NRG ENERGY, INC. 10-K

nrg-20211231 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 Form 10-K ☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Fiscal Year ended December 31 , 2021 . ☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Transition period from to . Commission file No. 001-15891 NRG Energy, Inc . (Exact name of registrant as specified in its charter) Delaware (State or other jurisdiction of incorporation or organization) 41-1724239 (I.R.S. Employer Identification No.) 910 Louisiana Street , Houston , Texas (Address of principal executive offices) 77002 (Zip Code) ( 713 ) 537-3000 (Registrant's telephone number, including area code) Securities registered pursuant to Section 12(b) of the Act: Title of Each Class Trading Symbol(s) Name of Exchange on Which Registered Common Stock, par value $0.01 NRG New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None I ndicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐ Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ☐ No ☒ Indicate by check mark whether the registrant (1) has filed all reports to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act. Large Accelerated Filer ☒ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company ☐ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C 7262(b)) by the registered public accounting firm that prepared or issued its audit report ☒ Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒ As of the last business day of the most recently completed second fiscal quarter, the aggregate market value of the common stock of the registrant held by non-affiliates was approximately $ 8,611,281,553 based on the closing sale price of $40.30 as reported on the New York Stock Exchange. Indicate the number of shares outstanding of each of the registrant's classes of common stock as of the latest practicable date. Class Outstanding at February 24, 2022 Common Stock, par value $0.01 per share 242,153,239 Documents Incorporated by Reference: Portions of the Registrant's definitive Proxy Statement relating to its 2022 Annual Meeting of Stockholders are incorporated by reference into Part III of this Annual Report on Form 10-K 1 TABLE OF CONTENTS GLOSSARY OF TERMS 3 PART I 7 Item 1 — Business 7 Item 1A — Risk Factors 24 Item 1B — Unresolved Staff Comments 39 Item 2 — Properties 40 Item 3 — Legal Proceedings 41 Item 4 — Mine Safety Disclosures 41 PART II 42 Item 5 — Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 42 Item 6 — Reserved 43 Item 7 — Management's Discussion and Analysis of Financial Condition and Results of Operations 44 Item 7A — Quantitative and Qualitative Disclosures About Market Risk 73 Item 8 — Financial Statements and Supplementary Data 76 Item 9 — Changes in and Disagreements With Accountants on Accounting and Financial Disclosure 76 Item 9A — Controls and Procedures 76 Item 9B — Other Information 79 Item 9C— Disclosure Regarding Foreign Jurisdictions that Prevent Inspections 79 PART III 80 Item 10 — Directors, Executive Officers and Corporate Governance 80 Item 11 — Executive Compensation 80 Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 80 Item 13 — Certain Relationships and Related Transactions, and Director Independence 81 Item 14 — Principal Accounting Fees and Services 81 PART IV 82 Item 15 — Exhibits, Financial Statement Schedules 82 Item 16 — Form 10-K Summary 166 EXHIBIT INDEX 160 2 Glossary of Terms When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below: ACE Affordable Clean Energy Adjusted EBITDA Adjusted earnings before interest, taxes, depreciation and amortization ARO Asset Retirement Obligation ASC The FASB Accounting Standards Codification, which the FASB established as the source of authoritative GAAP ASU Accounting Standards Updates – updates to the ASC AUC Alberta Utilities Commission Average realized prices Volume-weighted average power prices, net of average fuel costs and reflecting the impact of settled hedges Bankruptcy Code Chapter 11 of Title 11 of the U.S. Bankruptcy Code Bankruptcy Court United States Bankruptcy Court for the Southern District of Texas, Houston Division Baseload Units expected to satisfy minimum baseload requirements of the system and produce electricity at an essentially constant rate and run continuously Brazos Brazos Electric Power Cooperative, Inc. BTU British Thermal Unit Business NRG Business, which serves business customers CAA Clean Air Act CAISO California Independent System Operator CARES Act Coronavirus Aid, Relief, and Economic Security Act Carlsbad Carlsbad Energy Center, a 528 MW natural gas-fired project located in Carlsbad, CA CCR Coal Combustion Residuals CDD Cooling Degree Day Centrica Centrica plc CES Clean Energy Standard CFTC U.S. Commodity Futures Trading Commission Cleco Cleco Corporate Holdings LLC CO 2 Carbon Dioxide CO 2 e Carbon Dioxide Equivalents ComEd Commonwealth Edison Company NRG Energy, Inc. Convertible Senior Notes As of December 31, 2021, consists of NRG’s $575 million unsecured 2.75% Convertible Senior Notes due 2048 Cottonwood Cottonwood Generating Station, a 1,177 MW natural gas-fueled plant COVID-19 Coronavirus Disease 2019 CPP Clean Power Plan CPUC California Public Utilities Commission CWA Clean Water Act D.C. Circuit U.S. Court of Appeals for the District of Columbia Circuit Distributed Solar Solar power projects that primarily sell power to customers for usage on site, or are interconnected to sell power into a local distribution grid DSI Dry Sorbent Injection DSU Deferred Stock Unit Dual fuel customers Customer that have both electricity and natural gas service with the Company Economic gross margin Sum of energy revenue, capacity revenue, retail revenue and other revenue, less cost of fuels and other cost of sales EGU Electric Generating Unit 3 EPA U.S. Environmental Protection Agency EPC Engineering, Procurement and Construction ERCOT Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas ESCO Energy Service Companies ESP Electrostatic Precipitator ESPP NRG Energy, Inc. Amended and Restated Employee Stock Purchase Plan Exchange Act The Securities Exchange Act of 1934, as amended FASB Financial Accounting Standards Board FERC Federal Energy Regulatory Commission FGD Flue gas desulfurization FPA Federal Power Act FTRs Financial Transmission Rights GAAP Generally accepted accounting principles in the U.S. GenOn GenOn Energy, Inc. GenOn Entities GenOn and certain of its wholly owned subsidiaries, including GenOn Americas Generation, LLC, that filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court on June 14, 2017 GHG Greenhouse Gas GIP Global Infrastructure Partners Green Mountain Energy Green Mountain Energy Company GW Gigawatts GWh Gigawatt Hours HDD Heating Degree Day Heat Rate A measure of thermal efficiency computed by dividing the total BTU content of the fuel burned by the resulting kWhs generated. Heat rates can be expressed as either gross or net heat rates, depending whether the electricity output measured is gross or net generation and is generally expressed as BTU per net kWh HLBV Hypothetical Liquidation at Book Value HLW High-level radioactive waste Home NRG Home, which serves residential customers ICE Intercontinental Exchange ISO Independent System Operator, also referred to as RTOs ISO-NE ISO New England Inc. Ivanpah Ivanpah Solar Electric Generation Station, a 393 MW solar thermal power plant located in California's Mojave Desert in which NRG owns 54.5% interest kWh Kilowatt-hours LaGen Louisiana Generating LLC LIBOR London Inter-Bank Offered Rate LSE Load Serving Entities LTIPs Collectively, the NRG LTIP and the NRG GenOn LTIP MATS Mercury and Air Toxics Standards promulgated by the EPA MDth Thousand Dekatherms Merger The merger completed on December 14, 2012 by NRG and GenOn pursuant to the Merger Agreement Midwest Generation Midwest Generation, LLC MISO Midcontinent Independent System Operator, Inc. MMBtu Million British Thermal Units MMDth Million Dekatherms 4 MSU Market Stock Unit MW Megawatts MWe Megawatt equivalent MWh Saleable megawatt hour net of internal/parasitic load megawatt-hour NAAQS National Ambient Air Quality Standards NEIL Nuclear Electric Insurance Limited NEPOOL New England Power Pool NERC North American Electric Reliability Corporation Net Capacity Factor The net amount of electricity that a generating unit produces over a period of time divided by the net amount of electricity it could have produced if it had run at full power over that time period. The net amount of electricity produced is the total amount of electricity generated minus the amount of electricity used during generation Net Exposure Counterparty credit exposure to NRG, net of collateral Net Generation The net amount of electricity produced, expressed in kWhs or MWhs, that is the total amount of electricity generated (gross) minus the amount of electricity used during generation Net Revenue Rate Sum of retail revenues less TDSP transportation charges NOL Net Operating Loss NO x Nitrogen Oxides NPNS Normal Purchase Normal Sale NQSO Non-Qualified Stock Option NRC U.S. Nuclear Regulatory Commission NRG NRG Energy, Inc. NRG GenOn LTIP NRG 2010 Stock Plan for GenOn Employees (formerly the GenOn Energy, Inc. 2010 Omnibus Incentive Plan, which was assumed by NRG in connection with the Merger) NRG LTIP NRG Energy, Inc. Amended and Restated Long-Term Incentive Plan NRG Yield, Inc. NRG Yield, Inc., which changed its name to Clearway energy, Inc. following the sale by NRG or NRG Yield and the Renewables Platform to GIP Nuclear Decommissioning Trust Fund NRG's nuclear decommissioning trust fund assets, which are for the Company's portion of the decommissioning of the STP, units 1 & 2 Nuclear Waste Policy Act U.S. Nuclear Waste Policy Act of 1982 NYISO New York Independent System Operator NYMEX New York Mercantile Exchange NYSDEC New York State Department of Environmental Conservation OCI/OCL Other Comprehensive Income/(Loss) ORDC Operating Reserve Demand Curve ORDPA Online Reliability Deployment Price Adder Peaking Units expected to satisfy demand requirements during the periods of greatest or peak load on the system Petra Nova Petra Nova Parish Holdings, LLC Pipeline Projects that range from identified lead to shortlisted with an offtake, and represents a lower level of execution certainty PJM PJM Interconnection, LLC PM2.5 Particulate Matter that has a diameter of less than 2.5 micrometers PPA Power Purchase Agreement PPM Parts per million PSU Performance Stock Unit PUCT Public Utility Commission of Texas Rayburn Rayburn Country Electric Cooperative, Inc. RCRA Resource Conservation and Recovery Act of 1976 5 Receivables Securitization Facilities Collectively, the Receivables Facility and the Repurchase Facility RECs Renewable Energy Certificates Renewables Consists of the following projects in which NRG has an ownership interest: Agua Caliente, Ivanpah, and solar generating stations located at various NFL Stadiums Renewables Platform The renewable operating and development platform sold to GIP with NRG's interest in NRG Yield. Revolving Credit Facility The Company's $3.7 billion revolving credit facility as of December 31, 2021, a component of the Senior Credit Facility, due 2024 was amended on May 28, 2019 and August 20, 2020 RGGI Regional Greenhouse Gas Initiative RMR Reliability Must-Run RPS Renewable Portfolio Standards RPSU Relative Performance Stock Unit RSU Restricted Stock Unit RTO Regional Transmission Organization SCR Selective Catalytic Reduction Control System SEC U.S. Securities and Exchange Commission Securities Act The Securities Act of 1933, as amended Senior Credit Facility NRG's senior secured credit facility, comprised of the Revolving Credit Facility and the 2023 Term Loan Facility. The 2023 Term Loan Facility was repaid in the second quarter of 2019 Senior Notes As of December 31, 2021, NRG's $4.6 billion outstanding unsecured senior notes consisting of $375 million of the 6.625% senior notes due 2027, $821 million of 5.75% senior notes due 2028, $733 million of the 5.25% senior notes due 2029, $500 million of the 3.375% senior notes due 2029, $1.0 billion of the 3.625% senior notes due 2031 and $1.1 billion of the 3.875% senior notes due 2032 Senior Secured Notes As of December 31, 2021, NRG’s $2.5 billion outstanding Senior Secured First Lien Notes consists of $600 million of the 3.75% Senior Secured First Lien Notes due 2024, $500 million of the 2.0% Senior Secured First Lien Notes due 2025, $900 million of the 2.45% Senior Secured First Lien Notes due 2027, and $500 million of the 4.45% Senior Secured First Lien Notes due 2029 SNF Spent Nuclear Fuel SO 2 Sulfur Dioxide South Central Portfolio NRG's South Central Portfolio, which owned and operated a portfolio of generation assets consisting of Bayou Cove, Big Cajun-I, Big Cajun-II, Cottonwood and Sterlington, was sold on February 4, 2019. NRG is leasing back the Cottonwood facility through May 2025 S&P Standard & Poor's STP South Texas Project — nuclear generating facility located near Bay City, Texas in which NRG owns a 44% interest STPNOC South Texas Project Nuclear Operating Company Tax Act The Tax Cuts and Jobs Act of 2017 TDSP Transmission/distribution service provider Texas Genco Texas Genco LLC TSR Total Shareholder Return TWCC Texas Westmoreland Coal Co. TWh Terawatt Hours U.S. United States of America U.S. DOE U.S. Department of Energy VaR Value at Risk VIE Variable Interest Entity Winter Storm Uri A major winter and ice storm that had widespread impacts across North America occurring in February 2021 6 PART I Item 1 — Business General 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 sells power, natural gas, and 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 as of December 31, 2021. NRG sold 157 TWhs of electricity and 1,877 MMDth of natural gas in 2021, making it one of the largest competitive energy retailers in the U.S. As of the end of 2021, NRG had recurring electricity and/or natural gas sales in 24 U.S. states, the District of Columbia, and 8 provinces in Canada. NRG's retail brands, collectively, have the largest share of competitively served residential electric customers in Texas and nationwide. The following chart represents NRG's sales volumes for the year ended December 31, 2021: Strategy NRG's strategy is to maximize stakeholder value through the safe production and sale of reliable electricity and natural gas to its customers in the markets it serves, while positioning the Company to provide innovative solutions to the end-use energy or service customer. This strategy is intended to enable the Company to optimize its integrated model to generate stable and predictable cash flow, significantly strengthen earnings and cost competitiveness, and lower risk and volatility. Sustainability is a philosophy that underpins and facilitates value creation across our business for our stakeholders. It is an integral piece of NRG's strategy and ties directly to business success, reduced risks and enhanced reputation. To effectuate the Company’s strategy, NRG is focused on: (i) serving the energy needs of end-use residential, commercial and industrial, and wholesale customers in competitive markets through multiple brands and channels; (ii) offering a variety of energy products and services, including renewable energy solutions, that are differentiated by innovative features, premium service, sustainability, and loyalty/affinity programs; (iii) excellence in operating performance of its assets; (iv) optimal hedging of its portfolio; and (v) engaging in disciplined and transparent capital allocation. The 2021 fiscal year was pivotal for the Company. NRG completed the acquisition of Direct Energy, doubling the size of its retail portfolio, while further decreasing its physical generation through the sale and planned retirement of certain assets, each as further discussed below. The completion of these significant activities positioned NRG for the next phase of its strategy focusing on growth. 7 The Company implemented a four-year plan beginning in 2022 to invest up to $2 billion in order to achieve growth through optimization of the Company's core power and natural gas sales, as well as integrated solution sales within its core network in both power and home services. Significant Acquisitions, Dispositions and Announced Retirements On January 5, 2021, the Company acquired Direct Energy. Direct Energy is a leading retail provider of electricity, natural gas, and home and business energy-related products and services in North America, with operations in all 50 U.S. states and 8 Canadian provinces. The acquisition increased NRG's retail portfolio by over 3 million customers and complemented its integrated model. It also broadened the Company's presence in the Northeast and in states and locales where it did not previously operate, supporting NRG's objective to diversify its business. NRG realized its planned synergy target of $175 million in 2021 and expects to realize annual synergies of $225 million and $300 million in 2022 and 2023, respectively. See Item 15 — 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 of operations to Generation Bridge, an affiliate of ArcLight Capital Partners. 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. See Item 15 — Note 4, Acquisitions, Discontinued Operations and Dispositions , to the Consolidated Financial Statements for further discussion. 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. Extreme Weather Event in Texas During February 2021 and expected Uplift Securitization proceeds During February 2021, Texas experienced unprecedented cold temperatures for a prolonged duration as a result of Winter Storm Uri, resulting in a power emergency, blackouts, and an estimated all-time peak demand of 77 GW (without load shed). Ahead of the event, NRG launched residential customer communications calling for conservation across all of its brands, and initiated residential and commercial and industrial demand response programs to curtail customer load. The Company maximized available generating capacity and brought in additional resources to supplement in-state staff with technical and operating experts from the rest of its U.S. fleet. The Texas Legislature passed House Bill ("HB") 4492, which among other things, authorized ERCOT to obtain $2.1 billion of financing to distribute to LSEs that were charged and paid to ERCOT exceptionally highly priced ORDPA and ancillary service costs during Winter Storm Uri (the "Uplift Securitization"). NRG will receive $689 million from ERCOT based on LSE-level detail published by the PUCT on December 7, 2021. During the year ended December 31, 2021, Winter Storm Uri's pre-tax financial impact to the Company was a loss of $380 million, which reflects the recovery of $689 million of cost of operations as a result of the proceeds NRG will receive from the Uplift Securitization discussed above, with receipt expected to occur during the second quarter of 2022. The Company continues to pursue additional mitigants including, but not limited to, customer bad debt mitigation, counterparty default recovery, and additional ERCOT default recovery. Business Overview The Company’s core business is the sale of electricity and natural gas to residential, commercial and industrial and wholesale customers, supported by the Company's wholesale generation. NRG 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 all activity related to customer, plant and market operations in the East; • West/Services/Other, which primarily includes the following assets and activities: (i) all activity related to customer, plant and market operations in the West and Canada, (ii) the services businesses, (iii) activity related to the Cottonwood facility, (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; and • Corporate activities. 