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Item 9A. Controls and Procedures

2022-02-24 compared with 2021-03-01 · 865 added, 1107 removed, 2287 unchanged (46% of the section changed)

5 unchanged sentences

Changes in Internal Control over Financial Reporting

There were no changes in NRG’s internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred in the fourth quarter of 2020 that materially affected, or are reasonably likely to materially affect, NRG’s internal control over financial reporting.

During the year ended December 31, 2021, the Company completed its acquisition of Direct Energy.

In the first quarter of 2022, the Company integrated a significant component of Direct Energy's accounting systems into NRG's legacy ERP system.

As part of this integration, the Company has completed the evaluation of our internal controls related to Direct Energy, and designed and implemented a control structure over Direct Energy's operations.

Other than the Direct Energy 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 2021 that materially affected, or are reasonably likely to materially affect, NRG’s internal control over financial reporting.

Inherent Limitations over Internal Controls

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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, 2021.

On January 5, 2021, NRG acquired Direct Energy, as further described in Note 4, Acquisitions, Discontinued Operations and Dispositions.

Direct Energy comprised of approximately 35% of the Company's total assets as of December 31, 2021 and approximately 58% of the Company's total revenues for the year ended December 31, 2021.

As of December 31, 2021, we are in the process of evaluating the internal controls of the acquired business and integrated it into our existing operations.

The acquired business has, therefore, been excluded from management's assessment of internal control over financial reporting for the year ended December 31, 2021.

The effectiveness of the Company's internal control over financial reporting as of December 31, 2021 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.

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In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, 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, 2020 and 2019, and the related consolidated statements of operations, comprehensive income, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2020, and the related notes and financial statement schedule II (collectively, the consolidated financial statements), and our report dated March 1, 2021 expressed an unqualified opinion on those consolidated financial statements.

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, 2021 and 2020, the related consolidated statements of operations, comprehensive income, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2021, and the related notes and financial statement schedule II (collectively, the consolidated financial statements), and our report dated February 24, 2022 expressed an unqualified opinion on those consolidated financial statements.

The Company acquired Direct Energy during 2021 and management excluded from its assessment of the effectiveness of the Company's internal control over financial reporting as of December 31, 2021.

Direct Energy's internal control over financial reporting are associated with 35% of total assets and 58% of total revenues included in the consolidated financial statements of the Company as of and for the year ended December 31, 2021.

Our audit of internal control over financial reporting of the Company also excluded an evaluation of the internal control over financial reporting of Direct Energy.

Basis for Opinion

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Philadelphia, Pennsylvania

March 1, 2021

February 24, 2022

Item 9B — Other Information

Sale of 4.8 GWs of Generation Assets

On February 28, 2021, the Company entered into a Purchase and Sale Agreement (the "Purchase Agreement") with Generation Bridge Acquisition, LLC ("Generation"), a Delaware limited liability company, pursuant to which NRG has agreed to sell, or cause to be sold, as applicable, to Generation one hundred percent (100%) of the outstanding membership interests of each of (1) Long Beach Generation LLC ("Long Beach") and Mission Del Cielo, LLC ("Mission Del Cielo"), each of which is an indirect wholly owned subsidiary of NRG, and (2) Arthur Kill Power LLC ("Arthur Kill"), Connecticut Jet Power LLC ("Connecticut Jet Power"), Devon Power LLC ("Devon"), Middletown Power LLC ("Middletown"), Montville Power LLC ("Montville") and Oswego Harbor Power LLC ("Oswego," and together with Long Beach, Mission Del Cielo, Arthur Kill, Connecticut Jet Power, Devon, Middletown and Montville, the "Subsidiaries"), each of which is a wholly owned subsidiary of NRG (such sale, the "Transaction").

Mission Del Cielo owns one hundred percent (100%) of the outstanding membership interests of Mission del Sol, LLC ("Mission Del Sol," and together with Mission Del Cielo, the "Holdcos").

Mission Del Sol owns one hundred percent (100%) of the outstanding membership interests of Sunrise Power Company, LLC (together with Long Beach, the "California Project Companies").

Arthur Kill, Connecticut Jet Power, Devon, Middletown, Montville and Oswego, together with the California Project Companies, are referred to as the "Project Companies".

Consideration

Subject to the terms and conditions of the Purchase Agreement, NRG has agreed to sell, or cause to be sold, as applicable, to Generation all of the outstanding membership interests of the Subsidiaries for an aggregate base purchase price of $760 million, subject to adjustments for working capital, indebtedness, and certain operations of the Holdcos and the Project Companies during the interim period between the date of the Purchase Agreement and the consummation of the Transaction (the "Closing").

Representations and Warranties and Covenants

The Purchase Agreement contains customary representations and warranties of NRG and Generation.

The representations and warranties of each party set forth in the Purchase Agreement have been made solely for the benefit of the other party to the Purchase Agreement, and such representations and warranties should not be relied on by any other person.

In addition, such representations and warranties (a) have been qualified by disclosure schedules that the parties have delivered in connection with the execution of the Purchase Agreement, (b) are subject to the materiality standards set forth in the Purchase Agreement, which may differ from what may be viewed as material by investors, (c) in certain cases, were made as of a specific date, and (d) may have been used for purposes of allocating risk between the respective parties rather than establishing matters of fact.

Accordingly, no person should rely on the representations and warranties as characterizations of the actual state of facts.

Moreover, information concerning the subject matter of the representations and warranties may change after the date of the execution of the Purchase Agreement.

Generation has agreed to obtain, at its sole cost, a representation and warranty insurance policy.

As a result, NRG will not be liable for any breach of its representations and warranties that occurs after the Closing.

Between the date of the Purchase Agreement and the Closing, subject to certain exceptions, NRG agrees to cause the Holdcos and the Project Companies to be operated in the ordinary course of business consistent with laws and permits and past practice and to use commercially reasonable efforts to preserve, maintain and protect the assets and business of the Holdcos and the Project Companies.

Following the Closing, NRG will be required to pay all costs incurred by Generation or the applicable Project Companies arising out of or related to certain environmental liabilities (the "Specific Environmental Liabilities") relating to certain remedial actions or the ownership of the Project Companies or the generation facilities owned by the Project Companies, other than certain costs to decommission such facilities, prior to the date of the Closing (the "Closing Date"), subject to a $39 million cap established as set forth in the Purchase Agreement (the "Seller Environmental Liability Cap").

NRG's obligations to pay such costs will terminate on the earlier to occur of the seventh anniversary of the Closing Date and the date on which NRG has paid Generation an amount equal to the Seller Environmental Liability Cap, subject to an extension of such term and a corresponding increase in the Seller Environmental Liability Cap to the extent there are remaining costs to address Specific Environmental Liabilities that have been reasonably estimated but not yet incurred prior to such anniversary date.

Conditions to Closing and Deliverables

The Transaction is subject to various conditions to Closing, including:

(a) the accuracy of the representations and warranties of each party at the time of Closing, (b) compliance by each party with its covenants), (c) the absence of any law or order prohibiting the Closing, (d) certain contractual consents having been obtained, (e) receipt of certain regulatory approvals, as necessary (including HSR, FERC, and NYSPSC authorizations), and (f) the absence of a material adverse effect with respect

to the Holdcos, the California Project Companies and the other Subsidiaries, as well as other customary closing conditions.

The Transaction is expected to close in the fourth quarter of 2021.

In connection with the closing of the Transaction, NRG and Generation will enter in to certain additional ancillary agreements, including a transition services agreement.

In addition, ArcLight Energy Partners Fund VII, L.P., the parent company of Generation, has executed and delivered a parent guaranty with respect to the obligations of Generation in connection with the Transaction.

Indemnification and Termination

Both NRG and Generation have agreed, subject to certain limitations, to indemnify the other party for losses arising from certain breaches of the Purchase Agreement.

In addition, NRG has agreed to indemnify Generation for liabilities related to certain environmental matters and certain ongoing actions or proceedings, among other things.

The Purchase Agreement contains certain customary termination rights for each of NRG and Generation, including among other things, that either party may terminate the Purchase Agreement if (a) the parties mutually agree in writing, (b) the Closing has not occurred on or before December 31, 2021, which date may be extended for an additional 90 days to enable the parties to satisfy certain regulatory conditions, or (c) the other party has incurably breached a representation, warranty, covenant or agreement contained in the Purchase Agreement resulting in a failure of a condition set forth in the Purchase Agreement.

If NRG terminates the Purchase Agreement as a result of a breach by Generation of certain representations, warranties covenants or other agreements, Generation will be required to pay NRG a termination fee equal to 10 percent of the purchase price as adjusted in accordance with the Purchase Agreement.

Entry into a Material Definitive Agreement.

On February 22, 2022, the Company entered into a Supplemental Indenture (the “Supplemental Indenture”), by and among the Company, the guarantors named therein (the “Guarantors") and Delaware Trust Company, as trustee and conversion agent (the “Trustee”), to supplement the Indenture, dated as of May 24, 2018 (the “Indenture”), among the Company, the Guarantors and the Trustee, governing the Convertible Senior Notes.

Pursuant to the Supplemental Indenture, the Company has irrevocably (i) eliminated the right of the Company to elect Physical Settlement (as defined in the Indenture) as the Settlement Method (as defined in the Indenture) on any conversion of Convertible Senior Notes that occurs on or after the date of the Supplemental Indenture and (ii) elected that, with respect to any Combination Settlement (as defined in the Indenture), the Specified Dollar Amount (as defined in the Indenture) per $1,000 principal amount of the Convertible Senior Notes shall be no lower than $1,000.

The foregoing description of the Supplemental Indenture does not purport to be complete and is qualified in its entirety by reference to the full text of the Supplemental Indenture, a copy of which is filed as Exhibit 4.52 to this report and is incorporated herein by reference.

Departure of Directors or Certain Officers;

Election of Directors;

Appointment of Certain Officers;

Compensatory Arrangements of Certain Officers.

As previously disclosed in a Current Report on Form 8-K, filed with the SEC on February 4, 2021, the Company announced that Gaëtan Frotté was appointed Interim Chief Financial Officer of the Company effective February 4, 2021.

On March 1, 2021, the Compensation Committee of the Board of Directors of the Company (the "Compensation Committee") determined that while Mr.

Frotté serves as Interim Chief Financial Officer, in addition to his base salary, he will be entitled to a monthly stipend of $50,000, effective February 4, 2021, to recognize his additional responsibilities.

In addition, the Board of Directors of the Company approved the promotion of Mr.

Curci, the Senior Vice President and General Counsel, to Executive Vice President and General Counsel, effective on February 22, 2021.

Curci will continue to be responsible for the day-to-day legal operations of the Company.

In addition, on March 1, 2021, the Compensation Committee approved changes to Mr.

Curci's annual compensation.

Curci's annual base salary increased to $500,000 effective February 22, 2021.

In addition, Mr.

Curci's target long-term incentive award under the Company's LTIP has been increased to 200% of his base salary and Mr.

Curci's target bonus under the Company's Annual Incentive Plan ("AIP") has been increased to 75% of his base salary with a maximum of 150%.

The general terms and conditions of the LTIP and AIP are described in the Company's definitive proxy statement filed on March 15, 2020 with the SEC.

The description of the LTIP is qualified in its entirety by reference to the full text of the LTIP, a copy of which was filed as Exhibit 10.1 to the Company's current report on Form 8-K filed on April 28, 2017, and the description of the AIP is qualified in its entirety by reference to the full text of the AIP, a copy of which was filed as Exhibit 10.1 to the Company's current report on Form 8-K filed on May 7, 2015.

Effective February 24, 2022, Emily C.

Picarello, CPA, was named as Principal Accounting Officer of NRG Energy, Inc.

Picarello, age 41, joined the Company in December 2018 and served as Assistant Controller for the Company through November 2021, when she was promoted to Vice President and Corporate Controller.

Picarello will continue in this role reporting to Alberto Fornaro, NRG's Executive Vice President and Chief Financial Officer.

Prior to her employment with the Company, Ms.

Picarello spent over seven years with PVH Corp., one of the largest global apparel companies in the world, first as the Director of Financial Reporting and then as the Vice President, Financial Reporting.

Picarello's time with PVH Corp., she was an auditor with KPMG LLP for over eight years, holding various positions including Audit Senior Manager.

Item 9C— Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

Not applicable.

Item 10 — Directors, Executive Officers and Corporate Governance

Spencer Abraham has 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:

PBF Energy and Two Harbors Investment Corp., as well as chairman of the board of Uranium Energy Corp.

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 Occidental Petroleum Corporation, Deepwater Wind LLC, International Battery, C3 IoT, 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.

Antonio Carrillo has been a director of NRG since October 2019.

Carrillo currently serves as Arcosa Inc.’s President and Chief Executive Officer since November 2018 and is a member of its Board of Directors.

From April 2018 to November 2018, Mr.

Carrillo served as Senior Vice President and Group President of Construction, Energy, Marine and Components of Trinity Industries, Inc.

From 2012 to February 2018, Mr.

Carrillo served as the Chief Executive Officer of Orbia Advance Corporation (formerly known as Mexichem S.A.B.

de C.V.) (Orbia), a publicly-traded global specialty chemical company.

Prior to joining Orbia, Mr.

Carrillo spent 16 years at Trinity where he served as Senior Vice President and Group President of Trinity’s Energy Equipment Group and was responsible for Trinity’s Mexico operations.

Carrillo previously served as a director of Trinity from 2014 until November 2018 and a director of Dr Pepper Snapple Group, Inc.

from 2015 to 2018.

Matthew Carter, Jr.

has been a director of NRG since March 2018.

Carter currently serves as Chief Executive Officer of Aryaka Networks, Inc.

Carter served as President and Chief Executive Officer and a director of Inteliquent, Inc., a publicly traded provider of voice telecommunications services, from June 2015 until February 2017 when Inteliquent, Inc.

was acquired.

He served as President of the Sprint Enterprise Solutions business unit of Sprint Corporation, a publicly traded telecommunications company, from September 2013 until January 2015 and, previous to that position, served as President, Sprint Global Wholesale & Emerging Solutions at Sprint Nextel Corporation.

Carter also serves as a director of Jones Lang Lasalle Incorporated.

He previously served as a director of USG Corporation from 2012 to 2018, Apollo Education Group, Inc.

from 2012 to 2017 and Inteliquent, Inc.

from June 2015 to February 2017 and has significant marketing, technology and international experience, including previous management oversight for all of Inteliquent, Inc.’s operations.

Coben has served as Chairman of the Board since February 2017, and has been a director of NRG since December 2003.

He was Chairman and Chief Executive Officer of Tremisis Energy Corporation LLC until December 2017.

Coben was Chairman and Chief Executive Officer of both 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.

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.

Coben is also Executive Director of the Escala Initiative and a Consulting Scholar at the University of Pennsylvania Museum of Archaeology and Anthropology.

Heather Cox has been a director of NRG since March 2018.

Cox currently serves as Chief Digital Health and Analytics Officer at Humana Inc.

Cox was Executive Vice President, Chief Technology & Digital Officer of United Services Automobile Association, Inc.

from October 2016 to March 2018.

Cox served as Chief Executive Officer, Financial Technology Division and Head of Citi FinTech of Citigroup, Inc.

from November 2015 to September 2016, and as Chief Client Experience, Digital and Marketing Officer, Global Consumer Bank of Citigroup, Inc.

from April 2014 to November 2015.

Prior to that, Ms.

Cox served at Capital One Financial Corporation for six years, most recently as Executive Vice President, US Card Operations, Capital One from August 2011 to August 2014.

Cox also served in various managerial and executive roles at E*Trade Bank for ten years.

Donohue has been a director of NRG since October 2020.

Donohue retired in January 2020 from Publicis Groupe, the world’s third largest communications company where she spent 32 years advising clients on their consumer marketing efforts and business transformation.

Her most recent role included serving as the chief executive officer of Publicis Spine, a data and technology start up launched by Publicis Groupe in October 2017.

From April 2016 to October 2017, Ms.

Donohue served as Global Brand President of the media communications agency Starcom Worldwide.

From 2009 through 2016, Ms.

Donohue served as chief executive officer of Starcom USA, where she drove Starcom’s digital offering and built the

agency’s data and analytics practice.

Donohue plays leadership roles on two non-profit boards.

She is currently President of the Board of Trustees of Milton Academy based in Milton, Massachusetts and immediate past Board President of She Runs It based in New York City.

Donohue also serves as a director of Synacor, where she acts as the chair of the compensation committee and is a member of the audit committee.

Donohue graduated from Brown University with a B.A.

in both Organizational Behavior & Management and Business Economics.

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.

Gutierrez also served as the Interim President and Chief Executive Officer of Clearway Energy, Inc.

from December 2015 to May 2016 and Executive Vice President and Chief Operating Officer of Clearway Energy, Inc.

from December 2012 to December 2015.

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.

Gutierrez served as a director of Clearway Energy, Inc.

from 2012 until 2018.

Hobby has been a director of NRG since March 2006.

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.

Hobby routinely provides management and governance services to Genesis Park portfolio companies.

Since November 2020, Mr.

Hobby is also serving as Chief Executive Officer and a director of Genesis Park Acquisition Corp., a newly formed special purpose acquisition vehicle.

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 services to the global energy business from 2002 to 2006.

From November 1992 until January 2001, he served as Chairman and Chief Executive Officer of Hobby Media Services and was Chairman of Columbine JDS Systems, Inc.

from 1995 until 1997.

Hobby currently serves on the board of directors of Flotek Industries Inc.

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.

Alexandra Pruner has been a director of NRG since October 2019.

Pruner is a Senior Advisor of Perella Weinberg Partners, a global independent advisory firm providing strategic and financial advice and asset-management services, and its energy division, Tudor, Pickering, Holt & Co., since December 2018.

She previously served as Partner and Chief Financial Officer of Perella Weinberg Partners from December 2016 through November 2018.

She served as Chief Financial Officer and a member of the Management Committee at Tudor, Pickering, Holt & Co.

from the firm's founding in 2007 until its combination with Perella Weinberg in 2016.

Pruner serves on the board of directors and as a member of the audit committees of Plains All American Pipeline, L.P.

and its general partner PAA GP Holdings LLC, and on the Board of Directors of Encino Acquisition Partners, a privately held company backed by CCPIB.

She previously served on the Anadarko Petroleum Corporation Board until its merger with Occidental Petroleum.

She is the founder and a board member of Women's Global Leadership Conference in Energy & Technology, is an Emeritus Director of the Amegy Bank Development Board and is the Chair of Brown University's President's Advisory Council on the Economics Department.

Pruner is on the board of the Houston Zoo and serves on the Houston advisory Board of The Nature Conservancy, among other volunteer efforts.

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.

Schaumburg worked in the Investment Banking industry for 28 years specializing in the power sector.

She ran Credit Suisse's Power Group from 1994 - 1999, prior to its consolidation with Natural Resources and Project Finance, where she was responsible for assisting clients on advisory and finance assignments.

Her transaction expertise, across the spectrum of utility and unregulated power, includes mergers and acquisitions, debt and equity capital market financings, project finance and leasing, utility disaggregation and privatizations.

Schaumburg is also the chair of the board of directors of Brookfield Infrastructure Partners since 2008 and chair of its audit committee.

Weidemeyer has been a director of NRG since December 2003.

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, until his retirement in December 2003.

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.

Weidemeyer became Vice President and Airline Manager of UPS Airlines and, in 1994, was elected its President and Chief Operating Officer.

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.

Weidemeyer also serves as a director of The Goodyear Tire & Rubber Co., Waste Management, Inc.

and Amsted Industries Incorporated.

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."

Gaëtan Frotté has served as Interim Chief Financial Officer since February 2021 and Senior Vice President and Treasurer since December 2015.

Frotté has held various senior management positions since joining the Company in 2006.

He studied management at The University of Hertfordshire and received a B.A.

in Accounting and Financing from Institut Supérieur du Commerce.

He also holds an MBA, Finance from the University of Virginia - Darden Graduate School of Business Administration.

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.

Callen also has served as Vice President and Chief Accounting Officer of Clearway Energy, Inc.

from March 2015 to August 2018.

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.

Brian Curci has served as Executive Vice President, General Counsel of NRG since March 2021.

Curci served as Senior Vice President and General Counsel from March 2018 to March 2021 and Senior Vice President and Deputy General Counsel from April 2017 to March 2018.

Since joining NRG in 2007, Mr.

Curci has served in various legal roles with NRG, including as Corporate Secretary from October 2011 to July 2018.

Prior to NRG, Mr.

Curci was a corporate associate with the law firm Saul Ewing LLP in Philadelphia.

Robert Gaudette has served as Senior Vice President, Business Solutions of NRG since December 2013.

In this role, Mr.

Gaudette oversees NRG's broad portfolio of products and services for the commercial and industrial customers.

Prior to December 2013, Mr.

Gaudette was Senior Vice President, C&I and Origination, starting in August 2013, and Senior Vice President - Product Development & Origination following the acquisition of GenOn in December 2012.

Gaudette served as Senior Vice President and Chief Commercial Officer at GenOn from December 2010 to December 2012 and served as Vice President of Mirant's Mid-Atlantic business unit from August 2009 to December 2010.

During his career at Mirant, which began in 2001, Mr.

Gaudette worked in various other capacities including Director of West Power, Director of NYMEX Trading, Assistant to the Chief Operating Officer and NYMEX natural gas trader.

Elizabeth Killinger has served as Executive Vice President and President, NRG Retail and Reliant of NRG since February 2016.

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.

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.

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.

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.

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 2022 Annual Meeting of Stockholders.

Code of Ethics

38 unchanged sentences

(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 22, Stock-Based Compensation , for additional information

For further discussion, see Note 21, Stock-Based Compensation

NRG LTIP currently provides for grants of restricted stock units, relative performance stock units, deferred stock units and dividend equivalent rights.

10 unchanged sentences

The following consolidated financial statements of NRG Energy, Inc.

and related notes thereto, together with the reports thereon of KPMG LLP, are included herein:

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, 2021, 2020, and 2019

21 unchanged sentences

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, 2020, 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, 2021 expressed an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.

Changes in Accounting Principle

As discussed in Note 10 to the consolidated financial statements, effective January 1, 2019, the Company adopted Financial Accounting Standard Board (FASB) Accounting Standards Codification (ASC) Topic 842, Leases , and related amendments.

As discussed in Note 3 to the consolidated financial statements, effective January 1, 2018, the Company adopted FASB ASC Topic 606, Revenue from Contracts with Customers , and related amendments.

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, 2021, 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 24, 2022 expressed an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.

Basis for Opinion

9 unchanged sentences

We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that:

(1) relates 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 a critical audit matter 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 matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Evaluation of the sufficiency of audit evidence obtained over operating revenues

As discussed in Note 3 to the consolidated financial statements, the Company had $9,093 million of operating revenues.

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 operating revenues

As discussed in Note 3 to the consolidated financial statements, the Company had $26.989 billion of operating revenues.

Operating 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.

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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 each revenue stream 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;

involved IT professionals, who assisted in testing certain IT applications used by the Company in its revenue recognition processes;

and assessed the recorded revenue by selecting transactions and comparing the amounts recognized to underlying documentation, including contracts with customers.

For certain revenue streams, 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.

In addition, we evaluated the sufficiency of audit evidence obtained over operating revenues by assessing the results of procedures performed, including the appropriateness of such evidence.

Fair value of customer relationship intangible assets

As discussed in Note 4 to the consolidated financial statements, the Company acquired Direct Energy on January 5, 2021 for consideration of $3.724 billion.

The Company recorded the identifiable assets acquired and liabilities assumed at fair value at the acquisition date, including $1.277 billion of customer relationship intangible assets which represent the generation of future income reflective of Direct Energy's customer base.

Customer relationship intangible assets were valued using the excess earnings method of the income approach.

We identified the evaluation of the fair value of customer relationship intangible assets acquired in the Direct Energy transaction as a critical audit matter.

A higher degree of auditor judgment was required to evaluate the customer attrition used in the excess earnings method.

Changes in the customer attrition could have a significant impact on the forecasted future cash flows used in the excess earnings method and the resulting fair value of the customer relationship intangible assets.

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 over the development of the customer attrition.

We performed sensitivity analyses over the Company's customer attrition used to determine the estimated fair value of the customer relationship intangible assets to assess the effect of changes in that assumption on the Company's determination of fair value.

We evaluated the customer attrition by comparing it to the Company's actual customer attrition.

We have served as the Company's auditor since 2004.

Philadelphia, Pennsylvania

March 1, 2021

February 24, 2022

NRG ENERGY, INC.

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Operating Costs and Expenses

Cost of operations 6,540 7,303 7,108

Cost of operations (excluding depreciation and amortization shown below) 20,482 6,540 7,303

Depreciation and amortization 785 435 373

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Selling, general and administrative costs 1,293 810 760

Reorganization costs — 23 90

Development costs 8 7 11

Provision for credit losses 698 108 95

Acquisition-related transaction and integration costs 93 23 2

Total operating costs and expenses 23,895 7,991 8,538

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Other income, net 63 67 66

Loss on debt extinguishment, net ( 9 ) ( 51 ) ( 44 )

Loss on debt extinguishment ( 77 ) ( 9 ) ( 51 )

Interest expense ( 485 ) ( 401 ) ( 413 )

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Net Income 2,187 510 4,441

Net income attributable to noncontrolling interest and redeemable interests — 3 —

Net income attributable to redeemable noncontrolling interest — — 3

Net Income Attributable to NRG Energy, Inc.

