other receivables, accounts payable and cash collateral paid and received in support of energy risk management activities, the carrying amount approximates fair value because of the short-term maturity of those instruments and are classified as Level 1 within the fair value hierarchy.
The estimated carrying value and fair value of the Company's long-term debt, including current portion, is as follows:
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| | As of December 31, |
| 2023 | | 2022 |
| (In millions) | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Convertible Senior Notes | $ | 575 | | | $ | 739 | | | $ | 575 | | | $ | 576 | |
| Other long-term debt, including current portion | 10,219 | | | 9,835 | | | 7,523 | | | 6,432 | |
Total long-term debt, including current portion(a) | $ | 10,794 | | | $ | 10,574 | | | $ | 8,098 | | | $ | 7,008 | |
(a)Excludes deferred financing costs, which are recorded as a reduction to long-term debt on the Company's consolidated balance sheets
The fair value of the Company's publicly-traded long-term debt and the Vivint Smart Home Senior Secured Term Loan are based on quoted market prices and are classified as Level 2 within the fair value hierarchy.
Fair Value Accounting under ASC 820
ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:
•Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Company has the ability to access as of the measurement date. NRG's financial assets and liabilities utilizing Level 1 inputs include active exchange-traded securities, energy derivatives, and trust fund investments.
•Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data. NRG's financial assets and liabilities utilizing Level 2 inputs include fixed income securities, exchange-based derivatives, and over the counter derivatives such as swaps, options and forward contracts.
•Level 3 — unobservable inputs for the asset or liability only used when there is little, if any, market activity for the asset or liability at the measurement date. NRG's financial assets and liabilities utilizing Level 3 inputs include infrequently-traded, non-exchange-based derivatives and commingled investment funds, and are measured using present value pricing models.
In accordance with ASC 820, the Company determines the level in the fair value hierarchy within which each fair value measurement in its entirety falls, based on the lowest level input that is significant to the fair value measurement in its entirety.
Recurring Fair Value Measurements
Derivative assets and liabilities, debt securities, equity securities and trust fund investments, which were comprised of various U.S. debt and equity securities, are carried at fair market value.
The following tables present assets and liabilities measured and recorded at fair value on the Company's consolidated balance sheets on a recurring basis and their level within the fair value hierarchy:
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| | As of December 31, 2023 |
| | Fair Value |
| (In millions) | Total | | Level 1 | | Level 2 | | Level 3 |
| Investments in securities (classified within other current and non-current assets) | $ | 21 | | | $ | — | | | $ | 21 | | | $ | — | |
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| Derivative assets: | | | | | | | |
| Interest rate contracts | 12 | | | — | | | 12 | | | — | |
| Foreign exchange contracts | 5 | | | — | | | 5 | | | — | |
| Commodity contracts | 6,138 | | | 1,334 | | | 4,470 | | | 334 | |
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| Equity securities measured using net asset value practical expedient (classified within other non-current assets) | 6 | | | | | | | |
| Total assets | $ | 6,182 | | | $ | 1,334 | | | $ | 4,508 | | | $ | 334 | |
| Derivative liabilities: | | | | | | | |
| Interest rate contracts | $ | 8 | | | $ | — | | | $ | 8 | | | $ | — | |
| Foreign exchange contracts | 9 | | | — | | | 9 | | | — | |
| Commodity contracts | 5,356 | | | 1,413 | | | 3,728 | | | 215 | |
| Consumer Financing Program | 134 | | | — | | | — | | | 134 | |
| Total liabilities | $ | 5,507 | | | $ | 1,413 | | | $ | 3,745 | | | $ | 349 | |
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| | As of December 31, 2022 |
| | Fair Value |
| (In millions) | Total | | Level 1 | | Level 2 | | Level 3 |
| Investments in securities (classified within other current and non-current assets) | $ | 19 | | | $ | — | | | $ | 19 | | | $ | — | |
| Nuclear trust fund investments: | | | | | | | |
| Cash and cash equivalents | 15 | | | 15 | | | — | | | — | |
| U.S. government and federal agency obligations | 86 | | | 84 | | | 2 | | | — | |
| Federal agency mortgage-backed securities | 101 | | | — | | | 101 | | | — | |
| Commercial mortgage-backed securities | 35 | | | — | | | 35 | | | — | |
| Corporate debt securities | 114 | | | — | | | 114 | | | — | |
| Equity securities | 403 | | | 403 | | | — | | | — | |
| Foreign government fixed income securities | 1 | | | — | | | 1 | | | — | |
| Other trust fund investments (classified within other non-current assets): | | | | | | | |
| U.S. government and federal agency obligations | 1 | | | 1 | | | — | | | — | |
| Derivative assets: | | | | | | | |
| Foreign exchange contracts | 18 | | | — | | | 18 | | | — | |
| Commodity contracts | 11,976 | | | 1,929 | | | 8,796 | | | 1,251 | |
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| Measured using net asset value practical expedient: | | | | | | | |
| Equity securities - nuclear trust fund investments | 83 | | | | | | | |
| Equity securities (classified within other non-current assets) | 6 | | | | | | | |
| Total assets | $ | 12,858 | | | $ | 2,432 | | | $ | 9,086 | | | $ | 1,251 | |
| Derivative liabilities: | | | | | | | |
| Foreign exchange contracts | $ | 2 | | | $ | — | | | $ | 2 | | | $ | — | |
| Commodity contracts | 8,439 | | | 1,244 | | | 6,449 | | | 746 | |
| | | | | | | |
| Total liabilities | $ | 8,441 | | | $ | 1,244 | | | $ | 6,451 | | | $ | 746 | |
The following table reconciles, for the years ended December 31, 2023 and 2022, the beginning and ending balances for financial instruments that are recognized at fair value in the consolidated financial statements using significant unobservable inputs, for commodity derivatives:
| | | | | | | | | | | | | | |
| | | Fair Value Measurement Using Significant Unobservable Inputs (Level 3) |
| | Commodity Derivatives (a) |
| | For the Year Ended December 31, |
| (In millions) | | 2023 | | 2022 |
| Beginning balance | | $ | 505 | | | $ | 293 | |
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| Total (losses)/gains realized/unrealized included in earnings | | (164) | | | 53 | |
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| Purchases | | 42 | | | (110) | |
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Transfers into Level 3(b) | | 78 | | | 264 | |
Transfers out of Level 3(b)(c) | | (342) | | | 5 | |
| Ending balance | | $ | 119 | | | $ | 505 | |
| (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 year-end | | $ | (46) | | | $ | 204 | |
(a)Consists of derivatives assets and liabilities, net, excluding derivative 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 consensus pricing and external broker quotes, and are valued as of the end of the reporting period. All transfers into/out of Level 3 are from/to Level 2
(c)For the year ended December 31, 2023, due to the change to use consensus pricing, there was a decrease in the number of contracts valued with prices provided by models and other valuation techniques, which resulted in a large transfer out of Level 3
Realized and unrealized gains and losses included in earnings that are related to the commodity derivatives are recorded in revenues and cost of operations.
The following table reconciles, for the year ended December 31, 2023, the beginning and ending balances of the contractual obligations from the Consumer Financing Program that are recognized at fair value in the condensed consolidated financial statements, using significant unobservable inputs:
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| | | Fair Value Measurement Using Significant Unobservable Inputs (Level 3) |
| | | Consumer Financing Program |
| (In millions) | | | For the Year Ended December 31, 2023 |
| Beginning balance | | | $ | — | |
| Contractual obligations added from the acquisition of Vivint Smart Home | | | (112) | |
| New contractual obligations | | | (68) | |
| Settlements | | | 62 | |
| Total losses included in earnings | | | (16) | |
| Ending balance | | | $ | (134) | |
Gains and losses that are related to the Consumer Financing Program derivative are recorded in other income, net.
Non-derivative fair value measurements
For the year ended December 31, 2022 and through the sale of STP on November 1, 2023, the trust fund investments were held primarily to satisfy NRG's nuclear decommissioning obligations. These trust fund investments held debt and equity securities directly and equity securities indirectly through commingled funds. The fair values of equity securities held directly by the trust funds were based on quoted prices in active markets and were categorized in Level 1. In addition, U.S. government and federal agency obligations were categorized as Level 1 because they traded in a highly liquid and transparent market. The fair values of corporate debt securities were based on evaluated prices that reflected observable market information, such as actual trade information of similar securities, adjusted for observable differences and were categorized in Level 2. Certain equity securities, classified as commingled funds, were analogous to mutual funds, were maintained by investment companies, and held certain investments in accordance with a stated set of fund objectives. The fair value of the equity securities classified as commingled funds were based on net asset values per fund share (the unit of account), derived from the quoted prices in active markets of the underlying equity securities. However, because the shares in the commingled funds were not publicly quoted and not traded in an active market, the commingled funds were measured using net asset value practical expedient. See also Note 7, Nuclear Decommissioning Trust Fund.
Derivative fair value measurements
The Company's contracts consist of non-exchange-traded contracts valued using prices provided by external sources and exchange-traded contracts with readily available quoted market prices. Beginning in of the fourth quarter of 2023 and as of December 31, 2023, the fair value of non-exchange traded contracts were based on consensus pricing provided by independent pricing services. The pricing data was compiled from market makers with longer dated tenors as compared to broker quotes, enhancing reliability and increasing transparency.
Prior to the fourth quarter of 2023, the Company valued derivatives based on price quotes from brokers in active markets who regularly facilitate those transactions. For the majority of markets that NRG participates in, the Company would receive broker quotes from multiple sources and reflected the average of the bid-ask mid-point prices. The terms for which such price information is available vary by commodity, region and product. The Company believes both sources of price quotes are executable.
The remainder of the assets and liabilities represents contracts for which external sources or observable market quotes are not available. These contracts are valued based on various valuation techniques including but not limited to internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. As of December 31, 2023, contracts valued with prices provided by models and other valuation techniques make up 5% of derivative assets and 6% of derivative liabilities. As a result of NRG switching to consensus pricing as of December 31, 2023, there was a significant decrease in the number of contracts valued with prices provided by models and other valuation techniques. 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 for foreign exchange contracts and interest rate swaps is calculated utilizing the bilateral method based on published default probabilities. For commodities, to the extent that NRG's net exposure under a specific master agreement is an asset, the Company uses the counterparty's default swap rate. If the exposure under a specific master agreement is a liability, the Company uses NRG's default swap rate. For foreign exchange contracts, interest rate swaps, and commodities, the credit reserve is added to the discounted fair value to reflect the exit price that a market participant would be willing to receive to assume NRG's liabilities or that a market participant would be willing to pay for NRG's assets. As of December 31, 2023, the credit reserve resulted in a $18 million decrease primarily within cost of operations. As of December 31, 2022, the credit reserve resulted in $9 million decrease primarily within cost of operations.
The fair values in each category reflect the level of forward prices and volatility factors as of December 31, 2023 and may change as a result of changes in these factors. Management uses its best estimates to determine the fair value of commodity and derivative contracts NRG holds and sells. These estimates consider various factors including closing exchange, consensus and over-the-counter price quotations, time value, volatility factors and credit exposure. It is possible, however, that future market prices could vary from those used in recording assets and liabilities from energy marketing and trading activities and such variations could be material.
NRG's significant positions classified as Level 3 include physical and financial natural gas, power, capacity contracts and renewable energy certificates executed in illiquid markets as well as financial transmission rights ("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. Forward capacity prices are based on market information, forecasted future electricity demand and supply, past auctions and internally developed pricing models. Renewable energy certificate prices are based on market information and internally developed pricing models. For FTRs, NRG uses the most recent auction prices to derive the fair value. The Consumer Financing Program derivatives are valued using a discounted cash flow model, with inputs consisting of available market data, such as market yield discount rates, as well as unobservable internally derived assumptions, such as collateral prepayment rates, collateral default rates and credit loss rates.
The following tables quantify the significant unobservable inputs used in developing the fair value of the Company's Level 3 positions as of December 31, 2023 and 2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Significant Unobservable Inputs |
| December 31, 2023 |
| Fair Value | | | | Input/Range |
| (in millions, except as noted) | Assets | | Liabilities | | Valuation Technique | | Significant Unobservable Input | | Low | | High | | Weighted Average |
| Natural Gas Contracts | $ | 39 | | | $ | 65 | | | Discounted Cash Flow | | Forward Market Price ($ per MMBtu) | | $ | 1 | | | $ | 15 | | | $ | 3 | |
| Power Contracts | 197 | | | 66 | | | Discounted Cash Flow | | Forward Market Price ($ per MWh) | | 1 | | | 210 | | | 47 | |
| Capacity Contracts | 21 | | | 33 | | | Discounted Cash Flow | | Forward Market Price ($ per MW/Day) | | 49 | | | 658 | | | 285 | |
| Renewable Energy Certificates | 58 | | | 14 | | | Discounted Cash Flow | | Forward Market Price ($ per Certificate) | | 2 | | | 320 | | | 15 | |
| FTRs | 19 | | | 37 | | | Discounted Cash Flow | | Auction Prices ($ per MWh) | | (58) | | | 252 | | | 0 | |
| Consumer Financing Program | — | | | 134 | | | Discounted Cash Flow | | Collateral Default Rates | | 0.43 | % | | 93.30 | % | | 8.12 | % |
| | | | | Discounted Cash Flow | | Collateral Prepayment Rates | | 2.00 | % | | 3.00 | % | | 2.95 | % |
| | | | | Discounted Cash Flow | | Credit Loss Rates | | 6.00 | % | | 60.00 | % | | 12.57 | % |
| $ | 334 | | | $ | 349 | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Significant Unobservable Inputs |
| December 31, 2022 |
| Fair Value | | | | Input/Range |
| (in millions, except as noted) | Assets | | Liabilities | | Valuation Technique | | Significant Unobservable Input | | Low | | High | | Weighted Average |
| Natural Gas Contracts | $ | 340 | | | $ | 448 | | | Discounted Cash Flow | | Forward Market Price ($ per MMBtu) | | $ | 2 | | | $ | 48 | | | $ | 6 | |
| Power Contracts | 843 | | | 216 | | | Discounted Cash Flow | | Forward Market Price ($ per MWh) | | 3 | | | 431 | | | 48 | |
| FTRs | 68 | | | 82 | | | Discounted Cash Flow | | Auction Prices ($ per MWh) | | (32) | | | 610 | | | 0 | |
| $ | 1,251 | | | $ | 746 | | | | | | | | | | | |
| | | | | | | | | | | | | |
The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable inputs as of December 31, 2023 and 2022: | | | | | | | | | | | | | | | | | | | | |
| Significant Unobservable Input | | Position | | Change In Input | | Impact on Fair Value Measurement |
| Forward Market Price Natural Gas/Power/Capacity/Renewable Energy Certificates | | Buy | | Increase/(Decrease) | | Higher/(Lower) |
| Forward Market Price Natural Gas/Power/Capacity/Renewable Energy Certificates | | Sell | | Increase/(Decrease) | | Lower/(Higher) |
| FTR Prices | | Buy | | Increase/(Decrease) | | Higher/(Lower) |
| FTR Prices | | Sell | | Increase/(Decrease) | | Lower/(Higher) |
| Collateral Default Rates | | n/a | | Increase/(Decrease) | | Higher/(Lower) |
| Collateral Prepayment Rates | | n/a | | Increase/(Decrease) | | Lower/(Higher) |
| Credit Loss Rates | | n/a | | Increase/(Decrease) | | Higher/(Lower) |
Under the guidance of ASC 815, entities may choose to offset cash collateral posted or received against the fair value of derivative positions executed with the same counterparties under the same master netting agreements. The Company has chosen not to offset positions as defined in ASC 815. As of December 31, 2023, the Company recorded $441 million of cash collateral posted and $84 million of cash collateral received on its balance sheet.
Concentration of Credit Risk
In addition to the credit risk discussion as disclosed in Note 2, Summary of Significant Accounting Policies, the following item is a discussion of the concentration of credit risk for the Company's financial instruments. 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. The Company monitors and manages credit risk through credit policies that include: (i) an established credit approval process; (ii) a daily monitoring of counterparties' credit limits; (iii) the use of credit mitigation measures such as margin, collateral, prepayment arrangements, or volumetric limits; (iv) the use of payment netting agreements; and (v) the use of master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with a single counterparty. Risks surrounding counterparty performance and credit could ultimately impact the amount and timing of expected cash flows. The Company seeks to mitigate counterparty risk by having a diversified portfolio of counterparties. The Company also has credit protection within various agreements to call on additional collateral support if and when necessary. Cash margin is collected and held at the Company to cover the credit risk of the counterparty until positions settle.
Counterparty Credit Risk
As of December 31, 2023, counterparty credit exposure, excluding credit exposure from RTOs, ISOs, and registered commodity exchanges and certain long-term agreements, was $1.6 billion and NRG held collateral (cash and letters of credit) against those positions of $426 million, resulting in a net exposure of $1.2 billion. NRG periodically receives collateral from counterparties in excess of their exposure. Collateral amounts shown include such excess while net exposure shown excludes excess collateral received. Approximately 63% of the Company's exposure before collateral is expected to roll off by the end of 2025. Counterparty credit exposure is valued through observable market quotes and discounted at a risk free interest rate. The following tables highlight net counterparty credit exposure by industry sector and by counterparty credit quality. Net counterparty credit exposure is defined as the aggregate net asset position for NRG with counterparties where netting is permitted under the enabling agreement and includes all cash flow, mark-to-market and NPNS, and non-derivative transactions. The exposure is shown net of collateral held and includes amounts net of receivables or payables.
| | | | | |
| Category | Net Exposure (a) (b) (% of Total) |
| Utilities, energy merchants, marketers and other | 80 | % |
| Financial institutions | 20 | |
| |
| |
| Total | 100 | % |
| | | | | |
| Category | Net Exposure (a) (b) (% of Total) |
| Investment grade | 44 | % |
| Non-Investment grade/Non-Rated | 56 | |
| |
| Total | 100 | % |
(a)Counterparty credit exposure excludes coal transportation contracts because of the unavailability of market prices
(b)The figures in the tables above exclude potential counterparty credit exposure related to RTOs, ISOs, registered commodity exchanges and certain long term contracts
The Company currently has exposure to one wholesale counterparty in excess of 10% of the total net exposure discussed above as of December 31, 2023. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration.
RTOs and ISOs
The Company participates in the organized markets of CAISO, ERCOT, AESO, IESO, ISO-NE, MISO, NYISO and PJM, known as RTOs or ISOs. Trading in the majority of these markets is approved by FERC, whereas in the case of ERCOT, it is approved by the PUCT, and whereas in the case of AESO and IESO, both exist provincially with AESO primarily subject to Alberta Utilities Commission and the IESO subject 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 December 31, 2023, aggregate credit risk exposure managed by NRG to these counterparties was approximately $882 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, which serve 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 nonpayment of customer accounts receivable and the loss of in-the-money forward value. The Company manages retail credit risk through the use of established credit policies that include monitoring of the portfolio and the use of credit mitigation measures such as deposits or prepayment arrangements.
As of December 31, 2023, the Company's retail customer credit exposure to Home and Business customers was diversified across many customers and various industries, as well as government entities. Current economic conditions may affect the Company's customers' ability to pay bills in a timely manner, which could increase customer delinquencies and may lead to an increase in credit losses. The Company's provision for credit losses was $251 million, $11 million, and $698 million for the years ended December 31, 2023, 2022, and 2021, respectively. During the year ended December 31, 2022, the provision for credit losses included the Company's loss mitigation efforts recognized as income of $126 million related to Winter Storm Uri. During the year ended December 31, 2021, the provision for credit losses included $596 million of expenses due to the impacts of Winter Storm Uri.
Note 6 — Accounting for Derivative Instruments and Hedging Activities
ASC 815 requires the Company to recognize all derivative instruments on the balance sheet as either assets or liabilities and to measure them at fair value each reporting period unless they qualify for a NPNS exception. The Company may elect to designate certain derivatives as cash flow hedges, if certain conditions are met, and defer the change in fair value of the derivatives to accumulated OCI, until the hedged transactions occur and are recognized in earnings.
For derivatives that are not designated as cash flow hedges or do not qualify for hedge accounting treatment, the changes in the fair value will be immediately recognized in earnings. Certain derivative instruments may qualify for the NPNS exception and are therefore exempt from fair value accounting treatment. ASC 815 applies to NRG's energy related commodity contracts, foreign exchange contracts, interest rate swaps and Consumer Financing Program.
As the Company engages principally in the trading and marketing of its generation assets and retail operations, some of NRG's commercial activities qualify for NPNS accounting. Most of the retail load contracts either qualify for the NPNS exception or fail to meet the criteria for a derivative and the majority of the retail supply and fuels supply contracts are recorded under mark-to-market accounting. All of NRG's hedging and trading activities are subject to limits within the Company's Risk Management Policy.
Energy-Related Commodities
To manage the commodity price risk associated with the Company's competitive supply activities and the price risk associated with wholesale power sales from the Company's electric generation facilities and retail power and gas sales from NRG's retail businesses,operations, NRG enters into a variety of derivative and non-derivative hedging instruments, utilizing the following:
•Forward contracts, which commit NRG to purchase or sell energy commodities or purchase fuels in the future;
•Futures contracts, which are exchange-traded standardized commitments to purchase or sell a commodity or financial instrument;
•Swap agreements, which require payments to or from counterparties based upon the differential between two prices for a predetermined contractual, or notional, quantity;
•Option contracts, which convey to the option holder the right but not the obligation to purchase or sell a commodity; and
Extendable swaps, which include a combination of swaps and options executed simultaneously for different periods. This combination of instruments allows NRG to sell out-year volatility through call options in exchange for natural gas swaps with fixed prices in excess of the market price for natural gas at that time. The above-market swap combined with its later-year call option are priced in aggregate at market at the trade's inception; and
•Weather derivative products used to mitigate a portion of lost revenue due to weather.
The objectives for entering into derivative contracts designated as hedges include:
•Fixing the price of a portion of anticipated power and gas purchases for the Company's retail sales;
•Fixing the price for a portion of anticipated future electricity sales that provides an acceptable return on the Company's electric generation operations; and
•Fixing the price of a portion of anticipated fuel purchases for the operation of the Company's power plants; andplants.
Fixing the price of a portion of anticipated power purchases for the Company's retail sales.
NRG's trading and hedging activities are subject to limits within the Company's Risk Management Policy. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings.
As of December 31, 2017,2023, NRG's derivative assets and liabilities consisted primarily of the following:
•Forward and financial contracts for the purchase/sale of electricity and related products economically hedging NRG's generation assets' forecasted output or NRG's retail load obligations through 2031;2036;
•Forward and financial contracts for the purchase of fuel commodities relating to the forecasted usage of NRG's generation assets through 2019; and2025;
•Other energy derivatives instruments extending through 2024.2029.
Also, as of December 31, 2017,2023, NRG had other energy-related contracts that did not meet the definition of a derivative instrument or qualified for the NPNS exception and were therefore exempt from fair value accounting treatment as follows:
•Load-following forward electric sale contracts extending through 2026;2036;
•Load-following forward natural gas purchase and sale contracts extending through 2032;
•Power tolling contracts through 2043;2036;
•Coal purchase contracts through 2021;2024;
•Power transmission contracts through 2025;2029;
•Natural gas transportation contracts andthrough 2034;
•Natural gas storage agreements through 2030; and
•Coal transportation contracts through 2029.
Foreign Exchange Contracts
In order to mitigate foreign exchange risk primarily associated with the purchase of USD denominated natural gas for the Company's Canadian business, NRG enters into foreign exchange contract agreements through 2027.
Interest Rate Swaps
NRG is exposed to changes in interest ratesrate through the Company's issuance of variable rate debt. In order toTo manage the Company's interest rate risk, NRG enters into interest rate swap agreements. AsIn the first quarter of December 31, 2017, NRG had2023, the Company entered into $1.0 billion of interest rate derivative instrumentsswaps through 2027 to hedge the floating rate on recourse debtthe Term Loan acquired with the Vivint Smart Home acquisition. Additionally, in the first quarter of 2023, the Company had entered into interest rate swaps to hedge the floating rate on the Revolving Credit Facility extending through 20212024, which was fully terminated in conjunction with the pay down of the Revolving Credit Facility.
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 non-recourse debt extending through 2041, somereceives proceeds that are net of which arethese fees. Vivint Smart Home also shares the liability for credit losses, depending on the credit quality of the subscriber. Due to the nature of certain provisions under the Consumer Financing Program, the Company records a derivative liability that is not designated as a hedging instrument and is adjusted to fair value, measured using the present value of the estimated future payments. Changes to the fair value are recorded through other income, net in the consolidated statement of operations. The following represent the contractual future payment obligations with the Financing Providers under the Consumer Financing Program that are components of the derivative:
• Vivint Smart Home pays either a monthly fee based on the average daily outstanding balance of the loans, or the number of outstanding loans, depending on the Financing Provider;
• Vivint Smart Home shares the liability for credit losses depending on the credit quality of the subscriber; and
• Vivint Smart Home pays transactional fees associated with subscriber payment processing.
The derivative is classified as a Level 3 instrument. The derivative positions are valued using a discounted cash flow hedges.model, with inputs consisting of available market data, such as market yield discount rates, as well as unobservable internally derived assumptions, such as collateral prepayment rates, collateral default rates and credit loss rates. In summary, the fair value represents an estimate of the present value of the cash flows Vivint Smart Home will be obligated to pay to the Financing 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 commodity, excluding those derivatives that qualified for the NPNS exception as of December 31, 20172023 and 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 |
| Commodity | Units | December 31, 2017 | | December 31, 2016 |
| | | (In millions) |
| Emissions | Short Ton | 1 |
| | — |
|
| Coal | Short Ton | 21 |
| | 35 |
|
| Natural Gas | MMBtu | (17 | ) | | (53 | ) |
| Oil | Barrel | — |
| | 1 |
|
| Power | MWh | 14 |
| | 7 |
|
| Capacity | MW/Day | (1 | ) | | (1 | ) |
| Interest | Dollars | $ | 3,876 |
| | $ | 3,429 |
|
| Equity | Shares | 1 |
| | 1 |
|
The decrease in the natural gas position was primarily the result of the settlement of generation hedge positions. The increase in the interest rate position was primarily the result of entering into new interest rate swaps to hedge additional non-recourse project level debt.
| | | | | | | | | | | | | | |
| | Total Volume (In millions) |
| Category | Units | December 31, 2023 | | December 31, 2022 |
| Emissions | Short Ton | — | | | 1 | |
| Renewables Energy Certificates | Certificates | 12 | | | 15 | |
| Coal | Short Ton | 9 | | | 11 | |
| Natural Gas | MMBtu | 838 | | | 422 | |
| Oil | Barrels | — | | | 1 | |
| Power | MWh | 201 | | | 192 | |
| Interest | Dollars | 1,000 | | | — | |
| | | | |
| Foreign Exchange | Dollars | 548 | | | 569 | |
| Consumer Financing Program | Dollars | 1,116 | | | — | |
Fair Value of Derivative Instruments
The following table summarizes the fair value within the derivative instrument valuation on the balance sheet:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Fair Value |
| | Derivative Assets | | Derivative Liabilities |
| (In millions) | December 31, 2023 | | December 31, 2022 | | December 31, 2023 | | December 31, 2022 |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Derivatives Not Designated as Cash Flow or Fair Value Hedges: | | | | | | | |
| Interest rate contracts - current | $ | 12 | | | $ | — | | | $ | — | | | $ | — | |
| Interest rate contracts - long-term | — | | | — | | | 8 | | | — | |
| Foreign exchange contracts - current | 3 | | | 11 | | | 4 | | | 1 | |
| Foreign exchange contracts - long-term | 2 | | | 7 | | | 5 | | | 1 | |
| Commodity contracts- current | 3,847 | | | 7,875 | | | 3,922 | | | 6,194 | |
| Commodity contracts- long-term | 2,291 | | | 4,101 | | | 1,434 | | | 2,245 | |
| Consumer Financing Program - current | — | | | — | | | 93 | | | — | |
| Consumer Financing Program - long-term | — | | | — | | | 41 | | | — | |
| | | | | | | |
| Total Derivatives Not Designated as Cash Flow or Fair Value Hedges | $ | 6,155 | | | $ | 11,994 | | | $ | 5,507 | | | $ | 8,441 | |
| | | | | | | |
|
| | | | | | | | | | | | | | | |
| | Fair Value |
| | Derivative Assets | | Derivative Liabilities |
| (In millions) | December 31, 2017 | | December 31, 2016 | | December 31, 2017 | | December 31, 2016 |
Derivatives Designated as Cash Flow or Fair Value Hedges: | | | | | | | |
| Interest rate contracts current | $ | 1 |
| | $ | — |
| | $ | 5 |
| | $ | 28 |
|
| Interest rate contracts long-term | 11 |
| | 12 |
| | 11 |
| | 41 |
|
| Total Derivatives Designated as Cash Flow or Fair Value Hedges | 12 |
| | 12 |
| | 16 |
| | 69 |
|
Derivatives Not Designated as Cash Flow or Fair Value Hedges: | | | | | | | |
| Interest rate contracts current | 9 |
| | — |
| | 15 |
| | 7 |
|
| Interest rate contracts long-term | 32 |
| | 37 |
| | 28 |
| | 12 |
|
| Commodity contracts current | 616 |
| | 1,067 |
| | 535 |
| | 1,057 |
|
| Commodity contracts long-term | 129 |
| | 132 |
| | 158 |
| | 231 |
|
| Total Derivatives Not Designated as Cash Flow or Fair Value Hedges | 786 |
| | 1,236 |
| | 736 |
| | 1,307 |
|
| Total Derivatives | $ | 798 |
| | $ | 1,248 |
| | $ | 752 |
| | $ | 1,376 |
|
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 derivatives by counterparty master agreement level and collateral received or paid:
| | | | | | | | | | | | | | | | | | | | | | | |
| Gross Amounts Not Offset in the Statement of Financial Position |
| (In millions) | Gross Amounts of Recognized Assets/Liabilities | | Derivative Instruments | | Cash Collateral (Held)/Posted | | Net Amount |
| As of December 31, 2023 | |
| Interest rate contracts: | | | | | | | |
| Derivative assets | $ | 12 | | | $ | (8) | | | $ | — | | | $ | 4 | |
| Derivative liabilities | (8) | | | 8 | | | — | | | — | |
| Total interest rate contracts | 4 | | | — | | | — | | | 4 | |
| Foreign exchange contracts: | | | | | | | |
| Derivative assets | $ | 5 | | | $ | (5) | | | $ | — | | | $ | — | |
| Derivative liabilities | (9) | | | 5 | | | — | | | (4) | |
| Total foreign exchange contracts | $ | (4) | | | $ | — | | | $ | — | | | $ | (4) | |
| Commodity contracts: | | | | | | | |
| Derivative assets | $ | 6,138 | | | $ | (4,926) | | | $ | (74) | | | $ | 1,138 | |
| Derivative liabilities | (5,356) | | | 4,926 | | | 145 | | | (285) | |
| Total commodity contracts | $ | 782 | | | $ | — | | | $ | 71 | | | $ | 853 | |
| Consumer Financing Program: | | | | | | | |
| Derivative liabilities | $ | (134) | | | $ | — | | | $ | — | | | $ | (134) | |
| | | | | | | |
| | | | | | | |
| Total derivative instruments | $ | 648 | | | $ | — | | | $ | 71 | | | $ | 719 | |
| | Gross Amounts Not Offset in the Statement of Financial Position | | | Gross Amounts Not Offset in the Statement of Financial Position |
| (In millions) | | (In millions) | Gross Amounts of Recognized Assets/Liabilities | | Derivative Instruments | | Cash Collateral (Held)/Posted | | Net Amount |
| As of December 31, 2022 | |
| Foreign exchange contracts: | |
| Foreign exchange contracts: | |
| Foreign exchange contracts: | |
| Foreign exchange contracts: | |
| Foreign exchange contracts: | |
| Foreign exchange contracts: | |
| Foreign exchange contracts: | |
| Foreign exchange contracts: | |
| Foreign exchange contracts: | |
| Foreign exchange contracts: | |
| Foreign exchange contracts: | |
| Foreign exchange contracts: | |
| Foreign exchange contracts: | |
| Foreign exchange contracts: | |
| Foreign exchange contracts: | |
| Foreign exchange contracts: | |
| Foreign exchange contracts: | |
| Foreign exchange contracts: | |
| Foreign exchange contracts: | |
| Foreign exchange contracts: | |
| Foreign exchange contracts: | |
| Derivative assets | |
| Derivative assets | |
| Derivative assets | |
| Derivative liabilities | |
| Total foreign exchange contracts | |
| Commodity contracts: | |
| Derivative assets | |
| Derivative assets | |
| Derivative assets | |
| Derivative liabilities | |
| Total commodity contracts | |
| | | | 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, 2017 | (In millions) |
| Commodity contracts: | | | | | | | |
| Derivative assets | $ | 745 |
| | $ | (578 | ) | | $ | (11 | ) | | $ | 156 |
|
| Derivative liabilities | (693 | ) | | 578 |
| | 73 |
| | (42 | ) |
| Total commodity contracts | 52 |
|
| — |
| | 62 |
| | 114 |
|
| Interest rate contracts: | | | | | | | |
| Derivative assets | 53 |
| | (3 | ) | | — |
| | 50 |
|
| Derivative liabilities | (59 | ) | | 3 |
| | — |
| | (56 | ) |
| Total interest rate contracts | (6 | ) | | — |
| | — |
| | (6 | ) |
| Total derivative instruments | $ | 46 |
| | $ | — |
| | $ | 62 |
| | $ | 108 |
|
| | Total derivative instruments | |
| | Total derivative instruments | |
|
| | | | | | | | | | | | | | | |
| | 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 Income
The following tables summarize the effects on NRG's accumulated OCI balance attributable to cash flow hedge derivatives, net of tax:
|
| | | | | | | |
| | Year Ended December 31, 2017 |
| | Interest Rate | | Total |
| | (In millions) |
| Accumulated OCI balance at December 31, 2016 | $ | (66 | ) | | $ | (66 | ) |
| Reclassified from accumulated OCI to income: | | | |
| Due to realization of previously deferred amounts | 12 |
| | 12 |
|
| Mark-to-market of cash flow hedge accounting contracts | — |
| | — |
|
| Accumulated OCI balance at December 31, 2017, net of $8 tax | $ | (54 | ) | | $ | (54 | ) |
| Losses expected to be realized from other comprehensive loss during the next 12 months, net of $2 tax | $ | (12 | ) | | $ | (12 | ) |
|
| | | | | | | |
| | Year Ended December 31, 2016 |
| | Interest Rate | | Total |
| | (In millions) |
| Accumulated OCI balance at December 31, 2015 | $ | (101 | ) | | $ | (101 | ) |
| Reclassified from accumulated OCI to income: | | | |
| Due to realization of previously deferred amounts | 21 |
| | 21 |
|
| Mark-to-market of cash flow hedge accounting contracts | 14 |
| | 14 |
|
| Accumulated OCI balance at December 31, 2016, net of $16 tax | $ | (66 | ) | | $ | (66 | ) |
|
| | | | | | | | | | | |
| | Year Ended December 31, 2015 |
| | Energy Commodities | | Interest Rate | | Total |
| | (In millions) |
| Accumulated OCI balance at December 31, 2014 | $ | (1 | ) | | $ | (67 | ) | | $ | (68 | ) |
| Reclassified from accumulated OCI to income: | | | | | |
| Due to realization of previously deferred amounts | 1 |
| | 14 |
| | 15 |
|
| Mark-to-market of cash flow hedge accounting contracts | — |
| | (48 | ) | | (48 | ) |
| Accumulated OCI balance at December 31, 2015, net of $16 tax | $ | — |
| | $ | (101 | ) | | $ | (101 | ) |
Amounts reclassified from accumulated OCI into income are recorded to operating revenue for commodity contracts and interest expense for interest rate contracts.
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 matching 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.
Impact of Derivative Instruments on the Statement of Operations
Unrealized gains and losses associated with changes in the fair value of derivative instruments that are not accounted for as cash flow hedges are reflected in current period earnings.results of operations.
The following table summarizes the pre-tax effects of economic hedges that have not been designated as cash flow hedges or fair value hedges and trading activity on the Company's statement of operations. The effect of foreign exchange and commodity hedges is included within operating revenues and cost of operations and theoperations. The effect of the interest rate hedgescontracts are included within interest expense. The effect of the Consumer Financing Program is included in interest expense.other income, net.
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| (In millions) | 2023 | | 2022 | | 2021 |
| Unrealized mark-to-market results | | | | | |
| Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges | $ | (1,734) | | | $ | (1,232) | | | $ | (41) | |
| Reversal of acquired loss positions related to economic hedges | 20 | | | 2 | | | 256 | |
| Net unrealized (losses)/gains on open positions related to economic hedges | (1,149) | | | 2,478 | | | 2,501 | |
| Total unrealized mark-to-market (losses)/gains for economic hedging activities | (2,863) | | | 1,248 | | | 2,716 | |
| Reversal of previously recognized unrealized losses/(gains) on settled positions related to trading activity | 13 | | | 13 | | | (18) | |
| Reversal of acquired (gain) positions related to trading activity | — | | | — | | | (1) | |
| | | | | |
| Net unrealized gains/(losses) on open positions related to trading activity | 25 | | | (17) | | | (13) | |
| Total unrealized mark-to-market gains/(losses) for trading activity | 38 | | | (4) | | | (32) | |
| Total unrealized (losses)/gains - commodities and foreign exchange | $ | (2,825) | | | $ | 1,244 | | | $ | 2,684 | |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In millions) |
| Unrealized mark-to-market results | | | | | |
| Reversal of previously recognized unrealized loss/(gains) on settled positions related to economic hedges | $ | 47 |
| | $ | (128 | ) | | $ | (162 | ) |
| Reversal of acquired gain positions related to economic hedges | — |
| | (12 | ) | | (22 | ) |
| Net unrealized gains/(losses) on open positions related to economic hedges | 146 |
| | 6 |
| | (9 | ) |
| Total unrealized mark-to-market gains/(losses) for economic hedging activities | 193 |
| | (134 | ) | | (193 | ) |
| Reversal of previously recognized unrealized (gains)/losses on settled positions related to trading activity | (25 | ) | | 10 |
| | (46 | ) |
| Reversal of acquired gain positions related to trading activity | — |
| | — |
| | (14 | ) |
| Net unrealized gains/(losses) on open positions related to trading activity | 14 |
| | 18 |
| | (16 | ) |
| Total unrealized mark-to-market (losses)/gains for trading activity | (11 | ) | | 28 |
| | (76 | ) |
| Total unrealized gains/(losses) | $ | 182 |
| | $ | (106 | ) | | $ | (269 | ) |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In millions) |
| Unrealized gains/(losses) included in operating revenues | $ | 228 |
| | $ | (614 | ) | | $ | (210 | ) |
| Unrealized (losses)/gains included in cost of operations | (46 | ) | | 508 |
| | (59 | ) |
| Total impact to statement of operations — energy commodities | $ | 182 |
| | $ | (106 | ) | | $ | (269 | ) |
| Total impact to statement of operations — interest rate contracts | $ | 9 |
| | $ | 36 |
| | $ | 17 |
|
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| (In millions) | 2023 | | 2022 | | 2021 |
| Total impact to statement of operations - interest rate contracts | $ | 4 | | | $ | — | | | $ | — | |
| Unrealized gains/(losses) included in revenues - commodities | $ | 182 | | | $ | (87) | | | $ | (196) | |
| Unrealized (losses)/gains included in cost of operations - commodities | (2,988) | | | 1,315 | | | 2,880 | |
| Unrealized (losses)/gains included in cost of operations - foreign exchange | (19) | | | 16 | | | — | |
| Total impact to statement of operations - commodities and foreign exchange | $ | (2,825) | | | $ | 1,244 | | | $ | 2,684 | |
| Total impact to statement of operations - Consumer Financing Program | $ | (16) | | | $ | — | | | $ | — | |
The reversalreversals of gain or lossacquired loss/(gain) positions acquired as part of acquisitions were valued based upon the forward prices on the acquisition dates.date. The roll-off amounts were offset by realized gains or losses at the settled prices and are reflected in revenue or cost of operations during the same period.
For the year ended December 31, 2017, the $146 million gainThe loss from open economic hedge positions was primarily the result of an increase in the value of forward purchases of ERCOT heat rate contracts due to ERCOT heat rate expansion.
For$1.1 billion for the year ended December 31, 2016, the $6 million gain from economic hedge positions was primarily the result of an increase in the value of forward purchases of natural gas due to an increase in natural gas prices.
For the year ended December 31, 2015, the $9 million loss from economic hedge positions2023 was primarily the result of a decrease in the value of forward purchasespositions as a result of natural gas due to a decreasedecreases in natural gas and power prices in the East and West.
The gains from open economic hedge positions of $2.5 billion for the years ended December 31, 2022 and 2021 were primarily the result of an increase in 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 hedging and trading 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"“adequate assurance” under the agreements, or require the Company to post additional collateral if there were a one notch downgrade in the Company's credit rating. The collateral potentially required for contracts that havewith adequate assurance clauses that are in net liability positions as of December 31, 20172023 was $25 million. The collateral required for contracts with credit rating contingent features that are in a net liability position as of December 31, 2017 was $7$600 million. The Company is also a party to certain marginable agreements under which it has a net liability position, but the counterparty has not called for the collateral due, which was approximately $4$80 million as of December 31, 2017.2023. In the event of a downgrade in the Company's credit rating and
if called for by the counterparty, $8 million of additional collateral would be required for all contracts with credit rating contingent features as of December 31, 2023.
See Note 4, 5, Fair Value of Financial Instruments,, for discussion regarding concentration of credit risk.
Note 6 — 7—Nuclear Decommissioning Trust Fund
Through the sale of the Company's 44% equity interest in STP on November 1, 2023, NRG's Nuclear Decommissioning Trust Fund assets, which arewere for the decommissioning of STP, arewere comprised of securities classified as available-for-sale and recorded at fair value based on actively quoted market prices. Although NRG is responsible for managing the decommissioning of its 44% interest in STP, the predecessor utilities that owned STP are authorized by the PUCT to collect decommissioning funds from their ratepayers to cover decommissioning costs on behalf of NRG. NRC requirements determine the decommissioning cost estimate which is the minimum required level of funding. In the event that funds from the ratepayers that accumulate in the nuclear decommissioning trust are ultimately determined to be inadequate to decommission the STP facilities, the utilities will be required to collect through rates charged to rate payers all additional amounts, with no obligation from NRG, provided that NRG has complied with PUCT rules and regulations regarding decommissioning trusts. Following completion of the decommissioning, if surplus funds remain in the decommissioning trusts, any excess will be refunded to the respective ratepayers of the utilities.
NRG accountsaccounted for the Nuclear Decommissioning Trust Fund in accordance with ASC 980, Regulated Operations, or ASC 980, because the Company's nuclear decommissioning activities arewere 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 iswas in compliance with PUCT rules and regulations regarding decommissioning trusts and the cost of decommissioning iswas 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 arewere recorded to the Nuclear Decommissioning Trust liability and arewere not included in net income or accumulated other comprehensive income, consistent with regulatory treatment.
Following the sale of the Company's 44% equity interest in STP on November 1, 2023, the Company is no longer responsible for the decommissioning of STP and no longer holds the Nuclear Decommissioning Trust Fund assets. For further discussion of the sale, see Note 4, Acquisitions and Dispositions.
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 of December 31, 2022, as well as information about the contractual maturities of those securities.securities as of that date.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | As of December 31, 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) |
| Cash and cash equivalents | $ | 47 |
| | $ | — |
| | $ | — |
| | — |
| | $ | 25 |
| | $ | — |
| | $ | — |
| | — |
|
| U.S. government and federal agency obligations | 43 |
| | 1 |
| | — |
| | 11 |
| | 73 |
| | 1 |
| | — |
| | 11 |
|
| Federal agency mortgage-backed securities | 82 |
| | 1 |
| | 1 |
| | 23 |
| | 62 |
| | 1 |
| | 1 |
| | 25 |
|
| Commercial mortgage-backed securities | 13 |
| | — |
| | — |
| | 20 |
| | 17 |
| | — |
| | 1 |
| | 26 |
|
| Corporate debt securities | 99 |
| | 2 |
| | 1 |
| | 11 |
| | 84 |
| | 1 |
| | 2 |
| | 11 |
|
| Equity securities | 403 |
| | 272 |
| | — |
| | — |
| | 346 |
| | 214 |
| | — |
| | — |
|
| Foreign government fixed income securities | 5 |
| | — |
| | — |
| | 9 |
| | 3 |
| | — |
| | — |
| | 9 |
|
| Total | $ | 692 |
| | $ | 276 |
| | $ | 2 |
| | |
| | $ | 610 |
| | $ | 217 |
| | $ | 4 |
| | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | As of December 31, 2022 |
| (In millions, except otherwise noted) | | | | | | | | | Fair Value | | Unrealized Gains | | Unrealized Losses | | Weighted- average maturities (in years) |
| Cash and cash equivalents | | | | | | | | | $ | 15 | | | $ | — | | | $ | — | | | — | |
| U.S. government and federal agency obligations | | | | | | | | | 86 | | | — | | | 5 | | | 11 |
| Federal agency mortgage-backed securities | | | | | | | | | 101 | | | — | | | 11 | | | 26 |
| Commercial mortgage-backed securities | | | | | | | | | 35 | | | — | | | 4 | | | 30 |
| Corporate debt securities | | | | | | | | | 114 | | | — | | | 13 | | | 12 |
| Equity securities | | | | | | | | | 486 | | | 346 | | | 3 | | | — | |
| Foreign government fixed income securities | | | | | | | | | 1 | | | — | | | — | | | 17 |
| Total | | | | | | | | | $ | 838 | | | $ | 346 | | | $ | 36 | | | |
The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and losses from these sales.sales for the ten months ended October 31, 2023, and for the years ended December 31, 2022 and 2021. The cost of securities sold iswas determined using the specific identification method.
| | | | | | | | | | | | | | | | | |
| | | |
| (In millions) | 2023 | | 2022 | | 2021 |
| Realized gains | $ | 11 | | | $ | 14 | | | $ | 47 | |
| Realized losses | (19) | | | (25) | | | (9) | |
| Proceeds from sale of securities | 355 | | | 448 | | | 710 | |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In millions) |
| Realized gains | $ | 22 |
| | $ | 26 |
| | $ | 21 |
|
| Realized losses | 8 |
| | 11 |
| | 14 |
|
| Proceeds from sale of securities | 501 |
| | 510 |
| | 631 |
|
Note 78 — Inventory
Inventory consisted of:
| | | | | | | | | | | |
| | As of December 31, |
| (In millions) | 2023 | | 2022 |
| Fuel oil | $ | 8 | | | $ | 8 | |
| Coal | 178 | | | 114 | |
| Natural gas | 189 | | | 385 | |
| Spare parts | 68 | | | 136 | |
| Finished goods | 164 | | | 108 | |
| Total Inventory | $ | 607 | | | $ | 751 | |
|
| | | | | | | |
| | As of December 31, |
| | 2017 | | 2016 |
| | (In millions) |
| Fuel oil | $ | 90 |
| | $ | 142 |
|
| Coal/Lignite | 126 |
| | 219 |
|
| Natural gas | 24 |
| | 28 |
|
| Spare parts | 292 |
| | 332 |
|
| Total Inventory | $ | 532 |
|
| $ | 721 |
|
During the year ended December 31, 2017, the Company recorded a lower of weighted average cost or market adjustment related to fuel oil of $33 million.
Note 8 — Notes Receivable
Notes receivable consist of fixed and variable rate notes related primarily to amounts owed to the Company from transmission owners for certain projects for the financing of network upgrades. The Company's notes receivable were as follows:
|
| | | | | | | |
| | As of December 31, |
| | 2017 | | 2016 |
| | (In millions) |
| Notes receivable | $ | 16 |
| | $ | 34 |
|
Less current maturities(a) | 14 |
| | 18 |
|
| Total notes receivable — non-current | $ | 2 |
| | $ | 16 |
|
| |
(a) | The current portion of notes receivable is recorded in prepayments and other current assets on the consolidated balance sheets. |
Note 9 — Property, Plant and Equipment
The Company's major classes of property, plant, and equipment were as follows:
| | | | | | | | | | | | | | | | | |
| | As of December 31, | | Depreciable |
| (In millions) | 2023 | | 2022 | | Lives |
| Facilities and equipment | $ | 1,918 | | | $ | 1,727 | | | 1-40 years |
| Land and improvements | 256 | | | 263 | | | |
| Nuclear fuel | — | | | 271 | | | 5 years |
| Hardware and office equipment and furnishings | 732 | | | 712 | | | 2-10 years |
| Construction in progress | 152 | | | 197 | | | |
| Total property, plant, and equipment | 3,058 | | | 3,170 | | | |
| Accumulated depreciation | (1,295) | | | (1,478) | | | |
| Net property, plant, and equipment | $ | 1,763 | | | $ | 1,692 | | | |
|
| | | | | | | | | |
| | As of December 31, | | Depreciable |
| | 2017 | | 2016 | | Lives |
| | (In millions) | | |
| Facilities and equipment | $ | 15,907 |
| | $ | 18,698 |
| | 1-40 Years |
| Land and improvements | 710 |
| | 750 |
| | |
| Nuclear fuel | 236 |
| | 226 |
| | 5 Years |
| Office furnishings and equipment | 434 |
| | 412 |
| | 2-10 Years |
| Construction in progress | 1,086 |
| | 619 |
| | |
| Total property, plant, and equipment | 18,373 |
| | 20,705 |
| | |
| Accumulated depreciation | (4,465 | ) | | (5,336 | ) | | |
| Net property, plant, and equipment | $ | 13,908 |
| | $ | 15,369 |
| | |
The CompanyDepreciation expense of property, plant and equipment recorded long-lived asset impairments during the years ended December 31, 20172023, 2022 and 2016,2021 was $257 million, $291 million and $384 million, respectively.
Note 10— Leases
The Company leases generating facilities, land, office and equipment, railcars, fleet vehicles and storefront space at retail stores. Operating leases with an initial term greater than twelve months are recognized as further describedright-of-use assets and lease liabilities in Note 10, Asset Impairments.the consolidated balance sheets. The Company made an accounting policy election, as permitted by ASC 842, for all asset classes not to recognize right-of-use assets and lease liabilities in the consolidated balance sheets for its short-term leases, which are leases that have a lease term of twelve months or less. For the initial measurement of lease liabilities, the discount rate that the Company uses is either the rate implicit in the lease, if known, or its incremental borrowing rate, which is the rate of interest that the Company would have to pay to borrow, on a collateralized basis, over a similar term an amount equal to the payments for the lease. The Company recognizes lease expense for all operating leases on a straight-line basis over the lease term. In the future, should another systematic basis become more representative of the pattern in which the lessee expects to consume the remaining economic benefit of the right-of-use asset, the Company will use that basis for lease expense.
The Company considers a contract to be or to contain a lease when both of the following conditions apply: 1) an asset is either explicitly or implicitly identified in the contract and 2) the contract conveys to the Company the right to control the use of the identified asset for a period of time. The Company has the right to control the use of the identified asset when the Company has both the right to obtain substantially all the economic benefits from the use of the identified asset and the right to direct how and for what purpose the identified asset is used throughout the period of use.
Lease payments are typically fixed and payable on a monthly, quarterly, semi-annual or annual basis. Lease payments under certain agreements may escalate over the lease term either by a fixed percentage or a fixed dollar amount. Certain leases may provide for variable lease payments in the form of payments based on unit availability, usage, a percentage of sales from the location under lease, or index-based (e.g., the U.S. Consumer Price Index) adjustments to lease payments. The Company has no leases which contain residual value guarantees provided by the Company as a lessee.