8 As of December 31, 2021, in Texas, the Company’s generation supply is fully integrated with its retail load. In the East, the Company’s retail load is more dispersed throughout the region and not fully integrated with the Company’s generation supply due to the locations of its power plants in that region. In the West/Services/Other, the Company’s business is primarily serving retail load and services customers. The Company’s integrated model consists of three core functions: Customer Operations, Market Operations and Plant Operations, which directly support each other in each geographic region. The Company’s integrated model in Texas provides the advantage of being able to supply a significant portion of the Company’s retail customers with electricity from the Company’s assets, which reduces the need to sell electricity to and buy electricity from other institutions and intermediaries, resulting in stable earnings and cash flows, lower transaction costs and less credit exposure. The integrated model also results in a reduction in actual and contingent collateral through offsetting transactions, thereby reducing transactions with third parties. Customer Operations Customer Operations is responsible for growing and retaining the customer base and delivering an outstanding customer experience. This includes acquisition and retention of all of NRG’s residential, small commercial, government and commercial & industrial customers. NRG employs a multi-brand strategy that leverages a wide array of sales and partnership channels, direct face-to-face sales channels, call centers, websites, and brokers. Go-to-market activities include market strategy planning and development, product innovation, offer design, campaign execution, marketing and creative services, and selling. Customer portfolio maintenance and retention activities include fulfillment, billing, payment processing, collections, customer service, issue resolution, and contract renewals. NRG provides energy and related services at either fixed, indexed or month-to-month prices. Home customers typically contract for terms ranging from one month to five years, while Business contracts are often between one year and five years in length. Throughout all Customer Operations activities, the customer experience is kept at the forefront to inform decision-making and optimize retention, while creating supporters and advocates for NRG’s brands in the market. Following the expansion of the customer base with the acquisition of Direct Energy, Customer Operations now comprises three end-use customer facing teams: NRG Home, which serves residential customers, NRG Business, which serves business customers, and NRG Services, which primarily includes the services businesses acquired. Product Offerings NRG sells a variety of products to residential and small commercial customers, including retail electricity and energy management, natural gas, home security, line and surge protection products, HVAC installation, repair and maintenance, home protection products, carbon offsets, back-up power stations, portable power, portable solar and portable lighting. Home and Services customers make purchase decisions based on a variety of factors, including price, incentive, customer service, brand, innovative offers/features and referrals from friends and family. Through its broad range of service offerings and value propositions, NRG is able to attract, retain, and increase the value of its customer relationships. NRG's brands are recognized for exemplary customer service, innovative smart energy and technology product offerings, and environmentally-friendly solutions. The Company provides power and natural gas to the business-to-business markets in North America, as well as retail services, including demand response, commodity sales, energy efficiency and energy management solutions to Business customers. The Company is an integrated provider of supply and distributed energy resources and focuses on distributed products and services as businesses seek greater reliability, cleaner power and other benefits that they cannot obtain from the grid. These solutions include system power, distributed generation, renewable products, carbon management and specialty services, backup generation, storage and distributed solar, demand response, and energy efficiency and advisory services. In providing on-site energy solutions, the Company often benefits from its ability to supply energy products from its wholesale generation portfolio to Business customers. Market Operations Market Operations has two primary objectives: (i) to supply energy to our customers in the most cost-efficient manner; and (ii) to maximize the value of the Company's assets after satisfying its customer load requirements. These objectives are intended to reduce supply costs and maximize earnings with predictable cash flows. Power and natural gas are the two main commercial groups within market operations. Power The power commercial group is responsible for end-use electricity supply including power plant optimization and certain fuel supply. To meet the market operations objectives, NRG enters into supply, power and gas sales and hedging agreements via a wide range of products and contracts, including (i) physical and financial commodity instruments, (ii) fuel supply and transportation contracts, (iii) renewable PPAs and (iv) capacity and other contracted revenue sources, as further discussed below. 9 In addition, because changes in power prices in the markets where NRG operates are generally correlated to changes in natural gas prices, NRG uses hedging strategies that may include power and natural gas forward purchases and sales contracts to manage the commodity price risk. Physical and Financial Commodity Instruments NRG trades electric power, natural gas and related commodities, environmental products, weather products and financial products, including forwards, futures, options and swaps. NRG enters into these instruments primarily to manage price and delivery risk, optimize physical and contractual assets in the portfolio, manage working capital requirements, reduce the carbon exposure in its business and comply with laws. Fuel Supply and Transportation Contracts NRG's fuel requirements consist of various forms of fossil fuel and nuclear fuel. The prices of fossil fuels can be volatile. The Company obtains its fossil fuels from multiple suppliers and through multiple transporters. Although availability is generally not an issue, localized shortages, transportation availability, delays arising from extreme weather conditions and supplier financial stability issues can and do occur. The preceding factors related to the sources and availability of raw materials are fairly uniform across the Company's business and fuel products used. NRG's primary fuel requirements consist of the following: Natural Gas — NRG operates a fleet of mid-merit and peaking natural gas plants. Fuel needs are managed by the natural gas commercial group, on a spot basis, especially for peaking assets, as the Company does not believe it is prudent to forward purchase natural gas for these types of units as the dispatch is highly unpredictable. Coal —NRG actively manages its coal requirements based on forecasted generation, market volatility and its inventory on site. The Company believes it is adequately hedged, using forward coal supply agreements, for its domestic coal consumption for 2022. As of December 31, 2021, NRG had purchased forward contracts to provide fuel for approximately 88% of the Company's expected requirements for 2022 and 2023. For the domestic fleet, NRG purchased approximately 16.1 million tons of coal in 2021, almost all of which was Powder River Basin coal. For fuel transport, NRG has entered into various rail transportation and rail car lease agreements with varying tenors that will provide for most of the Company's transportation requirements of Powder River Basin coal for the next three years. Nuclear Fuel — STP's owners, including NRG, satisfy their fuel supply requirements by: (i) acquiring uranium concentrates and contracting for conversion of the uranium concentrates into uranium hexafluoride; (ii) contracting for enrichment of uranium hexafluoride; and (iii) contracting for fabrication of nuclear fuel assemblies. Through its proportionate participation in STPNOC, which is the NRC-licensed operator of STP that is responsible for all aspects of fuel procurement, NRG is party to a number of long-term forward purchase contracts with many of the world's largest suppliers covering STP's requirements for uranium concentrates with only approximately 25% of STP's requirements outstanding for the duration of the original operating license (through 2027/2028). Similarly, STP has begun the process of covering fuel supply requirements into the extended license period and has secured a fabrication contract with Westinghouse through 2047/2048. Other fuel requirements such as uranium, conversion and enrichment remain open at this time. Renewable PPAs The Company's strategy is to procure mid to long-term renewable generation through power purchase agreements. As of December 31, 2021, NRG has entered into PPAs totaling approximately 2.6 GW with third-party project developers and other counterparties. The average tenor of these agreements is twelve years. The Company expects to continue evaluating and executing similar agreements that support the needs of the business. The total GW entered into through PPAs may be impacted by contract terminations when they occur. Capacity and Other Contracted Revenue Sources NRG's revenues and cash flows, primarily in the East and West, benefit from capacity/demand payments and other contracted revenue sources, originating from market clearing capacity prices, resource adequacy contracts, tolling arrangements and other long-term contractual arrangements. The Company's largest sources of continuing capacity revenues are capacity auctions in PJM and NYISO. PJM operates a pay-for-performance model where capacity payments are modified based on real-time performance and NRG's actual revenues will be the combination of revenues based on the cleared auction MW plus the net of any over- and under-performance of NRG's respective generation assets. The Company primarily sells physical and financial capacity forward through bilateral contracts for our New York state assets. To the extent NRG is not able to enter into physical bilateral contracts, NRG will sell the remaining capacity into the NYISO six-month strip, monthly or spot auctions. 10 In California, there is a resource adequacy requirement that is primarily satisfied through bilateral contracts. Such bilateral contracts are typically short-term resource adequacy contracts. When bilateral contracting does not satisfy the resource adequacy need, such shortfalls can be addressed through procurement tools administered by the CAISO, including the capacity procurement mechanism or reliability must-run contracts. Natural Gas The natural gas commercial group is responsible for all costing, logistics and supply for all of NRG's residential, commercial & industrial and wholesale customers. The Direct Energy acquisition, which closed on January 5, 2021, significantly increased our capabilities and scale across the natural gas value chain. NRG has acquired contractual rights to natural gas transportation and storage assets across its footprint that allow for optimal supply economics in support of our various businesses. Our diversified load coupled with this asset portfolio enables us to deliver supply economically while providing incremental optimization activities when market conditions allow. The scale of the natural gas operation extends from the wellhead (through our producer services business) to our end use customers (through our various sales channels). This scale, coupled with our associated assets, gas system platform and people, create significant opportunity across North America. Plant Operations The Company owns and leases a diversified wholesale generation portfolio with approximately 18,000 MW of fossil fuel, nuclear and renewable generation capacity at 25 plants as of December 31, 2021, including approximately 1,600 MW of its PJM coal fleet with an announced retirement date of June 2022. The Company's wholesale generation assets are diversified by fuel-type and dispatch level, which helps mitigate the risks associated with fuel price volatility and market demand cycles. NRG continually evaluates its generation portfolio to focus on asset optimization opportunities and the locational value of its generation assets in each of the markets where the Company participates, as well as opportunities for the development of new generation. The following table summarizes NRG's generation portfolio as of December 31, 2021: (In MW) (a) Type Texas East West/Services/Other Total Natural gas 4,775 1,881 1,494 8,150 Coal 4,174 3,140 605 7,919 Oil — 455 — 455 Nuclear 1,132 — — 1,132 Utility Scale Solar — — 219 219 Battery Storage 2 — — 2 Total generation capacity 10,083 5,476 2,318 17,877 (a) All Utility Scale Solar are described in MW on an alternating current basis. MW figures provided represent nominal summer net MW capacity of power generated as adjusted for the Company's owned or leased interest. Plant Operations is responsible for operating the Company's generation facilities at the highest standards of safety and reliability, and includes (i) operations and maintenance, (ii) asset management, and (iii) development, engineering and construction. Operations & Maintenance NRG operates and maintains its generation portfolio, as well as approximately 7,377 MW of additional coal and natural gas generation capacity at 12 plants operated on behalf of third parties as of December 31, 2021 using prudent industry practices for the safe, reliable and economic generation of electricity in compliance with all local, state and federal requirements. The Company follows a consistent set of operating requirements, including a solid base of training, required adherence to specific safety and environmental limits, procedure and checklist usage, and the implementation of continuous process improvement through incident investigations. NRG uses best-in-class maintenance practices for preventive, predictive, and corrective maintenance planning. The Company’s strategic planning process evaluates equipment condition, performance, and obsolescence to support the development of a comprehensive work scope and schedule for long-term performance. 11 Asset Management NRG manages all aspects of its generation portfolio to optimize the lifecycle value of the assets, consistent with the Company’s goals. The Company evaluates capital projects required for continued operation and strategic enhancement of the assets, provides quality assurance on capital outlays, and assesses the impact of rules, regulations, and laws on business profitability. In addition, the Company manages its long-term contracts, PPAs, and real estate holdings and provides third party asset management services. Development, Engineering & Construction NRG develops, engineers and executes major plant modifications, “new build” generation and energy storage projects that enhance the value of its generation portfolio and provide options to meet generation growth needs in the retail markets we serve, in accordance with the Company’s strategic goals. Projects have included gas-fired generation development and construction, coal to gas conversions, grid scale energy storage development, grid scale renewable construction, and asset demolition, remediation and reclamation work. Operational Statistics The following statistics represent the Company's retail load and customer count: Year ended December 31, 2021 2020 2019 Sales volumes - Electricity (in GWh) Home - Texas 42,397 38,473 38,958 Home - East 14,108 10,221 9,918 Home - West/Services/Other 2,252 — — Business - Texas 34,367 17,928 18,976 Business - East 53,204 1,596 1,214 Business - West/Services/Other 10,625 — — Total Load 156,953 68,218 69,066 Sales volumes - Natural gas (in MDth) Home - East 74,920 23,509 23,359 Home - West/Services/Other 97,272 — — Business - East 1,595,533 — — Business - West/Services/Other 109,021 — — Total Load 1,876,746 23,509 23,359 12 Year ended December 31, 2021 2020 2019 Customer count - Electricity customers (a)(b) (in thousands) Home - Texas Average retail 3,055 2,449 2,358 Ending retail 3,024 2,451 2,450 Home - East Average retail 1,484 1,019 990 Ending retail 1,402 970 1,070 Home - West/Services/Other Average retail 510 — — Ending retail 498 — — Customer count - Natural gas customers (b) (in thousands) Home - East Average retail 360 156 122 Ending retail 364 166 158 Home - West/Services/Other Average retail 452 — — Ending retail 434 — — Total Customer count Average retail - Home 5,861 3,624 3,470 Ending retail - Home 5,722 3,587 3,678 (a) Includes services customers (b) Dual fuel customers are included within electricity customer counts only The following are industry statistics for the Company's fossil and nuclear plants, as defined by the NERC: Annual Equivalent Availability Factor, or EAF — Measures the percentage of maximum generation available over time as the fraction of net maximum generation that could be provided over a defined period of time after all types of outages and deratings, including seasonal deratings, are taken into account. Net Heat Rate — The net heat rate represents the total amount of fuel in BTU required to generate one net kWh provided. Net Capacity Factor — The net amount of electricity that a generating unit produces over a period of time divided by the net amount of electricity it could have produced if it had run at full power over that time period. The net amount of electricity produced is the total amount of electricity generated minus the amount of electricity used during generation by the station. The tables below presents these performance metrics for the Company's generation portfolio, including leased facilities, for the years ended December 