$ 2,187 $ 510 $ 4,438

Earnings/(Loss) Per Share Attributable to NRG Energy, Inc.

Income Per Share Attributable to NRG Energy, Inc.

Common Stockholders

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Income from continuing operations per weighted average common share — basic $ 8.93 $ 2.08 $ 15.71

Income/(loss) from discontinued operations per weighted average common share — basic $ — $ 1.23 $ ( 0.63 )

Income from discontinued operations per weighted average common share — basic $ — $ — $ 1.23

Net Income per Weighted Average Common Share — Basic $ 8.93 $ 2.08 $ 16.94

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Income from continuing operations per weighted average common share — diluted $ 8.93 $ 2.07 $ 15.59

Income/(loss) from discontinued operations per weighted average common share — diluted $ — $ 1.22 $ ( 0.62 )

Income from discontinued operations per weighted average common share — diluted $ — $ — $ 1.22

Net Income per Weighted Average Common Share — Diluted $ 8.93 $ 2.07 $ 16.81

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Other Comprehensive Income/(Loss), net of tax

Unrealized gain on derivatives, net of income tax

Foreign currency translation adjustments, net of income tax

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Defined benefit plans, net of income tax 85 ( 22 ) ( 78 )

Other comprehensive (loss) ( 14 ) ( 98 ) ( 22 )

Other comprehensive income/(loss) 80 ( 14 ) ( 98 )

Comprehensive Income 2,267 496 4,343

Comprehensive income attributable to noncontrolling interests and redeemable noncontrolling interests — 3 14

Net income attributable to redeemable noncontrolling interest — — 3

Comprehensive Income Attributable to NRG Energy, Inc.

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Accounts receivable, net 3,245 904

Uplift securitization proceeds receivable from ERCOT 689 —

Inventory 498 327

Derivative instruments 4,613 560

Cash collateral posted in support of energy risk management activities 50 190

Cash collateral paid in support of energy risk management activities 291 50

Prepayments and other current assets 395 257

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Current Liabilities

Current portion of long-term debt and finance lease $ 1 $ 88

Current portion of long-term debt and finance leases $ 4 $ 1

Current portion of operating lease liabilities 81 69

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Other Liabilities

Long-term debt and finance lease 8,691 5,803

Long-term debt and finance leases 7,966 8,691

Non-current operating lease liabilities 236 278

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Total other liabilities

11,667 11,307

Total Liabilities 19,582 13,222

Redeemable noncontrolling interest in subsidiaries

Commitments and Contingencies

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423,547,174 and 423,057,848 shares issued;

and 244,231,933 and 248,996,189 shares outstanding at December 31, 2020 and 2019

and 243,753,899 and 244,231,933 shares outstanding at December 31, 2021 and 2020, respectively

Additional paid-in capital 8,531 8,517

Accumulated deficit ( 1,403 ) ( 1,616 )

Retained earnings/(accumulated deficit) 464 ( 1,403 )

Treasury stock, at cost;

178,825,915 and 172,894,601 shares at December 31, 2020 and 2019

179,793,275 and 178,825,915 shares at December 31, 2021 and 2020, respectively

( 5,273 ) ( 5,232 )

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Net income $ 2,187 $ 510 $ 4,441

Income/(loss) from discontinued operations, net of income tax — 321 ( 192 )

Income from discontinued operations, net of income tax — — 321

Income from continuing operations 2,187 510 4,120

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Depreciation and amortization 785 435 373

Accretion expense related to asset retirement obligations 45 51 38

Accretion of asset retirement obligations 30 45 51

Provision for credit losses 698 108 95

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Amortization of financing costs and debt discounts 39 48 26

Loss on debt extinguishment, net 9 51 44

Amortization of emission allowances, out-of-market contracts and REC retirements 70 72 71

Loss on debt extinguishment 77 9 51

Amortization of in-the-money contracts and emission allowances 106 70 72

Amortization of unearned equity compensation 21 22 20

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Oil lower of cost or market adjustment — 29 —

GenOn settlement, net of insurance proceeds — — ( 63 )

Net loss on deconsolidation of Agua Caliente and Ivanpah projects — — 13

Cash provided/(used) by changes in other working capital, net of acquisition and disposition effects:

Uplift securitization proceeds receivable from ERCOT ( 689 ) — —

Cash (used)/provided by changes in other working capital, net of acquisition and disposition effects:

Accounts receivable - trade ( 1,232 ) — 5

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Proceeds from sale of assets, net of cash disposed and sale of discontinued operations, net of fees 830 81 1,294

Deconsolidations of Agua Caliente and Ivanpah projects — — ( 268 )

Changes in investments in unconsolidated affiliates — 2 ( 91 )

Net contributions to discontinued operations — — ( 44 )

Other — 6 ( 6 )

Cash (used)/provided by continuing operations ( 3,039 ) ( 494 ) 558

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Payments for short and long-term debt ( 1,861 ) ( 335 ) ( 2,571 )

Net (repayments)/proceeds of Revolving Credit Facility ( 83 ) 83 —

Payments of debt issuance costs ( 75 ) ( 35 ) ( 19 )

Payments of dividends to common stockholders ( 319 ) ( 295 ) ( 32 )

Net receipts/(payments) from settlement of acquired derivatives that include financing elements 938 ( 7 ) ( 4 )

Payments for share repurchase activity ( 48 ) ( 229 ) ( 1,440 )

Payments for debt extinguishment costs ( 65 ) ( 5 ) ( 26 )

Purchase of and distributions to noncontrolling interests from subsidiaries ( 2 ) ( 2 ) ( 16 )

Payments of debt issuance costs ( 18 ) ( 75 ) ( 35 )

Net (repayments)/proceeds of Revolving Credit Facility — ( 83 ) 83

Proceeds from issuance of common stock 1 1 3

Receivable from affiliate — — ( 26 )

Other ( 7 ) ( 4 ) ( 4 )

Cash provided/(used) by continuing operations 2,204 ( 2,191 ) ( 1,997 )

Purchase of and distributions to noncontrolling interests from subsidiaries — ( 2 ) ( 2 )

Cash (used)/provided by continuing operations ( 272 ) 2,204 ( 2,191 )

Cash provided by discontinued operations — — 43

Net Cash Provided/(Used) by Financing Activities 2,204 ( 2,148 ) ( 1,526 )

Net Cash (Used)/Provided by Financing Activities $ ( 272 ) $ 2,204 $ ( 2,148 )

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

Change in Cash from discontinued operations — — 49

Net Increase/(Decrease) in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash 3,545 ( 228 ) ( 473 )

Net (Decrease)/Increase in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash ( 2,820 ) 3,545 ( 228 )

Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period 3,930 385 613

Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period $ 1,110 $ 3,930 $ 385

For further discussion of supplemental cash flow information see Note 26, Cash Flow Information

See notes to Consolidated Financial Statements

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(In millions) Common

Accumulated Deficit Treasury

Retained Earnings/ (Accumulated Deficit) Treasury

Comprehensive

Noncon- trolling

Stock-holders'

Balances at December 31, 2018 $ 4 $ 8,510 $ ( 6,022 ) $ ( 3,632 ) $ ( 94 ) $ ( 1,234 )

Net income attributable to NRG Energy, Inc.

Other comprehensive loss

( 98 ) ( 98 )

Sale of assets to NRG Yield, Inc.

Shares reissuance for ESPP

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( 1,409 ) ( 1,409 )

Equity-based awards activity, net

Issuance of common stock 21 21

Common stock dividends and dividend equivalents declared (a)

( 37 ) ( 37 )

Distributions to noncontrolling interests

( 43 ) ( 43 )

Dividends paid to NRG Yield, Inc.

Equity-based awards activity, net (a)

( 16 ) ( 16 )

Contributions from noncontrolling interests

Adoption of new accounting standards 15 15

Sale of NRG Yield and other business

Issuance of common stock

Common stock dividends and dividend equivalents declared (b)

( 32 ) ( 32 )

Equity component of convertible senior notes

Balances at December 31, 2018 $ 4 $ 8,510 $ ( 6,022 ) $ ( 3,632 ) $ ( 94 ) $ — $ ( 1,234 )

Net income attributable to NRG Energy, Inc.

Balance at December 31, 2019 $ 4 $ 8,501 $ ( 1,616 ) $ ( 5,039 ) $ ( 192 ) $ 1,658

Other comprehensive loss ( 14 ) ( 14 )

( 98 ) ( 98 )

Repurchase of partners' equity interest in VIE

Shares reissuance for ESPP

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( 197 ) ( 197 )

Equity-based awards activity, net

( 16 ) ( 16 )

Equity-based awards activity, net (a)

Issuance of common stock

Common stock dividends and dividend equivalents declared (a)

Common stock dividends and dividend equivalents declared (b)

( 297 ) ( 297 )

Balance at December 31, 2020 $ 4 $ 8,517 $ ( 1,403 ) $ ( 5,232 ) $ ( 206 ) $ 1,680

Net income attributable to NRG Energy, Inc.

Other comprehensive loss ( 14 ) ( 14 )

Repurchase of partners' equity interest in VIE

Other comprehensive income 80 80

Shares reissuance for ESPP

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( 44 ) ( 44 )

Equity-based awards activity, net

Equity-based awards activity, net (a)

Issuance of common stock

Common stock dividends and dividend equivalents declared (a)

Common stock dividends and dividend equivalents declared (b)

( 320 ) ( 320 )

Balance at December 31, 2021 $ 4 $ 8,531 $ 464 $ ( 5,273 ) $ ( 126 ) $ 3,600

(a) Dividends per common share were $ 1.20 for the year ended December 31, 2020 and $ 0.12 for each of the years ended December 31, 2019 and 2018

(a) Includes $( 9 ) million, $( 27 ) million and $( 36 ) million of equivalent shares purchased in lieu of tax withholding on equity compensation issuances for the years ended December 31, 2021, 2020 and 2019, respectively

(b) Dividends per common share were $ 1.30 , $ 1.20 and $ 0.12 for each of the years ended December 31,2021, 2020 and 2019, respectively

See notes to Consolidated Financial Statements

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Note 1 — Nature of Business

NRG Energy, Inc., or NRG or the Company, is an integrated power company built on dynamic retail brands with diverse generation assets.

NRG brings the power of energy to customers by producing and selling energy and related products and services in major competitive power and gas markets in the U.S.

NRG Energy, Inc., or NRG or the Company, is a consumer services company built on dynamic retail brands.

NRG brings the power of energy to customers by producing and selling energy and related products and services, nation-wide in the U.S.

and Canada in a manner that delivers value to all of NRG's stakeholders.

NRG is a customer-centric business focused on perfecting the integrated model by balancing retail load with generation supply within its deregulated markets.

As of December 31, 2020, the Company sold energy, services, and innovative, sustainable products and services directly to retail customers under the names NRG, Reliant, Green Mountain Energy, Stream and XOOM Energy, as well as other brand names owned by NRG, supported by approximately 23,000 MW of generation.

NRG also conducts business under the brand name of Direct Energy as a result of the Company's acquisition of Direct Energy, a North American subsidiary of Centrica plc, on January 5, 2021.

NRG sells power, natural gas, home and power services, and develops innovative, sustainable solutions, predominately under the brand names NRG, Reliant, Direct Energy, Green Mountain Energy, Stream, and XOOM Energy.

The Company has a customer base that includes approximately 6 million Home customers as well as commercial, industrial, and wholesale customers, supported by approximately 18,000 MW of generation.

On January 5, 2021, the Company acquired Direct Energy, which had been a North American subsidiary of Centrica.

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.

Following the acquisition, the Company serves more than 6 million customers.

In addition, Direct Energy is a participant in the wholesale gas and power markets in the United States and Canada.

Note 4, Acquisitions, Discontinued Operations and Dispositions for further discussion of the acquisition of Direct Energy.

The Company began managing its integrated model based on the combined results of the retail and wholesale generation businesses with a geographical focus in 2020.

As a result, the Company changed its business segments from Retail and Generation to Texas, East and West/Other beginning in the first quarter of 2020.

The Company's updated segment structure reflects how management makes financial decisions and allocates resources.

The Company's businesses are segregated as follows:

The acquisition increases NRG's retail portfolio by over 3 million customers and complements its integrated model.

It also broadens the Company's presence in the Northeast and into states and locales where it does not currently operate, supporting NRG's objective to diversify its business.

See Note 4, Acquisitions, Discontinued Operations and Dispositions , to the Consolidated Financial Statements for further discussion of the acquisition of Direct Energy.

On December 1, 2021, the Company sold approximately 4,850 MWs of fossil generating assets from its East and West regions to Generation Bridge, an affiliate of ArcLight Capital Partners.

NRG received $ 623 million of net proceeds, after purchase price adjustments pursuant to the terms of the Purchase and Sale Agreement entered into on February 28, 2021.

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.

During the second quarter of 2021, the results of the PJM Base Residual Auction for the 2022/2023 delivery year were released, leading the Company to announce the near-term retirement of approximately 1,600 MW of its PJM coal generating assets in June 2022.

On July 30, 2021, PJM identified reliability impacts resulting from the proposed deactivation of one of those assets, Indian River Unit 4.

On August 27, 2021 the Company notified PJM that it would continue operations at Indian River Unit 4 until the reliability upgrades identified by PJM were completed, provided that the unit receives a satisfactory and compensatory reliability must run arrangement.

See Item 15 — Note 11, Asset Impairments, to the Consolidated Financial Statements for further discussion.

The Company is continuing to evaluate the viability of the remaining PJM generating assets.

The Company manages its operations based on the combined results of the retail and wholesale generation businesses with a geographical focus.

The Company's business is segmented as follows:

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

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

• West/Other, which includes the following assets and activities:

(i) all activity related to plant and market operations in the West, (ii) activity related to the Cottonwood power plant that was sold to Cleco on February 4, 2019 and is being leased back until 2025, (iii) the remaining renewables activity, including the Company’s equity method investments in Ivanpah Master Holdings, LLC and Agua Caliente (which was sold on February 3, 2021), the remaining Home Solar assets (which were primarily sold on November 13, 2020) and the NFL stadium solar generating assets, and (iv) activity related to the Company’s equity method investment for the Gladstone power plant in Australia;

• 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 plant and market operations in the West and Canada, (ii) the Services businesses (iii) activity related to the Cottonwood facility, (iv) the remaining renewables activity, including the Company’s equity method investment in Ivanpah Master Holdings, LLC, and (v) activity related to the Company’s equity method investment for the Gladstone power plant in Australia;

• Corporate activities.

All affected disclosures presented herein have been recast to reflect these changes for all periods presented.

For further discussion of segment reporting, refer to Note 20, Segment Reporting .

The acquired operations of Direct Energy will be integrated into the existing NRG segment structure.

Domestic customer and market operations will be combined into the corresponding geographical segments of Texas, East and West/Other.

The East segment will also include the deregulated customer and market operations of Canada.

The West/Other segment will also include activity related to the regulated operations in Alberta, Canada and the services businesses.

In March 2020, the World Health Organization categorized COVID-19 as a pandemic and the President of the United States declared the COVID-19 outbreak a national emergency.

Electricity was deemed a 'critical and essential business operation' under various state and federal governmental COVID-19 mandates.

NRG had activated its Crisis Management Team ("CMT") in January 2020 to proactively manage the Company's response to the impacts of COVID-19.

NRG continues to remain focused on protecting the health and well-being of its employees, while supporting its customers and the communities in which it operates and assuring the continuity of its operations.

In June 2020, summer-critical office employees returned to the offices and safety protocols were successfully implemented.

The Company continues to maintain certain restrictions on business travel and face-to-face sales channels, remote work practices remain in place and there are enhanced cleaning and hygiene protocols in all of its facilities.

In addition, select essential employees and contractors are continuing to report to plant and certain office locations.

The Company also continues to require pre-entry screening, including temperature checks, separation of work crews, additional personal protective

equipment for employees and contractors when social distancing cannot be maintained, and a ban on all non-essential visitors.

The Company has not experienced any material disruptions in its ability to continue its business operations to date.

The first COVID-19 vaccine became available in the United States in December 2020.

NRG continues to advocate alongside state and federal trade groups for the high prioritization of essential electric industry personnel for inoculation against COVID-19.

States are receiving weekly doses of vaccines and allocating those doses to frontline healthcare workers, elderly populations and high risk individuals.

NRG continues to monitor state information, as well as dosage and allocation numbers to anticipate the latest timing of vaccine distribution to our essential employees.

The Company will continue to evaluate additional return to normal work operations on a location-by-location basis as COVID-19 conditions evolve.

Discontinued Operations

On December 31, 2018, as described in Note 4, Acquisitions, Discontinued Operations and Dispositions , the Company concluded that the sale of its South Central Portfolio to Cleco, excluding the Cottonwood facility, met held-for-sale criteria and should be presented as a discontinued operation, as the sale represented a strategic shift in the business in which NRG operates.

The financial information for all historical periods was recast in 2018 to reflect the presentation of these entities as discontinued operations.

On August 31, 2018, as described in Note 4, Acquisitions, Discontinued Operations and Dispositions , the Company deconsolidated NRG Yield, Inc.

and its Renewables Platform for financial reporting purposes.

The financial information for all historical periods was recast in 2018 to reflect the presentation of these entities, as well as the Carlsbad project, as discontinued operations.

As a result of the sale of NRG Yield, the Company no longer controls the Agua Caliente project.

Due to this change in control, the Company deconsolidated the Agua Caliente project from its financial results and began accounting for the project as an equity method investment.

Note 2 — Summary of Significant Accounting Policies

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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.

However, a controlling financial interest may also exist through arrangements that do not involve controlling voting

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.

Net Income/(Loss) attributable to NRG Energy, Inc.

The following table reflects the net income/(loss) attributable to NRG Energy, Inc.

after removing the net loss attributable to the noncontrolling interest and redeemable noncontrolling interest:

Year Ended December 31,

(In millions) 2020 2019 2018

Income from continuing operations, net of income tax $ 510 $ 4,117 $ 465

Income/(loss) from discontinued operations, net of income tax — 321 ( 197 )

Net income attributable to NRG Energy, Inc.

$ 510 $ 4,438 $ 268

Cash and Cash Equivalents

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Funds deposited by counterparties consist of cash held by the Company as a result of collateral posting obligations from its counterparties.

Some amounts are segregated into separate accounts that are not contractually restricted but, based on the Company's intention, are not available for the payment of general corporate obligations.

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.

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.

Winter Storm Uri Uplift Securitization Proceeds

The Texas Legislature passed HB 4492 for ERCOT to mitigate exceptionally high price adders and ancillary service costs incurred by LSEs during Winter Storm Uri.

HB 4492 authorized ERCOT to obtain $2.1 billion of financing to distribute to LSEs that were charged and paid to ERCOT those highly priced ancillary service and ORDPA during Winter Storm Uri.

In December 2021, 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 we will receive 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 annual period for which the proceeds are intended to compensate.

The Company expects to receive proceeds of $ 689 million from ERCOT in the second quarter of 2022 and we concluded that the threshold for recognizing a receivable was met in December 2021 as the amounts to be received are determinable and ERCOT was directed by its governing body, the PUCT, to take all actions required to effectuate the $2.1 billion funding approved in the DOO.

The associated expense reduction is reflected in Cost of operations within our consolidated statements of operations as that is where the initial costs which are being compensated for were recorded.

Credit Losses

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The following table represents the activity in the allowance for credit losses for the year ended December 31, 2021:

(In millions) Year Ended December 31, 2020

Year Ended December 31,

(In millions) 2021 2020

Beginning balance $ 67 $ 43

Provision for credit losses 108

Acquired balance from Direct Energy 112 —

Provision for credit losses (a)

Write-offs ( 224 ) ( 101 )

Recoveries collected 30 17

Ending balance $ 67

Ending balance (a)

(a) Includes bilateral finance hedging risk of $ 403 million accounted for under ASC 815

The increase in the provision for credit losses during the year ended December 31, 2021, compared to 2020 was primarily due to the impacts of Winter Storm Uri on bilateral finance hedging risk of $ 403 million, counterparty credit risk of $ 126 million and ERCOT default shortfall payments of $ 67 million.

Restricted Cash

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$ 1,110 $ 3,930 $ 385

Restricted cash consists primarily of funds held within the Company's projects that are restricted in their use.

Inventory is valued at the lower of weighted average cost or market, and consists principally of fuel oil, coal and raw materials used to generate electricity or steam.

The Company removes these inventories as they are used in the production of electricity or steam.

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

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 in the delivery of goods 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.

Spare parts inventory is valued at weighted average cost.

The Company removes these inventories when they are used for repairs, maintenance or capital projects.

The Company expects to recover the fuel oil, coal, raw materials, and spare parts costs in the ordinary course of business.

Finished goods inventory is valued at the lower of cost or net realizable value with cost being determined on a first-in first-out basis.

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 these inventories as they are sold to customers.

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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 is amortized based on units

of production over the estimated useful lives.

Depreciation, other than nuclear fuel, is computed using the straight-line method, while nuclear fuel is 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.

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Intangible assets represent contractual rights held by the Company.

The Company recognizes specifically identifiable intangible assets including customer contracts, customer relationships, energy supply contracts, marketing partnerships, trade names, emission allowances, and fuel contracts when specific rights and contracts are acquired.

The Company recognizes specifically identifiable intangible assets including emission allowances, customer and supply contracts, customer relationships, marketing partnerships, 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.

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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 Amortization

Assets and liabilities recognized through acquisitions related to the sale of electric capacity and energy in future periods for which the fair value has been determined to be significantly less or more than market are amortized to cost of operations over the term of each underlying contract based on actual generation and/or contracted volumes.

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 operating 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 generate a specified amount of emissions, 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.

Lease Revenue

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Many of these agreements are accounted for as operating leases under ASC 842 .

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 finance lease .

Contingent rental income under ASC 840 was $ 104 million for the year ended December 31, 2018.

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, 2020, 2019 and 2018, the Company's revenues and cost of operations included gross receipts taxes of $ 107 million, $ 109 million and $ 99 million,

respectively.

During the years ended December 31, 2021, 2020 and 2019, the Company's revenues and cost of operations included gross receipts taxes of $ 184 million, $ 107 million and $ 109 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.

Purchased Energy and Other Cost of Sales for Customer Operations

The cost of energy for electricity sales and services to retail customers is included in cost of operations and is based on actual and estimated supply volumes for the applicable reporting period.

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, 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 purchased power agreements under PPAs with third-party developers, which are accounted for as NPNS (see further discussion in Derivative Financial 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, $ 189 million, $ 98 million and $ 103 million as of December 31, 2021, 2020 and 2019, respectively, was accrued and consisted of estimated transmission and distribution charges not yet billed by the transmission and distribution utilities.

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Volume estimates are then multiplied by the supply rate and recorded as cost of operations in the applicable reporting period.

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 unless they qualify for a 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 purchase or sales contracts, fuels purchase contracts, and other energy related commodities used to mitigate variability in earnings due to fluctuations in market prices and interest rates.

On an ongoing basis, the Company assesses the effectiveness of all derivatives that are designated as hedges for accounting purposes in order to determine 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 contract 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 gain 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.

The Company had no cash flow hedges as of December 31, 2020.

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 and other energy related commodities used to mitigate variability in earnings due to fluctuation in market prices.

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, 2021 and 2020 the Company did not have derivative instruments that were designated as cash flow or fair value or hedge.

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.

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 financial instruments are recognized in earnings.

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 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

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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.

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.

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The Company’s redeemable noncontrolling interest in subsidiaries represented third-party interests in the net assets under certain tax equity arrangements, which were consolidated by the Company, that had been entered into to finance the cost of solar energy systems under operating leases.

The Company determined that the provisions in the contractual agreements of

these structures represented substantive profit sharing arrangements.

The Company determined that the provisions in the contractual agreements of these structures represented substantive profit sharing arrangements.

Further, the Company had determined that the appropriate methodology for calculating the redeemable noncontrolling interest that reflected the substantive profit sharing arrangements was a balance sheet approach that utilized the HLBV method.

Under the HLBV method, the amounts reported as redeemable noncontrolling interests represented the amounts the investors that were 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.

Under the HLBV method, the amounts reported as redeemable

noncontrolling interests represented the amounts the investors that were 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.

The investors’ interests in the results of operations of the funding structures were determined as 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 included estimated calculations of taxable income or losses for each reporting period.

During the first quarter of 2020, the Company repurchased its partners' equity interest as further described in Note 18, Investments Accounted for by the Equity Method and Variable Interest Entities .

The Company has no remaining tax equity arrangements as of December 31, 2020.

During the first quarter of 2020, the Company repurchased its partners' equity interest, which was the Company's last remaining tax equity arrangement.

Redeemable Noncontrolling Interest

To the extent that the third-party has the right to redeem their interests for cash or other assets, the Company had included the noncontrolling interest attributable to the third party as a component of temporary equity in the mezzanine section of the consolidated balance sheet.

During the first quarter of 2020, the Company repurchased its partners' equity interest.

The following table reflects the changes in the Company's redeemable noncontrolling interest balance for the years ended December 31, 2020 and 2019.