Lease Cost:
| | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, |
| (In millions) | 2023 | | 2022 | | 2021 |
| Finance lease cost | $ | 8 | | | $ | 4 | | | $ | 4 | |
| Amortization of right-of-use assets | 7 | | | 4 | | | 4 | |
| Interest on lease liabilities | 1 | | | — | | | — | |
| Operating lease cost | 93 | | | 85 | | | 91 | |
| Short-term lease cost | 42 | | | 7 | | | 3 | |
| Variable lease cost | 91 | | | 86 | | | 9 | |
| Sublease income | (2) | | | (2) | | | (2) | |
| Total lease cost | $ | 232 | | | $ | 180 | | | $ | 105 | |
Other information: | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, |
| (In millions) | 2023 | | 2022 | | 2021 |
| | | | | |
| Cash paid for amounts included in the measurement of lease liabilities: | | | | | |
| Operating cash flows from operating leases | $ | 195 | | | $ | 183 | | | $ | 102 | |
| | | | | |
| Financing cash flows from finance leases | 7 | | | 5 | | | 6 | |
| Right-of-use assets obtained in exchange for new finance lease liabilities | 17 | | | 3 | | | 16 | |
| Right-of-use assets obtained in exchange for new operating lease liabilities | 52 | | | 28 | | | 47 | |
Lease Term and Discount Rate for leases: | | | | | | | | | | | |
| December 31, 2023 | | December 31, 2022 |
| Finance leases: | | | |
| Weighted average remaining lease term (in years) | 2.9 | | 2.6 |
| Weighted average discount rate | 4.87 | % | | 2.82 | % |
| | | |
| Operating leases: | | | |
| Weighted average remaining lease term (in years) | 3.6 | | 4.3 |
| Weighted average discount rate | 6.00 | % | | 5.37 | % |
As of December 31, 2023, annual payments based on the maturities of the Company's operating leases are expected to be as follows: | | | | | |
| In millions |
| 2024 | $ | 118 | |
| 2025 | 86 | |
| 2026 | 34 | |
| 2027 | 24 | |
| 2028 | 17 | |
| Thereafter | 32 | |
| Total undiscounted lease payments | $ | 311 | |
| Less: present value adjustment | (93) | |
| Total discounted lease payments | $ | 218 | |
Note 1011 — Asset Impairments
20172023 Impairment Losses
During the fourth quarter of 2017,2023, the Company completed its annual budget and revised its view of long-term power and fuel prices andanalyzed the corresponding impact on estimated cash flows associated with its long-lived assets. The most significant impactfair value of the assets was determined using an income approach by applying a decreasediscounted cash flow methodology to the long-term budget for each facility. The income approach utilized estimates of after-tax cash flows, which were Level 3 fair value measurements, and included key inputs such as forecasted power prices, fuel costs, operating and maintenance costs, plant investment capital expenditures and discount rates.
Gladstone — The Company recorded impairment losses of $102 million on its equity method investment in Gladstone within the West/Services/Other segment as a result of changes in the long-term outlook of the Gladstone facility, prompted by evolving energy policy conditions in Australia and an assessment of the long-term operational landscape of the facility, which concluded with the annual budget process. For further discussion of the Gladstone investment, see Note 17, Investments Accounted for by the Equity Method and Variable Interest Entities.
Other Impairments — The Company additionally recorded impairment losses related to property plant and equipment and leases of $2 million, $4 million and $20 million in the Texas, East and West/Services/Other segments, respectively.
2022 Impairment Losses
Astoria Redevelopment Impairment — During the third quarter of 2022, the Company entered into a purchase and sale agreement for the sale of the land and related assets at the Astoria generating site and the planned withdrawal and cancellation of its proposed Astoria redevelopment project. As a result, the Company impaired $43 million of Astoria project spend in the East segment. For further discussion of the transaction, see Note 4, Acquisitions and Dispositions.
PJM Asset Impairments — During the second quarter of 2022, the results of the PJM Base Residual Auction for the 2023/2024 delivery year were released leading the Company to revise its long-term view of certain facilities and announce the planned retirement of the Joliet generating facility. The Company considered the near-term retirement date of Joliet and the decline in PJM capacity prices to be a trigger for impairment and performed impairment tests on the PJM generating assets and the goodwill associated with Midwest Generation. The Company measured the impairment losses on the PJM generating assets and Midwest Generation goodwill as the difference between the carrying amount and the fair value of the PJM generating assets and Midwest Generation reporting unit, respectively. Fair values were determined using an income approach in which the Company applied a discounted cash flow methodology to the long-term budgets for the plants and reporting unit. Significant inputs impacting the income approach include the Company's long-term view of natural gascapacity and fuel prices, which resultedprojected generation, the physical and economic characteristics of each plant and the reporting unit as a whole, and the discount rate applied to the after-tax cash flow projections. Impairment losses of $20 million and $130 million were recorded in a reduction to long-term power prices and had a negative impactthe East segment on the Company's coal, nuclearPJM generating assets and renewable facilities. EachMidwest Generation goodwill, respectively.
Other Impairments — The Company additionally recorded impairment losses of $13 million in the facilities below hadEast segment.
2021 Impairment Losses
During the fourth quarter of 2021, the Company completed its annual budget and analyzed the corresponding impact on estimated cash flows that were lower than the carrying amount and the assets were considered impaired.
associated with its long-lived assets. The fair valuesvalue of the assets werewas determined using an income approach by applying a discounted cash flow methodology to the long-term budget for the facility. The income approach utilized estimates of discounted futureafter-tax cash flows, which were Level 3 fair value measurements, an includeand included key inputs such as forecasted power prices, nuclear fuel costs, forecasted operating and maintenance costs, plant investment capital expenditures and discount rates.
South Texas Project, or STP — TheJoliet —The Company recognized an impairment loss of $1,248$213 million related to its interest in STPthe East segment as a result of the decreasechanges in the Company's viewlong-term outlook of the Joliet facility prompted by market conditions and an assessment of various alternatives for the long-term power pricesoperational landscape of the facility including the impact of the CEJA in ERCOT.Illinois, which concluded with the annual budget process.
Indian RiverOther Impairments — The Company recognized an impairment loss of $36 million for Indian River as a result of the decrease in the Company's view of long-term power prices in PJM.
Keystone and Conemaugh — The Company recognized impairment losses of $35 million for Keystone and $35 million for Conemaugh as a result of the decrease in the Company's view of long-term power prices in PJM.
Wind Facilities — The Companyadditionally recorded impairment losses of $110 million, $26$16 million and $4$9 million for Langford, Elbow Creek and Forward, respectively, as a result of the decreaserelated to various power plants in the Company's view of long-term merchant power prices in ERCOTEast and PJM. While Elbow Creek and Forward have contracts to sell power, the significant decrease in estimated power prices had an impact on cash flows in post-contract periods.
West/Service/Other segments, respectively.
The Company also recorded the following impairmentsimpairment in 20172021 based on a specific triggering eventsevent that occurred:occurred using the same methodology previously discussed:
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 zero duringDuring 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 Long-Lived Asset Impairments — During the second, third and fourth quarters of 2017, the Company recorded impairment losses of approximately $22 million, $14 million and $15 million, respectively, in connection with the Company's Renewables business. These impairment losses were primarily to record the value of certain long-lived assets, including property, plant and equipment and intangible assets, at fair market value at acquisition date or in connection with an impairment indicator.
Petra Nova Parish Holdings — In connection with the preparation of the annual budget during the fourth quarter, management revised its view of oil production expectations with respect to Petra Nova Parish Holdings. As a result, the Company reviewed its 50% interest in Petra Nova Parish Holdings for impairment utilizing the other-than-temporary impairment model. In determining fair value, the Company utilized an income approach and considered project specific assumptions for the future project cash flows. The carrying amount of the Company's equity method investment exceeded the fair value of the investment and the Company concluded that the decline is considered to be other-than-temporary. As a result, the Company measured the impairment loss as the difference between the carrying amount and the fair value of the investment and recorded an impairment loss of $69 million.
The Company also recorded an additional $11 million in impairment losses for other investments during the fourth quarter of 2017.
2016 Impairment Losses
Rockford —As described in Note 3, Discontinued Operations, Acquisitions and Dispositions, on May 12, 2016, the Company entered into an agreement with RA Generation, LLC to sell 100% of its interests in the Rockford generating stations for cash consideration of $55 million. The transaction triggered an indicator of impairment as the sale price was less than the carrying amount of the assets, and, as a result, the assets were considered to be impaired. The Company measured the impairment loss as the difference between the carrying amount of the assets and the agreed-upon sale price. The Company recorded an impairment loss of $17 million during the year ended December 31, 2016, to reduce the carrying amount of the assets held for sale to the fair market value.
Wind Facilities — During the fourth quarter of 2016, as the Company updated its estimated future cash flows in connection with the preparation of its annual budget, the Company determined that the cash flows for the Elbow Creek and Goat Wind projects, located in Texas and the Forward project, located in Pennsylvania were below the carrying value of the related assets, primarily driven by the declining merchant power prices in post-contract periods, and the assets were considered impaired. The fair values of the facilities were determined using an income approach by applying a discounted cash flow methodology to the long-term budgets for each respective plant. The income approach utilized estimates of discounted future cash flows, which were Level 3 fair value measurements and include key inputs, such as forecasted power prices, operations and maintenance expense and discount rates. The Company measured the impairment loss as the difference between the carrying amount and the fair value of the assets and recorded impairment losses of $117 million, $60 million and $6 million for Elbow Creek, Goat Wind and Forward, respectively.
Long Beach —During the fourth quarter of 2016, the Company determined that by the end of 2017 it would retire its Long Beach generation station located in Long Beach, California. The generating station was not awarded a PPA extension in SCE's capacity auction during the fourth quarter of 2016 for the PPA set to expire on July 31, 2017. The Company considered this to be an indicator of impairment and performed an impairment test. The Company measured the impairment loss as the difference between the carrying amount and the fair value of the assets and recorded an impairment loss of $36 million. Subsequently, management decided to continue to operate in 2018, which did not significantly impact fair value.
Other Impairments — During 2016, the Company recorded other impairment losses of $153 million, which included $23 million in excess SO2 allowances, $23 million for other intangible assets, $19 million in previously purchased solar panels, $18 million in deferred marketing expenses, $22 million in other investments and $48 million of other impairment losses.
Petra Nova Parish Holdings —During the first quarter of 2016, management changed its plans with respect to its future capital commitments driven in part by the continued decline in oil prices. As a result, the Company reviewed its 50% interest in Petra Nova Parish Holdings for impairment utilizing the other-than-temporary impairment model. In determining fair value, the Company utilized an income approach and considered project specific assumptions for the future project cash flows. The carrying amount of the Company's equity method investment exceeded the fair value of the investment and the Company concluded that the decline is considered to be other-than-temporary. As a result, the Company measured the impairment loss as the difference between the carrying amount and the fair value of the investment and recorded an impairment loss of $140 million.
Community Wind North and Sherbino —During the fourth quarter of 2016, the Company offered several projects to NRG Yield including its interest in Community Wind North. The offer price was below its current carrying amount and this decline in fair value was determined to be other-than-temporary. Accordingly, the Company recorded an impairment loss of $36 million to reduce its carrying amount to fair value. In addition, in connection with the preparation of the annual budget, the Company noted that due to the anticipated difficulty in refinancing Sherbino’s debt that will mature in 2018, the project’s fair value had decreased significantly below its carrying amount and this decline was determined to be other-than-temporary. Accordingly, the Company determined that an other-than-temporary impairment existed and recorded an impairment loss on its investment in Sherbino of $70 million.
2015 Impairment Losses
Limestone and W.A. Parish —During the fourth quarter of 2015, as the Company updated its estimates of future cash flows in connection with the preparation of its annual budget, it was noted that the cash flows for the Limestone and W.A. Parish coal-fired facilities located in Texas were lower than the carrying amount, primarily driven by declining power prices as the cost of commodities continues to decline and the assets were impaired. The fair value of the Limestone and W.A. Parish plants was determined using an income approach by applying a discounted cash flow methodology to the long-term budgets for each respective plant. The income approach utilized estimates of discounted future cash flows, which were Level 3 fair value measurements, and include key inputs such as forecasted power prices, fuel costs and emissions credit expense, forecasted operating and capital expenditures and discount rates. The Company measured the impairment loss as the difference between the carrying amount and the fair value of the assets and recognized impairment losses of $1,514 million and $1,295 million related to Limestone and W.A. Parish, respectively.
Huntley —On August 25, 2015, the Company filed a notice with the NYSPSC of its intent to retire Huntley's operating units on March 1, 2016. The Company considered this to be an indicator of impairment and performed an impairment test for these assets under ASC 360, Property, Plant and Equipment. On October 14, 2015, the Company filed a cost-of-service filing at FERC in anticipation that the Huntley operating units would be needed for reliability purposes, proposing a reliability must run service agreement for a four-year period beginning on March 1, 2016. On October 30, 2015, NYISO released2021, the results of the PJM Base Residual Auction for the 2022/2023 delivery year were released leading the Company to announce the near-term retirement of a significant portion of its reliability study, indicating that the Huntley operating units are not needed for bulk system reliability.PJM coal generating assets in June 2022. The Company considered the impactdecline in PJM capacity prices and the near-term retirement dates of certain assets to be a trigger for impairment and performed impairment tests on the reliability study conductedPJM generating assets and evaluated the estimated cash flowsgoodwill associated with Midwest Generation. Impairment losses of $271 million and $35 million were recorded in the facility. Accordingly,East segment on the Company determined that the carrying amount of the assets was higher than the estimated future net cash flows expected to be generated by thePJM generating assets and thatMidwest Generation goodwill, respectively.
Note 12 — Goodwill and Other Intangibles
Goodwill
The table below presents the assets were impaired. The fair valuechanges of goodwill for the Huntley operating units was determined using the income approach. The income approach utilized estimates of discounted future cash flows, which were Level 3 fair value measurements, and include key inputs such as forecasted contract prices, forecasted operating expenses and discount rates. The Company recorded an impairment loss of $132 million during the yearyears ended December 31, 2015.
Dunkirk —The Company signed a ten-year agreement in November 2014 with National Grid to add natural gas-burning capabilities at the Dunkirk facility. On August 25, 2015, NRG announced that Dunkirk Unit 2 would be mothballed2023 and 2022 based on January 1, 2016 at the expiration of its reliability support services agreement. The project to add natural gas-burning capabilities has been suspended, pending the outcome of litigation with respect to the gas addition contract and its validity. On October 30, 2015, NYISO released the results of its reliability study, indicating that the Dunkirk facility is not needed for system reliability. In connection with the planned mothball of the facility, the pending litigation and the latest reliability assessment completed by NYISO, the Company evaluated whether the related fixed assets were impaired. The Company determined that the carrying amount of the assets was higher than the estimated future net cash flows expected to be generated by the assets and that the assets were impaired. The fair value of the Dunkirk facility was determined using the income approach. The income approach utilized estimates of discounted future cash flows, which were Level 3 fair value measurements, and include key inputs such as forecasted contract prices, forecasted operating and capital expenditures and discount rates. The Company recorded an impairment loss of $160 million during the year ended December 31, 2015.
Gregory — During the fourth quarter of 2015, the Company determined that the carrying amount of the assets was higher than the estimated future net cash flows expected to be generated by the assets and that the assets were impaired. The fair value of the Gregory facility was determined using the income approach, which utilized estimates of discounted future cash flows, which were Level 3 fair value measurements, and include key inputs such as forecasted prices, operating and capital expenditures and discount rates. The Company recorded an impairment loss of $176 million during the year ended December 31, 2015.
Solar Panels —During the fourth quarter of 2015, the Company recorded an impairment loss of $29 million to reduce the carrying value of certain solar panels to their approximate fair value.
Investments —During the fourth quarter of 2015, the Company reviewed certain of its cost method and equity method investments and concluded that losses incurred by these investments were other-than-temporary. These losses were primarily driven by the sustained decline in stock price of a publicly traded investment as well as change in financing structures of certain non-publicly traded investments. As a result, the Company recorded losses related to these investments of $56 million.
Note 11 — Goodwill and Other Intangibles
Goodwill
NRG's goodwill balance was $539 million and $662 million as of December 31, 2017 and 2016, respectively. As of December 31, 2017, and 2016, NRG had approximately $460 million and $547 million, respectively, of goodwill that is deductible for U.S. income tax purposes in future periods. As of December 31, 2017, goodwill consisted of $165 million associated with the acquisition of EME, $341 million for Retail business acquisitions, and $33 million associated with other business acquisitions.
2017Impairments of Goodwill
BETM — During the fourth quarter of 2017, the Company concluded that BETM was held for sale in connection with board approval and advanced negotiations to sell the business. Accordingly, the Company recorded the assets and liabilities at fair market value as of December 31, 2017, which resulted in an impairment loss of $90 million to record BETM’s goodwill at fair market value. The remaining goodwill balance for BETM of $21 million is included within non-current assets held-for-sale as of December 31, 2017.
SPP — During the fourth quarter of 2017, NRG sold its interests in certain SPP projects to NRG Yield. The goodwill recorded during the SPP acquisition was related primarily to its development pipeline, which was not sold to NRG Yield. As the Company does not expect to separately develop these projects and accordingly, has no cash flow stream associated with the goodwill, an impairment loss of $12 million was recorded to reduce the value to zero as of December 31, 2017.
2016Impairments of Goodwill
During the year ended December 31, 2016, the Company recorded a goodwill impairment charge of $337 million related to its Texas reporting unit, reducing the goodwill balance for Texas to zero.
In connection with the annual impairment assessment, the Company performed step one of the two-step impairment test for the Texas reporting unit, for which $1.7 billion of goodwill was recognized as part of the Texas Genco acquisition in 2006 and $1.4 billion was written off in 2015. The Company determined the fair value of the Texas reporting unit primarily using an income approach through which the Company applied a discounted cash flow methodology to the long-term budgets for all plants in the regions. Significant inputs impacting the income approach include the Company's views of power and fuel prices for the first five-year period and the Company's view for the longer term, which were finalized in connection with the preparation of the fourth quarter financial statements, projected generation based on an hourly dispatch meant to simulate the dispatch of each unit into the power market which is impacted by power prices, fuel prices, and the physical and economic characteristics of each plant, intangible value to Texas for synergies it provides to NRG's retail businesses, and the discount rate applied to cash flow projections. Under step one, the estimated fair value of the Texas invested capital was 43% below its carrying value as of December 31, 2016, and the Company concluded step two was required. Based on the results of step two of the impairment test, the Company determined the carrying amount of the reporting unit was higher than the fair value, and accordingly, the Company recognized an impairment loss of $337 million as of December 31, 2016.reportable segments.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (in millions) | Texas | | East | | West/Services/Other | | Vivint Smart Home | | Total |
| Balance as of January 1, 2022 | $ | 716 | | | $ | 853 | | | $ | 226 | | | $ | — | | | $ | 1,795 | |
| | | | | | | | | |
| Impairment losses | — | | | (130) | | | — | | | — | | | (130) | |
| Asset sales | (6) | | | — | | | — | | | — | | | (6) | |
| Foreign currency translation | — | | | — | | | (9) | | | — | | | (9) | |
| Balance as of December 31, 2022 | $ | 710 | | | $ | 723 | | | $ | 217 | | | $ | — | | | $ | 1,650 | |
| Goodwill resulted from the acquisition of Vivint | — | | | — | | | — | | | 3,494 | | | 3,494 | |
| | | | | | | | | |
| Asset sales | (67) | | | (2) | | | — | | | — | | | (69) | |
| Foreign currency translation | — | | | — | | | 4 | | | — | | | 4 | |
| Balance as of December 31, 2023 | $ | 643 | | | $ | 721 | | | $ | 221 | | | $ | 3,494 | | | $ | 5,079 | |
Intangible Assets
The Company's intangible assets as of December 31, 2017,2023, primarily reflect intangible assets established with the acquisitions of various companies, including Vivint Smart Home, Direct Energy, Stream Energy, other retail acquisitions and Texas Genco. Intangible assets are comprised of the following:
| |
• | Emission Allowances — These intangibles primarily consist of SO2•Emission Allowances — These intangibles primarily consist of SO2 emission allowances, including those established with the 2006 acquisition of Texas Genco, RGGI emission credits and California carbon allowances. These emission allowances are held-for-use and are amortized to cost of operations based on units of production. •Customer and NOx emission allowances established with the 2006 Texas Genco acquisition and also include RGGI emission credits which NRG began purchasing in 2009. These emission allowances are held-for-use and are amortized to cost of operations, with NOx allowances amortized on a straight-line basis and SO2 allowances and RGGI credits amortized based on units of production. During the year ended December 31, 2017, the Company recorded an impairment loss of $20 million to reduce the value of excess SO2 allowances to zero. |
Energy supply contracts— Established with the acquisitions of Reliant Energy and Green Mountain Energy, these representThese intangibles include the fair value at the acquisition date of in-market and out-of-market customer and supply contracts forfrom the purchaseacquisition of energy to serve retail electric customers. The contracts are amortized to cost of operations based on the expected delivery under the respective contracts.
In-market fuel (gas and nuclear) contracts — These intangibles were established with the Texas Genco acquisition in 2006Direct Energy and are amortized to revenue and cost of operations, over expected volumes over the life of each contract.
Customer contracts — Established with the acquisitions of Reliant Energy, Green Mountain Energy, and Northwind Phoenix, these intangibles representrespectively, based upon the fair market value, atas of the acquisition date, of contracts that primarily provide electricity to Reliant Energy's and Green Mountain Energy's C&I customers. These contracts are amortized to revenues based on expected volumes to be delivered for the portfolio.
each delivery month.•Customer relationships — These intangibles represent the fair value at the acquisition date of acquired businesses' customer base primarily for Dominion,from the acquisition of Vivint, Direct Energy Alternatives, Energy Plus, Reliant Energy, Green Mountain Energy, Energy Systems, Energy Curtailment Specialists, and Source Power & Gas. The customerother acquisitions. Customer relationships are amortized to depreciation and amortization expense based on the expected discounted future net cash flows by year.
•Marketing partnerships — Established with the acquisition of Energy Plus, theseThese intangibles represent the fair value at the acquisition date of existing agreements with marketing vendors and loyalty and affinity partners. The marketingpartners for customer acquisition. Marketing partnerships are amortized to depreciation and amortization expense based on the expected discounted future net cash flows by year.
•Technology — These intangibles represent the fair value at the acquisition date of developed technology for Vivint Smart Home integrated software and products. Technology is amortized to depreciation and amortization expense, ratably based on the expected discounted future net cash flows by year.
•Trade names — Established with the Reliant Energy, Green Mountain, Energy Plus and Dominion acquisitions, theseThese intangibles are amortized to depreciation and amortization expense on a straight-line basis.
Power purchase agreements•Other — Established predominantly withThese intangibles primarily include renewable energy credits. RECs are retired, as required, for the EME and Alta Wind acquisitions, these representapplicable compliance period. RECs are expensed to cost of operations based on NRG’s customer usage. Other also included in-market nuclear fuel contracts established from the fair value of PPAs acquired. These will beTexas Genco acquisition in 2006 which were amortized to revenues, generally on a straight-line basis,cost of operations over expected volumes over the termslife of the PPAs. During the year ended December 31, 2017, the Company recorded an impairment loss of $6 million related to PPAs.
Other — Consists of renewable energy credits, wind leasehold rights,each contract, costs to extend the operating license for STP Units 1 and 2 and the intangible assetsintellectual property related to purchased ground leases.
Goal Zero, which is amortized to depreciation and amortization expense.
The following tables summarize the components of NRG's intangible assetsassets:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2023 | Emission Allowances | | Customer and Supply Contracts | | | | Customer Relationships | | Marketing Partnerships | | Technology | | Trade Names | | Other(a) | | Total |
| January 1, 2023 | $ | 624 | | | $ | 635 | | | | | $ | 1,730 | | | $ | 284 | | | $ | — | | | $ | 679 | | | $ | 292 | | | $ | 4,244 | |
| Purchases | 10 | | | — | | | | | — | | | — | | | — | | | — | | | 465 | | | 475 | |
Acquisition of businesses(b) | — | | | — | | | | | 1,773 | | | 10 | | | 860 | | | 160 | | | — | | | 2,803 | |
| Usage/Sales/Retirements | — | | | — | | | | | — | | | — | | | — | | | — | | | (474) | | | (474) | |
| Write-off of fully amortized balances | (1) | | | (28) | | | | | (43) | | | — | | | — | | | — | | | — | | | (72) | |
Sale of STP(c) | — | | | — | | | | | — | | | — | | | — | | | — | | | (59) | | | (59) | |
| | | | | | | | | | | | | | | | | |
| Other | (5) | | | 2 | | | | | 4 | | | 1 | | | — | | | 2 | | | — | | | 4 | |
| December 31, 2023 | 628 | | | 609 | | | | | 3,464 | | | 295 | | | 860 | | | 841 | | | 224 | | | 6,921 | |
| Less accumulated amortization | (533) | | | (328) | | | | | (1,300) | | | (170) | | | (230) | | | (401) | | | (32) | | | (2,994) | |
| Net carrying amount | $ | 95 | | | $ | 281 | | | | | $ | 2,164 | | | $ | 125 | | | $ | 630 | | | $ | 440 | | | $ | 192 | | | $ | 3,927 | |
(a)RECs are not subject to amortization:amortization and had a carrying value of $177 million
(b)The weighted average amortization period for total amortizable intangible assets is approximately 10 years. See Note 4, Acquisitions and Dispositions, for weighted average life of acquired amortizable intangibles for each intangible asset type
(c)Includes $47 million of intangibles that were amortized
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | | | | | | | | | | | | | | | |
| Year Ended December 31, 2022 | Emission Allowances | | Customer and Supply Contracts | | | | Customer Relationships | | Marketing Partnerships | | Trade Names | | Other(a) | | Total |
| January 1, 2022 | $ | 634 | | | $ | 638 | | | | | $ | 1,679 | | | $ | 284 | | | $ | 683 | | | $ | 229 | | | $ | 4,147 | |
| Purchases | 26 | | | — | | | | | — | | | — | | | — | | | 404 | | | 430 | |
Acquisition of businesses(b) | — | | | — | | | | | 55 | | | — | | | — | | | — | | | 55 | |
| Usage/Retirements | (33) | | | — | | | | | — | | | — | | | — | | | (341) | | | (374) | |
| Write-off of fully amortized balances | (14) | | | — | | | | | — | | | — | | | — | | | — | | | (14) | |
| | | | | | | | | | | | | | | |
| Other | 11 | | | (3) | | | | | (4) | | | — | | | (4) | | | — | | | — | |
| December 31, 2022 | 624 | | | 635 | | | | | 1,730 | | | 284 | | | 679 | | | 292 | | | 4,244 | |
| Less accumulated amortization | (528) | | | (235) | | | | | (787) | | | (146) | | | (341) | | | (75) | | | (2,112) | |
| Net carrying amount | $ | 96 | | | $ | 400 | | | | | $ | 943 | | | $ | 138 | | | $ | 338 | | | $ | 217 | | | $ | 2,132 | |
(a)RECs are not subject to amortization and had a carrying value of $186 million
(b)The weighted average life of acquired amortizable intangibles was six years for customer relationships
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Contracts | | | | | | | | | | | | |
| Year Ended December 31, 2017 | Emission Allowances | | Energy
Supply | | Fuel | | Customer | | Customer Relationships | | Marketing Partnerships | | Trade Names | | PPA | | Other | | Total |
| | (In millions) |
| January 1, 2017 | $ | 789 |
| | $ | 54 |
| | $ | 72 |
| | $ | 16 |
| | $ | 816 |
| | $ | 88 |
| | $ | 342 |
| | $ | 1,286 |
| | $ | 198 |
| | $ | 3,661 |
|
| Purchases | 31 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 32 |
| | 63 |
|
| Acquisition of businesses | — |
| | — |
| | — |
| | — |
| | 18 |
| | — |
| | — |
| | — |
| | — |
| | 18 |
|
| Usage | (10 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (28 | ) | | (38 | ) |
Write-off of fully amortized balances(a) | — |
| | (54 | ) | | (23 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (77 | ) |
| Impairment | (20 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (6 | ) | | — |
| | (26 | ) |
| Other | (23 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 5 |
| | (19 | ) | | (37 | ) |
| December 31, 2017 | 767 |
| | — |
| | 49 |
| | 16 |
| | 834 |
| | 88 |
| | 342 |
| | 1,285 |
| | 183 |
| | 3,564 |
|
| Less accumulated amortization | (591 | ) | | — |
| | (45 | ) | | (9 | ) | | (698 | ) | | (54 | ) | | (182 | ) | | (205 | ) | | (34 | ) | | (1,818 | ) |
| Net carrying amount | $ | 176 |
| | $ | — |
| | $ | 4 |
| | $ | 7 |
| | $ | 136 |
| | $ | 34 |
| | $ | 160 |
| | $ | 1,080 |
| | $ | 149 |
| | $ | 1,746 |
|
(a) Adjusted for write-off of fully amortized energy supply contracts of $54 million and fuel contracts of $23 million. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Contracts | | | | | | | | | | | | |
| Year Ended December 31, 2016 | Emission Allowances | | Energy Supply | | Fuel | | Customer | | Customer Relationships | | Marketing Partnerships | | Trade Names | | PPA | | Other | | Total |
| | (In millions) |
| January 1, 2016 | $ | 816 |
| | $ | 54 |
| | $ | 72 |
| | $ | 16 |
| | $ | 834 |
| | $ | 88 |
| | $ | 342 |
| | $ | 1,286 |
| | $ | 213 |
| | $ | 3,721 |
|
| Purchases | 13 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 34 |
| | 47 |
|
| Acquisition of businesses | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | | 18 |
| | 18 |
|
| Usage | (1 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (44 | ) | | (45 | ) |
Write-off of fully amortized balances(a) | (10 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (10 | ) |
Impairment(b) | (23 | ) | | — |
| | — |
| | — |
| | (18 | ) | | — |
| | — |
| | — |
| | (23 | ) | | (64 | ) |
| Other | (6 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (6 | ) |
| December 31, 2016 | 789 |
| | 54 |
| | 72 |
| | 16 |
| | 816 |
| | 88 |
| | 342 |
| | 1,286 |
| | 198 |
| | 3,661 |
|
| Less accumulated amortization | (518 | ) | | (54 | ) | | (67 | ) | | (8 | ) | | (663 | ) | | (49 | ) | | (159 | ) | | (143 | ) | | (27 | ) | | (1,688 | ) |
| Net carrying amount | $ | 271 |
| | $ | — |
| | $ | 5 |
| | $ | 8 |
| | $ | 153 |
|
| $ | 39 |
|
| $ | 183 |
| | $ | 1,143 |
| | $ | 171 |
|
| $ | 1,973 |
|
(a) Adjusted for write-off of fully amortized emission allowances of $10 million.(b) The impairment of customer relationships and other intangibles included a write-off of accumulated amortization of $10 million and $8 million, respectively.
The following table presents NRG's amortization of intangible assets for each of the past three years:
| | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| (In millions) | 2023 | | 2022 | | 2021 |
| Emission allowances | $ | 6 | | | $ | 6 | | | $ | 24 | |
| Customer and supply contracts | 121 | | | 141 | | | 66 | |
| Customer relationships | 556 | | | 269 | | | 327 | |
| Marketing partnerships | 24 | | | 23 | | | 24 | |
| Technology | 230 | | | — | | | — | |
| Trade names | 60 | | | 47 | | | 47 | |
Other(a) | 4 | | | 4 | | | 7 | |
| Total amortization | $ | 1,001 | | | $ | 490 | | | $ | 495 | |
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| Amortization | 2017 | | 2016 | | 2015 |
| | (In millions) |
| Emission allowances | $ | 73 |
| | $ | 66 |
| | $ | 60 |
|
| Energy supply contracts | — |
| | 7 |
| | 5 |
|
| Fuel contracts | 1 |
| | 2 |
| | 2 |
|
| Customer contracts | 1 |
| | 2 |
| | 2 |
|
| Customer relationships | 35 |
| | 49 |
| | 67 |
|
| Marketing partnerships | 5 |
| | 8 |
| | 14 |
|
| Trade names | 23 |
| | 22 |
| | 23 |
|
| Power purchase agreements | 62 |
| | 64 |
| | 51 |
|
| Other | 7 |
| | 11 |
| | 14 |
|
| Total amortization | $ | 207 |
| | $ | 231 |
| | $ | 238 |
|
The following table presents estimated amortization of NRG's intangible assets as of December 31, 2023 for each of the next five years:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | | | | | | | | | | | | | | | | | |
| Year Ended December 31, | Emission Allowances | | | | Customer and Supply Contracts | | Customer Relationships | | Marketing Partnerships | | Technology | | Trade Names | | Other | | Total |
| 2024 | $ | 17 | | | | | $ | 73 | | | $ | 478 | | | $ | 24 | | | $ | 227 | | | $ | 54 | | | $ | 3 | | | $ | 876 | |
| 2025 | 14 | | | | | 50 | | | 371 | | | 23 | | | 176 | | | 47 | | | 3 | | | 684 | |
| 2026 | 9 | | | | | 52 | | | 300 | | | 23 | | | 130 | | | 39 | | | 3 | | | 556 | |
| 2027 | 8 | | | | | 30 | | | 233 | | | 23 | | | 89 | | | 39 | | | 3 | | | 425 | |
| 2028 | 9 | | | | | 13 | | | 189 | | | 15 | | | 9 | | | 39 | | | 2 | | | 276 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Contracts | | | | | | | | | | | | |
| Year Ended December 31, | Emission Allowances | | Fuel | | Customer | | Customer Relationships | | Marketing Partnerships | | Trade Names | | PPA | | Other | | Total |
| | (In millions) |
| 2018 | $ | 33 |
| | $ | 1 |
| | $ | 1 |
| | $ | 25 |
| | $ | 5 |
| | $ | 22 |
| | $ | 64 |
| | $ | 8 |
| | $ | 159 |
|
| 2019 | 30 |
| | — |
| | 1 |
| | 21 |
| | 4 |
| | 22 |
| | 64 |
| | 8 |
| | 150 |
|
| 2020 | 16 |
| | — |
| | 1 |
| | 17 |
| | 4 |
| | 22 |
| | 64 |
| | 8 |
| | 132 |
|
| 2021 | 16 |
| | — |
| | 1 |
| | 13 |
| | 4 |
| | 22 |
| | 64 |
| | 8 |
| | 128 |
|
| 2022 | 15 |
| | — |
| | 1 |
| | 7 |
| | 3 |
| | 22 |
| | 64 |
| | 8 |
| | 120 |
|
Intangible assets held for saleheld-for-sale — From time to time, management may authorize the transfer from the Company's emission bank of emission allowances held-for-use to intangible assets held-for-sale. Emission allowances held-for-sale are included in other non-current assets on the Company's consolidated balance sheet and are not amortized, but rather expensed as sold. As of December 31, 2017,2023 and 2022, the value of emission allowances held-for-sale is $9was $4 million and is managed$8 million, respectively, within the Corporate segment. Once transferred to held-for-sale, these emission allowances are prohibited from moving back to held-for-use.
Out-of-market contracts — Due primarily to business acquisitions, NRG acquired certain out-of-market contracts, which are classified as non-current liabilities on NRG's consolidated balance sheet. These include out-of-market lease contracts of $159 million acquired in the acquisition of EME. These out-of-market contracts are amortized to cost of operations. As of December 31, 2017 and 2016, the Company had accumulated amortization for out-of-market contracts of $358 million and $457 million, respectively.
The following table summarizes the estimated amortization related to NRG's out-of-market contracts:
|
| | | | | | | | | | | |
| Year Ended December 31, | Power Contracts | | Leases | | Total |
| | (In millions |
| 2018 | $ | 16 |
| | $ | 9 |
| | $ | 25 |
|
| 2019 | 16 |
| | 9 |
| | 25 |
|
| 2020 | 17 |
| | 9 |
| | 26 |
|
| 2021 | 14 |
| | 9 |
| | 23 |
|
| 2022 | 1 |
| | 9 |
| | 10 |
|
Note 1213 — Long-term Debt and CapitalFinance Leases
Long-term debt and capitalfinance leases consisted of the following:
| | | | | | | | | | | | | | | | | |
| As of December 31, | | |
| (In millions, except rates) | 2023 | | 2022 | | Interest rate % |
| Recourse debt: | | | | | |
| Senior Notes, due 2027 | $ | 375 | | | $ | 375 | | | 6.625 |
| Senior Notes, due 2028 | 821 | | | 821 | | | 5.750 |
| Senior Notes, due 2029 | 733 | | | 733 | | | 5.250 |
| Senior Notes, due 2029 | 500 | | | 500 | | | 3.375 |
| Senior Notes, due 2031 | 1,030 | | | 1,030 | | | 3.625 |
| Senior Notes, due 2032 | 480 | | | 1,100 | | | 3.875 |
Convertible Senior Notes, due 2048(a) | 575 | | | 575 | | | 2.750 |
| Senior Secured First Lien Notes, due 2024 | 600 | | | 600 | | | 3.750 |
| Senior Secured First Lien Notes, due 2025 | 500 | | | 500 | | | 2.000 |
| Senior Secured First Lien Notes, due 2027 | 900 | | | 900 | | | 2.450 |
| Senior Secured First Lien Notes, due 2029 | 500 | | | 500 | | | 4.450 |
| Senior Secured First Lien Notes, due 2033 | 740 | | | — | | | 7.000 |
| | | | | |
| Tax-exempt bonds | 466 | | | 466 | | | 1.250 - 4.750 |
| Subtotal recourse debt | 8,220 | | | 8,100 | | | |
| Non-recourse debt: | | | | | |
| Vivint Smart Home Senior Notes, due 2029 | 800 | | | — | | | 5.750 |
| Vivint Smart Home Senior Secured Notes, due 2027 | 600 | | | — | | | 6.750 |
| Vivint Smart Home Senior Secured Term Loan, due 2028 | 1,320 | | | — | | | SOFR + 3.51 |
| Subtotal all non-recourse debt | 2,720 | | | — | | | |
| Subtotal long-term debt (including current maturities) | 10,940 | | | 8,100 | | | |
| Finance leases | 19 | | | 11 | | | various |
| Subtotal long-term debt and finance leases (including current maturities) | 10,959 | | | 8,111 | | | |
| Less current maturities | (620) | | | (63) | | | |
| Less debt issuance costs | (60) | | | (70) | | | |
| Discounts | (146) | | | (2) | | | |
| Total long-term debt and finance leases | $ | 10,133 | | | $ | 7,976 | | | |
|
| | | | | | | | | |
| (In millions, except rates) | December 31, | | December 31, 2017 |
| | 2017 | | 2016 | | Interest Rate % (a) |
| Recourse debt: | | | | | |
| Senior notes, due 2018 | $ | — |
| | $ | 398 |
| | 7.625 |
| Senior notes, due 2021 | — |
| | 207 |
| | 7.875 |
| Senior notes, due 2022 | 992 |
| | 992 |
| | 6.250 |
| Senior notes, due 2023 | — |
| | 869 |
| | 6.625 |
| Senior notes, due 2024 | 733 |
| | 733 |
| | 6.250 |
| Senior notes, due 2026 | 1,000 |
| | 1,000 |
| | 7.250 |
| Senior notes, due 2027 | 1,250 |
| | 1,250 |
| | 6.625 |
| Senior notes, due 2028 | 870 |
| | — |
| | 5.750 |
| Term loan facility, due 2023 | 1,872 |
| | 1,891 |
| | L+2.25 |
| Tax-exempt bonds | 465 |
| | 455 |
| | 4.125 - 6.00 |
| Subtotal recourse debt | 7,182 |
| | 7,795 |
| | |
| Non-recourse debt: | | | | | |
| NRG Yield Operating LLC Senior Notes, due 2024 | 500 |
| | 500 |
| | 5.375 |
| NRG Yield Operating LLC Senior Notes, due 2026 | 350 |
| | 350 |
| | 5.000 |
| NRG Yield, Inc. Convertible Senior Notes, due 2019 | 345 |
| | 345 |
| | 3.500 |
| NRG Yield, Inc. Convertible Senior Notes, due 2020 | 288 |
| | 288 |
| | 3.250 |
NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility, due 2019 (b) | 55 |
| | — |
| | L+2.500 |
| El Segundo Energy Center, due 2023 | 400 |
| | 443 |
| | L+1.75 - L+2.375 |
| Marsh Landing, due 2023 | 318 |
| | 370 |
| | L+1.875 |
| Alta Wind I - V lease financing arrangements, due 2034 and 2035 | 926 |
| | 965 |
| | 5.696 - 7.015 |
| Walnut Creek, term loans due 2023 | 267 |
| | 310 |
| | L+1.625 |
| Utah Portfolio, due 2022 | 278 |
| | 287 |
| | L+2.625 |
| Tapestry, due 2021 | 162 |
| | 172 |
| | L+1.625 |
| CVSR, due 2037 | 746 |
| | 771 |
| | 2.339 - 3.775 |
| CVSR HoldCo, due 2037 | 194 |
| | 199 |
| | 4.680 |
| Alpine, due 2022 | 135 |
| | 145 |
| | L+1.750 |
| Energy Center Minneapolis, due 2025 | 83 |
| | 96 |
| | 3.55 - 5.95 |
| Energy Center Minneapolis, due 2031 | 125 |
| | 125 |
| | 3.55 |
| Viento, due 2023 | 163 |
| | 178 |
| | L+3.00 |
| NRG Yield - other | 579 |
| | 603 |
| | various |
Subtotal NRG Yield debt (non-recourse to NRG) (c) | 5,914 |
| | 6,147 |
| | |
| Ivanpah, due 2033 and 2038 | 1,073 |
| | 1,113 |
| | 2.285 - 4.256 |
Carlsbad Energy Project (c) | 427 |
| | — |
| | L+1.625 -.04120 |
| Agua Caliente, due 2037 | 818 |
| | 849 |
| | 2.395 - 3.633 |
| Agua Caliente Borrower 1, due 2038 | 89 |
| | — |
| | 5.430 |
Cedro Hill, due 2029 (c) | 151 |
| | 163 |
| | L+1.75 |
| Midwest Generation, due 2019 | 152 |
| | 231 |
| | 4.390 |
NRG Other Renewables (c) | 647 |
| | 269 |
| | |
| NRG Other | 180 |
| | 137 |
| | various |
| Subtotal other non-recourse debt | 3,537 |
| | 2,762 |
| | |
| Subtotal all non-recourse debt | 9,451 |
| | 8,909 |
| | |
| Subtotal long-term debt (including current maturities) | 16,633 |
| | 16,704 |
| | |
| Capital leases | 5 |
| | 6 |
| | various |
| Subtotal long-term debt and capital leases (including current maturities) | 16,638 |
| | 16,710 |
| | |
| Less current maturities | (688 | ) | | (516 | ) | | |
| Less debt issuance costs | (204 | ) | | (188 | ) | | |
| Discounts | (30 | ) | | (49 | ) | | |
| Total long-term debt and capital leases | $ | 15,716 |
| | $ | 15,957 |
| | |
| |
(a) | As of December 31, 2017, L+ equals 3 month LIBOR plus x%, except for the Utah Solar Portfolio where L+ equals 1 month LIBOR plus 2.629%.
|
| |
(b) | Applicable rate is determined by the Borrower Leverage Ratio, as defined in the credit agreement |
| |
(c) | Debt associated with the asset sales announced in February 2018 |
(a)As of the ex-dividend date of January 31, 2024, the Convertible Senior Notes were convertible at a price of $41.53, which is equivalent to a conversion rate of approximately 24.0763 shares of common stock per $1,000 principal amount
Long-term debtDebt includes the following discounts: | | | | | | | | | | | | | | |
| | As of December 31, |
| (In millions) | | 2023 | | 2022 |
| Senior Secured First Lien Notes, due 2024, 2025, 2027, 2029 and 2033 | | $ | (10) | | | $ | (2) | |
| Vivint Smart Home Senior Notes, due 2029 | | (103) | | | — | |
| Vivint Smart Home Senior Secured Notes, due 2027 | | (12) | | | — | |
| Vivint Smart Home Senior Secured Term Loan, due 2028 | | (21) | | | — | |
| Total discounts | | $ | (146) | | | $ | (2) | |
|
| | | | | | | | |
| | | As of December 31, |
| | | 2017 | | 2016 |
| | | (In millions) |
Term loan facility, due 2023 (a) | | $ | (7 | ) | | $ | (9 | ) |
| Yield, Inc. Convertible notes, due 2019 | | (5 | ) | | (10 | ) |
| Yield, Inc. Convertible notes, due 2020 | | (13 | ) | | (17 | ) |
| Midwest Generation, due 2019 | | (5 | ) | | (13 | ) |
| Total discounts | | $ | (30 | ) | | $ | (49 | ) |
| |
(a) | Term loan facility, due 2018 replaced with the Term loan facility due 2023. Discount of $1 million was related to current maturities in 2016. |
Consolidated Annual Maturities
AnnualAs of December 31, 2023, annual payments based on the maturities of NRG's debt and finance leases are expected to be as follows:
| | | | | |
| | (In millions) |
| 2024 | $ | 620 | |
| 2025 | 769 | |
| 2026 | 16 | |
| 2027 | 1,890 | |
| 2028 | 2,145 | |
| Thereafter | 5,519 | |
| Total | $ | 10,959 | |
Recourse Debt
Revolving Credit Facility
On February 14, 2023 (the “Revolving Credit Facility Sixth Amendment Effective Date”), the Company amended its Revolving Credit Facility to: (i) increase the existing revolving commitments thereunder by $600 million (the “Initial Incremental Commitment”), (ii) extend the maturity date of a portion of the revolving commitments thereunder to February 14, 2028, (iii) transition the benchmark rate applicable to revolving loans from LIBOR to SOFR and (iv) make certain other amendments to the terms of the Revolving Credit Facility for purposes of, among other things, providing additional flexibility.
On March 13, 2023 (the “Revolving Credit Facility Seventh Amendment Effective Date”), the Company further amended its Revolving Credit Facility to increase the existing revolving commitments by an additional $45 million (together with the Initial Incremental Commitment, the "Incremental Commitment").
After giving effect to the Incremental Commitment, the Company had a total of $4.305 billion of revolving commitments available under the Revolving Credit Facility. The full amount of the Initial Incremental Commitment was made available from and after the Revolving Credit Facility Sixth Amendment Effective Date and the full amount of the Incremental Commitment was made available from and after the Revolving Credit Facility Seventh Amendment Effective Date. A portion of the non-extended revolving commitments terminated on July 5, 2023, with the remaining portion thereof terminating on May 28, 2024, unless otherwise extended.
The Revolving Credit Facility is guaranteed by NRG’s existing and future direct and indirect subsidiaries, with customary and agreed-upon exceptions for, among other exceptions, unrestricted subsidiaries, foreign subsidiaries, project subsidiaries, immaterial subsidiaries, captive insurance subsidiaries and securitization vehicles. The Revolving Credit Facility is also secured by a first priority (subject to certain customary permitted liens) perfected security interest in a substantial portion of the property and assets owned by NRG and its subsidiaries that are guarantors under the Revolving Credit Facility, subject to certain exceptions that include, among other things, the capital leases forstock of certain specified subsidiaries, including unrestricted subsidiaries and certain excluded subsidiaries, equity interests in excess of 66% of the years ending aftertotal outstanding voting equity interests of certain foreign subsidiaries, equity interests the pledge of which is prohibited by applicable agreements binding on such subsidiaries and other assets that may be designated by NRG as excluded from the collateral that, when taken together with all other assets so designated since the Revolving Credit Facility Sixth Amendment Effective Date, have an aggregate fair market value not exceeding $750 million. The Revolving Credit Facility is secured on a pari passu basis with certain interest rate, foreign currency and commodity hedging obligations of NRG, the Senior Secured First Lien Notes and certain other indebtedness. The collateral securing the Revolving Credit Facility will be released at the Company's request if both the senior unsecured long-term debt securities of the Company and the revolving loans under the Revolving Credit Facility are rated investment grade by any two of the three rating agencies and the satisfaction of certain other conditions, subject to reversion if such rating agencies withdraw such investment grade rating or downgrade such rating below investment grade (or, with respect to the revolving loans, crease to publish a rating).
The Revolving Credit Facility contains customary covenants, which, among other things, require NRG to maintain a maximum first lien leverage ratio on a consolidated basis when amounts outstanding under the Revolving Credit Facility (subject to certain exceptions) exceed a certain threshold and limit, subject to certain exceptions, NRG’s ability to:
•incur indebtedness and liens and enter into sale and lease-back transactions;
•make investments, loans and advances;
•return capital to shareholders;
•repay material subordinated indebtedness;
•consummate mergers, consolidations and asset sales;
•enter into affiliate transactions; and
•change its fiscal year-end.
As of December 31, 2017 are as follows:
|
| | | |
| | (In millions) |
| 2018 | $ | 695 |
|
| 2019 | 933 |
|
| 2020 | 805 |
|
| 2021 | 606 |
|
| 2022 | 1,854 |
|
| Thereafter | 11,745 |
|
| Total | $ | 16,638 |
|
Recourse Debt2023, there were no outstanding borrowings and there were $883 million in letters of credit issued under the Revolving Credit Facility.
Senior Notes
Issuance of 20282033 Senior Secured First Lien Notes
On December 7, 2017, NRGMarch 9, 2023, the Company issued $870$740 million of aggregate principal amount at par of 5.75%7.000% senior unsecuredsecured first lien notes due 2028.2033 (the "2033 Senior Secured First Lien Notes"). The 20282033 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 and the satisfaction of certain other conditions, 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 JulySeptember 15, 2018,2023 until the maturity date of JanuaryMarch 15, 2028.2033. The proceeds from the issuance of the 20282033 Senior Secured First Lien Notes, were utilized to redeem the Company's 6.625% Senior Notes due 2023.
Issuance of 2026 Senior Notes
On May 23, 2016, NRG issued $1.0 billion in aggregate principal amount at par of 7.25% senior notes due 2026, or the 2026 Senior Notes. The 2026 Senior Notes are senior unsecured obligations of NRGalong with cash on hand and are guaranteed by certain of its subsidiaries. Interest is paid semi-annually beginning on November 15, 2016, until the maturity date of May 15, 2026. The proceeds from certain other financings, were used to fund the issuanceacquisition of the 2026 Senior Notes were utilized to repurchase a portion of the Senior Notes during 2016.Vivint Smart Home.
Issuance of 2027 Senior Notes
On August 2, 2016, NRG issued $1.25 billion in aggregate principal amount at par of 6.625% senior notes due 2027, or the 2027 Senior Notes. The 2027 Senior Notes are senior unsecured obligations of NRG and are guaranteed by certain of its subsidiaries. Interest is paid semi-annually beginning on January 15, 2017, until the 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.
2017 Senior Note Redemptions
During the year ended December 31, 2017,2023, the Company redeemed $1.5$620 million in aggregate principal amount of its 3.875% Senior Notes, due 2032, for $509 million, which included the payment of $7 million of accrued interest, using cash on hand at an average early redemption percentage of 81%. In connection with the redemption, a $109 million gain on debt extinguishment was recorded, which included the write-off of previously deferred financing costs and other fees of $9 million.
During the year ended December 31, 2021, the Company redeemed approximately $1.9 billion in aggregate principal amount of its Senior Notes for $1.5$1.9 billion which included accrued interestusing the proceeds of $29 million.the 2032 Senior Notes and cash on hand, as detailed in the table below. In connection with the redemptions, a $49$77 million loss on debt extinguishment was recorded, which included the write-off of previously deferred financing costs of $7$12 million.
| | | | | | | | | | | | | | | | | |
| (In millions, except percentages) | Principal Repurchased | | Cash Paid(a) | | Average Early Redemption Percentage |
| 7.250% Senior Notes, due 2026 | $ | 1,000 | | | $ | 1,056 | | | 103.625 | % |
| 6.625% Senior Notes, due 2027 | 855 | | | 893 | | | 103.313 | % |
| Total | $ | 1,855 | | | $ | 1,949 | | | |
|
| | | | | | | | | | |
| | Principal Repurchased | | Cash Paid (a) | | Average Early Redemption Percentage |
| Amount in millions, except rates | | | | | |
7.625% senior notes due 2018 | $ | 398 |
| | $ | 411 |
| | 101.42 | % |
| 7.875% senior notes due 2021 | 206 |
| | 218 |
| | 102.63 | % |
| 6.625% senior notes due 2023 | 869 |
| | 915 |
| | 103.57 | % |
| Total | $ | 1,473 |
| | $ | 1,544 |
| | |
(a)Includes paymentaccrued interest of $29 million for accrued interest.
2016 Senior Notes Repurchases
Duringredemptions for the year ended December 31, 2016,2021
2048 Convertible Senior Notes
Accounting for Convertible Senior Notes — Upon issuance in 2018, the Convertible Senior Notes were separated into liability and equity components for accounting purposes. The carrying amount of the liability component was initially calculated by measuring the fair value of similar liabilities that do not have an associated convertible feature. The carrying amount of the equity component representing the conversion option was determined by deducting the fair value of the liability component from the par value of the Convertible Senior Notes. This difference represented the debt discount that was amortized to interest expense over seven years, which was determined to be the expected life of the Convertible Senior Notes, using the effective interest rate method. The equity component was recorded in additional paid-in capital and was not remeasured as it continued to meet the conditions for equity classification.