31, 2021 and 2020: Year Ended December 31, 2021 Fossil and Nuclear Plants (a) Net Owned Capacity (MW) (b) Net Generation (In thousands of MWh) (a) Annual Equivalent Availability Factor Average Net Heat Rate BTU/kWh Net Capacity Factor Texas 10,083 36,920 70.6 % 10,717 42.4 % East 5,476 7,494 79.8 % 11,877 8.8 % West/Services/Other 2,318 7,949 88.0 % 7,337 47.2 % 13 Year Ended December 31, 2020 Fossil and Nuclear Plants (a) Net Owned Capacity (MW) Net Generation (In thousands of MWh) (a) Annual Equivalent Availability Factor Average Net Heat Rate BTU/kWh Net Capacity Factor Texas 10,082 31,385 76.0 % 10,781 35.9 % East 9,482 4,102 81.7 % 12,329 4.8 % West/Services/Other 3,234 9,171 88.0 % 7,338 52.3 % (a) Excludes equity method investments The generation performance by region for the three years ended December 31, 2021, 2020 and 2019 is shown below: Net Generation (In thousands of MWh) 2021 2020 2019 Texas Coal 18,876 15,701 21,985 Gas 8,846 6,006 6,315 Nuclear (a) 9,198 9,678 9,695 Total Texas 36,920 31,385 37,995 East Coal 5,774 1,888 4,435 Oil 201 322 209 Gas 1,519 1,892 2,269 Total East (b) 7,494 4,102 6,913 West/Services/Other Gas 7,941 9,165 9,450 Renewables 8 6 12 Total West/Services/Other (c) 7,949 9,171 9,462 Total generation performance 52,363 44,658 54,370 (a) Reflects the Company's undivided interest in total MWh generated by STP (b) Includes gas generation of 855 thousand MWh, 870 thousand MWh and 903 thousand MWh and oil generation of 199 thousand MWh, 322 thousand MWh and 209 thousand MWh for the years ended December 31, 2021, 2020 and 2019, respectively, that was sold to Generation Bridge (c) Includes gas generation of 2,445 thousand MWh, 3,002 thousand MWh, and 2,203 thousand MWh for the years ended December 31, 2021, 2020 and 2019, respectively, that was sold to Generation Bridge Competition While there has been consolidation in the competitive retail space over the past few years, there is still considerable competition for customers. In Texas, there is healthy competition in deregulated areas and customers can choose providers based on the most appealing offers. Outside of Texas, electricity retailers compete with the incumbent utilities, in addition to other retail electric providers, which can inhibit competition depending on the market rules of the state. There is a high degree of fragmentation, with both large and small competitors offering a range of value propositions, including value, rewards, and sustainability-based offerings. Wholesale generation is highly fragmented and diverse in terms of industry structure by region. As such, there is wide variation in terms of the capabilities, resources, nature and identities of the Company’s competitors depending on the market. Competitors include regulated utilities, municipalities, cooperatives, other independent power producers, and power marketers or trading companies, including those owned by financial institutions. Seasonality and Price Volatility The sale of power and natural gas to retail customers are seasonal businesses with the demand for power generally peaking during the summer, and the demand for natural gas generally peaking during the winter. As a result, net working capital requirements for the Company's retail operations generally increase during summer and winter months along with the higher revenues, and then decline during off-peak months. Weather may impact operating results and extreme weather conditions could have a material impact. The rates charged to retail customers may be impacted by fluctuations in total power 14 prices and market dynamics, such as the price of natural gas, transmission constraints, competitor actions, and changes in market heat rates. Annual and quarterly operating results of the Company's generation portfolio can be significantly affected by weather and energy commodity price volatility. Significant other events, such as the demand for natural gas, interruptions in fuel supply infrastructure and relative levels of hydroelectric capacity can increase seasonal fuel and power price volatility. The preceding factors related to seasonality and price volatility are fairly uniform across the regions in which the Company operates. Market Framework NRG sells electricity, natural gas and related products and services to customers throughout the U.S. and Canada. In most of the states and regions that have introduced retail consumer choice, NRG competitively offers electricity, natural gas, portable power and other value-enhancing services to customers. Each retail consumer choice state or province establishes its own retail competition laws and regulations, and the specific operational, licensing, and compliance requirements vary by state or province. Regulated terms and conditions of default service, as well as any movement to replace default service with competitive services, as is done in ERCOT, can affect customer participation in retail competition. In Canada, NRG sells energy and related services to residential and commercial customers in the province of Alberta pursuant both to a regulated rate service governed by provincial regulations as well as a competitive service with rates set by market forces. Sales of energy to commercial customers take place in other provinces as well. The attractiveness of NRG's retail offerings may be impacted by the rules, regulations, market structure and communication requirements from public utility commissions in each state and province. NRG's fleet of power plants which it owns, operates or manages are located in organized energy markets, known as RTOs or ISOs. Each organized market administers day-ahead and real-time centralized bid-based energy and ancillary services markets pursuant to tariffs approved by FERC, or in the case of ERCOT, market rules approved by the PUCT. These tariffs and rules dictate how the energy markets operate, how market participants make bilateral sales with one another, and how entities with market-based rates are compensated. Established prices reflect the value of energy at the specific location and time it is delivered, which is known as the Locational Marginal Price. Each market is subject to market mitigation measures designed to limit the exercise of locational market power. These market structures facilitate NRG's sale of power and capacity products at market-based rates. Other than ERCOT, each of the ISO regions also operates a capacity or resource adequacy market that provides an opportunity for generating and demand response resources to earn revenues to offset their fixed costs that are not recovered in the energy and ancillary services markets. The ISOs are also responsible for transmission planning and operations. Texas NRG's business in Texas is subject to standards and regulations adopted by the PUCT and ERCOT (a) , including the requirement for retailers to be certified by the PUCT in order to contract with end-users to sell electricity. The ERCOT market is one of the nation's largest and, historically, fastest growing power markets. ERCOT is an energy-only market and has implemented market rule changes referred to as the ORDC to provide pricing more reflective of higher energy value when operating reserves are scarce or constrained. The PUCT directed the implementation of the ORDC in 2014 to act as the primary scarcity pricing mechanism, with subsequent amendments made in 2019, 2020 and 2021. The majority of the retail load in the ERCOT market region is served by competitive retail suppliers, except certain areas that have not opted into competitive consumer choice and are served by municipal utilities and electric cooperatives. East While most of the states in the East region of the U.S. have introduced some level of retail consumer choice for electricity and/or natural gas, the incumbent utilities currently provide default service in most of the states and as a result typically serve the majority of residential customers. NRG’s retail activities in the East are subject to standards and regulations adopted by the ISOs, state public utility commissions and legislators, including the requirement for retailers to be certified in each state in order to contract with end-users to sell electricity. (a) The Cottonwood facility is located in Deweyville, Texas, but operates in the MISO market 15 Power plants owned, operated and managed by NRG and NRG's demand response assets located in the East region of the U.S. are within the control areas of PJM, NYISO and MISO. Each of the market regions in the East region provides for robust competition in the day-ahead and real-time energy and ancillary services markets. Additionally, the assets in the East region receive a significant portion of their revenues from capacity markets. PJM uses a forward capacity auction, while NYISO uses a month-ahead capacity auction. MISO has an annual auction. Capacity market prices are sensitive to design parameters, as well as additions of new capacity. PJM operates a pay-for-performance model where capacity payments are modified based on real-time generator performance. In such markets, NRG’s actual capacity revenues will be the combination of cleared auction prices times the quantity of MW cleared, plus the net of any over-performance "bonus payments" and any under-performance charges. Additionally, bidding rules allow for the incorporation of a risk premium into generator bids. West In the West region of the U.S., NRG owns equity interests in natural gas-fired power plants located entirely within the CAISO footprint. The CAISO operates day-ahead and real-time locational markets for energy and ancillary services, while managing congestion primarily through nodal prices. The CAISO system facilitates NRG's sale of power, ancillary services and capacity products at market-based rates, either within the CAISO's centralized energy and ancillary service markets or bilaterally pursuant to tolling arrangements or other capacity sales with California's LSEs. The CPUC also determines capacity requirements for LSEs and for specified local areas utilizing inputs from the CAISO. Both the CAISO and CPUC rules require LSEs to contract with sufficient generation resources in order to maintain minimum levels of generation within defined local areas. Additionally, the CAISO has independent authority to contract with needed resources under certain circumstances, typically either when LSEs have failed to procure sufficient resources, or system conditions change unexpectedly. Canada In Canada, NRG sells to residential and commercial retail customers in Alberta under both regulated rates approved by the AUC as well as through competitive service. The Company's regulated rates are approved through periodic rate applications that establish rates for power and gas sales as well as for recovery of other costs associated with operating the regulated business. In addition, the Company sells energy to commercial customers in other provinces. All sales and operations are subject to applicable federal and provincial laws. Regulatory Matters As participants in wholesale and retail energy markets and owners and operators of power plants, certain NRG entities are subject to regulation by various federal and state government agencies. These include the CFTC, FERC, NRC and the PUCT, as well as other public utility commissions in certain states where NRG's generation or distributed generation assets are located. In addition, NRG is subject to the market rules, procedures and protocols of the various ISO and RTO markets in which it participates. Likewise, certain NRG entities participating in the retail markets are subject to rules and regulations established by the states and provinces in which NRG entities are licensed to sell at retail. NRG must also comply with the mandatory reliability requirements imposed by NERC and the regional reliability entities in the regions where NRG operates. NRG's operations within the ERCOT footprint are not subject to rate regulation by FERC, as they are deemed to operate solely within the ERCOT market and not in interstate commerce. These operations are subject to regulation by the PUCT, as well as to regulation by the NRC with respect to NRG's ownership interest in STP. Federal Energy Regulation In March 2021, President Biden announced a framework for his "Build Back Better" initiative which includes policies to address climate change across the whole of the federal government through the tax code, an energy efficiency and clean energy incentives, research and development, among other areas of focus. The "Build Back Better" initiative has taken the form of two separate bills in Congress. The $1.2 trillion "core infrastructure" bill, which contains spending on new electric vehicle charging programs, among other things, was signed into law by President Biden on November 15, 2021. The remaining priorities, commonly referred to as "Build Back Better," are being monitored by NRG as they progress through the legislative process. State and Provincial Energy Regulation Illinois Legislation — Illinois enacted the Climate and Equitable Jobs Act ("CEJA") on September 15, 2021, which targets 100% clean energy by 2050. CEJA focuses on (i) decarbonization, (ii) incentives to transition coal plants into clean energy facilities and (iii) nuclear subsidies. CEJA requires non-publicly owned coal or oil electric generating units larger than 25 MWs to eliminate CO2e and copollutant emissions by January 1, 2030. Non-publicly owned electric generating units that are gas-fired, including Joliet, must eliminate CO2e and copollutant emissions, including through unit retirement or the use of 100% green hydrogen, in a timeframe ranging from January 1, 2030 to January 1, 2045 depending on certain emission rates and proximity to environmental justice communities. Furthermore, CEJA placed restrictions, with immediate effect, on gas-fired units that limits future emissions to their historic baselines. These limits affect the total potential energy production by gas units in Illinois. PJM, the PJM Independent Market Monitor and the Illinois Environmental Protection Agency have exchanged 16 correspondence to obtain clarification on the implications of these restrictions. The new energy law also provides $174 million in incentives to develop solar and battery storage at coal generating sites that may be available to NRG. Regional Regulatory Developments NRG is affected by rule/tariff changes that occur in the ISO regions. For further discussion on regulatory developments see Item 15 — Note 24, Regulatory Matters, to the Consolidated Financial Statements. Texas Public Utility Commission of Texas’ Actions with Respect to Wholesale Pricing and Market Design — In September 2021, the PUCT opened a rulemaking project to evaluate whether it should amend its rules to modify the High System Wide Offer cap ("HCAP") and the ORDC, which is intended to ensure prices in the competitive market appropriately reflect the value of operating reserves as the system approaches scarcity conditions. This rulemaking project concluded in December 2021, resulting in a rule amendment that lowered the HCAP to $5,000 per MWh and which expands the minimum contingency level to 3,000 MW. These two changes are broadly offsetting in their effect on overall average energy prices. Activity on Securitization and ERCOT Pricing during Winter Storm Uri — The Texas Legislature acted to pass a variety of securitization vehicles to finance exceptionally high power and gas costs from Winter Storm Uri, including HB 4492. ERCOT subsequently filed two applications requesting the PUCT to issue Debt Obligation Orders ("DOOs") based on the legislation. On October 13, 2021, the PUCT issued DOOs authorizing ERCOT's securitization of $800 million to cover short payments and reimburse congestion revenue right account holders for amounts related to the default of market participants other than electric cooperatives Brazos and Rayburn, which are discussed below (the "Default Securitization") and $2.1 billion related to highly priced ancillary service and ORPDA during Winter Storm Uri (the "Uplift Securitization"). The DOOs require ERCOT to issue loans or securitized bonds through a bankruptcy remote special purpose entity as the borrower and distribute the proceeds to affected market participants for default-related short payments and to LSEs for certain ancillary-service and ORDPA costs using an allocation of proceeds based on an LSE's exposure to relevant costs as calculated by the LSE's prevailing load-ratio share during the period of Winter Storm Uri, and a further redistribution of proceeds initially allocated to other LSEs and customers who opt-out of securitization. In turn, ERCOT will charge non-bypassable fees related to the Default Securitization and Uplift Securitization to all qualified scheduling entities and to all LSEs (other than those that have opted-out), respectively. The Uplift Securitization provided for a one-time opt-out for certain LSEs or individual transmission-level customers who in exchange for foregoing any securitization-related proceeds likewise avoid future fees assessed by ERCOT for the use of repaying ERCOT's debt obligations. However, nearly all competitive REPs were required by the law to participate, ensuring the charge established by the law is competitively neutral. These opt-outs and calculations of the allocation of proceeds have been finalized. Based on LSE-level detail published by the PUCT on December 7, 2021, NRG will receive $689 million of Uplift Securitization proceeds, with receipt expected to occur during the second quarter of 2022. The $800 million Default Securitization was disbursed by ERCOT in November 2021, with NRG receiving $12 million. Electric Cooperative Bankruptcy and Securitization — Of the defaults in the ERCOT market, two electric cooperatives, Brazos and Rayburn, constitute the vast majority. Brazos currently is in bankruptcy. NRG and ERCOT have both filed a proof of claim in the bankruptcy proceeding of Brazos, and Brazos has challenged ERCOT's claims in a manner that may prejudice NRG's claims against Brazos. During the fourth quarter of 2021, ERCOT filed a motion to dismiss Brazos' complaint relating to ERCOT's proof of claim, which NRG joined in support, but this motion was denied by the Bankruptcy Court, and ERCOT, NRG and certain other parties appealed. On January 11, 2022, the United States District Court for the Southern District of Texas entered an order allowing the appellants to seek direct review from the Fifth Circuit Court of Appeals of the Bankruptcy Court's decision on the motion to dismiss. On January 18, 2022, ERCOT, NRG and certain other parties filed a petition for direct review by the United States Court of Appeals for the Fifth Circuit. The Court of Appeals granted the petition on February 4, 2022. On February 7, 2022, the Bankruptcy Court entered an order granting summary judgement in favor of Brazos on