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Distributions to redeemable noncontrolling interest ( 2 )

Contributions from redeemable noncontrolling interest 26

Non-cash adjustments to redeemable noncontrolling interest ( 8 )

Net income attributable to redeemable noncontrolling interest - continuing operations 3

Net loss attributable to redeemable noncontrolling interest - discontinued operations ( 27 )

Sale of NRG Yield and the Renewables Platform (a) ( 48 )

Balance as of December 31, 2019 20

Distributions to redeemable noncontrolling interest ( 2 )

Net income attributable to redeemable noncontrolling interest - continuing operations 3

Balance as of December 31, 2019 20

Repurchase of redeemable noncontrolling interest ( 20 )

Balance as of December 31, 2020 $ —

(a) See Note 4, Acquisitions, Discontinued Operations and Dispositions , for further information regarding the sale of NRG Yield and its Renewables Platform

Sale-Leaseback Arrangements

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Advertising expenses for the years ended December 31, 2021, 2020 and 2019 were $ 109 million, $ 74 million and $ 66 million, respectively.

Reorganization Costs

Reorganization costs include costs incurred by the Company related to the Transformation Plan implementation and primarily reflect severance and contract modifications.

There were no reorganization costs for the year ended December 31, 2020.

Reorganization costs for the years ended December 31, 2019 and 2018 were $ 23 million and $ 90 million, respectively.

Business Combinations

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Reclassifications

Certain prior year amounts have been reclassified for comparative purposes.

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 2021

ASU 2020-09 — In October 2020, the FASB issued ASU 2020-09, Debt (Topic 470) - Amendments to SEC Paragraphs Pursuant to SEC Release No.

33-10762 , or ASU 2020-09, to reflect the SEC’s amended disclosure rules for guaranteed debt securities offerings.

The final rule amends the disclosure requirements in SEC Regulation S-X, Rule 3-10, which require entities to separately present financial statements for subsidiary issuers and guarantors of registered debt securities unless certain exceptions are met.

The amended rule allows entities to provide summarized financial information of the parent company and its issuers and guarantors on a combined basis either in a note to the financial statements or as part of management’s discussion and analysis.

ASU 2020-09 is effective for filings on or after January 4, 2021, with early adoption permitted.

The Company adopted the amendments effective December 31, 2020.

As the amendments contemplate changes in disclosures only, it did not have an impact on the Company's results of operations, cash flows, or statement of financial position.

ASU 2018-17 — In October 2018, the FASB issued ASU No.

2018-17, Consolidations (Topic 810):

Targeted Improvements to Related Party Guidance for Variable Interest Entities , or ASU No.

2018-17, in response to stakeholders’ observations that Topic 810, Consolidations , could be improved thereby improving general purpose financial reporting.

Specifically, ASU No.

2018-17 requires application of the variable interest entity (VIE) guidance to private companies under common control and consideration of indirect interest held through related parties under common control for determining whether fees paid to decision makers and service providers are variable interests.

The Company adopted the amendments effective January 1, 2020 using the retrospective approach.

The adoption did not have a material impact on the Company's results of operations, cash flows, or statement of financial position.

ASU 2018-15 — In August 2018, the FASB issued ASU No.

2018-15, Intangibles – Goodwill and Other – Internal-Use Software (Subtopic 350-40):

Customer’s Accounting for Implementation Costs Incurred in Cloud Computing Arrangement That Is a Service Contract , or ASU No.

The amendments in ASU No.

2018-15 align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing costs incurred to develop or obtain internal-use software (and hosting arrangement that include an internal-use software license).

The amendment also requires the customer to amortize the capitalized implementation costs of a hosting arrangement that is a service contract over the term of the hosting arrangement.

The Company adopted the amendments effective January 1, 2020 using the prospective approach.

The adoption did not have a material impact on the Company's results of operations, cash flows, or statement of financial position.

ASU 2018-13 — In August 2018, the FASB issued ASU No.

2018-13, Fair Value Measurement (Topic 820):

Disclosure Framework - Changes to the Disclosure Requirement for Fair value Measurement) , or ASU No.

The amendments in ASU No.

2018-13 eliminate such disclosures as the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy and add new disclosure requirements for Level 3 measurements.

The Company adopted the amendments

effective January 1, 2020.

Certain disclosures in ASU No.

2018-13 were applied on a retrospective basis and others on a prospective basis as required.

As the amendments contemplates changes in disclosures only, it did not have an impact on the Company's results of operations, cash flows, or statement of financial position.

ASU 2016-13 — In June 2016, the FASB issued ASU No.

2016-13, Financial Instruments - Credit Losses (Topic 326):

Measurement of Credit Losses on Financial Statements, or ASU No.

2016-13, which was further amended through various updates issued by the FASB thereafter.

The guidance in ASU No.

2016-13 provides a new model for recognizing credit losses on financial assets carried at amortized cost using an estimate of expected credit losses, instead of the "incurred loss" methodology previously required for recognizing credit losses that delayed recognition until it was probable that a loss was incurred.

The estimate of expected credit losses is to be based on consideration of past events, current conditions and reasonable and supportable forecasts of future conditions.

The Company adopted the standard and its subsequent corresponding updates effective January 1, 2020 using the modified retrospective approach.

Results for the reporting periods after January 1, 2020 are presented under Topic 326 while prior period amounts continue to be reported in accordance with previously applicable GAAP.

The Company's adoption of Topic 326 did not have a material impact on the Company's results of operations, cash flows, or statement of financial position.

Recent Accounting Developments - Guidance Not Yet Adopted

ASU 2020-06 — In August 2020, the FASB issued ASU No.

2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40) , or ASU No.

The guidance in ASU 2020-06 reduces the number of accounting models for convertible debt instruments and convertible preferred stock.

In addition, ASU 2020-06 improves and amends the related earnings per share guidance.

This standard is effective for fiscal years beginning after December 15, 2021, and interim periods within those fiscal years.

Early adoption is permitted in fiscal years beginning after December 15, 2020, including interim periods within those fiscal years.

The Company is currently in the process of assessing the impact of this guidance on the consolidated financial statements and disclosures related to earnings per share.

ASU 2019-12 — In December 2019, the FASB issued ASU No.

2019-12, Income Taxes (Topic 740):

Simplifying the Accounting for Income Taxes, or ASU No.

2019-12, to simplify various aspects related to accounting for income taxes.

Simplifying the Accounting for Income Taxes, or ASU 2019-12, to simplify various aspects related to accounting for income taxes.

The guidance in ASU 2019-12 amends the general principles in Topic 740 to eliminate certain exceptions for recognizing deferred taxes for investment, performing intraperiod allocation and calculating income taxes in interim periods.

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ASU 2019-12 is effective for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years.

The Company does not believe that the adoption of this ASU will have a material impact on the Company's results of operations, cash flows, or statement of financial position.

The Company adopted the amendments effective January 1, 2021 using the prospective approach.

The adoption did not have a material impact on the Company's results of operations, statements of cash flows, or statement of financial position.

ASU 2021-10 — In November 2021, the FASB issued ASU 2021-10, Government Assistance (Topic 832):

Disclosures by Business Entities about Government Assistance , which requires additional disclosures for transactions with a government accounted for by applying a grant or contribution model by analogy, including:

(i) the nature of the transactions and the related accounting policy used to account for the transactions;

(ii) the line items on the balance sheet and income statement that are affected by the transactions, and the amounts applicable to each financial statement line item;

and (iii) significant terms and conditions of the transactions, including commitments and contingencies.

The amendments were applied prospectively to all transactions within the scope of the amendments.

Early application of the new standard is permitted and the effect of the new standard only impacted the Company’s financial statement disclosures.

Recent Accounting Developments - Guidance Not Yet Adopted

ASU 2020-06 — In August 2020, the FASB issued ASU No.

2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40) , or ASU 2020-06.

The guidance in ASU 2020-06 reduces the number of accounting models for convertible debt instruments and convertible preferred stock.

In addition, ASU 2020-06 improves and amends the related earnings per share guidance.

This standard is effective for fiscal years beginning after December 15, 2021.

The Company adopted this standard on January 1, 2022 using the modified retrospective approach.

As a result of the provisions of the amended guidance, the Company estimates a $ 100 million decrease to additional paid-in capital, a $ 57 million decrease to debt discount, a $ 57 million increase to retained earnings, and a $ 14 million decrease to long-term deferred tax liabilities.

The Company does not expect the adoptions of ASU 2020-06 to have a material impact on its statement of operations, statements of cash flows or earnings per share amounts.

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.

Under current GAAP, an acquirer generally recognizes assets acquired and liabilities assumed in a business combination, including contract assets and contract liabilities arising from revenue contracts with customers and other similar contracts that are accounted for in accordance with ASC 606, Revenue from Contracts with Customers , or ASC 606, at fair value on the acquisition date.

ASU 2021-08 requires that an entity recognize and measure contract assets and contract liabilities acquired in a business combination in accordance with ASC 606.

At the acquisition date, an acquirer should account for the related revenue contracts in accordance with ASC 606 as if it had originated the contracts, which should generally result in an acquirer recognizing and measuring the acquired contract assets and contract liabilities consistent with how they were recognized and measured in the acquiree’s financial statements.

This update also provides certain practical expedients for acquirers when recognizing and measuring acquired contract assets and contract liabilities from revenue contracts in a business combination.

The amendments in this update are effective for fiscal years beginning after December 15, 2022, including interim periods within those fiscal years and should be applied prospectively to business combinations occurring on or after the effective date of the amendments.

Early adoption is permitted, including adoption in an interim period.

Adoption during an interim period requires retrospective application to all business combinations for which the acquisition date occurs on or after the beginning of the fiscal year that includes the interim period of early application and prospectively to all business combinations that occur on or after the date of initial application.

The Company does not expect the adoption of ASU 2021-08 to have a material impact on the consolidated financial statements and disclosures.

Note 3 — Revenue Recognition

Revenue from Contracts with Customers

On January 1, 2018, the Company adopted the guidance in ASC 606, Revenue from Contracts with Customers, or ASC 606, using the modified retrospective method applied to contracts that were not completed as of the adoption date.

The Company recognized the cumulative effect of initially applying the new standard as a credit to the opening balance of accumulated deficit, resulting in a decrease of $ 15 million.

The adjustment primarily related to costs incurred to obtain a contract with customers and customer incentives.

Following the adoption of the new standard, the Company’s revenue recognition of its contracts with customers remains materially consistent with its historical practice.

The Company's policies with respect to its various revenue streams are detailed below.

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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.

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.

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Financial transactions used to hedge the sale of electricity are recorded net within operating 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.

Capacity Revenue

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Performance Obligations

As of December 31, 2020, estimated future fixed fee performance obligations are $ 668 million, $ 289 million, $ 47 million, $ 36 million and $ 20 million for fiscal years 2021, 2022, 2023, 2024 and 2025, respectively.

As of December 31, 2021, estimated future fixed fee performance obligations are $ 258 million, $ 48 million and $ 1 million for fiscal years 2022, 2023 and 2024, respectively.

These performance obligations are for cleared auction MWs in the PJM, ISO-NE, NYISO and MISO capacity auctions and are subject to penalties for non-performance.

Renewable Energy Credits

Renewable energy credits are usually sold through long-term contracts.

Revenue from the sale of self-generated RECs is recognized when related energy is generated and simultaneously delivered even in cases where there is a certification lag as it has been deemed to be perfunctory.

In a bundled contract to sell energy, capacity and/or self-generated RECs, all performance obligations are deemed to be delivered at the same time and hence, timing of recognition of revenue for all performance obligations is the same and occurs over time.

In such cases, it is often unnecessary to allocate transaction price to multiple performance obligations.

Sale of Emission Allowances

The Company records its inventory of emission allowances as part of intangible assets.

From time to time, management may authorize the transfer of emission allowances in excess of expected 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.

Disaggregated Revenue

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(In millions)

Texas East West/Other Corporate/Eliminations Total

Texas East West/Services/Other Corporate/Eliminations Total

Retail revenue

Mass Market $ 5,027 $ 1,306 $ — $ ( 2 ) $ 6,331

Business Solutions 1,034 95 — — 1,129

$ 5,665 $ 1,959 $ 2,053 $ ( 1 ) $ 9,676

Business 2,745 9,903 1,237 — 13,885

Total retail revenue 8,410 11,862 3,290 ( 1 ) 23,561

Energy revenue (a)

Energy revenue (c)

329 508 371 7 1,215

Capacity revenue (a)

Capacity revenue (c)

— 718 57 — 775

Mark-to-market for economic hedging activities (b)

Mark-to-market for economic hedging activities (d)

( 3 ) ( 88 ) ( 86 ) 13 ( 164 )

Other revenue (a)

Contract amortization — ( 26 ) ( 4 ) — ( 30 )

Other revenue (b)(c)

1,557 59 25 ( 9 ) 1,632

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Realized and unrealized ASC 815 revenue 130 184 ( 96 ) 16 234

Contract amortization — ( 26 ) ( 4 ) — ( 30 )

Total revenue from contracts with customers $ 10,163 $ 12,874 $ 3,746 $ ( 6 ) $ 26,777

(a) The following amounts of energy, capacity and other revenue relate to derivative instruments and are accounted for under ASC 815:

(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/Other Corporate/Eliminations Total

Texas East West/Services/Other Corporate/Eliminations Total

Energy revenue $ — $ 131 $ 2 $ 3 $ 136

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Other revenue 133 ( 8 ) ( 12 ) — 113

(b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815

(d) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815

For the Year Ended December 31, 2020

(In millions)

Texas East West/Other Corporate/Eliminations Total

Texas East West/Services/Other Corporate/Eliminations Total

Retail revenue

Mass Market $ 5,027 $ 1,230 $ — $ ( 3 ) $ 6,254

Business Solutions 1,205 74 — — 1,279

$ 5,027 $ 1,210 $ 96 $ ( 2 ) $ 6,331

Business 1,034 95 — — 1,129

Total retail revenue 6,061 1,305 96 ( 2 ) 7,460

Energy revenue (a)

Energy revenue (b)

24 183 333 ( 1 ) 539

Capacity revenue (a)

Capacity revenue (b)

— 620 61 ( 1 ) 680

Mark-to-market for economic hedging activities (b)

Mark-to-market for economic hedging activities (c)

2 88 ( 3 ) 8 95

Other revenue (a)(c)

Other revenue (b)

222 62 43 ( 8 ) 319

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Total revenue from contracts with customers $ 6,279 $ 1,943 $ 475 $ ( 7 ) $ 8,690

(a) The following amounts of energy, capacity and other revenue relate to derivative instruments and are accounted for under ASC 815:

(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/Other Corporate/Eliminations Total

Texas East West/Services/Other Corporate/Eliminations Total

Energy revenue $ — $ 67 $ 43 $ ( 5 ) $ 105

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Other revenue 28 3 ( 2 ) — 29

(b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815

For the Year Ended December 31, 2019

(In millions)

Texas East West/Other Corporate/Eliminations Total

Texas East West/Services/Other Corporate/Eliminations Total

Retail revenue

Mass Market $ 4,618 $ 974 $ — $ ( 1 ) $ 5,591

Business Solutions 1,238 65 — — 1,303

$ 5,027 $ 1,173 $ 57 $ ( 3 ) $ 6,254

Business 1,205 74 — — 1,279

Total retail revenue 6,232 1,247 57 ( 3 ) 7,533

Energy revenue (a)

Energy revenue (b)

529 322 318 — 1,169

Capacity revenue (a)

Capacity revenue (b)

— 664 36 — 700

Mark-to-market for economic hedging activities (b)

Mark-to-market for economic hedging activities (c)

47 ( 29 ) 16 ( 1 ) 33

Other revenue (a)(c)

Other revenue (b)

261 58 70 ( 3 ) 386

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Total revenue from contracts with customers $ 5,507 $ 2,078 $ 411 $ ( 5 ) $ 7,991

(a) The following amounts of energy, capacity and other revenue relate to derivative instruments and are accounted for under ASC 815:

(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/Other Corporate/Eliminations Total

Texas East West/Services/Other Corporate/Eliminations Total

Energy revenue $ 1,459 $ 98 $ 39 $ ( 1 ) $ 1,595

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Other revenue 56 5 12 — 73

(b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815

Contract Balances

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(a) Deferred revenues from contracts with customers for the years ended December 31, 2021 and 2020 were approximately $ 224 million and $ 31 million, respectively

The revenue recognized from contracts with customers during both years ended December 31, 2020 and 2019 relating to the deferred revenue balance at the beginning of each period was $ 13 million.

The revenue recognized from contracts with customers during the years ended December 31, 2021 and 2020 relating to the deferred revenue balance at the beginning of each period was $ 23 million and $ 13 million, respectively.

The change in deferred revenue balances during the years ended December 31, 2021 and 2020 was primarily due to the timing difference of when consideration was received and when the performance obligation was transferred.

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Direct Energy Acquisition

On January 5, 2021 (the "Acquisition Closing Date"), the Company acquired all of the issued and outstanding common shares of Direct Energy, a North American subsidiary of Centrica plc.

On January 5, 2021 (the "Acquisition Closing Date"), 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.

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The Company funded the purchase price using a combination of $ 715 million of cash on hand, $ 166 million from a draw on its Revolving Credit Facility (of which $ 107 million was used to fund acquisition costs and financing fees that are not included in the aggregate purchase price above) as well as approximately $ 2.9 billion in secured and unsecured corporate debt issued in December 2020.

The final purchase price adjustment resulted in additional payment of $ 22 million, which was paid in December 2021.

The Company also increased its collective collateral facilities by $ 3.4 billion as of the Acquisition Closing Date to meet the additional liquidity requirements related to the acquisition, as detailed in the following table:

(In millions) December 31, 2020

Revolving Credit Facility commitment increase (a)

Revolving Credit Facility new tranche (a)

(In millions)

Available on Acquisition Closing Date

Revolving Credit Facility commitment increase $ 802

Revolving Credit Facility new tranche 273

Facility agreement in connection with the sale of pre-capitalized trust securities 874

Available as of December 31, 2020

Credit default swap facility 150

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Repurchase facility 75

Facility agreement in connection with the sale of pre-capitalized trust securities (a)

Bilateral letter of credit facilities 475

Total Increases to Liquidity and Collateral Facilities $ 3,399

(a) Available upon the Acquisition Closing Date

For further discussion see Note 13, Receivables Securitization and Repurchase Facility and Note 14, Long-term Debt and Finance Leases .

Acquisition costs of $ 17 million for the year ended December 31, 2020 are included in selling, general and administrative costs in the Company's consolidated statement of operations.

The acquisition will be recorded as a business combination under ASC 805, with identifiable assets acquired and liabilities assumed provisionally recorded at their estimated fair values on the acquisition date.

The initial accounting for the business combination is not complete because the evaluation necessary to assess the fair value of certain net assets acquired and the amount of goodwill to be recognized are still in process.

The provisional amounts are subject to revision until the evaluations are completed to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date.

The purchase price is provisionally allocated as follows:

For further discussion see Note 13, Long-term Debt and Finance Leases .

Acquisition costs of $ 25 million and $ 17 million for the years ended December 31, 2021 and 2020, 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 acquired and liabilities assumed recorded at their estimated fair values on the acquisition date.

The purchase price is allocated as follows:

(In millions)

Cash and cash equivalents $ 152

Current Assets

Property, plant and equipment 166

Goodwill and other intangibles (a)

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

Intangible assets, net:

Customer relationships (b)

Customer and supply contracts (b)

Trade names (b)

Renewable energy credits 124

Total intangible assets, net 2,321

Derivative instruments 531

Other non-current assets 31

Total assets acquired 7,825

Total other assets 4,133

Total Assets $ 7,794

(In millions)

Current Liabilities

Non-current liabilities 1,038

Total liabilities assumed 4,123

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 is 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 expected to be deductible for tax purposes is $ 322 million

(b) The weighted average amortization period for total amortizable intangible assets is 12 years

Measurement Period Adjustments

The following measurement period adjustments were recognized during the quarter ended December 31, 2021:

(In millions)

Prepayments and other current assets $ ( 10 )

Goodwill ( 7 )

Total decrease in assets $ ( 17 )

Accounts payable $ ( 4 )

Accrued expenses and other current liabilities ( 20 )

Deferred income taxes ( 18 )

Total decrease in liabilities $ ( 42 )

Net measurement period adjustments $ 25

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

Fair Value Measurement of Intangible Assets

The fair values of intangible assets as of the Acquisition Closing Date were measured primarily based on significant inputs that are observable and unobservable in the market and thus represent Level 2 and Level 3 measurements, respectively.

Significant inputs were as follows:

Customer relationships — Customer relationships, reflective of Direct Energy’s customer base, were valued using an excess earning method of the income approach.

Under this approach, the Company estimated the present value of expected future cash flows resulting from existing customer relationships, considering attrition and charges for contributory assets (such as net working capital, fixed assets, workforce and trade names) utilized in the business, discounted at an independent power producer peer group’s weighted average cost of capital.

The customer relationships are amortized to depreciation and amortization, ratably based on discounted future cash flows.

The weighted average amortization period is 12 years.

Customer and supply contracts — The fair value of in-market and out-of-market customer and supply contracts were estimated based on contractual terms compared to market prices as of the Acquisition Closing Date.

The majority of the contracts were valued using prices provided by external sources, primarily price quotations available through broker or over-the-counter and online exchanges.

For contracts for which external sources or observable market quotes were not available, these values were based on valuation techniques including, but not limited to, internal models based on fundamental analysis of the market and extrapolation of the observable market data with similar characteristics.

In addition, the Company applied a credit reserve to reflect credit risk, which is calculated based on published default probabilities.

The customer and supply contracts are amortized to revenue and cost of operations, respectively, based upon the fair market value, as of the acquisition date, for each delivery month.

The weighted average amortization period is 14 years.

Trade names — Trade names were valued using a "relief from royalty" method of the income approach.

Under this approach, the fair value is estimated to be the present value of royalties saved because NRG owns the intangible asset and therefore does not have to pay a royalty for its use.

The trade names are amortized to depreciation and amortization, on a straight line basis, over a weighted average amortization period of 15 years.

Renewable energy credits — Renewable energy credits were valued based on the market prices as of the Acquisition Closing Date.

Renewable energy credits are retired, as required, for the applicable compliance period.

They are expensed to cost of operations based on customer usage.

Fair Value Measurement of Derivative Assets and Liabilities

The fair values of derivatives assets and liabilities as of the Acquisition Closing Date were as follows:

(In millions) Total Level 1 Level 2 Level 3

Derivatives assets

$ 1,545 $ 155 $ 1,272 $ 118

Derivatives liabilities 1,828 207 1,489 132

Refer to Note 5 , Fair Value of Financial Instruments for discussion on derivative fair value measurements.

Supplemental Information

For the Year Ended December 31, 2021 Direct Energy contributed revenue and income before income taxes of $ 15.6 billion and $ 2.4 billion, respectively.

Supplemental Unaudited Pro Forma Financial Information

The following table provides unaudited pro forma combined financial information of NRG and Direct Energy, after giving effect to the Direct Energy acquisition and related financing transactions as if they had occurred on January 1, 2019.

The pro forma financial information has been prepared for illustrative and informational purposes only, and is not intended to project future operating results or indicative of what our financial performance would have been had the transactions occurred on the date assumed.

No effect has been given to operating synergies.

For the Year Ended December 31,

(In millions) 2021 2020 2019

Total operating revenues $ 26,987 $ 21,326 $ 23,673

Income from continuing operations 2,225 471 3,623

Amounts above reflect certain pro forma adjustments that were directly attributable to the Direct Energy 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, depreciation of property, plant and equipment and lease expense.

(ii) Interest expense assumes the financing transactions directly attributable to the Direct Energy acquisition occurred on January 1, 2019.

(iii) Removal of Direct Energy historical interest expense associated with related party notes receivable/payable between Direct Energy and Centrica and its subsidiaries, as those notes are assumed to be repaid as of January 1, 2019.

(iv) Elimination of transactions between NRG and Direct Energy.

(v) Adjustments to reflect all acquisition costs occurring during the year ended December 31, 2019.

(vi) Tax effects of pro forma adjustments on all periods presented and shifting the recognition of one time tax benefits resulting from the acquisition from the year ended December 31, 2021 to the year ended December 31, 2019.

Midwest Generation Lease Purchase — On September 29, 2020, Midwest Generation acquired all of the ownership interests in the Powerton facility and Units 7 and 8 of the Joliet facility, which were being leased through 2034 and 2030, respectively, for approximately $ 260 million.

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Goodwill of $ 5 million and $ 1 million was assigned to the Texas and East segments, respectively, and is not deductible for tax purposes

XOOM Energy Acquisition — On June 1, 2018, the Company completed the acquisition of XOOM Energy, LLC, an electricity and natural gas retailer operating in 19 states, Washington, D.C.

and Canada, for approximately $ 213 million, including working capital and other adjustments of $ 48 million.

The acquisition increased NRG's retail portfolio by approximately 395,000 RCEs or 300,000 customers.

The purchase price was allocated as follows:

(In millions)

Net current and non-current working capital $ 46

Other intangible assets 133

XOOM Purchase Price $ 213

(a) Goodwill arising from the acquisition is attributed to the value of the platform acquired and the synergies expected from combining the operations of XOOM Energy with NRG's existing businesses.

Goodwill of $ 28 million and $ 6 million was assigned to the Texas and East segments, respectively, and is deductible for tax purposes

Small Book Acquisitions — In 2020, the Company acquired multiple books of customers totaling approximately 56,000 customers for $ 22 million.

During 2019, the Company acquired several books of customers totaling approximately 72,000 customers for $ 17 million, of which $ 13 million was paid in 2019.

During 2018, the Company acquired several books of customers totaling approximately 115,000 customers, along with brand names, for $ 44 million, of which $ 40 million was paid in 2018 and $ 2 million was paid in 2019.