Following the adoption of ASU 2020-06 as of January 1, 2022, the Company repurchased $3.0 billionno longer records the conversion feature of its convertible senior notes in equity. Instead, the Company combined the previously separated equity component with the liability component, which together is now classified as debt, thereby eliminating the subsequent amortization of the debt discount as interest expense. As a result of the provisions of the amended guidance, the Company recorded a $100 million decrease to additional paid-in capital, a $57 million decrease to debt discount, a $57 million increase to retained earnings, and a $14 million decrease to long-term deferred tax liabilities.
Modification to Convertible Senior Notes — On February 22, 2022, the Company irrevocably elected to eliminate the right to settle conversions only in shares of the Company's common stock, such that any conversion after such date, the Company will pay cash per $1,000 principal amount and will settle in cash or a combination of cash and the Company's common stock for the remainder, if any, of the Company’s conversion obligation in excess of the aggregate principal of itsamount.
Convertible Senior Notes Features — As of December 31, 2023, the Convertible Senior Notes were convertible, under certain circumstances, into cash or a combination of cash and the Company’s common stock at a price of $41.83 per common share, which is equivalent to a conversion rate of approximately 23.9079 shares of common stock per $1,000 principal amount of Convertible Senior Notes. As of December 31, 2022, the Convertible Senior Notes were convertible at a price of $43.46 per common share, which is equivalent to a conversion rate of approximately 23.0116 shares of common stock per $1,000 principal amount of Convertible Senior Notes. The net carrying amounts of the Convertible Senior Notes as of December 31, 2023 and December 31, 2022 were $572 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, including, among others, during any calendar quarter (and only during such calendar quarter) if the last reported sales price per share of the Company's common stock exceeds 130% of the conversion price for $3.1 billion, which included accruedeach of at least 20 trading days, whether or not consecutive, during the 30 consecutive trading days ending on, and including, the last trading day of the immediately preceding calendar quarter. Thereafter during specified periods as follows:
•from December 1, 2024 until the close of business on the second scheduled trading day immediately before June 1, 2025; and
•from December 1, 2047 until the close of business on the second scheduled trading day immediately before the maturity date
All conversions with a conversion date that occurs within the specific periods above will be settled after such period pursuant to the terms of the indenture. The following table details the interest of $77 million. Inexpense recorded in connection with the repurchases, a $117 million lossConvertible Senior Notes, due 2048:
| | | | | | | | | | | | | | | | | |
| For the years ended December 31, |
| ($ In millions) | 2023 | | 2022 | | 2021 |
| Contractual interest expense | $ | 16 | | | $ | 16 | | | $ | 16 | |
Amortization of discount and deferred finance costs(a) | 2 | | | 1 | | | 15 | |
| Total | $ | 18 | | | $ | 17 | | | $ | 31 | |
| | | | | |
| Effective Interest Rate | 3.18 | % | | 3.01 | % | | 5.34 | % |
(a)Upon adoption of ASU 2020-06 on debt extinguishment was recorded,January 1, 2022, which includedresulted in the write-off of previously deferred financing costs of $16 million.
|
| | | | | | | | | | |
| | Principal Repurchased | | Cash Paid (a) | | Average Early Redemption Percentage |
| Amount in millions, except rates | | | | | |
7.625% senior notes due 2018 (b) | $ | 641 |
| | $ | 706 |
| | 107.89 | % |
| 8.250% senior notes due 2020 | 1,058 |
| | 1,129 |
| | 103.12 | % |
7.875% senior notes due 2021 (c) | 922 |
| | 978 |
| | 104.00 | % |
| 6.250% senior notes due 2022 | 108 |
| | 105 |
| | 94.73 | % |
| 6.625% senior notes due 2023 | 67 |
| | 64 |
| | 94.13 | % |
| 6.250% senior notes due 2024 | 171 |
| | 163 |
| | 94.52 | % |
| Total | $ | 2,967 |
| | $ | 3,145 |
| | |
(a) Includes payment for accrued interest.
(b) $186 millionremoval of the redemptions financed by cash on hand.
(c) $193 million of the redemptions financed by cash on hand.
debt discount, no further debt discount amortization is being recorded
Senior Notes OutstandingEarly Redemption
As of December 31, 2017,2023, NRG had the following outstanding issuances of senior notes with an early redemption feature, or Senior Notes:
i.6.250% senior notes, issued January 27, 2014 and due July 15, 2022, or the 2022 Senior Notes;
ii.6.250% senior notes, issued April 21, 2014 and due November 1, 2024, or the 2024 Senior Notes;
iii.7.250% senior notes, issued May 23, 2016 and due May 15, 2026, or the 2026 Senior Notes;
iv.6.625% senior notes, issued August 2, 2016 and due January 15, 2027, or the 2027 Senior Notes; and
v.ii.5.750% senior notes, issued December 7, 2017 and due January 15, 2028, or the 2028 Senior Notes.Notes;
iii.5.250% senior notes, issued May 24, 2019 and due June 15, 2029, or the 2029 Senior Notes;
iv.3.375% senior notes, issued December 2, 2020 and due February 15, 2029, or the 3.375% 2029 Senior Notes;
The Company periodically enters into supplemental indentures forv.3.625% senior notes, issued December 2, 2020 and due February 15, 2031, or the purpose of adding entities under2031 Senior Notes; and
vi.3.875% senior notes, issued August 23, 2021 and due February 15, 2032, or the 2032 Senior Notes as guarantors.Notes.
The indentures and the forms of notes provide, among other things, that the Senior Notes will be senior unsecured obligations of NRG.the Company. The indentures also provide for customary events of default, which include, among others: nonpayment of principal or interest; breach of other agreements in the indentures; defaults in failure to pay certain other indebtedness; the rendering of judgments to pay certain amounts of money against NRGthe Company and its subsidiaries; the failure of certain guarantees to be enforceable; and certain events of bankruptcy or insolvency. Generally, if an event of default occurs, the Trusteetrustee or the Holdersholders of at least 25% or 30% (depending on the series of Senior Notes) in principal amount of the then outstanding series of Senior Notes may declare all of the Senior Notes of such series to be due and payable immediately. The terms of the indentures, among other things, limit NRG'sthe Company's ability and certain of its subsidiaries' ability to return capital to stockholders, grant liens on assets to lenders and incur additional debt. Interest is payable semi-annually on the Senior Notes until their maturity dates.
2027 Senior Notes
The Company may redeem some or all of the 2027 Senior Notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:
| | | | | |
| Redemption Period | Redemption
Percentage |
| July 15, 2023 to July 14, 2024 | 101.104 | % |
| July 15, 2024 and thereafter | 100.000 | % |
2028 Senior Notes
The Company may redeem some or all of the 2028 Senior Notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:
| | | | | |
| Redemption Period | Redemption
Percentage |
| |
| January 15, 2024 to January 14, 2025 | 101.917 | % |
| January 15, 2025 to January 14, 2026 | 100.958 | % |
| January 15, 2026 and thereafter | 100.000 | % |
5.250% 2029 Senior Notes
At any time prior to JulyJune 15, 2017, NRG may redeem up to 35% of2024, the aggregate principal amount of the 2022 Senior Notes, at a redemption price equal to 106.25% of the principal amount of the notes redeemed, plus accrued and unpaid interest, with an amount equal to the net cash proceeds of certain equity offerings. At any time prior to July 15, 2018, NRGCompany may redeem all or a part of the 20225.250%2029 Senior Notes, at a redemption price equal to 100% of the principal amount of the notes redeemed, plus accrued and unpaid interest to the redemption date, plus a premium. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following: the present value of 103.125%102.625% of the note, plus interest payments due on the note fromthrough June 15, 2024 (excluding accrued but unpaid interest to the date of redemption through July 15, 2018,date), computed using a discount rate equal to the Treasury Rate as of such redemption date plus 0.50%. over the principal amount of the note. In addition, on or after JulyJune 15, 2018, NRG2024, the Company may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:
| | | | | |
| Redemption Period | Redemption Percentage |
| June 15, 2024 to June 14, 2025 | 102.625 | % |
Redemption PeriodJune 15, 2025 to June 14, 2026 | Redemption
Percentage
101.750 | % |
JulyJune 15, 20182026 to JulyJune 14, 20192027 | 103.125100.875 | % |
JulyJune 15, 2019 to July 14, 2020 | 101.563 | % |
July 15, 20202027 and thereafter | 100.000 | % |
20243.375% 2029 Senior Notes
At any time prior to May 1, 2017, NRG may redeem up to 35% of the aggregate principal amount of the 2024 Senior Notes, at a redemption price equal to 106.25% of the principal amount of the notes redeemed, plus accrued and unpaid interest, with an amount equal to the net cash proceeds of certain equity offerings. At any time prior to May 1, 2019, NRG may redeem all or a part of the 2024 Senior Notes, at a redemption price equal to 100% of the principal amount, accrued and unpaid interest to the redemption date, plus a premium. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following: the present value of 103.125% of the note, plus interest payments due on the note from the date of redemption through May 1, 2019 computed using a discount rate equal to the Treasury Rate as of such redemption date plus 0.50%. In addition, onOn or after May 1, 2019, NRGFebruary 15, 2024, the Company may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:
| | | | | |
| Redemption Period | Redemption Percentage |
| February 15, 2024 to February 14, 2025 | 101.688 | % |
Redemption PeriodFebruary 15, 2025 to February 14, 2026 | Redemption
Percentage
100.844 | % |
May 1, 2019 to April 30, 2020 | 103.125 | % |
May 1, 2020 to April 30, 2021 | 102.083 | % |
May 1, 2021 to April 30, 2022 | 101.042 | % |
May 1, 2022February 15, 2026 and thereafter | 100.000 | % |
20262031 Senior Notes
At any time prior to MayFebruary 15, 2019, NRG may redeem up to 35% of2026, the aggregate principal amount of the 2026 Senior Notes, at a redemption price equal to 107.25% of the principal amount of the notes redeemed, plus accrued and unpaid interest, with an amount equal to the net cash proceeds of certain equity offerings. At any time prior to May 15, 2021, NRGCompany may redeem all or a part of the 20262031 Senior Notes, at a redemption price equal to 100% of the principal amount of the notes redeemed, plus accrued and unpaid interest to the redemption date, plus a premium. The premium is the greater of: (i) 1% of the principal amount of the notes;note; or (ii) the excess of the principal amount of the note over the following: the present value of 103.625%101.813% of the note, plus interest payments due on the note fromthrough February 15, 2026 (excluding accrued but unpaid interest to the date of redemption through May 15, 2021date), computed using a discount rate equal to the Treasury Rate as of such redemption date plus 0.50%. over the principal amount of the note. In addition, on or after MayFebruary 15, 2021, NRG2026, the Company may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:
| | | | | |
| Redemption Period | Redemption Percentage |
| February 15, 2026 to February 14, 2027 | 101.813 | % |
Redemption PeriodFebruary 15, 2027 to February 14, 2028 | Redemption
Percentage
101.208 | % |
MayFebruary 15, 20212028 to MayFebruary 14, 20222029 | 103.625100.604 | % |
MayFebruary 15, 2022 to May 14, 2023 | 102.417 | % |
May 15, 2023 to May 14, 2024 | 101.208 | % |
May 15, 20242029 and thereafter | 100.000 | % |
20272032 Senior Notes
At any time prior to JulyAugust 15, 2019, NRG2024, the Company may redeem up to 35%40% of the aggregate principal amount of the 20272032 Senior Notes, at a redemption price equal to 106.625%103.875% of the principal amount of the notes redeemed, plus accrued and unpaid interest, with an amount equal to the net cash proceeds of certain equity offerings.offerings, provided that at least 50% of the aggregate principal amount remains outstanding immediately after the occurrence of such redemption. At any time prior to JulyFebruary 15, 2021 NRG2027, the Company may redeem all or a part of the 20272032 Senior Notes, at a redemption price equal to 100% of the principal amount of the notes redeemed, plus accrued and unpaid interest to the redemption date, plus a premium. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following:(A) the present value of 103.313%(1) the redemption price of the note at February 15, 2027 (such redemption price being set forth in the table appearing below in the column “Redemption Percentage (If Sustainability Performance Target has not been satisfied and/or confirmed by External Verifier)” unless the Sustainability Performance Target has been satisfied in respect of the year ended December 31, 2025 and the Company has provided confirmation thereof to the trustee together with a related confirmation by the External Verifier by the date that is at least 15 days prior to August 15, 2026 in which case the redemption price shall be as set forth in the column “Redemption Percentage (If Sustainability Performance Target has been satisfied and confirmed by External Verifier)”) plus (2) interest payments due on the note fromthrough February 15, 2027 (excluding accrued but unpaid interest to the date of redemption through July 15, 2021date) computed using a discount rate equal to the Treasury Rate as of such redemption date plus 0.50%., over (B) the principal amount of the note. In addition, on or after JulyFebruary 15, 2021, NRG2027, the Company may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table during the twelve-month period beginning on February 15 of the years indicated below, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:
| | | | | | | | | | | |
| Year | Redemption Percentage
(If Sustainability Performance Target has been satisfied and confirmed by External Verifier) | | Redemption Percentage
(If Sustainability Performance Target has not been satisfied and/or confirmed by External Verifier) |
| 2027 | 101.938 | % | | 102.188 | % |
| 2028 | 101.292 | % | | 101.458 | % |
| 2029 | 100.646 | % | | 100.729 | % |
| 2030 and thereafter | 100.000 | % | | 100.000 | % |
|
| | |
Redemption Period | Redemption
Percentage
|
July 15, 2021 to July14, 2022 | 103.313 | % |
July 15, 2022 to July 14, 2023 | 102.208 | % |
July 15, 2023 to July 14, 2024 | 101.104 | % |
July 15, 2024 and thereafter | 100.000 | % |
Receivables Facility2028 Senior Notes
At any time priorIn 2020, NRG Receivables LLC, a bankruptcy remote, special purpose, indirect wholly owned subsidiary, ("NRG Receivables") entered into the Receivables Facility, subject to January 15, 2021,adjustments on a seasonal basis, with issuers of asset-backed commercial paper and commercial banks (the "Lenders"). The assets of NRG may redeem upReceivables are first available to 35%satisfy the claims of the aggregate principal amountLenders before making payments on the subordinated note and equity issued by NRG Receivables. The assets of NRG Receivables are not available to the Company and its subsidiaries or creditors unless and until distributed by NRG Receivables. Under the Receivables Facility, certain indirect subsidiaries of the 2028 Senior Notes, atCompany sell their accounts receivables to NRG Receivables, subject to certain terms and conditions. In turn, NRG Receivables grants a redemption price equal to 105.750% ofsecurity interest in the principal amount of the notes redeemed, plus accrued and unpaid interest, with an amount equalpurchased receivables to the netLenders as collateral for cash proceedsborrowings and issuances of certain equity offerings. At any time prior to January 15, 2023 NRG may redeem all or a partletters of the 2028 Senior Notes, at a redemption price equal to 100% of the principal amount, accrued and unpaid interestcredit. Pursuant to the redemption date, plus a premium. The premium isPerformance Guaranty, the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following: the present value of 102.875% of the note, plus interest payments due on the note from the date of redemption through January 15, 2023 computed using a discount rate equal to the Treasury Rate as of such redemption date plus 0.50%. In addition, on or after January 15, 2023, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:
|
| | |
Redemption Period | Redemption
Percentage
|
January 15, 2023 to January 14, 2024 | 102.875 | % |
January 15, 2024 to January 14, 2025 | 101.917 | % |
January 15, 2025 to January 14, 2026 | 100.958 | % |
January 15, 2026 and thereafter | 100.000 | % |
Senior Credit Facility
On June 30, 2016, NRG replaced its Senior Credit Facility, consisting of its Term Loan Facility and Revolving Credit Facility with a new senior secured facility, or the Senior Credit Facility, which includes the following:
A $1.9 billion term loan facility, or the 2023 Term Loan Facility, with a maturity date of June 30, 2023, which will pay interest at a rate of LIBOR plus 2.75%, with a LIBOR floor of 0.75%. The debt was issued at 99.50% of face value; the discount will be amortized to interest expense over the life of the loan. Repayments under the 2023 Term Loan Facility will consist of 0.25% of principal per quarter, with the remainder due at maturity. The proceeds of the new term loan facility as well as cash on hand were used to repay the 2018 Term Loan Facility balance outstanding. A $21 million loss on extinguishment of the Term Loan Facility was recorded during the second quarter of 2016, which consisted of the write-off of previously deferred financing costs. 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%.
A $289 million revolving senior credit facility, or the Tranche A Revolving Facility, with a maturity date of July 1, 2018 and a $2.2 billion revolving senior credit facility, or the Tranche B Revolving Facility, with a maturity date of June 30, 2021, which will pay interest at a rate of LIBOR plus 2.25%.
The Senior Credit Facility isCompany has guaranteed, by substantially all of NRG's existing and future direct and indirect subsidiaries, with certain customary or agreed-upon exceptions for unrestricted foreign subsidiaries, and certain other subsidiaries, including GenOn, NRG Yield, Inc. and their respective subsidiaries. The capital stock of these guarantor subsidiaries has been pledged for the benefit of NRG Receivables and the Senior Credit Facility's lenders.Lenders, the payment and performance by each indirect subsidiary of its respective obligations under the Receivables Facility. The accounts receivables remain on the
Company's consolidated balance sheet and any amounts funded by the Lenders to NRG Receivables will be reflected as short-term borrowings. Cash flows from the Receivables Facility are reflected as financing activities in the Company's consolidated statements of cash flows. The Senior CreditCompany continues to service the accounts receivables sold in exchange for a servicing fee.
On June 22, 2023, NRG Receivables amended its existing Receivables Facility is also secured by first-priority perfected security interests in substantially allto, among other things, (i) extend the scheduled termination date to June 21, 2024, (ii) increase the aggregate commitments from $1.0 billion to $1.4 billion (adjusted seasonally) and (iii) add a new originator. On October 6, 2023, the Receivables Facility was further amended to replace the benchmark interest rate of the propertyReceivable Facility's subordinated note from LIBOR to SOFR. The weighted average interest rate related to usage under the Receivables Facility as of December 31, 2023 was 0.841%. As of December 31, 2023, there were no outstanding borrowings and assets owned or acquiredthere were $1.0 billion in letters of credit issued under the Receivables Facility.
Repurchase Facility
In 2020, the Company entered into the Repurchase Facility related to the Receivables Facility. Under the Repurchase Facility, the Company can currently borrow up to $150 million, collateralized by a subordinated note issued by NRG and its subsidiaries, other than certain limited exceptions. These exceptions include assets of certain unrestricted subsidiaries, equity interestsReceivables to NRG Retail LLC in certain of NRG's affiliates that have non-recourse debt financing, including GenOn, NRG Yield, Inc. and their respective subsidiaries, and voting equity interests in excess of 66%favor of the totaloriginating entities representing a portion of the balance of receivables sold to NRG Receivables under the Receivables Facility.
In addition, in connection with the amendments to the Receivables Facility, on June 22, 2023, the Company and the originators thereunder renewed the existing uncommitted Repurchase Facility. Such renewal, among other things, extended the maturity date to June 21, 2024 and joined an additional originator to the Repurchase Facility. On October 6, 2023, the Repurchase Facility was further amended to reflect the concurrent amendment to the Receivables Facility's subordinated note. The Repurchase Facility has no commitment fee and borrowings will be drawn at SOFR + 1.55%. As of December 31, 2023, there were no outstanding voting equity interestborrowings under the Repurchase Facility.
Bilateral Letter of certainCredit Facilities
On May 19, 2023, May 30, 2023 and October 17, 2023 the Company increased the size of NRG's foreign subsidiaries.its bilateral letter of credit facilities by $25 million, $100 million and $50 million, respectively, to provide additional liquidity and to allow for the issuance of up to $850 million of letters of credit. These facilities are uncommitted. As of December 31, 2023, $671 million was issued under these facilities.
Tax Exempt Bonds
| | | | | | | | | | | | | | | | | | | | |
| | As of December 31, | | |
| (In millions, except rates) | | 2023 | | 2022 | | Interest Rate % |
| NRG Indian River Power 2020, tax exempt bonds, due 2040 | | $ | 57 | | | $ | 57 | | | 1.250 | |
| NRG Indian River Power 2020, tax exempt bonds, due 2045 | | 190 | | | 190 | | | 1.250 | |
| NRG Dunkirk 2020, tax exempt bonds, due 2042 | | 59 | | | 59 | | | 4.250 | |
| City of Texas City, tax exempt bonds, due 2045 | | 33 | | | 33 | | | 4.125 | |
| Fort Bend County, tax exempt bonds, due 2038 | | 54 | | | 54 | | | 4.750 | |
| Fort Bend County, tax exempt bonds, due 2042 | | 73 | | | 73 | | | 4.750 | |
| Total | | $ | 466 | | | $ | 466 | | | |
Dunkirk Bonds
On April 3, 2023, NRG remarketed $59 million in aggregate principal amount of 4.25% tax-exempt refinancing bonds of the Chautauqua County Capital Resource Corporation (the "Dunkirk Bonds"). The Dunkirk Bonds are guaranteed on a first-priority basis by each of NRG's current and future subsidiaries that guarantee indebtedness under the Revolving Credit Facility. The Dunkirk Bonds are secured by a first priority security interest in the same collateral that is pledged for the benefit of the lenders under the Revolving Credit Facility, which consists of a substantial portion of the property and assets owned by NRG and the guarantors. The collateral securing the Dunkirk Bonds will, at the request of NRG, be released if NRG satisfies certain conditions, including receipt of an investment grade rating on its senior, unsecured debt securities from two out of the three rating agencies, subject to reversion if those rating agencies withdraw their investment grade rating of the Dunkirk Bonds or any of NRG's senior, unsecured debt securities or downgrade such ratings below investment grade. The Dunkirk Bonds are subject to mandatory tender and purchase on April 3, 2028 and have a final maturity date of April 1, 2042.
|
| | | | | | | | | | |
| | | As of December 31, | | |
| | | 2017 | | 2016 | | Interest Rate % |
| Amount in millions, except rates | | | | | | |
| Indian River Power tax exempt bonds, due 2040 | | $ | 57 |
| | $ | 57 |
| | 6.000 |
| Indian River Power LLC, tax exempt bonds, due 2045 | | 190 |
| | 190 |
| | 5.375 |
| Dunkirk Power LLC, tax exempt bonds, due 2042 | | 59 |
| | 59 |
| | 5.875 |
| City of Texas City, tax exempt bonds, due 2045 | | 32 |
| | 22 |
| | 4.125 |
| Fort Bend County, tax exempt bonds, due 2038 | | 54 |
| | 54 |
| | 4.750 |
| Fort Bend County, tax exempt bonds, due 2042 | | 73 |
| | 73 |
| | 4.750 |
| Total | | $ | 465 |
| | $ | 455 |
| |
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On August 29, 2023, the Company entered into a Facility Agreement (as defined below) with Alexander Funding Trust II, a newly-formed Delaware statutory trust (the “Trust”), in connection with the sale by the Trust of $500 million pre-capitalized trust securities redeemable July 31, 2028 (the “P-Caps”). The Trust invested the proceeds from the sale of the P-Caps in a portfolio of principal and interest strips of U.S. Treasury securities (the “Eligible Treasury Assets”). The P-Caps replaced the Company’s existing pre-capitalized trust securities redeemable 2023 issued by Alexander Funding Trust, which matured on November 15, 2023.
In connection with the sale of the P-Caps, the Company and the guarantors named therein entered into a facility agreement, dated August 29, 2023 (the “Facility Agreement”), with the Trust and Deutsche Bank Trust Company Americas, as notes trustee (the “Notes Trustee”). Under the Facility Agreement, the Company has the right, from time to time, to issue to the Trust, and to require the Trust to purchase from the Company, on one or more occasions (the “Issuance Right”), up to $500 million aggregate principal amount of the Company’s 7.467% Senior Secured First Lien Notes due 2028 (the “P-Caps Secured Notes”) in exchange for all or a portion of the Eligible Treasury Assets corresponding to the portion of the Issuance Right under the Facility Agreement being exercised at such time. The Company pays to the Trust a facility fee equal to 3.13427% applied to the unexercised portion of the Issuance Right on a semi-annual basis.
The P-Caps are to be redeemed by the Trust on July 31, 2028 or earlier upon an early redemption of the P-Caps Secured Notes. Following any distribution of P-Caps Secured Notes to the holders of the P-Caps, the Company may similarly redeem such P-Caps Secured Notes, in whole or in part, at the redemption price described in the P-Caps Indenture (as defined below), plus accrued but unpaid interest to, but excluding, the date of redemption. Any P-Caps Secured Notes outstanding and held by the Trust as a result of the exercise of the Issuance Right that remain outstanding will also mature on July 31, 2028.
Non-RecourseThe Issuance Right will be exercised automatically in full if (i) the Company fails to pay the facility fee when due or any amount due and owing under the trust expense reimbursement agreement or fails to purchase and pay for any Eligible Treasury Assets that are due and not paid on their payment date and such failure is not cured within 30 days or (ii) upon certain bankruptcy events of the Company. The Company will be required to mandatorily exercise the Issuance Right if certain mandatory exercise events occur upon the terms and conditions set forth in the Facility Agreement.
The P-Caps Secured Notes that may be sold to the Trust from time to time will be governed by the base indenture, dated August 29, 2023 (the “Base Indenture”), between the Company and the Notes Trustee, as supplemented by the supplemental indenture, dated August 29, 2023 (the “Supplemental Indenture” and, together with the Base Indenture, the “P-Caps Indenture”), among the Company, the guarantors named therein and the Notes Trustee.
The P-Caps Secured Notes will, if sold to the Trust, be guaranteed on a first-priority basis by each of the Company’s subsidiaries that guarantee indebtedness under the Revolving Credit Facility. The P-Caps Secured Notes will, if sold to the Trust, be secured by a first priority security interest in the same collateral that is pledged for the benefit of the lenders under the Revolving Credit Facility, which consists of a substantial portion of the property and assets owned by the Company and the guarantors. The collateral securing the P-Caps Secured Notes will be released at the Company’s request if the senior unsecured long-term debt securities of the Company are rated investment grade by any two of the three rating agencies, subject to reversion if such rating agencies downgrade such rating below investment grade or withdraw such investment grade rating.
In connection with the issuance of the P-Caps, on August 29, 2023, the Company entered into a letter of credit facility agreement (the “LC Agreement”) with Deutsche Bank Trust Company Americas, as collateral agent (the “Collateral Agent”) and administrative agent, and certain financial institutions (the “LC Issuers”) for the issuance of letters of credit in an aggregate amount not to exceed $485 million. The LC Agreement replaced the Company’s existing letter of credit facility agreement, effective August 29, 2023. In addition, on August 29, 2023, the Trust entered into a pledge and control agreement (the “Pledge Agreement”), among the Company, the Trust and the Collateral Agent, under which the Company and the Trust agreed to grant a security interest over the Eligible Treasury Assets in favor of the Collateral Agent for the benefit of the LC Issuers. Pursuant to the LC Agreement and the Pledge Agreement, the Collateral Agent is entitled to withdraw Eligible Treasury Assets in the amount of any drawn letters of credit issued pursuant to the LC Agreement from the Company's and the Trust’s pledged accounts, following notice to the Company, in the event the Company has failed to reimburse such drawn amounts and the LC Issuers have the right to instruct the Collateral Agent to enforce the pledge over the Eligible Treasury Assets upon the occurrence of any event of default under the LC Agreement.
Non-recourse Debt
The following are descriptions of certain indebtedness of NRG's subsidiaries that are outstanding as of December 31, 2017.subsidiaries. All of NRG's non-recourse debt is secured by the assets in the respective project subsidiaries as further described below.
Yield LLC and Yield Operating LLC Revolving Credit Facility
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, which can be used for cashfacility.
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 for the issuanceare guaranteed by APX Group Holdings, Inc., each of letters of credit. At December 31, 2017, there was $55 million outstanding on the revolverAPX's existing and $74 million of letters of credit issued under the revolving credit facility.
NRG Yield Operating 2026 Senior Notes
On August 18, 2016, NRG Yield Operating LLC issued $350 million of senior unsecured notes, or the NRG Yield Operating 2026 Senior Notes. The NRG Yield Operating 2026 Senior Notes bear interest of 5.00%future wholly owned U.S. restricted subsidiaries (subject to customary exclusions and mature on September 15, 2026.qualifications) and Vivint Smart Home. Interest on the notesVivint Smart Home 2027 Senior Secured Notes is payablepaid semi-annually in arrears on MarchFebruary 15 and SeptemberAugust 15 until the maturity date of each year, and will commence on MarchFebruary 15, 2017.2027.
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 Yield Operating 2026Vivint Smart Home 2029 Senior Notes are senior unsecured obligations of NRG Yield Operating LLCAPX and are guaranteed by NRG Yield LLC,APX Group Holdings, Inc., each of APX's existing and by certain of NRG Yield Operating LLC’sfuture wholly owned currentU.S. restricted subsidiaries (subject to customary exclusions and future subsidiaries. A portion ofqualifications) and Vivint Smart Home. Interest on the proceeds from the 2026Vivint Smart Home 2029 Senior Notes was used to repay NRG Yield Operating LLC's revolving credit facility.
Project Financings
The following are descriptions of certain indebtedness of NRG's project subsidiaries that are outstanding as of December 31, 2017.
Aqua Caliente Holdco Financing Agreement
On February 17, 2017, Agua Caliente Borrower I LLCis paid semi-annually in arrears on January 15 and Agua Caliente Borrower II LLC, Agua Caliente Holdco, the indirect owners 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. Net proceeds were distributed to the Company.
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 December 31, 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. As of December 31, 2017, $20 million was outstanding under the construction loan and $29 million in in letters of credit in support of the project were issued.
Utah Portfolio
As part of the November 2, 2016 utility-scale solar and wind acquisition, as discussed in Note 3, Discontinued Operations, Acquisitions and Dispositions, NRG recorded $222 million of non-recourse project level debt. As of term conversion for the three associated debt facilities, the Company borrowed an additional $65 million of non-recourse debt. Each facility bears interest of LIBOR plus 2.625% and matures on December 16, 2022.
Thermal Financing
On October 31, 2016, NRG Energy Center Minneapolis LLC, a subsidiary of NRG Yield, Inc., received proceeds of $125 million from the issuance of 3.55% Series D notes due October 31, 2031, or the Series D Notes, and entered into a shelf facility for the anticipated issuance of an additional $70 million of notes. The Series D Notes are secured by substantially all of the assets of NRG Energy Center Minneapolis LLC. NRG Thermal LLC has guaranteed the indebtedness and its guarantee is secured by a pledge of the equity interests in all of NRG Thermal LLC’s subsidiaries. NRG Energy Center Minneapolis LLC distributed the proceeds of the Series D Notes to NRG Thermal LLC, who in turn distributed the proceeds to NRG Yield Operating LLC to be utilized for general corporate purposes, including potential acquisitions.
Alta Wind lease financing arrangements
Alta Wind Holdings (Alta Wind II - V) and Alta I have finance lease obligations issued under lease transactions whereby the respective operating entities sold and leased back undivided interests in specific assets of the projects. All of the assets of Alta I-V are pledged as collateral under these arrangements. The sale and related lease transactions are accounted for as financing arrangements as the operating entities have continued involvement with the property.
|
| | | | | | | | | | | | | | | | |
| Amount in millions, except rates | | Lease Financing Arrangement | | Letter of Credit Facility |
| Non-Recourse Debt | | Amount Outstanding as of December 31, 2017 | | Interest Rate | | Maturity Date | | Amount Outstanding as of December 31, 2017 | | Interest Rate | | Maturity Date |
| Alta Wind I | | $ | 231 |
| | 7.015% | | 12/30/2034 | | $ | 16 |
| | 3.00% - 3.25% | | 1/5/2021 |
| Alta Wind II | | 183 |
| | 5.696% | | 12/30/2034 | | 27 |
| | 1.250% | | 3/21/2022 |
| Alta Wind III | | 191 |
| | 6.067% | | 12/30/2034 | | 27 |
| | 1.750% | | various |
| Alta Wind IV | | 123 |
| | 5.938% | | 12/30/2034 | | 19 |
| | 1.750% | | various |
| Alta Wind V | | 198 |
| | 6.071% | | 6/30/2035 | | 30 |
| | 1.750% | | various |
| Total | | $ | 926 |
| | | | | | $ | 119 |
| | | | |
Midwest Generation
On April 7, 2016, Midwest Generation, LLC, or MWG, entered into an agreement to sell certain quantities of unforced capacity that has cleared various PJM Reliability Pricing Model auctions to a trading counterparty for net proceeds of $253 million. MWG will continue to operate the applicable generation facilities and remains responsible for performance penalties and eligible for performance bonus payments, if any. Accordingly, MWG will continue to account for all revenues and costs as before; however, the proceeds will be recorded as a financing obligation while capacity payments by PJM to the counterparty will be reflected as debt amortization and interest expense through the end of the 2018/19 delivery year. MWG will amortize the upfront discount to interest expense, at an effective interest rate of 4.39%, over the term of the arrangement, through June 2019. As of December 31, 2017, $152 million was outstanding.
CVSR
On July 15 2016, CVSR Holdco LLC, the indirect owner of the CVSR project, issued $200 million of senior secured notes. The $199 million of net proceeds from the notes were distributed to a subsidiary of NRG and NRG Yield Operating LLC, the owners of CVSR Holdco LLC, based on their pro-rata ownership. The notes were issued at par and bear an interest rate at 4.68%. Interest is payable semi-annually beginning on September 30, 2016, until the maturity date of March 31, 2037.July 15, 2029.
Capistrano RefinancingVivint Smart Home Senior Secured Credit Facilities
On July 13, 2016, Cedro Hill, Broken BowThe Vivint Smart Home senior secured credit agreement (the “Vivint Smart Home Credit Agreement”) provides for (i) a term loan facility in an initial aggregate principal amount of $1.4 billion (the “Vivint Smart Home Term Loan Facility”, and Crofton Bluffs,the loans thereunder, the “Vivint Smart Home Term Loans”) and (ii) a revolving credit facility in an initial 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 (subject to certain customary permitted liens) perfected security interest in (i) substantially all of Capistrano Wind Partners, each amended their respective credit facilities to increase borrowings to a totalthe present and future tangible and intangible assets of $312 millionAPX, and to lower their respective interest rates. The netthe guarantors, including without limitation equipment, subscriber contracts and communication paths, intellectual property, general intangibles, investment property, material intercompany notes and proceeds of $87 million were distributedthe foregoing, subject to Capistrano Wind Partnerspermitted liens and subsequently distributedother customary exceptions, (ii) substantially all personal property of APX and the guarantors consisting of accounts receivable arising from the sale of inventory and other goods and services (including related contracts and contract rights, inventory, cash, deposit accounts, other bank accounts and securities accounts), inventory and intangible assets to the holdersextent attached to the foregoing books and records of APX and the guarantors, and the proceeds thereof, subject to permitted liens and other customary exceptions, in each case held by APX and the guarantors and (iii) a pledge of all of the Class Bcapital stock of APX, each of its subsidiary guarantors and each restricted subsidiary of APX and its subsidiary guarantors (subject to customary exclusions and qualifications), in each case other than certain excluded assets and subject to the limitations and exclusions provided in the applicable collateral documents.
The Vivint Smart Home Credit Agreement contains customary covenants, which, among other things, require APX to maintain a maximum first lien net leverage ratio when amounts outstanding under the Vivint Smart Home Revolving Facility exceed a certain threshold and restrict, subject to certain exceptions, APX and its restricted subsidiaries’ ability to:
•incur or guarantee additional debt or issue disqualified stock or preferred equity interestsstock;
•pay dividends and make other distributions on, or redeem or repurchase, capital stock;
•make certain investments;
•incur certain liens;
•enter into transactions with affiliates;
•merge or consolidate;
•materially change the nature of Capistrano Wind Partners.their business;
•enter into agreements that restrict the ability of restricted subsidiaries to make dividends or other payments to APX or grant liens on their assets;
•designate restricted subsidiaries as unrestricted subsidiaries;
•amend, prepay, redeem or purchase certain material contractually subordinated debt; and
Interest Rate Swaps — Project Financings•transfer or sell certain assets.
Many of NRG's project subsidiariesOn June 9, 2023, Vivint Smart Home entered into interestan amendment to the Vivint Smart Home Credit Agreement which transitioned the benchmark rate swaps, intendedapplicable to hedge the risks associated withVivint Smart Home Term Loans and the Vivint Smart Home Revolving Loans from LIBOR to SOFR. As of December 31, 2023, the aggregate outstanding principal amount of the Vivint Term Loans was $1.3 billion. As of December 31, 2023, Vivint Smart Home had no outstanding borrowings under the Vivint Smart Home Revolving Credit Facility.
Vivint Smart Home Notes Early Redemption
2027 Senior Secured Notes
APX may redeem some or all of the 2027 Senior Secured Notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest rates on non-recourse project level debt. These swaps amortize in proportion to their respective loans and are floating for fixed where the project subsidiary pays its counterparty the equivalent of a fixed interest payment on a predetermined notional value and will receive quarterly the equivalent of a floating interest payment based on the same notional value. Allnotes redeemed to the first applicable redemption date:
| | | | | |
| Redemption Period | Redemption Percentage |
| February 15, 2024 to February 14, 2025 | 101.688 | % |
| February 15, 2025 and thereafter | 100.000 | % |
2029 Senior Notes
At any time prior to July 15, 2024 and from time to time, APX may redeem the notes in whole or in part, at a redemption price equal to 100% of the principal amount of the notes redeemed, plus accrued and unpaid interest to the redemption date, plus a premium. The premium is the greater of: (i) 1% of the principal amount of the note; and (ii) the excess , if any, of (a) the present value at such redemption date of (i) the redemption price of such note at July 15, 2024, plus (ii) interest payments due on the note through July 15, 2024 (excluding accrued but unpaid interest to the redemption date), computed using a discount rate swap payments byequal to the project subsidiary and its counterparty are made quarterly, andTreasury Rate as of such redemption date plus 0.50% over the LIBOR is determinedthen outstanding principal amount of such note. In addition, on or after July 15, 2024, APX may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in advance of each interest period. Thethe following table, summarizesplus accrued and unpaid interest on the swaps, some of which are forward starting as indicated, relatednotes redeemed to NRG's project level debt as of December 31, 2017.the first applicable redemption date:
| | | | | |
| Redemption Period | Redemption Percentage |
| July 15, 2024 to July 14, 2025 | 102.875 | % |
| July 15, 2025 to July 14, 2026 | 101.438 | % |
| July 15, 2026 and thereafter | 100.100 | % |
|
| | | | | | | | | | | | | | | |
| | % of Principal | | Fixed Interest Rate | | Floating Interest Rate | | Notional Amount at December 31, 2017 (In millions) | | Effective Date | | Maturity Date |
| Recourse Debt | | | | | | | | | | | |
| NRG Energy | 85 | % | | various |
| | 1-mo. LIBOR | | $ | 1,000 |
| | June 30, 2016 | | June 30, 2021 |
| Non-Recourse Debt |
| |
| | | |
|
| | | | |
| El Segundo Energy Center | 75 | % | | various |
| | 3-mo. LIBOR | | 340 |
| | various | | various |
| South Trent Wind LLC | 75 | % | | 3.265 | % | | 3-mo. LIBOR | | 40 |
| | June 15, 2010 | | June 14, 2020 |
| South Trent Wind LLC | 75 | % | | 4.95 | % | | 3-mo. LIBOR | | 21 |
| | June 30, 2020 | | June 14, 2028 |
| NRG Solar Roadrunner LLC | 75 | % | | 4.313 | % | | 3-mo. LIBOR | | 26 |
| | September 30, 2011 | | December 31, 2029 |
| NRG Solar Alpine LLC | 85 | % | | various | | 3-mo. LIBOR | | 115 |
| | various | | various |
| NRG Solar Avra Valley LLC | 85 | % | | 2.333 | % | | 3-mo. LIBOR | | 46 |
| | November 30, 2012 | | November 30, 2030 |
| NRG Marsh Landing | 75 | % | | 3.244 | % | | 3-mo. LIBOR | | 295 |
| | June 28, 2013 | | June 30, 2023 |
| Utah Portfolio | 80 | % | | various |
| | 1-mo. LIBOR | | 223 |
| | various | | September 30, 2036 |
| DGPV 4 | 85 | % | | various |
| | 3-mo. LIBOR | | 95 |
| | various | | various |
| Other | 75 | % | | various |
| | various | | 653 |
| | various | | various |
| EME Project Financings | | | | | | | — |
| | | | |
| Broken Bow | 75 | % | | various |
| | 3-mo. LIBOR | | 55 |
| | various | | various |
| Cedro Hill | 90 | % | | various |
| | 3-mo. LIBOR | | 136 |
| | various | | various |
| Crofton Bluffs | 75 | % | | various |
| | 3-mo. LIBOR | | 36 |
| | various | | various |
| Laredo Ridge | 75 | % | | 2.310 | % | | 3-mo. LIBOR | | 75 |
| | March 31, 2011 | | March 31, 2026 |
| Tapestry | 75 | % | | 2.210 | % | | 3-mo. LIBOR | | 146 |
| | December 30, 2011 | | December 21, 2021 |
| Tapestry | 50 | % | | 3.570 | % | | 3-mo. LIBOR | | 60 |
| | December 21, 2021 | | December 21, 2029 |
| Viento Funding II | 90 | % | | various |
| | 6-mo. LIBOR | | 148 |
| | various | | various |
| Viento Funding II | 90 | % | | 4.985 | % | | 6-mo. LIBOR | | 65 |
| | July 11, 2023 | | June 30, 2028 |
| Walnut Creek Energy | 75 | % | | various |
| | 3-mo. LIBOR | | 239 |
| | June 28, 2013 | | May 31, 2023 |
| WCEP Holdings | 90 | % | | 4.003 | % | | 3-mo. LIBOR | | 45 |
| | June 28, 2013 | | May 21, 2023 |
| Alta Wind Project Financings | | | | | | | | | | | |
| AWAM | 100 | % | | 2.470 | % | | 3-mo. LIBOR | | 17 |
| | May 22, 2013 | | May 15, 2031 |
| Total | | | | | | | $ | 3,876 |
| | | | |
Note 1314 — Asset Retirement Obligations
The Company's AROs are primarily related to the environmental obligations for mine reclamation, ash disposal, site closures, fuel storage facilities and future dismantlement of equipment on leased property and environmental obligations related to nuclear decommissioning, ash disposal, site closures, and fuel storage facilities.property. In addition, the Company has also identified conditional AROs for asbestos removal and disposal, which are specific to certain power generation operations.
See Note 6, Nuclear Decommissioning Trust Fund, for a further discussionFollowing the sale of the Company's 44% equity interest in STP on November 1, 2023, the Company no longer has asset retirement obligations related to nuclear decommissioning obligations. Accretiondecommissioning. Prior to the sale, accretion for the nuclear decommissioning ARO and amortization of the related ARO asset arewere recorded to the Nuclear Decommissioning Trust Liability to the ratepayers and arewere not included in net income, consistent with regulatory treatment.treatment per ASC 980, Regulated Operations.
The following table represents the balance of ARO obligations as of December 31, 20172023 and 2016,2022, along with the additions, reductions and accretionactivity related to the Company's ARO obligations for the year ended December 31, 2017:2023:
| | | | | | | | | | | | | | | | | |
| (In millions) | Nuclear Decommission | | Other(a) | | Total |
| Balance as of December 31, 2022 | $ | 340 | | | $ | 418 | | | $ | 758 | |
| Revisions in estimates for current obligations | (13) | | | 3 | | | (10) | |
| Additions | — | | | 13 | | | 13 | |
| Spending for current obligations | — | | | (42) | | | (42) | |
| Accretion | 16 | | | 23 | | | 39 | |
| Dispositions | (343) | | | (8) | | | (351) | |
| Balance as of December 31, 2023 | $ | — | | | $ | 407 | | | $ | 407 | |
(a)Total accretion expense related to asset retirement obligations included in the consolidated statement of cash flows includes accretion and revisions in estimates for asset retirement liabilities on non-operating plants
|
| | | |
| | (In millions) |
| Balance as of December 31, 2016 | $ | 735 |
|
| Revisions in estimates for current obligations | (3 | ) |
| Additions | 9 |
|
| Spending for current obligations | (21 | ) |
| Accretion — Expense | 35 |
|
| Accretion — Nuclear decommissioning | 16 |
|
| Balance as of December 31, 2017 | $ | 771 |
|
Note 1415 — Benefit Plans and Other Postretirement Benefits
NRG sponsors and operates defined benefit pension and other postretirement plans.
NRG pension benefits are available to eligible non-union and union employees through various defined benefit pension plans. These benefits are based on pay, service history and age at retirement. Most pension benefits are provided through tax-qualified plans. NRG also provides postretirement health and welfare benefits for certain groups of employees. Cost sharing provisions vary by the terms of any applicable collective bargaining agreements.
NRG maintains twothree separate qualified pension plans, the NRG Pension Plan for Bargained Employees, and the NRG Pension Plan.Plan and the Pension Plan for Employees of both NRG and GenOn participateDirect Energy Marketing Limited ("DEML"). Participation in each of the pension plans, depending upon whether their employment is covered by a bargaining agreement. As controlled group members, ERISA requires that NRG and GenOn are jointly and severally liable for the NRG Pension Plan for Bargained Employees and thedepends upon whether an employee is covered by a bargaining agreement. The NRG Pension Plan, including pension liabilities associated with GenOn employees.
As described in Note 1, Nature of Business, and Note 3, Discontinued Operations, Acquisitions and Dispositions, NRG and GenOn entered into a Restructuring Support Agreement and various support agreements, including a transition services agreement, that providesplan was frozen for a restructuring and recapitalization of the GenOn Entities through a prearranged plan of reorganization and was approved by the Bankruptcy Court pursuant to an order of confirmationnon-union employees on December 12, 2017.In accordance with the agreements, NRG will retain GenOn's pension liability31, 2018. The Pension Plan for service provided by GenOn employees priorEmployees of DEML is closed to the completion of the reorganization. NRG determined that the retention of this liability is probable and has recorded the estimated accumulated pension benefit obligation as of December 31, 2017 of $92 million in other non-current liabilities with a corresponding loss from discontinued operations. The balance reflects a contribution of $13 million to the plans with respect to GenOn's employees paid in September 2017. NRG will also retain the liability for GenOn's post-employment and retiree health and welfare benefits, in an amount up to $25 million. Retention of this liability is probable and accordingly, NRG has recorded the $25 million in other non-current liabilities with a corresponding loss from discontinued operations as of December 31, 2017. NRG's obligation for both of these liabilities will be revalued through and at GenOn's emergence from bankruptcy, with NRG's obligation for the post-employment and retiree health and welfare plan capped at $25 million.new participants.
NRG expects to contribute $31$43 million to the Company's pension plans in 2018. Of this amount, $132024, of which $23 million relatedrelates to employees of GenOn.the GenOn plan.
NRG Defined Benefit Plans
The annual net periodic benefit cost/(credit) related to NRG's pension and other postretirement benefit plans include the following components:
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | Pension Benefits |
| (In millions) | 2023 | | 2022 | | 2021 |
| Service cost benefits earned | $ | 5 | | | $ | 7 | | | $ | 9 | |
| Interest cost on benefit obligation | 50 | | | 41 | | | 27 | |
| Expected return on plan assets | (39) | | | (47) | | | (66) | |
| Amortization of unrecognized net loss | 6 | | | 3 | | | 1 | |
| Curtailment and special termination benefits (income)/expense | (1) | | | 14 | | | 2 | |
| Net periodic benefit cost/(credit) | $ | 21 | | | $ | 18 | | | $ | (27) | |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | Pension Benefits |
| | 2017 | | 2016 | | 2015 |
| | (In millions) |
| Service cost benefits earned | $ | 26 |
| | $ | 30 |
| | $ | 32 |
|
| Interest cost on benefit obligation | 43 |
| | 43 |
| | 53 |
|
| Expected return on plan assets | (58 | ) | | (60 | ) | | (62 | ) |
| Amortization of unrecognized net loss | 4 |
| | 2 |
| | 2 |
|
| Net periodic benefit cost | $ | 15 |
| | $ | 15 |
| | $ | 25 |
|
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | Other Postretirement Benefits |
| (In millions) | 2023 | | 2022 | | 2021 |
| | | | | |
| Interest cost on benefit obligation | $ | 4 | | | $ | 2 | | | $ | 2 | |
| Amortization of unrecognized prior service cost | (8) | | | (8) | | | (10) | |
| Amortization of unrecognized net loss | 1 | | | 2 | | | 1 | |
| Curtailment expense | — | | | — | | | 1 | |
| Net periodic benefit credit | $ | (3) | | | $ | (4) | | | $ | (6) | |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | Other Postretirement Benefits |
| | 2017 | | 2016 | | 2015 |
| | (In millions) |
| Service cost benefits earned | $ | 1 |
| | $ | 2 |
| | $ | 3 |
|
| Interest cost on benefit obligation | 4 |
| | 6 |
| | 9 |
|
| Amortization of unrecognized prior service credit | (9 | ) | | (5 | ) | | (5 | ) |
| Amortization of unrecognized net (gain)/loss | (1 | ) | | — |
| | 1 |
|
| Curtailment gain | — |
| | — |
| | (14 | ) |
| Net periodic benefit (credit)/cost | $ | (5 | ) | | $ | 3 |
| | $ | (6 | ) |
A comparison of the pension benefit obligation, other postretirement benefit obligations and related plan assets for NRG's plans on a combined basis is as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| | As of December 31, |
| | Pension Benefits | | Other Postretirement
Benefits |
| (In millions) | 2023 | | 2022 | | 2023 | | 2022 |
| Benefit obligation at January 1 | $ | 1,036 | | | $ | 1,452 | | | $ | 84 | | | $ | 105 | |
| Service cost | 5 | | | 7 | | | — | | | — | |
| Interest cost | 50 | | | 41 | | | 4 | | | 2 | |
| | | | | | | |
| Actuarial loss/(gain) | 22 | | | (289) | | | (5) | | | (11) | |
| Employee and retiree contributions | — | | | — | | | 4 | | | 3 | |
| Curtailment and special termination benefit loss | (2) | | | — | | | (1) | | | — | |
| Benefit payments | (89) | | | (171) | | | (11) | | | (15) | |
| Foreign exchange translation | 1 | | | (4) | | | — | | | — | |
| Benefit obligation at December 31 | 1,023 | | | 1,036 | | | 75 | | | 84 | |
| Fair value of plan assets at January 1 | 844 | | | 1,336 | | | — | | | — | |
| Actual return on plan assets | 93 | | | (317) | | | — | | | — | |
| Employee and retiree contributions | — | | | — | | | 4 | | | 3 | |
| Employer contributions | 2 | | | — | | | 7 | | | 12 | |
| Benefit payments | (89) | | | (171) | | | (11) | | | (15) | |
| Foreign exchange translation | 1 | | | (4) | | | — | | | — | |
| Fair value of plan assets at December 31 | 851 | | | 844 | | | — | | | — | |
| Funded status at December 31 — excess of obligation over assets | $ | (172) | | | $ | (192) | | | $ | (75) | | | $ | (84) | |
|
| | | | | | | | | | | | | | | |
| | As of December 31, |
| | Pension Benefits | | Other Postretirement Benefits |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (In millions) |
| Benefit obligation at January 1 | $ | 1,241 |
| | $ | 1,196 |
| | $ | 128 |
| | $ | 178 |
|
| Service cost | 26 |
| | 30 |
| | 1 |
| | 2 |
|
| Interest cost | 43 |
| | 43 |
| | 4 |
| | 6 |
|
| Plan amendments | — |
| | — |
| | (1 | ) | | (42 | ) |
| Actuarial loss/(gain) | 77 |
| | 40 |
| | 6 |
| | (2 | ) |
| Employee and retiree contributions | — |
| | — |
| | 3 |
| | 3 |
|
| Benefit payments | (58 | ) | | (68 | ) | | (13 | ) | | (17 | ) |
| Benefit obligation at December 31 | 1,329 |
| | 1,241 |
| | 128 |
| | 128 |
|
| Fair value of plan assets at January 1 | 953 |
| | 916 |
| | — |
| | — |
|
| Actual return on plan assets | 173 |
| | 72 |
| | — |
| | — |
|
| Employee and retiree contributions | — |
| | — |
| | 3 |
| | 3 |
|
| Employer contributions | 36 |
| | 33 |
| | 10 |
| | 14 |
|
| Benefit payments | (58 | ) | | (68 | ) | | (13 | ) | | (17 | ) |
| Fair value of plan assets at December 31 | 1,104 |
| | 953 |
| | — |
| | — |
|
| Funded status at December 31 — excess of obligation over assets | $ | (225 | ) | | $ | (288 | ) | | $ | (128 | ) | | $ | (128 | ) |
Less: GenOn postretirement obligation(a) | — |
| | — |
| | 38 |
| | 46 |
|
Add: Retained obligation in bankruptcy proceeding(a) | — |
| | — |
| | (25 | ) | | (25 | ) |
| Net obligation for NRG | $ | (225 | ) | | $ | (288 | ) | | $ | (115 | ) | | $ | (107 | ) |
| |
(a) | The difference between GenOn's postretirement benefit obligation and NRG's retained obligation of $13 million and $21 million is presented in noncurrent liabilities for discontinued operations as of December 31, 2017 and 2016, respectively. |
During the year ended December 31, 2023, the actuarial loss of $22 million on pension benefits was primarily driven by decreasing discount rates.