whether ERCOT's sales to Brazos were in the ordinary course of Brazos' business. The Bankruptcy Court ruled that the portion of ERCOT's claims for charges incurred by Brazos after the intervention of the PUCT and ERCOT were not in the ordinary course and thus are not entitled to administrative expense status under the Bankruptcy Code. The amount and priority of ERCOT's claim for amounts incurred prior to such intervention or after such intervention ceased are issues to be determined at trial. The Bankruptcy Court's summary judgement ruling may also apply to NRG's claims again Brazos. Trial on the merits of the ERCOT proof of claim and Brazos' complaint is set to commence before the Bankruptcy Court on February 22, 2022. To the extent the Bankruptcy Court reduces or disallows claims against Brazos, this presents risk for NRG. ERCOT's market protocols provide for short payments to be extinguished through a process of uplift, whereby the cost of defaults is allocated to all market participants, including retailers, generators, municipal and cooperative utilities, and financial traders. However, the total amount of this uplift is limited by ERCOT's current protocols of $2.5 million per month. Consequently, it would take approximately 63 years for the net short-pay balance of $1.887 billion related to Brazos to be uplifted to the market under the current market rules. NRG's undiscounted share of the uplift based on its current market share 17 is estimated to be approximately $121 million and has been short-paid $68 million. The remaining $53 million has been discounted based on the 63 year repayment term and present value of $9 million was recorded as an additional liability. Rayburn announced that it intended to securitize the amounts owed to ERCOT and payment from such securitization is expected in the first quarter of 2022. Reliability and Plant Operations Standards — The PUCT established a rulemaking to establish weatherization standards, and issued a notice for comments in response to provisions of Texas Senate Bill 3 ("SB3") that require mandatory standards for power generators and others within the electric-power sector. SB3 provides that the standards adopted by the PUCT be implemented by generation owners, be subject to ERCOT inspections, and that ERCOT provide asset owners with a reasonable period of time to remedy any violation. Continuing violations would be subject to an administrative penalty and a requirement that a third-party contractor assess the asset owner's weatherization plans. On August 24, 2021, Commission Staff issued a proposal of weatherization standards for publication. NRG, through its trade association, filed comments. On October 21, 2021, Commissioners of the PUCT voted to adopt the rule without substantial modifications from the proposal. PJM PJM’s Variable Resource Requirement Curve — On July 9, 2021, the Court of Appeals for the D.C. Circuit issued a decision denying in part and granting in part an appeal by several PJM state consumer advocates regarding FERC’s order approving revisions to PJM’s Variable Resource Requirement Curve (“VRR”). The court upheld PJM's use of a greenfield gas-fired combustion turbine as the reference unit to establish Net Cost of New Entry ("Net CONE"). However, the court remanded back to FERC the issue of allowing generators to have a 10% adder to their offer to supply capacity in the PJM market, and on January 20, 2022, FERC issued an order removing the 10% adder. The VRR is the demand curve that represents the slope of bids in the auction that ultimately results in the price and quantity of capacity allocated to load-serving entities, including NRG. The VRR curve is based on several inputs, including the Net CONE. The outcome could affect PJM’s capacity market prices. PJM Revisions to Minimum Offer Price Rule — On July 30, 2021, PJM filed proposed tariff changes at FERC to largely eliminate the current minimum offer price rules ("MOPR") except in very narrow cases. The proposal would eliminate: (i) the current MOPR for new entrant natural gas resources effective with the 2023/2024 delivery year and (ii) the expanded MOPR established in FERC's December 2019 Order to address out-of-market subsidies. On September 30, 2021, PJM's proposal went into effect by operation of law because the FERC Commissioners were split 2-2 as to the lawfulness of the change. Multiple parties filed motions for rehearing and ultimately appealed to the federal court of appeals. On December 21, 2021 and December 30, 2021, respectively, the Third Circuit Court of Appeals and the Seventh Circuit Court of Appeals issued an order holding the appeals in abeyance. The proposed revisions would allow PJM to address specific and narrow instances of buyer-side market power through subsequent filings at FERC. Any changes to the PJM capacity market construct may impact the outcome of future Base Residual Auctions. PJM's ORDC Filing and Compliance Directives — On May 21, 2020, PJM proposed energy and reserve market reforms to enhance price formation in reserve markets, which included modifying ORDC and aligning market-based reserve products in Day-Ahead and Real-Time markets. In addition to approving PJM's proposal, FERC also directed PJM to implement a forward-looking Energy and Ancillary Services Offset to be used in PJM's capacity markets. After multiple compliance filings, parties filed appeals at the Court of Appeals for the D.C. Circuit of FERC’s orders, and on August 13, 2021, FERC filed a motion and was granted a voluntary remand the case back to the agency. On December 22, 2021, FERC issued its order on voluntary remand affirming in part and reversing in part FERC's determination. Specifically, FERC reversed itself and ordered PJM to: (i) eliminate the more robust ORDC curves and reserve penalty adders and maintain the existing (lower) curves and (lower) penalty adders and (ii) restore its tariff provisions related to its prior backward-looking Energy and Ancillary Services Offset. At the direction of FERC, on January 21, 2022, PJM filed a compliance fling proposing a new schedule for the Base Residual Auctions. Independent Market Monitor Market Seller Offer Cap Complaint — On March 18, 2021, finding that the calculation of the default Market Seller Offer Cap was unjust and unreasonable, the Order permitted the current PJM May 2021 capacity auction for the 2022/2023 delivery rule to continue under the existing rules and set a procedural schedule for parties to file briefs with possible solutions. On September 2, 2021, FERC issued an order in response to a complaint filed by the PJM Independent Market Monitor's proposal, which eliminates the Cost of New Entry-based Market Seller Offer Cap and implements a limited default cap for certain asset classes based on going-forward costs and provides for unit specific cost review by the Independent Market Monitor for all other non-zero offers into the auctions. As required by the Order, PJM submitted its compliance tariff on October 4, 2021. On October 4, certain parties filed a motion for rehearing. which was denied. Multiple parties filed appeals at the Court of Appeals for the D.C. Circuit. The appeals are currently being held in abeyance. The removal of the Offer Caps may impact the outcome of future Base Residual Auctions. 18 New York NYISO's Revisions to the Buyer Side Mitigation Rules — On January 5, 2022, the NYISO filed its Comprehensive Mitigation Review proposing changes to the buyer-side mitigation rules. The proposal would remove certain facilities to be reviewed under the buyer-side mitigation rules to serve the goals of New York's Climate Leadership and Community Protection Act, adopt a marginal capacity accreditation market design and adjust the rules surrounding installed and unforced capacity. Changes to NYISO's Buyer Side Mitigation rules may impact the outcome of future capacity auctions. California California Resource Adequacy Proceedings — On March 25, 2021, the CPUC directed the state's major investor-owned utilities to engage in up to 1.5 GW of emergency procurement for 2021 and 2022 and is currently evaluating further procurement directives through 2023. In the same docket, the CPUC approved a new demand response program for use during emergency conditions. As part of the Integrated Resource Procurement docket, the CPUC approved a decision on June 24, 2021 that will require all Load Serving Entities to procure a pro rata share of 11.5 GW of new non-fossil resource adequacy from 2023 to 2026. To replace the retiring Diablo Canyon nuclear plant, this will consist largely of GHG-free energy, long-duration storage, baseload renewables and energy storage. A new resource adequacy docket opened in October 2021 will consider changes to the reserve margin and qualifying capacity of different resource types, and the CPUC and CAISO will continue to evaluate major structural reforms to the resource adequacy program in California that would begin in 2024. Midway-Sunset Reliability Must Run Proceeding — San Joaquin Energy, LLC, a subsidiary of NRG, owns a 50%, non-controlling interest in the Midway-Sunset Cogeneration Company ("MSCC"). MSCC owns a cogeneration facility near Fellows, California and submitted mothball notices for the cogeneration facility to the CAISO in the latter half of 2020. On December 17, 2020, the CAISO Board effectively rejected the mothball notices by authorizing its staff to designate the MSCC facility as a reliability must-run ("RMR") resource conditioned on execution of a RMR contract. On January 29, 2021, MSCC made its RMR filing at FERC. Multiple parties filed protests and on March 16, 2021, MSCC filed a response to those protests. On April 2, 2021, FERC accepted the RMR filing, suspended it to become effective February 1, 2021 subject to refund and established hearing and settlement judge proceedings. The parties are engaging in settlement proceedings. On September 27, 2021, the CAISO gave notice to MSCC extending the term of the reliability designation through December 31, 2022. Canada Alberta Energy Market — In December 2020, prior to its acquisition by NRG, Direct Energy filed a Non-Energy Rate Application with the AUC to approve cost recovery for the 2020-2022 period. Major cost elements of this application relate to bad debt, corporate costs, and customer care and billing contracts. The Company engaged in a mediation and settlement process, and on April 20, 2021 an all-party settlement was executed, and was filed with the AUC on April 23, 2021. The AUC approved the settlement agreement on June 4, 2021. Separately, the Company received approval from the AUC of a negotiated rate settlement for its electricity focused 2020-2022 Energy Price Setting Plan which went into effect on July 1, 2021. The Company has completed the last repayment to the Balancing Pool and the Alberta government as part of its 90-day utility bill deferral program. This program, effective March 18, 2020, was designed to assist residential, farms, and small business customers who were negatively affected by COVID-19 related economic circumstances by temporarily deferring their utility bill payments. The program was also designed to mitigate bad debt risks associated with the implementation of the program. Environmental Regulatory Matters NRG is subject to numerous environmental laws in the development, construction, ownership and operation of power plants. These laws generally require that governmental permits and approvals be obtained before construction and maintained during operation of power plants. Federal and state environmental laws historically have become more stringent over time. Future laws may require the addition of emissions controls or other environmental controls or impose restrictions on the Company's operations. Complying with environmental laws often involves specialized human resources and significant capital and operating expenses, as well as occasionally curtailing operations. NRG decides to invest capital for environmental controls based on the relative certainty of the requirements, an evaluation of compliance options, and the expected economic returns on capital. A number of regulations that affect the Company have been revised recently by the EPA, including ash storage and disposal requirements, NAAQS revisions and implementation and effluent limitation guidelines. Some of these recent revisions may, in turn, be revised by the current U.S. presidential administration. NRG will evaluate the impact of these regulations as they are revised but cannot fully predict the impact of each until anticipated revisions and legal challenges are resolved. Air The CAA and related regulations (as well as similar state and local requirements) have the potential to affect air emissions, operating practices and pollution control equipment required at power plants. Under the CAA, the EPA sets NAAQS for certain pollutants including SO 2 , ozone, and PM2.5. Many of the Company's facilities are located in or near areas that are 19 classified by the EPA as not achieving certain NAAQS (non-attainment areas). The relevant NAAQS may become more stringent. The Company maintains a comprehensive compliance strategy to address continuing and new requirements. Complying with increasingly stringent air regulations could require the installation of additional emissions control equipment at some NRG facilities or retiring of units if installing such controls is not economic. Significant changes to air regulatory programs affecting the Company are described below. CPP/ACE Rules — The attention in recent years on GHG emissions has resulted in federal and state regulations. In October 2015, the EPA promulgated the CPP, addressing GHG emissions from existing EGUs. On February 9, 2016, the U.S. Supreme Court stayed the CPP. In July 2019, EPA promulgated the ACE rule, which rescinded the CPP, which had sought to broadly regulate CO 2 emissions from the power sector. On January 19, 2021, the D.C. Circuit vacated the ACE rule (but on February 22, 2021, at the EPA's request, stayed the issuance of the portion of the mandate that would vacate the repeal of the CPP). On 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. Greenhouse Gas Emissions — NRG emits CO 2 (and small quantities of other GHGs) when generating electricity at a majority of its facilities. Nearly all (>99%) of NRG's domestic GHG emissions are subject to federal (U.S. EPA) GHG reporting requirements. NRG's climate goals are to reduce greenhouse gas emissions by 50% by 2025, from its current 2014 baseline, and to achieve net-zero emissions by 2050. Greenhouse gas emissions include directly controlled emissions, emissions from NRG's purchased energy, and emissions from employee business travel. In 2021, NRG's climate goals were certified by the Science Based Targets initiative as aligned with a 1.5 degree Celsius trajectory. From the current 2014 baseline to 2021, the Company's CO 2 e emissions decreased from 61 million metric tons to 34 million metric tons, representing a cumulative 44% reduction. The decrease is attributed to reductions in fleet-wide annual net generation and a market-driven shift away from coal as a primary fuel to natural gas. The increase in emissions in 2021, as compared to 2020, was primarily due to higher power demand which was a result of the easing of COVID-19 pandemic lockdowns and the associated economic recovery. The Company is continuing to target a 50% reduction by 2025 and is on track to meet that goal. As of December 31, 2021, less than 5% of the Company's consolidated operating revenues were derived from coal-fired operating assets. The following charts reflect the Company’s domestic generation portfolio, including leased facilities and those accounted for through equity method investments. Prior year information was adjusted to remove divested assets. 20 Byproducts, Wastes, Hazardous Materials and Contamination In April 2015, the EPA finalized the rule regulating byproducts of coal combustion (e.g., ash and gypsum) as solid wastes under the RCRA. In September 2017, the EPA agreed to reconsider the rule. On July 30, 2018, the EPA promulgated a rule that amended the existing ash rule by extending some of the deadlines and providing more flexibility for compliance. On August 21, 2018, the D.C. Circuit found, among other things, that the EPA had not adequately regulated unlined ponds and legacy ponds. In 2019 and 2020, the EPA proposed several changes to this rule. On August 28, 2020, the EPA finalized "A Holistic Approach to Closure Part A: Deadline to Initiate Closure," which amended the April 2015 Rule to address the August 2018 D.C. Circuit decision and extend some of the deadlines. On November 12, 2020, the EPA finalized "A Holistic Approach to Closure Part B: Alternative Demonstration for Unlined Surface Impoundments," which further amended the April 2015 Rule to, among other things, provide procedures for requesting approval to operate existing ash impoundments with an alternate liner. Domestic Site Remediation Matters Under certain federal, state and local environmental laws, a current or previous owner or operator of a facility, including an electric generating facility, may be required to investigate and remediate releases or threatened releases of hazardous or toxic substances or petroleum products. NRG may be responsible for property damage, personal injury and investigation and remediation costs incurred by a party in connection with hazardous material releases or threatened releases. These laws impose liability without regard to whether the owner knew of or caused the presence of the hazardous substances, and the courts have interpreted liability under such laws to be strict (without fault) and joint and several. Cleanup obligations can often be triggered during the closure or decommissioning of a facility, in addition to spills during its operations. Further discussions of affected NRG sites can be found in Item 15 — Note 23, Commitments and Contingencies , to the Consolidated Financial Statements. Jewett Mine Lignite Contract — The Company's Limestone facility historically burned lignite obtained from the Jewett mine, which was operated by TWCC. In 2019, the Jewett mine and related lignite supply agreement with NRG were acquired by Westmoreland Jewett Mining LLC ("Jewett Mining"), a subsidiary of Westmoreland Mining LLC pursuant to a plan of reorganization confirmed by the Texas Bankruptcy Court. Effective August 5, 2020, NRG's subsidiary, NRG Texas LLC, acquired all of the equity interests of Jewett Mining. Active mining under the lignite supply agreement ceased as of December 31, 2016; however, under the terms of the lignite supply agreement, Jewett Mining remains responsible for reclamation activities and NRG is responsible for all reclamation costs. NRG has recorded an adequate ARO liability. The Railroad Commission of Texas has imposed a bond obligation of approximately $99 million for the reclamation of the Jewett mine, which NRG supports through surety bonds. The cost of the reclamation may exceed the value of the bonds. NRG may provide additional performance assurance if required by the Railroad Commission of Texas. Nuclear Waste — The federal government's program to construct a nuclear waste repository at Yucca Mountain, Nevada was discontinued in 2010. Since 1998, the U.S. DOE has been in default of the federal government's obligations to begin accepting spent nuclear fuel, or SNF, and high-level radioactive waste, or HLW, under the Nuclear Waste Policy Act. Owners of nuclear plants, including the owners of STP, had been required to enter into contracts setting out the obligations of the owners and the U.S. DOE, including the fees to be paid by the owners for the U.S. DOE's services to license a spent fuel repository. Effective May 16, 2014, the U.S. DOE stopped collecting the fees. On February 5, 2013, STPNOC entered into a settlement agreement with the U.S. DOE for payment of damages relating to the U.S. DOE's failure to accept SNF and HLW under the Nuclear Waste Policy Act through December 31, 2013, which has been extended three times through addendums to cover payments through December 31, 2022. There are no facilities for the reprocessing or permanent disposal of SNF currently in operation in the U.S., nor has the NRC licensed any such facilities. STPNOC currently stores all SNF generated by its nuclear generating facilities on-site. STPNOC plans to continue to assert claims against the U.S. DOE for damages relating to the U.S. DOE's failure to accept SNF and HLW. Under the federal Low-Level Radioactive Waste Policy Act of 1980, as amended in 1985, the state of Texas is required to provide, either on its own or jointly with other states in a compact, for the disposal of all low-level radioactive waste generated within the state. Texas is currently in a compact with the state of Vermont, and the compact low-level waste facility located in Andrews County in Texas has been operational since 2012. Water The Company is required under the CWA to comply with intake and discharge requirements, requirements for technological controls and operating practices. As with air quality regulations, federal and state water regulations have become more stringent and imposed new requirements. 