The majority of the purchase price for the 2020, 2019 and 2018 book acquisitions were allocated to acquired intangible assets.

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 $ 137 million, resulting in net proceeds of $ 623 million.

The Company recorded a gain of $ 210 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.

Sale of Home Solar

In the third quarter of 2020, the Company concluded its Home Solar business was held for sale and recorded an impairment loss of $ 29 million, as further discussed in Note 11, Asset Impairments .

On November 13, 2020, the Company completed the sale of the Home Solar business for cash proceeds of $ 66 million, resulting in a $ 2 million loss on the sale.

In connection with the sale, the Company extinguished debt of $ 27 million and recognized a $ 5 million loss on the extinguishment.

Company completed other asset sales for cash proceeds of $ 12 million and $ 15 million during the years ended December 31, 2021 and 2020, respectively.

Discontinued Operations

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On February 4, 2019, the Company completed the sale of its South Central Portfolio to Cleco for cash consideration of $ 1 billion excluding working capital and other adjustments.

The Company concluded that the divested business met the criteria for discontinued operations, as the disposition represents a strategic shift in the business in which NRG operates and held-for-sale criteria as of December 31, 2018.

As such, all prior period results for the operations of the South Central Portfolio were reclassified as discontinued operations at December 31, 2018.

The Company concluded that the divested business met the criteria for discontinued operations, as the disposition represented a strategic shift in the business in which NRG operates.

In connection with the transaction, NRG also entered into a transition services agreement to provide certain corporate services to the divested business, which have been substantially completed in 2020.

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Due to its continuing involvement with the Cottonwood facility, NRG did not use held-for-sale or discontinued operations treatment in accounting for the Cottonwood facility.

Summarized results of South Central discontinued operations were as follows:

Year Ended December 31,

Summarized results of South Central discontinued operations for the year ended December 31, 2019 were as follows:

(In millions)

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Operating costs and expenses ( 23 )

Other income — 2

Gain from operations of discontinued components 8

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The Company concluded that the divested businesses met the criteria for discontinued operations, as the dispositions represented a strategic shift in the business in which NRG operates.

As such, all prior period results for the transaction were reclassified as discontinued operations.

In connection with the transaction, NRG entered into a transition services agreement to provide certain corporate services to the divested businesses in 2018, which concluded in 2020.

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Summarized results of NRG Yield, Inc.

and Renewables Platform and Carlsbad discontinued operations were as follows:

and Renewables Platform and Carlsbad discontinued operations for the year ended December 31, 2019 were as follows:

(In millions)

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Other expenses ( 5 )

Gain/(loss) from operations of discontinued components, before tax 5 74

Income tax expense — 4

Gain/(loss) from discontinued operations, net of tax 5

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Income/(loss) from discontinued operations, net of tax $ 296

Sale of Assets to NRG Yield, Inc.

Prior to Discontinued Operations

On June 19, 2018, the Company completed the UPMC Thermal Project and received cash consideration from NRG Yield of $ 84 million, plus an additional $ 3 million received at final completion in January 2019.

On March 30, 2018, as part of the Transformation Plan, the Company sold to NRG Yield, Inc.

100 % of NRG's interests in Buckthorn Renewables, LLC, which owns a 154 MW construction-stage utility-scale solar generation project, located in Texas.

NRG Yield, Inc.

paid cash consideration of approximately $ 42 million, excluding working capital adjustments, and assumed non-recourse debt of $ 183 million.

On June 14, 2017, the GenOn Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court.

As a result of the bankruptcy filings, NRG concluded that it no longer controlled GenOn as it was subject to the control of the Bankruptcy Court;

On June 14, 2017, the GenOn Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Texas Bankruptcy Court.

As a result of the bankruptcy filings, NRG concluded that it no longer controlled GenOn as it was subject to the control of the Texas Bankruptcy Court;

and accordingly, NRG deconsolidated GenOn and its subsidiaries for financial reporting purposes as of such date.

By eliminating a large portion of its operations in the PJM market with the deconsolidation of GenOn, NRG concluded that GenOn met the criteria for discontinued operations, as this represented a strategic shift in the business in which NRG operated.

As such, all prior period results for GenOn were reclassified in 2017 as discontinued operations.

Summarized results of discontinued operations were as follows:

Year Ended December 31,

(In millions) 2019 2018

Interest income - affiliate $ — $ 3

Income/(loss) from discontinued operations, net of tax — 3

Settlement consideration, insurance and services credit — 63

Pension and post-retirement liability assumption — 21

Other ( 3 ) ( 53 )

(Loss)/income on disposal of discontinued operations, net of tax ( 3 ) 31

(Loss)/income from discontinued operations, net of tax $ ( 3 ) $ 34

GenOn Settlement and Plan Confirmation

Effective July 16, 2018, NRG and GenOn consummated the GenOn Settlement whereby the Company paid GenOn approximately $ 125 million, which included (i) the settlement consideration of $ 261 million, (ii) the transition services credit of $ 28 million and (iii) the return of $ 15 million of collateral posted to NRG;

offset by the (i) $ 151 million in borrowings under the intercompany secured revolving credit facility, (ii) related accrued interest and fees of $ 12 million, (iii) remaining payments due under the transition services agreement of $ 10 million, (iv) $ 4 million reduction of the settlement payment related to NRG assigning to GenOn approximately $ 8 million of historical claims against REMA and (v) certain other balances due to NRG totaling $ 2 million.

GenOn's plan of reorganization was confirmed on December 14, 2018.

Pursuant to the confirmed plan, NRG retained the pension liability for GenOn employees for service provided prior to the completion of the reorganization.

NRG also retained the liability for GenOn's post-employment and retiree health and welfare benefits.

As a result of GenOn's emergence from bankruptcy, NRG took a deduction for GenOn tax losses of $ 9.5 billion, including a worthless stock deduction.

Other than those obligations which survive or are independent of the releases described herein, the GenOn Settlement and the GenOn Chapter 11 plan provide NRG releases from GenOn and each of its debtor and non-debtor subsidiaries.

REMA Plan of Reorganization

On October 16, 2018, REMA and its subsidiaries filed voluntary petitions for chapter 11 relief and a prepackaged plan of reorganization in the United States Bankruptcy Court for the Southern District of Texas.

The REMA debtors' plan of reorganization has been formally accepted by REMA's voting creditors and is consistent with the releases NRG received under the GenOn Settlement and the GenOn plan.

GenMA Settlement

The Bankruptcy Court order confirming the plan of reorganization also approved the settlement terms agreed to among the GenOn Entities, NRG, the Consenting Holders, GenOn Mid-Atlantic, and certain of GenOn Mid-Atlantic’s stakeholders, or the GenMA Settlement, and directed the settlement parties to cooperate in good faith to negotiate definitive documentation consistent with the GenMA Settlement term sheet in order to pursue consummation of the GenMA Settlement.

The definitive documentation effectuating the GenMA Settlement was finalized and effective as of April 27, 2018.

Certain terms of the compromise with respect to NRG and GenOn Mid-Atlantic are as follows:

• Settlement of all pending litigation and objections to the Plan (including with respect to releases and feasibility);

• NRG provided $ 38 million in letters of credit as new qualifying credit support to GenOn Mid-Atlantic;

such letters of credit were never drawn and were returned and canceled on December 17, 2019 and

• NRG paid approximately $ 6 million as reimbursement of professional fees incurred by certain of GenOn Mid-Atlantic's stakeholders in connection with the GenMA Settlement.

On February 28, 2021, the Company entered into a definitive purchase agreement with Generation Bridge, an affiliate of ArcLight Capital Partners, to sell approximately 4,850 MWs of fossil generating assets from its East and West regions of operations for total proceeds of $ 760 million, subject to standard purchase price adjustments and certain other indemnifications.

As part of the transaction, NRG is entering into a tolling agreement for its 866 MW Arthur Kill plant in New York City through April 2025.

The transaction is expected to close in the fourth quarter of 2021, and is subject to various closing conditions, approvals and consents, including FERC, NYSPSC, and antitrust review under Hart-Scott-Rodino.

On November 19, 2020, the Company entered an agreement to sell its 35 % ownership in Agua Caliente to Clearway Energy for $ 202 million.

The sale of the solar project closed on February 3, 2021.

In the third quarter of 2020, the Company concluded its Home Solar business was held for sale and recorded an impairment loss of $ 29 million, as further discussed in Note 11, Asset Impairments .

On November 13, 2020, the Company completed the sale of the Home Solar business for cash proceeds of $ 66 million, resulting in a $ 2 million loss on the sale.

In connection with the sale, the Company extinguished debt of $ 27 million and recognized a $ 5 million loss on the extinguishment.

On August 1, 2018, the Company completed the sale of 100 % of its ownership interests in BETM to Diamond Energy Trading and Marketing, LLC for $ 71 million, net of working capital adjustments, which resulted in a gain of $ 15 million on the sale.

The sale also resulted in the release and return of approximately $ 119 million of letters of credit, $ 32 million of parent guarantees, and $ 4 million of net cash collateral to NRG.

On June 29, 2018, the Company completed the sale of Canal 3 to Stonepeak Kestrel for cash proceeds of approximately $ 16 million and recorded a gain of $ 17 million.

Prior to the sale, Canal 3 entered into a financing arrangement and received cash proceeds of $ 167 million, of which $ 151 million was distributed to the Company.

The related debt was non-recourse to NRG and was transferred to Stonepeak Kestrel in connection with the sale of Canal 3.

The Company entered into a project management agreement in 2018 to manage construction of Canal 3 and substantial completion was reached in June 2019.

The Company completed other asset sales for cash proceeds of $ 15 million and $ 22 million during the years ended December 31, 2020 and 2019, respectively.

For the Year Ended December 31, 2019 NRG recorded $ 3 million loss from discontinued operations, net of tax for GenOn results of operations.

Note 5 — 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 posted 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 values and fair values of the Company's recorded financial instruments not carried at fair market value are as follows:

For cash and cash equivalents, funds deposited by counterparties, restricted cash, accounts and other receivables, accounts payable, restricted cash, and cash collateral paid and received in support of energy risk management activities, the carrying amount 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:

As of December 31,

(In millions) Carrying Amount Fair Value Carrying Amount Fair Value

Notes receivable $ 2 $ 2 $ 11 $ 8

Long-term debt, including current portion (a)

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The fair value of the Company's publicly-traded long-term debt is based on quoted market prices and is 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, 2020 and 2019:

As of December 31, 2020 As of December 31, 2019

(In millions) Level 2 Level 3 Level 2 Level 3

Long-term debt, including current portion $ 9,446 $ — $ 6,388 $ 116

Fair Value Accounting under ASC 820

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Foreign government fixed income securities 4 — 4 —

Other trust fund investments:

Other trust fund investments (classified within other non-current assets):

government and federal agency obligations 1 1 — —

Derivative assets:

Foreign exchange contracts 1 — 1 —

Commodity contracts 7,139 981 5,701 457

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Equity securities-nuclear trust fund investments 99

Equity securities 8 — — —

Equity securities (classified within other non-current assets) 7

$ 8,188 $ 1,635 $ 5,990 $ 457

Derivative liabilities:

Foreign exchange contracts $ 1 $ — $ 1 $ —

Commodity contracts

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Foreign government fixed income securities 7 1 6 —

Other trust fund investments:

Other trust fund investments (classified within other non-current assets):

government and federal agency obligations 1 1 — —

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Equity securities-nuclear trust fund investments 87

Equity securities 8 — — —

Equity securities (classified within other non-current assets) 8

Total assets $ 1,745 $ 597 $ 914 $ 139

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Beginning balance as of January 1, 2021 $ ( 16 )

Total (losses) — realized/unrealized included in earnings

Purchases ( 13 )

Contracts added from Direct Energy acquisition

Total gains realized/unrealized included in earnings

Transfers into Level 3 (b)

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Fair Value Measurement Using Significant Unobservable Inputs (Level 3)

(In millions) Debt

Derivatives (a)

(In millions) Derivatives (a)

Beginning balance as of January 1, 2020 $ 38

Contracts added from acquisitions

— ( 3 ) $ ( 3 )

Total (losses) realized/unrealized included in earnings

— ( 26 ) ( 26 )

Purchases ( 13 )

Sale ( 19 ) — ( 19 )

Transfers into Level 3 (b)

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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, 2020

$ — $ 17 $ 17

(a) Consists of derivatives assets and liabilities, net

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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 interest rate swaps is calculated utilizing the bilateral method based on published default probabilities.

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 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, 2020 the credit reserve resulted in a $ 2 million increase primarily within cost of operations.

As of December 31, 2019 the credit reserve did not result in a significant change in fair value in operations revenue and cost of operations.

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, 2021 the credit reserve resulted in a $ 11 million decrease primarily within cost of operations.

As of December 31, 2020 the credit reserve resulted in $ 2 million increase primarily within cost of operations.

The fair values in each category reflect the level of forward prices and volatility factors as of December 31, 2021, and may change as a result of changes in these factors.

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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 power executed in illiquid markets as well as financial transmission rights, or FTRs.

The significant unobservable inputs used in developing fair value include illiquid power location pricing which is derived as a basis to liquid locations.

NRG's significant positions classified as Level 3 include physical and financial natural gas and power executed in illiquid markets as well as financial transmission rights, or FTRs.

The significant unobservable inputs used in developing fair value include illiquid natural gas and power location pricing which is derived as a basis to liquid locations.

The basis spread is based on observable market data when available or derived from historic prices and forward market prices from similar observable markets when not available.

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(In millions) Assets Liabilities Valuation Technique Significant Unobservable Input Low High Weighted Average

Natural Gas Contracts $ 16 $ 1 Discounted Cash Flow Forward Market Price (per MMBtu) $ 3 $ 40 $ 15

Power Contracts 392 121 Discounted Cash Flow Forward Market Price (per MWh) 3 212 35

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Significant Unobservable Input Position Change In Input Impact on Fair Value Measurement

Forward Market Price Power Buy Increase/(Decrease) Higher/(Lower)

Forward Market Price Power Sell Increase/(Decrease) Lower/(Higher)

Forward Market Price Natural Gas/ Power Buy Increase/(Decrease) Higher/(Lower)

Forward Market Price Natural Gas/Power Sell Increase/(Decrease) Lower/(Higher)

FTR Prices Buy Increase/(Decrease) Higher/(Lower)

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Counterparty Credit Risk

As of December 31, 2020, counterparty credit exposure, excluding credit exposure from RTOs, ISOs, and registered commodity exchanges and certain long-term agreements, was $ 210 million and NRG held collateral (cash and letters of credit) against those positions of $ 14 million, resulting in a net exposure of $ 204 million.

As of December 31, 2021, counterparty credit exposure, excluding credit exposure from RTOs, ISOs, and registered commodity exchanges and certain long-term agreements, was $ 2.2 billion and NRG held collateral (cash and letters of credit) against those positions of $ 598 million, resulting in a net exposure of $ 1.6 billion.

NRG periodically receives collateral from counterparties in excess of their exposure.

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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

The Company currently has $ 47 million exposure to two wholesale counterparties in excess of 10 % of the total net exposure discussed above as of December 31, 2020.

The Company currently has no exposure to wholesale counterparties in excess of 10 % of the total net exposure discussed above as of December 31, 2021.

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.

During Winter Storm Uri, the Company experienced nonperformance by a counterparty in one of its bilateral financial hedging transactions, resulting in exposure of $ 403 million.

The Company is pursuing all means available to enforce its rights under this transaction but, given the size of the exposure, cannot determine with certainty what the amount of its ultimate recovery will be.

The full exposure was recorded as a provision for credit losses during the year ended December 31, 2021.

RTOs and ISOs

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Exchange Traded Transactions

The Company enters into commodity transactions on registered exchanges, notably ICE and NYMEX.

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.

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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, 2020, aggregate credit risk exposure managed by NRG to these counterparties was approximately $ 645 million for the next five years.

Based on these valuation techniques, as of December 31, 2021, aggregate credit risk exposure managed by NRG to these counterparties was approximately $ 1.1 billion for the next five years.

Retail Customer Credit Risk

The Company is exposed to retail credit risk through the Company's retail electricity providers, which serve C&I customers and the Mass market.

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.

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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, 2020, the Company's retail customer credit exposure to C&I and Mass customers was diversified across many customers and various industries, as well as government entities.

As of December 31, 2021, 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.

The Company is also subject to risk with respect to its residential solar customers.

The Company's provision for credit losses was $ 698 million, $ 108 million, and $ 95 million for the years ending December 31, 2021, 2020, and 2019, 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 credit losses.

As a result of Winter Storm Uri, the Company incurred additional credit losses from Business customers primarily due to a segment of customers whose contracts included a pass through of wholesale power prices which were significantly escalated during the storm and from customers who failed to meet their obligations in ERCOT load curtailment programs.

Note 6 — Accounting for Derivative Instruments and Hedging Activities

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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, and interest rate swaps.

ASC 815 applies to NRG's energy related commodity contracts, foreign exchange contracts, and interest rate swaps.

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.

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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 sales from NRG's retail 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;

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 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 fuels in the future;

• Futures contracts, which are exchange-traded standardized commitments to purchase or sell a commodity or financial instrument;

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The objectives for entering into derivative contracts designated as hedges include:

• Fixing the price of a portion of anticipated power purchases for the Company's retail sales;

• 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;

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• Load-following forward electric sale contracts extending through 2036;

• Load-following forward natural gas sale contracts extending through 2032;

• Power tolling contracts through 2038;

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• Power transmission contracts through 2025;

• Natural gas transportation contracts and storage agreements through 2030;

• Natural gas transportation contracts through 2034;

• Natural gas storage agreements through 2025;

• Coal transportation contracts through 2029.

Interest Rate Swaps

NRG was exposed to changes in interest rates through the Company's issuance of variable rate debt.

In order to manage the Company's interest rate risk, NRG entered into interest rate swap agreements.

As of December 31, 2019, NRG had no interest rate derivative instruments as a result of the early termination of such contracts in connection with the repayment of the 2023 Term Loan Facility during the second quarter of 2019.

During the fourth quarter of 2020, NRG entered into $ 1.6 billion of interest rate hedges associated with anticipated certain financing needs.

As of December 31, 2020, the interest rate hedges were settled in connection with the issuance of fixed rate debt, resulting in a gain of $ 11 million that was recorded as a reduction to interest expense.

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 2025.

Volumetric Underlying Derivative Transactions

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Natural Gas MMBtu 813 ( 286 )

Oil Barrels 1 —

Power MWh 185 57

Capacity MW/Day — ( 1 )

Foreign Exchange Dollars 279 —

The increase in positions is primarily the result of Direct Energy acquisition.

Fair Value of Derivative Instruments

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Derivatives Not Designated as Cash Flow or Fair Value Hedges :

Foreign exchange contracts - current $ — $ — $ 1 $ —

Foreign exchange contracts - long-term 1 — — —

Commodity contracts- current 4,613 560 3,386 499

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As of December 31, 2021

Foreign exchange contracts:

Derivative assets $ 1 $ ( 1 ) $ — $ —

Derivative liabilities ( 1 ) 1 — —

Total foreign exchange contracts $ — $ — $ — $ —

Commodity contracts:

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Total commodity contracts $ 2,341 $ — $ ( 814 ) $ 1,527

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

Gross Amounts Not Offset in the Statement of Financial Position

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Total commodity contracts $ ( 63 ) $ — $ ( 5 ) $ ( 68 )

Accumulated Other Comprehensive Income

The following table summarizes the effects on NRG's accumulated OCI balance attributable to cash flow hedge derivatives, net of tax, for the year 2018:

Interest Rate Contracts

(In millions) 2018

Accumulated OCI beginning balance $ ( 54 )

Reclassified from accumulated OCI to income:

Due to realization of previously deferred amounts 8

Mark-to-market of cash flow hedge accounting contracts 21

Sale of NRG Yield and Renewables 25

Accumulated OCI ending balance $ —

Amounts reclassified from accumulated OCI into income were recorded in discontinued operations.

Impact of Derivative Instruments on the Statement of Operations

Unrealized gains and losses associated with changes in the fair value of derivative instruments not accounted for as cash flow hedges are reflected in current period earnings.

Unrealized gains and losses associated with changes in the fair value of derivative instruments not accounted for as cash flow hedges are reflected in current period results of operations.

The following table summarizes the pre-tax effects of economic hedges that have not been designated as cash flow hedges or fair value hedges and trading activity on the Company's statement of operations.

The effect of commodity hedges is included within operating revenues and cost of operations and the effect of interest rate hedges is included in interest expense.

The effect of foreign exchange and commodity hedges is included within operating revenues and cost of operations and the effect of interest rate hedges is included in interest expense.

Year Ended December 31,

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$ ( 41 ) $ ( 55 ) $ ( 68 )

Reversal of acquired loss/(gain) positions related to economic hedges

Net unrealized (losses)/gains on open positions related to economic hedges

Total unrealized mark-to-market (losses)/gains for economic hedging activities

Reversal of acquired loss positions related to economic hedges

Net unrealized gains/(losses) on open positions related to economic hedges

2,501 ( 68 ) 42

Total unrealized mark-to-market gains/(losses) for economic hedging activities

2,716 ( 119 ) ( 20 )

Reversal of previously recognized unrealized (gains) on settled positions related to trading activity

( 18 ) ( 20 ) ( 11 )

Net unrealized gains on open positions related to trading activity

Reversal of acquired (gain) positions related to trading activity

Net unrealized (losses)/gains on open positions related to trading activity

Total unrealized mark-to-market (losses)/gains for trading activity ( 32 ) ( 5 ) 20

Total unrealized (losses)/gains $ ( 124 ) $ — $ 31

Total unrealized gains/(losses) $ 2,684 $ ( 124 ) $ —

Year Ended December 31,

(In millions) 2021 2020 2019

Unrealized gains/(losses) included in operating revenues

Unrealized (losses)/gains included in operating - commodities

$ ( 196 ) $ 90 $ 53

Unrealized (losses)/gains included in cost of operations ( 214 ) ( 53 ) 144

Total impact to statement of operations — energy commodities

Unrealized gains/(losses) included in cost of operations- commodities 2,880 ( 214 ) ( 53 )

Total impact to statement of operations- commodities

$ 2,684 $ ( 124 ) $ —

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$ — $ — $ ( 38 )

The reversal of gain or loss positions acquired as part of acquisitions were valued based upon the forward prices on the acquisition dates.

The reversals of acquired loss/(gain) positions were valued based upon the forward prices on the acquisition date.

The roll-off amounts were offset by realized gains or losses at the settled prices and are reflected in revenue or cost of operations during the same period.

For the year ended December 31, 2020, the $ 68 million loss from open economic hedge positions was primarily the result of a decrease in the value of forward positions as a result of decreases in ERCOT power prices and heat rate contraction, partially offset by an increase in value of forward positions as a result of decreases in New York capacity prices.

The gains from open economic hedge positions of $ 42 million and $ 97 million for the years ended December 31, 2019 and 2018, respectively, were primarily the result of an increase in the value of forward purchases of ERCOT heat rate contracts due to ERCOT heat rate expansion.

The gain from open economic hedge positions of $ 2.5 billion for the year ended December 31, 2021 was primarily the result of an increase in value of forward positions as a result of increases in natural gas and power prices.

The loss from open economic hedge positions of $ 68 million for the year ended December 31, 2020 was primarily the result of a decrease in the value of forward positions as a result of decreases in ERCOT power prices and heat rate contraction, partially offset by an increase in value of forward positions as a result of decreases in New York capacity prices.

The gain from open economic hedge positions of $ 42 million for the year ended December 31, 2019 was primarily the result of an increase in the value of forward purchases of ERCOT heat rate contracts due to ERCOT heat rate expansion.

Credit Risk Related Contingent Features

Certain of the Company's hedging agreements contain provisions that require the Company to post additional collateral if the counterparty determines that there has been deterioration in credit quality, generally termed "adequate assurance" under the agreements, or require the Company to post additional collateral if there were a downgrade in the Company's credit rating.

The collateral required for contracts that have adequate assurance clauses that are in net liability positions as of December 31, 2020 was $ 26 million.

Certain of the Company's hedging and trading agreements contain provisions that entitle the counterparty to demand that the Company post additional collateral if the counterparty determines that there has been deterioration in the Company's credit quality, generally termed “adequate assurance” under the agreements, or require the Company to post additional collateral if there were a downgrade in the Company's credit rating.

In addition, as a result of the acquisition of Direct Energy from Centrica, certain of the Company’s agreements as of December 31, 2021, were still supported by credit support posted by Centrica, and as a result could require the Company to post collateral upon a deterioration or downgrade of Centrica.

The collateral potentially required for contracts with adequate assurance clauses that are in net liability positions as of December 31, 2021 was $ 1.0 billion.

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 $ 70 million as of December 31, 2021.

If called for by the counterparty, $ 1 million of additional collateral would be required for all contracts with credit rating contingent features as of December 31, 2020.

In the event of a downgrade in the Company's credit rating and if called for by the counterparty, $ 1 million of additional collateral would be required for all contracts with credit rating contingent features as of December 31, 2021.

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

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Natural gas 206 22

Spare parts 195 196

Spare parts and finished goods 201 195

Total Inventory $ 498 $ 327

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The Company recorded long-lived asset impairments during the years ended December 31, 2021 and 2020, as further described in Note 11, Asset Impairments.

Depreciation expense of property, plant and equipment recorded during the years ended 2020, 2019 and 2018 was $ 295 million, $ 271 million and $ 356 million, respectively.