During the year ended December 31, 2022, the actuarial gain of $289 million on pension benefits was primarily driven by increasing discount rates.
Amounts recognized in NRG's balance sheets were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| | As of December 31, |
| | Pension Benefits | | Other Postretirement Benefits |
| (In millions) | 2023 | | 2022 | | 2023 | | 2022 |
| Other current liabilities | $ | — | | | $ | — | | | $ | 5 | | | $ | 7 | |
| Other non-current liabilities | 172 | | | 192 | | | 70 | | | 77 | |
|
| | | | | | | | | | | | | | | |
| | As of December 31, |
| | Pension Benefits | | Other Postretirement Benefits |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (In millions) |
| Current liabilities | $ | — |
| | $ | — |
| | $ | 7 |
| | $ | 8 |
|
Less: GenOn other postretirement benefits(a) | — |
| | — |
| | (3 | ) | | (5 | ) |
| Total current liabilities | $ | — |
| | $ | — |
| | $ | 4 |
| | $ | 3 |
|
| | | | | | | | |
| Non-current liabilities | $ | 225 |
| | $ | 288 |
| | $ | 121 |
| | $ | 120 |
|
Less: GenOn other postretirement benefits(a) | — |
| | — |
| | (10 | ) | | (16 | ) |
| Total non-current liabilities | $ | 225 |
| | $ | 288 |
| | $ | 111 |
| | $ | 104 |
|
| |
(a) | The difference between GenOn's postretirement benefit obligation and NRG's retained obligation of $13 million and $21 million is presented in noncurrent liabilities for discontinued operations as of December 31, 2017 and 2016, respectively. |
Of the amounts recognized in NRG's balance sheet, $92 million and $120 million related to GenOn's pension benefits obligation as of December 31, 2017 and 2016, respectively, and $25 million related to GenOn's postretirement benefits obligation as of December 31, 2017 and 2016.
Amounts recognized in NRG's accumulated OCI that have not yet been recognized as components of net periodic benefit cost were as follows: | | | | | | | | | | | | | | | | | | | | | | | |
| | As of December 31, |
| | Pension Benefits | | Other Postretirement Benefits |
| (In millions) | 2023 | | 2022 | | 2023 | | 2022 |
| Net loss/(gain) | $ | 73 | | | $ | 110 | | | $ | (14) | | | $ | (7) | |
| Prior service cost/(credit) | — | | | 1 | | | (4) | | | (12) | |
| Total accumulated OCI | $ | 73 | | | $ | 111 | | | $ | (18) | | | $ | (19) | |
| | | | | | | |
| | | | | | | |
|
| | | | | | | | | | | | | | | |
| | As of December 31, |
| | Pension Benefits | | Other Postretirement Benefits |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (In millions) |
| Net loss/(gain) | $ | 53 |
| | $ | 94 |
| | $ | (4 | ) | | $ | (11 | ) |
| Prior service cost/(credit) | 3 |
| | 3 |
| | (37 | ) | | (45 | ) |
| Total accumulated OCI | $ | 56 |
| | $ | 97 |
| | $ | (41 | ) | | $ | (56 | ) |
| Less: GenOn (deconsolidated June 14, 2017) | (22 | ) | | (37 | ) | | 10 |
| | 8 |
|
| Net accumulated OCI | $ | 34 |
| | $ | 60 |
| | $ | (31 | ) | | $ | (48 | ) |
Other changes in plan assets and benefit obligations recognized in OCI were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | Pension Benefits | | Other Postretirement Benefits |
| (In millions) | 2023 | | 2022 | | 2023 | | 2022 |
| Net actuarial (gain)/loss | $ | (31) | | | $ | 74 | | | $ | (5) | | | $ | (11) | |
| Amortization of net actuarial loss | (6) | | | (3) | | | (1) | | | (2) | |
| | | | | | | |
| | | | | | | |
| Amortization of prior service cost | — | | | — | | | 8 | | | 8 | |
| Effect of settlement/curtailment | (1) | | | (14) | | | (1) | | | — | |
| Total recognized in OCI | $ | (38) | | | $ | 57 | | | $ | 1 | | | $ | (5) | |
| Net periodic benefit cost/(credit) | 21 | | | 18 | | | (3) | | | (4) | |
| Net recognized in net periodic pension (credit)/cost and OCI | $ | (17) | | | $ | 75 | | | $ | (2) | | | $ | (9) | |
|
| | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | Pension Benefits | | Other Postretirement Benefits |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (In millions) |
| Net actuarial (gain)/loss | $ | (37 | ) | | $ | 28 |
| | $ | 6 |
| | $ | (2 | ) |
| Amortization of net actuarial (gain)/loss | (4 | ) | | (2 | ) | | 1 |
| | — |
|
| Prior service credit | — |
| | — |
| | (1 | ) | | (41 | ) |
| Amortization of prior service cost | — |
| | — |
| | 9 |
| | 5 |
|
| Total recognized in OCI | $ | (41 | ) | | $ | 26 |
| | $ | 15 |
| | $ | (38 | ) |
| Less: GenOn (deconsolidated June 14, 2017) | 15 |
| | $ | (17 | ) | | $ | 2 |
| | $ | 3 |
|
| Net recognized in OCI | $ | (26 | ) | | $ | 9 |
| | $ | 17 |
| | $ | (35 | ) |
| Less: GenOn (deconsolidated June 14, 2017) | 15 |
| | (17 | ) | | 3 |
| | 3 |
|
| Net recognized in net periodic pension (credit)/cost and OCI | $ | (11 | ) | | $ | 24 |
| | $ | 13 |
| | $ | 39 |
|
As a result of GenOn's deconsolidation during 2017, NRG reduced the loss recorded in other comprehensive income by $28 million related to GenOn's pension and other postretirement benefits.
The Company's estimated unrecognized loss and unrecognized prior service cost for NRG's pension plan that will be amortized from accumulated OCI to net periodic cost over the next fiscal year is less than $1 million. The Company's estimated unrecognized gain and unrecognized prior service credit for NRG's postretirement plan that will be amortized from accumulated OCI to net periodic cost over the next fiscal year is less than $1 million and $7 million, respectively.
The following table presents the balances of significant components of NRG's pension plan:
| | | | | | | | | | | |
| | As of December 31, |
| | Pension Benefits |
| (In millions) | 2023 | | 2022 |
| Projected benefit obligation | $ | 1,023 | | | $ | 1,036 | |
| Accumulated benefit obligation | 1,015 | | | 1,022 | |
| Fair value of plan assets | 851 | | | 844 | |
|
| | | | | | | |
| | As of December 31, |
| | Pension Benefits |
| | 2017 | | 2016 |
| | (In millions) |
| Projected benefit obligation | $ | 1,329 |
| | $ | 1,241 |
|
| Accumulated benefit obligation | 1,255 |
| | 1,174 |
|
| Fair value of plan assets | 1,104 |
| | 953 |
|
NRG's market-related value of its plan assets is the fair value of the assets. The fair values of the Company's pension plan assets by asset category and their level within the fair value hierarchy are as follows:
| | | | | | | | | | | | | | | | | |
| | Fair Value Measurements as of December 31, 2023 |
| (In millions) | Quoted Prices in Active Markets for Identical Assets (Level 1) | | Significant Observable Inputs (Level 2) | | Total |
| Common/collective trust investment — U.S. equity | $ | — | | | $ | 156 | | | $ | 156 | |
| Common/collective trust investment — non-U.S. equity | — | | | 58 | | | 58 | |
| Common/collective trust investment — non-core assets | — | | | 81 | | | 81 | |
| Common/collective trust investment — fixed income | — | | | 188 | | | 188 | |
| Short-term investment fund | 19 | | | — | | | 19 | |
| Subtotal fair value | $ | 19 | | | $ | 483 | | | $ | 502 | |
| Measured at net asset value practical expedient: | | | | | |
| Common/collective trust investment — non-U.S. equity | | 32 | |
| Common/collective trust investment — fixed income | | 243 | |
| Common/collective trust investment — non-core assets | | 47 | |
| Partnerships/joint ventures | | 27 | |
| Total fair value | | $ | 851 | |
|
| | | | | | | | | | | |
| | Fair Value Measurements as of December 31, 2017 |
| | Quoted Prices in Active Markets for Identical Assets (Level 1) | | Significant Observable Inputs (Level 2) | | Total |
| | (In millions) |
| Common/collective trust investment — U.S. equity | $ | — |
| | $ | 256 |
| | $ | 256 |
|
| Common/collective trust investment — non-U.S. equity | — |
| | 66 |
| | 66 |
|
| Common/collective trust investment — non-core assets | — |
| | 178 |
| | 178 |
|
| Common/collective trust investment — fixed income | — |
| | 230 |
| | 230 |
|
| Short-term investment fund | 5 |
| | — |
| | 5 |
|
| Subtotal fair value | $ | 5 |
| | $ | 730 |
| | $ | 735 |
|
| Measured at net asset value practical expedient |
|
| |
|
| |
|
|
| Common/collective trust investment — non-U.S. equity |
|
| |
|
| | 94 |
|
| Common/collective trust investment — fixed income |
|
| |
|
| | 233 |
|
| Partnerships/joint ventures |
|
| |
|
| | 42 |
|
| Total fair value |
|
| |
|
| | $ | 1,104 |
|
|
| | | | | | | | | | | |
| | Fair Value Measurements as of December 31, 2016 |
| | Quoted Prices in Active Markets for Identical Assets (Level 1) | | Significant Observable Inputs (Level 2) | | Total |
| | (In millions) |
| Common/collective trust investment — U.S. equity | $ | — |
| | $ | 283 |
| | $ | 283 |
|
| Common/collective trust investment — non-U.S. equity | — |
| | 71 |
| | 71 |
|
| Common/collective trust investment — global equity | — |
| | 104 |
| | 104 |
|
| Common/collective trust investment — fixed income | — |
| | 190 |
| | 190 |
|
| Short-term investment fund | 3 |
| | — |
| | 3 |
|
| Subtotal fair value | $ | 3 |
| | $ | 648 |
| | $ | 651 |
|
| Measured at net asset value practical expedient |
|
| |
|
| |
|
|
| Common/collective trust investment — non-U.S. equity |
|
| |
|
| | 78 |
|
| Common/collective trust investment — fixed income |
|
| |
|
| | 193 |
|
| Partnerships/joint ventures |
|
| |
|
| | 31 |
|
| Total fair value |
|
| |
|
| | $ | 953 |
|
| | | | | | | | | | | | | | | | | |
| | Fair Value Measurements as of December 31, 2022 |
| (In millions) | Quoted Prices in Active Markets for Identical Assets (Level 1) | | Significant Observable Inputs (Level 2) | | Total |
| Common/collective trust investment — U.S. equity | $ | — | | | $ | 155 | | | $ | 155 | |
| Common/collective trust investment — non-U.S. equity | — | | | 65 | | | 65 | |
| Common/collective trust investment — non-core assets | — | | | 90 | | | 90 | |
| Common/collective trust investment — fixed income | — | | | 181 | | | 181 | |
| Short-term investment fund | 22 | | | — | | | 22 | |
| Subtotal fair value | $ | 22 | | | $ | 491 | | | $ | 513 | |
| Measured at net asset value practical expedient: | | | | | |
| Common/collective trust investment — non-U.S. equity | | 33 | |
| Common/collective trust investment — fixed income | | 220 | |
| Common/collective trust investment — non-core assets | | 55 | |
| Partnerships/joint ventures | | 23 | |
| Total fair value | | $ | 844 | |
In accordance with ASC 820, the Company determines the level in the fair value hierarchy within which each fair value measurement in its entirety falls, based on the lowest level input that is significant to the fair value measurement in its entirety. The fair value of the common/collective trust investments is valued at fair value which is equal to the sum of the market value of all of the fund's underlying investments. Certain common/collective trust investments have readily determinable fair value as they publish daily net asset value, or NAV, per share and are categorized as Level 2. Certain other common/collective trust investments and partnerships/joint ventures use NAV per share, or its equivalent, as a practical expedient for valuation, and thus have been removed from the fair value hierarchy table.
The following table presents the significant assumptions used to calculate NRG's benefit obligations:
| | | | As of December 31, | | As of December 31, |
| | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits |
| Weighted-Average Assumptions | 2017 | | 2016 | | 2017 | | 2016 | Weighted-Average Assumptions | 2023 | | 2022 | | 2023 | | 2022 |
| Discount rate | 3.71 | % | | 4.26 | % | | 3.71 | % | | 4.29 | % | Discount rate | 4.97 | % | | 5.18 | % | | 4.96 | % | | 5.19 | % |
| Interest crediting rate | | Interest crediting rate | 5.67 | % | | 5.21 | % | | 4.66 | % | | 4.00 | % |
| Rate of compensation increase | 3.00 | % | | 3.00 | % | | N/A |
| | N/A |
|
| Health care trend rate | — |
| | — |
| | 8.2% grading to 4.5% in 2025 |
| | 7.0% grading to 5.0% in 2025 |
| Health care trend rate | — | | | — | | — | | | 7.7% grading to 4.5% in 2033 | | 7.7% grading to 4.5% in 2033 | | 7% grading to 4.4% in 2031 |
The following table presents the significant assumptions used to calculate NRG's benefit expense:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | As of December 31, |
| | Pension Benefits | | Other Postretirement Benefits |
| Weighted-Average Assumptions | 2023 | | 2022 | | 2021 | | 2023 | | 2022 | | 2021 |
| Discount rate | 5.18 | % | | 2.89%/4.71%/5.41% | | 2.55 | % | | 5.19 | % | | 2.82 | % | | 2.81 | % |
| Interest crediting rate | 5.21 | % | | 3.07 | % | | 3.13 | % | | 4.00 | % | | 1.94 | % | | 1.62 | % |
| Expected return on plan assets | 5.55 | % | | 4.99 | % | | 5.62 | % | | — | | | — | | | — | |
| Rate of compensation increase | 3.06 | % | | 3.06 | % | | 3.06 | % | | — | | | — | | | — | |
| Health care trend rate | — | | | — | | | — | | | 7.2% grading to 4.5% in 2028 | | 6.9% grading to 4.4% in 2028 | | 7.0% grading to 4.4% in 2028 |
|
| | | | | | | | | | | | | | | | | |
| | As of December 31, |
| | Pension Benefits | | Other Postretirement Benefits |
| Weighted-Average Assumptions | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 |
| Discount rate | 4.26 | % | | 4.52 | % | | 4.16 | % | | 4.29 | % | | 4.55 | % | | 4.20 | % |
| Expected return on plan assets | 6.85 | % | | 6.65 | % | | 6.36 | % | | — |
| | — |
| | — |
|
| Rate of compensation increase | 3.00 | % | | 3.00 | % | | 3.45 | % | | — |
| | — |
| | — |
|
| Health care trend rate | — |
| | — |
| | — |
| | 7.0% grading to 5.0% in 2025 |
|
| 7.25% grading to 5.0% in 2025 |
|
| 8.6% grading to 5.0% in 2023 |
|
NRG uses December 31 of each respective year as the measurement date for the Company's pension and other postretirement benefit plans. The Company sets the discount rate assumptions on an annual basis for each of NRG's defined benefit retirement plans as of December 31. The discount rate assumptions represent the current rate at which the associated liabilities could be effectively settled at December 31. The Company utilizes the Aon Hewitt AA Above Median, or AA-AM, yield curve and the AON Canada yield curve to select the appropriate discount rate assumption for eachits retirement plan.plans. The AA-AM yield curve is a hypothetical AA yield curve represented by a series of annualized individual spot discount rates from 6 months to 99 years. EachUnder the AA-AM yield curve, each bond issue used to build this yield curve must be non-callable, and have an average rating of AA when averaging available Moody's Investor Services, Standard & Poor's and Fitch ratings. The AON Canada yield curve is based on high quality corporate bonds. Under the AON Canada yield curve, expected plan cash flows were discounted using the yield curve, and then a single rate is determined which produces an equivalent present value.
NRG employs a total return investment approach, whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status, and corporate financial condition. The Investment Committee reviews the asset mix periodically and as the plan assets increase in future years, the Investment Committee may examine other asset classes such as real estate or private equity. NRG employs a building block approach to determining the long-term rate of return assumption for plan assets, with proper consideration given to diversification and rebalancing. Historical markets are studied and long-term historical relationships between equities and fixed income are preserved, consistent with the widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current factors such as inflation and interest rates are evaluated before long-term capital market assumptions are determined. Peer data and historical returns are reviewed to check for reasonableness and appropriateness.
In 2016, NRG changed the approach utilized to estimate the service cost and interest cost components of net periodic benefit cost for pension and postretirement benefit plans. Historically, the Company estimated these components by using a single weighted average discount rate derived from the yield curve used to measure the benefit obligation. The Company has elected to use a spot rate approach in the estimation of the components of benefit cost by applying specific spot rates along the yield curve to the relevant projected cash flows, as this provides a better estimate of service and interest costs. This election is considered a change in estimate and, accordingly, has been accounted for starting in 2016. This change does not affect the measurement of NRG's total benefit obligation.
The target allocations of NRG's pension plan assets were as follows for the year ended December 31, 2017:
| | | | | |
| U.S. equity | 19 | % |
| Non-U.S. equity | 12 | % |
U.S. equityNon-core assets | 2217 | % |
Non-U.S. equityFixed Income | 1452 | % |
Non-core assets | 19 | % |
U.S. fixed income | 45 | % |
Plan assets are currently invested in a diversified blend of equity and fixed-income investments. Furthermore, equity investments are diversified across U.S., non-U.S., global, and emerging market equities, as well as among growth, value, small and large capitalization stocks.
Investment risk and performance are monitored on an ongoing basis through quarterly portfolio reviews of each asset fund class to a related performance benchmark, if applicable, and annual pension liability measurements. Performance benchmarks are composed of the following indices:
| | | | | | | | |
| Asset Class | | Index |
| | |
Asset Class | | Index |
| U.S. equities | | Dow Jones U.S. Total Stock Market Index |
| Non-U.S. equities | | MSCI All Country World Ex-U.S. IMI Index |
Non-core assets(a) | | Various (per underlying asset class) |
| Fixed income securities | | Barclays CapitalShort, Intermediate and Long Term Government/Credit Index & Credits/Barclays Strips 20+ Index and FTSE Canada Universe Bond Index |
| |
(a) | Non-Core Assets are defined as diversifying asset classes approved by the Investment Committee that are intended to enhance returns and/or reduce volatility of the U.S. and non-U.S. equities. Asset classes considered Non-Core include, but may not be limited to: Emerging Market Equity, Emerging Market Debt, Non-US Developed Market Small Cap, High Yield Fixed Income, Real Estate, Bank Loans, Global Infrastructure and other Alternatives. |
(a)Non-Core Assets are defined as diversifying asset classes approved by the Investment Committee that are intended to enhance returns and/or reduce volatility of the U.S. and non-U.S. equities. Asset classes considered Non-Core include, but may not be limited to: Emerging Market Equity, Emerging Market Debt, Non-US Developed Market Small Cap, High Yield Fixed Income, Real Estate, Bank Loans, Global Infrastructure and other Alternatives
NRG's expected future benefit payments for each of the next five years, and in the aggregate for the five years thereafter, are as follows:
|
| | | | | | | | | | | |
| | | | Other Postretirement Benefit |
| | Pension Benefit Payments | | Benefit Payments | | Medicare Prescription Drug Reimbursements |
| | (In millions) |
| 2018 | $ | 68 |
| | $ | 7 |
| | $ | — |
|
| 2019 | 71 |
| | 8 |
| | — |
|
| 2020 | 75 |
| | 8 |
| | — |
|
| 2021 | 79 |
| | 8 |
| | — |
|
| 2022 | 82 |
| | 8 |
| | — |
|
| 2023-2027 | 421 |
| | 33 |
| | 1 |
|
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effect:
|
| | | | | | | |
| | 1-Percentage- Point Increase | | 1-Percentage- Point Decrease |
| | (In millions) |
| Effect on total service and interest cost components | $ | 1 |
| | $ | — |
|
| Effect on postretirement benefit obligation | 9 |
| | (8 | ) |
| | | | | | | | | | | | | | | | | |
| | Pension | | Other Postretirement Benefit |
| (In millions) | Benefit Payments | | Benefit Payments | | Medicare Prescription Drug Reimbursements |
| 2024 | $ | 82 | | | $ | 5 | | | $ | — | |
| 2025 | 81 | | | 5 | | | — | |
| 2026 | 79 | | | 5 | | | — | |
| 2027 | 78 | | | 5 | | | — | |
| 2028 | 76 | | | 5 | | | — | |
| 2029-2033 | 360 | | | 27 | | | 2 | |
STP Defined Benefit Plans
NRG has a 44% undivided ownership interest in STP, as discussed further in Note 27, Jointly Owned Plants. STPNOC, which operates and maintains STP, provides its employees a defined benefit pension plan, as well as postretirement health and welfare benefits. Although NRG doesdid not sponsor the STP plan, it reimbursesreimbursed STPNOC for 44% of the contributions made towards its retirement plan obligations. For the yearyears ended December 31, 2017,2023 and December 31, 2022, NRG reimbursed STPNOC $8$3 million towards its defined benefit plans. For the year ended December 31, 2016, NRG reimbursed STPNOC $7and $18 million, towards its defined benefit plans. In 2018, NRG expects to reimburse STPNOC $6 millionrespectively, for its contribution towardsto the plans. On November 1, 2023, the Company closed on the sale of its 44% equity interest in STP. Following the sale, the Company is no longer responsible for further reimbursements to the STP pension plan.
The Company has recognized the following in its statement of financial position, statement of operations and accumulated OCI related to its former 44% interest in STP:
| | | | As of December 31, |
| | Pension Benefits | | Other Postretirement Benefits | | | As of December 31, |
| | 2017 | | 2016 | | 2017 | | 2016 | | | | Pension Benefits | | | | Other Postretirement Benefits |
| | (In millions) |
| (In millions) | | (In millions) | | | 2022 | | | | 2022 |
| Funded status — STPNOC benefit plans | $ | (76 | ) | | $ | (74 | ) | | $ | (24 | ) | | $ | (23 | ) |
| Net periodic benefit cost/(credit) | 8 |
| | 7 |
| | (3 | ) | | (2 | ) |
| Other changes in plan assets and benefit obligations recognized in other comprehensive (loss)/income | (6 | ) | | 11 |
| | 5 |
| | (1 | ) |
| Other changes in plan assets and benefit obligations recognized in other comprehensive income | |
Defined Contribution Plans
NRG's employees are also eligible to participate in defined contribution 401(k) plans.
The Company's contributionscosts related to these plans were as follows:
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| (In millions) | 2023 | | 2022 | | 2021 |
| Cost recognized for defined contribution plans | $ | 61 | | | $ | 37 | | | $ | 35 | |
The Company's costs, which are primarily related to employer matching of a portion of employee contributions to defined contribution plans, increased during 2023 primarily due to an increase in retirement saving plan match and the Vivint acquisition.
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In millions) |
| Company contributions to defined contribution plans | $ | 56 |
| | $ | 55 |
| | $ | 53 |
|
Note 1516 — Capital Structure
For the period from December 31, 20142020 to December 31, 2017,2023, the Company had 10,000,000 shares of preferred stock authorized and 500,000,000 shares of common stock authorized. The following table reflects the changes in NRG's preferred and common shares issued and outstanding for each period presented:
| | | | | | | | | Preferred Shares | | Common Shares |
| | Common | | Issued and Outstanding | | Issued | | Treasury | | Outstanding |
| | Issued | | Treasury | | Outstanding |
| Balance as of December 31, 2014 | 415,506,176 |
| | (78,843,552 | ) | | 336,662,624 |
|
| Balance as of December 31, 2020 | |
| Shares issued under ESPP | — |
| | 283,139 |
| | 283,139 |
|
| Shares issued under LTIPs | 1,433,774 |
| | — |
| | 1,433,774 |
|
| Share repurchases | — |
| | (24,189,495 | ) | | (24,189,495 | ) |
| Balance as of December 31, 2015 | 416,939,950 |
| | (102,749,908 | ) | | 314,190,042 |
|
| Balance as of December 31, 2021 | |
| Shares issued under ESPP | — |
| | 609,094 |
| | 609,094 |
|
| Shares issued under LTIPs | 643,875 |
| | — |
| | 643,875 |
|
| Balance as of December 31, 2016 | 417,583,825 |
| | (102,140,814 | ) | | 315,443,011 |
|
| Share repurchases | |
| Balance as of December 31, 2022 | |
| Issuance of Series A Preferred Stock | |
| Shares issued under ESPP | — |
| | 560,769 |
| | 560,769 |
|
| Shares issued under LTIPs | 739,309 |
| | — |
| | 739,309 |
|
| Balance as of December 31, 2017 | 418,323,134 |
| | (101,580,045 | ) | | 316,743,089 |
|
| Share repurchases | |
| Retirement of treasury stock | |
| Balance as of December 31, 2023 | |
| Shares issued under LTIPs | |
| Share repurchases | |
| Retirement of treasury stock | |
| Balance as of February 1, 2024 | |
Common Stock
The following table summarizes NRG'sAs of December 31, 2023, NRG had 27,362,083 shares of common stock reserved for the maximum number of shares potentially issuable based on the conversion and redemption features of the long-term incentive plans as of December 31, 2017:plans.
|
| | |
Equity Instrument | Common Stock
Reserve Balance
|
Long-term incentive plans | 19,597,433 |
|
Common stock dividends — In 2015, NRGThe Company declared and paid $0.3775, $0.350 and $0.325 quarterly dividends on the Company'sdividend per common stock of $0.145 per share, or $0.58$1.51, $1.40 and $1.30 per share on an annualized basis. basis for 2023, 2022 and 2021 respectively.
In 2016, as part of2021, 2022 and 2023, NRG increased the 2016 Capital Allocation Program, the Company decreasedannual dividend on its annual common stock to $1.30, $1.40 and $1.51 per share, respectively, representing an 8% increase each year. The long-term capital allocation policy targets an annual dividend growth rate of 7%-9% per share in subsequent years. Beginning in the first quarter of 2024, NRG will increase the annual dividend by 79%8% to $0.12$1.63 per share for 2016share.
The Company's common stock dividends are subject to available capital, market conditions, and 2017. The following table lists the dividends paid per common share during 2017, 2016compliance with associated laws, regulations and 2015:
|
| | | | | | | | | | | | | | | |
| | Fourth Quarter | | Third Quarter | | Second Quarter | | First Quarter |
| 2017 | $ | 0.030 |
| | $ | 0.030 |
| | $ | 0.030 |
| | $ | 0.030 |
|
| 2016 | $ | 0.030 |
| | $ | 0.030 |
| | $ | 0.030 |
| | $ | 0.145 |
|
| 2015 | $ | 0.145 |
| | $ | 0.145 |
| | $ | 0.145 |
| | $ | 0.145 |
|
On January 19, 2018,2024, NRG declared a quarterly dividend on the Company's common stock of $0.03$0.4075 per share, or $0.12$1.63 per share on an annualized basis, payable on February 15, 2018,2024, to stockholders of record as of February 1, 2018.2024.
Employee Stock Purchase Plan — Under
The Company offers participation in the ESPP which allows eligible employees mayto elect to withhold up to between 1% and 10% of their eligible compensation to purchase shares of NRG common stock at the lesser of 85%90% of its fair market value on the offering date or 85%90% of the fair market value on the exercise date. An offering date occurs each JanuaryApril 1 and JulyOctober 1. An exercise date occurs each JuneSeptember 30 and DecemberMarch 31. On April 27, 2023, NRG stockholders approved the adoption of the Amended and Restated Employee Stock Purchase Plan, effective April 1, 2023, which included a reduction in the price at which eligible employees may purchase shares of NRG common stock from 95% to 90% of the fair market value of the shares on the applicable date. NRG stockholders also approved an increase of 4,400,000 shares available for the issuance under the ESPP. As of December 31, 2017,2023, there remained 3,107,0506,702,125 shares of treasury stock reserved for issuance under the ESPP,ESPP.
Share Repurchases
Share repurchases in 2021 and in January2022 were made under the December 6, 2021 $1 billion authorization, as part of 2018, 175,862NRG’s capital allocation policy. On June 22, 2023, following the acquisition of Vivint Smart Home, 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.
On November 6, 2023, the Company executed Accelerated Share Repurchase agreements to repurchase a total of $950 million of NRG's outstanding common stock. Under the ASR agreements, the Company paid a total of $950 million and will receive shares of NRG's common stock on specified settlement dates. The total number of shares purchased pursuant to the ASR agreements will generally be based on the volume-weighted average prices of NRG's common stock during the term of each ASR agreement, less a discount. The Company received initial shares of 4,494,224 on November 8, 2023 and an additional 13,181,918 shares on December 27, 2023, which were issued to employee accounts fromrecorded in treasury stock forat fair value based on the offeringvolume-weighted average closing prices of $833 million, with the remaining $117 million recorded in additional paid in capital, representing the value of the forward contracts to purchase additional shares. On January 30, 2024, an additional 770,205 shares were delivered. The ASR period will end in March of July 1, 2017 to December 31, 2017. Beginning January 2018, NRG suspended2024 and additional shares may be delivered upon final settlement of the ESPP.
Share Repurchases —During 2015remaining agreements. The total number of shares delivered and 2014, the Company's board of directors authorized share repurchases of $481 million of its common stock, which were made as follows:
|
| | | | | | | | | | |
| | Total number of shares purchased | | Average price paid per share (a) | | Amounts paid for shares purchased (in millions) (a) |
| Board Authorized Share Repurchases | | | | | |
| Fourth Quarter 2014 | 1,624,360 |
| | $ | 26.95 |
| | $ | 44 |
|
| First Quarter 2015 | 3,146,484 |
| | 25.15 |
| | 79 |
|
| Second Quarter 2015 | 4,379,907 |
| | 24.53 |
| | 107 |
|
| Third Quarter 2015 | 11,104,184 |
| | 15.06 |
| | 167 |
|
| Fourth Quarter 2015 | 5,558,920 |
| | 15.03 |
| | 84 |
|
| Total Board Authorized Share Repurchases | 25,813,855 |
| | | | $ | 481 |
|
(a) The average price paid per share and amounts paid for shares purchased exclude the commissions of $0.015 per share paid in connection with the share repurchase.
Preferred Stock
2.822% Redeemable Preferred Stock
Preferred Stock
On May 24, 2016, NRG entered an agreement with Credit Suisse Group to repurchase 100%all of the outstanding shares delivered under the ASR agreements will be determined at the end of its $344.5 million 2.822% preferred stock. On June 13, 2016,the ASR period.
During the year ended December 31, 2023, the Company completed $1.2 billion of share repurchases under the repurchase from Credit Suisse of 100% of$2.7 billion authorization, including $950 million through the outstanding sharesASR and $200 million through open market repurchases at aan average price of $226 million. The transaction resulted in a gain on redemption$39.56. As of $78 million, measured asFebruary 1, 2024, $1.5 billion is remaining under the difference between the fair value of the cash consideration paid upon redemption of $226 million and the carrying value of the preferred stock at the time of the redemption of $304 million. This amount is reflected in net income/(loss) available to NRG common stockholders in the calculation of earnings per share.$2.7 billion authorization.
The following table reflectssummarizes the changes in the Company's redeemable preferred stock balance for the years endedshare repurchases made from 2021 through February 1, 2024:
| | | | | | | | | | | | | | |
| Total number of shares purchased | Average price paid per share | Amounts paid for shares purchased (in millions) |
| 2021 Repurchases: | | | | |
Open market repurchases(a) | 1,084,752 | | $ | 40.85 | | $ | 44 | | |
| | | | |
| | | | |
| 2022 Repurchases: | | | | |
| Open market repurchases | 14,685,521 | | 40.48 | | 595 | | |
| | | | |
| | | | |
| 2023 Repurchases: | | | | |
| Open market repurchases | 5,054,798 | | | 200 | | |
| | | | |
Repurchases made under the accelerated share repurchase agreements(b) | 17,676,142 | | | 950 | | |
| Total Share Repurchases during 2023 | 22,730,940 | | (e) | $ | 1,150 | | (c) |
Repurchases made subsequent to December 31, 2023 under the accelerated share repurchase agreements(d) | 770,205 | | | — | | |
| Total Share Repurchases January 1, 2023 through February 1, 2024 | 23,501,145 | | (e) | $ | 1,150 | | |
(a)Includes $5 million accrued as of December 31, 2017, 2016,2021
(b)Initial and 2015:interim shares delivered under the November 6, 2023 accelerated share repurchase agreements
(c)Excludes $10 million accrued for excise tax owed as of December 31, 2023
(d)Additional shares delivered under the November 6, 2023 accelerated share repurchase agreements
(e)The total number of shares delivered and the average price per share under the ASR agreements will be determined at the end of the ASR period
Retirement of Treasury Stock
In the fourth quarter of 2023, the Company retired 157,676,142 shares of treasury stock. These retired shares are now included in NRG's pool of authorized but unissued shares. The retired stock had a carrying value of approximately $5.0 billion. The Company's accounting policy upon the formal retirement of treasury stock is to deduct its par value from common stock and to reflect any excess of cost over par value as a deduction from additional paid-in capital.
Preferred Stock
Series A Preferred Stock
On March 9, 2023 ("Series A Issuance Date"), the Company issued 650,000 shares of 10.25% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock. 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
|
| | | |
| | (In millions) |
| Balance as of December 31, 2014 | $ | 291 |
|
| Accretion to redemption value | 11 |
|
| Balance as of December 31, 2015 | 302 |
|
| Accretion to redemption value | 2 |
|
| Repurchase of 2.822% redeemable preferred stock | (226 | ) |
| Gain on redemption of 2.822% redeemable preferred stock | (78 | ) |
| Balance as of December 31, 2016 | — |
|
| Balance as of December 31, 2017 | $ | — |
|
Series A Preferred Stock Dividends The annual dividend rate on each share of Series A Preferred Stock is 10.25% from the Series A Issuance Date to, but excluding the Series A First Reset Date. On and after the Series A First Reset Date, the dividend rate on each share of Series A Preferred Stock shall equal the five-year U.S. Treasury rate as of the most recent reset dividend determination date (subject to a floor of 1.00%), plus a spread of 5.92% per annum. Cumulative cash dividends on the Series A Preferred Stock are payable semiannually, in arrears, on each March 15 and September 15, when, as and if declared by the Board of Directors. In September 2023, the Company declared and paid a semi-annual dividend of $52.96 per share on its outstanding Series A Preferred Stock, totaling $34 million.
Note 1617 — Investments Accounted for by the Equity Method and Variable Interest Entities
Entities that are not Consolidated
NRG accounts for the Company's significant investments using the equity method of accounting. NRG's carrying value of equity investments can be impacted by a number of elements including impairments unrealized gains and losses on derivatives and movements in foreign currency exchange rates, as well as other adjustments.rates.
The following table summarizes NRG's equity method investments as of December 31, 2017:2023:
| | | | | | | | | | | |
| (In millions, except percentages) | | | |
| Name: | Economic
Interest | | Investment Balance |
| Gladstone | 37.5 | % | | $ | 34 | |
| Midway-Sunset Cogeneration Company | 50.0 | % | | 8 | |
| | | |
| Total equity investments in affiliates | | $ | 42 | |
|
| | | | | | |
| Name | Economic Interest | | Investment Balance |
| | | | (In millions) |
Avenal Solar Holdings LLC (a) | 50.0 | % | | $ | (6 | ) |
Desert Sunlight Investment Holdings, LLC (a) | 25.0 | % | | 272 |
|
Elkhorn Ridge Wind, LLC (a) | 47.0 | % | | 73 |
|
GenConn Energy LLC (a) | 50.0 | % | | 102 |
|
Four Brothers Solar, LLC (a)(c) | 50.0 | % | | 213 |
|
Granite Mountain Holdings, LLC (a)(c) | 50.0 | % | | 78 |
|
Iron Springs Holdings, LLC (a)(c) | 50.0 | % | | 54 |
|
| Midway-Sunset Cogeneration Company | 50.0 | % | | 16 |
|
San Juan Mesa Wind Project, LLC (a) | 75.0 | % | | 66 |
|
| Watson Cogeneration Company | 49.0 | % | | 21 |
|
Gladstone Power Station (b) | 37.5 | % | | 139 |
|
Other(d) | Various |
| | 10 |
|
| Total equity investments in affiliates | | | $ | 1,038 |
|
(a) Equity method investments owned by NRG Yield
(b) Gladstone Power Station is located in Australia
(c) Economic interest based on cash to be distributed
(d) Refer to Note 10 - Asset Impairments for discussion ofThe following table summarizes the undistributed earnings from NRG's investment in Petra Nova Parish Holdings, LLC.
|
| | | | | | | |
| | As of December 31, |
| | 2017 | | 2016 |
| | (In millions) |
| Undistributed earnings from equity investments | $ | 120 |
| | $ | 101 |
|
Variable Interest Entities
NRG accounts for its interests in certain entities that are considered VIEs under ASC 810, for which NRG is not the primary beneficiary, under the equity method.
Utility-Scale Solar Portfolio —As described in Note 3, Discontinued Operations, Acquisitions and Dispositions, on November 2, 2016, the Company acquired equity interests in a tax equity financed portfolio comprised of 530 MW of mechanically-complete solar assets located in Utah, and subsequently sold these interests to NRG Yield, Inc. on March 27, 2017. These equity interests in Four Brothers Solar, LLC, Granite Mountain Holdings, LLC, and Iron Springs Holdings, LLC are accounted for as equity method investments as the Company does not have a controlling financial interest. The assets reached commercial operations during the fourth quarter of 2016 and have 20-year PPAs with PacifiCorp. NRG's maximum exposure to loss is limited to its equity investment, which was $345 million as of December 31, 2017.2023:
GenConn — NRG owns a 50% interest in GenConn, a limited liability company formed to construct, own and operate two 190-MW peaking generation facilities in Connecticut at NRG's Devon and Middletown sites. | | | | | | | | | | | |
| | As of December 31, |
| (In millions) | 2023 | | 2022 |
| Undistributed earnings | $ | — | | | $ | 42 | |
GenConn has a $237 million note with an interest rate of 4.73% and a maturity date of July 2041 and a 5-year, $35 million working capital facility which can be used to issue letters of credit at an interest rate of 1.875%. As of December 31, 2017, $204 million was outstanding under the note and $14 million of letters of credit issued under the working capital facility. The note is secured by all of the GenConn assets. NRG's maximum exposure to loss is limited to its equity investment, which was $102 million as of December 31, 2017.
Other Equity Investments
Gladstone — Through a joint venture, NRG owns a 37.5% interest in Gladstone, a 1,613 MW coal-fueled power generation facility in Queensland, Australia. The power generation facility is managed by the joint venture participants and the facility is operated by NRG. Operating expenses incurred in connection with the operation of the facility are funded by each of the participants in proportion to their ownership interests. Coal is sourced from local mines in Queensland. NRG and the joint venture participants receive their respective share of revenues directly from the off takers in proportion to the ownership interests in the joint venture. Power generated by the facility is primarily sold to an adjacent aluminum smelter, with excess power sold to the Queensland Government ownedGovernment-owned utility under long termlong-term supply contracts. NRG's investment in Gladstone was $139$34 million as of December 31, 2017.2023.
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 Policies. For one of the tax equity arrangements, the Company has a deficit restoration obligation equal to $110 million as of December 31, 2017, which would be required to be funded if the arrangement were to be dissolved.13, Long-term Debt and Finance Leases.
The summarized financial information for the Company's consolidated VIEs consisted of the following: | | | | | | | | | | | |
| (In millions) | December 31, 2023 | | December 31, 2022 |
| Accounts receivable and Other current assets | $ | 1,541 | | | $ | 2,108 | |
| | | |
| | | |
| | | |
| | | |
| Current liabilities | 153 | | | 152 | |
| | | |
| | | |
| | | |
| | | |
| Net assets | $ | 1,388 | | | $ | 1,956 | |
|
| | | | | | | |
| (In millions) | December 31, 2017 | | December 31, 2016 |
| Current assets | $ | 118 |
| | $ | 87 |
|
| Net property, plant and equipment | 2,337 |
| | 1,534 |
|
| Other long-term assets | 658 |
| | 954 |
|
| Total assets | 3,113 |
|
| 2,575 |
|
| Current liabilities | 96 |
| | 59 |
|
| Long-term debt | 661 |
| | 442 |
|
| Other long-term liabilities | 209 |
| | 183 |
|
| Total liabilities | 966 |
|
| 684 |
|
| Redeemable noncontrolling interests | 78 |
| | 46 |
|
| Noncontrolling interests | 507 |
| | 529 |
|
| Net assets less noncontrolling interests | $ | 1,562 |
|
| $ | 1,316 |
|
Note 1718 — Earnings/(Loss)/Income Per Share
Basic earnings/(loss)/income per common share is computed by dividing net income/(loss)/income less accumulatedcumulative dividends attributable to preferred stock dividends by the weighted average number of common shares outstanding. Shares issued and treasury shares repurchased during the year are weighted for the portion of the year that they were outstanding. Diluted earnings/(loss)/income per share is computed in a manner consistent with that of basic earnings/(loss)/income per share, while giving effect to all potentially dilutive common shares that were outstanding during the period.
Dilutive effect for equity compensation and other equity instruments — The outstanding non-qualifiedrelative performance stock options,units, non-vested restricted stock units, and market stock units and non-qualified stock options are not considered outstanding for purposes of computing basic earnings/(loss)/income per share. However, these instruments are included in the denominator for purposes of computing diluted earnings/(loss)/income per share under the treasury stock method.method for periods when there is net income. The if-converted methodConvertible Senior Notes are convertible, under certain circumstances, into cash or combination of cash and Company’s common stock. Prior to adoption of ASU 2020-06, there was used to determine theno dilutive effect for the Convertible Senior Notes due to the Company’s expectation to settle the liability in cash. Upon adoption of embedded derivativesASU 2020-06, on January 1, 2022, the Company is including the potential share settlements, if any, in the denominator for purposes of computing diluted (loss)/income per share under the if converted method for periods when there is net income. The potential shares settlements are calculated as the excess of the Company's 2.822% Preferred Stockconversion obligation over the aggregate principal amount (which will be settled in cash), divided by the average share price for the period. For the year ended December 31, 2015. During 2016,2023, there was no dilutive effect for the Company repurchased 100% ofConvertible Senior Note since there was a net loss. For the outstanding shares of its 2.822% preferred stock.year ended December 31, 2022, there was no dilutive effect for the Convertible Senior Notes since there were no potential share settlements for the period.
The reconciliation of NRG's basic earnings/(loss) per share toand diluted earnings/(loss)/income per share is shown in the following table:
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| (In millions, except per share amounts) | 2023 | | 2022 | | 2021 |
| Basic and diluted (loss)/income per share: | | | | | |
| Net (loss)/income | $ | (202) | | | $ | 1,221 | | | $ | 2,187 | |
| Less: Cumulative dividends attributable to Series A Preferred Stock | 54 | | | — | | | — | |
| | | | | |
| (Loss)/Income Available to Common Stockholders | $ | (256) | | | $ | 1,221 | | | $ | 2,187 | |
| Weighted average number of common shares outstanding - basic and diluted | 228 | | | 236 | | | 245 | |
| (Loss)/Income per weighted average common share — basic and diluted | $ | (1.12) | | | $ | 5.17 | | | $ | 8.93 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In millions, except per share amounts) |
| Basic and diluted loss per share attributable to NRG common stockholders | | | | | |
| Net loss attributable to NRG Energy, Inc. | $ | (2,153 | ) | | $ | (774 | ) | | $ | (6,382 | ) |
| Dividends for preferred shares | — |
| | 5 |
| | 20 |
|
| Gain on redemption of 2.822% redeemable perpetual preferred shares | — |
| | (78 | ) | | — |
|
| Loss Available to Common Stockholders | $ | (2,153 | ) | | $ | (701 | ) |
| $ | (6,402 | ) |
| Weighted average number of common shares outstanding | 317 |
|
| 316 |
|
| 329 |
|
Loss per weighted average common share — basic and diluted | $ | (6.79 | ) | | $ | (2.22 | ) | | $ | (19.46 | ) |
The following table summarizes NRG'sAs of December 31, 2023, the Company had 6 million of outstanding equity instruments that are anti-dilutive and were not included in the computation of the Company's diluted loss per share:share. As of December 31, 2022 and 2021, the Company had an insignificant number of outstanding equity instruments that are anti-dilutive and were not included in the computation of the Company’s diluted income per share.
|
| | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In millions of shares) |
| Equity compensation | 5 |
| | 5 |
| | 6 |
|
| Embedded derivative of 2.822% redeemable perpetual preferred stock | — |
| | — |
| | 16 |
|
| Total | 5 |
| | 5 |
| | 22 |
|
Note 1819 — Segment Reporting
The Company'sCompany’s segment structure reflects how management currently makes financial decisions and allocates resources. The Company's businesses are segregated as follows: Generation, which includes generation, international and BETM; Retail, which includes Mass customers and Business Solutions, which includes C&I customers and other distributed and reliability products; Renewables, which includes solar and wind assets, excluding those in NRG Yield; NRG Yield; and corporate activities. Intersegment sales are accounted for at market.
NRG Yield includes certainCompany manages its operations based on the combined results of the Company's contractedretail and wholesale generation assets. During 2017, NRG Yield acquired several projects totaling 555 MW for cash consideration of approximately $245 million from NRG. These acquisitions were treated asbusinesses with a transfer of entities under common control and accordingly, the financial information for years ended December 31, 2017, 2016, and 2015 have been recast to reflect these changes.
On June 14, 2017, as described in Note 3, Discontinued Operations, Acquisitions and Dispositions, NRG deconsolidated GenOn for financial reporting purposes. The financial information for years ended December 31, 2017, 2016, and 2015 have been recast to present GenOn as discontinuedgeographical focus. Vivint Smart Home operations are reported within the corporateVivint Smart Home segment.
NRG’sNRG's chief operating decision maker, its interim chief executive officer, evaluates the performance of its segments based on operational measures including adjusted earnings before interest, taxes, depreciation and amortization, or Adjusted EBITDA, free cash flow and allocation of capital, for allocation, as well as net income/(loss) and net income/(loss) attributable to NRG Energy, Inc.. 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.