21 Effluent Limitations Guidelines — In November 2015, the EPA revised the Effluent Limitations Guidelines ("ELG") for Steam Electric Generating Facilities, which imposed more stringent requirements (as individual permits were renewed) for wastewater streams from FGD, fly ash, bottom ash, and flue gas mercury control. On September 18, 2017, the EPA promulgated a final rule that, among other things, postponed the compliance dates to preserve the status quo for FGD wastewater and bottom ash transport water by two years to November 2020 until the EPA amended the rule. On October 13, 2020, the EPA amended the 2015 ELG rule by: (i) altering the stringency of certain limits for FGD wastewater; (ii) relaxing the zero-discharge requirement for bottom ash transport water; and (iii) changing several deadlines. 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. Regional Environmental Developments Ash Regulation in Illinois — On July 30, 2019, Illinois enacted legislation that requires the state to promulgate regulations regarding coal ash at surface impoundments. On April 15, 2021, the state promulgated the implementing regulation, which became effective on April 21, 2021. The new regulation requires NRG to apply for initial operating permits for its coal ash surface impoundments by October 31, 2021 and construction permits (for closure) starting in 2022. Customers NRG sells to a wide variety of customers, primarily end-use customers in the residential, commercial and industrial sectors. The Company owns and operates power plants to generate and sell power to wholesale customers, such as utilities and other intermediaries. The Company had no customer that comprised more than 10% of the Company's consolidated revenues for the year ended December 31, 2021. Human Capital As of December 31, 2021, NRG and its consolidated subsidiaries had 6,635 employees, approximately 13% of whom were covered by U.S. collective bargaining agreements. During 2021, the Company did not experience any labor stoppages or labor disputes at any of its facilities. NRG believes its employees are vital to its success and is committed to offering employees a rewarding career that provides opportunities for growth and the ability to make valuable contributions toward the achievement of the Company’s business objectives. NRG focuses on safety, health and wellness, diversity, equity and inclusion, talent development and total rewards for its employees. Safety Safety is embedded in the culture at NRG. The Company strives to begin each meeting with a safety moment and regularly reminds its employees that safety comes first. NRG has achieved its targeted top decile safety record of Occupational Safety and Health Administration recordable injury rates in each of the 5 previous years. 22 Health and Wellness For several years, NRG has invested in the well-being of its employees and their families. NRG provides programs that holistically support its employees’ physical, emotional and financial wellness, allowing employees the opportunity to take control of their well-being and focus on what matters most to them for a healthy, secure future. During 2020, the Company evaluated its approach to health and well-being in light of the circumstances resulting from the COVID-19 pandemic. In response to COVID-19, NRG implemented additional programs to provide services to support the needs of employees, including those working from home, such as programs that provided back-up childcare, expanded access to telemedicine (for both physical and mental health), and supported mental and emotional well-being through programs such as mindfulness. During 2021, the Company continued its support of employees by partnering with the National Council for Behavioral Health to roll out their Mental Health First Aid program. This program safely, respectfully and effectively opens the conversation about mental illness and addiction, encourages employees to recognize and take responsibility for their mental health, teaches managers to recognize and speak to an employee with a mental health concern before it creates performance problems, complements and supports existing benefit and wellness programs and company’s policies and procedures. Diversity, Equity and Inclusion NRG is committed to diversity, equity and inclusion ("DE&I") as an integral part of the Company. In 2020, NRG completed a gender and race pay equity study to ensure that the Company's pay decisions were not influenced by gender, race, or other similar factors. The study showed equitable pay practices after accounting for education, experience, performance and location. NRG also conducted company-wide unconscious bias training to help all employees recognize, understand, and reduce implicit bias and offers various other related guides and tools to its employees and management. In 2021, the Company focused on embedding DE&I in the Company’s operations, culture and communications, by working with diverse suppliers, finding diverse talent, facilitating engagement and awareness of DE&I by employees, and committing to be accountable for our DE&I progress. Talent Development NRG deploys various talent development strategies and programs with the goal of ensuring a pipeline of leadership who can execute on the Company’s strategy and drive value for all stakeholders. The Board of Directors regularly engages with management on leadership development and succession planning, including providing feedback on development plans and bench strength for key senior leader positions. The Board of Directors also has a structured program that allows directors to interact directly with individuals deeper within the organization whom management, through a robust talent assessment program, as well as mentoring relationships, has identified as high potential future leaders. In 2021, the Company launched an Executive Leadership Program to strengthen the identified pipeline of future leaders and create a cohort of high potential candidates for the program. The Company has a performance management tool that emphasizes a continuous feedback loop and a robust online training curriculum with topics including leadership, communication and productivity. Total Rewards NRG seeks to provide the median target of compensation and benefits, benchmarked against direct peers, industry, and, where appropriate, general peers. To ensure incentives are properly aligned with business needs and can attract and retain qualified employees, the Compensation Committee of the Board of Directors actively reviews the Company's total rewards programs, including benchmarking programs against peer groups, assessing the risks of programs and evaluating the design of the annual and long-term incentive programs. The Company offers full-time employees incentives designed to motivate and reward success. NRG continues to evaluate its offerings taking into consideration the needs of its employees to ensure they are competitive and best serve its employees. Every two years, the Company engages an independent third party to benchmark its compensation and benefits programs against its peers and report the results to the Compensation Committee of the Board of Directors. For further discussion and recent available data regarding the Company’s efforts and programs please see the Company’s 2021 Proxy Statement and 2020 Sustainability Report, which are available on the Company’s website at: www.nrg.com . Information included in these documents is not intended to be incorporated into this Form 10-K. Available Information NRG's annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to section 13(a) or 15(d) of the Exchange Act are available free of charge through the SEC's website, www.sec.gov , and through the Company's website, www.nrg.com , as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC. The Company also routinely posts press releases, presentations, webcasts, sustainability reports and other information regarding the Company on the Company's website. The information posted on the Company's website is not a part of this report. 23 Item 1A — Risk Factors NRG's risk factors are grouped into the following categories: (i) Risks Related to the Acquisition of Direct Energy; (ii) Risks Related to the Operation of NRG's Business; (iii) Risks Related to Governmental Regulation and Laws; (iv) Risks Related to Public Health Threats; and (v) Risks Related to Economic and Financial Market Conditions, and the Company's Indebtedness. Risks Related to the Acquisition of Direct Energy The acquisition of Direct Energy may not achieve its intended results. Achieving the anticipated benefits of cost savings and operating efficiencies of the acquisition is subject to a number of uncertainties, including whether the businesses of NRG and Direct Energy are integrated in an efficient and effective manner. Failure to achieve these anticipated benefits could result in increased costs, lower-than-expected revenues or income generated by the combined company and diversion of management's time and energy, which could have an adverse effect on the Company's business, financial results and prospects. The Company will be subject to business uncertainties related to Direct Energy that could adversely affect its financial results. Uncertainty about the effects of the acquisition of Direct Energy on employees, customers and suppliers may have an adverse effect on NRG's business. Although the Company intends to take steps designed to reduce any adverse effects, these uncertainties may impair its ability to attract, retain and motivate key personnel for a period of time, and could cause customers, suppliers and others that deal with it to seek to change existing business relationships. Employee retention and recruitment may be particularly challenging, as employees and prospective employees may experience uncertainty about their future roles with the Company. If, despite the Company's retention and recruiting efforts, key employees depart or fail to accept employment with NRG because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with NRG, the Company's financial results could be affected. The integration of NRG and Direct Energy may disrupt or have a negative impact on the Company’s business. The acquisition of Direct Energy is complex, and the Company will devote significant time and resources to integrating its operations with the operations of NRG. NRG could have difficulty integrating the acquired assets and personnel of Direct Energy with its own. The integration of NRG and Direct Energy may place a significant burden on management and internal resources. The diversion of management attention away from ongoing business concerns and any difficulties encountered in the transition and integration process could affect the Company's business, results of operations and financial condition. Risks that could impact the Company negatively include: • the difficulty of managing and integrating Direct Energy and its operations ; • the potential disruption of the ongoing businesses and distraction of management; • changes in our business focus and/or management; • difficulties in implementing and maintaining uniform processes, systems, standards, controls, procedures, practices, policies and compensation standards; • unanticipated issues in integrating information technology, communications, and other systems; • the possibility of faulty assumptions underlying expectations regarding the integration process; • the potential impairment of relationships with employees and partners; • unforeseen expenses associated with the acquisition of Direct Energy, including delays to the integration of Direct Energy’s business as a result of the COVID-19 pandemic; • the potential difficulty in managing an increased number of locations and employees; • the potential loss of valuable employees; • difficulty addressing any possible differences in corporate cultures and management philosophies; • unanticipated changes in federal or state laws or regulations; and • the effect of any government regulations that relate to the business acquired. If the Company is not successful in addressing these risks effectively, the business could be impacted. Many of these factors will be outside of the Company’s control, and any one of them could result in delays, increased costs, decreases in the amount of expected revenues and diversion of management’s time and energy, which could materially affect NRG’s business, results of operations and financial condition . 24 Risks Related to the Operation of NRG's Business NRG's financial performance may be impacted by price fluctuations in the retail and wholesale power and natural gas markets, as well as fluctuations in coal and oil markets and other market factors that are beyond the Company's control. Market prices for power, capacity, ancillary services, natural gas, coal and oil are unpredictable and tend to fluctuate substantially. Unlike most other commodities, electric power can only be stored on a very limited basis and generally must be produced concurrently with its use. As a result, power prices are subject to significant volatility due to supply and demand imbalances, especially in the day-ahead and spot markets. Long and short-term power and gas prices may also fluctuate substantially due to other factors outside of the Company's control, including: • changes in generation capacity in the Company’s markets, including the addition of new supplies of power as a result of the development of new plants, expansion of existing plants, the continued operation of uneconomic power plants due to state subsidies, retirement of existing plants or addition of new transmission capacity; • environmental regulations and legislation; • electric supply disruptions, including plant outages and transmission disruptions; • changes in power and gas transmission infrastructure; • fuel price volatility and transportation capacity constraints or inefficiencies; • changes in law, including judicial decisions; • weather conditions, including extreme weather conditions and seasonal fluctuations, including the effects of climate change; • changes in commodity prices and the supply of commodities, including but not limited to natural gas, coal and oil; • changes in the demand for power or gas, or in patterns of power or gas usage, including the potential development of demand-side management tools and practices, distributed generation, and more efficient end-use technologies; • development of new fuels, new technologies and new forms of competition for the production of power; • economic and political conditions; • federal, state and provincial power regulations and legislation, and regulations and actions of the ISO and RTOs; • changes in prices related to RECs; and • changes in capacity prices and capacity markets. While retail rates are generally designed to allow retail sellers of electricity and natural gas to pass through price fluctuations and other changes to costs, the Company may not be able to pass through all such changes to customers. For example, serving retail power customers in ISOs that have a capacity market exposes the Company to the risk that capacity costs can change and may not be recoverable, or the Company may engage in sales of power at fixed prices. Additionally, increases in wholesale costs to retail customers may cause additional customer defaults or increased customer attrition, or may be impacted by regulatory rules. Further, in low natural gas price environments, natural gas can be the more cost-competitive fuel compared to coal for generating electricity. The Company enters into guaranteed supply contracts to provide for the amount of coal needed to operate its base load coal-fired generating facilities, the Company may experience periods where it holds excess amounts of coal if fuel pricing results in the Company reducing or idling coal-fired generating facilities. In addition, the Company may incur costs to terminate supply contracts for coal in excess of its generating requirements. Such factors and the associated fluctuations in power prices have affected the Company's wholesale and retail profitability in the past and are expected to continue to do so in the future. Volatile power and gas supply costs and demand for power and gas could adversely affect the financial performance of NRG's retail operations. NRG's retail power operations purchase a significant portion of their supply from third parties. All of the gas sold by the Company in retail and wholesale markets is purchased from third parties. As a result, financial performance depends on the ability