Depreciation expense of property, plant and equipment recorded during the years ended December 31, 2021, 2020 and 2019 was $ 384 million, $ 295 million and $ 271 million, respectively.

Note 10 — Leases

The Company leases generating facilities, land, office and equipment, railcars, and storefront space at retail stores.

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 right-of-use assets and lease liabilities in the consolidated balance sheets.

The Company made an accounting policy election 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.

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.

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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.

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.

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The Company has no leases which contain residual value guarantees provided by the Company as a lessee.

The Company’s leases may grant the Company an option to renew a lease for an additional term(s) or to terminate the lease after a certain period.

As part of its transition from the guidance contained in ASC 840 to the updated guidance in ASC 842, the Company elected not to use the practical expedient of using hindsight to determine the lease term and in assessing impairment of the right-of-use assets.

As permitted by ASC 842, the Company made an accounting policy election 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.

In transition to ASC 842, the Company elected to apply the effective date transition method as of the January 1, 2019 adoption date.

In accordance with this method, the Company’s reporting for comparative periods prior to January 1, 2019 presented in the financial statements continues to be in conformity with the guidance in ASC 840.

The Company elected the following practical expedients, which allow entities to:

• Not reassess whether any contracts that existed prior to the January 1, 2019 implementation date are or contain leases;

• Not reassess the lease classification for any leases that commenced prior to the January 1, 2019 implementation date, meaning that all commenced capital leases under ASC 840 will be classified as finance leases under ASC 842 and all commenced operating leases under ASC 840 will be classified as operating leases under ASC 842;

• Not reassess initial direct costs for any leases;

• Not reassess whether existing land easements, which were not previously accounted as leases under ASC 840, are or contain leases;

• Not separate lease and non-lease components for all asset classes, except office space leases and generation facilities leases.

As described in Note 4, Acquisitions, Discontinued Operations and Dispositions , upon the close of the South Central Portfolio sale in 2019, the Company entered into an agreement to leaseback the Cottonwood facility through May 2025.

The lease was accounted for in accordance with ASC 842-40, Sale and Leaseback Transactions , as an operating lease and accordingly, a right-of-use asset and lease liability were established on the lease commencement date and will be amortized through the end of the lease.

(In millions) For the Year Ended December 31, 2020 For the Year Ended December 31, 2019

For the Year Ended December 31,

(In millions) 2021 2020 2019

Finance lease cost $ 4 $ 3 $ —

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Other information:

(In millions) For the Year Ended December 31, 2020 For the Year Ended December 31, 2019

For the Year Ended December 31,

(In millions) 2021 2020 2019

Cash paid for amounts included in the measurement of lease liabilities:

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Weighted average discount rate 5.44 % 5.63 %

As of December 31, 2020, annual payments based on the maturities of NRG's leases are expected to be as follows:

(In millions)

As of December 31, 2021, annual payments based on the maturities of NRG's operating leases are expected to be as follows:

Thereafter 48

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2021 Impairment Losses

During the fourth quarter of 2021, the Company completed its annual budget and analyzed the corresponding impact on estimated cash flows associated with its long-lived assets.

The fair value of the assets was 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 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.

Joliet —The Company recognized an impairment loss of $ 213 million in the East segment as a result of changes in the long-term outlook of the Joliet facility prompted by market conditions and an assessment of various alternatives for the long-term operational landscape of the facility including the impact of the CEJA in Illinois, which concluded with the annual budget process.

Other Impairments — The Company additionally recorded impairment losses of $ 16 million and $ 9 million related to various power plants in the East and West/Service/Other segments, respectively.

The Company also recorded the following impairment in 2021 based on a specific triggering event that occurred using the same methodology previously discussed:

PJM Asset Impairments — During the second quarter of 2021, the results of the PJM Base Residual Auction for the 2022/2023 delivery year were released leading the Company to announce the near-term retirement of a significant portion of its PJM coal generating assets in June 2022.

The Company considered the decline in PJM capacity prices and the near-term retirement dates of certain assets to be a trigger for impairment and performed impairment tests on the PJM generating assets and the goodwill associated with Midwest Generation.

Impairment losses of $ 271 million and $ 35 million were recorded in the East segment on the PJM generating assets and Midwest Generation goodwill, respectively.

2020 Impairment Losses

During the fourth quarter of 2020, 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-lives assets.

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The Cottonwood facility is being leased through 2025 and the Company recognized an impairment loss of $ 32 million in 2020 in the West/Other segment associated with the Company's long-term services agreement and related lease payments, as the carrying amounts of the assets from the contract were higher than the estimated operating cash flow though the remaining lease period.

The Cottonwood facility is being leased through 2025 and the Company recognized an impairment loss of $ 32 million in 2020 in the West/Services/Other segment associated with the Company's long-term services agreement and related lease payments, as the carrying amounts of the assets from the contract were higher than the estimated operating cash flow though the remaining lease period.

The Company also recorded the following impairments in 2020 based on specific triggering events that occurred:

Home Solar — In the third quarter of 2020, the Company concluded its Home Solar business was held for sale and recorded an impairment loss of $ 29 million in the West/Other segment to adjust the carrying amount of the assets and liabilities to fair market value based on indicative sale prices.

Home Solar — In the third quarter of 2020, the Company concluded its Home Solar business was held for sale and recorded an impairment loss of $ 29 million in the West/Services/Other segment to adjust the carrying amount of the assets and liabilities to fair market value based on indicative sale prices.

Petra Nova Parish Holdings — During the first quarter of 2020, due to the decline in oil prices, NRG determined that the carrying amount of the Company’s equity method investment exceeded the fair value of the investment and that the decline is considered to be other-than-temporary.

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Other Impairments — For the year ended December 31, 2019, the Company recorded $ 12 million of impairment losses primarily related to investments and intangibles.

2018 Impairment Losses

Guam — During the fourth quarter of 2018, the Company concluded its wholly-owned subsidiary, NRG Solar Guam, LLC, was held for sale after 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, 2018 based on the contractual sale price, which resulted in an impairment loss of $ 12 million.

On February 20, 2019, the Company completed the sale of Guam for cash consideration of approximately $ 8 million.

Keystone and Conemaugh — On September 5, 2018, the Company sold its approximately 3.7 % interests in the Keystone and Conemaugh generating stations.

NRG recorded impairment losses of $ 14 million for Keystone and $ 14 million for Conemaugh to adjust the carrying amount of the assets to fair value based on the contractual sale price.

Dunkirk — During the second quarter of 2018, NRG ceased its development of the project to add gas capability at the Dunkirk generating station.

The project was put on hold in 2015 pending the resolution of a lawsuit filed by Entergy Corporation against the NYPSC, which challenged the legality of its contract with Dunkirk.

The lawsuit was later dropped and development continued, but the delay imposed a new requirement on Dunkirk to enter into the NYISO interconnection study process.

The NYISO studies have concluded that extensive electric system upgrades would be necessary for the station to return to service.

This would cause the Company to incur a material increase in cost and delay the project schedule that would render the project impractical.

Consequently, the Company has recorded an impairment loss of $ 46 million, reducing the carrying amount of the related assets to $ 0 .

Other Impairments — As of December 31, 2018, the Company recorded additional asset impairment losses of $ 13 million and impairment losses on equity method investments of $ 15 million.

Note 12 — Goodwill and Other Intangibles

NRG's goodwill balance was $ 579 million as of December 31, 2020 and 2019.

As of December 31, 2020, goodwill consisted of $ 165 million associated with the acquisition of Midwest Generation and $ 414 million for retail operations acquisitions, including Stream Energy and XOOM, which were acquired in 2019 and 2018, respectively.

The table below presents the changes of goodwill for the year ended December 31, 2021 based on the Company's reportable segments.

Goodwill did not change during the year ended December 31, 2020.

(in millions) Texas East West/Services/Other Total

Balance as of January 1, 2021 $ 324 $ 240 $ 15 $ 579

Goodwill resulted from the acquisition of Direct Energy 427 648 175 1,250

Impairment losses — ( 35 ) — ( 35 )

Foreign currency translation — — 1 1

Balance as of December 31, 2021 $ 751 $ 853 $ 191 $ 1,795

Intangible Assets

The Company's intangible assets as of December 31, 2020, primarily reflect intangible assets established with the acquisitions of various companies, including Stream Energy, XOOM, other retail acquisitions, and Texas Genco.

The Company's intangible assets as of December 31, 2021, primarily reflect intangible assets established with the acquisitions of various companies, including Direct Energy, Stream Energy, other retail acquisitions, and Texas Genco.

Intangible assets are comprised of the following:

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These emission allowances are held-for-use and are amortized to cost of operations based on units of production.

• In-market nuclear fuel contracts — These intangibles were established with the Texas Genco acquisition in 2006 and are amortized to cost of operations over expected volumes over the life of each contract.

• Customer relationships — These intangibles represent the fair value at the acquisition date of acquired businesses' customer base.

• Customer and supply contracts — These intangibles include the fair value at the acquisition date of in-market and out-of-market customer and supply contracts from the acquisition of Direct Energy and are amortized to revenue and cost of operations, respectively, based upon the fair market value, as of the acquisition date, for each delivery month.

It also included energy supply contracts acquired with Stream Energy that represent the fair value at the acquisition date of in-market contracts for the purchase of energy to serve retail electric customers and are amortized based on the expected delivery under the respective contracts.

• Customer relationships — These intangibles represent the fair value at the acquisition date of acquired businesses' customer base from the acquisition of Direct Energy and other acquisitions.

The customer relationships are amortized to depreciation and amortization expense based on the expected discounted future net cash flows by year.

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• Trade names — These intangibles are amortized to depreciation and amortization expense on a straight-line basis.

• Other — Consists of renewable energy credits, costs to extend the operating license for STP Units 1 and 2, and energy supply contracts acquired with Stream Energy that represent the fair value at the acquisition date of in-market contracts for the purchase of energy to serve retail electric customers.

• Other — These intangibles primarily include renewable energy credits.

Renewable energy credits are retired, as required, for the applicable compliance period.

They are expensed to cost of operations based on NRG’s customer usage.

Energy supply contracts are amortized to depreciation and amortization based on the expected delivery under the respective contracts.

The following tables summarize the components of NRG's intangible assets subject to amortization:

It also includes in-market nuclear fuel contracts established from the Texas Genco acquisition in 2006 which are amortized to cost of operations over expected volumes over the life of each contract, costs to extend the operating license for STP Units 1 and 2 and intellectual property related to Goal Zero which are amortized to depreciation and amortization expense.

The following tables summarize the components of NRG's intangible assets:

(In millions)

Year Ended December 31, 2021 Emission

Fuel Contracts Customer

Customer and Supply Contracts Customer

Relationships

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— 610 1,308 — 310 124 2,352

Retirements — — — — — ( 35 ) ( 35 )

Usage/Sales/Retirements ( 1 ) — — — — ( 364 ) ( 365 )

Write-off of fully amortized balances ( 51 ) — ( 158 ) — — ( 7 ) ( 216 )

Impairment ( 14 ) — — — — — ( 14 )

Other 4 — 2 ( 1 ) — ( 2 ) 3

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Net carrying amount $ 98 $ 544 $ 1,161 $ 161 $ 389 $ 158 $ 2,511

(a) The weighted average life of acquired intangibles was 5 years for customer relationships

(a) The weighted average life of total acquired amortizable intangibles from the Direct Energy acquisition was 12 years, see Note 4 — Acquisitions, Discontinued Operations and Dispositions for weighted average life of acquired amortizable intangibles for each intangible asset type

(b) RECs are not subject to amortization and had a carrying value of $ 123 million

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Year Ended December 31, 2020 Emission

Fuel Contracts Customer

Customer and Supply Contracts Customer

Relationships

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Net carrying amount $ 109 $ — $ 178 $ 186 $ 126 $ 69 $ 668

(a) The weighted average life of acquired intangibles was:

customer relationships 7 years, trade names 12 years, marketing partnerships 9 years, and energy supply contracts 2 years

(a) The weighted average life of acquired intangibles was 5 years for customer relationships

(b) RECs are not subject to amortization and had a carrying value of $ 28 million

The following table presents NRG's amortization and retirements of intangible assets for each of the past three years:

The following table presents NRG's amortization of intangible assets for each of the past three years:

Years Ended December 31,

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Emission allowances $ 24 $ 28 $ 32

Customer and supply contracts 66 12 14

Customer relationships 327 74 44

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Total amortization $ 495 $ 168 $ 134

(a) For the years ended December 31, 2020, 2019 and 2018, RECs were retired to cost of operations for $ 36 million, $ 17 million and $ 28 million, respectively.

For the years ended December 31, 2020, 2019 and 2018, other intangibles were amortized to depreciation and amortization expense for $ 15 million, $ 18 million and $ 2 million, respectively.

(a) For the years ended December 31, 2021, 2020 and 2019, other intangibles were amortized to depreciation and amortization expense for $ 3 million, $ 3 million and $ 4 million, respectively

The following table presents estimated amortization of NRG's intangible assets as of December 31, 2021 for each of the next five years:

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Year Ended December 31, Emission

Fuel Contracts Customer

Customer and Supply Contracts Customer

Relationships

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Once transferred to held-for-sale, these emission allowances are prohibited from moving back to held-for-use.

Note 13 — Receivables Securitization and Repurchase Facility

Receivables Securitization

On September 22, 2020, NRG Receivables LLC, a bankruptcy remote, special purpose, indirect wholly owned subsidiary, entered into the Receivables Facility for an amount up to $ 750 million, subject to adjustments on a seasonal basis, with issuers of asset-backed commercial paper and commercial banks (the "Lenders".) The assets of NRG Receivables LLC are first available to satisfy the claims of the Lenders before making payments on the subordinated note and equity issued by NRG Receivables LLC.

The assets of NRG Receivables LLC are not available to the Company and its subsidiaries or creditors unless and until distributed by NRG Receivables LLC.

Under the Receivables Facility, certain indirect subsidiaries of the Company sell their accounts receivables to NRG Receivables LLC, subject to certain terms and conditions.

In turn, NRG Receivables LLC grants a security interest in the purchased receivables to the Lenders as collateral for cash borrowings and issuances of letters of credit.

Pursuant to the Performance Guaranty, the Company has guaranteed, for the benefit of NRG Receivables and the 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 LLC 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 Company will continue to service the accounts receivables sold in exchange for a servicing fee.

The Receivables Facility is scheduled to expire on September 21, 2021, unless renewed by the mutual consent of the parties in accordance with its terms.

Borrowings by NRG Receivables LLC under the Receivables Facility bear interest as defined under the Receivables Financing Agreement.

The weighted average interest rate related to usage under the Securitization Facility as of December 31, 2020 was 0.537 %.

As of December 31, 2020, there were no outstanding borrowings and there were $ 198 million in letters of credit issued under the Receivables Facility.

Repurchase Facility

On September 22, 2020, the Company entered into an uncommitted repurchase facility (“Repurchase Facility”) related to the Receivables Facility.

Under the Repurchase Facility, the Company can borrow up to $ 75 million, collateralized by a

subordinated note issued by NRG Receivables LLC to NRG Retail LLC in favor of the originating entities representing a portion of the balance of receivables sold to NRG Receivables LLC under the Receivables Facility.

The Repurchase Facility is scheduled to expire on September 22, 2021, unless renewed by the mutual consent of the parties in accordance with its terms.

The Repurchase Facility has no commitment fee and borrowings will be drawn at LIBOR + 1.25 %.

As of December 31, 2020, there were no outstanding borrowings under the Repurchase Facility.

Note 13 — Long-term Debt and Finance Leases

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Senior Notes, due 2031 1,030 1,030 3.625

Senior Notes, due 2032 1,100 — 3.875

Convertible Senior Notes, due 2048 (a)

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Senior Secured First Lien Notes, due 2029 500 500 4.450

Revolving Credit Facility — 83 L+ 1.75

Tax-exempt bonds 466 466 1.250 - 4.750

Subtotal recourse debt 8,855 6,008

Non-recourse debt:

Other — 34 various

Subtotal all non-recourse debt — 34

Subtotal long-term debt (including current maturities)

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(a) The effective interest rate was 5.34 % and 5.19 % for the years ended December 31, 2021 and 2020, respectively.

As of the ex-dividend date of January 29, 2021, the Convertible Notes were convertible at a price of $ 45.94 , which is equivalent to a conversion rate of approximately 21.77 shares of common stock per $1,000 principal amount.

The remaining period over which the discount on the liability component will be amortized is 4.7 years.

As of the ex-dividend date of January 31, 2022, the Convertible Senior Notes were convertible at a price of $ 44.53 , which is equivalent to a conversion rate of approximately 22.4563 shares of common stock per $1,000 principal amount.

The remaining period over which the discount on the liability component would have been amortized is 3.7 years.

However, the adoption of ASU 2020-06 on January 1, 2022 resulted in the elimination of the debt discount.

Debt includes the following discounts:

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Total $ 8,113

Recourse Debt

Issuance of 2032 Senior Notes

On August 23, 2021, the Company issued $ 1.1 billion of aggregate principal amount of 3.875 % senior notes due 2032.

The 2032 Senior Notes are senior unsecured obligations of NRG and are guaranteed by certain of its subsidiaries.

Interest is paid semi-annually beginning on February 15, 2022 until the maturity date of February 15, 2032.

The 2032 Senior Notes were issued under NRG's Sustainability-Linked Bond Framework, which sets out certain sustainability targets, including reducing greenhouse gas emissions.

Failure to meet such sustainability targets will result in a 25 basis point increase to the interest rate payable on the 2032 Senior Notes from and including August 15, 2026.

The proceeds of the 2032 Senior Notes, along with cash on hand, were used to fund the redemption of $ 1.0 billion aggregate principal amount of the 7.250 % Senior Notes due 2026 and $ 355 million aggregate principal amounts of the 6.625 % Senior Notes due 2027.

Issuance of 2029 Senior Unsecured Notes and 2031 Senior Unsecured Notes

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The 2025 and 2027 Senior Secured First Lien Notes are guaranteed on a first-priority basis by each of NRG’s current and future subsidiaries that guarantee indebtedness under its credit agreement.

The 2025 and 2027 Senior Secured First Lien Notes will be secured by a first priority security interest in the same collateral that is pledged for the benefit of the lenders under NRG’s credit agreement, which consists of a substantial portion of the property and assets owned by NRG and the guarantors.

The 2025 and 2027 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 NRG’s credit agreement, which consists of a substantial portion of the property and assets owned by NRG and the guarantors.

The collateral securing the 2025 and 2027 Senior Secured First Lien Notes will be released if the Company obtains an investment grade rating from two out of the three rating agencies, subject to an obligation to reinstate the collateral if such rating agencies withdraw the Company's investment grade rating or downgrade its rating below investment grade.

Interest is payable on the 2025 and 2027 Senior Secured First Lien Notes on June 2 and December 2 of each year beginning on June 2, 2021 until the maturity date of December 2, 2025 for the 2025 Secured Notes and until the maturity date of December 2, 2027 for the 2027 Secured Notes.

Issuance of 2029 Senior Notes

On May 14, 2019, NRG issued $ 733 million of aggregate principal amount at par of 5.25 % senior unsecured notes due 2029, or the 2029 Senior Notes.

The 2029 Senior Notes are senior unsecured obligations of NRG and are guaranteed by certain of its subsidiaries.

Interest will be paid semi-annually beginning on December 15, 2019, until the maturity date of June 15, 2029.

The proceeds from the issuance of the 2029 Senior Notes were utilized to redeem the Company's remaining 6.25 % Senior Notes due 2024.

Issuance of 2024 and 2029 Senior Secured First Lien Notes

On May 28, 2019, NRG issued $ 1.1 billion of aggregate principal amount of senior secured first lien notes, consisting of $ 600 million 2.75 % senior secured first lien notes due 2024 and $ 500 million 4.45 % senior secured first lien notes due 2029, or the Senior Secured First Lien Notes, at a discount.

The Senior Secured First Lien Notes are guaranteed on a first-priority basis by each of NRG’s current and future subsidiaries that guarantee indebtedness under its credit agreement.

The Senior Secured First Lien Notes will be secured by a first priority security interest in the same collateral that is pledged for the benefit of the lenders under NRG’s credit agreement, which consists of a substantial portion of the property and assets owned by NRG and the guarantors.

The collateral securing the Senior Secured First Lien Notes will be released if the Company obtains an

investment grade rating from two out of the three rating agencies, subject to an obligation to reinstate the collateral if such rating agencies withdraw the Company's investment grade rating or downgrade its rating below investment grade.

Interest will be paid semi-annually beginning on December 15, 2019, until the maturity dates of June 15, 2024 and June 15, 2029.

The proceeds from the issuance of the Senior Secured First Lien Notes, together with cash on hand, were used to repay the Company's 2023 Term Loan Facility.

Senior Note Redemptions

During the year ended December 31, 2019, the Company redeemed $ 733 million of its 6.25 % Senior Notes due 2024 and recorded a loss on debt extinguishment of $ 29 million, which included the write-off of previously deferred debt issuance costs of $ 5 million.

During the year ended December 31, 2021, the Company redeemed approximately $ 1.9 billion in aggregate principal amount of its Senior Notes for $ 1.9 billion using the proceeds of the 2032 Senior Notes and cash on hand, as detailed in the table below.

In connection with the redemptions, a $ 77 million loss on debt extinguishment was recorded, which included the write-off of previously deferred financing costs of $ 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

(a) Includes accrued interest of $ 29 million for redemptions for the year ended December 31, 2021

2048 Convertible Senior Notes

The Convertible Notes are accounted for in accordance with ASC 470-20, Debt with Conversion and Other Options .

The Convertible Senior Notes are accounted for in accordance with ASC 470-20, Debt with Conversion and Other Options .

Under ASC 470-20, issuers of convertible debt instruments that may be settled in cash upon conversion, including partial cash settlement, are required to separately account for the liability (debt) and equity (conversion option) components.

The Convertible Notes are convertible, under certain circumstances, into the Company's common stock, cash or a combination thereof (at NRG's option) at a price of $ 46.24 per common share as of December 31, 2020, which is equivalent to an conversion rate of approximately 21.6242 shares of common stock per $1,000 principal amount of Convertible Notes.

As of December 31, 2019, the Convertible Notes were convertible at a price of $ 47.74 per common share, which is equivalent to an conversion rate of approximately 20.9479 shares of common stock per $1,000 principal amount of Convertible Notes.

Prior to February 22, 2022, the Convertible Senior Notes were convertible, under certain circumstances, into the Company's common stock, cash or a combination thereof (at NRG's option) at a price of $ 44.89 per common share as of December 31, 2021, which is equivalent to a conversion rate of approximately 22.2761 shares of common stock per $1,000 principal amount

of 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 will be settled in cash or a combination of cash and the Company's common stock.

As of December 31, 2020, the Convertible Senior Notes were convertible at a price of $ 46.24 per common share, which is equivalent to a conversion rate of approximately 21.6242 shares of common stock per $1,000 principal amount of Convertible Senior Notes.

The carrying amounts of the liability components as of December 31, 2021 and 2020 of $ 518 million and $ 503 million, respectively, were calculated by estimating the fair value of similar liabilities without a conversion feature at inception and amortizing the debt discount using the effective interest rate over the life of the note.

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As of December 31, 2021, NRG had the following outstanding issuances of senior notes with an early redemption feature, or Senior Notes:

7.250 % senior notes, issued May 23, 2016 and due May 15, 2026, or the 2026 Senior Notes;

6.625 % senior notes, issued August 2, 2016 and due January 15, 2027, or the 2027 Senior Notes;

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3.625 % senior notes, issued December 2, 2020 and due February 15, 2031, or the 2031 Senior Notes;

3.875 % senior notes, issued August 23, 2021 and due February 15, 2032, or the 2032 Senior Notes.

The Company periodically enters into supplemental indentures for the purpose of adding entities under the Senior Notes as guarantors.

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and certain events of bankruptcy or insolvency.

Generally, if an event of default occurs, the Trustee or the Holders of at least 25 % 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.

Generally, if an event of default occurs, the Trustee or the Holders 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's ability and certain of its subsidiaries' ability to return capital to stockholders, grant liens on assets to lenders and incur additional debt.

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2027 Senior Notes

At any time prior to May 15, 2021, NRG may redeem all or a part of the 2026 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 103.625 % of the note, plus interest payments due on the note from the date of redemption through May 15, 2021 computed using a discount rate equal to the Treasury Rate as of such redemption date plus 0.50 %.

In addition, on or after May 15, 2021, 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

May 15, 2021 to May 14, 2022 103.625 %

May 15, 2022 to May 14, 2023 102.417 %

May 15, 2023 to May 14, 2024 101.208 %

May 15, 2024 and thereafter 100.000 %

2027 Senior Notes

At any time prior to July 15, 2021, NRG may redeem all or a part of the 2027 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 103.313 % of the note, plus interest payments due on the note from the date of redemption through July 15, 2021 computed using a discount rate equal to the Treasury Rate as of such redemption date plus 50 %.

In addition, on or after July 15, 2021, 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:

NRG 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

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2028 Senior Notes

At any time prior to January 15, 2021, NRG may redeem up to 35 % of the aggregate principal amount of the 2028 Senior Notes, at a redemption price equal to 105.750 % 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 January 15, 2023, NRG may redeem all or a part of the 2028 Senior Notes, at a redemption price equal to 100 % of the principal amount, accrued and unpaid interest to the redemption date, plus a premium.