During the years ended December 31, 2017, 2016 and 2015, theThe Company had no customer whichthat comprised more than 10% of the Company's consolidated revenues. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Year Ended December 31, 2017 |
| | Generation(a) |
| Retail (a) |
| Renewables(a) |
| NRG Yield(a) |
| Corporate(a) |
| Eliminations |
| Total |
| | (In millions) |
Operating revenues(a) | $ | 3,773 |
|
| $ | 6,380 |
|
| $ | 424 |
|
| $ | 1,009 |
|
| $ | 14 |
|
| $ | (971 | ) |
|
| $ | 10,629 |
|
| Operating expenses | 3,300 |
|
| 5,372 |
|
| 211 |
|
| 348 |
|
| 220 |
|
| (964 | ) |
|
| 8,487 |
|
| Depreciation and amortization | 377 |
|
| 117 |
|
| 196 |
|
| 334 |
|
| 32 |
|
| — |
|
|
| 1,056 |
|
| Impairment losses | 1,504 |
|
| 7 |
|
| 154 |
|
| 44 |
|
| — |
|
| — |
|
|
| 1,709 |
|
| Development costs | 13 |
|
| 2 |
|
| 45 |
|
| — |
|
| 7 |
|
| — |
|
|
| 67 |
|
| Total operating cost and expenses | 5,194 |
|
| 5,498 |
|
| 606 |
|
| 726 |
|
| 259 |
|
| (964 | ) |
|
| 11,319 |
|
| Other income - affiliate | — |
|
| — |
|
| — |
|
| — |
|
| 87 |
|
| — |
|
|
| 87 |
|
| Gain/(loss) on sale of assets | 20 |
|
| — |
|
| (5 | ) |
| — |
|
| 1 |
|
| — |
|
|
| 16 |
|
| Operating (loss)/income | (1,401 | ) |
| 882 |
|
| (187 | ) |
| 283 |
|
| (157 | ) |
| (7 | ) |
|
| (587 | ) |
| Equity in (losses)/earnings of unconsolidated affiliates | (14 | ) |
| — |
|
| — |
|
| 71 |
|
| 6 |
|
| (32 | ) |
|
| 31 |
|
| Impairment losses on investments | (74 | ) |
| — |
|
| — |
|
| — |
|
| (5 | ) |
| — |
|
|
| (79 | ) |
| Other income, net | 22 |
|
| 1 |
|
| — |
|
| 4 |
|
| 11 |
|
| — |
|
|
| 38 |
|
| Loss on debt extinguishment | — |
|
| — |
|
| (1 | ) |
| (3 | ) |
| (49 | ) |
| — |
|
|
| (53 | ) |
| Interest expense | (29 | ) |
| (6 | ) |
| (98 | ) |
| (306 | ) |
| (451 | ) |
| — |
|
|
| (890 | ) |
| (Loss)/income from continuing operations before income taxes | (1,496 | ) |
| 877 |
|
| (286 | ) |
| 49 |
|
| (645 | ) |
| (39 | ) |
|
| (1,540 | ) |
| Income tax expense/(benefit) | 2 |
|
| (9 | ) |
| (20 | ) |
| 72 |
|
| (37 | ) |
| — |
|
|
| 8 |
|
| Net (loss)/income from continuing operations | $ | (1,498 | ) |
| $ | 886 |
|
| $ | (266 | ) |
| $ | (23 | ) |
| $ | (608 | ) |
| $ | (39 | ) |
|
| $ | (1,548 | ) |
| Loss from discontinued operations, net of income tax | — |
|
| — |
|
| — |
|
| — |
|
| (789 | ) |
| — |
|
|
| $ | (789 | ) |
| Net (Loss)/Income | (1,498 | ) |
| 886 |
|
| (266 | ) |
| (23 | ) |
| (1,397 | ) |
| (39 | ) |
|
| (2,337 | ) |
| Less: Net income/(loss) attributable to noncontrolling interests and redeemable noncontrolling interests | — |
|
| 2 |
|
| (103 | ) |
| (87 | ) |
| (4 | ) |
| 8 |
|
|
| (184 | ) |
| Net (loss)/income attributable to NRG Energy, Inc. | $ | (1,498 | ) |
| $ | 884 |
|
| $ | (163 | ) |
| $ | 64 |
|
| $ | (1,393 | ) |
| $ | (47 | ) |
|
| $ | (2,153 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Balance sheet | |
| |
|
|
| |
| |
|
|
|
|
| Equity investments in affiliates | $ | 179 |
|
| $ | — |
|
| $ | 4 |
|
| $ | 852 |
|
| $ | 3 |
|
| $ | — |
|
|
| $ | 1,038 |
|
Capital expenditures (b) | 481 |
|
| 82 |
|
| 521 |
|
| 31 |
|
| 12 |
|
| — |
|
| 1,127 |
|
| Goodwill | 165 |
|
| 374 |
|
| — |
|
| — |
|
| — |
|
| — |
|
|
| 539 |
|
| Total assets | $ | 7,209 |
|
| $ | 2,630 |
|
| $ | 5,129 |
|
| $ | 8,283 |
|
| $ | 8,919 |
|
| $ | (8,852 | ) | — |
| $ | 23,318 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (a) Inter-segment sales and net derivative gains and losses included in operating revenues | $ | 910 |
| | $ | 5 |
| | $ | 31 |
| | $ | — |
| | $ | 25 |
| | $ | — |
| | $ | 971 |
|
(b) Includes accruals. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2023 |
| (In millions) | Texas | | East | | West/Services/Other | | Vivint Smart Home(a) | | Corporate(b) | | Eliminations | | Total |
Revenue(b) | $ | 10,476 | | | $ | 12,547 | | | $ | 4,281 | | | $ | 1,549 | | | $ | — | | | $ | (30) | | | $ | 28,823 | |
| Operating expenses | 8,407 | | | 14,412 | | | 5,025 | | | 917 | | | 133 | | | (30) | | | 28,864 | |
| Depreciation and amortization | 294 | | | 116 | | | 95 | | | 586 | | | 36 | | | — | | | 1,127 | |
| Impairment losses | 2 | | | 4 | | | 20 | | | — | | | — | | | — | | | 26 | |
| Total operating cost and expenses | 8,703 | | | 14,532 | | | 5,140 | | | 1,503 | | | 169 | | | (30) | | | 30,017 | |
| | | | | | | | | | | | | |
| Gain on sale of assets | 1,319 | | | 259 | | | — | | | — | | | — | | | — | | | 1,578 | |
| Operating income/(loss) | 3,092 | | | (1,726) | | | (859) | | | 46 | | | (169) | | | — | | | 384 | |
| Equity in earnings of unconsolidated affiliates | — | | | — | | | 16 | | | — | | | — | | | — | | | 16 | |
| Impairment losses on investments | — | | | — | | | (102) | | | — | | | — | | | — | | | (102) | |
| Other income, net | 2 | | | 11 | | | 6 | | | (12) | | | 56 | | | (16) | | | 47 | |
| Gain on debt extinguishment | — | | | — | | | — | | | — | | | 109 | | | — | | | 109 | |
| Interest expense | (3) | | | (3) | | | (31) | | | (177) | | | (469) | | | 16 | | | (667) | |
| Income/(loss) before income taxes | 3,091 | | | (1,718) | | | (970) | | | (143) | | | (473) | | | — | | | (213) | |
Income tax (benefit)/expense(c) | — | | | — | | | (111) | | | (32) | | | 132 | | | — | | | (11) | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Net income/(loss) | $ | 3,091 | | | $ | (1,718) | | | $ | (859) | | | $ | (111) | | | $ | (605) | | | $ | — | | | $ | (202) | |
| | | | | | | | | | | | | |
| Balance sheet | | | | | | | | | | | | | |
| Equity investments in affiliates | $ | — | | | $ | — | | | $ | 42 | | | $ | — | | | $ | — | | | $ | — | | | $ | 42 | |
| Capital expenditures | 495 | | | 5 | | | 27 | | | 18 | | | 53 | | | — | | | 598 | |
| Goodwill | 643 | | | 721 | | | 221 | | | 3,494 | | | — | | | — | | | 5,079 | |
| Total assets | $ | 8,236 | | | $ | 13,712 | | | $ | 3,626 | | | $ | 7,043 | | | $ | 19,919 | | | $ | (26,498) | | | $ | 26,038 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (a) Includes results of operations following the acquisition date of March 10, 2023 |
| (b) Inter-segment sales and inter-segment net derivative gains and losses included in revenues | $ | 5 | | | $ | 9 | | | $ | 16 | | | $ | — | | | $ | — | | | $ | — | | | $ | 30 | |
| (c) Consolidated domestic federal and state income taxes are recorded to the Corporate segment, except for Vivint Smart Home which is recorded directly to the Vivint Smart Home segment. West/Services/Other amounts represent foreign income taxes |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Year Ended December 31, 2022 |
| (In millions) | Texas | | East | | West/Services/Other | | Corporate(a) | | Eliminations | | Total |
Revenue(a) | $ | 10,057 | | | $ | 16,763 | | | $ | 4,706 | | | $ | — | | | $ | 17 | | | $ | 31,543 | |
| Operating expenses | 8,495 | | | 16,031 | | | 4,108 | | | 86 | | | 17 | | | 28,737 | |
| Depreciation and amortization | 310 | | | 208 | | | 85 | | | 31 | | | — | | | 634 | |
| Impairment losses | — | | | 206 | | | — | | | — | | | — | | | 206 | |
| Total operating cost and expenses | 8,805 | | | 16,445 | | | 4,193 | | | 117 | | | 17 | | | 29,577 | |
| | | | | | | | | | | |
| Gain/(loss) on sale of assets | 10 | | | — | | | 45 | | | (3) | | | — | | | 52 | |
| Operating income/(loss) | 1,262 | | | 318 | | | 558 | | | (120) | | | — | | | 2,018 | |
| Equity in (losses)/earnings of unconsolidated affiliates | (2) | | | — | | | 8 | | | — | | | — | | | 6 | |
| | | | | | | | | | | |
| Other income, net | 5 | | | 10 | | | 3 | | | 54 | | | (16) | | | 56 | |
| | | | | | | | | | | |
| Interest expense | — | | | (1) | | | (32) | | | (400) | | | 16 | | | (417) | |
| Income/(loss) before income taxes | 1,265 | | | 327 | | | 537 | | | (466) | | | — | | | 1,663 | |
Income tax expense(b) | — | | | 1 | | | 57 | | | 384 | | | — | | | 442 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Net income/(loss) | $ | 1,265 | | | $ | 326 | | | $ | 480 | | | $ | (850) | | | $ | — | | | $ | 1,221 | |
| | | | | | | | | | | |
| Balance sheet | | | | | | | | | | | |
| Equity investments in affiliates | $ | — | | | $ | — | | | $ | 133 | | | $ | — | | | $ | — | | | $ | 133 | |
| Capital expenditures | 273 | | | 7 | | | 37 | | | 50 | | | — | | | 367 | |
| Goodwill | 710 | | | 723 | | | 217 | | | — | | | — | | | 1,650 | |
| Total assets | $ | 11,475 | | | $ | 19,526 | | | $ | 8,139 | | | $ | 35,780 | | | $ | (45,774) | | | $ | 29,146 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (a) Inter-segment sales and inter-segment net derivative gains and losses included in revenues | $ | 4 | | | $ | (26) | | | $ | 5 | | | $ | — | | | $ | — | | | $ | (17) | |
| (b) Consolidated domestic federal and state income taxes are recorded to the Corporate segment. West/Services/Other amounts represent foreign income taxes |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Year Ended December 31, 2021 |
| (In millions) | Texas | | East | | West/Services/Other | | Corporate(a) | | Eliminations | | Total |
Revenue(a) | $ | 10,295 | | | $ | 13,025 | | | $ | 3,659 | | | $ | — | | | $ | 10 | | | $ | 26,989 | |
| Operating expenses | 8,692 | | | 10,256 | | | 3,467 | | | 141 | | | 10 | | | 22,566 | |
| Depreciation and amortization | 336 | | | 333 | | | 88 | | | 28 | | | — | | | 785 | |
| Impairment losses | — | | | 535 | | | 9 | | | — | | | — | | | 544 | |
| Total operating cost and expenses | 9,028 | | | 11,124 | | | 3,564 | | | 169 | | | 10 | | | 23,895 | |
| | | | | | | | | | | |
| Gain on sale of assets | 19 | | | — | | | 17 | | | 211 | | | — | | | 247 | |
| Operating income | 1,286 | | | 1,901 | | | 112 | | | 42 | | | — | | | 3,341 | |
| Equity in (losses)/earnings of unconsolidated affiliates | (3) | | | — | | | 20 | | | — | | | — | | | 17 | |
| | | | | | | | | | | |
| Other income, net | 8 | | | 7 | | | 3 | | | 59 | | | (14) | | | 63 | |
| Loss on debt extinguishment | — | | | — | | | — | | | (77) | | | — | | | (77) | |
| Interest expense | (1) | | | (1) | | | (28) | | | (469) | | | 14 | | | (485) | |
| Income/(loss) before income taxes | 1,290 | | | 1,907 | | | 107 | | | (445) | | | — | | | 2,859 | |
Income tax expense(b) | — | | | — | | | 19 | | | 653 | | | — | | | 672 | |
| Net income/(loss) | $ | 1,290 | | | $ | 1,907 | | | $ | 88 | | | $ | (1,098) | | | $ | — | | | $ | 2,187 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (a) Inter-segment sales and inter-segment net derivative gains and losses included in revenues | $ | 5 | | | $ | (18) | | | $ | 3 | | | $ | — | | | $ | — | | | $ | (10) | |
| (b) Consolidated domestic federal and state income taxes are recorded to the Corporate segment. West/Services/Other amounts represent foreign income taxes |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Year Ended December 31, 2016 |
| | Generation(a) |
| Retail (a) |
| Renewables(a) |
| NRG Yield(a) |
| Corporate(a) |
| Eliminations |
| Total |
| | (In millions) |
Operating revenues(a) | $ | 3,833 |
|
| $ | 6,335 |
|
| $ | 406 |
|
| $ | 1,035 |
|
| $ | 77 |
|
| $ | (1,174 | ) |
| $ | 10,512 |
|
| Operating expenses | 3,545 |
|
| 5,164 |
|
| 217 |
|
| 325 |
|
| 323 |
|
| (1,178 | ) |
| 8,396 |
|
| Depreciation and amortization | 516 |
|
| 111 |
|
| 185 |
|
| 303 |
|
| 57 |
|
| — |
|
| 1,172 |
|
| Impairment losses | 430 |
|
| 1 |
|
| 54 |
|
| 185 |
|
| 32 |
|
| — |
|
| 702 |
|
| Development costs | 15 |
|
| 4 |
|
| 40 |
|
| — |
|
| 30 |
|
| — |
|
| 89 |
|
| Total operating cost and expenses | 4,506 |
|
| 5,280 |
|
| 496 |
|
| 813 |
|
| 442 |
|
| (1,178 | ) |
| 10,359 |
|
| Other income - affiliate | — |
|
| — |
|
| — |
|
| — |
|
| 193 |
|
| — |
|
| 193 |
|
| Loss on sale of assets | — |
|
| (1 | ) |
| — |
|
| — |
|
| (79 | ) |
|
|
|
| (80 | ) |
| Operating (loss)/income | (673 | ) |
| 1,054 |
|
| (90 | ) |
| 222 |
|
| (251 | ) |
| 4 |
|
| 266 |
|
| Equity in (losses)/earnings of unconsolidated affiliates | (5 | ) |
| — |
|
| (58 | ) |
| 60 |
|
| 13 |
|
| 17 |
|
| 27 |
|
| Impairment losses on investments | (142 | ) |
| — |
|
| (105 | ) |
| — |
|
| (21 | ) |
| — |
|
| (268 | ) |
| Other income, net | 21 |
|
| (6 | ) |
| 1 |
|
| 3 |
|
| 19 |
|
| (4 | ) |
| 34 |
|
| Loss on debt extinguishment | — |
|
| — |
|
| — |
|
| — |
|
| (142 | ) |
| — |
|
| (142 | ) |
| Interest expense | (26 | ) |
| 6 |
|
| (98 | ) |
| (284 | ) |
| (495 | ) |
| 2 |
|
| (895 | ) |
| (Loss)/income from continuing operations before income taxes | (825 | ) |
| 1,054 |
|
| (350 | ) |
| 1 |
|
| (877 | ) |
| 19 |
|
| (978 | ) |
| Income tax (benefit)/expense | (1 | ) |
| 1 |
|
| (20 | ) |
| (1 | ) |
| 26 |
|
| — |
|
| 5 |
|
| Net (loss)/income from continuing operations | (824 | ) |
| 1,053 |
|
| (330 | ) |
| 2 |
|
| (903 | ) |
| 19 |
|
| (983 | ) |
| Income from discontinued operations, net of income tax | — |
|
| — |
|
| — |
|
| — |
|
| 92 |
|
|
|
|
| 92 |
|
| Net (Loss)/Income | (824 | ) |
| 1,053 |
|
| (330 | ) |
| 2 |
|
| (811 | ) |
| 19 |
|
| (891 | ) |
| Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests | — |
|
| (2 | ) |
| (13 | ) |
| (54 | ) |
| 18 |
|
| (66 | ) |
| (117 | ) |
| Net (loss)/income attributable to NRG Energy, Inc. | $ | (824 | ) |
| $ | 1,055 |
|
| $ | (317 | ) |
| $ | 56 |
|
| $ | (829 | ) |
| $ | 85 |
|
| $ | (774 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Balance sheet | |
| |
| |
| |
| |
| |
|
|
| Equity investments in affiliates | $ | 204 |
|
| $ | — |
|
| $ | 26 |
|
| $ | 886 |
|
| $ | 4 |
|
| $ | — |
|
| $ | 1,120 |
|
Capital expenditures(b) | 522 |
|
| 12 |
|
| 330 |
|
| 23 |
|
| 110 |
|
| — |
|
| 997 |
|
| Goodwill | 276 |
|
| 374 |
|
| 12 |
|
| — |
|
| — |
|
| — |
|
| 662 |
|
| Total assets | $ | 13,514 |
|
| $ | 2,332 |
|
| $ | 4,921 |
|
| $ | 8,962 |
|
| $ | 11,891 |
|
| $ | (10,938 | ) |
| $ | 30,682 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (a) Inter-segment sales and net derivative gains and losses included in operating revenues | $ | 1,033 |
| | $ | 4 |
| | $ | 24 |
| | $ | 8 |
| | $ | 105 |
| | $ | — |
| | $ | 1,174 |
|
(b) Includes accruals.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Year Ended December 31, 2015 |
| | Generation(a) | | Retail(a) | | Renewables(a) | | NRG Yield(a) | | Corporate(a) | | Eliminations | | Total |
| | (In millions) |
Operating revenues(a) | $ | 5,179 |
| | $ | 6,913 |
| | $ | 383 |
| | $ | 968 |
| | $ | 38 |
| | $ | (1,153 | ) | | $ | 12,328 |
|
| Operating expenses | 4,198 |
| | 6,138 |
| | 187 |
| | 338 |
| | 502 |
| | (1,135 | ) | | 10,228 |
|
| Depreciation and amortization | 693 |
| | 132 |
| | 176 |
| | 303 |
| | 47 |
| | — |
| | 1,351 |
|
| Impairment losses | 4,655 |
| | 36 |
| | 13 |
| | 1 |
| | 133 |
| | 22 |
| | 4,860 |
|
| Development costs | 26 |
| | 4 |
| | 61 |
| | — |
| | 63 |
| | — |
| | 154 |
|
| Total operating costs and expenses | 9,572 |
| | 6,310 |
| | 437 |
| | 642 |
| | 745 |
| | (1,113 | ) | | 16,593 |
|
| Other income - affiliate | — |
| | — |
| | — |
| | — |
| | 193 |
| | — |
| | 193 |
|
| Gain on postretirement benefits curtailment | 21 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 21 |
|
| Operating (loss)/income | (4,372 | ) | | 603 |
| | (54 | ) | | 326 |
| | (514 | ) | | (40 | ) | | (4,051 | ) |
| Equity in earnings/(losses)of unconsolidated affiliates | 10 |
| | — |
| | (7 | ) | | 31 |
| | — |
| | 2 |
| | 36 |
|
| Impairment losses on investments | (14 | ) | | — |
| | — |
| | — |
| | (42 | ) | | — |
| | (56 | ) |
| Other income, net | 18 |
| | (4 | ) | | 3 |
| | 3 |
| | 13 |
| | (7 | ) | | 26 |
|
| Loss on sale of equity method investment | — |
| | — |
| | — |
| | — |
| | (14 | ) | | — |
| | (14 | ) |
| Loss on debt extinguishment | — |
| | — |
| | — |
| | (9 | ) | | 19 |
| | — |
| | 10 |
|
| Interest expense | (25 | ) | | 2 |
| | (79 | ) | | (267 | ) | | (574 | ) | | 6 |
| | (937 | ) |
| (Loss)/income from continuing operations before income taxes | (4,383 | ) | | 601 |
| | (137 | ) | | 84 |
| | (1,112 | ) | | (39 | ) | | (4,986 | ) |
| Income tax expense/(benefit) | — |
| | 1 |
| | (18 | ) | | 12 |
| | 1,350 |
| | — |
| | 1,345 |
|
| Net (loss)/income from continuing operations | $ | (4,383 | ) | | 600 |
| | (119 | ) | | 72 |
| | (2,462 | ) | | (39 | ) | | (6,331 | ) |
| Loss from discontinued operations, net of income tax | — |
| | — |
| | — |
| | — |
| | (105 | ) | | — |
| | (105 | ) |
| Net (Loss)/Income | (4,383 | ) | | 600 |
| | (119 | ) | | 72 |
| | (2,567 | ) | | (39 | ) | | (6,436 | ) |
| Less: Net income/(loss) attributable to noncontrolling interests and redeemable noncontrolling interests | — |
| | — |
| | 6 |
| | 19 |
| | (37 | ) | | (42 | ) | | (54 | ) |
| Net (loss)/income attributable to NRG Energy, Inc. | $ | (4,383 | ) | | $ | 600 |
| | $ | (125 | ) | | $ | 53 |
| | $ | (2,530 | ) | | $ | 3 |
| | $ | (6,382 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (a) Inter-segment sales and net derivative gains and losses included in operating revenues | $ | 896 |
| | $ | 6 |
| | $ | 31 |
| | $ | 29 |
| | $ | 191 |
| | $ | — |
| | $ | 1,153 |
|
Note 1920 — Income Taxes
The income tax provision from continuing operations consisted of the following amounts:
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| (In millions, except effective income tax rate) | 2023 | | 2022 | | 2021 |
| Current | | | | | |
| U.S. Federal | $ | 26 | | | $ | 3 | | | $ | — | |
| State | 84 | | | 65 | | | 48 | |
| Foreign | (12) | | | 3 | | | 3 | |
| Total — current | 98 | | | 71 | | | 51 | |
| Deferred | | | | | |
| U.S. Federal | 50 | | | 258 | | | 569 | |
| State | (61) | | | 59 | | | 36 | |
| Foreign | (98) | | | 54 | | | 16 | |
| Total — deferred | (109) | | | 371 | | | 621 | |
| Total income tax (benefit)/expense | $ | (11) | | | $ | 442 | | | $ | 672 | |
| Effective income tax rate | 5.2 | % | | 26.6 | % | | 23.5 | % |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In millions, except percentages) |
| Current | | | | | |
| State | $ | 19 |
| | $ | 6 |
| | $ | 9 |
|
| Total — current | 19 |
| | 6 |
| | 9 |
|
| Deferred | | | | | |
| U.S. Federal | (6 | ) | | 3 |
| | 1,020 |
|
| State | (7 | ) | | (6 | ) | | 315 |
|
| Foreign | 2 |
| | 2 |
| | 1 |
|
| Total — deferred | (11 | ) | | (1 | ) | | 1,336 |
|
| Total income tax expense | $ | 8 |
| | $ | 5 |
| | $ | 1,345 |
|
| Effective tax rate | (0.5 | )% | | (0.5 | )% | | (27.0 | )% |
The following representsrepresented the domestic and foreign components of lossincome before income tax expense:taxes:
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| (In millions) | 2023 | | 2022 | | 2021 |
| U.S. | $ | 261 | | | $ | 1,436 | | | $ | 2,759 | |
| Foreign | (474) | | | 227 | | | 100 | |
| Total | $ | (213) | | | $ | 1,663 | | | $ | 2,859 | |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In millions) |
| U.S. | $ | (1,557 | ) | | $ | (989 | ) | | $ | (4,997 | ) |
| Foreign | 17 |
| | 11 |
| | 11 |
|
| Total | $ | (1,540 | ) | | $ | (978 | ) | | $ | (4,986 | ) |
A reconciliationReconciliations of the U.S. federal statutory tax rate of 35% to NRG's effective tax rate iswere as follows:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In millions, except percentages) |
| Loss before income taxes | $ | (1,540 | ) | | $ | (978 | ) | | $ | (4,986 | ) |
| Tax at 35% | (539 | ) | | (342 | ) | | (1,745 | ) |
| State taxes | 19 |
| | — |
| | (215 | ) |
| Foreign operations | 2 |
| | 10 |
| | 1 |
|
| Federal and state tax credits, excluding PTCs | — |
| | — |
| | (5 | ) |
| Tax Act - corporate income tax rate change | 733 |
| | — |
| | — |
|
| Valuation allowance due to corporate income tax rate change | (660 | ) | | — |
| | — |
|
| Valuation allowance - current period activities | 482 |
| | 398 |
| | 3,023 |
|
| Impact of non-taxable equity earnings | (5 | ) | | 22 |
| | (10 | ) |
| Book goodwill impairment | 30 |
| | — |
| | 340 |
|
| Net interest accrued on uncertain tax positions | — |
| | 1 |
| | (3 | ) |
| Production tax credits | (20 | ) | | (26 | ) | | (33 | ) |
| Recognition of uncertain tax benefits | (5 | ) | | 2 |
| | (15 | ) |
| Tax expense attributable to consolidated partnerships | 4 |
| | (1 | ) | | 12 |
|
| State rate change including true-up to current period activity | 18 |
| | (59 | ) | | (7 | ) |
| AMT refundable credit | (64 | ) | | — |
| | — |
|
| Other | 13 |
| | — |
| | 2 |
|
| Income tax expense | $ | 8 |
| | $ | 5 |
| | $ | 1,345 |
|
| Effective income tax rate | (0.5 | )% | | (0.5 | )% | | (27.0 | )% |
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| (In millions, except effective income tax rate) | 2023 | | 2022 | | 2021 |
| (Loss)/Income before income taxes | $ | (213) | | | $ | 1,663 | | | $ | 2,859 | |
| Tax at federal statutory tax rate | (45) | | | 349 | | | 600 | |
| State taxes | (22) | | | 69 | | | 111 | |
| Foreign rate differential | (10) | | | 7 | | | (3) | |
| Changes in state valuation allowances | 42 | | | (3) | | | (29) | |
| | | | | |
| Permanent differences | 31 | | | 17 | | | 8 | |
| Recognition of uncertain tax benefits | 12 | | | 8 | | | (10) | |
| | | | | |
| | | | | |
| Deferred impact of state tax rate changes | 3 | | | 14 | | | (10) | |
| | | | | |
| Foreign tax refunds | (17) | | | — | | | — | |
| Return to provision adjustments | (5) | | | — | | | 5 | |
| Carbon capture tax credits | — | | | (19) | | | — | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Income tax (benefit)/expense | $ | (11) | | | $ | 442 | | | $ | 672 | |
| Effective income tax rate | 5.2 | % | | 26.6 | % | | 23.5 | % |
For the year ended December 31, 2017,2023, NRG's overall effective income tax rate was differentlower than the federal statutory tax rate of 35%21%, primarily due to tax expense recorded from the revaluation of the existing net deferred tax assetpermanent differences and changes in state taxes, partially offset by the change in valuation allowance, establishing the AMT credit receivable and the generation of PTC’s from various wind facilities. The tax expense recorded for revaluation of the net deferred tax asset is required to reflect the reduction in the corporate income tax rate from 35% to 21% in accordance with the Tax Cuts and Jobs Act of 2017, or the Tax Act.allowances.
For the year ended December 31, 2016,2022, NRG's overall effective income tax rate was differenthigher than the federal statutory tax rate of 35%21% primarily due to the change in valuation allowance, the impact of non-taxable equity earnings and current state tax expense partially offset by the generationrecognition of PTCs from various wind facilities.carbon capture tax credits.
For the year ended December 31, 2015,2021, NRG's overall effective income tax rate was differenthigher than the federal statutory tax rate of 35%21% primarily due to recordingstate tax expense partially offset by tax benefits from the revaluation of a valuation allowance on the federal and certain state net deferred tax assets, that may not be realizable under a “more likely than not” measurement. In addition, a portionvaluation allowance, and settlements of the book goodwill impairment is classified as a permanent reversal impacting the effectiveuncertain tax rate.positions.
The temporary differences, which gave rise to the Company's deferred tax assets and liabilities consisted of the following:
|
| | | | | | | |
| | As of December 31, |
| | 2017 | | 2016 |
| | (In millions) |
| Deferred tax liabilities: | | | |
| Emissions allowances | $ | 15 |
| | $ | 31 |
|
| Derivatives, net | 15 |
| | — |
|
| Cumulative translation adjustments | — |
| | 11 |
|
| Investment in projects | 231 |
| | 378 |
|
| Discount/premium on notes | 2 |
| | 5 |
|
| Deferred financing costs | 2 |
| | 2 |
|
| Discontinued operations | — |
| | 6 |
|
| Total deferred tax liabilities | 265 |
| | 433 |
|
| Deferred tax assets: | | | |
| Deferred compensation, accrued vacation and other reserves | 141 |
| | 256 |
|
| Difference between book and tax basis of property | 596 |
| | 530 |
|
| Goodwill | 38 |
| | 83 |
|
| Differences between book and tax basis of contracts | 68 |
| | 60 |
|
| Pension and other postretirement benefits | 74 |
| | 122 |
|
| Equity compensation | 10 |
| | 11 |
|
| Bad debt reserve | 14 |
| | 12 |
|
| U.S. capital loss carryforwards | 1 |
| | 1 |
|
| U.S. Federal net operating loss carryforwards | 596 |
| | 728 |
|
| Foreign net operating loss carryforwards | 66 |
| | 63 |
|
| State net operating loss carryforwards | 140 |
| | 106 |
|
| Foreign capital loss carryforwards | 1 |
| | 1 |
|
| Federal and state tax credit carryforwards | 376 |
| | 446 |
|
| Federal benefit on state uncertain tax positions | 7 |
| | 12 |
|
| Intangibles amortization (excluding goodwill) | 101 |
| | 115 |
|
| Derivatives, net | — |
| | 106 |
|
| Inventory obsolescence | 12 |
| | 5 |
|
| Other | — |
| | 7 |
|
| Discontinued operations | — |
| | 2,093 |
|
| Total deferred tax assets | 2,241 |
| | 4,757 |
|
| Valuation allowance | (1,863 | ) | | (2,032 | ) |
| Discontinued operations | — |
| | (2,087 | ) |
| Total deferred tax assets, net of valuation allowance | 378 |
| | 638 |
|
| Net deferred tax asset | $ | 113 |
| | $ | 205 |
|
| | | | | | | | | | | |
| | As of December 31, |
| (In millions) | 2023 | | 2022 |
| Deferred tax assets: | | | |
| U.S. Federal net operating loss carryforwards | $ | 1,762 | | | $ | 1,717 | |
| State net operating loss carryforwards | 367 | | | 315 | |
| Foreign net operating loss carryforwards | 110 | | | 104 | |
| Deferred revenues | 347 | | | — | |
| Difference between book and tax basis of property | 353 | | | 399 | |
| Federal and state tax credit carryforwards | 317 | | | 393 | |
| Deferred compensation, accrued vacation and other reserves | 141 | | | 93 | |
| Interest disallowance carryforward per §163(j) of the Tax Act | 132 | | | 65 | |
| Pension and other postretirement benefits | 48 | | | 62 | |
| Allowance for credit losses | 35 | | | 33 | |
| Equity compensation | 24 | | | 8 | |
| | | |
| Federal benefit on state uncertain tax positions | 13 | | | 5 | |
| | | |
| Inventory obsolescence | 11 | | | 10 | |
| U.S. capital loss | 1 | | | 15 | |
| Other | 33 | | | 22 | |
| | | |
| Total deferred tax assets | 3,694 | | | 3,241 | |
| Deferred tax liabilities: | | | |
| Intangibles amortization (excluding goodwill) | 726 | | | 269 | |
| Derivatives | 156 | | | 874 | |
| Capitalized contract costs | 131 | | | — | |
| Equity method investments | 93 | | | 82 | |
| Goodwill | 40 | | | 26 | |
| Debt discount amortization | 26 | | | — | |
| Emissions allowances | 18 | | | 19 | |
| | | |
| | | |
| | | |
| Total deferred tax liabilities | 1,190 | | | 1,270 | |
| Total deferred tax assets less deferred tax liabilities | 2,504 | | | 1,971 | |
| Valuation allowance | (275) | | | (224) | |
| | | |
| Total net deferred tax assets, net of valuation allowance | $ | 2,229 | | | $ | 1,747 | |
| | | |
The following table summarizes NRG's net deferred tax position:position as presented in the consolidated balance sheets:
|
| | | | | | | |
| | As of December 31, |
| | 2017 | | 2016 |
| | (In millions) |
| Net deferred tax asset — noncurrent | $ | 134 |
| | $ | 225 |
|
| Net deferred tax liability — noncurrent | (21 | ) | | (20 | ) |
| Net deferred tax asset | $ | 113 |
| | $ | 205 |
|
| | | | | | | | | | | |
| | As of December 31, |
| (In millions) | 2023 | | 2022 |
| Deferred tax asset | $ | 2,251 | | | $ | 1,881 | |
| | | |
| Deferred tax liability | (22) | | | (134) | |
| Net deferred tax asset | $ | 2,229 | | | $ | 1,747 | |
| | | |
The primary driverdrivers for the decreaseincrease in the net deferred tax asset from $205 million to $113 million is the revaluation of the ending balance utilizing a 21% corporate income tax rate instead of a 35% corporate income tax rate pursuant to the Tax Act$1.7 billion as of December 22, 2017. NRG Energy, Inc.’s revaluation31, 2022 to $2.2 billion as of December 31, 2023 is completelydue to unrealized mark-to-market book losses and deferred revenues, partially offset by its valuation allowance. Since NRG Yield, Inc. does not havecapitalized contract costs and a valuation allowance against its net deferred tax asset, its ending balance remains at December 31, 2017. Additionally, due to GenOn's petition for bankruptcy on June 14, 2017, its inventorystep-up in basis of deferreds is reclassed to discontinued operations forbook intangibles associated with the year ended December 31, 2016 and is completely deconsolidated for the year ended December 31, 2017.acquisition of Vivint Smart Home.
Deferred tax assets and valuation allowance
Net deferred tax balance — As of December 31, 20172023 and 2016,2022, NRG recorded a net deferred tax asset, excluding valuation allowance, of $1.9$2.5 billion and $2.2$2.0 billion, respectively. The Company believes the federal and certain state net deferred tax assetsoperating losses may not be realizable under a “more likely than not”the more-likely-than-not measurement and as such, a valuation allowance was recorded as of December 31, 2023 as discussed below.
NOL carryforwards — As of December 31, 2023, the Company had tax-effected cumulative U.S. NOLs consisting of carryforwards for federal and state income tax purposes of $1.8 billion and $367 million, respectively. In addition, NRG has beentax-effected cumulative foreign NOL carryforwards of $110 million. The majority of NRG's NOL carryforwards have no expiration date.
Valuation allowance — As of December 31, 2023, the Company's tax-effected valuation allowance was $275 million, consisting of state NOL carryforwards and foreign NOL carryforwards. The valuation allowance was recorded to reducebased on the asset accordingly. The Company assessesassessment of cumulative and forecasted pretaxpre-tax book earnings and the future reversal of existing taxable temporary differences, including the potential impacts of the recently enacted Tax Act. In December 2017, the SEC staff issued Staff Accounting Bulletin No. 118, which addresses how a company may recognize provisional amounts for the effect of the changes related to the Tax Act. Consistent with that guidance, the Company recognized provisional amounts based upon our interpretation of the tax laws and estimates which require significant judgments.differences.
Based on the Company's assessment of positive and negative evidence, including available tax planning strategies, NRG believes that it is more likely than not that a benefit will not be realized on $1.8 billion and $2.0 billion of tax assets as of December 31, 2017, and 2016, respectively, thus a valuation allowance has been recorded. The net deferred tax asset of $113 million is predominantly due to the inclusion of NRG Yield Inc.'s net deferred tax asset consisting primarily of net operating losses.
NOL carryforwards — At December 31, 2017, the Company had tax effected cumulative domestic NOLs consisting of carryforwards for federal income tax purposes of $596 million and state of $140 million. The Company estimates it will need to generate future taxable income to fully realize the net federal deferred tax asset before expiration commencing in 2026. In addition, NRG has cumulative foreign NOL carryforwards of $66 million with no expiration date.
Valuation allowance — As of December 31, 2017, the Company's tax effected valuation allowance was $1.8 billion, consisting of domestic federal net deferred tax assets of approximately $1.5 billion, domestic state net deferred tax assets of $267 million, foreign net operating loss carryforwards of $66 million and foreign capital loss carryforwards of approximately $1 million. Based upon the assessment of cumulative and forecasted pretax book earnings, and the future reversal of existing taxable temporary differences, it was determined that a valuation allowance was required to be recorded during the year.
Taxes Receivable and Payable
As of December 31, 2017,2023, NRG recorded a current taxfederal payable of $7$20 million, that represents a tax liability due forcurrent net state income taxes. NRG haspayable of $3 million and a taxcurrent net foreign receivable of $1 million, comprised of refunds due from state income tax estimated payments and return filings for 2017 and 2016, respectively.$7 million.
Uncertain tax benefits
NRG has identified uncertain tax benefits whosewith after-tax value is $30of $73 million for which,and $22 million as of December 31, 20172023 and 2016,2022, for which NRG has recorded a non-current tax liability of $33$76 million and $37$24 million, respectively. The Company recognizes interest and penalties related to uncertain tax benefits in income tax expense. DuringThe Company recognized $1 million of interest expense for the year ended December 31, 2017, the Company recognized an expense of2023, $1 million in interest.for the year ended 2022 and an immaterial amount for the year ended 2021. As of December 31, 20172023 and 2016,2022, NRG had cumulative interest and penalties related to these uncertain tax benefits of $3 million and $4$2 million, respectively.
Tax jurisdictions — 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 no longer subject to U.S. federal income tax examinations for years prior to 2015.2020. With few exceptions, state and localCanadian income tax examinations are no longer open for years before 2010.2015.
The following table reconciles the total amounts ofsummarizes uncertain tax benefits:benefits activity:
| | | | | | | | | | | |
| | As of December 31, |
| (In millions) | 2023 | | 2022 |
| Balance as of January 1 | $ | 22 | | | $ | 13 | |
| Increase due to current year positions | 28 | | | 9 | |
| Increase due to acquired balance from Vivint Smart Home | 23 | | | — | |
| | | |
| | | |
| Uncertain tax benefits as of December 31 | $ | 73 | | | $ | 22 | |
|
| | | | | | | |
| | As of December 31, |
| | 2017 | | 2016 |
| | (In millions) |
| Balance as of January 1 | $ | 34 |
| | $ | 32 |
|
| Increase due to current year positions | 4 |
| | 8 |
|
| Decrease due to prior year positions | (8 | ) | | — |
|
| Decrease due to settlements and payments | — |
| | (6 | ) |
| Uncertain tax benefits as of December 31 | $ | 30 |
| | $ | 34 |
|
Note 2021 — Stock-Based Compensation
The Company's stock-based compensation consists of awards granted under the NRG LTIP and following the Acquisition in March 2023, the Vivint LTIP.
NRG Energy, Inc. Long-Term Incentive Plan
On April 27, 2017, the NRG LTIP was amended to increase the number of shares available for issuance by 3,000,000. As of December 31, 20172023 and 2016,2022, a total of 25,000,000 and 22,000,000 shares of NRG common stock were authorized for issuance under the NRG LTIP, respectively.LTIP. There were 8,724,5957,717,139 and 7,487,0588,179,771 shares of common stock remaining available for grants under the NRG LTIP as of December 31, 20172023 and 2016,2022, respectively. The NRG LTIP is subject to adjustments in the event of reorganization, recapitalization, stock split, reverse stock split, stock dividend, and a combination of shares, merger or similar change in NRG's structure or outstanding shares of common stock.
Upon adoption of the amended NRG LTIP effective April 27, 2017, no shares of NRG common stock remain available for future issuance under the NRG GenOn LTIP as of December 31, 2017. There were 5,558,390 shares of NRG common stock authorized for issuance under the NRG GenOn LTIP as of December 31, 2016. As of December 31, 2017 and 2016, there were 1,369,880 and 960,904 shares of common stock remaining available for grants2023, the outstanding awards under the NRG GenOn LTIP respectively.include restricted stock units, deferred stock units and relative performance stock units.
Restricted Stock OptionsUnits
NQSOsAs of December 31, 2023, RSUs granted under the NRG LTIP and the NRG GenOn LTIP typically have three-year graded vesting schedules beginning on the grant date and become exercisable at the end of the requisite service period. NRG recognizes compensation costs for NQSOs over the requisite service period for the entire award. The maximum contractual term is 10 years for NRG's outstanding NQSOs. No NQSOs were granted in 2017, 2016 or 2015.
The following table summarizes the Company's NQSO activity and changes during the year:
|
| | | | | | | | | | | | |
| | Shares(a) | | Weighted Average Exercise Price | | Weighted Average Remaining Contractual Term | | Aggregate Intrinsic Value |
| | | | (In years) | | (In millions) |
| Outstanding at December 31, 2016 | 1,522,919 |
| | $ | 25.03 |
| | 3 | | $ | — |
|
| Forfeited | (50,001 | ) | | 29.35 |
| | | | |
| Exercised | (187,060 | ) | | 20.71 |
| | | | |
| Outstanding at December 31, 2017 | 1,285,858 |
| | 25.49 |
| | 3 | | 6 |
|
| Exercisable at December 31, 2017 | 1,285,858 |
| | 25.49 |
| | 3 | | 6 |
|
(a) As of December 31, 2017, 51,207 NQSOs granted to employees of GenOn remain outstanding and exercisable.
The following table summarizes the total intrinsic value of options exercised and the cash received from the exercises of options:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In millions) |
| Total intrinsic value of options exercised | $ | 1 |
| | $ | — |
| | $ | 2 |
|
| Cash received from options exercised | 4 |
| | — |
| | 9 |
|
There were no options exercised during the year ended December 31, 2016.
Restricted Stock Units
As of December 31, 2017, RSUs granted under the Company's LTIPs typically have three-yearthree-year graded vesting schedules beginning on the grant date. Fair value of the RSUs granted during 2023 and 2022 is based onderived from the closing price of NRG common stock on the date of grant.grant date. The following table summarizes the Company's non-vested RSU awards and changes during the year:
|
| | | | | | |
| | Units(a) | | Weighted Average Grant-Date Fair Value per Unit |
| Non-vested at December 31, 2016 | 1,980,141 |
| | $ | 19.29 |
|
| Granted | 1,247,075 |
| | 12.44 |
|
| Forfeited | (176,132 | ) | | 14.98 |
|
| Vested | (673,271 | ) | | 23.65 |
|
| Non-vested at December 31, 2017 | 2,377,813 |
| | 14.63 |
|
(a) As of December 31, 2017, 20,822 RSUs granted to GenOn employees remain outstanding. | | | | | | | | | | | |
| Units | | Weighted Average Grant Date Fair Value per Unit |
| Non-vested at December 31, 2022 | 856,917 | | | $ | 40.25 | |
| Granted | 1,031,469 | | | 35.71 | |
| Forfeited | (284,076) | | | 34.70 | |
| Vested | (393,470) | | | 39.67 | |
| | | |
| Non-vested at December 31, 2023 | 1,210,840 | | | 37.88 | |
The total fair value of RSUs vested during the years ended December 31, 2017, 2016,2023, 2022 and 2015,2021 was $19$20 million, $11$10 million and $10$12 million, respectively. The weighted average grant date fair value of RSUs granted during the years ended December 31, 2017, 2016,2023, 2022 and 20152021 was $12.44, $11.54,$35.71, $41.26 and $27.31,$39.00, respectively.
Deferred Stock Units
DSUs represent the right of a participant to be paid one share of NRG common stock at the end of a deferral period established under the terms of the award. DSUs granted under the Company's LTIPsNRG LTIP are fully vested at the date of issuance. Fair value of the DSUs, which is based on the closing price of NRG common stock on the date of grant, is recorded as compensation expense in the period of grant.
The following table summarizes the Company's outstanding DSU awards and changes during the year:
|
| | | | | | |
| | Units(a) | | Weighted Average Grant-Date Fair Value per Unit |
| Outstanding at December 31, 2016 | 453,674 |
| | $ | 21.54 |
|
| Granted | 120,251 |
| | 16.76 |
|
| Converted to Common Stock | (146,777 | ) | | 17.62 |
|
| Outstanding at December 31, 2017 | 427,148 |
| | 21.54 |
|
(a) There were no DSUs granted to GenOn employees and outstanding as of December 31, 2017. | | | | | | | | | | | |
| Units | | Weighted Average Grant Date Fair Value per Unit |
| Outstanding at December 31, 2022 | 418,014 | | | $ | 27.63 | |
| Granted | 79,072 | | | 34.40 | |
| | | |
| Converted to Common Stock | (53,799) | | | 25.11 | |
| | | |
| Outstanding at December 31, 2023 | 443,287 | | | 29.07 | |
The aggregate intrinsic values for DSUs outstanding as of December 31, 2017, 2016,2023, 2022 and 20152021 were approximately $12$23 million,, $6 $13 million, and $5$17 million,, respectively. The aggregate intrinsic values for DSUs converted to common stock for the years ended December 31, 2017, 2016,2023, 2022 and 20152021 were $4$3 million, $1 million and less than a$1 million, respectively. The weighted average grant date fair value of DSUs granted during the years ended December 31, 2017, 2016,2023, 2022 and 20152021 was $16.76, $16.85$34.40, $45.49 and $25.14,$32.27, respectively.
Relative Performance Stock Units
PSUsRPSUs entitle the recipient to stock upon vesting. The amount of the award is subject to the Company's achievement of certain performance measures over the vesting period. As of December 31, 2017, non-vested PSUs consist of Market Stock Units, or MSUs, and Relative Performance Stock Units, or RPSUs.
Relative Performance Stock Units — RPSUs are restricted grants where the quantity of shares increases and decreases alongside the Company's Total Shareholder Return or TSR,("TSR"), relative to the TSR of the Company’sCompany's current proxy peer group and the total returns of select indexes, or Peer Group. For RPSU's granted in 2022 and forward, the peer group consists of the companies that comprise the Standard & Poor’s 500 Index on the first day of the performance period. Each RPSU represents the potential to receive NRG common stock after the completion of the performance period, typically three years of service from the date of grant. The number of shares of NRG common stock to be paid (if any) as of the vesting date for each RPSU will depend on the Company’s percentile rank within the Peer Group. The number of shares of common stock to be paid as of the vesting date for each RPSU is linearly interpolated for TSR performance between the following points: (i) 0% if ranked below the 25th percentile; (ii) 25% if ranked at the 25th percentile; (iii) 100% if ranked at the 55th percentile (or the 65th percentile if the Company’sCompany's absolute TSR is less than negative 15%); and (iv) 200% if ranked at the 75th percentile or above. The value of the common stock on the date of grant is based on the closing price of NRG common stock on the date of grant.
Market Stock Units — MSUs are restricted grants where the quantity of shares increases and decreases alongside the Company's TSR. Each MSU represents the potential to receive NRG common stock after the completion of the performance period, typically three years of service from the date of grant. The number of shares of common stock to be paid as of the vesting date for each MSU is : (i) zero shares, if the TSR has decreased by more than 25% over the performance period, (ii) three-quarters of one share, if the TSR has decreased by 25% over the performance period; (iii) interpolated between three-quarters of one share and one share, if the TSR has decreased less than 25% over the performance period; (iv) one share, if there is no change in TSR over the performance period; (v) interpolated between one share and two shares, if TSR increases less than 100% during the performance period; and (vi) two shares, if the TSR increases 100% over the performance period. The value of the common stock on the date of grant is based on the closing price of NRG common stock on the date of grant. The Company last granted MSUs during the year ended December 31, 2016.
The following table summarizes the Company's non-vested PSURPSU awards and changes during the year:
| | | | | | | | | | | |
| Units | | Weighted Average Grant-Date Fair Value per Unit |
| Non-vested at December 31, 2022 | 795,335 | | | $ | 50.23 | |
| Granted | 617,510 | | | 39.46 | |
Forfeited(a) | (737,227) | | | 45.61 | |
| Vested | (3,729) | | | 50.28 | |
| Non-vested at December 31, 2023 | 671,889 | | | 46.27 | |
|
| | | | | | |
| | Units(a) | | Weighted Average Grant-Date Fair Value per Unit |
| Non-vested at December 31, 2016 | 1,282,588 |
| | $ | 21.47 |
|
| Granted | 738,830 |
| | 15.91 |
|
| Forfeited | (162,597 | ) | | 31.85 |
|
| Non-vested at December 31, 2017 | 1,858,821 |
| | 18.27 |
|
There were no PSUs grantedIncludes January 2023 vestings that occurred at a 0% payout as well as forfeitures due to GenOn employees and outstanding asthe departure of December 31, 2017.certain officersThe weighted average grant date fair value of PSUsRPSUs granted during the years ended December 31, 2017, 20162023, 2022 and 2015,2021, was $15.91, $14.73$39.46, $57.41 and $26.68,$46.78, respectively.
The fair value of PSUsRPSUs is estimated on the date of grant using a Monte Carlo simulation model and expensed over the service period, which equals the vesting period. Significant assumptions used in the fair value model with respect to the Company's PSUsRPSUs are summarized below:
| | | | | | | | | | | | | | | | | | | | |
| 2023 | | 2022 | | 2021(a) | | | |
| | | | | | | | |
| Expected volatility | 41.35 | % | | 37.54 | % | | 34.05 | % | | | |
| Expected term (in years) | 3 | | 3 | | 3 | | | |
| Risk free rate | 4.18 | % | | 0.97 | % | | 0.17 | % | | | |
|
| | | | | |
| | 2017 | | 2016 |
| | RPSUs | | MSUs |
| Expected volatility | 43.96 | % | | 34.33 | % |
| Expected term (in years) | 3 |
| | 3 |
|
| Risk free rate | 1.5 | % | | 1.31 | % |
For the years ended December 31, 2017 and 2016,The expected volatility is calculated based on NRG's historical stock price volatility data over the period commensurate with the expected term of the PSU,RPSU, which equals the vesting period.
Vivint Smart Home Long-Term Incentive Plan
Effective March 10, 2023, in connection with the Vivint Smart Home Acquisition, as discussed in Note 4, Acquisitions and Dispositions, NRG assumed the Vivint Smart Home, Inc. Long-Term Incentive Plan, or Vivint LTIP. In addition to the rollover awards converted as part of the Acquisition, the Vivint LTIP provides for issuances of time-based restricted stock units and performance-based restricted stock units. As of December 31, 2023, 17,500,000 shares of NRG common stock were authorized for issuance under the Vivint LTIP, and there were 12,749,736 shares of common stock remaining available for grants.
Restricted Stock Units
As of December 31, 2023, RSUs under the Vivint LTIP include RSUs which were granted prior to the Acquisition and were converted into awards that will vest as NRG common stock ("Rollover RSUs"). These awards typically had four-year graded vesting schedules beginning on the grant date. The fair value of the Rollover RSUs is based on the fair value of NRG common stock on the Acquisition date after applying the conversion ratio as per the Merger Agreement. The RSUs that were granted following the Acquisition date are typically subject to the same terms as the RSUs under the NRG LTIP.
The following table summarizes the non-vested RSUs under the Vivint LTIP and changes during the year:
| | | | | | | | | | | | | | | | | | | | | | | |
| Rollover RSUs | | RSUs granted following the Acquisition |
| Units | | Weighted Average Grant Date Fair Value per Unit | | Units | | Weighted Average Grant Date Fair Value per Unit |
| Non-vested at December 31, 2022 | — | | | $ | — | | | — | | | $ | — | |
| Rollover RSUs at the Acquisition date | 4,553,998 | | | 31.63 | | | — | | | — | |
| Granted following the Acquisition date | — | | | — | | | 895,827 | | | 35.24 | |
| Forfeited | (288,776) | | | 31.63 | | | (110,531) | | | 35.21 | |
| Vested | (1,280,321) | | | 31.63 | | | (4,998) | | | 35.21 | |
| | | | | | | |
| Non-vested at December 31, 2023 | 2,984,901 | | | 31.63 | | | 780,298 | | | 35.24 | |
The total fair value of RSUs vested during the year ended December 31, 2023 was $66 million.
Performance Stock Units
As of December 31, 2023, PSUs granted under the Vivint LTIP are generally granted under the same terms as the PSUs granted under the NRG LTIP, and are valued using the same methods and assumptions. During the year ended December 31, 2023, 102,837 PSUs were granted at a weighted average grant date fair value per unit of $44.96 and remain outstanding as of year end.
Supplemental Information
The following table summarizes NRG's total compensation expense recognized for the years presented, as well as total non-vested compensation costs not yet recognized and the period over which this expense is expected to be recognized as of December 31, 2017,2023, for each of the types of awards issued under the LTIPs. Minimum tax withholdings of $5$22 million,, $5 $6 million,, and $21$9 million for the years ended December 31, 2017, 2016,2023, 2022, and 2015,2021, respectively, are reflected as a reduction to additional paid-in capital on the Company's consolidated balance sheet and are reflected as operating activities on the Company's consolidated statement of cash flows.sheets.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Non-vested Compensation Cost | |
| (In millions, except weighted average data) | Compensation Expense | | Unrecognized Total Cost | | Weighted Average Recognition Period Remaining (In years) | |
| Year Ended December 31, | | As of December 31, | |
| Award | 2023 | | 2022 | | 2021 | | 2023 | | 2023 | |
| | | | | | | | | | |
| RSUs under NRG LTIP | $ | 20 | | | $ | 15 | | | $ | 9 | | | $ | 29 | | | 1.61 | |
| RSUs under Vivint LTIP | 76 | | | — | | | — | | | 69 | | | 1.82 | |
| PSUs under Vivint LTIP | 2 | | | — | | | — | | | 3 | | | 2.25 | |
| DSUs | 2 | | | 2 | | | 2 | | | — | | | 0.00 | |
| | | | | | | | | | |
| RPSUs | 3 | | | 11 | | | 9 | | | 17 | | | 1.69 | |
PRSUs under NRG LTIP(a) | 12 | | | 6 | | | 7 | | | 15 | | | 1.74 | |
PRSUs under Vivint LTIP(a) | 8 | | | — | | | — | | | 14 | | | 2.29 | |
| Total | $ | 123 | | | $ | 34 | | | $ | 27 | | | $ | 147 | | | | |
| Tax detriment recognized | $ | 2 | | | $ | 3 | | | $ | 2 | | | | | | |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | Non-vested Compensation Cost |
| | Compensation Expense | | Unrecognized Total Cost | | Weighted Average Recognition Period Remaining (In years) |
| | Year Ended December 31, | | As of December 31, |
| Award | 2017 | | 2016 | | 2015 | | 2017 | | 2017 |
| | (In millions, except weighted average data) |
NQSOs(a) | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | — |
|
| RSUs | 17 |
| | 13 |
| | 22 |
| | 13 |
| | 1.37 |
|
| DSUs | 2 |
| | 2 |
| | 2 |
| | — |
| | — |
|
| MSUs | 6 |
| | 3 |
| | 16 |
| | 4 |
| | 0.82 |
|
| RPSUs | 4 |
| | — |
| | — |
| | 6 |
| | 1.99 |
|
PRSUs(b) | 15 |
| | 5 |
| | — |
| | 14 |
| | 1.51 |
|
Total(c) | $ | 44 |
| | $ | 23 |
| | $ | 40 |
| | $ | 37 |
| | |
|
| Tax detriment recognized | $ | (5 | ) | | $ | (4 | ) | | $ | (12 | ) | | |
| | |
|
(a) All NQSOs granted under the Company's LTIP were fully vested as of December 31, 2017, 2016, and 2015.
(b) Phantom Restricted Stock Units, PRSUs, are liability-classified time-based awards that typically vest ratably over a three-yearthree-year period. The amount to be paid upon vesting is based on NRG's closing stock price for the period.period
(c) Does not include GenOn compensation expense incurred prior to the deconsolidation of GenOn on June 14, 2017, of approximately $1 million for each of the years ended December 31, 2017, 2016, and 2015, which is recorded in loss from discontinued operations in the Company's consolidated statement of operations.
Note 2122 — Related Party Transactions
NRG provides services to some of its related parties, who are accounted for as equity method investments, under operations and maintenance agreements. Fees for the services under these agreements include recovery of NRG's costs of operating the plants. Certain agreements also include fees for administrative service, a base monthly fee, profit margin and/or annual incentive bonus.
The following table summarizes NRG's material related party transactions with third party affiliates that are included in the Company's operating revenues, operating costs and other income and expense:third-party affiliates: | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| (In millions) | 2023 | | 2022 | | 2021 |
| Revenues from Related Parties Included in Revenues | | | | | |
| Gladstone | $ | 4 | | | $ | 4 | | | $ | 4 | |
Ivanpah(a) | 78 | | | 42 | | | 39 | |
| Midway-Sunset | 2 | | | 6 | | | 6 | |
| Total | $ | 84 | | | $ | 52 | | | $ | 49 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In millions) |
| Revenues from Related Parties Included in Operating Revenues | | | | | |
| Gladstone | $ | 3 |
| | $ | 2 |
| | $ | 4 |
|
| GenConn | 5 |
| | 5 |
| | 4 |
|
| Total | $ | 8 |
| | $ | 7 |
| | $ | 8 |
|
Gladstone — NRG provides services to Gladstone, an equity method investment,(a)Includes fees under an operations and maintenance agreement. Fees for services under this contract primarily include recovery of NRG's costs of operating the plant as approved in the annual budget, as well as a base monthly fee.