to obtain adequate supplies of power and gas from third parties at prices below the prices NRG charges its customers. Consequently, the Company's earnings and cash flows could be adversely affected in any period in which the wholesale power or gas prices rise at a greater rate than the rates the Company can charge to customers. The price of wholesale electricity and gas supply purchases associated with the retail operations' energy commitments can be different than that reflected in the rates charged to customers due to, among other factors: • varying supply procurement contracts used and the timing of entering into related contracts; • subsequent changes in the overall price of natural gas; 25 • daily, monthly or seasonal fluctuations in the price of natural gas relative to the 12-month forward prices; • transmission and transportation constraints and the Company's ability to move power or gas to its customers; and • changes in market heat rate (i.e., the relationship between power and natural gas prices). The Company's earnings and cash flows could also be adversely affected in any period in which its customers' actual usage of electricity or gas significantly varies from the forecasted usage, which could occur due to, among other factors, weather events, changes in usage patterns, competition and economic conditions. Substantially all of NRG's businesses operates, wholly or partially, without long-term power sale agreements. Many of NRG’s retail customers are contracted for a period of one year or less, and NRG may or may not hedge its retail power sales exposure, or may hedge in a manner that is not effective at managing quantity or price risk in the retail market. In addition, many of NRG’s generation facilities are exposed to market risk because they operate as "merchant" facilities without long-term power sales agreements for some or all of their generating capacity and output. Without the benefit of long-term power sales or purchase agreements, and without long-term load obligations, NRG cannot be sure that it will be able to sell or purchase power at commercially attractive rates or that its generation facilities will be able to operate profitably. This could lead to future impairments of the Company's property, plants and equipment, the closing of certain of its facilities or the loss of retail customers, which could have a material adverse effect on the Company's results of operations, financial condition or cash flows. Competition may have a material adverse effect on NRG's results of operations, cash flows and the market value of its assets. NRG has numerous competitors in all aspects of its business, and additional competitors may enter the industry. The Company's retail operations specifically face competition for customers. Competitors may offer different products, lower prices, and other incentives which may attract customers away from the Company. In some retail electricity markets, the principal competitor may be the incumbent utility. The incumbent utility has the advantage of long-standing relationships with its customers and strong brand recognition. Furthermore, NRG may face competition from other energy service providers, other energy industry participants, or nationally branded providers of consumer products and services, who may develop businesses that will compete with NRG. The Company’s plant operations face competition from newer or more efficient plants owned by competitors, which may put some of the Company's plants at a disadvantage to the extent these competitors are able to consume the same or less fuel as the Company's plant. Over time, the Company's plants may be unable to compete with these more efficient plants, which could result in retirements. NRG’s competitors may have greater liquidity, greater access to credit and other financial resources, lower cost structures, more effective risk management policies and procedures, greater ability to incur losses, longer-standing relationships with customers, greater potential for profitability from retail sales or greater flexibility in the timing of their sale of generation capacity and ancillary services than NRG does. Competitors may also have better access to subsidies or other out-of-market payments that put NRG at a competitive disadvantage. NRG's competitors may be able to respond more quickly to new laws or regulations or emerging technologies, or devote greater resources to marketing of retail energy than NRG can. In addition, current and potential competitors may make strategic acquisitions or establish cooperative relationships among themselves or with third parties. Accordingly, it is possible that new competitors or alliances among current and new competitors may emerge and rapidly gain significant market share. There can be no assurance that NRG will be able to compete successfully against current and future competitors, and any failure to do so would have a material adverse effect on the Company's business, financial condition, results of operations and cash flow. NRG's costs, results of operations, financial condition and cash flows could be adversely impacted by disruption of its fuel supplies. NRG relies on natural gas, coal and oil to fuel a majority of its power generation facilities. Grid operations depend on the continuing financial viability of contractual counterparties, as well as the infrastructure (including rail lines, rail cars, barge facilities, roadways, riverways and natural gas pipelines) available to serve generation facilities and to ensure that there is sufficient power produced to meet retail demand. As a result, the Company’s wholesale generation facilities are subject to the risks of disruptions or curtailments in the production of power at its generation facilities if no fuel is available at any price, if a counterparty fails to perform or if there is a disruption in the fuel delivery infrastructure. NRG routinely hedges both its wholesale sales and purchases to support its retail load obligations. In order to hedge these obligations, the Company may enter into long-term and short-term contracts for the purchase and delivery of fuel. Many of the forward power sales contracts do not allow the Company to pass through changes in fuel costs or discharge the power sale obligations in the case of a disruption in fuel supply due to force majeure events or the default of a fuel supplier or transporter. 26 Disruptions in the Company's fuel supplies or power supply arrangements may therefore require it to find alternative fuel sources at higher costs, to find other sources of power to deliver to retail customers or other counterparties at a higher cost, or to pay damages to counterparties for failure to deliver power or sell electricity or natural gas as contracted. Any such event could have a material adverse effect on the Company's financial performance. NRG also buys significant quantities of energy and fuel on a short-term or spot market basis. Prices sometimes rise or fall significantly over a relatively short period of time. The price NRG can obtain for the sale of energy may not rise at the same rate, or may not rise at all, to match a rise in fuel or delivery costs. Retail rates may also not rise at the same rate or may not rise at all. This may have a material adverse effect on the Company's financial performance. NRG's plant operating characteristics and equipment, particularly at its coal-fired plants, often dictate the specific fuel quality to be combusted. The availability and price of specific fuel qualities may vary due to supplier financial or operational disruptions, transportation disruptions and force majeure. At times, coal of specific quality may not be available at any price or the Company may not be able to transport such coal to its facilities on a timely basis. In this case, the Company may not be able to run the coal facility even if it would be profitable. Operating a coal facility with different quality coal can lead to emission or operating problems. If the Company had sold forward the power from such a coal facility, it could be required to supply or purchase power from alternate sources, perhaps at a loss. This could have a material adverse impact on the financial results of specific plants and on the Company's results of operations. There may be periods when NRG will not be able to meet its commitments under forward sale or purchase obligations at a reasonable cost or at all. The Company may sell fixed price gas as a proxy for power. Because the obligations under most of the Company's forward sale agreements are not contingent on a unit being available to generate power, NRG is generally required to deliver power to the buyer, even in the event of a plant outage, fuel supply disruption or a reduction in the available capacity of the unit. To the extent that the Company does not have sufficient lower-cost capacity to meet its commitments under its forward sale obligations, the Company would be required to supply replacement power either by running its other, higher cost power plants or by obtaining power from third-party sources at market prices that could substantially exceed the contract price. If NRG fails to deliver the contracted power, it would be required to pay the difference between the market price at the delivery point and the contract price, and the amount of such payments could be substantial. NRG's trading operations and use of hedging agreements could result in financial losses that negatively impact its results of operations , and NRG's hedging activities may increase the volatility in the Company's quarterly and annual financial results. The Company typically enters into hedging agreements, including contracts to purchase or sell commodities at future dates and at fixed prices, to manage the commodity price risks inherent in its business. The Company’s risk management policies and hedging procedures may not mitigate risk as planned, and the Company may fail to fully or effectively hedge its commodity supply and price risk. In addition, these activities, although intended to mitigate price volatility, expose the Company to other risks. When the Company sells or buys power or gas forward, it gives up the opportunity to buy or sell at the future price, which not only may result in lost opportunity costs but also may require the Company to post significant amounts of cash collateral or other credit support to its counterparties. The Company also relies on counterparty performance under its hedging agreements and is exposed to the credit quality of its counterparties under those agreements. Further, if the values of the financial contracts change in a manner that the Company does not anticipate, or if a counterparty fails to perform under a contract, it could harm the Company's business, operating results or financial position. NRG does not typically hedge the entire exposure of its operations against commodity price volatility. To the extent it does not hedge against commodity price volatility, the Company's results of operations and financial position may be improved or diminished based upon movement in commodity prices. NRG may engage in trading activities, including the trading of power, fuel and emissions allowances that are not directly related to the operation of the Company's generation facilities or the management of related risks. These trading activities take place in volatile markets and some of these trades could be characterized as speculative. The Company would expect to settle these trades financially rather than through the production of power or the delivery of fuel. This trading activity may expose the Company to the risk of significant financial losses which could have a material adverse effect on its business and financial condition. NRG generally attempts to balance its fixed-price physical and financial purchases and sales commitments in terms of contract volumes and the timing of performance and delivery obligations through the use of financial and physical derivative contracts. These derivatives are accounted for in accordance with the FASB ASC 815, Derivatives and Hedging, or ASC 815, which requires the Company to record all derivatives on the balance sheet at fair value with changes in the fair value resulting from fluctuations in the underlying commodity prices immediately recognized in earnings, unless the derivative qualifies for 27 cash flow hedge accounting treatment or a scope exception. As a result, the Company's quarterly and annual results are subject to significant fluctuations caused by changes in market prices. NRG may not have sufficient liquidity to hedge market risks effectively. The Company is exposed to market risks through its retail and wholesale operations, which involve the purchase of electricity and natural gas for resale, the sale of energy, capacity and related products, and the purchase and sale of fuel, transmission services and emission allowances. These market risks include, among other risks, volatility arising from location and timing differences that may be associated with buying and transporting fuel, converting fuel into energy and delivering energy to a buyer. NRG undertakes these market activities through agreements with various counterparties. Many of the Company's agreements with counterparties include provisions that require the Company to provide guarantees, offset or netting arrangements, letters of credit, a first lien on assets and/or cash collateral to protect the counterparties against the risk of the Company's default or insolvency. The amount of such credit support that must be provided typically is based on the difference between the price of the commodity in a given contract and the market price of the commodity. Significant movements in market prices can result in the Company being required to provide cash collateral and letters of credit in very large amounts. The effectiveness of the Company's strategy may depend on the amount of collateral available to enter into or maintain these contracts, and liquidity requirements may be greater than the Company anticipates or will be able to meet. Without a sufficient amount of working capital to post as collateral in support of performance guarantees or as a cash margin, the Company may not be able to manage price volatility effectively or to implement its strategy. An increase in the amount of letters of credit or cash collateral required to be provided to the Company's counterparties may negatively affect the Company's liquidity and financial condition. Further, if retail customers use more power or gas than expected, or if any of NRG's facilities experience unplanned outages, the Company may be required to procure additional power or gas at spot market prices to fulfill contractual commitments. Without adequate liquidity to meet margin and collateral requirements, the Company may be exposed to significant losses, may miss significant opportunities, and may have increased exposure to the volatility of spot markets. NRG relies on storage, transportation assets and suppliers, which it does not own or control, to deliver natural gas. The Company depends on natural gas pipelines and other transportation and storage facilities owned and operated by third parties to deliver natural gas to wholesale and retail markets and to provide retail energy services to customers. The Company's ability to provide natural gas for its present and projected customers will depend upon its suppliers' ability to obtain and deliver supplies of natural gas, as well as NRG's ability to acquire supplies directly from new sources. Factors beyond the control of the Company and its suppliers may affect the Company's ability to deliver such supplies. These factors include other parties' control over the drilling of new wells and the facilities to transport natural gas to the Company's receipt points, development of additional interstate pipeline infrastructure, availability of supply sources competition for the acquisition of natural gas, priority allocations, impact of severe weather disruptions to natural gas supplies and the regulatory and pricing policies of federal and state regulatory agencies, as well as the availability of Canadian reserves for export to the U.S. Energy deregulation legislation may increase competition among natural gas utilities and impact the quantities of natural gas requirements needed for sales service. If supply, transportation or storage is disrupted, including for reasons of force majeure, the ability of the Company to sell and deliver its products and services may be hindered. As a result, the Company may be responsible for damages incurred by its customers, such as the additional cost of acquiring alternative supply at then-current market rates. These conditions could have a material impact on the Company's financial condition, results of operations and cash flows. Operation of power generation facilities involves significant risks and hazards customary to the power industry that could have a material adverse effect on NRG's revenues and results of operations, and NRG may not have adequate insurance to cover these risks and hazards. The ongoing operation of NRG's facilities involves risks that include the breakdown or failure of equipment or processes, performance below expected levels of output or efficiency and the inability to transport the Company's products to its customers in an efficient manner due to a lack of transmission capacity. Unplanned outages of generating units, including extensions of scheduled outages due to mechanical failures or other problems occur from time to time and are an inherent risk of the Company's business. Unplanned outages typically increase the Company's operation and maintenance expenses and may reduce the Company's revenues as a result of selling fewer MWh or incurring non-performance penalties and/or require NRG to incur significant costs as a result of obtaining replacement power from third parties in the open market or running one of its higher cost units to satisfy the Company's forward power sales obligations. NRG's inability to operate the Company's plants efficiently, manage capital expenditures and costs, and generate earnings and cash flow from the Company's asset-based businesses could have a material adverse effect on the Company's results of operations, financial condition or cash flows. In addition, NRG provides plant operations and commercial services to a variety of third-parties. There is a risk that mistakes, mis-operations, or actions taken by these third-parties could be attributed to NRG, including the risk of investigation 28 or penalties being assessed to NRG in connection with the services it offers, or that regulators could question whether NRG had the appropriate safeguards in place. Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of rotating equipment and delivering electricity to transmission and distribution systems. In addition to natural risks such as earthquake, flood, lightning, hurricane and wind, other hazards, such as fire, explosion, structural collapse and machinery failure are inherent risks in the Company's operations. These and other hazards can cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment, contamination of, or damage to, the environment and suspension of operations. The occurrence of any one of these events may result in NRG being named as a defendant in lawsuits asserting claims for substantial damages, including for environmental cleanup costs, personal injury and property damage and fines and/or penalties. NRG maintains an amount of insurance protection that it considers adequate, obtains warranties from vendors and obligates contractors to meet certain performance levels, but the Company cannot provide any assurance that these measures will be sufficient or effective under all circumstances and against all hazards or liabilities to which it may be subject. A successful claim for which the Company is not fully insured or protected could hurt its financial results and materially harm NRG's financial condition. NRG cannot provide any assurance that its insurance coverage will continue to be available at all or at rates or on terms similar to those presently available. Any losses not covered by insurance could have a material adverse effect on the Company's financial condition, results of operations or cash flows. Supplier and/or customer concentration may expose the Company to significant financial credit or performance risks. NRG often relies on a single contracted supplier or a small number of suppliers for the provision of fuel, transportation of fuel, chemicals and other services required for the operation of certain of its facilities. If these suppliers cannot perform, the Company utilizes the marketplace to provide these services. There can be no assurance that the marketplace can provide these services as, when and where required or at comparable prices. The Company may also hedge a portion of its exposure to power and fuel price fluctuations through various physical or financial agreements with counterparties. Counterparties to these agreements may breach or may be unable to perform their obligations, and in case of renewable generation, such counterparties may be subject to additional risks, such as facility development and transmission risks, unfavorable weather and atmospheric conditions, and mechanical or operational failures. NRG may not be able to enter into replacement agreements on terms as favorable as its existing agreements, or at all. If the Company is unable to enter into replacement purchase agreements or other replacement hedging agreements, the Company would be exposed to market price volatility and the risk that fuel and transportation may not be available during certain periods at any price. The failure of any supplier or customer to fulfill its contractual obligations to NRG could have a material adverse effect on the Company's financial results. Consequently, the financial performance of the Company's facilities is dependent on the credit quality of, and continued performance by, suppliers and customers. Maintenance, expansion and refurbishment of power generation facilities involve significant risks that could result in unplanned power outages or reduced output and could have a material adverse effect on NRG's results of operations, cash flows and financial condition. NRG's facilities require periodic maintenance and repair. Any unexpected failure, including failure associated with breakdowns, forced outages or any unanticipated capital expenditures could result in reduced profitability. NRG cannot be certain of the level of capital expenditures that will be required due to changing environmental and safety laws (including changes in the interpretation or enforcement thereof) needed facility repairs and unexpected events (such as natural disasters or terrorist attacks). The unexpected requirement of large capital expenditures could have a material adverse effect on the Company's liquidity and financial condition. NRG and its subsidiaries have guaranteed the performance of third parties, which may result in substantial costs in the event of non-performance. NRG and its subsidiaries have issued certain guarantees of the performance of others, which obligate NRG and its subsidiaries to perform in the event that the third parties do not perform. In the event of non-performance by the third parties, NRG could incur substantial cost to fulfill their obligations under these guarantees. Such performance guarantees could have a material impact on the operating results, financial condition, or cash flows of the Company. NRG relies on power transmission and distribution facilities that it does not own or control and that are subject to transmission constraints within a number of the Company's core regions. NRG depends on transmission and distribution facilities owned and operated by others to deliver power to its customers. If transmission or distribution is disrupted, including by force majeure events, or if the transmission or distribution 29 infrastructure is inadequate, NRG's ability to deliver power may be adversely impacted. The Company also cannot predict whether transmission or distribution facilities will be expanded in specific markets to accommodate competitive access to those markets. In addition, in certain of the markets in which NRG operates, energy transmission congestion may occur and the Company may be deemed responsible for congestion costs associated with power sales or purchases, or retail sales, particularly where the Company’s load is not co-located with its retail sales obligations. If NRG were liable for such congestion costs, the Company's financial results could be adversely affected. Rates and terms for service of certain residential and commercial customers in Alberta are subject to regulatory review and approval. The Company owns Direct Energy Regulated Services, which serves as a regulated rate supplier for residential and commercial energy customers in portions of the province of Alberta. It is required to engage in regulatory approval proceedings as a part of the process of establishing the terms and rates for sales of power and natural gas. These proceedings typically involve multiple parties, including governmental bodies and officials, consumer advocacy groups and various consumers of energy, who have differing concerns but who have the common objective of limiting rate increases or even reducing rates. Decisions are subject to appeal, potentially leading to additional uncertainty associated with the approval proceedings. The potential duration of such proceedings creates a risk that rates ultimately approved by the applicable regulatory body may not be sufficient for the Company to recover its costs by the time the rates become effective. Established rates are also subject to subsequent reviews by regulators, whereby various portions of rates could be adjusted, subject to refund or disallowed. In certain instances, the Company could agree to negotiated settlements related to various rate matters and other cost recovery elements. These settlements are subject to regulatory approval. The ultimate outcome and timing of regulatory rate proceedings have a significant effect on the Company to recover its costs or earn an adequate return. In addition, subsequent legislative or regulatory action could alter the terms on which the regulated business operates and future earnings could be negatively impacted. The Company also operates a competitive energy supply business in Alberta that is not subject to rate regulation and is subject to stringent requirements to segregate operations and information relating to the competitive business from the regulated business. Failure to comply with these and other requirements on the business could subject the Company's regulated and competitive businesses in Alberta to fines, penalties, and restrictions on the ability to continue business. Because NRG owns less than a majority of the ownership interests of some of its project investments, the Company cannot exercise complete control over their operations. NRG has limited control over the operation of some project investments and joint ventures because the Company's investments are in projects where it beneficially owns less than a majority of the ownership interests. NRG seeks to exert a degree of influence with respect to the management and operation of projects in which it owns less than a majority of the ownership interests by negotiating to obtain positions on management committees or to receive certain limited governance rights, such as rights to veto significant actions. However, the Company may not always succeed in such negotiations. NRG may be dependent on its co-venturers to operate such projects. The Company's co-venturers may not have the level of experience, technical expertise, human resources management or other attributes necessary to operate these projects optimally. The approval of co-venturers also may be required for NRG to receive distributions of funds from projects or to transfer the Company's interest in projects. NRG may be unable to integrate the operations of acquired entities in the manner expected. NRG enters into acquisitions that result in various benefits, including, among other things, cost savings and operating efficiencies. Achieving the anticipated benefits of these acquisitions depends on whether the businesses can be integrated into NRG in an efficient and effective manner. The integration process could take longer than anticipated and could result in the loss of valuable employees, the disruption of NRG's businesses, processes and systems or inconsistencies in standards, controls, procedures, practices, policies and compensation arrangements, any of which could divert the attention of management and adversely affect the Company's ability to achieve the anticipated benefits of the acquisitions. NRG may have difficulty addressing possible differences in corporate cultures and management philosophies. Failure to achieve these anticipated benefits could result in increased costs or decreases in the amount of expected revenues and could adversely affect NRG's future business, financial condition, operating results and prospects. Future acquisition or disposition activities could involve unknown risks and may have materially adverse effects and NRG may be subject to trailing liabilities from businesses that it disposes of or that are inactive. NRG may in the future acquire or dispose of businesses or assets, acquire or sell books of retail customers, or pursue other business activities, directly or indirectly through subsidiaries, that involve a number of risks. The acquisition of companies and assets is subject to substantial risks, including the failure to identify material problems during due diligence, the risk of over-paying for assets or customers, the ability to retain customers and the inability to arrange financing for an acquisition as may be required or desired. Further, the integration and consolidation of acquisitions requires substantial human, financial and other 30 resources and, ultimately, the Company's acquisitions may not be successfully integrated. In the case of dispositions, such risks may relate to employment matters, counterparties, regulators and other stakeholders in the disposed business, risks relating to separating the disposed assets from NRG’s business, risks related to the management of NRG’s ongoing business, risks unknown to NRG at the time, and other financial, legal and operational risks related to such disposition. In addition, NRG may be subject to material trailing liabilities from disposed businesses. Any such risk may result in one or more costly disputes or litigation. There can be no assurances that any future acquisitions will perform as expected or that the returns from such acquisitions will support the indebtedness incurred to acquire them or the capital expenditures needed to develop them. There can also be no assurances that NRG will realize the anticipated benefits from any such dispositions. The failure to realize the anticipated returns or benefits from an acquisition or disposition could adversely affect NRG's results of operations, cash flows and financial condition. Risks that are beyond NRG's control, including but not limited to acts of terrorism or related acts of war, natural disaster, hostile cyber intrusions, data breaches or other catastrophic events could have a material adverse effect on NRG's financial condition, results of operations and cash flows. NRG's generation facilities and the facilities of third parties on which they rely may be targets of terrorist activities, as well as events occurring in response to or in connection with such activities, all of which could cause environmental repercussions and/or result in full or partial disruption of the facilities ability to generate, transmit, transport or distribute electricity or natural gas. Strategic targets, such as energy-related facilities, may be at greater risk of future terrorist activities than other domestic targets. Any such environmental repercussions or disruption could result in a significant decrease in revenues or significant reconstruction or remediation costs beyond what could be recovered through insurance policies, which could have a material adverse effect on the Company's financial condition, results of operations and cash flows. In addition, significant weather events or terrorist actions could damage or shut down the power or gas transmission and distribution facilities upon which the Company is dependent, which may reduce retail volume for extended periods of time. Power or gas supply may be sold at a loss if these events cause a significant loss of retail customer demand. Numerous functions affecting the efficient operation of NRG’s businesses depend on the secure and reliable storage, processing and communication of electronic data and the use of sophisticated computer hardware and software systems. Hostile cyber intrusions, including those targeting information systems, as well as electronic control systems used at the generation facilities and for the distribution systems, could severely disrupt business operations and result in loss of service to customers, as well as significant expense to repair security breaches or system damage. The operation of NRG’s generation plants, including STP, and of NRG's energy and fuel trading businesses rely on cyber-based technologies and, therefore, are subject to the risk that such systems could be the target of disruptive actions, particularly through cyber-attack or cyber intrusion, including by computer hackers, foreign governments and cyber terrorists, or otherwise be compromised by unintentional events. As a result, operations could be interrupted, property could be damaged and sensitive customer information could be lost or stolen, causing NRG to incur significant losses of revenues, other substantial liabilities and damages, costs to replace or repair damaged equipment and damage to NRG's reputation. In addition, NRG may experience increased capital and operating costs to implement increased security for its cyber systems and plants. In addition, the Company requires access to sensitive data in the ordinary course of business. Examples of sensitive data are names, addresses, account information, historical electricity usage, expected patterns of use, payment history, credit bureau data, credit and debit card account numbers, driver's license numbers, social security numbers and bank account information. NRG provides sensitive data to vendors and service providers, who require access to this information in order to provide services to NRG, such as call center operations. If a significant breach occurs or if sensitive data that was entrusted to the Company were mishandled, the reputation of NRG and its businesses may be adversely affected, customer confidence may be diminished, or NRG and its retail operations may be subject to legal claims, any of which may contribute to the loss of customers and have a negative impact on the business and/or results of operations. The Company has made investments, and may continue to make investments, in new business initiatives predominantly focused on consumer products and in markets that may not be successful, may not achieve the intended financial results or may result in product liability and reputational risk that could adversely affect the Company. NRG continues to pursue growth in its existing businesses and markets and further diversification across the competitive energy value chain. Such initiatives may involve significant risks and uncertainties, including distraction of management from current operations, inadequate return on capital, and unidentified issues not discovered in the diligence performed prior to launching an initiative or entering a market. As part of these initiatives, the Company may be liable to customers for any damage caused to customers’ homes, facilities, belongings or property during the installation of Company products and systems, such as home back-up generators and residential HVAC system repairs, installation and replacements. Where such work is performed by independent contractors, such as repairs performed under the Company's home warranty and protection plan products, the Company may nonetheless face claims and costs for damage. In addition, shortages of skilled labor for Company projects could significantly delay a 31 project or otherwise increase its costs. The products that the Company sells or manufactures may expose the Company to product liability claims relating to personal injury, death, or environmental or property damage, and may require product recalls or other actions. Although the Company maintains liability insurance, the Company cannot be certain that its coverage will be adequate for liabilities actually incurred or that insurance will continue to be available to the Company on economically reasonable terms, or at all. Further, any product liability claim or damage caused by the Company could significantly impair the Company’s brand and reputation, which may result in a failure to maintain customers and achieve the Company’s desired growth initiatives in these new businesses. Changes in technology may impair the value of NRG's power plants and the attractiveness of its retail products, and the Company may potentially be affected by emerging technologies that may over time affect change in capacity markets and the energy industry overall with the inclusion of distributed generation and clean technology. Research and development activities are ongoing in the industry to provide alternative and more efficient technologies to produce power, including wind, photovoltaic (solar) cells, hydrogen, energy storage, and