At any time prior to January 15, 2023, NRG may redeem all or a part of the 2028 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:

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At any time prior to June 15, 2022, NRG may redeem up to 40 % of the aggregate principal amount of the 2029 Senior Notes, at a redemption price equal to 105.250 % 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, provided that at least 50 % of the aggregate principal amount remains outstanding immediately after the occurrence of such redemption.

At any time prior to June 15, 2024, NRG may redeem all or a part of the 2029 Senior Notes, at a redemption price equal to 100 % of the principal amount accrued and unpaid interest to the redemption date, plus a premium.

At any time prior to June 15, 2024, NRG may redeem all or a part of the 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:

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At any time prior to February 15, 2024, NRG may redeem up to 40 % of the aggregate principal amount of the 2029 Senior Notes, at a redemption price equal to 103.375 % 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, provided that at least 50 % of the aggregate principal amount remains outstanding immediately after the occurrence of such redemption.

At any time prior to February 15, 2024, NRG may redeem all or a part of the 2029 Senior Notes, at a redemption price equal to 100 % of the principal amount accrued and unpaid interest to the redemption date, plus a premium.

At any time prior to February 15, 2024, NRG may redeem all or a part of the 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:

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At any time prior to February 15, 2026, NRG may redeem up to 40 % of the aggregate principal amount of the 2031 Senior Notes, at a redemption price equal to 103.625 % 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, provided that at least 50 % of the aggregate principal amount remains outstanding immediately after the occurrence of such redemption.

At any time prior to February 15, 2026, NRG may redeem all or a part of the 2031 Senior Notes, at a redemption price equal to 100 % of the principal amount accrued and unpaid interest to the redemption date, plus a premium.

At any time prior to February 15, 2026, NRG may redeem all or a part of the 2031 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:

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February 15, 2029 and thereafter 100.000 %

2032 Senior Notes

At any time prior to August 15, 2024, NRG may redeem up to 40 % of the aggregate principal amount of the 2032 Senior Notes, at a redemption price equal to 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, provided that at least 50 % of the aggregate principal amount remains outstanding immediately after the occurrence of such redemption.

At any time prior to February 15, 2027, NRG may redeem all or a part of the 2032 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 (A) the present value of (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 through February 15, 2027 (excluding accrued but unpaid interest to the redemption date) 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 February 15, 2027, 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 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 %

Receivables Facility

The assets of NRG Receivables LLC are not available to the Company and its subsidiaries or creditors unless and until distributed by NRG Receivables LLC.

Under the Receivables Facility, certain indirect subsidiaries of the Company sell their accounts receivables to NRG Receivables LLC, subject to certain terms and conditions.

In turn, NRG Receivables LLC grants a security interest in the purchased receivables to the Lenders as collateral for cash borrowings and issuances of letters of credit.

Pursuant to the Performance Guaranty, the Company has guaranteed, for the benefit of NRG Receivables and the 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 LLC 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 Company will continue to service the accounts receivables sold in exchange for a servicing fee.

On July 26, 2021, NRG Receivables LLC entered into the First Amendment to the Receivables Facility with a group of conduit lenders and banks and Royal Bank of Canada, as Administrative Agent to, among other things, (i) increase the existing revolving commitments by $ 50 million to an aggregate amount of $ 800 million, (ii) extend the maturity date until July 26, 2022, (iii) make certain adjustments to the pool of receivables through the Receivables Facility and certain related covenants and (iv) provide for revised language relating to interest determination based on SOFR in case of a LIBOR cessation or the occurrence of certain other trigger events.

Borrowings by NRG Receivables LLC under the Receivables Facility bear interest as defined under the Receivables Financing Agreement.

The weighted average interest rate related to usage under the Receivables Facility as of December 31, 2021 was 0.646 %.

As of December 31, 2021, there were no outstanding borrowings and there were $ 400 million in letters of credit issued under the Receivables Facility.

Repurchase Facility

On September 22, 2020, the Company entered into the Repurchase Facility related to the Receivables Facility.

Under the Repurchase Facility, the Company can borrow up to $ 75 million, collateralized by a subordinated note issued by NRG Receivables LLC to NRG Retail LLC in favor of the originating entities representing a portion of the balance of receivables sold to NRG Receivables LLC under the Receivables Facility.

On July 26, 2021, the Company renewed its existing Repurchase Facility to, among other things, (i) extend the maturity date to July 26, 2022 and (ii) provide for revised language relating to interest determination based on SOFR in case of a LIBOR cessation or the occurrence of certain other trigger events.

On February 9, 2022, the Company entered into amendments to its existing Repurchase Facility to, among other things, (i) increase the size of the facility from $ 75 million to $ 150 million and (ii) replace LIBOR with term SOFR as the benchmark for the pricing rate.

The Repurchase Facility has no commitment fee and borrowings will be drawn at SOFR + 1.30 %.

As of December 31, 2021, there were no outstanding borrowings under the Repurchase Facility.

Senior Credit Facility

2023 Term Loan Facility Repayment

On May 28, 2019, the Company repaid its $ 1.7 billion 2023 Term Loan Facility using the proceeds from the issuance of the Senior First Lien Notes, as well as cash on hand, resulting in a decrease of $ 594 million to long-term debt outstanding.

The Company recorded a loss on debt extinguishment of $ 17 million, which included the write-off of previously deferred debt issuance costs of $ 13 million.

As a result of the repayment of the outstanding 2023 Term Loan Facility, the Company terminated the related interest rate swap agreements, which were in-the-money, and received $ 25 million that was recorded as a reduction to interest expense.

Revolving Credit Facility Modification

On May 28, 2019, the Company amended its existing credit agreement to, among other thing, (i) provide for a $ 184 million increase in revolving commitments, resulting in aggregate revolving commitments under the amended credit agreement equal to $ 2.6 billion, (ii) extend the maturity date of the revolving loans and commitments under the amended credit agreement to May 28, 2024, (iii) provide for a release of the collateral securing the amended credit agreement if NRG obtains an investment grade rating form two out of the three rating agencies, subject to an obligation to reinstate the collateral if such rating agencies withdraw NRG's investment grade rating or downgrade NRG's rating below investment grade, (iv) reduce the applicable margins for borrowings under (a) ABR Revolving Loans from 1.25 % to 0.75 % and (b) Eurodollar Revolving Loans from 2.25 % to 1.75 %, (v) add a sustainability covenant and (vi) make certain other changes to the existing covenants.

On August 20, 2020, the Company amended its existing credit agreement to, among other things, (i) increase the existing revolving commitments in an aggregate amount of $ 802 million, (ii) provide for a new tranche of revolving commitments in an aggregate amount of $ 273 million with a maturity date that is 30 months after the Acquisition Close Date.

The maturity date of the new revolving tranche of commitments may, upon request by the Company, at the option of each applicable lender under the new tranche be extended by a further 12 months, but not beyond May 28, 2024, which is the maturity date of the existing and increased commitments.

Other than with respect to the maturity date, the terms of all revolving commitments and loan made pursuant thereto are identical.

The increase in the existing commitments, and the commitments with respect to the new tranche, are effective on August 20, 2020 but only became available on the Acquisition Closing Date.

For further discussion on the acquisition of Direct Energy see Note 4, Acquisitions, Discontinued Operations and Dispositions .

Upon the Acquisition Closing Date, total revolving commitments available, subject to usage, under this amendment will be $ 3.7 billion.

In addition, the amendment includes changes to, among other things, (i) permit the borrowing of up to full amount of the revolving commitments in Canadian dollars, (ii) increase the swingline facility from $ 50 million to $ 100 million and provide a $ 10 million swingline facility in Canadian dollars, (iii) increase the credit facilities lien basket from the greater of $ 6 billion and 30 % of total assets to the greater of $ 10 billion and 30 % of total assets, (iv) increase the credit facilities debt basket from $ 6 billion to $ 10 billion, (v) increase the basket for securitization indebtedness from $ 750 million to $ 1.7 billion, (vi) provide an additional indebtedness basket equal to $ 600 million for certain liquidity facilities, and (vii) make certain other changes to the existing covenants and other provisions.

During the third quarter of 2020, the Company amended its existing credit agreement to, among other things, (i) increase the existing revolving commitments in an aggregate amount of $ 802 million, and (ii) provide for a new tranche of revolving commitments in an aggregate amount of $ 273 million with a maturity date of July 5, 2023.

The maturity date of the new revolving tranche of commitments may, upon request by the Company, and at the option of each applicable lender under the

new tranche be extended to May 28, 2024, which is the maturity date of the existing and increased commitments.

Other than with respect to the maturity date, the terms of all revolving commitments and loans made pursuant thereto are identical.

The increase in the existing commitments, and the commitments with respect to the new tranche were effective on August 20, 2020 and became available on January 5, 2021 upon the closing of the Direct Energy Acquisition.

As of December 31, 2021, total revolving commitments available, subject to usage, under the amended credit agreement was $ 3.7 billion.

Credit Default Swap Facility

On January 4, 2019, the Company entered into an $ 80 million credit agreement to issue letters of credit, which is currently supporting the Cottonwood facility lease.

Annual fees of 1.33 % on the facility were paid quarterly in advance.

On August 13, 2020, the agreement was amended permitting the Company to increase the size of the facility and fees on the facility were adjusted to reflect the costs of the credit default swaps that serve as collateral for the facility.

In order to increase the Company’s collective collateral facilities in connection with the Direct Energy acquisition, NRG expanded the facility allowing for the issuance of an additional $ 150 million of letters of credit as of December 31, 2020.

As of December 31, 2021, $ 222 million was issued under this facility.

Bilateral Letter of Credit Facilities

In December 2020 the Company entered into a series of Bilateral Letter of Credit Facilities to allow for the issuance of up to $ 475 million of letters of credit.

These facilities are uncommitted.

As of December 31, 2021, $ 469 million was issued under these facilities.

Put Option Agreement for Senior Debt Issuance

During the fourth quarter of 2020, the Company entered into a 3 -year put option agreement with a Delaware trust formed by the Company upon completion of the sale of $ 900 million pre-capitalized trust securities redeemable November 15, 2023 (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”).

Under the put option agreement, NRG has the right, from time to time, to issue to the Trust and to require the Trust to purchase from NRG, on one or more occasions (the “Issuance Right”), up to $ 900 million aggregate principal amount of NRG’s 1.841 % Senior Secured First Lien Notes due 2023 (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.

NRG will pay a semi-annual premium to the Trust at a rate of 1.65 %.

In connection with the issuance of the P-Caps, on December 11, 2020, NRG entered into an amended and restated facility agreement for the issuance of letters of credit (the “LC Agreement”) with Deutsche Bank Trust Company Americas as collateral agent (the “Collateral Agent”) and administrative agent pursuant to which certain financial institutions (the “LC Issuers”) have agreed to provide letters of credit in an aggregate amount not to exceed $ 874 million to support the operations of NRG and its subsidiaries and minority investments, including to replace certain letters of credit and other credit support issued for the account of entities acquired pursuant to the Direct Energy Acquisition.

In addition, on December 11, 2020, the Trust entered into an amended and restated pledge and control agreement (the “Pledge Agreement”), among NRG, the Trust and the Collateral Agent for the LC Issuers, under which the Trust agreed to grant a pledge over the Eligible Treasury Assets in favor of the Collateral Agent for the benefit of the LC Issuers.

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

The LC Agreement and the Pledge Agreement were available on January 5, 2021.

As of December 31, 2021, $ 873 million of letters of credit were issued under the LC Agreement .

Tax Exempt Bonds

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NRG Indian River Power 2020, tax exempt bonds, due 2045 190 190 1.250

Indian River Power, tax exempt bonds, due 2040 — 57 6.000

Indian River Power LLC, tax exempt bonds, due 2045 — 190 5.375

NRG Dunkirk 2020, tax exempt bonds, due 2042 59 59 1.300

Dunkirk Power LLC, tax exempt bonds, due 2042 — 59 5.875

City of Texas City, tax exempt bonds, due 2045 33 33 4.125

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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 NRG’s credit agreement, 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 Bonds or any of NRG’s senior, unsecured debt securities or downgrade such rating below investment grade.

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 rating below investment grade.

The Dunkirk Bonds are subject to mandatory tender and purchase on April 3, 2023 and have a final maturity date of April 1, 2042.

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NRG used the net proceeds from the offering to redeem during 2020 the existing principal amounts of outstanding Indian River Power 6.000 % tax exempt bonds due 2040 and Indian River Power LLC 5.375 % tax exempt bonds due 2045.

Non-Recourse Debt

The following are descriptions of certain indebtedness of NRG's subsidiaries.

All of NRG's non-recourse debt is secured by the assets in the respective project subsidiaries as further described below.

Credit Default Swap Facility

On January 4, 2019, the Company entered into an $ 80 million credit agreement to issue letters of credit, which is currently supporting the Cottonwood facility lease.

Annual fees of 1.33 % on the facility were paid quarterly in advance.

As of December 31, 2020, $ 229 million was issued under this facility.

Bilateral Letter of Credit Facilities

In December 2020 the Company entered into a series of Bilateral Letter of Credit Facilities to allow for the issuance of up to $ 475 million of letters of credit.

These facilities are uncommitted.

As of December 31, 2020, $ 5 million was issued under these facilities.

Put Option Agreement for Senior Debt Issuance

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”).

NRG will pay a semi-annual premium to the Trust at a rate of 1.65 %.

The P-Caps are to be redeemed by the Trust on November 15, 2023 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, NRG may similarly redeem such P-Caps Secured Notes, in whole or in part, at the redemption price described 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 November 15, 2023.

The Issuance Right will be exercised automatically in full if (1) NRG 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 (2) upon certain bankruptcy events of NRG.

NRG will be required to mandatorily exercise the Issuance Right if (1) an Acquisition Triggering Event has occurred, (2) NRG’s consolidated stockholders’ equity, determined in accordance with GAAP, but excluding accumulated other comprehensive income (or loss), equity of non-controlling interests attributable thereto and treasury stock at cost, has fallen below $ 2.0 billion, which amount may be adjusted from time to time upon the occurrence of certain specified events, (3) an event of default under the P-Caps Secured Notes Indenture (as defined below) has occurred or would have occurred had the P-Caps Secured Notes been outstanding, (4) NRG breaches its covenant to maintain sufficient capacity under other material agreements to permit the issuance of the P-Caps Secured Notes in full, (5) a Collateral Enforcement Event (as defined below) has occurred, (6) a change of control triggering event has occurred in respect of NRG or (7) certain events relating to the Trust’s status as an “investment company” under the Investment Company Act of 1940, as amended (the “Investment Company Act”), have occurred.

Upon the occurrence of any event described in clause (1), (2), (3), (4) or (7) of this paragraph, the Issuance Right will be exercised in full, and upon the occurrence of any event described in clause (5) or (6) of this paragraph, the Issuance Right will be exercised with respect to the applicable portion of the available amount of P-Caps Secured Notes specified in the Facility Agreement.

In connection with the issuance of the P-Caps, on December 2, 2020, NRG entered into a facility agreement for the issuance of letters of credit (the “LC Agreement”) and Deutsche Bank Trust Company Americas as collateral agent (the “Collateral Agent”) and administrative agent pursuant to which certain financial institutions (the “LC Issuers”) are permitted to join with commitments to provide letters of credit in an aggregate amount not to exceed $ 874 million to support the operations of NRG and its subsidiaries and minority investments, including to replace certain currently outstanding letters of credit and other credit support issued for the account of entities being acquired pursuant to the Acquisition.

In addition, on December 2, 2020, the Trust entered into a pledge and control agreement (the “Pledge Agreement”), among NRG, the Trust and the Collateral Agent for the LC Issuers, under which the Trust agreed to grant a pledge over the Eligible Treasury Assets in favor of the Collateral Agent for the benefit of the LC Issuers.

As of December 31, 2020 no letters of credit were issued under this agreement .

Agua Caliente Borrower 1

On January 22, 2019, the lenders of the Agua Borrower 1 notes notified Agua Caliente Borrower 1, a subsidiary of the Company, of certain defaults under the financing agreement as it relates to the bankruptcy filing made by PG&E on January 29, 2019.

PG&E is the offtaker of the underlying contracts, which are material to the project.

The financing was entered into along with Agua Caliente Borrower 2, LLC, a subsidiary of Clearway Energy Inc., which is joint and several to the parties.

October 21, 2019, the Company repaid the outstanding amount on the notes at 102 % plus accrued interest through the payment date of $ 83 million.

Note 14 — Asset Retirement Obligations

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Cost sharing provisions vary by the terms of any applicable collective bargaining agreements.

NRG maintains two separate qualified pension plans, the NRG Pension Plan for Bargained Employees and the NRG Pension Plan.

NRG maintains three separate qualified pension plans, the NRG Pension Plan for Bargained Employees, the NRG Pension Plan and the Pension Plan for Employees of Direct Energy Marketing Limited ("DEML").

Participation in the NRG Pension Plan for Bargained Employees depends upon whether an employee is covered by a bargaining agreement.

NRG expects to contribute $ 30 million to the Company's pension plans in 2021, of which $ 14 million relates to the GenOn plan.

The NRG Pension plan was frozen for non-union employees on December 31, 2018.

The Pension Plan for Employees of DEML is closed to new participants.

Due to updated assumptions as a result of ARPA, NRG does no t expect to contribute to the Company's pension plans in 2022.

NRG Defined Benefit Plans

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Amortization of unrecognized net loss 1 1 —

Curtailment gain — — ( 10 )

Curtailment loss 1 — —

Net periodic benefit credit $ ( 6 ) $ ( 10 ) $ ( 9 )

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Benefit obligation at January 1 $ 1,489 $ 1,397 $ 90 $ 93

Acquired benefit obligation from Direct Energy 74 — 19 —

Service cost 9 10 — —

Interest cost 27 38 2 3

Plan amendments — — — ( 2 )

Actuarial loss 126 207 — 16

Actuarial (gain)/loss ( 55 ) 126 — —

Employee and retiree contributions — — 3 3

Curtailment loss — — 1 —

Benefit payments ( 93 ) ( 82 ) ( 10 ) ( 9 )

Foreign exchange translation 1 — — —

Benefit obligation at December 31 1,452 1,489 105 90

Fair value of plan assets at January 1 1,272 1,150 — —

Acquired fair value of plan assets from Direct Energy 64 — —

Actual return on plan assets 85 193 — —

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Benefit payments ( 93 ) ( 82 ) ( 10 ) ( 9 )

Foreign exchange translation 1 — — —

Fair value of plan assets at December 31 1,336 1,272 — —

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$ ( 116 ) $ ( 217 ) $ ( 105 ) $ ( 90 )

During the year ended December 31, 2020, the actuarial loss of $ 126 million on pension benefits was driven by decreasing discount rates and demographic assumptions, partially offset by gains from life expectancy projection updates.

During the year ended December 31, 2019, the actuarial loss of $ 207 million on pension benefits was driven by decreasing discount rates, assumption changes to reflect current market conditions and actual experience different than assumed, partially offset by gains from life expectancy projection updates.

During the year ended December 31, 2021, the actuarial gain of $ 55 million on pension benefits was primarily driven by increasing discount rates and changes in demographic assumptions.

During the year ended December 31, 2020, the actuarial loss of $ 126 million on pension benefits was driven by decreasing discount rates and changes in demographic assumptions, partially offset by gains from life expectancy projection updates.

Amounts recognized in NRG's balance sheets were as follows:

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Year Ended December 31,

Other Postretirement

Pension Benefits Other Postretirement

(In millions) 2021 2020 2021 2020

Net actuarial (gain)/loss $ ( 6 ) $ 50 $ — $ 16

Amortization of net actuarial (gain) ( 5 ) ( 3 ) ( 1 ) —

Prior service credit — — — ( 2 )

Net actuarial gain $ ( 72 ) $ ( 6 ) $ — $ —

Amortization of net actuarial loss ( 1 ) ( 5 ) ( 1 ) ( 1 )

Amortization of prior service cost — — 10 14

Effect of settlement ( 2 ) — — —

Total recognized in OCI $ ( 75 ) $ ( 11 ) $ 9 $ 13

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3.26 % 4.37 %

3.71 % / 4.08 %

Interest crediting rate 3.13 % 3.66 % — 1.62 % 2.28 % —

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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 AA Above Median, or AA-AM, yield curve to select the appropriate discount rate assumption for each retirement plan.

The Company utilizes the Aon AA Above Median, or AA-AM, yield curve and the AON Canada yield curve to select the appropriate discount rate assumption for its retirement 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.

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.

Under 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 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.

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Total Stock Market Index

MSCI All Country World Ex-U.S.

MSCI All Country World Index

Non-core assets (a)

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Fixed income securities

Barclays Short, Intermediate and Long Credits/Barclays Strips 20+ Index

Barclays Short, Intermediate and Long 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.

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Although NRG does not sponsor the STP plan, it reimburses STPNOC for 44 % of the contributions made towards its retirement plan obligations.

During the third quarter of 2019, STPNOC announced that the defined benefit pension plan will be frozen for non-union employees on December 31, 2021, This resulted in the curtailment of benefits, thereby requiring a remeasurement, including an update to the discount rate used to determine benefit obligations.

During 2019, STPNOC announced that the defined benefit pension plan would be frozen.

As a result, during 2019, NRG recognized a gain of $ 8 million related to the curtailment of benefits and an increase of $ 32 million to the pension liability was recorded to other comprehensive income.

The Company measures the fair value of its pension assets in accordance with ASC 820, Fair Value Measurements and Disclosures, or ASC 820.

As of December 31, 2021, the STPNOC defined benefit pension plan was frozen to all employees.

For the years ended December 31, 2021 and December 31, 2020, NRG reimbursed STPNOC $ 17 million and $ 8 million, respectively, for its contribution to the plans.

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Net periodic benefit cost/(credit) 17 7 ( 4 ) ( 4 )

Other changes in plan assets and benefit obligations recognized in other comprehensive income/(loss)

Other changes in plan assets and benefit obligations recognized in other comprehensive income

( 51 ) 22 4 5

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The following table reflects the changes in NRG's common shares issued and outstanding for each period presented:

Common Shares

Issued Treasury Outstanding

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Balance as of December 31, 2021 423,547,174 ( 179,793,275 ) 243,753,899

Shares issued under LTIPs 288,491 — 288,491

Share repurchases — ( 1,889,151 ) ( 1,889,151 )

Balance as of February 24, 2022 423,835,665 ( 181,682,426 ) 242,153,239

As of December 31, 2021, NRG had 14,372,743 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.

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The long-term capital allocation policy targets an annual dividend growth rate of 7 - 9 % per share in years subsequent to 2020.

In 2021 NRG increased the annual dividend to $ 1.30 per share, representing an 8 % increase.

In 2021 and 2022, NRG increased the annual dividend to $ 1.30 and $ 1.40 per share, representing an 8 % increase each year.

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

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An exercise date will occur each September 30 and March 31.

The ESPP, that was suspended in 2018, allowed eligible employees to elect to withhold up to 10 % of their eligible compensation to purchase shares of NRG common stock at the lesser of 85 % of its fair market value on the offering date or 85 % of the fair market value on the exercise date.

An offering date occurred each January 1 and July 1.

An exercise date occurred each June 30 and December 31.

As of December 31, 2021, there remained 2,636,199 shares of treasury stock reserved for issuance under the ESPP.

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The Company executed $ 1.194 billion of these share repurchases in 2019 and completed the remaining $ 56 million under the 2019 authorization by February 27, 2020.

The remaining repurchases in 2020 were made under the long-term capital allocation policy discussed above.

The following table summarizes the shares repurchases made during the years 2018, 2019 and 2020:

The remaining repurchases in 2020 and were made under the long-term capital allocation policy discussed above.

On December 6, 2021 the Company announced that the Board of Directors has authorized $ 1 billion for share repurchases, as part of NRG’s Capital Allocation Program.

The program began in 2021 and will continue throughout 2022.

The following table summarizes the shares repurchases made during the years ended December 31, 2019, 2020 and 2021 as well as through February 24, 2022:

Total number of shares and share equivalents purchased Average price paid per share and share equivalent Amounts paid for shares and share equivalents purchased (in millions)

2019 repurchases:

Shares repurchased under May 24, 2018 Accelerated Repurchase Agreement 10,829,903 354

Shares repurchased under September 5, 2018 Accelerated Repurchase Agreement 13,307,130 500

Other repurchases 11,097,631 396

Total Share Repurchases during 2018 35,234,664 $ 35.48 $ 1,250

2019 repurchases:

Repurchases under February 28, 2019 Accelerated Share Repurchase Agreement

9,438,671 400

Other repurchases 26,863,211 1,008

Equivalent shares purchased in lieu of tax withholdings on equity compensation issuances (a)

Other repurchases (a)

26,863,211 1,008

Equivalent shares purchased in lieu of tax withholdings on equity compensation issuances (b)

Total Share Repurchases during 2019 37,238,810 $ 38.79 $ 1,444

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6,062,783 197

Equivalent shares purchased in lieu of tax withholdings on equity compensation issuances (a)

Equivalent shares purchased in lieu of tax withholdings on equity compensation issuances (b)

Total Share Repurchases during 2020 6,774,031 $ 33.05 $ 224

(a) NRG elected to pay cash for tax withholding on equity awards instead of issuing actual shares to management.