GenConn — NRG provides services to GenConn under operations and maintenanceproject management agreements with GenConn Devon and GenConn Middletown that began in June 2010 and June 2011, respectively.each project company
Services Agreement and Transition Services Agreement with GenOn
The Company 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, commercial operations, and asset management, as set forth in the services agreement 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 annual fees under the Services Agreement were approximately $193 million and management has concluded that this method of charging overhead costs is reasonable. As described in Note 3, Discontinued Operations, Acquisitions and Dispositions, 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. Beginning on June 14, 2017, and through December 2017, NRG recorded amounts earned for shared services of approximately $5 million per month.
In December 2017, in conjunction with the confirmation of the GenOn Entities' plan of reorganization, the Services Agreement was terminated and replaced by the transition services agreement. Under the transition services agreement, NRG will continue to provide the shared services and other separation services at an annualized rate of $84 million, subject to certain credits and adjustments, until June 30, 2018, which may be extended by GenOn through September 30, 2018. NRG may provide additional separation services that are necessary for or reasonably related to the operation of GenOn's business after such date, subject to NRG's prior written consent, not to be unreasonably withheld. For the year ended December 31, 2017, NRG recorded other income - affiliate related to these services of $87 million prior to the Chapter 11 Filing and $42 million against selling, general and administrative expenses post-Chapter 11 Filing. For the year ended December 31, 2016, NRG recorded other income - affiliate related to these services of $193 million.
Also in December 2017, NRG provided GenOn with a $3.5 million credit for services provided under the transition services agreement and began recording amounts earned of approximately $7 million per month. NRG has also agreed to provide GenOn with a $28 million credit against amounts owed to NRG under the transition services agreement. The credit is intended to reimburse GenOn for its payment of financing costs. Any unused amount can be paid in cash at GenOn's request, subject to the terms and conditions of the transition services agreement.
See Note 3, Discontinued Operations, Acquisitions and Dispositions, for further discussion regarding the December 2017 agreed upon changes to the Restructuring Support Agreement and transition services agreement, based on which NRG recorded a reserve of $12 million against affiliate receivable balances as of December 31, 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 December 31, 2017 and December 31, 2016, $92 million and $272 million, respectively, of letters of credit were issued and outstanding under the NRG credit agreement for GenOn. Additionally, as of December 31, 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 December 31, 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 December 31, 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 December 31, 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. Additionally, as of December 31, 2017 and December 31, 2016, the Company had $32 million and $79 million, respectively, of cash collateral posted in support of energy risk management activities by GenOn.
Note 2223 — Commitments and Contingencies
Operating Lease Commitments
Powerton and Joliet Leases
The Company leases 100% interests in the Powerton facility and Unit 7 and Unit 8 of the Joliet facility through 2034 and 2030, respectively, through its indirect subsidiary, Midwest Generation, LLC. The Company accounts for these leases as operating leases and records lease expense on a straight-line basis over the lease term. In connection with the acquisition of EME, the Company recorded the out-of-market value as a liability in out-of-market contracts of $159 million. The liability will be amortized through rent expense on a straight-line basis over the term of the lease. The Company expects to record lease expense, net of amortization of the out-of-market liability, of approximately $14 million per year through the term of the lease.
Future minimum lease commitments under the Powerton and Joliet operating leases for the years ending after December 31, 2017 are as follows:
|
| | | |
| Period | (In millions) |
| 2018 | $ | 1 |
|
| 2019 | 1 |
|
| 2020 | 1 |
|
| 2021 | 3 |
|
| 2022 | 6 |
|
| Thereafter | 228 |
|
| Total | $ | 240 |
|
Other Operating Leases
NRG leases certain Company facilities and equipment under operating leases, some of which include escalation clauses, expiring on various dates through 2041. NRG also has certain tolling arrangements to purchase power, which qualify as operating leases. Certain operating lease agreements include provisions such as scheduled rent increases, leasehold incentives, and rent concessions over their lease term. The Company recognizes the effects of these scheduled rent increases, leasehold incentives, and rent concessions on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed. Lease expense under operating leases was $81 million, $96 million, and $97 million for the years ended December 31, 2017, 2016, and 2015, respectively.
Future minimum lease commitments under operating leases for the years ending after December 31, 2017 are as follows:
|
| | | |
| Period | (In millions) |
| 2018 | $ | 78 |
|
| 2019 | 80 |
|
| 2020 | 75 |
|
| 2021 | 65 |
|
| 2022 | 64 |
|
| Thereafter | 479 |
|
Total (a) | $ | 841 |
|
(a) Amounts in the table exclude future sublease income of $49 million associated with long-term leases for office locations.
Coal, Gas and Transportation Commitments
NRG has entered into long-term contractual arrangements related to procureenergy products, including power purchases, gas transportation and storage, and fuel and transportation services for the Company's generation assets and for the years ended December 31, 2017, 2016, and 2015, the Company purchased $1.2 billion, $1.2 billion, and $1.8 billion, respectively, under such arrangements.
As of December 31, 2017, the Company's commitments under such outstanding agreements are as follows:
|
| | | |
| Period | (In millions) |
| 2018 | $ | 527 |
|
| 2019 | 188 |
|
| 2020 | 150 |
|
| 2021 | 112 |
|
| 2022 | 103 |
|
| Thereafter | 296 |
|
| Total | $ | 1,376 |
|
Purchased Power Commitments
NRG has purchased power contracts of various quantities and durations that are not classified as derivative assets and liabilities and do not qualify as operating leases.services. These contracts are not included in the consolidated balance sheet as of December 31, 2017. Minimum purchase commitment obligations are as follows as2023.
As of December 31, 2017:2023, the Company's minimum commitments under such outstanding agreements are estimated as follows: | | | | | |
| Period | (In millions) |
| 2024 | $ | 573 | |
| 2025 | 836 | |
| 2026 | 540 | |
| 2027 | 364 | |
| 2028 | 292 | |
| Thereafter | 823 | |
Total(a) | $ | 3,428 | |
(a)The year 2024 does not include an additional $978 million of short-term commitments |
| | | |
| Period | (In millions) |
| 2018 | $ | 21 |
|
| 2019 | 14 |
|
| 2020 | 12 |
|
| 2021 | 11 |
|
| 2022 | 10 |
|
| Thereafter | — |
|
Total (a) | $ | 68 |
|
| |
(a) | As of December 31, 2017, the maximum remaining term under any individual purchased power contract is five years.
|
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 GenOn and 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 December 31, 2017,2023, all hedges under the first lienliens were in-the-money for NRG on a counterparty aggregate basis.
Lignite Contract with Texas Westmoreland Coal Co.
The Company's Limestone facility utilizes a blend of coal including lignite obtained from the Jewett mine, a surface mine adjacent to the Limestone facility, under a long-term contract with Texas Westmoreland Coal Co., or TWCC. The contract is a cost-plus arrangement with certain performance incentives and penalties. On August 18, 2016, NRG gave notice to TWCC terminating the active mining of lignite under the contract, effective on December 31, 2016.
Under the contract, TWCC continues to be responsible for reclamation activities. 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.
Nuclear Insurance
STP maintains required insurance coverage for liability claims arising from nuclear incidents pursuant to the Price-Anderson Act. Effective January 1, 2017, the current liability limit per incident is $13.44 billion, subject to change to account for the effects of inflation and the number of licensed reactors. An inflation adjustment must be made at least once every five years with the next due no later than September 10, 2018. Under the Price-Anderson Act, owners of nuclear power plants in the U.S. are required to purchase primary insurance limits of $450 million for each operating site. In addition, the Price-Anderson Act requires an additional layer of protection through mandatory participation in a retrospective rating plan for power reactors resulting in an additional $13 billion in funds available for public liability claims. The current maximum assessment per incident, per reactor, is approximately $127 million, taking into account a 5% adjustment for administrative fees, payable at approximately $19 million per year, per reactor. NRG would be responsible for 44% of the maximum assessment, or $8 million per year, per reactor, and a maximum of $112 million per incident. In addition, the U.S. Congress retains the ability to impose additional financial requirements on the nuclear industry to pay liability claims that exceed $13 billion for a single incident. The liabilities of the co-owners of STP with respect to the retrospective premium assessments for nuclear liability insurance are joint and several.
STP purchases insurance for property damage and site decontamination cleanup costs from Nuclear Electric Insurance Limited, or NEIL, an industry mutual insurance company, of which STP is a member. STP has purchased $2.75 billion in limits for nuclear events and $1.5 billion in limits for non-nuclear events, the maximum available from NEIL. The upper $1.25 billion in limits (excess of the first $1.5 billion in limits) is a single limit blanket policy shared with two Diablo Canyon nuclear reactors, which have no affiliation with the Company. This shared limit is not subject to automatic reinstatement in the event of a loss. The NEIL policy covers both nuclear and non-nuclear property damage events, and a NEIL companion policy provides Accidental Outage coverage for the co-owners of STP's lost revenue following a property damage event, at a weekly indemnity limit of $2.52 million per unit up to a maximum of $274.4 million nuclear and $183.5 million non-nuclear, and is subject to an eight-week waiting period. NRG also purchases an Accidental Outage policy from NEIL, which provides protection for lost revenue due to an insurable event. This coverage allows for reimbursement up to $1.98 million per week per unit up to a maximum of $215.6 million nuclear and $144 million non-nuclear, and is subject to an eight-week waiting period. Under the terms of the NEIL policies, member companies may be assessed up to ten times their annual premium if the NEIL Board of Directors determines their surplus has been depleted due to the payment of property losses at any of the licensed reactors in a single policy year. NEIL requires that its members maintain an investment grade credit rating or insure their annual retrospective obligation by providing a financial guarantee, letter of credit, deposit premium, or an insurance policy. NRG has purchased an insurance policy from NEIL to guarantee the Company's obligation; however this insurance will only respond to retrospective premium adjustments assessed within twenty-four months after the policy term, whereas NEIL's Board of Directors can make such an adjustment up to 6 years after the policy expires.
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 24, Regulatory Matters, and Note 25, 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 Liabilities LLC— 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. In 2023, the IPCB held hearings to determine 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 operating in the industry, from time-to-time, the Company and/or its subsidiaries may be subject to potential asbestos liabilitiesconsumer lawsuits in various jurisdictions where they sell natural gas and electricity.
Variable Price Cases — In the cases set forth below, referred to as the Variable Price Cases, such actions involve consumers alleging that one of the Company’s ESCOs promised that consumers would pay the same or less than they would have paid if they stayed with their default utility or previous energy supplier. The underlying claims of each case are similar and the Company continues to deny the allegations and is vigorously defending these matters. These matters were known and accrued for at the time of each acquisition.
XOOM Energy
Mirkin v. XOOM Energy (E.D.N.Y. Aug. 2019) is a resultdefendant in a putative class action lawsuit pending in New York. The Court denied XOOM's motion for summary judgment and granted class certification. The Second Circuit denied XOOM's request to appeal the class certification grants. XOOM plans to challenge Mirkin's expert testimony to further hamper Mirkin's ability to support its case.
Direct Energy
There was one putative class action pending against Direct Energy: 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 occurred on October 25, 2023. The Second Circuit upheld the trial court's grant of its acquisitionsummary judgment in favor of EME.Direct Energy.
Telephone Consumer Protection Act ("TCPA") Cases — In the cases set forth below, referred to as the TCPA Cases, such actions involve consumers alleging violations of the Telephone Consumer Protection Act of 1991, as amended, by receiving calls, texts or voicemails without consent in violation of the federal Telemarketing Sales Rule, and/or state counterpart legislation. The underlying claims of each case are similar. The Company is currently analyzingdenies the scopeallegations asserted by plaintiffs and intends to vigorously defend these matters. These matters were known and accrued for at the time of potential liability as it may relatethe 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 Midwest Generation.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 Company believesCourt denied Direct Energy's motion stating the Court does not have the benefit of all of the facts that it has established an adequate reserve for these cases.
were in front of the Burk court to issue a similar ruling. On October 19, 2022, Direct Energy Plus Holdings—On August 7, 2012, Energy Plus Holdings receivedfiled a subpoena fromMotion to Transfer Venue asking the NYAG which generally sought information and business records relatedCourt to Energy Plus Holdings' sales, marketing and business practices. Energy Plus Holdings provided documents and informationtransfer the case to the NYAG.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 matter is back at the trial court. The parties will conduct further fact discovery and expert discovery and are likely to resubmit motions for further review by the Court.
Sales Practice Lawsuits
There are three litigation matters relating to claims made by Vivint Smart Home competitors against Vivint Smart Home alleging, among other things, that Vivint Smart Home's sales representatives used deceptive sales practices. These matters were known and accrued for at the time of the acquisition. The three matters are: (1) CPI Security Systems, Inc. ("CPI") v. Vivint Smart Home, Inc. (W.D.N.C. Sept. 2020). The CPI matter that was filed in 2020 went to trial, and in February 2023, the jury issued a verdict against Vivint Smart Home, in favor of CPI for $50 million of compensatory damages and an additional $140 million of punitive damages. Vivint Smart Home has filed its notice of appeal and is awaiting a briefing schedule. 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 22, 2015,2023, the NYAG issued another subpoena seeking additional information. Energy Plus Holdings provided responsive documents to this second subpoena.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 August 28, 2017, the parties entered into an Assurance of Discontinuance resolving this matter.
Midwest Generation New Source Review Litigation— In August 2009, the EPA and the Illinois Attorney General, or the Government Plaintiffs,March 1, 2023, Alert 360 filed a complaint oragainst Vivint Smart Home alleging, among other things, deceptive sales practices. The parties settled the Governments’ Complaint,dispute in October 2023 and the case was dismissed.
Patent Infringement Lawsuits
SB IP Holdings LLC (“Skybell”) v. Vivint Smart Home, Inc. — On October 23, 2023, a jury in the U.S. District Court, Eastern District of Texas, Sherman Division, issued a verdict against the Company in favor of Skybell for $45 million in damages for patent infringement. The patents that were the basis for the Northern District of Illinoisclaims made by Skybell were ruled invalid by the U.S. International Trade Commission in November 2021. In accordance with advice by legal counsel, the Company does not believe the verdict is legally supported and will pursue post-judgment and appellate remedies along with any other legal options available.
Contract Disputes
Alarm.com — In September 2022, Vivint Smart Home sent Alarm.com a notice asserting that it was no longer obligated to pay certain license fees under the Patent Cross License Agreement between the parties on the basis that Vivint Smart Home no longer practices any claim under any valid Alarm.com patent and, therefore, no license fees are due. Alarm.com filed an arbitration demand against Vivint Smart Home alleging, 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 owneramong other things, breach of the stations, including alleged failuresagreement due 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 Vcontinued use of the CAA allegedly arising from such claimed PSD, opacity and PM emission violations. Several environmental groups intervened as plaintiffspatents in thisquestion. The parties have resolved all outstanding litigation and entered into a long-term intellectual property licensing agreement.
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 complaint, orright of first refusal exists in relation to the Intervenors’ Complaint, which alleged opacity, PMproposed sale of NRG South Texas' 44% interest in STP to Constellation. NRG believes the claims set forth by CPS and related Title V violations. Midwest Generation filed a motionAustin Energy in the lawsuit and the NRC proceedings are without merit and intends to dismiss ninevigorously defend against them. For further discussion of the ten PSD countstransaction, 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 Governments’ Complaint,lawsuits related to Winter Storm Uri are consolidated into a single multi-district litigation matter in Harris County District Court. NRG's REPs have since been severed from the multi-district litigation and to dismisswill be seeking dismissal in any remaining cases. As a power generator, the tenth PSD count to the extent the Governments’ Complaint sought civil penalties for that count.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 trial courtFirst Court of Appeals conditionally granted the motion in March 2010.
In June 2010, the Government Plaintiffs and Intervenors each filed an amended complaint. The Governments’ Amended Complaint again alleged that Midwest Generation violated PSD (based upon the same projects as alleged in their original complaint, but adding allegations that the Company was liable as the “successor” to ComEd), Title V and opacity and PM standards. It named EME and ComEd as additional defendants and alleged PSD violations (again, premised on the same projects) against them. The Intervenors’ Amended Complaint named only Midwest Generation as a defendant and alleged Title V and opacity/PM violations, as well as one of the ten PSD violations alleged in the Governments’ Amended Complaint. Midwest Generation again moved to dismiss all but one of the Government Plaintiffs’ PSD claims and the related Title V claims. Midwest Generation also filed a motion to dismiss the PSD claim in the Intervenors’ Amended Complaint and the related Title V claims. In March 2011,generators' mundamus relief, ordering the trial court granted Midwest Generation’s partial motion to dismissgrant the Government Plaintiffs’ PSD claims.generator defendents' Motions to Dismiss. The trial court denied Midwest Generation’s motionCompany expected the Plaintiffs to dismiss the PSD claim asserted in the Intervenors’ Amended Complaint, but noted that the plaintiffs would be requiredchallenge this ruling. The Company intends 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 opacityvigorously defend these matters.
Indemnifications 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.Other Contractual Arrangements
Following the trial court ruling, the Government Plaintiffs appealed the trial court’s dismissals of their PSD claims, including the dismissal of nine of the ten PSD claims against Midwest Generation and of the PSD claims against the other defendants. Those PSD claim dismissals were affirmed by the U.S. Court of Appeals for the Seventh Circuit in July 2013. In addition, in 2012, all but one of the environmental groups that had intervened in the case dismissed their claims without prejudice. As a result, only one environmental group remains a plaintiff intervenor in the case. In February 2018, the parties agreed in principal to settle the matter. After the settlement agreement is signed by all parties (which the Company expects to occur in March 2018) and approved by the court, Midwest Generation will be required to (x) pay $500,000 to each of the State of Illinois and the Federal Government and (y) make and maintain certain operational improvements.
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 final court approval of 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 which was approved by the court on November 17, 2017. On February 20, 2018 at the close of the objection deadline, two objections were filed to the Dobkin 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. At the time the PPA was entered into, Sunrise had a transportation services agreement, or TSA, to purchase natural gas from Kern River through April 30, 2018. In August 2003, CDWR entered into an agreement with Sunrise and Kern River in which CDWR accepted assignment of the TSA through the term of the PPA. After the PPA expired, Kern River demanded that any reassignment be to a party which met certain creditworthiness standards which Sunrise did not. As such, the plaintiffs brought this lawsuit against the defendants alleging breach of contract, breach of covenant of good faith and fair dealing and improper distributions. Plaintiffs generally claim damages of $1.2 million per month for the remaining 70 months of the TSA. On April 20, 2016, the defendants filed objections in response to the plaintiffs' complaint. The objections 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 objections to the amended complaints. On November 18, 2016, the court sustained the objections 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 objections without leave to amend. On July 14, 2017, CDWR filed a notice of appeal. On January 10, 2018, CDWR filed its appellate brief.
Braun v. NRG Yield, Inc. — On April 19, 2016, plaintiffs filed a putative class action lawsuit against NRG Yield, Inc., the current and former members of its board of directors individually, and other parties in California Superior Court in Kern County, CA. Plaintiffs allege various violations of the Securities Act due to the defendants’ alleged failure to disclose material facts related to low wind production prior to the NRG Yield, Inc.'s June 22, 2015 Class C common stock offering. Plaintiffs seek compensatory damages, rescission, attorney’s fees and costs. The Defendants filed objections and a motion challenging jurisdiction on October 18, 2016. On December 1, 2017, the parties agreed to a stipulation which provides the plaintiffs' opposition is due on March 6, 2018 and defendants' reply is due on May 4, 2018.
Ahmed v. NRG Energy, Inc. and the NRG Yield Board of Directors — On September 15, 2016, plaintiffs filed a putative class action lawsuit against NRG Energy, Inc., the directors of NRG Yield, Inc., and other parties in the Delaware Chancery Court. The complaint alleges that the defendants breached their respective fiduciary duties with regard to the recapitalization of NRG Yield, Inc. common stock in 2015. The plaintiffs generally seek economic damages, attorney’s fees and injunctive relief. The defendants filed a motion to dismiss the lawsuit on December 21, 2016. Plaintiffs filed their objection to the motion to dismiss on February 15, 2017. The defendants' reply was filed on March 24, 2017. The court heard oral argument on defendants' motion to dismiss on June 20, 2017. On September 7, 2017, the court requested additional briefing which the parties provided on September 21, 2017. On December 11, 2017, the court dismissed the lawsuit with prejudice, thereby ending the case.
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. The appeal is fully briefed and scheduled for argument on April 24, 2018.
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. On September 14, 2017,February 4, 2019, NRG sold 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 whichSouth Central Portfolio, including the court denied on November 2, 2017. LaGen filed its answer and affirmative defenses on November 17, 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 supported the Bankruptcy Court's approval of the plan of reorganization. GenOn has a customary "fiduciary out" under the Restructuring Support Agreement. If the plan of reorganization is not consummated, NRG may not be entitled to the benefits of the Settlement Agreement provided under the Restructuring Support Agreement and it will remainentities 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 due 2020, and the GenOn Americas Generation, LLC8.50% 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 againstthis litigation. However, 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 partieshas agreed to suspend all deadlinesindemnify the purchaser for certain losses suffered in connection with this litigation. In February 2020, the case untilfederal court dismissed this lawsuit without prejudice for lack of subject matter jurisdiction. On 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. The17, 2020, plaintiffs among other things, generally seek return of all monies paid under the services agreement and any other damages that the court deems appropriate. On December 14, 2017, a settlement agreement was executed between GenOn and NRG which should ultimately resolve this lawsuit.
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. On November 7, 2017, the Bankruptcy Court issued an order estimating the claims to be valued at $0. On December 14, 2017, a settlement agreement was executed between GenOn and NRG which should ultimately resolve this lawsuit.
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 appealed the District Court's dismissal of its complaint against the Commerzbank Defendants 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. The bankruptcy court is scheduled to hear a Motion for a Final Decree in the Mirant bankruptcy on April 11, 2018.
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,same matters, 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. On November 22, 2017, plaintiffs filed their appellate brief. On January 22, 2018, the defendants filed their opposition brief.
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 and was argued on February 16, 2018. GenOn has agreed to indemnify CenterPoint against 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 plaintiffs 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 penalties are appropriate in light of the violations. NRG Potomac River LLC is currently reviewing the information provided by DOEE.
Natixis v. GenOn Mid-Atlantic—On February 16, 2018, Natixis Funding Corp. and Natixis, New York Branch filed a complaint in the Supreme Court of the State of New York against GenOn Mid-Atlantic, the owner lessors under GenOn Mid-Atlantic’s operating leases of the Dickerson and Morgantown coal generation units, and the lease indenture trustee under those leases. The plaintiffs’ allegations against GenOn Mid-Atlantic relateOctober 2, 2023 pursuant to a payment agreement between GenOn Mid-Atlantic and Natixis Funding Corp. to procure credit support for the payment of certain lease payments owed pursuant to the GenOn Mid-Atlantic operating leases for Morgantown and Dickerson. Plaintiffs seek approximately $34 million in damages arising from GenOn Mid-Atlantic’s purported breach of certain warranties in the paymentsettlement agreement.
Note 2324 — Regulatory 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.
In addition to the regulatory proceedings noted below, NRG and its subsidiaries are parties to other regulatory proceedings arising in the ordinary course of business or have other regulatory exposure. In management's opinion, the disposition of these ordinary course matters will not materially adversely affect NRG's consolidated financial position, results of operations, or cash flows.
National
Zero-Emission Credits for Nuclear Plants in Illinois — In 2016, Illinois enacted 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 Governor of Illinois and Exelon have already announced that the ZECs will be awarded to two Exelon-owned nuclear 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. Briefing is complete. Oral argument was held on January 3, 2018, with supplemental briefs filed on January 26, 2018. On February 21, 2018, the Seventh Circuit invited the U.S. to file an amicus brief in the proceeding.
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 plaintiff companies, filed a notice of appeal to the U.S. Court of Appeals for the Second Circuit. Briefing is complete. Oral argument has been noticed for March 12, 2018.
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. On January 8, 2018, FERC terminated the proposed rulemaking and opened a new rulemaking asking each ISO/RTO to address specific questions focused on grid resilience.
East/West
Montgomery County Station Power Tax—On December 20, 2013, NRG received a letter from Montgomery County, Maryland requesting payment of an energy tax for the consumption of station power at the Dickerson Facility over the previous three years. Montgomery County seeks payment in the amount of $22 million, which includes tax, interest and penalties. NRG disputed the applicability of the tax. On December 11, 2015, the Maryland Tax Court reversed Montgomery County's assessment. Montgomery County filed an appeal, and on February 2, 2017, the Montgomery County Circuit Court affirmed the decision of the tax court. On February 17, 2017, Montgomery County filed an appeal to the Court of Special Appeals of Maryland. On February 1, 2018, the court heard oral arguments.
California Station Power —As the result of unfavorable final and non-appealable litigation, the Company has accrued a liability associated with consumption of station power at three of the Company’sCompany's Encina power plantsplant facility in California after August 30, 2010. In December 2017, subsidiaries of the Company entered into settlements with SCE for the liabilities associated with the Company's El Segundo and Long Beach facilities. The Company has established an appropriate reserveaccrual pending potential regulatory action by SDG&ESan Diego Gas & Electric regarding Encina.the Company's Encina facility.
Federal Trade Commission Investigation— On October 5, 2017,In 2019, Vivint Smart Home received a civil investigative demand from the California Energy Commission, or CEC, the agency responsible for permitting the Puente Power Project, issued a statement on behalfstaff of the committeeFederal Trade Commission (“FTC”) concerning potential violations of two Commissioners overseeing the permittingFair Credit Reporting Act and the “Red Flags Rule” thereunder, and the FTC Act. In April 2021, Vivint Smart Home entered into a settlement with the FTC that resolved this investigation. As part of this settlement, which was approved by a federal court on May 3, 2021, Vivint Smart Home paid $20 million and agreed to implement various additional compliance related measures ("Stipulated Order"). The Company is currently in the process stating their intentionof administering the terms of the Stipulated Order, which includes multiple undertakings by the Company. The Company is engaged in ongoing discussions with the staff of the FTC regarding the Company’s compliance with the terms of the Stipulated Order. Under the terms of the Stipulated Order, Vivint Smart Home is required to issueundertake biennial assessments by an independent third-party assessor (the "Assessor"), which reviews Vivint Smart Home’s compliance program and provides a proposed decisionreport on Vivint Smart Home’s ongoing compliance with the Stipulated Order. Since its inception until December 31, 2023, Vivint Smart Home has completed its initial assessment and its first biennial assessment as required by the Stipulated Order. In addition, Vivint Smart Home has voluntarily undertaken six quarterly audits by the appointed Assessor. In all the assessments, Vivint Smart Home received a report from the Assessor with no findings of non-compliance of any kind.
New York State Public Service Commission ("NYSPSC") - Notice of Apparent Violation — The NYSPSC issued an order referred to as the Retail Reset Order in December 2019 that would denylimited ESCO's offers for electric and natural gas to three compliant products: guaranteed savings from the utility default rate, a permit forfixed term capped at 5% of the Puente Power Project. On October 16, 2017, NRG filed a motion to suspend the permitting proceeding forrolling 12-month average utility default rate, or NY-sourced renewable energy that is at least six months, which was granted on November 3, 2017. During50% greater than the six month suspension period, which could conceivably be extended,prevailing NY Renewable Energy Standard for load serving entities. The order effectively limited ESCO offers to natural gas customers to only the guaranteed savings and capped fixed term compliant products because no equivalent renewable energy product exists for natural gas. NRG will evaluatetook action to comply with the progressorder when it became effective April 16, 2021. On January 8, 2024, the NYSPSC notified eight of a procurementNRG's retail energy suppliers (serving both electricity and natural gas) of alleged non-compliance with New York regulatory requirements. Among other items, the notices allege that the NRG suppliers did not transition existing residential customers to one of the three compliant products authorized by the NYSPSC following the effective date of the order. NRG responded to the notices in February 2024. The outcome of this process initiated by SCEhas the potential to replacenegatively impact the Puente Power Project.retail business in New York.
Note 2425 — 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 — In 2019, the EPA promulgated the ACE rule, which rescinded the CPP, which had sought to broadly regulate CO2 emissions from the power sector. The ACE rule required states that have become more stringent over time, although this trend could slow or pause in the near term with respectcoal-fired EGUs to federal laws under the current U.S. presidential administration.
The EPA finalized CSAPR in 2011, which was intendeddevelop plans to replace CAIR inseek heat rate improvements from coal-fired EGUs. On January 2012, to address certain states' obligations to reduce emissions so that downwind states can achieve federal air quality standards. In December 2011,19, 2021, the D.C. Circuit vacated the ACE rule (but on February 22, 2021, at the EPA's request, stayed the implementationissuance of CSAPR and then vacated CSAPR in August 2012 but kept CAIR in place until the EPA could replace it. In April 2014,portion of the mandate that would vacate the repeal of the CPP). On June 30, 2022, the U.S. Supreme Court reversed and remanded the D.C. Circuit's decision. In October 2014, the D.C. Circuit lifted the stay of CSAPR. In response, the EPA in November 2014 amended the CSAPR compliance dates. Accordingly, CSAPR replaced CAIR on January 1, 2015. On July 28, 2015, the D.C. Circuit held that the EPA had"generation shifting" approach in the CPP exceeded its authority by requiring certain reductions that were not necessary for downwind statesthe powers granted to achieve federal standards. Although the D.C. Circuit kept the rule in place, the court ordered the EPA to reviseby Congress. The Court did not address the Phase 2 (or 2017) (i) SO2 budgets for four states including Texas and (ii) ozone-season NOx budgets for 11 states including Maryland, New Jersey, New York, Ohio, Pennsylvania and Texas. On October 26, 2016,related issues of whether the EPA finalizedmay adopt only measures applied at each source. On May 23, 2023, the CSAPR Update Rule,EPA proposed significantly revising the manner in which reduces future NOx allocationsnew and discountsexisting 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 current banked allowances to account for the more stringent 2008 Ozone NAAQS and to address the D.C. Circuit's July 2015 decision. Thisfinal rule has beenwill be challenged in the D.C. Circuit. The Company believes its investment in pollution controlscourts and cleaner technologies leave the fleet well-positioned for compliance.
In February 2012, the EPA promulgated standards (the MATS rule) to control emissions of HAPs from coal and oil-fired electric generating units. The rule established limits for mercury, non-mercury metals, certain organics and acid gases, which had to be met beginning in April 2015 (with some units getting a 1-year extension). In June 2015, the U.S. Supreme Court issued a decision in the case of Michigan v. EPA, and held that the EPA unreasonably refused to consider costs when it determined that it was "appropriate and necessary" to regulate HAPs emitted by electric generating units. The U.S. Supreme Court did not 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 costs to address the U.S. Supreme Court's ruling that the EPA had not properly considered costs. This finding has been challenged in the D.C. Circuit. On April 18, 2017, the EPA asked the D.C. Circuit to postpone oral argument that had been scheduled for May 18, 2017 because the EPA is closely reviewing the supplemental finding to determine whether it should reconsider all or part of the rule. On April 27, 2017, the D.C. Circuit granted EPA's request to postpone the oral argument and hold the case in abeyance. While NRG cannot predict the final outcome of this rulemaking, NRG believes that because it has already invested in pollution controls and cleaner technologies, the fleet is well-positioned to comply with the MATS rule.
Water
In August 2014, the EPA finalized the regulation regarding the use of water for once through cooling at existing facilities to address impingement and entrainment concerns. NRG anticipates that more stringent requirements will be incorporated into some of its water discharge permitsaccordingly uncertain over the next several yearsyears.
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 in 2023 by assuming that participants in this cap-and-trade program had or would optimize existing NOx controls and later install additional NOx controls. The Company cannot predict the outcome of the legal challenges to the: (i) various state disapprovals; (ii) the final rule promulgated on June 5, 2023; and (iii) the interim final rule promulgated on July 31, 2023 that seeks to address the judicial orders.
Regional Haze Proposal — On May 2023, the EPA proposed to withdraw the existing Texas Sulfur Dioxide Trading Program and replace it with unit-specific SO2 limits for 12 units in Texas to address requirements to improve visibility at National Parks and Wilderness areas. If finalized as NPDES permits are renewed.proposed, the rule would result in more stringent SO2 limits for two of the Company's coal-fired units in Texas. The Company cannot predict the outcome of this proposal.
Water
Effluent Limitations Guidelines — In November 2015, the EPA revised the Effluent Limitations GuidelinesELG 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 the rule. Accordingly,(iii) changing several deadlines. 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 ruleend of 2028 at its domestic coal units outside of Texas, and installing appropriate controls by the end of 2025 at its two plants that have coal-fired units in Texas. On March 29, 2023, the EPA proposed revisions to the ELG and sought comments, which the EPA is revised. analyzing.
Byproducts Wastes, Hazardous Materials and Contamination
In April 2015, the EPA finalized thea rule regulating byproducts of coal combustion (e.g., ash and gypsum) as solid wastes under the RCRA. On September 13, 2017,August 21, 2018, the D.C. Circuit found, among other things, that the EPA grantedhad not adequately regulated unlined ponds and legacy surface impoundments. On August 28, 2020, the petition for reconsideration thatEPA finalized "A Holistic Approach to Close Part A: Deadline to Initiate Closure," which amended the Utility Solid Waste Activities Group filed in May 2017. The Company has evaluatedApril 2015 Rule to address the impactAugust 2018 D.C. Circuit decision and extend some of the new rule 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 December 31, 2017.
East/West Region
New Source Review — The EPA and various states have been investigating compliance of electric generating facilities with the pre-construction permitting requirements of the CAA known as “new source review,” or NSR. In 2007, Midwest Generation received an NOV fromdeadlines. On November 12, 2020, the EPA alleging that past workfinalized "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 alternative liner. On May 23, 2023, the EPA proposed establishing requirements for: (i) inactive (or legacy) surface impoundments at Crawford, Fisk, Joliet, Powerton, Waukeganinactive facilities and Will County generating stations violated NSR and other regulations. These alleged violations are(ii) all CCR management units (regardless of how or when the subject of litigation described in Item 15 — Note 22, Commitments and Contingencies. Additionally, in April 2013, the Connecticut Department of Energy and Environmental Protection issued four NOVs alleging that past workCCR was placed) at oil-fired combustion turbines at the Torrington Terminal, Franklin, Branford and Middletown generating stations violated regulations regarding NSR.
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 respectregulated facilities. NRG anticipates further rulemaking related to Burton Island Old Ash Landfill, a historic captive landfill located at the Indian River facility. On October 1, 2007, 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 no further action was required in relation tolegacy 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, the Company's Closure Reportimpoundments 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 and remediation was completed in 2017. The estimated cost to comply with the Long-Term Stewardship Plan was added to the liability in December 2016.Federal Permit Program.
In addition to the VCP, on May 29, 2008, DNREC requested that NRG's Indian River Power LLC participate in the development and performance of a Natural Resource Damage Assessment at the Burton Island Old Ash Landfill. NRG is currently working with DNREC and other trustees to close out the assessment process.
For further discussion of these matters, refer to Note 22, Commitments and Contingencies.
Note 2526 — Cash Flow Information
Detail of supplemental disclosures of cash flow and non-cash investing and financing information was:
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| (In millions) | 2023 | | 2022 | | 2021 |
| Interest paid, net of amount capitalized | $ | 548 | | | $ | 383 | | | $ | 433 | |
| Income taxes paid, net of refunds | 48 | | | 66 | | | 32 | |
| Non-cash investing activities: | | | | | |
| Decreases to fixed assets for accrued capital expenditures | — | | | (68) | | | (16) | |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In millions) |
| Interest paid, net of amount capitalized | $ | 868 |
| | $ | 890 |
| | $ | 924 |
|
Income taxes paid (a) | 9 |
| | 14 |
| | 12 |
|
| Non-cash investing and financing activities: | | | | | |
| Additions/(decrease) to fixed assets for accrued capital expenditures | 70 |
| | 35 |
| | (44 | ) |
(a) In 2017, income taxes paid of $11 million are offset by $2 million in income tax refunds. In 2015, income taxes paid of $13 million are offset by $1 million in income tax refunds.
Note 2627 — Guarantees
NRG and its subsidiaries enter into various contracts that include indemnification and guarantee provisions as a routine part of the Company's business activities. Examples of these contracts include asset purchases and sale agreements, commodity sale and purchase agreements, retail contracts, joint venture agreements, EPC agreements, operation and maintenance agreements, service agreements, settlement agreements, and other types of contractual agreements with vendors and other third parties, as well as affiliates. These contracts generally indemnify the counterparty for tax, environmental liability, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements. The Company is obligated with respect to customer deposits associated with the Company's retail businesses.operations. In some cases, NRG's maximum potential liability cannot be estimated, since the underlying agreements contain no limits on potential liability.
The following table summarizes the maximum potential exposures that can be estimated for NRG's guarantees, indemnities, and other contingent liabilities by maturity:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | By Remaining Maturity at December 31, |
| (In millions) | 2023 | | |
| Guarantees | Under 1 Year | | 1-3 Years | | 3-5 Years | | Over 5 Years | | Total | | 2022 Total |
| Letters of credit and surety bonds | $ | 4,555 | | | $ | 37 | | | $ | — | | | $ | — | | | $ | 4,592 | | | $ | 5,211 | |
| Asset sales guarantee obligations | 13 | | | 24 | | | 22 | | | 67 | | | 126 | | | 409 | |
| Other guarantees | — | | | — | | | — | | | 27 | | | 27 | | | 15 | |
| Total guarantees | $ | 4,568 | | | $ | 61 | | | $ | 22 | | | $ | 94 | | | $ | 4,745 | | | $ | 5,635 | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | By Remaining Maturity at December 31, |
| | 2017 | | |
| Guarantees | Under 1 Year | | 1-3 Years | | 3-5 Years | | Over 5 Years | | Total | | 2016 Total |
| | (In millions) |
Letters of credit and surety bonds(a) | $ | 1,467 |
|
| $ | 66 |
|
| $ | 7 |
|
| $ | 93 |
|
| $ | 1,633 |
|
| $ | 1,837 |
|
| Asset sales guarantee obligations | — |
|
| — |
|
| 257 |
|
| 55 |
|
| 312 |
|
| 677 |
|
| Other guarantees | — |
|
| 32 |
|
| — |
|
| 613 |
|
| 645 |
|
| 253 |
|
| Total guarantees | $ | 1,467 |
|
| $ | 98 |
|
| $ | 264 |
|
| $ | 761 |
|
| $ | 2,590 |
|
| $ | 2,767 |
|
| |
(a) | Excludes$92 million and $272 million of letters of credit issued under the intercompany revolving credit agreement between NRG and GenOn as of December 31, 2017 and 2016, respectively. |
Letters of credit and surety bonds — As of December 31, 2017,2023, NRG and its consolidated subsidiaries were contingently obligated for a total of $1.6$4.6 billion under letters of credit and surety bonds. Most of these letters of credit and surety bonds are issued in support of the Company's obligations to perform under commodity agreements and obligations associated with future closure and maintenance of ash sites, as well as for financing or other arrangements. A majority of these letters of credit and surety bonds expire within one year of issuance, and it is typical for the Company to renew them on similar terms.
The material indemnities, within the scope of ASC 460, are as follows:
Asset sales — The purchase and sale agreements which govern NRG's asset or share investments and divestitures customarily contain guarantees and indemnifications of the transaction to third parties. The contracts indemnify the parties for liabilities incurred as a result of a breach of a representation or warranty by the indemnifying party, or as a result of a changechanges in tax laws.laws or for pre-existing environmental matters. These obligations generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or estimate at the time of the transaction. In several cases, the contract limits the liability of the indemnifier. NRG has no reason to believe that the Company currently has any material liability relating to such routine indemnification obligations included in the table above, except for the California property tax indemnity for estimated increases in California property taxes of certain solar properties that the Company agreed to indemnify, as part of the agreement to sell NRG Yield and the Renewables Platform. The California property tax indemnity is estimated to be $126 million as of December 31, 2023 and is included in the above table under asset sales guarantee obligations.
Other guarantees — NRG has issued other guarantees of obligations including payments under certain agreements with respect to certain of its unconsolidated subsidiaries, payment or performance by fuel providers and payment or reimbursement of credit support and deposits. The Company does not believe that it will be required to perform under these guarantees.
Other indemnities — Other indemnifications NRG has provided cover operational, tax, litigation and breaches of representations, warranties and covenants. NRG has also indemnified, on a routine basis in the ordinary course of business, consultants or other vendors who have provided services to the Company. NRG's maximum potential exposure under these indemnifications can range from a specified dollar amount to an indeterminate amount, depending on the nature of the transaction. Total maximum potential exposure under these indemnifications is not estimable due to uncertainty as to whether claims will be made or how they will be resolved. NRG does not have any reason to believe that the Company will be required to make any material payments under these indemnity provisions.
Because many of the guarantees and indemnities NRG issues to third parties and affiliates do not limit the amount or duration of its obligations to perform under them, there exists a risk that the Company may have obligations in excess of the amounts described above. For those guarantees and indemnities that do not limit the Company's liability exposure, it may not be able to estimate what the Company's liability would be, until a claim is made for payment or performance, due to the contingent nature of these contracts.
Note 2728 — Jointly Owned PlantsPlant
Certain NRG subsidiaries ownowns an undivided interestsinterest in jointly-owned plants, as described below. These plants areCedar Bayou. Cedar Bayou is maintained and operated pursuant to theirits joint ownership participation and operating agreements.agreement. NRG is responsible for its subsidiaries' share of operating costs and direct expenses and includes its proportionate share of the facilitiesfacility and related revenues and direct expenses in thesethe jointly-owned plantsplant in the corresponding balance sheet and income statement captions of the Company's consolidated financial statements.
The following table summarizes NRG's proportionate ownership interest in the Company's jointly-owned facilities:facility: | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions unless otherwise stated) | | | | | | | |
| As of December 31, 2023 | Ownership Interest | | Property, Plant & Equipment | | Accumulated Depreciation | | Construction in Progress |
| | | | | | | |
| Cedar Bayou Unit 4, Baytown, TX | 50.00 | % | | $ | 222 | | | $ | (115) | | | $ | 2 | |
|
| | | | | | | | | | | | | | |
| As of December 31, 2017 | Ownership Interest | | Property, Plant & Equipment | | Accumulated Depreciation | | Construction in Progress |
| | (In millions unless otherwise stated) |
| South Texas Project Units 1 and 2, Bay City, TX | 44.00 | % | | $ | 395 |
| | $ | (207 | ) | | $ | 7 |
|
| Big Cajun II Unit 3, New Roads, LA | 58.00 | % | | 202 |
| | (132 | ) | | — |
|
| Cedar Bayou Unit 4, Baytown, TX | 50.00 | % | | 215 |
| | (75 | ) | | 7 |
|
| Keystone, Shelocta, PA | 3.70 | % | | 12 |
| | — |
| | 1 |
|
| Conemaugh, New Florence, PA | 3.72 | % | | 14 |
| | — |
| | 1 |
|
Note 28 — Unaudited Quarterly Financial Data
Refer to Note 3, Discontinued Operations, Acquisitions and Dispositions, and Note 10, Asset Impairments, for a description of the effect of unusual or infrequently occurring events during the quarterly periods. Summarized unaudited quarterly financial data is as follows:
|
| | | | | | | | | | | | | | | |
| | Quarter Ended |
| | 2017 |
| | December 31 | | September 30 | | June 30 | | March 31 |
| | (In millions, except per share data) |
| Operating revenues | $ | 2,497 |
| | $ | 3,049 |
| | $ | 2,701 |
| | $ | 2,382 |
|
| Operating (loss)/ income | (1,345 | ) | | 376 |
| | 343 |
| | 39 |
|
| Net (loss)/income from continuing operations | (1,667 | ) | | 190 |
| | 99 |
| | (170 | ) |
| Income/(loss) from discontinued operations | 13 |
| | (27 | ) | | (741 | ) | | (34 | ) |
| Net (loss)/income | (1,655 | ) | | 163 |
| | (642 | ) | | (203 | ) |
| Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests | (120 | ) | | (8 | ) | | (16 | ) | | (40 | ) |
| Net (loss)/income attributable to NRG Energy, Inc. | (1,535 | ) | | 171 |
| | (626 | ) | | (163 | ) |
| (Loss)/income available to Common Stockholders | $ | (1,535 | ) | | $ | 171 |
| | $ | (626 | ) | | $ | (163 | ) |
| Weighted average number of common shares outstanding — basic | 317 |
| | 317 |
| | 316 |
| | 316 |
|
| Income/(loss) from discontinued operations per weighted average common share — basic | $ | 0.04 |
| | $ | (0.09 | ) | | $ | (2.34 | ) | | $ | (0.11 | ) |
| Net (loss)/income per weighted average common share — basic | $ | (4.84 | ) | | $ | 0.54 |
| | $ | (1.98 | ) | | $ | (0.52 | ) |
| Weighted average number of common shares outstanding — diluted | 317 |
| | 322 |
| | 316 |
| | 316 |
|
| Income/(loss) from discontinued operations per weighted average common share — diluted | $ | 0.04 |
| | $ | (0.08 | ) | | $ | (2.34 | ) | | $ | (0.11 | ) |
| Net (loss)/income per weighted average common share — diluted | $ | (4.84 | ) | | $ | 0.53 |
| | $ | (1.98 | ) | | $ | (0.52 | ) |
|
| | | | | | | | | | | | | | | | | | |
| | Quarter Ended |
| | 2016 |
| | December 31 | | September 30 | | June 30 | | March 31 |
| | (In millions, except per share data) |
| Operating revenues | $ | 2,184 |
| | $ | 3,421 |
| | $ | 2,248 |
| | $ | 2,659 |
|
| Operating (loss)/income | (658 | ) | — |
| 429 |
| — |
| 164 |
| | 331 |
|
| Net (loss)/income from continuing operations | (891 | ) | | 128 |
| | (163 | ) | | (57 | ) |
| (Loss)/income from discontinued operations | (164 | ) | | 265 |
| | (113 | ) | | 104 |
|
| Net (loss)/income | (1,055 | ) | | 393 |
| | (276 | ) | | 47 |
|
| Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests | (68 | ) | — |
| (9 | ) | | (5 | ) | | (35 | ) |
| Net (loss)/income attributable to NRG Energy, Inc. | (987 | ) | | 402 |
| | (271 | ) | | 82 |
|
| (Loss)/income available to Common Stockholders | $ | (987 | ) | | $ | 402 |
| | $ | (193 | ) | | $ | 77 |
|
| Weighted average number of common shares outstanding — basic | 316 |
| | 316 |
| — |
| 315 |
| | 315 |
|
| (Loss)/income from discontinued operations per weighted average common share — basic | $ | (0.52 | ) | | $ | 0.84 |
| | $ | (0.36 | ) | | $ | 0.33 |
|
| Net (loss)/income per weighted average common share — basic | $ | (3.12 | ) | | $ | 1.27 |
| | $ | (0.61 | ) | | $ | 0.24 |
|
| Weighted average number of common shares outstanding — diluted | 316 |
| | 317 |
| | 315 |
| | 315 |
|
| (Loss)/income from discontinued operations per weighted average common share — diluted | $ | (0.52 | ) | | $ | 0.84 |
| | $ | (0.36 | ) | | $ | 0.33 |
|
| Net (loss)/income per weighted average common share — diluted | $ | (3.12 | ) | — |
| $ | 1.27 |
| — |
| $ | (0.61 | ) | — |
| $ | 0.24 |
|
Note 29 — Condensed Consolidating Financial Information
As of December 31, 2017, the Company had outstanding $4.8 billion of Senior Notes due 2022 - 2028, as shown in Note 12, 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, including GenOn and its 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 December 31, 2017:
|
| | |
Ace Energy, Inc. | New Genco GP, LLC | NRG Norwalk Harbor Operations Inc. |
Allied Home Warranty GP LLC | Norwalk Power LLC | NRG Operating Services, Inc. |
Allied Warranty LLC | NRG Advisory Services LLC | NRG Oswego Harbor Power Operations Inc. |
Arthur Kill Power LLC | NRG Affiliate Services Inc. | NRG PacGen Inc. |
Astoria Gas Turbine Power LLC | NRG Arthur Kill Operations Inc. | NRG Portable Power LLC |
Bayou Cove Peaking Power, LLC | NRG Astoria Gas Turbine Operations Inc. | NRG Power Marketing LLC |
BidURenergy, Inc. | NRG Bayou Cove LLC | NRG Reliability Solutions LLC |
Cabrillo Power I LLC | NRG Business Services LLC | NRG Renter's Protection LLC |
Cabrillo Power II LLC | NRG Cabrillo Power Operations Inc. | NRG Retail LLC |
Carbon Management Solutions LLC | NRG California Peaker Operations LLC | NRG Retail Northeast LLC |
Cirro Group, Inc. | NRG Cedar Bayou Development Company, LLC | NRG Rockford Acquisition LLC |
Cirro Energy Services, Inc. | NRG Connected Home LLC | NRG Saguaro Operations Inc. |
Conemaugh Power LLC | NRG Connecticut Affiliate Services Inc. | NRG Security LLC |
Connecticut Jet Power LLC | NRG Construction LLC | NRG Services Corporation |
Cottonwood Development LLC | NRG Curtailment Solutions, Inc | NRG SimplySmart Solutions LLC |
Cottonwood Energy Company LP | NRG Development Company Inc. | NRG South Central Affiliate Services Inc. |
Cottonwood Generating Partners I LLC | NRG Devon Operations Inc. | NRG South Central Generating LLC |
Cottonwood Generating Partners II LLC | NRG Dispatch Services LLC | NRG South Central Operations Inc. |
Cottonwood Generating Partners III LLC | NRG Distributed Energy Resources Holdings LLC | NRG South Texas LP |
Cottonwood Technology Partners LP | NRG Distributed Generation PR LLC | NRG SPV #1 LLC |
Devon Power LLC | NRG Dunkirk Operations Inc. | NRG Texas C&I Supply LLC |
Dunkirk Power LLC | NRG El Segundo Operations Inc. | NRG Texas Gregory LLC |
Eastern Sierra Energy Company LLC | NRG Energy Efficiency-L LLC | NRG Texas Holding Inc. |
El Segundo Power, LLC | NRG Energy Labor Services LLC | NRG Texas LLC |
El Segundo Power II LLC | NRG ECOKAP Holdings LLC | NRG Texas Power LLC |
Energy Alternatives Wholesale, LLC | NRG Energy Services Group LLC | NRG Warranty Services LLC |
Energy Choice Solutions LLC | NRG Energy Services International Inc. | NRG West Coast LLC |
Energy Plus Holdings LLC | NRG Energy Services LLC | NRG Western Affiliate Services Inc. |
Energy Plus Natural Gas LLC | NRG Generation Holdings, Inc. | O'Brien Cogeneration, Inc. II |
Energy Protection Insurance Company | NRG Greenco LLC | ONSITE Energy, Inc. |
Everything Energy LLC | NRG Home & Business Solutions LLC | Oswego Harbor Power LLC |
Forward Home Security, LLC | NRG Home Services LLC | Reliant Energy Northeast LLC |
GCP Funding Company, LLC | NRG Home Solutions LLC | Reliant Energy Power Supply, LLC |
Green Mountain Energy Company | NRG Home Solutions Product LLC | Reliant Energy Retail Holdings, LLC |
Gregory Partners, LLC | NRG Homer City Services LLC | Reliant Energy Retail Services, LLC |
Gregory Power Partners LLC | NRG Huntley Operations Inc. | RERH Holdings, LLC |
Huntley Power LLC | NRG HQ DG LLC | Saguaro Power LLC |
Independence Energy Alliance LLC | NRG Identity Protect LLC | Somerset Operations Inc. |
Independence Energy Group LLC | NRG Ilion Limited Partnership | Somerset Power LLC |
Independence Energy Natural Gas LLC | NRG Ilion LP LLC | Texas Genco GP, LLC |
Indian River Operations Inc. | NRG International LLC | Texas Genco Holdings, Inc. |
Indian River Power LLC | NRG Maintenance Services LLC | Texas Genco LP, LLC |
Keystone Power LLC | NRG Mextrans Inc. | Texas Genco Services, LP |
Langford Wind Power, LLC | NRG MidAtlantic Affiliate Services Inc. | US Retailers LLC |
Louisiana Generating LLC | NRG Middletown Operations Inc. | Vienna Operations Inc. |
Meriden Gas Turbines LLC | NRG Montville Operations Inc. | Vienna Power LLC |
Middletown Power LLC | NRG New Roads Holdings LLC | WCP (Generation) Holdings LLC |
Montville Power LLC | NRG North Central Operations Inc. | West Coast Power LLC |
NEO Corporation | NRG Northeast Affiliate Services Inc. | |
The non-guarantor subsidiaries include all of NRG's foreign subsidiaries and certain domestic subsidiaries. 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. Except for NRG Bayou Cove, LLC, which is subject to certain restrictions under the Company's Peaker financing agreements, there are no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to NRG. In addition, 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's 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.