2021 repurchases:

Repurchases (a)

Equivalent shares purchased in lieu of tax withholdings on equity compensation issuances (b)

Total Share Repurchases during 2021 1,333,765 $ 40.22 $ 53

2022 repurchases:

Repurchases made subsequent to December 31, 2021

Equivalent shares purchased in lieu of tax withholdings on equity compensation issuances (b)

Total share repurchases January 1, 2021 through February 24, 2022 2,019,825 $ 40.26 $ 82

(a) Includes $ 5 million and $ 4 million accrued as of December 31, 2021 and December 31,2019, respectively

(b) NRG elected to pay cash for tax withholding on equity awards instead of issuing actual shares to management.

The average price per equivalent shares withheld was $ 43.08 , $ 37.50 , $ 38.23 and $ 38.78 in 2022, 2021, 2020 and 2019, respectively.

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(In millions, except percentages)

Name Economic

Interest Investment Balance (a)

Agua Caliente 35.0 % $ 185

Gladstone 37.5 % $ 127

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Midway-Sunset Cogeneration Company 50.0 % 12

Total equity investments in affiliates $ 157

Petra Nova Parish Holdings, LLC (b)

50.0 % $ ( 16 )

Total equity investments in affiliates $ 346

(a) As of December 31, 2020, the carry value of NRG's equity method investment was $ 343 million lower than the underlying net assets of the investees.

(a) As of December 31, 2021, the carrying value of NRG's equity method investment was $ 116 million lower than the underlying net assets of the investees.

The basis difference is being amortized into net income over the remaining estimated useful lives of the underlying net assets.

The basis difference is primarily due to impairments booked on Petra Nova, but not booked at the project level, as well as differences related to the deconsolidations of Ivanpah and Agua Caliente in 2018 and the treatment of certain deferred tax assets.

(b) Refer to Note 11, Asset Impairments , for discussion of NRG's investment in Petra Nova Parish Holdings, LLC

(b) The Company continues to account for Petra Nova under the equity method due to the fact that NRG still has a financial guaranty.

As a result, the Company continues to record losses for a negative equity method investment.

As of December 31, 2021, NRG recorded $ 16 million to other non-current liabilities.

Refer to Note 11, Asset Impairments , for discussion of NRG's investment in Petra Nova Parish Holdings, LLC

As of December 31,

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Undistributed earnings from equity investments $ 33 $ 30

PG&E Bankruptcy — The Agua Caliente project and two of the three Ivanpah units are party to PPAs with PG&E.

Both projects have project financing with the U.S.

On January 29, 2019, PG&E Corp.

and primary operating subsidiary utility PG&E filed for Chapter 11 relief in the California Bankruptcy Court.

As a result of the bankruptcy filing, Agua Caliente and the two Ivanpah units were issued notices of events of default under their respective loan agreements.

On September 9, 2019, PG&E filed a plan of reorganization that would assume all power purchase agreements, including those held by Agua Caliente and the two Ivanpah units.

The California Bankruptcy Court approved the PG&E plan and the Confirmation Order was entered on June 19, 2020.

The plan went effective, and PG&E emerged from bankruptcy on July 1, 2020.

In July 2020, the U.S.

DOE agreed to waivers of the bankruptcy-related events of default with respect to the Agua Caliente and Ivanpah projects.

Subsequent to PG&E's emergence from bankruptcy, the Agua Caliente and the Ivanpah projects were allowed to resume distributions, and as of December 31, 2020, NRG received $ 50 million.

In November 2020, Clearway Energy Inc.

agreed to buy NRG’s 35 % interest in Agua Caliente.

The transaction closed on February 3, 2021.

Variable Interest Entities

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The Company accounts for its interest under the equity method of accounting.

The Ivanpah solar electric generating projects were funded in large part by loans guaranteed by the U.S.

DOE and equity from the projects' partners.

During the first quarter of 2018, all interested parties sought a restructuring of Ivanpah's debt in order to avoid a potential event of default with respect to the loans in connection with several recent events.

Ensuing negotiations culminated in a settlement during the second quarter of 2018 between the parties which resulted in certain transactions, including the release of reserves totaling $ 95 million to fund equity distributions to the partners, which reduced the equity at risk, and the prepayment of certain of the debt balance outstanding, and the amendment of certain of Ivanpah's governing documents.

The equity distributions and prepayment of debt were funded by the agreed upon release of reserve funds.

These events were considered to be a reconsideration event in accordance with ASC 810.

As a result, NRG determined that it is not the primary beneficiary and deconsolidated Ivanpah.

NRG recognized a loss of $ 22 million on the deconsolidation and subsequent recognition of Ivanpah as an equity method investment.

The deconsolidation of Ivanpah reduced the Company's

assets by approximately $ 1.3 billion, which was primarily property, plant and equipment, and reduced the Company's liabilities by $ 1.2 billion, which was primarily long-term debt.

Other Equity Investments

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Entities that are Consolidated

The Company has a controlling financial interest in certain entities which have been identified as VIEs under ASC 810.

These arrangements are related to the Receivables Facility, as further described in Note 13, Receivables Securitization and Repurchase Facility, and tax equity arrangements entered into with third-parties in order to finance the cost of solar energy systems under operating leases eligible for certain tax credits as further described in Note 2, Summary of Significant Accounting Policies .

During the first quarter of 2020, the Company repurchased its partners' equity interest in one of the remaining partnerships.

As the Company retains control of its interest in the entity, the repurchase was recorded to equity.

During the fourth quarter of 2020, the Company completed the sale of its other remaining tax equity arrangement, as part of the sale of the Home Solar business for $ 66 million.

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

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

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Other current assets — 2

Net property, plant and equipment — 71

Other long-term assets — 27

Total assets 939 649

Current liabilities 78 78

Long-term debt — 24

Other long-term liabilities — 8

Total liabilities 78 36

Redeemable noncontrolling interests — 20

Net assets less noncontrolling interests $ 571 $ 45

Note 19 — Earnings Per Share

Net assets $ 861 $ 571

Note 18 — Income Per Share

Basic income per common share is computed by dividing net income by the weighted average number of common shares outstanding.

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Diluted income per share is computed in a manner consistent with that of basic 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-qualified stock options, non-vested restricted stock units, and market stock units and relative performance stock units are not considered outstanding for purposes of computing basic income per share.

Dilutive effect for equity compensation and other equity instruments — The outstanding relative performance stock units, non-vested restricted stock units, market stock units and non-qualified stock options are not considered outstanding for purposes of computing basic income per share.

However, these instruments are included in the denominator for purposes of computing diluted income per share under the treasury stock method.

The 2048 Convertible Senior Notes are convertible, under certain circumstances, into the Company’s common stock, cash or combination thereof (at NRG's option).

There is no dilutive effect for the 2048 Convertible Senior Notes due to the Company’s expectation to settle the liability in cash.

The reconciliation of NRG's basic income/(loss) per share to diluted income/(loss) per share is shown in the following table:

As of December 31, 2021, 2020 and 2019, the Convertible Senior Notes were convertible, under certain circumstances, into the Company’s common stock, cash or combination thereof (at NRG's option).

There was no dilutive effect for the Convertible Senior Notes due to the Company’s expectation, as of such dates, to settle the liability in cash.

The reconciliation of NRG's basic income per share to diluted income per share is shown in the following table:

Year Ended December 31,

(In millions, except per share amounts) 2021 2020 2019

Basic income per share attributable to NRG, Inc;

Basic income per share attributable to NRG Energy, Inc;

Net income attributable to NRG Energy, Inc.

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Income per weighted average common share — basic $ 8.93 $ 2.08 $ 16.94

Diluted income per share attributable to NRG, Inc;

Diluted income per share attributable to NRG Energy, Inc;

Net income attributable to NRG Energy, Inc.

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Income per weighted average common share — diluted $ 8.93 $ 2.07 $ 16.81

As of December 31, 2020 and 2019 and 2018 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.

As of December 31, 2021, 2020 and 2019 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.

Note 19 — Segment Reporting

The Company began managing its integrated model based on the combined results of the retail and wholesale generation businesses with a geographical focus in 2020.

As a result, the Company changed its business segments to Texas, East and West/Other beginning in the first quarter of 2020.

The Company's updated segment structure reflects how management makes financial decisions and allocates resources.

All affected disclosures presented herein have been recast to reflect these changes for all periods presented.

For further discussion, refer to Note 1, Nature of Busines s.

The Company’s segment structure reflects how management makes financial decisions and allocates resources.

The Company manages its operations based on the combined results of the retail and wholesale generation businesses with a geographical focus.

NRG's chief operating decision maker, its chief executive officer, evaluates the performance of its segments based on operational measures including adjusted earnings before interest, taxes, depreciation and amortization, or Adjusted EBITDA, free cash flow and capital for allocation, as well as net income/(loss) and net income/(loss) attributable to NRG Energy, Inc.

The acquired operations of Direct Energy are integrated into the existing NRG segment structure.

Domestic customer and market operations are combined into the corresponding geographical segments of Texas, East and West/Services/Other.

The West/Services/Other segment includes activity related to the Canadian operations as well as the services businesses.

In February 2019, the Company completed the sale and deconsolidation of the South Central Portfolio and Carlsbad.

On August 31, 2018, NRG deconsolidated NRG Yield Inc., its Renewables Platform and Carlsbad for financial reporting purposes.

In 2018, the financial information for historical periods was recast to reflect the presentation of discontinued operations within the corporate segment.

Refer to Note 4, Acquisitions, Discontinued Operations and Dispositions , for further discussion.

The Company had no customer that comprised more than 10% of the Company's consolidated revenues during the years ended December 31, 2021, 2020 and 2019.

The company had one customer in the Texas segment that comprised 11 % of the Company's consolidated revenues during the year ended December 31, 2018.

Intersegment sales are accounted for at market.

For the Year Ended December 31, 2021

(In millions) Texas East West/Other Corporate (a)

(In millions) Texas East West/Services/Other Corporate (a)

Operating revenues (a)

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Impairment losses — 535 9 — — 544

Development costs 4 3 1 — — 8

Total operating cost and expenses 9,023 11,130 3,563 169 10 23,895

(Loss)/gain on sale of assets — — ( 2 ) 5 — 3

Operating income/(loss) 818 381 ( 8 ) ( 86 ) — 1,105

Gain on sale of assets 19 — 17 211 — 247

Operating income 1,289 1,903 107 42 — 3,341

Equity in (losses)/earnings of unconsolidated affiliates ( 3 ) — 20 — — 17

Impairment losses on investments ( 18 ) — — — — ( 18 )

Other income, net 8 7 3 59 ( 14 ) 63

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Income/(loss) from continuing operations before income taxes 1,293 1,909 102 ( 445 ) — 2,859

Income tax (benefit)/expense — ( 1 ) 2 250 — 251

Income tax expense — — 19 653 — 672

Net income/(loss) attributable to NRG Energy, Inc.

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Capital expenditures 153 50 21 45 — 269

325 254 — — — 579

Goodwill 751 853 191 — — 1,795

Total assets $ 12,265 $ 13,673 $ 4,816 $ 19,081 $ ( 26,653 ) $ 23,182

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$ 5 $ ( 18 ) $ 3 $ — $ — $ ( 10 )

(b) Goodwill was allocated based on the regions in which the business operates and are expected to benefit using a relative fair value approach

For the Year Ended December 31, 2020

(In millions) Texas East West/Other Corporate (a)

(In millions) Texas East West/Services/Other Corporate (a)

Operating revenues (a)

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Impairment losses 14 — 61 — — 75

Development costs 3 3 1 — — 7

Total operating cost and expenses 5,490 1,896 518 91 ( 4 ) 7,991

Gain on sale of assets — 1 — 6 — 7

(Loss)/gain on sale of assets — — ( 2 ) 5 — 3

Operating income/(loss) 819 362 10 ( 86 ) — 1,105

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Income/(loss) from continuing operations before income taxes 800 351 39 ( 429 ) — 761

Income tax expense/(benefit) — 2 1 ( 3,337 ) — ( 3,334 )

Net income from continuing operations 972 287 7 2,854 — 4,120

Gain from discontinued operations, net of income tax — — — 321 — 321

Net Income 972 287 7 3,175 — 4,441

Net income attributable to noncontrolling interests and redeemable noncontrolling interests — — 3 — — 3

Income tax (benefit)/expense — ( 1 ) 2 250 — 251

Net income attributable to NRG Energy, Inc.

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For the Year Ended December 31, 2019

(In millions) Texas East West/Other Corporate (a)

(In millions) Texas East West/Services/Other Corporate (a)

Eliminations Total

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Impairment losses 1 — 4 — — 5

Development costs 3 3 3 2 — 11

Total operating cost and expenses 6,010 1,960 494 81 ( 7 ) 8,538

Gain/(loss) on sale of assets 4 — ( 2 ) 30 — 32

Gain on sale of assets — 1 — 6 — 7

Operating income/(loss)

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Impairment losses on investments ( 103 ) — — ( 5 ) — ( 108 )

Other income/(loss), net 13 2 4 ( 1 ) — 18

Other income, net 20 6 10 30 — 66

Loss on debt extinguishment — — ( 3 ) ( 48 ) — ( 51 )

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Income/(loss) from continuing operations before income taxes 972 291 6 ( 483 ) — 786

Income tax expense — 1 — 6 — 7

Net income/(loss) from continuing operations

837 136 91 ( 604 ) — 460

Loss from discontinued operations, net of income tax — — — ( 192 ) — ( 192 )

Net Income/(loss) 837 136 91 ( 796 ) — 268

Net income/(loss) attributable to noncontrolling interests and redeemable noncontrolling interests — — 5 ( 5 ) — —

Net income/(loss) attributable to NRG Energy, Inc.

Income tax expense/(benefit) — 2 1 ( 3,337 ) — ( 3,334 )

Net income from continuing operations 972 289 5 2,854 — 4,120

Gain from discontinued operations, net of income tax — — — 321 — 321

Net Income 972 289 5 3,175 — 4,441

Net income attributable to noncontrolling interests and redeemable noncontrolling interests — — 3 — — 3

Net income attributable to NRG Energy, Inc.

$ 972 $ 289 $ 2 $ 3,175 $ — $ 4,438

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$ 1 $ 8 $ ( 2 ) $ — $ — $ 7

(b) Goodwill was allocated based on the regions in which the business operates and are expected to benefit using a relative fair value approach

Note 20 — Income Taxes

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Tax at federal statutory tax rate 600 160 165

Foreign rate differential ( 3 ) — —

State taxes 111 18 13

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Deferred impact of state tax rate changes ( 10 ) 2 12

Production tax credits ("PTC") — — ( 7 )

Recognition of uncertain tax benefits ( 10 ) 3 ( 10 )

Return to provision adjustments 5 36 —

Alternative minimum tax ("AMT") refundable credit — — ( 4 )

Other — — ( 13 )

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Effective income tax rate 23.5 % 33.0 % ( 424.2 ) %

For the year ended December 31, 2021, NRG's effective income tax rate was higher than the federal statutory tax rate of 21% primarily due to state tax expense partially offset by tax benefits from the revaluation of state deferred tax assets, valuation allowance, and settlements of uncertain tax positions.

For the year ended December 31, 2020, NRG's effective income tax rate was higher than the federal statutory tax rate of 21% primarily due to state tax expense, the recognition of state valuation allowance on NOLs, and return to provision adjustments.

For the year ended December 31, 2019, NRG's effective income tax rate was lower than the federal statutory tax rate of 21% primarily due to the tax benefit from the release of the valuation allowance.

For the year ended December 31, 2018, NRG's effective income tax rate was lower than the federal statutory tax rate of 21% primarily due to a tax benefit for the change in valuation allowance, the generation of PTCs from various wind facilities and establishment of the previously sequestered AMT credit receivable, partially offset by current state tax expense.

The temporary differences, which gave rise to the Company's deferred tax assets and liabilities consisted of the following:

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Emissions allowances 20 21

Derivatives, net — 27

Derivatives 591 —

Goodwill 40 29

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Net deferred tax asset $ 2,082 $ 3,047

The primary drivers for the decrease in the net deferred tax asset from $ 3.3 billion as of December 31, 2019 to $ 3.0 billion as of December 31, 2020 are a decrease in the tax basis of property and the utilization of previously disallowed interest, partially offset by a change in equity method investments.

The primary drivers for the decrease in the net deferred tax asset from $ 3.0 billion as of December 31, 2020 to $ 2.1 billion as of December 31, 2021 are an increase in mark-to-market book gains and step-up in basis of book intangibles associated with the acquisition of Direct Energy.

Deferred tax assets and valuation allowance

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Taxes Receivable and Payable

As of December 31, 2020, NRG recorded a current tax payable of $ 12 million that represents a tax liability due for state income taxes that is primarily comprised of Texas margin tax.

NRG has a tax receivable of $ 1 million, comprised of refunds due from state income tax estimated payments and return filings.

As of December 31, 2021, NRG recorded a current net federal receivable of $ 16 million, comprised of refunds due from the IRS, a current net state tax payable of $ 13 million that is primarily comprised of Texas margin tax, and a current net foreign receivable of $ 11 million due to filings of Canadian amended returns as well as prepayments of estimated taxes.

Uncertain tax benefits

NRG has identified uncertain tax benefits with after-tax value of $ 15 million as of December 31, 2020 and 2019, for which NRG has recorded a non-current tax liability of $ 18 million and $ 17 million, respectively.

NRG has identified uncertain tax benefits with after-tax value of $ 13 million and $ 15 million as of December 31, 2021 and 2020, for which NRG has recorded a non-current tax liability of $ 14 million and $ 18 million, respectively.

The Company recognizes interest and penalties related to uncertain tax benefits in income tax expense.

The Company recognized expense of $ 1 million related to interest in each of the years ended December 31, 2020, 2019 and 2018.

The Company recognized an immaterial amount of interest expense for the year ended December 31, 2021, and $ 1 million for the years ended 2020 and 2019.

As of December 31, 2021 and 2020, NRG had cumulative interest and penalties related to these uncertain tax benefits of $ 1 million and $ 3 million, respectively.

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federal income tax examinations for years prior to 2018.

With few exceptions, state and local income tax examinations are no longer open for years before 2012.

With few exceptions, state and Canadian income tax examinations are no longer open for years before 2013.

The following table summarizes uncertain tax benefits activity:

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Increase due to current year positions 4 3

Increase due to acquired balance from Direct Energy 9 —

Settlements, payments and statute closure ( 15 ) ( 3 )

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As of December 31, 2021, RSUs granted under the Company's LTIPs typically have three -year graded vesting schedules beginning on the grant date.

Fair value of the RSUs granted during 2020 is derived from the closing price of NRG common stock on the grant date.

Fair value of the RSUs granted during 2021 and 2020 is derived from the closing price of NRG common stock on the grant date.

The following table summarizes the Company's non-vested RSU awards and changes during the year:

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Outstanding at December 31, 2021 384,128 26.11

The aggregate intrinsic values for DSUs outstanding as of December 31, 2020, 2019 and 2018 were approximately $ 13 million each year.

The aggregate intrinsic values for DSUs outstanding as of December 31, 2021, 2020 and 2019 were approximately $ 17 million, $ 13 million and $ 13 million, respectively.

The aggregate intrinsic values for DSUs converted to common stock for the years ended December 31, 2021, 2020 and 2019 were $ 1 million, $ 2 million and $ 2 million, respectively.

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PSUs include RPSUs and MSUs.

As of December 31, 2020, non-vested PSUs consist primarily of 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, relative to the TSR of the Company's current proxy peer group and the total returns of select indexes, or Peer Group.

As of December 31, 2021, non-vested PSUs consist of RPSUs.

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.

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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 was 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.

As of March 1, 2021 all MSUs were vested.

(a) For RPSU's granted in 2022 and forward the peer group will consist of the companies that comprise the Standard & Poor’s 500 Index on the first day of the performance period.

The following table summarizes the Company's non-vested PSU awards and changes during the year:

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Non-vested at December 31, 2020 793,561 $ 41.69

928,215 23.75

Granted 426,768 46.78

Forfeited ( 93,031 ) 47.21

( 1,330,053 ) 15.91

Non-vested at December 31, 2020 (c)

793,561 41.69

(a) The weighted average grant date fair value per unit includes RPSUs that were granted during 2020 with grant date fair value of $ 45.60 .

It also includes RPSUs with 2017 grant date fair value of $ 15.91 and MSUs with 2016 grant date fair value of $ 15.28 , that due to vesting at 200 %, were considered additional grants in 2020

(b) MSUs granted during 2016 and RPSUs granted during 2017 vested during 2020 at 200 %

Vested ( 396,793 ) 35.32

Non-vested at December 31, 2021 730,505 47.40

The weighted average grant date fair value of PSUs granted during the years ended December 31, 2021, 2020 and 2019, was $ 46.78 , $ 23.75 and $ 22.50 , respectively.

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Significant assumptions used in the fair value model with respect to the Company's PSUs are summarized below:

2020 2019 2018 2017 2016

RPSUs RPSUs RPSUs RPSUs MSUs

RPSUs RPSUs RPSUs

Expected volatility 34.05 % 30.15 % 40.72 %

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Risk free rate 0.17 % 1.58 % 2.45 %

(a) Assumptions pertain to the main award granted in January 2021.

Additional 60,815 RPSUs were granted in September 2021 with a risk free rate of 0.42 % and expected volatility of 37.38 %

For the years ended December 31, 2021 and 2020, expected volatility is calculated based on NRG's historical stock price volatility data over the period commensurate with the expected term of the PSU, which equals the vesting period.

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DSUs 2 2 2 — 0.00

MSUs — — 4 — 0.01

RPSUs 9 10 10 15 1.19

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Total $ 27 $ 27 $ 32 $ 41

Tax detriment recognized $ ( 9 ) $ ( 12 ) $ ( 4 )

Tax detriment/(benefit) recognized $ 2 $ ( 9 ) $ ( 12 )

(a) Phantom Restricted Stock Units, PRSUs, are liability-classified time-based awards that typically vest ratably over a three -year period.

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Note 22 — Related Party Transactions

NRG provides services to some of its equity method investments under operations and maintenance agreements.

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.

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$ 49 $ 52 $ 44

(a) As of August 31, 2018, NRG no longer had an ownership interest in GenConn as a result of the sale of its ownership interests in NRG Yield, Inc.

and its Renewables Platform

(b) Includes fees under project management agreements with each project company.

Ivanpah became a related party to NRG upon deconsolidation in the second quarter of 2018

Services Agreement and Transition Services Agreement with GenOn

The Company provided GenOn with various management, personnel and other services, which included 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.

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 provided the shared services and other separation services.

For the year ended December 31, 2018, NRG recorded approximately $ 53 million, under the transition services agreement against selling, general and administrative costs post-Chapter 11 Filing.

(a) Includes fees under project management agreements with each project company

Note 23 — Commitments and Contingencies

Coal, Gas and Transportation Commitments

NRG has entered into long-term contractual arrangements to procure fuel and transportation services for the Company's generation assets.

Certain Fuel and Transportation Commitments

NRG has entered into long-term contractual arrangements to procure certain fuel and transportation services for the Company's generation assets.

As of December 31, 2021, the Company's minimum commitments under such outstanding agreements are estimated as follows:

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Thereafter 26

(a) Actual coal, gas and transportation purchases are significantly higher than these estimated minimum unconditional long-term firm commitments

For the years ended December 31, 2020, 2019 and 2018, the Company purchased $ 0.8 billion, $ 1.2 billion and $ 1.2 billion, respectively, under coal, gas and transportation arrangements.

Purchased Power Commitments

NRG has purchased power contracts of various quantities and durations, including renewable purchased power agreements under PPAs with third-party project developers, which are accounted for as NPNS.

(a) Actual fuel and transportation purchases are significantly higher than these estimated minimum unconditional long-term firm commitments with remaining term in excess of one year

For the years ended December 31, 2021, 2020 and 2019, the costs of certain fuel and transportation were $ 0.6 billion, $ 0.5 billion and $ 0.6 billion, respectively.

Purchased Energy Commitments

NRG has long-term contractual commitments related to electricity and natural gas products, including power purchases, gas transportation and storage of various quantities and durations, and renewable purchased power agreements under PPAs with third-party project developers, which are accounted for as NPNS.

These contracts are not included in the consolidated balance sheet as of December 31, 2021.

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Thereafter 1,071

(a) Actual power purchases are significantly higher than these estimated minimum unconditional long-term firm commitments

For the years ended December 31, 2020, 2019 and 2018, the Company purchased $ 142 million, $ 183 million and $ 138 million, respectively, under purchased power arrangements.

(a) Actual energy purchases are significantly higher than these estimated minimum unconditional long-term firm commitments with remaining term in excess of one year

For the years ended December 31, 2021, 2020 and 2019, the costs of purchased energy were $ 12.8 billion, $ 1.8 billion and $ 2.6 billion, respectively.

First Lien Structure

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To the extent that the underlying hedge positions for a counterparty are out-of-the-money to NRG, the counterparty would have a claim under the first lien program.

As of December 31, 2020, hedges under the first lien were in-the-money for NRG on a counterparty aggregate basis.

As of December 31, 2021, hedges under the first lien were out-of-the-money for NRG on a counterparty aggregate basis.

Nuclear Insurance

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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 $ 13.3 billion in funds available for public liability claims.

The current maximum

assessment per incident, per reactor, is approximately $ 138 million, taking into account a 5 % adjustment for administrative fees, payable at approximately $ 21 million per year, per reactor.

The current maximum assessment per incident, per reactor, is approximately $ 138 million, taking into account a 5 % adjustment for administrative fees, payable at approximately $ 21 million per year, per reactor.

NRG would be responsible for 44 % of the maximum assessment, or $ 9 million per year, per reactor, and a maximum of $ 61 million per incident, per reactor.

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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 $ 2 million per week per unit up to a maximum of $ 216 million nuclear and $ 144 million non-nuclear, and is subject to an eight-week waiting period.

This coverage allows for reimbursement up to $ 2 million per week per unit up to a maximum of $ 216 million nuclear and $ 144 million non-nuclear, and is subject to an eight-

week waiting period.

Accidental Outage coverage amounts decrease in the event more than one unit at a station is out of service due to a common accident.

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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.

Midwest Generation LLC — In 2012, several environmental groups filed a complaint against Midwest Generation with the Illinois Pollution Control Board ("IPCB") alleging violations of environmental law resulting in groundwater contamination.

In June 2019, the IPCB found that Midwest Generation violated the law because it had improperly handled coal ash at four facilities in Illinois and caused or allowed coal ash constituents to impact groundwater.

On September 9, 2019, Midwest Generation filed a Motion to Reconsider numerous issues, which the court granted in part and denied in part on February 6, 2020.

The IPCB will hold 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 (“ESCOs”) operating in the industry, from time-to-time, the Company and/or its subsidiaries may be subject to consumer lawsuits in various jurisdictions where they sell natural gas and electricity.

Variable Price Cases — In the cases set forth below, referred to as the Variable Price Cases, such actions involve consumers alleging that one of the Company’s ESCOs promised that consumers would pay the same or less than they would have paid if they stayed with their default utility or previous energy supplier.

The underlying claims of each case are similar and the Company continues to deny the allegations and is vigorously defending these matters.

These matters were known and accrued for at the time of each acquisition.

XOOM Energy is a defendant in a putative class action lawsuit pending in New York.

This case is in the discovery phase.

Direct Energy

There are three putative class actions pending against Direct Energy:

(1) Linda Stanley v.

Direct Energy (S.D.N.Y Apr.

2019) - The parties mediated in June and agreed on a settlement.

On November 16, 2021, the Court granted preliminary approval of the settlement.

The final approval hearing will be held on April 5, 2022.

It may take several months to determine the final payout amount;

(2) Martin Forte v.

Direct Energy (N.D.N.Y.

2017) - The Court recently granted Direct Energy’s Motion for Summary Judgment effectively ending the matter at the district court level.

It is likely that the plaintiff will appeal;

however, it is unlikely plaintiff will prevail;

(3) Richard Schafer v.

Direct Energy (W.D.N.Y.

on appeal 2nd Cir.

N.Y.) - The Court granted limited discovery that will end April 29, 2022.

Summary judgement briefing is due on May 20, 2022.

Telephone Consumer Protection Act ("TCPA") Cases — In the cases set forth below, referred to as the TCPA Cases, such actions involve consumers alleging violations of the Telephone Consumer Protection Act of 1991, as amended, by receiving calls, texts or voicemails without consent in violation of the federal Telemarketing Sales Rule, and/or state counterpart legislation.

The underlying claims of each case are similar.

The Company denies the allegations asserted by plaintiffs and intends to vigorously defend these matters.

These matters were known and accrued for at the time of the acquisition.

There are two putative class actions pending against Direct Energy:

(1) Brittany Burk v.

Direct Energy (S.D.

2019) - The Court denied Plaintiff's Motion for Class Certification and Motion for Substitution of a New Plaintiff on September 20, 2021.

The parties reached a settlement of the plaintiff's individual claims and the Court has conditionally dismissed the matter;

and (2) Matthew Dickson v.

Direct Energy (N.D.

2018) - Direct Energy has filed a Third-Party Petition against its vendor, Total Marketing Concepts, LLC, who placed voicemails without consent from Direct Energy and in violation of the parties’ agreement.

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.

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.

At this time, the Company is unable to determine the extent or impact of these various litigation matters due to their preliminary nature.

The Company intends to vigorously defend these matters.

Indemnifications and Other Contractual Arrangements

Washington-St.

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filed a lawsuit against LaGen in the United States District Court for the Middle District of Louisiana.

The plaintiffs claim breach of contract against LaGen for allegedly improperly charging the plaintiffs for costs related to the installation and maintenance of certain pollution control technology.

The plaintiffs claimed breach of contract against LaGen for allegedly improperly charging the plaintiffs for costs related to the installation and maintenance of certain pollution control technology.

Plaintiffs sought damages for the alleged improper charges and a declaration as to which charges were proper under the contract.

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On March 17, 2020, plaintiffs filed a lawsuit in the Nineteenth Judicial District Court for the Parish of East Baton Rouge in Louisiana alleging substantially the same matters.

The Company anticipates a trial, in state court, to begin in 2023.

On February 4, 2019, NRG sold the South Central Portfolio, including the entities subject to this litigation.

However, NRG has agreed to indemnify the purchaser for certain losses suffered in connection therewith.

Sierra club et al.

On September 9, 2019, Midwest Generation filed a Motion to Reconsider numerous issues, which the court granted in part and denied in part on February 6, 2020.

The IPCB will hold hearings to determine the appropriate relief.

Midwest Generation has been working with the Illinois EPA to address the groundwater issues since 2010.

XOOM Energy Litigation — XOOM has been a defendant in two purported class action lawsuits in Maryland and New York.

The plaintiffs generally claim that they did not receive the savings they were promised in their natural gas and electricity bills.

In the Maryland lawsuit, the district court denied plaintiff's' bid to certify the case as a class action on August 18, 2020.

The matter has been dismissed.

In the New York case, XOOM filed a motion to dismiss, which the court granted on September 21, 2018, later entering judgment in XOOM's favor on September 24, 2018.

The plaintiffs in the New York case appealed to the U.S.

Court of Appeals for the Second Circuit.

On July 26, 2019, the Second Circuit reversed the judgment of the district court and remanded to the district court with instructions that plaintiffs be permitted to proceed on their proposed amended complaint.

The New York case is in the discovery phase.

This matter was known and accrued for at the time of the acquisition.

Note 24 — Regulatory Matters

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California Station Power — As the result of unfavorable final and non-appealable litigation, the Company accrued a liability associated with consumption of station power at the Company's Encina power plant facility in California after August 30, 2010.

The Company has established an appropriate accrual pending potential regulatory action by SDG&E regarding the Company's Encina facility.

The Company has established an appropriate accrual pending potential regulatory action by San Diego Gas & Electric regarding the Company's Encina facility.

South Central — On August 4, 2016, NRG received a document hold notice from FERC regarding conduct in the MISO and PJM markets.

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NRG responded to the preliminary findings on January 15, 2021.

FERC has the authority to require disgorgement of profits and to impose penalties and NRG retains any liability following the sale of the South Central Portfolio.

ISO-NE — On January 8, 2021, the Commission approved a settlement agreement the Company entered into to resolve FERC Enforcement Staff's investigation of offers submitted during the qualification period for the ISO-NE Forward Capacity Auction in 2016.

The settlement was approved in a 2-1 vote.

The Commission Chairman dissented on the basis that the investigation should have been terminated because the Company should not be penalized for reflecting a different expectation from that of the ISO-NE Internal Market Monitor in its forecast of future events submitted for independent review in the tariff-prescribed bid review process.

Under the settlement, the Company agreed to pay a civil penalty of $ 85 thousand and is subject to compliance monitoring.

On September 16, 2021, FERC Office of Enforcement Staff informed NRG that the investigation is closed with no further action.

Note 25 — Environmental Matters

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Circuit vacated the ACE rule (but on February 22, 2021, at the EPA's request, stayed the issuance of the portion of the mandate that would vacate the repeal of the CPP).

Accordingly, we expect the EPA to promulgate a new rule to regulate GHG emissions from power plants.

Effluent Limitations Guidelines — In November 2015, the EPA revised the Effluent Limitations Guidelines for Steam Electric Generating Facilities, which imposed more stringent requirements (as individual permits were renewed) for wastewater streams from FGD, fly ash, bottom ash, and flue gas mercury control.

On October 29, 2021, the U.S.

Supreme Court agreed to review the D.C.

Circuit's decision, which should provide some clarity regarding the scope of the EPA's authority to regulate CO 2 under the Clean Air Act.

The Company expects the EPA to promulgate a new rule to regulate GHG emissions from power plants after a decision from the U.S.

Supreme Court.

Effluent Limitations Guidelines — In November 2015, the EPA revised the ELG for Steam Electric Generating Facilities, which imposed more stringent requirements (as individual permits were renewed) for wastewater streams from FGD, fly ash, bottom ash, and flue gas mercury control.

On September 18, 2017, the EPA promulgated a final rule that, among other things, postponed the compliance dates to preserve the status quo for FGD wastewater and bottom ash transport water by two years to November 2020 until the EPA amended the rule.

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and (iii) changing several deadlines.

The Company is in the process of estimating the environmental capital expenditures that will be required to comply.

The capital expenditures required to comply will depend on elections regarding future operations of each coal-fired unit.

NRG expects to make these elections for each unit in Q4 2021 at which time the EPA will be notified as required.

Accordingly, we do not expect to provide estimates of ELG compliance costs until early 2022.

On July 26, 2021, the EPA announced that it is initiating a new rulemaking to evaluate revising the ELG rule.

While the EPA is developing the new rule, the existing rule (as amended in 2020) will stay in place, and the EPA expects permitting authorities to continue to implement the current regulation.

The EPA anticipates releasing a proposed rule in fall 2022.

In October 2021, NRG informed its regulators that the Company intends to comply with the ELG by ceasing combustion of coal by the end of 2028 at its domestic coal units outside of Texas, and installing appropriate controls by the end of 2025 at its two plants in Texas.

Byproducts, Wastes, Hazardous Materials and Contamination

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On November 12, 2020, the EPA finalized "A Holistic Approach to Closure Part B," which further amended the April 2015 Rule to, among other things, provide procedures for requesting approval to operate existing impoundments with an alternative liner.

The Company has updated its estimates of required environmental capital expenditures.

Note 26 — Cash Flow Information

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Letters of credit and surety bonds — As of December 31, 2021, NRG and its consolidated subsidiaries were contingently obligated for a total of $ 4.1 billion under letters of credit and surety bonds.

The significant increase in 2021 is primarily due to the acquisition of Direct Energy.

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.

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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, except for the California property tax indemnity for estimated increases in California property taxes of certain solar properties that the Company agreed to indemnify NRG Yield for, as part of the agreement to sell NRG Yield and the Renewables Platform.

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 NRG Yield for, as part of the agreement to sell NRG Yield and the Renewables Platform.

The California property tax indemnity is estimated to be $ 158 million as of December 31, 2021 and is included in the above table under asset sales guarantee obligations.

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Year Ended December 31, 2020 242 24 — — 266

Year Ended December 31, 2018 1,863 1,934 ( 128 ) 125 (b)

Year Ended December 31, 2019 3,794 ( 3,543 ) ( 9 ) —

(a) Represents principally net amounts charged as uncollectible

(b) Represents removal of NRG Yield, Inc.

and its Renewables Platform due to their sale on August 31, 2018

EXHIBIT INDEX

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Incorporated herein by reference to Exhibit 2.10 to the Registrant's annual report on Form 10-K filed on March 1, 2018.

2.8‡ Purchase and Sale Agreement dated as of February 28, 2021 by and between NRG Energy, Inc., and Generation Bridge Acquisition, LLC, as a Purchaser

Incorporated herein by reference to Exhibit 2.1 to the Registrant's quarterly report on Form 10-Q filed on May 6, 2021.

3.1 Amended and Restated Certificate of Incorporation.

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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 Fourth Amended and Restated By-Laws.

Incorporated herein by reference to Exhibit 3.1 to the Registrant's current report on Form 8-K filed on February 13, 2017.

3.3 Fifth Amended and Restated By-Laws.

Filed herewith.

4.1 Specimen of Certificate representing common stock of NRG Energy, Inc.

Incorporated herein by reference to Exhibit 4.3 to the Registrant's quarterly report on Form 10-Q filed on August 4, 2006.

4.2 Indenture, dated May 23, 2016, between NRG Energy, Inc.

and Law Debenture Trust Company of New York

Incorporated herein by reference to Exhibit 4.1 to the Registrant's Current Report on Form 8-K, filed on May 23, 2016.

4.3 Supplemental Indenture, dated May 23, 2016, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York.

Incorporated herein by reference to Exhibit 4.2 to the Registrant's Current Report on Form 8-K, filed on May 23, 2016.

4.4 Form of 7.250% Senior Notes due 2026

Incorporated herein by reference to Exhibit 4.1 to the Registrant's Current Report on Form 8-K, filed on May 23, 2016.

4.5 Registration Rights Agreement,dated May 23, 2016, among NRG Energy, Inc., the guarantors named therein and Deutsche Bank Securities Inc., as representative to the initial purchasers listed in Schedule I thereto

Incorporated herein by reference to Exhibit 4.4 to the Registrant's Current Report on Form 8-K, filed on May 23, 2016.

4.2 Second Supplemental Indenture, dated as of July 19, 2016, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York.

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Incorporated herein by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on September 22, 2020.

10.1* Form of NRG Energy Inc.

Long-Term Incentive Plan Deferred Stock Unit Agreement for Officers and Key Management.

Incorporated herein by reference to Exhibit 10.14 to the Registrant's annual report on Form 10-K filed on March 30, 2005.

4.42 Supplemental Indenture (Additional Subsidiary Guarantees-2.750% Convertible Senior Notes due 2048) dated January 5, 2021, among NRG Energy, Inc., each of its guarantor subsidiaries, and Delaware Trust Company as trustee .

Incorporated herein by reference to Exhibit 4.1 to the Registrant's quarterly report on Form 10-Q filed on May 6, 2021.

4.43 Supplemental Indenture (Additional Subsidiary Guarantees 1.841% Senior Secured First Lien Notes due 2023) dated January 5, 2021, among NRG Energy, Inc., each of its guarantor subsidiaries, and Deutsche Bank Trust Company Americas as trustee.

Incorporated herein by reference to Exhibit 4.2 to the Registrant's quarterly report on Form 10-Q filed on May 6, 2021.

4.44 Supplemental Indenture (additional Subsidiary Guarantees-6.625% Senior Notes due 2027) dated January 5, 2021, among NRG Energy, Inc., each of its guarantor subsidiaries , and Delaware Trust Company as trustee.

Incorporated herein by reference to Exhibit 4.4 to the Registrant's quarterly report on Form 10-Q filed on May 6, 2021.

4.45 Supplemental Indenture (additional Subsidiary Guarantees-5.750% Senior Notes due 2028) dated January 5, 2021, Supplemental Indenture (additional Subsidiary Guarantees-5.750% Senior Notes due 2028) dated January 5, 2021, among NRG Energy, Inc., each of its guarantor subsidiaries, and Delaware Trust Company as trustee.

Incorporated herein by reference to Exhibit 4.5 to the Registrant's quarterly report on Form 10-Q filed on May 6, 2021.

4.46 Supplemental Indenture (additional Subsidiary Guarantees-5.250% Senior Notes due 2029) dated January 5, 2021, among NRG Energy, Inc., each of its guarantor subsidiaries, and Delaware Trust Company as trustee.

Incorporated herein by reference to Exhibit 4.6 to the Registrant's quarterly report on Form 10-Q filed on May 6, 2021.

4.47 Supplemental Indenture (Additional Subsidiary Guarantees 3.375% Senior Notes due 2029 and 3.625% Senior Notes due 2031) dated January 5, 2021, among NRG Energy, Inc., each of its guarantor subsidiaries , and Deutsche Bank Trust Company Americas as trustee.

Incorporated herein by reference to Exhibit 4.7 to the Registrant's quarterly report on Form 10-Q filed on May 6, 2021.

4.48 Supplemental Indenture (additional Subsidiary Guarantees-3.750% Senior Secured First Lien Notes due 2024 and 4.450% Senior Secured First Lien Notes due 2029) dated January 5, 2021, among NRG Energy, Inc., each of its guarantor subsidiaries , and Delaware Trust Company as trustee.

Incorporated herein by reference to Exhibit 4.2 to the Registrant's Current Report on Form 8-K, filed on August 23, 2021.

4.49 Supplemental Indenture (Additional Subsidiary Guarantees 2.000% Senior Secured First Lien Notes due 2025 and 2.450% Senior Secured First Lien Notes due 2027) dated January 5, 2021, among NRG Energy, Inc., each of its guarantor subsidiaries , and Deutsche Bank Trust Company Americas as trustee.

Incorporated herein by reference to Exhibit 4.3 to the Registrant's Current Report on Form 8-K, filed on August 23, 2021.

4.50 Second Supplemental Indenture, dated August 23, 2021, among NRG Energy, Inc., the guarantors named therein and Deutsche Bank Trust Company Americas, as trustee.

Incorporated herein by reference to Exhibit 4.2 to the Registrant's Current Report on Form 8-K, filed on August 23, 2021.

4.51 Form of 3.875% Senior Notes due 2032 .

Incorporated herein by reference to Exhibit 4.2 to the Registrant's Current Report on Form 8-K, filed on August 23, 2021.

4.52 Supplemental Indenture (Settlement Elections - 2.750% Convertible Senior Notes due 2048) dated February 22 , 2022, among NRG Energy, Inc., each of its guarantor subsidiaries, and Delaware Trust Company as trustee.

Filed herewith.

4.53 Supplemental Indenture (Additional Subsidiary Guarantees-2.750% Convertible Senior Notes due 2048) dated February 17, 2022, among NRG Energy, Inc., each of its guarantor subsidiaries, and Delaware Trust Company as trustee.

Filed herewith.

4.54 Supplemental Indenture (Additional Subsidiary Guarantees-1.841% Senior Secured First Lien Notes due 2023) dated February 17, 2022, among NRG Energy, Inc., each of its guarantor subsidiaries, and Deutsche Bank Trust Company Americas as trustee .

Filed herewith.

4.55 Supplemental Indenture (Additional Subsidiary Guarantees-6.625% Senior Notes due 2027) dated February 17, 2022, among NRG Energy, Inc., each of its guarantor subsidiaries, and Delaware Trust Company as trustee .

Filed herewith.

4.56 Supplemental Indenture (Additional Subsidiary Guarantees-5.750% Senior Notes due 2028) dated February 17, 2022, among NRG Energy, Inc., each of its guarantor subsidiaries, and Delaware Trust Company as trustee .

Filed herewith.

4.57 Supplemental Indenture (Additional Subsidiary Guarantees-5.250% Senior Notes due 2029) dated February 17, 2022, among NRG Energy, Inc., each of its guarantor subsidiaries, and Delaware Trust Company as trustee .

Filed herewith.

4.58 Supplemental Indenture (Additional Subsidiary Guarantees-3.375% Senior Notes due 2029 and 3.625% Senior Notes due 2031) dated February 17, 2022, among NRG Energy, Inc., each of its guarantor subsidiaries, and Deutsche Bank Trust Company Americas as trustee .

Filed herewith.

4.59 Supplemental Indenture (Additional Subsidiary Guarantees-3.750% Senior Secured First Lien Notes due 2024 and 4.450% Senior Secured First Lien Notes due 2029) dated February 17, 2022, among NRG Energy, Inc., each of its guarantor subsidiaries, and Delaware Trust Company as trustee .

Filed herewith.

4.60 Supplemental Indenture (Additional Subsidiary Guarantees-2.000% Senior Secured First Lien Notes due 2025 and 2.450% Senior Secured First Lien Notes due 2027) dated February 17, 2022, among NRG Energy, Inc., each of its guarantor subsidiaries, and Deutsche Bank Trust Company Americas as trustee .

Filed herewith.

4.61 Supplemental Indenture (Additional Subsidiary Guarantees-3.875% Senior Notes due 2032) dated February 17, 2022, among NRG Energy, Inc., each of its guarantor subsidiaries, and Deutsche Bank Trust Company Americas as trustee .

Filed herewith.

10.1* Form of NRG Energy, Inc.

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10.2* Form of NRG Energy, Inc.

Long-Term Incentive Plan Non-Qualified Stock Option Agreement.

Incorporated herein by reference to Exhibit 10.1 to the Registrant's quarterly report on Form 10-Q filed on November 9, 2004.

10.4* Form of NRG Energy, Inc.

Long-Term Incentive Plan Restricted Stock Unit Agreement for Officers.

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Incorporated herein by reference to Exhibit 10.54 to the Registrant's annual report on Form 10-K filed on February 28, 2014.

10.13* Amended and Restated Employee Stock Purchase Plan.

Incorporated herein by reference to Exhibit 10.2 to the Registrant's current report on Form 8-K filed on April 28, 2017.

10.11 Employment Agreement, dated December 21, 2015, by and between NRG Energy, Inc.

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Incorporated herein by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on December 18, 2017.

10.16 Transition Services Agreement, dated as of December 14, 2017, by and between GenOn Energy, Inc.

and NRG Energy, Inc.

Incorporated herein by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed on December 18, 2017.

10.17 Cooperation Agreement, dated as of December 14, 2017, by and between GenOn Energy, Inc.

and NRG Energy, Inc.

Incorporated herein by reference to Exhibit 10.3 to the Registrant's Current Report on Form 8-K filed on December 18, 2017.

10.13 Pension Indemnity Agreement, dated as of December 14, 2017, by and between NRG Energy, Inc.

1 unchanged sentence

Incorporated herein by reference to Exhibit 10.4 to the Registrant's Current Report on Form 8-K filed on December 18, 2017.

10.19 Employee Matters Agreement, dated as of December 14, 2017, by and between NRG Energy, Inc.

and GenOn Energy, Inc.

Incorporated herein by reference to Exhibit 10.5 to the Registrant's Current Report on Form 8-K filed on December 18, 2017.

10.14 Tax Matters Agreement, initially dated as of December 14, 2017, by and between NRG Energy, Inc.

11 unchanged sentences

10.18* Amended and Restated Employee Stock Purchase Plan

Incorporated herein by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on May 7, 2018.

Incorporated herein by reference to Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q filed on May 2, 2019.

10.19* NRG Energy, Inc.

1 unchanged sentence

Incorporated herein by reference to Exhibit 10.2 to the Registrant's Quarterly Report on Form 10-Q filed on August 2, 2018.

10.20 A copy of Amendment No.

1 to Receivables Loan and Servicing Agreement, dated as of July 26, 2021, 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, 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 Exhibit 4.9 to the Registrant's quarterly report on Form 10-Q filed on August 5, 2021.

10.21* Form of NRG Energy, Inc.

Long-Term Incentive Plan Relative Performance Stock Unit Agreement for Chief Executive Officer

Filed herewith.

10.22* Form of NRG Energy, Inc.

Long-Term Incentive Plan Relative Performance Stock Unit Agreement for Executive Vice Presidents

Filed herewith.

10.23* Form of NRG Energy, Inc.

Long-Term Incentive Plan Relative Performance Stock Unit Agreement for Senior Vice Presidents.

Filed herewith.

21.1 Subsidiaries of NRG Energy, Inc.

6 unchanged sentences

Filed herewith.

31.2 Rule 13a-14(a)/15d-14(a) certification of Gaëtan Frotté.

31.2 Rule 13a-14(a)/15d-14(a) certification of Alberto Fornaro.

Filed herewith.

31.3 Rule 13a-14(a)/15d-14(a) certification of David Callen.

31.3 Rule 13a-14(a)/15d-14(a) certification of Emily Picarello.

Filed herewith.

18 unchanged sentences

^ 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 “[***]”.

Form 10-K Summary

4 unchanged sentences

Chief Executive Officer

March 1, 2021

February 24, 2022

POWER OF ATTORNEY

2 unchanged sentences

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, 2021.

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 February 24, 2022.

Signature Title Date

/s/ MAURICIO GUTIERREZ President, Chief Executive Officer and March 1, 2021

/s/ MAURICIO GUTIERREZ President, Chief Executive Officer and February 24, 2022

Mauricio Gutierrez Director (Principal Executive Officer)

/s/ GAËTAN FROTTÉ Interim Chief Financial Officer March 1, 2021

Gaëtan Frotté (Principal Financial Officer)

/s/ DAVID CALLEN Chief Accounting Officer March 1, 2021

David Callen (Principal Accounting Officer)

/s/ ALBERTO FORNARO Chief Financial Officer February 24, 2022

Alberto Fornaro (Principal Financial Officer)

/s/ EMILY PICARELLO Corporate Controller February 24, 2022

Emily Picarello (Principal Accounting Officer)

/s/ LAWRENCE S.

COBEN Chairman of the Board March 1, 2021

SPENCER ABRAHAM Director March 1, 2021

COBEN Chair of the Board February 24, 2022

SPENCER ABRAHAM Director February 24, 2022

Spencer Abraham

/s/ ANTONIO CARRILLO Director March 1, 2021

/s/ ANTONIO CARRILLO Director February 24, 2022

Antonio Carrillo

/s/ MATTHEW CARTER, JR.

Director March 1, 2021

Director February 24, 2022

Matthew Carter, Jr.

/s/ HEATHER COX Director March 1, 2021

/s/ HEATHER COX Director February 24, 2022

/s/ ELISABETH B.

DONOHUE Director March 1, 2021

HOBBY Director March 1, 2021

/s/ ALEXANDRA PRUNER Director March 1, 2021

DONOHUE Director February 24, 2022

HOBBY Director February 24, 2022

/s/ ALEXANDRA PRUNER Director February 24, 2022

Alexandra Pruner

SCHAUMBURG Director March 1, 2021

SCHAUMBURG Director February 24, 2022

/s/ THOMAS H.

WEIDEMEYER Director March 1, 2021

WEIDEMEYER Director February 24, 2022

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 9A. Controls and Procedures