In addition, the condensed parent company financial statements are provided in accordance with Rule 12-04, Schedule I of Regulation S-X, as the restricted net assets of NRG Energy, Inc.’s subsidiaries exceed 25 percent of the consolidated net assets of NRG Energy, Inc. These statements should be read in conjunction with the consolidated statements and notes thereto of NRG Energy, Inc. For a discussion of NRG Energy, Inc.'s long-term debt, see Note 12, Debt and Capital Leasesto the consolidated financial statements. For a discussion of NRG Energy, Inc.'s contingencies, see Note 22, Commitments and Contingenciesto the consolidated financial statements. For a discussion of NRG Energy, Inc.'s guarantees, see Note 26, Guaranteesto the consolidated financial statements.
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Year Ended December 31, 2017
|
| | | | | | | | | | | | | | | | | | | | | |
| | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc. (Note Issuer) | | Eliminations (a) | | Consolidated Balance |
| | (In millions) |
| Operating Revenues | | | | | | | | | |
| Total operating revenues | $ | 7,182 |
| — |
| $ | 3,699 |
| — |
| $ | — |
| | $ | (252 | ) | | $ | 10,629 |
|
| Operating Costs and Expenses | | | | | | | | | |
| Cost of operations | 5,373 |
| | 2,353 |
| | 59 |
| | (249 | ) | | 7,536 |
|
| Depreciation and amortization | 405 |
| | 619 |
| | 32 |
| | — |
| | 1,056 |
|
| Impairment losses | 1,463 |
| | 246 |
| | — |
| | — |
| | 1,709 |
|
| Selling, general and administrative | 371 |
| | 146 |
| | 393 |
| | (3 | ) | | 907 |
|
| Reorganization costs | 6 |
| | — |
| | 38 |
| | — |
| | 44 |
|
| Development costs | — |
| | 49 |
| | 18 |
| | — |
| | 67 |
|
| Total operating costs and expenses | 7,618 |
| | 3,413 |
| | 540 |
| | (252 | ) | | 11,319 |
|
| Other income - affiliate | — |
| | — |
| | 87 |
| | — |
| | 87 |
|
| Gain on sale of assets | 4 |
| | 12 |
| | — |
| | — |
| | 16 |
|
| Operating (Loss)/Income | (432 | ) | | 298 |
| | (453 | ) | | — |
| | (587 | ) |
| Other (Expense)/Income | | | | | | | | | |
| Equity in (losses)/earnings of consolidated subsidiaries | (1,162 | ) | | (113 | ) | | 26 |
| | 1,249 |
| | — |
|
| Equity in earnings/(losses) of unconsolidated affiliates | — |
| | 95 |
| | (4 | ) | | (60 | ) | | 31 |
|
| Impairment losses on investments | — |
| | (75 | ) | | (4 | ) | | — |
| | (79 | ) |
| Other income, net | 9 |
| | 17 |
| | 12 |
| | — |
| | 38 |
|
| Net loss on debt extinguishment | — |
| | (4 | ) | | (49 | ) | | — |
| | (53 | ) |
| Interest expense | (14 | ) | | (424 | ) | | (452 | ) | | — |
| | (890 | ) |
| Total other expense | (1,167 | ) | | (504 | ) | | (471 | ) | | 1,189 |
| | (953 | ) |
| Loss from Continuing Operations Before Income Taxes | (1,599 | ) | | (206 | ) | | (924 | ) | | 1,189 |
| | (1,540 | ) |
| Income tax (benefit)/expense | (598 | ) | | (10 | ) | | 616 |
| | — |
| | 8 |
|
| Loss from Continuing Operations | (1,001 | ) | | (196 | ) | | (1,540 | ) | | 1,189 |
| | (1,548 | ) |
| Loss from Discontinued Operations, net of income tax | — |
| | (160 | ) | | (629 | ) | | — |
| | (789 | ) |
| Net Loss | (1,001 | ) | | (356 | ) | | (2,169 | ) | | 1,189 |
| | (2,337 | ) |
| Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests | — |
| | (108 | ) | | (16 | ) | | (60 | ) | | (184 | ) |
| Net Loss Attributable to NRG Energy, Inc. | $ | (1,001 | ) | | $ | (248 | ) | | $ | (2,153 | ) | | $ | 1,249 |
| | $ | (2,153 | ) |
| |
(a) | All significant intercompany transactions have been eliminated in consolidation. |
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE (LOSS)/INCOME
For the Year Ended December 31, 2017
|
| | | | | | | | | | | | | | | | | | | | | | |
| | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc. (Note Issuer) | | Eliminations(a) | | Consolidated Balance |
| | (In millions) |
| Net Loss | $ | (1,001 | ) | | $ | (356 | ) | | $ | (2,169 | ) | | $ | 1,189 |
| | $ | (2,337 | ) |
| Other Comprehensive (Loss)/Income, net of tax | | | | | | | | | |
| Unrealized gain on derivatives, net | 1 |
| | 13 |
| | 25 |
| | (26 | ) | | 13 |
|
| Foreign currency translation adjustments, net | 6 |
| | 7 |
| | — |
| | (1 | ) | | 12 |
|
| Available-for-sale securities, net | — |
| | — |
| | (8 | ) | | — |
| | (8 | ) |
| Defined benefit plan, net | (24 | ) | | 29 |
| | 41 |
| | — |
| | 46 |
|
| Other comprehensive (loss)/income | (17 | ) | | 49 |
| | 58 |
| | (27 | ) | | 63 |
|
| Comprehensive Loss | (1,018 | ) | | (307 | ) | | (2,111 | ) | | 1,162 |
| | (2,274 | ) |
| Less: Comprehensive loss attributable to noncontrolling interests and redeemable noncontrolling interests | — |
| — |
| (103 | ) | — |
| (16 | ) | — |
| (60 | ) | | (179 | ) |
| Comprehensive Loss Attributable to NRG Energy, Inc. | $ | (1,018 | ) | | $ | (204 | ) | | $ | (2,095 | ) | | $ | 1,222 |
| | $ | (2,095 | ) |
| |
(a) | All significant intercompany transactions have been eliminated in consolidation. |
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2017
|
| | | | | | | | | | | | | | | | | | | | | |
| | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc. | | Eliminations (a) | | Consolidated Balance |
| | (In millions) |
| ASSETS | | | | | | | | | |
| Current Assets | | | | | | | | | |
| Cash and cash equivalents | $ | — |
| | $ | 348 |
| | $ | 643 |
| | $ | — |
| | $ | 991 |
|
| Funds deposited by counterparties | 37 |
| | — |
| | — |
| | — |
| | 37 |
|
| Restricted cash | 4 |
| | 504 |
| | — |
| | — |
| | 508 |
|
| Accounts receivable - trade | 769 |
| | 306 |
| | 4 |
| | — |
| | 1,079 |
|
| Inventory | 339 |
| | 193 |
| | — |
| | — |
| | 532 |
|
| Derivative instruments | 625 |
| | 80 |
| | 9 |
| | (88 | ) | | 626 |
|
| Cash collateral posted in support of energy risk management activities | 170 |
| | 1 |
| | — |
| | — |
| | 171 |
|
| Accounts receivable - affiliate | 712 |
| | 210 |
| | (129 | ) | | (698 | ) | | 95 |
|
| Current assets held-for-sale | 8 |
| | 107 |
| | — |
| | — |
| | 115 |
|
| Prepayments and other current assets | 116 |
| | 118 |
| | 27 |
| | — |
| | 261 |
|
| Total current assets | 2,780 |
| | 1,867 |
| | 554 |
| | (786 | ) | | 4,415 |
|
| Net Property, Plant and Equipment | 2,527 |
| | 11,169 |
| — |
| 238 |
| — |
| (26 | ) | | 13,908 |
|
| Other Assets | | | | | | | | | |
| Investment in subsidiaries | (106 | ) | | 28 |
| — |
| 7,581 |
| | (7,503 | ) | | — |
|
| Equity investments in affiliates | — |
| | 1,036 |
| | 2 |
| | — |
| | 1,038 |
|
| Notes receivable, less current portion | — |
| | 2 |
| | 36 |
| | (36 | ) | | 2 |
|
| Goodwill | 360 |
| | 179 |
| | — |
| | — |
| | 539 |
|
| Intangible assets, net | 458 |
| | 1,291 |
| | — |
| | (3 | ) | | 1,746 |
|
| Nuclear decommissioning trust fund | 692 |
| | — |
| | — |
| | — |
| | 692 |
|
| Deferred income taxes | 377 |
| | (7 | ) | | (236 | ) | | — |
| | 134 |
|
| Derivative instruments | 121 |
| | 40 |
| | 31 |
| | (20 | ) | | 172 |
|
| Non-current assets held-for-sale | — |
| | 43 |
| | — |
| | — |
| | 43 |
|
| Other non-current assets | 51 |
| | 458 |
| | 120 |
| | — |
| | 629 |
|
| Total other assets | 1,953 |
| | 3,070 |
| | 7,534 |
| | (7,562 | ) | | 4,995 |
|
| Total Assets | $ | 7,260 |
| | $ | 16,106 |
| | $ | 8,326 |
| | $ | (8,374 | ) | | $ | 23,318 |
|
| LIABILITIES AND STOCKHOLDERS' EQUITY | | | | | | | | | |
| Current Liabilities | | | | | | | | | |
| Current portion of long-term debt and capital leases | $ | — |
| | $ | 667 |
| | $ | 57 |
| | $ | (36 | ) | | $ | 688 |
|
| Accounts payable | 546 |
| | 280 |
| | 55 |
| | — |
| | 881 |
|
| Accounts payable - affiliate | 752 |
| | (202 | ) | | 181 |
| | (698 | ) | | 33 |
|
| Derivative instruments | 535 |
| | 108 |
| | — |
| | (88 | ) | | 555 |
|
| Cash collateral received in support of energy risk management activities | 37 |
| | — |
| | — |
| | — |
| | 37 |
|
| Accrued interest expense | 3 |
| | 56 |
| | 97 |
| | — |
| | 156 |
|
| Current liabilities - held-for-sale | — |
| | 72 |
| | — |
| | — |
| | 72 |
|
| Other accrued expenses and other current liabilities | 288 |
| | 118 |
| | 328 |
| | — |
| | 734 |
|
| Other accrued expenses and other current liabilities - affiliate | — |
| | — |
| | 161 |
| | — |
| | 161 |
|
| Total current liabilities | 2,161 |
| | 1,099 |
| | 879 |
| | (822 | ) | | 3,317 |
|
| Other Liabilities | | | | | | | | | |
| Long-term debt and capital leases | 244 |
| | 8,733 |
| | 6,739 |
| | — |
| | 15,716 |
|
| Nuclear decommissioning reserve | 269 |
| | — |
| | — |
| | — |
| | 269 |
|
| Nuclear decommissioning trust liability | 415 |
| | — |
| | — |
| | — |
| | 415 |
|
| Postretirement and other benefit obligations | 118 |
| | 1 |
| | 339 |
| | — |
| | 458 |
|
| Deferred income taxes | 112 |
| | 64 |
| | (155 | ) | | — |
| | 21 |
|
| Derivative instruments | 110 |
| | 107 |
| | — |
| | (20 | ) | | 197 |
|
| Out-of-market contracts, net | 66 |
| | 141 |
| | — |
| | — |
| | 207 |
|
| Non-current liabilities held-for-sale | — |
| | 8 |
| | — |
| | — |
| | 8 |
|
| Other non-current liabilities | 295 |
| | 317 |
| | 52 |
| | — |
| | 664 |
|
| Total non-current liabilities | 1,629 |
| | 9,371 |
| | 6,975 |
| | (20 | ) | | 17,955 |
|
| Total Liabilities | 3,790 |
| | 10,470 |
| | 7,854 |
| | (842 | ) | | 21,272 |
|
| Redeemable noncontrolling interest in subsidiaries | — |
| | 78 |
| | — |
| | — |
| | 78 |
|
| Stockholders' Equity | 3,470 |
| | 5,558 |
| | 472 |
| | (7,532 | ) | | 1,968 |
|
| Total Liabilities and Stockholders' Equity | $ | 7,260 |
| | $ | 16,106 |
| | $ | 8,326 |
| | $ | (8,374 | ) | | $ | 23,318 |
|
| |
(a) | All significant intercompany transactions have been eliminated in consolidation. |
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 2017
|
| | | | | | | | | | | | | | | | | | | |
| | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc. (Note Issuer) | | Eliminations(a) | | Consolidated Balance |
| | |
| Cash Flows from Operating Activities | | | | | | | | | |
| Net loss | $ | (1,001 | ) | | $ | (356 | ) | | $ | (2,169 | ) | | $ | 1,189 |
| | $ | (2,337 | ) |
| Loss from discontinued operations | — |
| | (160 | ) | | (629 | ) | | — |
| | (789 | ) |
| Net loss from continuing operations | (1,001 | ) | | (196 | ) | | (1,540 | ) | | 1,189 |
| | (1,548 | ) |
| Adjustments to reconcile net loss to net cash provided by operating activities: |
| |
| |
| |
| |
|
| Equity in earnings and distributions from unconsolidated affiliates | — |
| | 5 |
| | 4 |
| | 46 |
| | 55 |
|
| Depreciation and amortization | 405 |
| | 619 |
| | 32 |
| | — |
| | 1,056 |
|
| Provision for bad debts | 54 |
| | 2 |
| | 12 |
| | — |
| | 68 |
|
| Amortization of nuclear fuel | 51 |
| | — |
| | — |
| | — |
| | 51 |
|
| Amortization of financing costs and debt discount/premiums | — |
| | 42 |
| | 18 |
| | — |
| | 60 |
|
| Adjustment for debt extinguishment | — |
| | 4 |
| | 49 |
| | — |
| | 53 |
|
| Amortization of intangibles and out-of-market contracts | 27 |
| | 81 |
| | — |
| | — |
| | 108 |
|
| Amortization of unearned equity compensation | — |
| | — |
| | 35 |
| | — |
| | 35 |
|
| Net gain on sale of assets and equity method investments | (18 | ) | | (16 | ) | | — |
| | — |
| | (34 | ) |
| Impairment losses | 1,463 |
| | 321 |
| | 4 |
| | — |
| | 1,788 |
|
| Changes in derivative instruments | (100 | ) | | (69 | ) | | 24 |
| | (26 | ) | | (171 | ) |
| Changes in deferred income taxes and liability for uncertain tax benefits | (300 | ) | | 69 |
| | 322 |
| | — |
| | 91 |
|
| Changes in collateral deposits in support of energy risk management activities | (98 | ) |
| 18 |
| | — |
| | — |
| | (80 | ) |
| Proceeds from sale of emission allowances | 25 |
| | — |
| | — |
| | — |
| | 25 |
|
| Changes in nuclear decommissioning trust liability | 11 |
| | — |
| | — |
| | — |
| | 11 |
|
| Cash (used)/provided by changes in other working capital | (363 | ) | | (164 | ) | | 1,593 |
| | (1,209 | ) | | (143 | ) |
| Cash provided by continuing operations | 156 |
| | 716 |
| | 553 |
| | — |
| | 1,425 |
|
| Cash used by discontinued operations | — |
| | (38 | ) | | — |
| | — |
| | (38 | ) |
| Net Cash Provided by Operating Activities | 156 |
| | 678 |
| | 553 |
| | — |
| | 1,387 |
|
| Cash Flows from Investing Activities |
| |
| |
| |
|
| | |
|
| Dividends from NRG Yield, Inc. | — |
| | — |
| | 94 |
| | (94 | ) | | — |
|
| Acquisition of Drop Down Assets, net of cash acquired | — |
| | (249 | ) | | — |
| | 249 |
| | — |
|
| Intercompany dividends | — |
| | — |
| | 129 |
| | (129 | ) | | — |
|
| Acquisition of businesses, net of cash acquired | (14 | ) | | (27 | ) | | — |
| | — |
| | (41 | ) |
| Capital expenditures | (183 | ) | | (906 | ) | | (22 | ) | | — |
| | (1,111 | ) |
| Net cash proceeds from notes receivable | — |
| | 17 |
| | — |
| | — |
| | 17 |
|
| Proceeds from renewable energy grants | 8 |
| | — |
| | — |
| | — |
| | 8 |
|
| Proceeds from sale of emission allowances | 66 |
| | — |
| | — |
| | — |
| | 66 |
|
| Investments in nuclear decommissioning trust fund securities | (512 | ) | | — |
| | — |
| | — |
| | (512 | ) |
| Proceeds from sales of nuclear decommissioning trust fund securities | 501 |
| | — |
| | — |
| | — |
| | 501 |
|
| Proceeds from sale of assets, net | 33 |
| | 54 |
| | — |
| | — |
| | 87 |
|
| Investments in unconsolidated affiliates | — |
| | (40 | ) | | — |
| | — |
| | (40 | ) |
| Other | 18 |
| | (6 | ) | | — |
| | — |
| | 12 |
|
| Cash (used)/provided by continuing operations | (83 | ) | | (1,157 | ) | | 201 |
| | 26 |
| | (1,013 | ) |
| Cash used by discontinued operations | — |
| | (53 | ) | | — |
| | — |
| | (53 | ) |
| Net Cash (Used)/Provided by Investing Activities | (83 | ) | | (1,210 | ) | | 201 |
| | 26 |
| | (1,066 | ) |
| Cash Flows from Financing Activities |
|
| | |
| | |
| | | | |
| Dividends from NRG Yield, Inc. | — |
| | (94 | ) | | — |
| | 94 |
| | — |
|
| Payments from/(for) intercompany loans | (45 | ) | | 13 |
| | 32 |
| | — |
| | — |
|
| Acquisition of Drop Down Assets, net of cash acquired | — |
| | — |
| | 249 |
| | (249 | ) | | — |
|
| Intercompany dividends | — |
| | (129 | ) | | — |
| | 129 |
| | — |
|
| Payment of dividends to common and preferred stockholders | — |
| | — |
| | (38 | ) | | — |
| | (38 | ) |
| Net receipts from settlement of acquired derivatives that include financing elements | — |
| | 2 |
| | — |
| | — |
| | 2 |
|
| Payments for debt extinguishment costs | — |
| | — |
| | (42 | ) | | — |
| | (42 | ) |
| Distributions from, net of contributions to, noncontrolling interest in subsidiaries | — |
| | 95 |
| | — |
| | — |
| | 95 |
|
| Payments from issuance of common stock | — |
| | — |
| | (2 | ) | | — |
| | (2 | ) |
| Proceeds from issuance of long-term debt | — |
| | 1,186 |
| | 1,084 |
| | — |
| | 2,270 |
|
| Payment of debt issuance and hedging costs | — |
| | (47 | ) | | (16 | ) | | — |
| | (63 | ) |
| Payments for short and long-term debt | — |
| | (647 | ) | | (1,701 | ) | | — |
| | (2,348 | ) |
| Receivable from affiliate | — |
| | (125 | ) | | — |
| | — |
| | (125 | ) |
| Other | — |
| | (10 | ) | | — |
| | — |
| | (10 | ) |
| Cash provided/(used) by continuing operations | (45 | ) | | 244 |
| | (434 | ) | | (26 | ) | | (261 | ) |
| Cash used by discontinued operations | — |
| | (224 | ) | | — |
| | — |
| | (224 | ) |
| Net Cash Provided/(Used) by Financing Activities | (45 | ) | | 20 |
| | (434 | ) | | (26 | ) | | (485 | ) |
| Effect of exchange rate changes on cash and cash equivalents | — |
| | (1 | ) | | — |
| | — |
| | (1 | ) |
| Change in cash from discontinued operations | — |
| | (315 | ) | | — |
| | — |
| | (315 | ) |
| Net Increase/(Decrease) in Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties | 28 |
| | (198 | ) | | 320 |
| | — |
| | 150 |
|
| Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at Beginning of Period | 13 |
| | 1,050 |
| | 323 |
| | — |
| | 1,386 |
|
| Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at End of Period | $ | 41 |
| | $ | 852 |
| | $ | 643 |
| | $ | — |
| | $ | 1,536 |
|
| |
(a) | All significant intercompany transactions have been eliminated in consolidation. |
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Year Ended December 31, 2016
|
| | | | | | | | | | | | | | | | | | | | | |
| | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc. (Note Issuer) | | Eliminations (a) | | Consolidated Balance |
| | (In millions) |
| Operating Revenues | | | | | | | | | |
| Total operating revenues | $ | 7,509 |
| — |
| $ | 3,222 |
| — |
| $ | — |
| | $ | (219 | ) | | $ | 10,512 |
|
| Operating Costs and Expenses |
| |
| |
| |
| | |
| Cost of operations | 5,402 |
| | 2,080 |
| | 42 |
| | (223 | ) | | 7,301 |
|
| Depreciation and amortization | 565 |
| | 581 |
| | 26 |
| | — |
| | 1,172 |
|
| Impairment losses | 378 |
| | 324 |
| | — |
| | — |
| | 702 |
|
| Selling, general and administrative | 415 |
| | 192 |
| | 488 |
| | — |
| | 1,095 |
|
| Development costs | — |
| | 59 |
| | 30 |
| | — |
| | 89 |
|
| Total operating costs and expenses | 6,760 |
| | 3,236 |
| | 586 |
| | (223 | ) | | 10,359 |
|
| Other income - affiliate | — |
| | — |
| | 193 |
| | — |
| | 193 |
|
| Loss on sale of assets | (1 | ) | | — |
| | (79 | ) | | — |
| | (80 | ) |
| Operating Income/(Loss) | 748 |
| | (14 | ) | | (472 | ) | | 4 |
| | 266 |
|
| Other (Expense)/Income | | |
| | | | | | |
| Equity in (losses)/earnings of consolidated subsidiaries | (176 | ) | | (5 | ) | | 313 |
| | (132 | ) | | — |
|
| Equity in earnings/(losses) of unconsolidated affiliates | 5 |
| | 36 |
| | (4 | ) | | (10 | ) | | 27 |
|
| Impairment losses on investments | — |
| | (252 | ) | | (16 | ) | | — |
| | (268 | ) |
| Other income, net | 4 |
| | 23 |
| | 9 |
| | (2 | ) | | 34 |
|
| Net loss on debt extinguishment | — |
| | (4 | ) | | (138 | ) | | — |
| | (142 | ) |
| Interest expense | (15 | ) | | (396 | ) | | (484 | ) | | — |
| | (895 | ) |
| Total other expense | (182 | ) | | (598 | ) | | (320 | ) | | (144 | ) | | (1,244 | ) |
| Income/(Loss) from Continuing Operations Before Income Taxes | 566 |
| | (612 | ) | | (792 | ) | | (140 | ) | | (978 | ) |
| Income tax (benefit)/expense | (1 | ) | | 7 |
| | (63 | ) | | 62 |
| | 5 |
|
| Income/(Loss) from Continuing Operations | 567 |
| | (619 | ) | | (729 | ) | | (202 | ) | | (983 | ) |
| Income from Discontinued Operations, net of income tax | — |
| | 81 |
| | 11 |
| | — |
| | 92 |
|
| Net Income/(Loss) | 567 |
| | (538 | ) | | (718 | ) | | (202 | ) | | (891 | ) |
| Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests | — |
| | (103 | ) | | 56 |
| | (70 | ) | | (117 | ) |
| Net Income/(Loss) Attributable to NRG Energy, Inc. | $ | 567 |
| | $ | (435 | ) | | $ | (774 | ) | | $ | (132 | ) | | $ | (774 | ) |
| |
(a) | All significant intercompany transactions have been eliminated in consolidation. |
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE (LOSS)/INCOME
For the Year Ended December 31, 2016
|
| | | | | | | | | | | | | | | | | | | | | |
| | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc. (Note Issuer) | | Eliminations(a) | | Consolidated Balance |
| | (In millions) |
| Net Income/(Loss) | $ | 567 |
| | $ | (538 | ) | | $ | (718 | ) | | $ | (202 | ) | | $ | (891 | ) |
| Other Comprehensive Income, net of tax | | | | | | | | | |
| Unrealized gain on derivatives, net | — |
| | 32 |
| | 89 |
| | (86 | ) | | 35 |
|
| Foreign currency translation adjustments, net | (1 | ) | | (1 | ) | | (1 | ) | | 2 |
| | (1 | ) |
| Available-for-sale securities, net | — |
| | — |
| | 1 |
| | — |
| | 1 |
|
| Defined benefit plan, net | 34 |
| | (13 | ) | | (51 | ) | | 33 |
| | 3 |
|
| Other comprehensive income | 33 |
| | 18 |
| | 38 |
| | (51 | ) | | 38 |
|
| Comprehensive Income/(Loss) | 600 |
| | (520 | ) | | (680 | ) | | (253 | ) | | (853 | ) |
| Less: Comprehensive (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests | — |
| | (103 | ) | — |
| 56 |
| | (70 | ) | | (117 | ) |
| Comprehensive Income/(Loss) Attributable to NRG Energy, Inc. | 600 |
| | (417 | ) | — |
| (736 | ) | | (183 | ) | | (736 | ) |
| Dividends for preferred shares | — |
| | — |
| | 5 |
| — |
| — |
| | 5 |
|
| Gain on redemption of preferred shares | — |
| | — |
| | (78 | ) | | — |
| | (78 | ) |
| Comprehensive Income/(Loss) Available for Common Stockholders | $ | 600 |
| | $ | (417 | ) | | $ | (663 | ) | | $ | (183 | ) | | $ | (663 | ) |
| |
(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. | | Eliminations (a) | | Consolidated Balance |
| | |
| ASSETS | | | | | | | | | |
| Current Assets | | | | | | | | | |
| Cash and cash equivalents | $ | — |
| | $ | 615 |
| | $ | 323 |
| | $ | — |
| | $ | 938 |
|
| Funds deposited by counterparties | 2 |
| | — |
| | — |
| | — |
| | 2 |
|
| Restricted cash | 11 |
| | 435 |
| | — |
| | — |
| | 446 |
|
| Accounts receivable - trade | 734 |
| | 321 |
| | 3 |
| | — |
| | 1,058 |
|
| Inventory | 482 |
| | 239 |
| | — |
| | — |
| | 721 |
|
| Derivative instruments | 962 |
| | 196 |
| | 1 |
| | (92 | ) | | 1,067 |
|
| Cash collateral posted in support of energy risk management activities | 116 |
| | 34 |
| | — |
| | — |
| | 150 |
|
| Accounts receivable - affiliate | 307 |
| | (254 | ) | | 200 |
| | (139 | ) | | 114 |
|
| Current assets held-for-sale | — |
| | 9 |
| | — |
| | — |
| | 9 |
|
| Prepayments and other current assets | 76 |
| | 152 |
| | 62 |
| | — |
| | 290 |
|
| Current assets - discontinued operations | — |
| | 1,919 |
| | — |
| | — |
| | 1,919 |
|
| Total current assets | 2,690 |
| | 3,666 |
| | 589 |
| | (231 | ) | | 6,714 |
|
| Net Property, Plant and Equipment | 4,219 |
| | 10,926 |
| | 251 |
| | (27 | ) | | 15,369 |
|
| Other Assets | | | | | | | | | |
| Investment in subsidiaries | 1,090 |
| | 145 |
| | 10,128 |
| | (11,363 | ) | | — |
|
| Equity investments in affiliates | (13 | ) | | 1,103 |
| | 30 |
| | — |
| | 1,120 |
|
| Notes receivable, less current portion | — |
| | 16 |
| | (76 | ) | | 76 |
| | 16 |
|
| Goodwill | 359 |
| | 303 |
| | — |
| | — |
| | 662 |
|
| Intangible assets, net | 592 |
| | 1,384 |
| | — |
| | (3 | ) | | 1,973 |
|
| Nuclear decommissioning trust fund | 610 |
| | — |
| | — |
| | — |
| | 610 |
|
| Derivative instruments | 144 |
| | 44 |
| | 36 |
| | (43 | ) | | 181 |
|
| Deferred income taxes | 3 |
| | — |
| | 222 |
| | — |
| | 225 |
|
| Non-current assets held for sale | — |
| | 10 |
| | — |
| | — |
| | 10 |
|
| Other non-current assets | 67 |
| | 446 |
| | 328 |
| | — |
| | 841 |
|
| Non-current assets - discontinued operations | — |
| | 2,961 |
| | — |
| | — |
| | 2,961 |
|
| Total other assets | 2,852 |
| | 6,412 |
| | 10,668 |
| | (11,333 | ) | | 8,599 |
|
| Total Assets | $ | 9,761 |
| | $ | 21,004 |
| | $ | 11,508 |
| | $ | (11,591 | ) | | $ | 30,682 |
|
| LIABILITIES AND STOCKHOLDERS' EQUITY | | | | | | | | | |
| Current Liabilities | | | | | | | | | |
| Current portion of long-term debt and capital leases | $ | — |
| | $ | 498 |
| | $ | (58 | ) | | $ | 76 |
| | $ | 516 |
|
| Accounts payable | 501 |
| | 247 |
| | 34 |
| | — |
| | 782 |
|
| Accounts payable - affiliate | 753 |
| | (443 | ) | | (200 | ) | | (79 | ) | | 31 |
|
| Derivative instruments | 947 |
| | 237 |
| | — |
| | (92 | ) | | 1,092 |
|
| Cash collateral received in support of energy risk management activities | 81 |
| | — |
| | — |
| | — |
| | 81 |
|
| Accrued interest expense | 3 |
| | 54 |
| | 123 |
| | — |
| | 180 |
|
Other accrued expenses and other current liabilities
| 313 |
| | 155 |
| | 342 |
| | — |
| | 810 |
|
| Current liabilities - discontinued operations | — |
| | 1,210 |
| | — |
| | — |
| | 1,210 |
|
| Total current liabilities | 2,598 |
| | 1,958 |
| | 241 |
| | (95 | ) | | 4,702 |
|
| Other Liabilities | | | | | | | | | |
| Long-term debt and capital leases | 244 |
| | 8,252 |
| | 7,461 |
| | — |
| | 15,957 |
|
| Nuclear decommissioning reserve | 287 |
| | — |
| | — |
| | — |
| | 287 |
|
| Nuclear decommissioning trust liability | 339 |
| | — |
| | — |
| | — |
| | 339 |
|
| Postretirement and other benefit obligations | 113 |
| | 122 |
| | 275 |
| | — |
| | 510 |
|
| Deferred income taxes | 186 |
| | 125 |
| | (291 | ) | | — |
| | 20 |
|
| Derivative instruments | 157 |
| | 170 |
| | — |
| | (43 | ) | | 284 |
|
| Out-of-market contracts, net | 80 |
| | 150 |
| | — |
| | — |
| | 230 |
|
| Non-current liabilities held-for-sale | — |
| | 11 |
| | — |
| | — |
| | 11 |
|
| Other non-current liabilities | 283 |
| | 309 |
| | 74 |
| | — |
| | 666 |
|
| Other non-current liabilities - discontinued operations | — |
| | 3,184 |
| | — |
| | — |
| | 3,184 |
|
| Total non-current liabilities | 1,689 |
| | 12,323 |
| | 7,519 |
| | (43 | ) | | 21,488 |
|
| Total Liabilities | 4,287 |
| | 14,281 |
| | 7,760 |
| | (138 | ) | | 26,190 |
|
| Redeemable noncontrolling interest in subsidiaries | — |
| | 46 |
| | — |
| | — |
| | 46 |
|
| Stockholders' Equity | 5,474 |
| | 6,677 |
| — |
| 3,748 |
| — |
| (11,453 | ) | | 4,446 |
|
| Total Liabilities and Stockholders' Equity | $ | 9,761 |
| | $ | 21,004 |
| | $ | 11,508 |
| | $ | (11,591 | ) | | $ | 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 Year Ended December 31, 2016 |
| | | | | | | | | | | | | | | | | | | |
| | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc. (Note Issuer) | | Eliminations(a) | | Consolidated Balance |
| | (In millions) |
| Cash Flows from Operating Activities | | | | | | | | | |
| Net income/(loss) | $ | 567 |
| | $ | (538 | ) | | $ | (718 | ) | | $ | (202 | ) | | $ | (891 | ) |
| Income from discontinued operations | — |
| | 81 |
| | 11 |
| | — |
| | 92 |
|
| Net income/(loss) from continuing operations | 567 |
| | (619 | ) | | (729 | ) | | (202 | ) | | (983 | ) |
| Adjustments to reconcile net income/(loss) to net cash provided by operating activities: | | | | | | | | | |
| Equity in earnings and distribution of unconsolidated affiliates | (5 | ) | | 52 |
| | 5 |
| | 2 |
| | 54 |
|
| Depreciation and amortization | 565 |
| | 581 |
| | 26 |
| | — |
| | 1,172 |
|
| Provision for bad debts | 41 |
| | 7 |
| | — |
| | — |
| | 48 |
|
| Amortization of nuclear fuel | 49 |
| | — |
| | — |
| | — |
| | 49 |
|
| Amortization of financing costs and debt discount/premiums | — |
| | 34 |
| | 21 |
| | — |
| | 55 |
|
| Adjustment for debt extinguishment | — |
| | 4 |
| | 138 |
| | — |
| | 142 |
|
| Amortization of intangibles and out-of-market contracts | 39 |
| | 128 |
| | — |
| | — |
| | 167 |
|
| Amortization of unearned equity compensation | — |
| | — |
| | 10 |
| | — |
| | 10 |
|
| Net loss on sale of assets and equity method investments, net | — |
| | — |
| | 70 |
| | — |
| | 70 |
|
| Impairment losses | 378 |
| | 578 |
| | 16 |
| | — |
| | 972 |
|
| Changes in derivative instruments | (77 | ) | | 145 |
| | (36 | ) | | — |
| | 32 |
|
| Changes in deferred income taxes and liability for uncertain tax benefits | (1 | ) | | 18 |
| | (60 | ) | | — |
| | (43 | ) |
| Changes in collateral deposits in support of energy risk management activities | 437 |
| | (39 | ) | | — |
| | — |
| | 398 |
|
| Proceeds from sale of emission allowances | 34 |
| | — |
| | — |
| | — |
| | 34 |
|
| Changes in nuclear decommissioning trust liability | 41 |
| | — |
| | — |
| | — |
| | 41 |
|
| Cash (used)/provided by changes in other working capital | (1,815 | ) | | 417 |
| | 1,187 |
| | 200 |
| | (11 | ) |
| Cash provided by continuing operations | 253 |
| | 1,306 |
| | 648 |
| | — |
| | 2,207 |
|
| Cash used by discontinued operations | — |
| | (119 | ) | | — |
| | — |
| | (119 | ) |
| Net Cash Provided by Operating Activities | 253 |
| | 1,187 |
| | 648 |
| | — |
| | 2,088 |
|
| Cash Flows from Investing Activities | | | | | | | | | |
|
| Dividends from NRG Yield, Inc. | — |
| | — |
| | 81 |
| | (81 | ) | | — |
|
| Intercompany dividends | — |
| | — |
| | 12 |
| | (12 | ) | | — |
|
| Acquisition of Drop Down Assets, net of cash acquired | — |
| | (77 | ) | | — |
| | 77 |
| | — |
|
| Acquisition of businesses, net of cash acquired | — |
| | (209 | ) | | — |
| | — |
| | (209 | ) |
| Capital expenditures | (180 | ) | | (748 | ) | | (48 | ) | | — |
| | (976 | ) |
| Net cash proceeds from notes receivable | — |
| | 17 |
| | — |
| | — |
| | 17 |
|
| Proceeds from renewable energy grants | — |
| | 36 |
| | — |
| | — |
| | 36 |
|
| Purchases of emission allowances, net of proceeds | (1 | ) | | — |
| | — |
| | — |
| | (1 | ) |
| Investments in nuclear decommissioning trust fund securities | (551 | ) | | — |
| | — |
| | — |
| | (551 | ) |
| Proceeds from sales of nuclear decommissioning trust fund securities | 510 |
| | — |
| | — |
| | — |
| | 510 |
|
| Proceeds from sale of assets, net | — |
| | 56 |
| | 17 |
| | — |
| | 73 |
|
| Investments in unconsolidated affiliates | 3 |
| | (26 | ) | | — |
| | — |
| | (23 | ) |
| Other | 27 |
| | — |
| | 8 |
| | — |
| | 35 |
|
| Cash (used)/provided by continuing operations | (192 | ) | | (951 | ) | | 70 |
| | (16 | ) | | (1,089 | ) |
| Cash provided by discontinued operations | — |
| | 297 |
| | — |
| | — |
| | 297 |
|
| Net Cash (Used)/Provided by Investing Activities | (192 | ) | | (654 | ) | | 70 |
| | (16 | ) | | (792 | ) |
| Cash Flows from Financing Activities | | | |
| | |
| | | | |
| Dividends from NRG Yield, Inc. | — |
| | (81 | ) | | — |
| | 81 |
| | — |
|
| Intercompany dividends | (52 | ) | | 40 |
| | — |
| | 12 |
| | — |
|
| Payments (for)/from intercompany loans | (52 | ) | | (49 | ) | | 101 |
| | — |
| | — |
|
| Acquisition of Drop Down Assets, net of cash acquired | — |
| | — |
| | 77 |
| | (77 | ) | | — |
|
| Payment of dividends to common and preferred stockholders | — |
| | — |
| | (76 | ) | | — |
| | (76 | ) |
| Net receipts from settlement of acquired derivatives that include financing elements | — |
| | 6 |
| | — |
| | — |
| | 6 |
|
| Payment for preferred shares | — |
| | — |
| | (226 | ) | | — |
| | (226 | ) |
| Payments for debt extinguishment costs | — |
| | — |
| | (121 | ) | | — |
| | (121 | ) |
| Distributions from, net of contributions to, noncontrolling interest in subsidiaries | — |
| | (156 | ) | | — |
| | — |
| | (156 | ) |
| Proceeds from issuance of common stock | — |
| | — |
| | 1 |
| | — |
| | 1 |
|
| Proceeds from issuance of long-term debt | — |
| | 1,387 |
| | 4,140 |
| | — |
| | 5,527 |
|
| Payment of debt issuance and hedging costs | — |
| | (29 | ) | | (60 | ) | | — |
| | (89 | ) |
| Payments for short and long-term debt | (1 | ) | | (983 | ) | | (4,924 | ) | | — |
| | (5,908 | ) |
| Other | (3 | ) | | (10 | ) | | — |
| | — |
| | (13 | ) |
| Cash (used)/provided by continuing operations | (108 | ) | | 125 |
| | (1,088 | ) | | 16 |
| | (1,055 | ) |
| Cash provided by discontinued operations | — |
| | 140 |
| | — |
| | — |
| | 140 |
|
| Net Cash (Used)/Provided by Financing Activities | (108 | ) | | 265 |
| | (1,088 | ) | | 16 |
| | (915 | ) |
| Effect of exchange rate changes on cash and cash equivalents | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
| Change in cash from discontinued operations | — |
| | 318 |
| | — |
| | — |
| | 318 |
|
| Net (Decrease)/Increase in Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties | (47 | ) | | 481 |
| | (370 | ) | | — |
| | 64 |
|
| Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at Beginning of Period | 60 |
| | 569 |
| | 693 |
| | — |
| | 1,322 |
|
| Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at End of Period | $ | 13 |
| | $ | 1,050 |
| | $ | 323 |
| | $ | — |
| | $ | 1,386 |
|
(a) All significant intercompany transactions have been eliminated in consolidation.
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Year Ended December 31, 2015
|
| | | | | | | | | | | | | | | | | | | | | |
| | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc. | | Eliminations (a) | | Consolidated Balance |
| | (In millions) |
| Operating Revenues | | | | | | | | | |
| Total operating revenues | $ | 9,881 |
| — |
| $ | 2,541 |
| — |
| $ | — |
| | $ | (94 | ) | | $ | 12,328 |
|
| Operating Costs and Expenses | | | | | | | | | |
| Cost of operations | 7,610 |
| | 1,470 |
| | 14 |
| | (94 | ) | | 9,000 |
|
| Depreciation and amortization | 751 |
| | 580 |
| | 20 |
| | — |
| | 1,351 |
|
| Impairment losses | 4,494 |
| | 366 |
| | — |
| | — |
| | 4,860 |
|
| Selling, general and administrative | 468 |
| | 204 |
| | 556 |
| | — |
| | 1,228 |
|
| Development costs | — |
| | 61 |
| | 93 |
| | — |
| | 154 |
|
| Total operating costs and expenses | 13,323 |
| | 2,681 |
| | 683 |
| | (94 | ) | | 16,593 |
|
| Other income - affiliate | — |
| | — |
| | 193 |
| | — |
| | 193 |
|
| Gain on postretirement benefits curtailment | — |
| | 21 |
| | — |
| | — |
| | 21 |
|
| Operating Loss | (3,442 | ) | | (119 | ) | | (490 | ) | | — |
| | (4,051 | ) |
| Other (Expense)/Income | | | | | | | | | |
| Equity in losses of consolidated subsidiaries | (109 | ) | | (1 | ) | | (2,800 | ) | | 2,910 |
| | — |
|
| Equity in earnings of unconsolidated affiliates | 8 |
| | 37 |
| | — |
| | (9 | ) | | 36 |
|
| Impairment losses on investments | — |
| | (25 | ) | | (31 | ) | | — |
| | (56 | ) |
| Other income, net | 4 |
| | 21 |
| | 1 |
| | — |
| | 26 |
|
| Loss on sale of equity-method investment | — |
| | — |
| | (14 | ) | | — |
| | (14 | ) |
| Net (loss)/gain on debt extinguishment | — |
| | (9 | ) | | 19 |
| | — |
| | 10 |
|
| Interest expense | (14 | ) | | (366 | ) | | (557 | ) | | — |
| | (937 | ) |
| Total other expense | (111 | ) | | (343 | ) | | (3,382 | ) | | 2,901 |
| | (935 | ) |
| Loss from Continuing Operations Before Income Taxes | (3,553 | ) | | (462 | ) | | (3,872 | ) | | 2,901 |
| | (4,986 | ) |
| Income tax (benefit)/expense | (1,104 | ) | | (93 | ) | | 2,489 |
| | 53 |
| | 1,345 |
|
| Loss from Continuing Operations | (2,449 | ) | | (369 | ) | | (6,361 | ) | | 2,848 |
| | (6,331 | ) |
| Loss/(income) from Discontinued Operations, net of income tax | — |
| | (115 | ) | | 10 |
| | — |
| | (105 | ) |
| Net Loss | (2,449 | ) | | (484 | ) | | (6,351 | ) | | 2,848 |
| | (6,436 | ) |
| Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests | — |
| | (23 | ) | | 31 |
| | (62 | ) | | (54 | ) |
| Net Loss Attributable to NRG Energy, Inc. | $ | (2,449 | ) | | $ | (461 | ) | | $ | (6,382 | ) | | $ | 2,910 |
| | $ | (6,382 | ) |
| |
(a) | All significant intercompany transactions have been eliminated in consolidation. |
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE (LOSS)/INCOME
For the Year Ended December 31, 2015
|
| | | | | | | | | | | | | | | | | | | |
| | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc. (Note Issuer) | | Eliminations(a) | | Consolidated Balance |
| | (In millions) |
| Net Loss | $ | (2,449 | ) | | $ | (484 | ) | | $ | (6,351 | ) | | $ | 2,848 |
| | $ | (6,436 | ) |
| Other Comprehensive (Loss)/Income, net of tax | | | | | | | | | |
| Unrealized (loss)/gain on derivatives, net | (8 | ) | | (16 | ) | | 48 |
| | (39 | ) | | (15 | ) |
| Foreign currency translation adjustments, net | — |
| | (7 | ) | | (4 | ) | | — |
| | (11 | ) |
| Available-for-sale securities, net | — |
| | (1 | ) | | 18 |
| | — |
| | 17 |
|
| Defined benefit plan, net | (22 | ) | | (15 | ) | | (42 | ) | | 89 |
| | 10 |
|
| Other comprehensive (loss)/income | (30 | ) | | (39 | ) | | 20 |
| | 50 |
| | 1 |
|
| Comprehensive Loss | (2,479 | ) | | (523 | ) | | (6,331 | ) | | 2,898 |
| | (6,435 | ) |
| Less: Comprehensive (loss)/income attributable to noncontrolling interest | — |
| | (42 | ) | | 31 |
| | (62 | ) | | (73 | ) |
| Comprehensive Loss Attributable to NRG Energy, Inc. | (2,479 | ) | | (481 | ) | | (6,362 | ) | | 2,960 |
| | (6,362 | ) |
| Dividends for preferred shares | — |
| | — |
| | 20 |
| | — |
| | 20 |
|
| Comprehensive Loss Available for Common Stockholders | $ | (2,479 | ) | | $ | (481 | ) | | $ | (6,382 | ) | | $ | 2,960 |
| | $ | (6,382 | ) |
| |
(a) | All significant intercompany transactions have been eliminated in consolidation. |
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 2015 |
| | | | | | | | | | | | | | | | | | | |
| | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc. (Note Issuer) | | Eliminations(a) | | Consolidated Balance |
| | (In millions) |
| Cash Flows from Operating Activities | | | | | | | | | |
| Net loss | $ | (2,449 | ) | | $ | (484 | ) | | $ | (6,351 | ) | | $ | 2,848 |
| | $ | (6,436 | ) |
| (Loss)/income from discontinued operations | — |
| | (115 | ) | | 10 |
| | — |
| | (105 | ) |
| Net loss from continuing operations | (2,449 | ) | | (369 | ) | | (6,361 | ) | | 2,848 |
| | (6,331 | ) |
| Adjustments to reconcile net loss to net cash (used)/provided by operating activities: | | | | | | | | | |
| Equity in earnings and distribution of unconsolidated affiliates | (5 | ) | | 54 |
| | — |
| | (12 | ) | | 37 |
|
| Depreciation and amortization | 751 |
| | 580 |
| | 20 |
| | — |
| | 1,351 |
|
| Provision for bad debts | 58 |
| | 3 |
| | 3 |
| | — |
| | 64 |
|
| Amortization of nuclear fuel | 45 |
| | — |
| | — |
| | — |
| | 45 |
|
| Amortization of financing costs and debt discount/premiums | — |
| | 21 |
| | 26 |
| | — |
| | 47 |
|
| Adjustment for debt extinguishment | — |
| | 9 |
| | (19 | ) | | — |
| | (10 | ) |
| Amortization of intangibles and out-of-market contracts | 52 |
| | 99 |
| | — |
| | — |
| | 151 |
|
| Amortization of unearned equity compensation | — |
| | (2 | ) | | 41 |
| | — |
| | 39 |
|
| Net loss on sale of assets and equity method investments | — |
| | — |
| | 14 |
| | — |
| | 14 |
|
| Gain on post retirement benefits curtailment | — |
| | (21 | ) | | — |
| | — |
| | (21 | ) |
| Impairment losses | 4,494 |
| | 391 |
| | 31 |
| | — |
| | 4,916 |
|
| Changes in derivative instruments | 264 |
| | (29 | ) | | — |
| | — |
| | 235 |
|
| Changes in deferred income taxes and liability for uncertain tax benefits | (1,092 | ) | | (237 | ) | | 2,655 |
| | — |
| | 1,326 |
|
| Changes in collateral deposits in support of energy risk management activities | (323 | ) | | (11 | ) | | — |
| | — |
| | (334 | ) |
| Proceeds from sale of emission allowances | (24 | ) | | — |
| | — |
| | — |
| | (24 | ) |
| Changes in nuclear decommissioning trust liability | (2 | ) | | — |
| | — |
| | — |
| | (2 | ) |
| Cash (used)/provided by changes in other working capital | (8,656 | ) | | (907 | ) | | 12,183 |
| | (2,836 | ) | | (216 | ) |
| Cash (used)/provided by continuing operations | (6,887 | ) | | (419 | ) | | 8,593 |
| | — |
| | 1,287 |
|
| Cash provided by discontinued operations | — |
| | 62 |
| | — |
| | — |
| | 62 |
|
| Net Cash (Used)/Provided by Operating Activities | (6,887 | ) | | (357 | ) | | 8,593 |
| | — |
| | 1,349 |
|
| Cash Flows from Investing Activities | | | | | | | | | |
|
| Dividends from NRG Yield, Inc. | — |
| | — |
| | 70 |
| | (70 | ) | | — |
|
| Intercompany dividends | — |
| | — |
| | 33 |
| | (33 | ) | | — |
|
| Acquisition of Drop Down Assets, net of cash acquired | — |
| | (698 | ) | | — |
| | 698 |
| | — |
|
| Acquisition of business, net of cash acquired | — |
| | (31 | ) | | — |
| | — |
| | (31 | ) |
| Capital expenditures | (316 | ) | | (654 | ) | | (59 | ) | | — |
| | (1,029 | ) |
| Net cash proceeds from notes receivable | — |
| | 18 |
| | — |
| | — |
| | 18 |
|
| Proceeds from renewable energy grants | — |
| | 82 |
| | — |
| | — |
| | 82 |
|
| Proceeds from emission allowances, net of purchases | 41 |
| | — |
| | — |
| | — |
| | 41 |
|
| Investments in nuclear decommissioning trust fund securities | (629 | ) | | — |
| | — |
| | — |
| | (629 | ) |
| Proceeds from sales of nuclear decommissioning trust fund securities | 631 |
| | — |
| | — |
| | — |
| | 631 |
|
| Proceeds from sale of assets, net | — |
| | 1 |
| | 26 |
| | — |
| | 27 |
|
| Investments in unconsolidated affiliates | 1 |
| | (357 | ) | | (39 | ) | | — |
| | (395 | ) |
| Other | — |
| | 16 |
| | — |
| | — |
| | 16 |
|
| Cash (used)/provided by continuing operations | (272 | ) | | (1,623 | ) | | 31 |
| | 595 |
| | (1,269 | ) |
| Cash used by discontinued operations | — |
| | (259 | ) | | — |
| | — |
| | (259 | ) |
| Net Cash (Used)/Provided by Investing Activities | (272 | ) | | (1,882 | ) | | 31 |
| | 595 |
| | (1,528 | ) |
| Cash Flows from Financing Activities | | | |
| | |
| | | | |
| Dividends from NRG Yield, Inc. | — |
| | (70 | ) | | — |
| | 70 |
| | — |
|
| Intercompany dividends | — |
| | (33 | ) | | — |
| | 33 |
| | — |
|
| Payments from/(for) intercompany loans | 7,183 |
| | 1,258 |
| | (8,441 | ) | | — |
| | — |
|
| Acquisition of Drop Down Assets, net of cash acquired | — |
| | — |
| | 698 |
| | (698 | ) | | — |
|
| Payment of dividends to common and preferred stockholders | — |
| | — |
| | (201 | ) | | — |
| | (201 | ) |
| Net receipts from settlement of acquired derivatives that include financing elements | — |
| | 14 |
| | — |
| | — |
| | 14 |
|
| Payment for treasury stock | — |
| | — |
| | (437 | ) | | — |
| | (437 | ) |
| Distributions from, net of contributions to, noncontrolling interest in subsidiaries | — |
| | 47 |
| | — |
| | — |
| | 47 |
|
| Proceeds from sale of noncontrolling interests in subsidiaries | — |
| | 600 |
| | — |
| | — |
| | 600 |
|
| Proceeds from issuance of common stock | — |
| | — |
| | 1 |
| | — |
| | 1 |
|
| Proceeds from issuance of long-term debt | — |
| | 953 |
| | 51 |
| | — |
| | 1,004 |
|
| Payment of debt issuance and hedging costs | — |
| | (21 | ) | | — |
| | — |
| | (21 | ) |
| Payments for short and long-term debt | — |
| | (1,116 | ) | | (246 | ) | | — |
| | (1,362 | ) |
| Other | — |
| | (22 | ) | | — |
| | — |
| | (22 | ) |
| Cash provided/(used) by continuing operations | 7,183 |
| | 1,610 |
| | (8,575 | ) | | (595 | ) | | (377 | ) |
| Cash used by discontinued operations | — |
| | (55 | ) | | — |
| | — |
| | (55 | ) |
| Net Cash Provided/(Used) by Financing Activities | 7,183 |
| | 1,555 |
| | (8,575 | ) | | (595 | ) | | (432 | ) |
| Effect of exchange rate changes on cash and cash equivalents | — |
| | 10 |
| | — |
| | — |
| | 10 |
|
| Change in cash from discontinued operations | — |
| | (252 | ) | | — |
| | — |
| | (252 | ) |
| Net Increase/(Decrease) in Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties | 24 |
| | (422 | ) | | 49 |
| | — |
| | (349 | ) |
| Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at Beginning of Period | 36 |
| | 991 |
| | 644 |
| | — |
| | 1,671 |
|
| Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at End of Period | $ | 60 |
| | $ | 569 |
| | $ | 693 |
| | $ | — |
| | $ | 1,322 |
|
(a) All significant intercompany transactions have been eliminated in consolidation.
SCHEDULE II.II — VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2017, 2016,2023, 2022 and 20152021 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period |
| Allowance for credit losses, deducted from accounts receivable and other non-current assets | | | | | | | | | |
| Year Ended December 31, 2023 | $ | 133 | | | $ | 251 | | | $ | 35 | | | $ | (274) | | (a) | $ | 145 | |
| Year Ended December 31, 2022 | 683 | | | 11 | | | — | | | (561) | | (a) | 133 | |
| Year Ended December 31, 2021 | 67 | | | 698 | | | 112 | | | (194) | | (a) | 683 | |
| Income tax valuation allowance, deducted from deferred tax assets | | | | | | | | | |
| Year Ended December 31, 2023 | $ | 224 | | | $ | 42 | | | $ | 9 | | | $ | — | | | $ | 275 | |
| Year Ended December 31, 2022 | 248 | | | (20) | | | (4) | | | — | | | 224 | |
| Year Ended December 31, 2021 | 266 | | | (29) | | | 11 | | | — | |
| 248 | |
(a) Represents principally net amounts charged as uncollectible
|
| | | | | | | | | | | | | | | | | | | |
| | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period |
| | (In millions) |
| Allowance for doubtful accounts, deducted from accounts receivable | | | | | | | | | |
| Year Ended December 31, 2017 | $ | 29 |
| | $ | 56 |
| | $ | — |
| | $ | (57 | ) | (a) | $ | 28 |
|
| Year Ended December 31, 2016 | 21 |
| | 47 |
| | — |
| | (39 | ) | (a) | 29 |
|
| Year Ended December 31, 2015 | 21 |
| | 62 |
| | — |
| | (62 | ) | (a) | 21 |
|
Income tax valuation allowance, deducted from deferred tax assets(b) | | | | | | | | | |
| Year Ended December 31, 2017 | $ | 4,116 |
| | $ | (151 | ) | | $ | (15 | ) | | $ | (2,087 | ) | (c) | $ | 1,863 |
|
| Year Ended December 31, 2016 | 3,575 |
| | 306 |
| | 235 |
| | — |
| | 4,116 |
|
| Year Ended December 31, 2015 | 265 |
| | 3,039 |
| | 271 |
| | — |
| | 3,575 |
|
EXHIBIT INDEX | | | | | | | | | | | | | | | | | |
(a)Number | | Represents principally net amounts charged as uncollectible.
| Description | |
(b) | Includes income tax valuation allowance deducted from deferred tax assets recorded as discontinued operations, which amounted to $2,087 million and $2,194 million as of December 31, 2016 and 2015, respectively. |
| |
(c) | Represents deconsolidation of GenOn due to its petition for bankruptcy on June 14, 2017. |
EXHIBIT INDEX
|
| | | | |
Number | | Description | | Method of Filing | |
| 2.1 | | | | | Incorporated herein by reference to Exhibit 99.1 to the Registrant's current report on Form 8-K filed on November 19, 2003. |
2.2 | | | | Incorporated herein by reference to Exhibit 99.2 to the Registrant's current report on Form 8-K filed on November 19, 2003. |
2.3 | | | | Incorporated herein by reference to Exhibit 2.1 to the Registrant's current report on Form 8-K filed on October 3, 2005. |
2.4 | | | | Incorporated herein by reference to Exhibit 99.2 to the Registrant's current report on Form 8-K filed on August 13, 2010. |
2.5 | | | | Incorporated herein by reference to Exhibit 2.1 to the Registrant's current report on Form 8-K filed on July 23, 2012. |
2.6 | | Plan Sponsor Agreement, dated October 18, 2013, by and among NRG Energy, Inc., NRG Energy Holdings, Inc., Edison Mission Energy, certain of Edison Mission Energy’s debtor subsidiaries, the Official Committee of Unsecured Creditors of Edison Mission Energy and its affiliated debtors, the PoJo Parties (as defined therein) and the proponent noteholders thereto. | | Incorporated herein by reference to Exhibit 2.1 to Amendment No. 1 to the Registrant’s current report on Form 8-K filed on October 21, 2013. |
2.7 | | | | Incorporated herein by reference to Exhibit 2.2 to Amendment No. 1 to the Registrant’s current report on Form 8-K filed on October 21, 2013. |
2.8 | | | | Incorporated herein by reference to Exhibit 2.1 to the Registrant's current report on Form 8-K filed on December 18, 2017. | |
2.9†2.2†^ | | | | Incorporated herein by reference to Exhibit 2.9 to the Registrant's annual report on Form 10-K filed on March 1, 2018. | | Filed herewith.
2.10^2.3^ | | | | Incorporated herein by reference to Exhibit 2.10 to the Registrant's annual report on Form 10-K filed on March 1, 2018. | |
| 2.4‡ | | | | Incorporated herein by reference to Exhibit 2.1 to the Registrant's quarterly report on Form 10-Q filed on May 6, 2021. | |
| 2.5^ | | | | Incorporated herein by reference to Exhibit 2.1 to the Registrant's Current Report on Form 8-K, filed on December 6, 2022. | |
| 2.6 | | | | Incorporated herein by reference to Exhibit 2.1 to the Registrant's current report on Form 8-K filed on June 1, 2023. | |
| 2.7 | | | | Filed herewith. | |
3.12.8 | | | | Filed herewith. | |
| 2.9 | | | | Filed herewith. | |
| 3.1 | | | | Incorporated herein by reference to Exhibit 3.1 to the Registrant's quarterly report on Form 10-Q filed on May 3, 2012. | |
| 3.2 | | | | Incorporated herein by reference to Exhibit 3.1 to the Registrant's current report on Form 8-K filed on December 14, 2012. | |
| 3.3 | | | | Incorporated herein by reference to Exhibit 3.2 to the Registrant's current report on Form 8-K filed on December 2, 2022. | |
| 3.4 | | | | Incorporated herein by reference to Exhibit 3.1 to the Registrant's current report on Form 8-K filed on February 13, 2017.March 10, 2023. | |
3.44.1 | | | | | Incorporated herein by reference to Exhibit 10.7 to the Registrant's current report on Form 8-K filed on August 10, 2006. |
3.5 | | | | Incorporated herein by reference to Exhibit 3.1 to the Registrant's quarterly report on Form 10-Q filed on May 1, 2008. |
3.6 | | | | Incorporated herein by reference to Exhibit 3.1 to the Registrant's quarterly report on Form 10-Q filed on October 30, 2008. |
3.7 | | | | Incorporated herein by reference to Exhibit 3.1 to the Registrant's current report on Form 8-K filed on December 30, 2014. |
4.1 | | | | Incorporated herein by reference to Exhibit 10.1 to the Registrant's current report on Form 8-K filed on January 4, 2006. |
|
| | | | |
4.2 | | Amended and Restated Common Agreement among XL Capital Assurance Inc., Goldman Sachs Mitsui Marine Derivative Products, L.P., Law Debenture Trust Company of New York, as Trustee, The Bank of New York, as Collateral Agent, NRG Peaker Finance Company LLC and each Project Company Party thereto, dated as of January 6, 2004, together with Annex A to the Common Agreement. | | Incorporated herein by reference to Exhibit 4.9 to the Registrant's annual report on Form 10-K filed on March 16, 2004. |
4.3 | | | | Incorporated herein by reference to Exhibit 4.10 to the Registrant's annual report on Form 10-K filed on March 16, 2004. |
4.4 | | | | Incorporated herein by reference to Exhibit 4.11 to the Registrant's annual report on Form 10-K filed on March 16, 2004. |
4.5 | | Indenture dated June 18, 2002, between NRG Peaker Finance Company LLC, as Issuer, Bayou Cove Peaking Power LLC, Big Cajun I Peaking Power LLC, NRG Rockford LLC, NRG Rockford II LLC and Sterlington Power LLC, as Guarantors, XL Capital Assurance Inc., as Insurer, and Law Debenture Trust Company, as Successor Trustee to the Bank of New York. | | Incorporated herein by reference to Exhibit 4.23 to the Registrant's annual report on Form 10-K filed on March 31, 2003. |
4.6 | | | | Incorporated herein by reference to Exhibit 4.3 to the Registrant's quarterly report on Form 10-Q filed on August 4, 2006. | |
4.74.2 | | | | | Incorporated herein by reference to Exhibit 4.1 to the Registrant's current reportCurrent Report on Form 8-K filed on February 6, 2006.May 30, 2019. | |
4.84.3 | | | Thirty-Sixth Supplemental Indenture, dated August 20, 2010,May 28, 2019, among NRG Energy, Inc., the guarantors named therein and Law DebentureDelaware Trust Company, as trustee, containing Form 3.750% Senior Secured First Lien Notes due 2024 and Form of New York as Trustee, re:4.440% Senior Secured First Lien Notes due 2029 | | Incorporated herein by reference to Exhibit 4.2 to the Registrant's Current Report on Form 8-K filed on May 30, 2019. | |
| 4.4 | | | | | Incorporated herein by reference to Exhibit 4.1 to the Registrant's current reportCurrent Report on Form 8-K, filed on August 20, 2010.December 4, 2020. | |
4.94.5 | | | | | Incorporated herein by reference to Exhibit 4.2 to the Registrant's Current Report on Form 8-K, filed on December 4, 2020. | |
| | | | | | | | | | | | | | | | | |
| 4.6 | | | | | Incorporated herein by reference to Exhibit 4.2 to the Registrant's current report on Form 8-K filed on August 20, 2010.March 10, 2023. | |
4.104.7 | | | | | Incorporated herein by reference to Exhibit 10.1 to the Registrant's current report on Form 8-K filed on August 20, 2010. |
4.11 | | | | Incorporated herein by reference to Exhibit 4.5 to the Registrant's current report on Form 8-K filed on December 16, 2010. |
4.12 | | | | Incorporated herein by reference to Exhibit 4.1 to the Registrant's current report on Form 8-K filed on January 28, 2011. |
4.13 | | | | Incorporated herein by reference to Exhibit 4.2 to the Registrant's current report on Form 8-K filed on January 28, 2011. |
4.14 | | | | Incorporated herein by reference to Exhibit 10.1 to the Registrant's current report on Form 8-K filed on January 28, 2011. |
4.15 | | | | Incorporated herein by reference to Exhibit 4.4 to the Registrant's current report on Form 8-K filed on May 25, 2011. |
4.16 | | | | Incorporated herein by reference to Exhibit 4.5 to the Registrant's current report on Form 8-K filed on May 25, 2011. |
4.17 | | | | Incorporated herein by reference to Exhibit 4.3 to the Registrant's current report on Form 8-K filed on May 25, 2011. |
|
| | | | |
4.18 | | | | Incorporated herein by reference to Exhibit 4.4 to the Registrant's current report on Form 8-K filed on May 25, 2011. |
4.19 | | Registration Rights Agreement, dated May 24, 2011, among NRG Energy, Inc., the guarantors named therein and Morgan Stanley & Co. Incorporated, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Barclays Capital Inc., Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, Deutsche Bank Securities Inc., Goldman, Sachs & Co., J.P. Morgan Securities LLC and RBS Securities Inc., as representatives of the initial purchasers. | | Incorporated herein by reference to Exhibit 4.5 to the Registrant's current report on Form 8-K filed on May 25, 2011. |
4.20 | | | | Incorporated herein by reference to Exhibit 4.3 to the Registrant's current report on Form 8-K filed on November 8, 2011. |
4.21 | | | | Incorporated herein by reference to Exhibit 4.4 to the Registrant's current report on Form 8-K filed on November 8, 2011. |
4.22 | | | | Incorporated herein by reference to Exhibit 4.6 to the Registrant's current report on Form 8-K filed on November 8, 2011. |
4.23 | | | | Incorporated herein by reference to Exhibit 4.3 to the Registrant's current report on Form 8-K filed on April 6, 2012. |
4.24 | | | | Incorporated herein by reference to Exhibit 4.4 to the Registrant's current report on Form 8-K filed on April 6, 2012. |
4.25 | | | | Incorporated herein by reference to Exhibit 4.6 to the Registrant's current report on Form 8-K filed on April 6, 2012. |
4.26 | | | | Incorporated herein by reference to Exhibit 4.3 to the Registrant's current report on Form 8-K filed on May 11, 2012. |
4.27 | | | | Incorporated herein by reference to Exhibit 4.4 to the Registrant's current report on Form 8-K filed on May 11, 2012. |
4.28 | | | | Incorporated herein by reference to Exhibit 4.6 to the Registrant's current report on Form 8-K filed on May 11, 2012. |
4.29 | | | | Incorporated herein by reference to Exhibit 4.1 to the Registrant's current report on Form 8-K filed on September 24, 2012. |
4.30 | | | | Incorporated herein by reference to Exhibit 4.2 to the Registrant's current report on Form 8-K filed on September 24, 2012. |
4.31 | | | | Incorporated herein by reference to Exhibit 4.2 to the Registrant's current report on Form 8-K filed on October 12, 2012. |
|
| | | | |
4.32 | | | | Incorporated herein by reference to Exhibit 4.3 to the Registrant's current report on Form 8-K filed on October 12, 2012. |
4.33 | | | | Incorporated herein by reference to Exhibit 4.5 to the Registrant's current report on Form 8-K filed on October 12, 2012. |
4.34 | | | | Incorporated herein by reference to Exhibit 4.6 to the Registrant's current report on Form 8-K filed on October 12, 2012. |
4.35 | | | | Incorporated herein by reference to Exhibit 4.1 to GenOn Energy, Inc.’s current report on Form 8-K filed on December 27, 2004. |
4.36 | | | | Incorporated herein by reference to Exhibit 4.1 to GenOn Energy Inc.'s current report on Form 8-K filed on June 15, 2007. |
4.37 | | | | Incorporated herein by reference to Exhibit 4.2 to GenOn Energy Inc.'s current report on Form 8-K filed June 15, 2007. |
4.38 | | | | Incorporated herein by reference to Exhibit 4.1 to Mirant Americas Generation, Inc.'s Registration Statement on Form S-4 filed on June 18, 2001. |
4.39 | | | | Incorporated herein by reference to Exhibit 4.4 to Mirant Americas Generation, Inc.'s Registration Statement on Form S-4 filed on June 18, 2001. |
4.40 | | | | Incorporated herein by reference to Exhibit 4.6 to Mirant Americas Generation, Inc.'s Registration Statement on Form S-4/A filed on May 7, 2002. |
4.41 | | | | Incorporated herein by reference to Exhibit 4.6 to Mirant Corporation's annual report on Form 10-K filed on February 27, 2009. |
4.42 | | | | Incorporated herein by reference to Exhibit 4.1 to Mirant Americas Generation, LLC's quarterly report on Form 10-Q filed on May 14, 2007. |
4.43 | | | | Incorporated by reference to Exhibit 4.4 to Mirant Corporation's quarterly report on Form 10-Q filed on November 5, 2010. |
4.44 | | | | Incorporated by reference to Exhibit 4.2 to GenOn Energy Inc.'s current report on Form 8-K filed on December 7, 2010. |
4.45 | | | | Incorporated herein by reference to Exhibit 4.2 to the Registrant’s current report on Form 8-K filed on January 9, 2013. |
4.46 | | | | Incorporated herein by reference to Exhibit 4.3 to the Registrant’s current report on Form 8-K filed on January 9, 2013. |
4.47 | | | | Incorporated herein by reference to Exhibit 4.5 to the Registrant’s current report on Form 8-K filed on January 9, 2013. |
4.48 | | | | Incorporated herein by reference to Exhibit 4.6 to the Registrant’s current report on Form 8-K filed on January 9, 2013. |
|
| | | | |
4.49 | | | | Incorporated herein by reference to Exhibit 4.2 to the Registrant’s current report on Form 8-K filed on March 13, 2013. |
4.50 | | | | Incorporated herein by reference to Exhibit 4.3 to the Registrant’s current report on Form 8-K filed on March 13, 2013. |
4.51 | | | | Incorporated herein by reference to Exhibit 4.5 to the Registrant’s current report on Form 8-K filed on March 13, 2013. |
4.52 | | | | Incorporated herein by reference to Exhibit 4.6 to the Registrant’s current report on Form 8-K filed on March 13, 2013. |
4.53 | | | | Incorporated herein by reference to Exhibit 4.7 to the Registrant’s current report on Form 8-K filed on March 13, 2013. |
4.54 | | | | Incorporated herein by reference to Exhibit 4.2 to the Registrant’s current report on Form 8-K filed on May 3, 2013. |
4.55 | | | | Incorporated herein by reference to Exhibit 4.3 to the Registrant’s current report on Form 8-K filed on May 3, 2013. |
4.56 | | | | Incorporated herein by reference to Exhibit 4.5 to the Registrant’s current report on Form 8-K filed on May 3, 2013. |
4.57 | | | | Incorporated herein by reference to Exhibit 4.6 to the Registrant’s current report on Form 8-K filed on May 3, 2013. |
4.58 | | | | Incorporated herein by reference to Exhibit 4.2 to the Registrant’s current report on Form 8-K filed on September 6, 2013. |
4.59 | | | | Incorporated herein by reference to Exhibit 4.3 to the Registrant’s current report on Form 8-K filed on September 6, 2013. |
4.60 | | | | Incorporated herein by reference to Exhibit 4.5 to the Registrant’s current report on Form 8-K filed on September 6, 2013. |
4.61 | | | | Incorporated herein by reference to Exhibit 4.6 to the Registrant’s current report on Form 8-K filed on September 6, 2013. |
4.62 | | | | Incorporated herein by reference to Exhibit 4.2 to the Registrant’s current report on Form 8-K filed on October 8, 2013. |
4.63 | | | | Incorporated herein by reference to Exhibit 4.3 to the Registrant’s current report on Form 8-K filed on October 8, 2013. |
4.64 | | | | Incorporated herein by reference to Exhibit 4.5 to the Registrant’s current report on Form 8-K filed on October 8, 2013. |
4.65 | | | | Incorporated herein by reference to Exhibit 4.6 to the Registrant’s current report on Form 8-K filed on October 8, 2013. |
|
| | | | |
4.66 | | One Hundred-Eighth Supplemental Indenture, dated as of November 13, 2013, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as trustee, re: NRG Energy, Inc.’s 8.5% Senior Notes due 2019, 8.25% Senior Notes due 2020, 7.625% Senior Notes due 2018, 7.625% Senior Notes due 2019, 7.875% Senior Notes due 2021 and 6.625% Senior Notes due 2023. | | Incorporated herein by reference to Exhibit 4.1 to the Registrant’s current report on Form 8-K filed on November 13, 2013. |
4.67 | | | | Incorporated herein by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed on January 27, 2014. |
4.68 | | | | Incorporated herein by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K filed on January 27, 2014. |
4.69 | | Registration Rights Agreement, dated January 27, 2014, among NRG Energy, Inc., the guarantors named therein and Barclays Capital Inc., Deutsche Bank Securities Inc., Goldman, Sachs & Co., Morgan Stanley & Co. LLC, Credit Agricole Securities (USA) Inc., Natixis Securities Americas LLC and RBC Capital Markets, LLC, as initial purchasers. | | Incorporated herein by reference to Exhibit 4.3 to the Company's Current Report on Form 8-K filed on January 27, 2014. |
4.70 | | One Hundred-Tenth Supplemental Indenture, dated as of March 24, 2014, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as trustee, re: NRG Energy, Inc.'s 8.5% Senior Notes due 2019, 8.25% Senior Notes due 2020, 7.625% Senior Notes due 2018, 7.625% Senior Notes due 2019, 7.875% Senior Notes due 2021, 6.625% Senior Notes due 2023 and 6.25% Senior Notes due 2022. | | Incorporated herein by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed on March 28, 2014. |
4.71 | | | | Incorporated herein by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed on April 21, 2014. |
4.72 | | | | Incorporated herein by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K filed on April 21, 2014. |
4.73 | | Registration Rights Agreement, dated April 21, 2014, among NRG Energy, Inc., the guarantors named therein and Citigroup Global Markets Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Credit Suisse Securities (USA), Inc., J.P. Morgan Securities LLC, Mitsubishi UFJ Securities (USA), Inc., SMBC Nikko Securities America, Inc. and RBS Securities Inc. | | Incorporated herein by reference to Exhibit 4.3 to the Company's Current Report on Form 8-K filed on April 21, 2014. |
4.74 | | One Hundred-Eleventh Supplemental Indenture, dated as of April 28, 2014, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as trustee, re: NRG Energy, Inc.'s 8.5% Senior Notes due 2019, 8.25% Senior Notes due 2020, 7.625% Senior Notes due 2018, 7.625% Senior Notes due 2019, 7.875% Senior Notes due 2021, 6.625% Senior Notes due 2023 and 6.25% Senior Notes due 2022. | | Incorporated herein by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed on May 2, 2014. |
4.75 | | | | Incorporated herein by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K filed on May 2, 2014. |
4.76 | | | | Incorporated herein by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed on October 3, 2014. |
4.77 | | | | Incorporated herein by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K filed on October 3, 2014. |
4.78 | | One Hundred-Thirteenth Supplemental Indenture, dated as of November 12, 2014, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as trustee, re: NRG Energy, Inc.'s 8.25% Senior Notes due 2020, 7.625% Senior Notes due 2018, 7.875% Senior Notes due 2021, 6.625% Senior Notes due 2023 and 6.25% Senior Notes due 2022. | | Incorporated herein by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed on November 14, 2014.
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4.79 | | | | Incorporated herein by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K filed on November 14, 2014. |
|
| | | | |
4.80 | | One Hundred-Fourteenth Supplemental Indenture, dated as of November 24, 2014, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York, as trustee, re: NRG Energy, Inc.'s 8.25% Senior Notes due 2020, 7.625% Senior Notes due 2018, 7.875% Senior Notes due 2021, 6.625% Senior Notes due 2023 and 6.25% Senior Notes due 2022. | | Incorporated herein by reference to Exhibit 4.1 to the Registrant's current report on Form 8-K filed on November 25, 2014.
|
4.81 | |
| | Incorporated herein by reference to Exhibit 4.2 to the Registrant's current report on Form 8-K filed on November 25, 2014.
|
4.82 | | | | Incorporated herein by reference to Exhibit 4.1 to the Company's current report on Form 8-K filed on April 9, 2015. |
4.83 | | | | Incorporated herein by reference to Exhibit 4.2 to the Company's current report on Form 8-K filed on April 9, 2015. |
4.84 | | | | Incorporated herein by reference to Exhibit 4.1 to the Company's current report on Form 8-K filed on April 30, 2015. |
4.85 | | | | Incorporated herein by reference to Exhibit 4.2 to the Company's current report on Form 8-K filed on April 30, 2015. |
4.86 | | | | Incorporated herein by reference to Exhibit 4.1 to the Company's current report on Form 8-K filed on May 22, 2015. |
4.87 | | | | Incorporated herein by reference to Exhibit 4.2 to the Company's current report on Form 8-K filed on May 22, 2015. |
4.88 | | | | Incorporated herein by reference to Exhibit 4.1 to the Company's current report on Form 8-K filed on November 2, 2015. |
4.89 | | | | Incorporated herein by reference to Exhibit 4.2 to the Company's current report on Form 8-K filed on November 2, 2015. |
4.90 | |
| | Incorporated herein by reference to Exhibit 4.1 to the Registrant's Current Report on Form 8-K filed on May 23, 2016. | |
4.914.8 | | | | Incorporated herein by reference to Exhibit 4.2 to the Registrant's Current Report on Form 8-K, filed on May 23, 2016. |
4.92 | |
| | Incorporated herein by reference to Exhibit 4.3 to the Registrant's Current Report on Form 8-K, filed on May 23, 2016. |
4.93 | |
| | Incorporated herein by reference to Exhibit 4.4 to the Registrant's Current Report on Form 8-K, filed on May 23, 2016.
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4.94 | | | | Incorporated herein by reference to Exhibit 4.1 to the Registrant's Current Report on Form 8-K, filed on July 25, 2016. |
4.95 | | | | Incorporated herein by reference to Exhibit 4.2 to the Registrant's Current Report on Form 8-K, filed on July 25, 2016. |
4.96 | | | | Incorporated herein by reference to Exhibit 4.3 to the Registrant's Current Report on Form 8-K, filed on July 25, 2016. |
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| | | | |
4.97 | | | | Incorporated herein by reference to Exhibit 4.2 to the Registrant's Current Report on Form 8-K, filed on August 3, 2016. | |
4.984.9 | |
| | Incorporated herein by reference to Exhibit 4.3 to the Registrant's Current Report on Form 8-K, filed on August 3, 2016. |
4.99 | | | | Incorporated herein by reference to Exhibit 4.4 to the Registrant's Current Report on Form 8-K, filed on August 3, 2016.
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4.100 | | | | Incorporated herein by reference to Exhibit 4.2 to the Registrant's Current Report on Form 8-K, filed on December 8, 2017. | |
4.1014.10 | | | | | Incorporated herein by reference to Exhibit 4.34.2 to the Registrant's Current Report on Form 8-K filed on May 16, 2019. | |
| 4.11 | | | | | Incorporated herein by reference to Exhibit 4.5 to the Registrant's Current Report on Form 8-K, filed on December 8, 2017.4, 2020. | |
4.1024.12 | | | Registration Rights Agreement,Supplemental Indenture, dated December 7, 2017,2, 2020, among NRG Energy, Inc., the guarantors named therein and Citigroup Global Markets, Inc.,Deutsche Bank Trust Company Americas, as representative to the initial purchasers listed in Schedule I thereto.trustee, containing Form of 3.375% Senior Notes due 2029 and Form of 3.625% Senior Notes due 2031. | | Incorporated herein by reference to Exhibit 4.44.6 to the Registrant's Current Report on Form 8-K, filed on December 8, 2017.
4, 2020. | |
10.14.13 | | | Note Agreement,Second Supplemental Indenture, dated August 20, 1993, between23, 2021, among NRG Energy, Inc., Energy Center, Inc.the guarantors named therein and eachDeutsche Bank Trust Company Americas, as trustee, containing Form of the purchasers named therein.3.875% Senior Notes due 2032. | | Incorporated herein by reference to Exhibit 10.54.2 to the Registrant's Registration StatementCurrent Report on Form S-1, as amended, Registration No. 333-33397.8-K, filed on August 23, 2021. | |
10.24.14 | | | Master Shelf and Revolving Credit Agreement,Indenture, dated August 20, 1993, betweenMay 24, 2018, among NRG Energy, Inc., Energy Center, Inc., The Prudential Insurance Registrantsthe guarantors named therein and Delaware Trust Company, as trustee, containing Form of America and each Prudential Affiliate, which becomes party thereto.2.750% Convertible Senior Notes due 2048.
| | Incorporated herein by reference to Exhibit 10.44.1 to the Registrant's Registration StatementCurrent Report on Form S-1, as amended, Registration No. 333-33397.8-K, filed on May 25, 2018. | |
10.3*4.15 | | | | | Incorporated herein by reference to Exhibit 10.144.1 to the Registrant's quarterly report on Form 10-Q filed on May 6, 2021. | |
| 4.16 | | | | | Incorporated herein by reference to Exhibit 4.53 to the Registrant's annual report on Form 10-K filed on March 30, 2005.February 24, 2022. | |
10.4*4.17 | | | | | Incorporated herein by reference to Exhibit 4.52 to the Registrant's annual report on Form 10-K filed on February 24, 2022. | |
| 4.18 | | | | | Incorporated herein by reference to Exhibit 4.4 to the Registrant's current report on Form 8-K filed on August 29, 2023. | |
| 4.19 | | | | | Incorporated herein by reference to Exhibit 4.5 to the Registrant's current report on Form 8-K filed on August 29, 2023. | |
| 4.20 | | | | | Incorporated herein by reference to Exhibit 10.1 to Vivint Smart Home, Inc.'s Current Report on Form 8-K filed on February 19, 2020). | |
| 4.21 | | | Indenture, dated as of July 9, 2021, between APX Group, Inc., as the Issuer, the guarantors party hereto, and Wilmington Trust, National Association, as trustee, payment agent and registrar, relating to the Company's 5.75% Senior Notes due 2029. | | Incorporated herein by reference to Exhibit 10.1 to Vivint Smart Home, Inc.'s Current Report on Form 8-K filed on July 12, 2021. | |
| | | | | | | | | | | | | | | | | |
| 4.22 | | | | | Incorporated herein by reference to Exhibit 4.15 to the Registrant's Annual Report on Form 10-K, filed on February 27, 2020. | |
| 10.1* | | | | Incorporated herein by reference to Exhibit 10.15 to the Registrant's annual report on Form 10-K filed on March 30, 2005. | |
10.5*10.2* | | | | Incorporated herein by reference to Exhibit 10.1 to the Registrant's quarterly report on Form 10-Q filed on November 9, 2004. |
10.6* | | | | Incorporated herein by reference to Exhibit 10.6 to the Registrant's annual report on Form 10-K filed on March 1, 2018. | | Filed herewith.
10.7*10.3* | |
| | Filed herewith |
10.8* | | | | Incorporated herein by reference to Exhibit 10.7 to the Registrant's annual report on Form 10-K filed on February 23, 2010.March 1, 2018. | |
10.9*10.4* | | | | Incorporated herein by reference to Exhibit 10.1 to the Registrant's current report on Form 8-K filed on May 7, 2015. | |
10.1010.5* | | | | Incorporated herein by reference to Exhibit 10.28 to the Registrant's annual report on Form 10-K filed on March 30, 2005. |
10.11 | | | | Incorporated herein by reference to Exhibit 10.1 to the Registrant's current report on Form 8-K filed on December 28, 2005. |
10.12 | | | | Incorporated herein by reference to Exhibit 10.2 to the Registrant's current report on Form 8-K filed on December 28, 2005. |
10.13 | | | | Incorporated herein by reference to Exhibit 10.1 to the Registrant's current report on Form 8-K filed on August 11, 2005. |
10.14 | | | | Incorporated herein by reference to Exhibit 10.13 to the Registrant's annual report on Form 10-K filed on February 12, 2009. |
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| | | | |
10.15 | | | | Incorporated herein by reference to Exhibit 10.1 to the Registrant's current report on Form 8-K filed on February 8, 2006. |
10.16† | | | | Incorporated herein by reference to Exhibit 10.32 to the Registrant's annual report on Form 10-K filed on March 7, 2006. |
10.17* | | | | Incorporated herein by reference to Exhibit 10.16 to the Registrant's annual report on Form 10-K filed on February 12, 2009. |
10.18* | | | | Incorporated herein by reference to Exhibit 10.1 to the Registrant's current report on Form 8-K filed on December 10, 2014. |
10.19* | | | | Incorporated herein by reference to Exhibit 10.2 to the Registrant's current report on Form 8-K/A filed on January 8, 2016. |
10.20 | | | | Incorporated herein by reference to Exhibit 10.1 to the Registrant's current report on Form 8-K filed on August 10, 2006. |
10.21 | | | | Incorporated herein by reference to Exhibit 10.3 to the Registrant's current report on Form 8-K filed on August 10, 2006. |
10.22 | | | | Incorporated herein by reference to Exhibit 10.5 to the Registrant's quarterly report on Form 10-Q filed on May 1, 2008. |
10.23 | | | | Incorporated herein by reference to Exhibit 10.23 to the Registrant's annual report on Form 10-K filed on February 12, 2009. |
10.24 | | | | Incorporated herein by reference to Exhibit 10.26 to the Registrant's annual report on Form 10-K filed on February 12, 2009. |
10.25 | | | | Incorporated herein by reference to Exhibit 10.24 to the Registrant's annual report on Form 10-K filed on February 12, 2009. |
10.26 | | | | Incorporated herein by reference to Exhibit 10.27 to the Registrant's annual report on Form 10-K filed on February 12, 2009. |
10.27 | | | | Incorporated herein by reference to Exhibit 10.5 to the Registrant's current report on Form 8-K filed on August 10, 2006. |
10.28 | | | | Incorporated herein by reference to Exhibit 10.6 to the Registrant's quarterly report on Form 10-Q filed on May 1, 2008. |
10.29 | | | | Incorporated herein by reference to Exhibit 10.31 to the Registrant's annual report on Form 10-K filed on February 12, 2009. |
10.30 | | | | Incorporated herein by reference to Exhibit 10.34 to the Registrant's annual report on Form 10-K filed on February 12, 2009. |
10.31 | | | | Incorporated herein by reference to Exhibit 10.32 to the Registrant's annual report on Form 10-K filed on February 12, 2009. |
10.32 | | | | Incorporated herein by reference to Exhibit 10.35 to the Registrant's annual report on Form 10-K filed on February 12, 2009. |
10.33† | | | | Incorporated herein by reference to Exhibit 10.1 to the Registrant's quarterly report on Form 10-Q filed on May 1, 2008. |
|
| | | | |
10.34† | | | | Incorporated herein by reference to Exhibit 10.2 to the Registrant's quarterly report on Form 10-Q filed on May 1, 2008. |
10.35† | | | | Incorporated herein by reference to Exhibit 10.3 to the Registrant's quarterly report on Form 10-Q filed on May 1, 2008. |
10.36† | | | | Incorporated herein by reference to Exhibit 10.4 to the Registrant's quarterly report on Form 10-Q filed on May 1, 2008. |
10.37† | | | | Incorporated herein by reference to Exhibit 10.1 to the Registrant's quarterly report on Form 10-Q filed on April 30, 2009. |
10.38 | | Project Agreement, Settlement Agreement and Mutual Release, dated March 1, 2010, by and among by and among Nuclear Innovation North America LLC, the City of San Antonio acting by and through the City Public Service Board of San Antonio, a Texas municipal utility, NINA Texas 3 LLC and NINA Texas 4 LLC, and solely for purposes of certain sections of the Settlement Agreement, by NRG Energy, Inc and NRG South Texas LP. | | Incorporated herein by reference to Exhibit 10.1 to the Registrant's current report on Form 8-K filed on March 2, 2010. |
10.39† | | | | Incorporated herein by reference to Exhibit 10.2 to the Registrant's current report on Form 8-K filed on March 2, 2010. |
10.40* | | | | Filed herewith. |
10.41† | | | | Incorporated herein by reference to Exhibit 10.3 to the Registrant's quarterly report on Form 10-Q filed on August 2, 2010. |
10.42† | | | | Incorporated herein by reference to Exhibit 10.4 to the Registrant's quarterly report on Form 10-Q filed on August 2, 2010. |
10.43(a) | | | | Incorporated herein by reference to Exhibit 10.2(a) the Registrant's current report on Form 8-K filed on July 1, 2010. |
10.43(b) | | | | Incorporated herein by reference to Exhibit 10.2(b) to the Registrant's current report on Form 8-K filed on July 1, 2010. |
10.44* | | | | Incorporated herein by reference to Exhibit 10.1 to the Registrant's current report on Form 8-K filed on April 28, 2017. | |
10.4510.6* | | Amended and Restated Credit Agreement, dated July 1, 2011, by and among NRG Energy, Inc., the lenders party thereto, the joint lead bookrunners and joint lead arrangers party thereto, Citicorp North America, Inc., Morgan Stanley Senior Funding, Inc. and the documentation agents party thereto. | | Incorporated herein by reference to Exhibit 10.1 to the Registrant's current report on Form 8-K filed on July 5, 2011. |
10.46* | | | | Incorporated herein by reference to Exhibit 10.1 to the Registrant's current report on Form 8-K/A filed on September 12, 2011. |
10.47 | | Registration Rights Agreement, dated September 24, 2012, among NRG Energy, Inc., the guarantors named therein and Deutsche Bank Securities Inc., Merrill, Lynch, Pierce, Fenner & Smith Incorporated, Barclays Capital Inc., Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, Goldman, Sachs & Co., J.P. Morgan Securities LLC, Morgan Stanley & Co. LLC and RBS Securities Inc., as initial purchasers. | | Incorporated herein by reference to Exhibit 10.1 to the Registrant's current report on Form 8-K filed on September 24, 2012. |
10.48* | | | | Incorporated herein by reference to Exhibit 10.49 to the Registrant’s annual report on Form 10-K filed on February 27, 2013. | |
10.4910.7* | | Revolving Credit Agreement among GenOn Energy, Inc., as Borrower, GenOn Americas, Inc., as Borrower, the several lenders from time to time parties thereto, and NRG Energy, Inc., as Administrative Agent, dated as of December 14, 2012. | | Incorporated herein by reference to Exhibit 10.50 to the Registrant’s annual report on Form 10-K filed on February 27, 2013. |
10.50 | | | | Incorporated herein by reference to Exhibit 10.1 to the Registrant’s quarterly report on Form 10-Q filed on May 7, 2013. |
|
| | | | |
10.51 | | | | Incorporated herein by reference to Exhibit 10.1 to the Registrant’s current report on Form 8-K filed on June 10, 2013. |
10.52* | | | | Incorporated herein by reference to Exhibit 10.53 to the Registrant's annual report on Form 10-K filed on February 28, 2014. |
10.53* | | | | Incorporated herein by reference to Exhibit 10.54 to the Registrant's annual report on Form 10-K filed on February 28, 2014. |
10.54* | | | | Incorporated herein by reference to Exhibit 10.2 to the Registrant's current report on Form 8-K filed on April 28, 2017. |
10.55 | | | | Incorporated herein by reference to Exhibit 10.1 to the Registrant's current report on Form 8-K filed on December 30, 2014. |
10.56 | | | | Incorporated herein by reference to Exhibit 10.1 to the Registrant's current report on Form 8-K filed on December 24, 2015. |
10.57 | | | | Incorporated herein by reference to Exhibit 10.1 to the Registrant's quarterly report on Form 10-Q filed on August 9, 2016.
|
10.58 | | Second Amended and Restated Credit Agreement, dated as of June 30, 2016, by and among NRG Energy, Inc., the lenders party thereto, the joint lead arrangers and joint lead bookrunners party thereto, Citicorp North America, Inc., Commerzbank AG, New York Branch, Keybank Capital Markets Inc. and CIT Bank, N.A. | | Incorporated herein by reference to Exhibit 10.2 to the Registrant's quarterly report on Form 10-Q filed on August 9, 2016.
|
10.59 | | | | Incorporated herein by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on January 24, 2017. |
10.60 | | | | Incorporated herein by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on February 13, 2017. |
10.61 | | | | Incorporated herein by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed on February 13, 2017. |
10.62 | |
| | Incorporated herein by reference to Exhibit 10.1 to GenOn Energy, Inc. and GenOn Americas Generation, LLC's Current Report on Form 8-K filed on May 23, 2017.
|
10.63(a) | |
| | Incorporated herein by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on June 14, 2017.
|
10.63(b) | | First Amendment, dated as of October 2, 2017, to the Restructuring Support and Lock-Up Agreement, dated as of June 12, 2017, by and among GenOn Energy, Inc., GenOn Americas Generation, LLC, NRG Energy, Inc. and the consenting noteholders party thereto.
| | Incorporated herein by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed on October 6, 2017.
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10.64(a) | |
| | Incorporated herein by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed on June 14, 2017.
|
10.64(b) | |
| | Incorporated herein by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on October 6, 2017.
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10.65 | |
| | Incorporated herein by reference to Exhibit 10.3 to the Registrant's Current Report on Form 8-K filed on June 14, 2017.
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10.66 | |
| | Incorporated herein by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on October 31, 2017.
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10.67 | | | | Incorporated herein by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on December 18, 2017. |
10.68 | | | | Incorporated herein by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed on December 18, 2017. |
10.69 | | | | Incorporated herein by reference to Exhibit 10.3 to the Registrant's Current Report on Form 8-K filed on December 18, 2017.
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10.70 | | | | Incorporated herein by reference to Exhibit 10.4 to the Registrant's Current Report on Form 8-K filed on December 18, 2017. |
10.71 | | | | Incorporated herein by reference to Exhibit 10.5 to the Registrant's Current Report on Form 8-K filed on December 18, 2017. |
10.72 | | | | Incorporated herein by reference to Exhibit 10.5 to the Registrant's Current Report on Form 8-K filed on December 18, 2017. |
10.73* | | | | Incorporated herein by reference to Exhibit 10.73 to the Registrant's annual report on Form 10-K filed on March 1, 2018. | | Filed herewith.
10.74*10.8* | | | | Incorporated herein by reference to Exhibit 10.74 to the Registrant's annual report on Form 10-K filed on March 1, 2018. | | Filed herewith.
10.75†10.9† | | Consent and Indemnity Agreement, dated as of February 6, 2018, by and among NRG Energy, Inc., NRG Repowering Holdings LLC, NRG Yield, Inc., and GIP III Zephyr Acquisition Partners, L.P., and NRG Yield Operating LLC (solely with respect to Sections E.5, E.6 and G.12).
| | Incorporated herein by reference to Exhibit 10.34 to NRG Yield, Inc.'s Annual Report on Form 10-K filed on March 1, 2018. | |
12.110.10* | |
| | Filed herewith | |
| 10.11 | | | Sixth Amendment to Second Amended and Restated Credit Agreement, dated as of RatioFebruary 14, 2023, by and among NRG Energy, Inc., its subsidiaries party thereto, the lenders and issuing banks party thereto, Citicorp North America, Inc., as administrative agent and collateral agent, and Deutsche Bank Trust Company Americas, as collateral trustee, and included as Exhibit A-2 thereto a clean conformed copy of Earningsthe Second Amended and Restated Credit Agreement
| | Incorporated herein by reference to Fixed Charges.Exhibit 10.1 to the Registrant's current report on Form 8-K filed on February 15, 2023. | |
| 10.12 | | | Seventh Amendment to Second Amended and Restated Credit Agreement, dated as of March 13, 2023, by and among NRG Energy, Inc., its subsidiaries party thereto, the lenders and issuing banks party thereto, Citicorp North America, Inc., as administrative agent and collateral agent, and Deutsche Bank Trust Company Americas, as collateral trustee.
| | Incorporated herein by reference to Exhibit 4.2 to the Registrant's quarterly report on Form 10-Q filed on May 4, 2023. | | Filed herewith.
12.210.13 | | | Second Amended and Restated Credit Agreement, dated as of July 9, 2021, among APX Group Holdings, Inc., as Holdings, APX Group, Inc., as the borrower, the guarantors party hereto from time to time, Bank of America, N.A., as administrative agent, swing line lender and an L/C issuer. | | Incorporated herein by reference to Exhibit 10.2 to Vivint Smart Home, Inc.'s Current Report on Form 8-K filed on July 12, 2021. | |
| 10.14 | | | | | Incorporated herein by reference to Exhibit 4.1 to the Registrant's quarterly report on Form 10-Q filed on August 8, 2023. | |
| | | | | | | | | | | | | | | | | |
| 10.15 | | | | | Incorporated herein by reference to Exhibit 4.1 to the Registrant's current report on Form 8-K filed on August 29, 2023. | |
| 10.16 | | |
| | Incorporated herein by reference to Exhibit 4.2 to the Registrant's current report on Form 8-K filed on August 29, 2023. | |
| 10.17 | | |
| | Incorporated herein by reference to Exhibit 4.3 to the Registrant's current report on Form 8-K filed on August 29, 2023. | |
| 10.18 | | | | | Incorporated herein by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on September 22, 2020. | |
| 10.19 | | | Amendment No. 3 to Receivables Loan and Servicing Agreement, dated as of EarningsJune 22, 2023, among NRG Retail LLC, as Servicer, NRG Receivables LLC, as Borrower, NRG Energy, Inc., as Performance Guarantor, the Conduit Lenders, Committed Lenders, Facility Agents and LC Issuers party thereto, and Royal Bank of Canada, as administrative Agent, and included as Exhibit A-2 thereto a clean, conformed copy of the Receivables Loan and Servicing Agreement. | | Incorporated herein by reference to Fixed ChargesExhibit 10.1 to the Registrant's current report on Form 8-K filed on June 27, 2023. | |
| 10.20* | | | | Incorporated herein by reference to Exhibit 10.21 to the Registrant's annual report on Form 10-K filed on February 24, 2022. | |
| 10.21* | | | | Incorporated herein by reference to Exhibit 10.22 to the Registrant's annual report on Form 10-K filed on February 24, 2022. | |
| 10.22* | | | | Incorporated herein by reference to Exhibit 10.23 to the Registrant's annual report on Form 10-K filed on February 24, 2022. | |
| 10.23* | | | | Filed herewith | |
| 10.24* | | | | Filed herewith | |
| 10.25* | | | | Filed herewith | |
| 10.26* | | | | Incorporated herein by reference to Exhibit 4.4 to Vivint Smart Home's Post-Effective Amendment on Form S-8 to Registration Statement on Form S-4 filed with the Securities and Exchange Commission on March 24, 2020 | |
| 10.27* | | | | Incorporated herein by reference to Exhibit 10.2 to the Registrant's quarterly report on Form 10-Q filed on May 4, 2023. | | Filed herewith.
21.110.28* | | | | Incorporated herein by reference to Exhibit 10.3 to the Registrant's quarterly report on Form 10-Q filed on May 4, 2023. | |
| 10.29* | | | | Filed herewith | |
| 10.30* | | | | Filed herewith | |
| | | | | | | | | | | | | | | | | |
| 10.31* | | | | Incorporated herein by reference to Exhibit 10.1 to the Registrant's current report on Form 8-K filed on May 2, 2023. | |
| 10.32* | | | | Incorporated herein by reference to Exhibit 10.45 to Vivint Smart Home, Inc.'s Annual Report on Form 10-K for the annual period ended December 31, 2022. | |
| 10.33* | | | | Incorporated by reference to Exhibit 10.5 to Vivint Smart Home, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 2022 | |
| 10.34* | | | | Incorporated herein by reference to Exhibit 10.1 to the Registrant's quarterly report on Form 10-Q filed on August 8, 2023. | |
| 10.35 | | | | Incorporated herein by reference to Exhibit 10.1 to the Registrant’s current report on Form 8-K filed on November 20, 2023 | |
| 21.1 | | | | | Filed herewith. | |
23.122.1 | | | | Filed herewith. | |
| 23.1 | | | | Filed herewith. | |
31.124.1 | | Power of Attorney | | Included on signature page | |
| 31.1 | | | | Filed herewith. | |
| 31.2 | | | | Filed herewith. | |
| 31.3 | | | | Filed herewith. | |
| 32 | | | | Furnished herewith. | |
| 97 | | | | Filed herewith. | |
| 101 INS | | Inline XBRL Instance Document. | | The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document. | | Filed herewith.
| 101 SCH | | Inline XBRL Taxonomy Extension Schema. | | Filed herewith. | |
| 101 CAL | | Inline XBRL Taxonomy Extension Calculation Linkbase. | | Filed herewith. | |
| 101 DEF | | Inline XBRL Taxonomy Extension Definition Linkbase. | | Filed herewith. | |
| 101 LAB | | Inline XBRL Taxonomy Extension Label Linkbase. | | Filed herewith. | |
| 101 PRE | | Inline XBRL Taxonomy Extension Presentation Linkbase. | | Filed herewith. | |
| 104 | | Cover Page Interactive Data File (the cover page interactive data file does not appear in Exhibit 104 because it's Inline XBRL tags are embedded within the Inline XBRL document). | | Filed herewith. | |
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| * | | |
* | | Exhibit relates to compensation arrangements. |
†
| | Portions of this exhibit have been redacted and are subject to a confidential treatment request filed with the Secretary of the Securities and Exchange Commission pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended. |
| ^ | | This filing excludes schedules pursuant to Item 601(b)(2) of Regulation S-K, which the registrant agrees to furnish supplementary to the Securities and Exchange Commission upon request by the Commission.
|
| ‡ | | Portions of this exhibit have been excluded because they are both not material and would likely cause competitive harm to the registrant if publicly disclosed. Information that has been omitted has been noted in this document with a placeholder identified by the mark “[***]”. |
Item 16. Form 10-K Summary
None.
None.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
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| NRG ENERGY, INC. (Registrant) | |
| | | |
| By: | /s/ MAURICIO GUTIERREZLAWRENCE S. COBEN | |
| | |
| | Mauricio GutierrezLawrence S. Coben
Interim President and Chief Executive Officer | |
Date: March 1, 2018February 28, 2024
POWER OF ATTORNEY
Each person whose signature appears below constitutes and appoints David R. Hill and Brian E. Curci and Christine A. Zoino, each or any of them, such person's true and lawful attorney-in-fact and agent with full power of substitution and resubstitution for such person and in such person's name, place and stead, in any and all capacities, to sign any and all amendments to this report on Form 10-K, and to file the same with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing necessary or desirable to be done in and about the premises, as fully to all intents and purposes as such person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them or his or their substitute or substitutes, may lawfully do or cause to be done by virtue hereof.
In accordance with the Exchange Act, this report has been signed by the following persons on behalf of the registrant in the capacities indicated on March 1, 2018.
| | | | | | | | | | | | | | |
| Signature | | Title | | Date |
| | | | |
Signature | | Title | | Date |
/s/ MAURICIO GUTIERREZ LAWRENCE S. COBEN | | Interim President and Chief Executive Officer and | | March 1, 2018February 28, 2024 |
Mauricio GutierrezLawrence S. Coben | | Director (Principal Executive Officer)Officer, Chair of the Board) | |
/s/ KIRKLAND B. ANDREWS WOO-SUNG CHUNG | | Chief Financial Officer | | March 1, 2018February 28, 2024 |
Kirkland B. AndrewsWoo-Sung Chung | | (Principal Financial Officer) | |
/s/ DAVID CALLENG. ALFRED SPENCER | | Chief Accounting Officer | | March 1, 2018February 28, 2024 |
David CallenG. Alfred Spencer | | (Principal (Principal Accounting Officer) | |
| /s/ LAWRENCE S. COBEN | | Chairman of the Board | | March 1, 2018
| Lawrence S. Coben | | | |
| /s/ E. SPENCER ABRAHAM | | Director | | Director | March 1, 2018February 28, 2024 |
| E. Spencer Abraham | | |
| /s/ ANTONIO CARRILLO | | Director | | February 28, 2024 |
| Antonio Carrillo | | |
/s/ KIRBYJON H. CALDWELLMATTHEW CARTER, JR. | | Director | | Director | March 1, 2018February 28, 2024 |
Kirbyjon H. CaldwellMatthew Carter, Jr. | | |
| /s/ HEATHER COX | | Director | | February 28, 2024 |
| Heather Cox | | |
/s/ TERRY G. DALLASELISABETH B. DONOHUE | | Director | | Director | March 1, 2018February 28, 2024 |
Terry G. DallasElisabeth B. Donohue | | |
| /s/ MARWAN FAWAZ | | Director | | February 28, 2024 |
/s/ WILLIAM E. HANTKE Marwan Fawaz | | | Director | March 1, 2018 |
William E. Hantke | | |
| /s/ PAUL W. HOBBY | | Director | | Director | March 1, 2018February 28, 2024 |
| Paul W. Hobby | | |
| /s/ ALEX POURBAIX | | Director | | February 28, 2024 |
| Alex Pourbaix | | |
| /s/ ALEXANDRA PRUNER | | Director | | February 28, 2024 |
| Alexandra Pruner | | |
| | | | |
| | |
| /s/ ANNE C. SCHAUMBURG | | Director | | Director | March 1, 2018February 28, 2024 |
| Anne C. Schaumburg | | |
| /s/ MARCIE C. ZLOTNIK | | Director | | February 28, 2024 |
/s/ EVAN J. SILVERSTEINMarcie C. Zlotnik | | | Director | March 1, 2018 |
Evan J. Silverstein | | |
/s/ BARRY T. SMITHERMAN | | Director | | March 1, 2018 |
Barry T. Smitherman | | |
/s/ THOMAS H. WEIDEMEYER | | Director | | March 1, 2018 |
Thomas H. Weidemeyer | | |
/s/ C. JOHN WILDER | | Director | | March 1, 2018 |
C. John Wilder | | |
/s/ WALTER R. YOUNG | | Director | | March 1, 2018 |
Walter R. Young | | |