improvements in traditional technologies and equipment, such as more efficient gas turbines. Advances in these or other technologies could reduce the costs of power production to a level below what the Company has currently forecasted, which could adversely affect its cash flows, results of operations or competitive position. Technology, including distributed technology or changes in retail rate structures, may also have a material impact on the Company’s ability to retain retail customers. Some emerging technologies, such as distributed renewable energy technologies, broad consumer adoption of electric vehicles and energy storage devices, could affect the price of energy. These emerging technologies may affect the financial viability of utility counterparties and could have significant impacts on wholesale market prices, which could ultimately have a material adverse effect on NRG's financial condition, results of operations and cash flows. NRG's business, financial condition and results of operations could be adversely impacted by strikes or work stoppages by its unionized employees or inability to replace employees as they retire. As of December 31, 2021, approximately 13% of NRG's employees were covered by collective bargaining agreements. In the event that the Company's union employees strike, participate in a work stoppage or slowdown or engage in other forms of labor strife or disruption, NRG would be responsible for procuring replacement labor or the Company could experience reduced power generation or outages. Although NRG's ability to procure such labor is uncertain, contingency staffing planning is completed as part of each respective contract negotiations. Strikes, work stoppages or the inability to negotiate future collective bargaining agreements on favorable terms could have a material adverse effect on the Company's business, financial condition, results of operations and cash flows. In addition, a number of the Company's employees at NRG's plants are close to retirement. The Company's inability to replace retiring workers could create potential knowledge and expertise gaps as such workers retire. Risks Related to Governmental Regulation and Laws NRG's business is subject to substantial energy regulation and may be adversely affected by legislative or regulatory changes, as well as liability under, or any future inability to comply with, existing or future energy regulations or requirements. NRG's business is subject to extensive U.S. federal, state and local laws and foreign laws. Compliance with, or changes to, the requirements under these legal regimes may cause the Company to incur significant additional costs, reduce the Company's ability to hedge exposure or to sell retail power within certain states or to certain classes of retail customers, or restrict the Company’s marketing practices, its ability to pass through costs to retail customers, or its ability to compete on favorable terms with competitors, including the incumbent utility. Retail competition and home warranty services are regulated on a state-by-state or at the province-by-province level and are highly dependent on state and provincial laws, regulations and policies, which could change at any moment. Failure to comply with such requirements could result in the shutdown of a non-complying facility, the imposition of liens, fines, and/or civil or criminal liability. Public utilities under the FPA are required to obtain FERC acceptance of their rate schedules for wholesale sales of electricity. Except for ERCOT generation facilities and power marketers, all of NRG's non-qualifying facility generating companies and power marketing affiliates in the U.S. make sales of electricity in interstate commerce and are public utilities for purposes of the FPA. FERC has granted each of NRG's generating and power marketing companies that make sales of electricity outside of ERCOT the authority to sell electricity at market-based rates. FERC's orders that grant NRG's generating and power marketing companies market-based rate authority reserve the right to revoke or revise that authority if FERC subsequently determines that NRG can exercise market power in transmission or generation, create barriers to entry, or engage in abusive affiliate transactions. In addition, NRG's market-based sales are subject to certain market behavior rules, and if any of NRG's generating and power marketing companies were deemed to have violated those rules, they are subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of their market-based rate authority. If NRG's generating and power marketing companies were to lose their market-based rate authority, such companies would be required to obtain FERC's acceptance of a cost-of-service rate schedule and could become subject to the accounting, record- 32 keeping, and reporting requirements that are imposed on utilities with cost-based rate schedules. This could have a material adverse effect on the rates NRG charges for power from its facilities. Substantially all of the Company's generation assets are also subject to the reliability standards promulgated by the designated Electric Reliability Organization (currently NERC) and approved by FERC. If NRG fails to comply with the mandatory reliability standards, NRG could be subject to sanctions, including substantial monetary penalties and increased compliance obligations. NRG is also affected by legislative and regulatory changes, as well as changes to market design, market rules, tariffs, cost allocations, and bidding rules that occur in the existing ISOs. The ISOs that oversee most of the wholesale power markets impose, and in the future may continue to impose, mitigation, including price limitations, offer caps, non-performance penalties and other mechanisms to address some of the volatility and the potential exercise of market power in these markets. These types of price limitations and other regulatory mechanisms may have a material adverse effect on the profitability of NRG's generation facilities that sell energy and capacity into the wholesale power markets. The regulatory environment has undergone significant changes in the last several years due to state and federal policies affecting wholesale and retail competition and the creation of incentives for the addition of large amounts of new renewable generation and, in some cases, transmission. These changes are ongoing, and the Company cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on NRG's business. In addition, in some of these markets, interested parties have proposed material market design changes. If competitive restructuring of the electric power markets is reversed, discontinued, or delayed, the Company's business prospects and financial results could be negatively impacted. In addition, since 2010, there have been a number of reforms to the regulation of the derivatives markets, both in the United States and internationally. These regulations, and any further changes thereto, or adoption of additional regulations, including any regulations relating to position limits on futures and other derivatives or margin for derivatives, could negatively impact NRG’s ability to hedge its portfolio in an efficient, cost-effective manner by, among other things, potentially decreasing liquidity in the forward commodity and derivatives markets or limiting NRG’s ability to utilize non-cash collateral for derivatives transactions. NRG’s business may be affected by interference in the competitive wholesale marketplace. NRG’s generation and competitive retail operations rely on a competitive wholesale marketplace. The competitive wholesale marketplace may be impacted by out-of-market subsidies, including bailouts of uneconomic nuclear plants, imports of power from Canada, renewable mandates or subsidies, mandates to sell power below its cost of acquisition and associated costs, as well as out-of-market payments to new or existing generators. These out-of-market subsidies to existing or new generation undermine the competitive wholesale marketplace, which can lead to premature retirement of existing facilities, including those owned by the Company. If these measures continue, capacity and energy prices may be suppressed, and the Company may not be successful in its efforts to insulate the competitive market from this interference. The Company's retail operations may be materially impacted by rules or regulations that allow regulated utilities to participate in competitive retail markets or own and operate facilities that could be provided by competitive market participants. The integration of the Capacity Performance product into the PJM market could lead to substantial changes in capacity income and non-performance penalties, which could have a material adverse effect on NRG’s results of operations, financial condition and cash flows. PJM operates a pay-for-performance model where capacity payments are modified based on real-time generator performance. Capacity market prices are sensitive to design parameters, as well as additions of new capacity. NRG may experience substantial changes in capacity income and non-performance penalties, which could have a material adverse effect on NRG’s results of operations, financial condition and cash flows. NRG's ownership interest in a nuclear power facility subjects the Company to regulations, costs and liabilities uniquely associated with these types of facilities. Under the Atomic Energy Act of 1954, as amended, or AEA, ownership and operation of STP, of which NRG indirectly owns a 44% interest, is subject to regulation by the NRC. Such regulation includes licensing, inspection, enforcement, testing, evaluation and modification of all aspects of nuclear reactor power plant design and operation, environmental and safety performance, technical and financial qualifications, decommissioning funding assurance and transfer and foreign ownership restrictions. The current facility operating licenses for STP expire on August 20, 2047 (Unit 1) and December 15, 2048 (Unit 2). There are unique risks to owning and operating a nuclear power facility. These include liabilities related to the handling, treatment, storage, disposal, transport, release and use of radioactive materials, particularly with respect to spent nuclear fuel, and uncertainties regarding the ultimate, and potential exposure to, technical and financial risks associated with modifying or decommissioning a nuclear facility. The NRC could require the shutdown of the plant for safety reasons or refuse to permit restart of the unit after unplanned or planned outages. New or amended NRC safety and regulatory requirements may give rise to additional operation and maintenance costs and capital expenditures. Additionally, aging equipment may require more capital expenditures to keep each of these nuclear power plants operating efficiently. This equipment is also likely to require periodic 33 upgrading and improvement. Any unexpected failure, including failure associated with breakdowns, forced outages, or any unanticipated capital expenditures, could result in reduced profitability. STP will be obligated to continue storing spent nuclear fuel if the U.S. DOE continues to fail to meet its contractual obligations to STP made pursuant to the U.S. Nuclear Waste Policy Act of 1982 to accept and dispose of STP's spent nuclear fuel. Costs associated with these risks could be substantial and could have a material adverse effect on NRG's results of operations, financial condition or cash flow to the extent not covered by the Decommissioning Trusts or recovered from ratepayers. In addition, to the extent that all or a part of STP is required by the NRC to permanently or temporarily shut down or modify its operations, or is otherwise subject to a forced outage, NRG may incur additional costs to the extent it is obligated to provide power from more expensive alternative sources — either NRG's own plants, third party generators or the ERCOT — to cover the Company's then existing forward sale obligations. Such shutdown or modification could also lead to substantial costs related to the storage and disposal of radioactive materials and spent nuclear fuel. While STP maintains property and liability insurance for losses related to nuclear operations, there may be limitations on the amounts and types of insurance commercially available. See also Item 15 — Note 23, Commitments and Contingencies , Nuclear Insurance . An accident at STP or another nuclear facility could have a material adverse effect on NRG's financial condition, its operational results, or liquidity as losses may exceed the insurance coverage available and/or may result in the obligation to pay retrospective premium obligations. NRG is subject to environmental laws that impose extensive and increasingly stringent requirements on the Company's ongoing operations, as well as potentially substantial liabilities arising out of environmental contamination. These environmental requirements and liabilities could adversely impact NRG's results of operations, financial condition and cash flows. NRG is subject to the environmental laws of foreign and U.S., federal, state and local authorities. The Company must comply with numerous environmental laws and obtain numerous governmental permits and approvals to build and operate the Company's plants. Federal and state environmental laws generally have become more stringent over time. Should NRG fail to comply with any environmental requirements that apply to its operations, the Company could be subject to administrative, civil and/or criminal liability and fines, and regulatory agencies could take other actions seeking to curtail the Company's operations. In addition, when new requirements take effect or when existing environmental requirements are revised, reinterpreted or subject to changing enforcement policies, NRG's business, results of operations, financial condition and cash flows could be adversely affected. NRG's businesses are subject to physical, market and economic risks relating to potential effects of climate change, and policies at the national, regional and state levels to regulate GHG emissions and mitigate climate change could adversely impact NRG's results of operations, financial condition and cash flows. Fluctuations in weather and other environmental conditions, including temperature and precipitation levels, may affect consumer demand for electricity or natural gas. In addition, the potential physical effects of climate change, such as increased frequency and severity of storms, floods and other climatic events, could disrupt NRG's operations and supply chain, and cause it to incur significant costs in preparing for or responding to these effects. These or other changes in climate could lead to increased operating costs or capital expenses. NRG's customers may also experience the potential physical impacts of climate change and may incur significant costs in preparing for or responding to these efforts, including increasing the mix and resiliency of their energy solutions and supply. Hazards customary to the power production industry include the potential for unusual weather conditions, which could affect fuel pricing and availability, the Company's route to market or access to customers, i.e., transmission and distribution lines, transportation and delivery, or critical plant assets. The contribution of climate change to the frequency or intensity of weather-related events could affect NRG's operations and planning process. Climate change could also affect the availability of a secure and economical supply of water in some locations, which is essential for the continued operation of NRG's generation plants. NRG monitors water risk carefully. If it is determined that a water supply risk exists that could impact projected generation levels at any plant risk mitigation efforts are identified and evaluated for implementation. Further, demand for NRG's energy-related services could be similarly impacted by consumers’ preferences or market factors favoring energy efficiency, low-carbon power sources or reduced electricity usage. NRG's GHG emissions for 2021 can be found in Item 1, Business —Environmental Regulatory Matters. GHG regulation, at the state or federal level, could increase the cost of electricity generated by fossil fuels, and such increases could reduce demand for the power NRG generates and markets. Any increase in costs at a national, regional or state level could adversely affect NRG’s results of operations, financial condition and cash flows 34 Changes in data privacy and data protection laws and regulations or any non-compliance with such laws and regulations, could adversely affect NRG’s business and financial results. The consumer privacy landscape continues to experience momentum for greater privacy protection and reform at the state and federal level in response to precedents set forth by the General Data Protection Regulation (the "GDPR") and the California Consumer Privacy Act (the "CCPA"). The development and evolving nature of domestic and international privacy regulation and enforcement could impact and potentially limit how NRG processes personally identifiable information. The 2020 enactment of the CCPA granted certain data access rights to California residents with respect to their personal information, and with the forthcoming amendments to the CCPA supported by the California Privacy Rights Act (the “CPRA”), effective January 1, 2023, California residents will have increased access rights (including the right to limit the use and disclosure of sensitive personal information), which will be enforced by a new state privacy regulator, resulting in more scrutiny of business practices and disclosures. Additional states including Virginia, Colorado, and Nevada have similarly adopted enhanced data privacy legislation patterned after the standards set forth by CCPA, including broader data access rights, with Virginia going a step further requiring businesses to perform data protection assessments for certain processing activities. As new laws and regulations are created, requiring businesses to implement processes to enable customer access to their data and enhanced data protection and management standards, NRG cannot forecast the impact that they may have on the Company’s business. Any non-compliance with laws may result in proceedings or actions against the Company by governmental entities or individuals. Moreover, any inquiries or investigations, government penalties or sanctions, or civil actions by individuals may be costly to comply with, resulting in negative publicity, increased operating costs, significant management time and attention, and may lead to remedies that harm the business, including fines, demands or orders that existing business practices be modified or terminated. NRG's retail operations are subject to changing rules and regulations that could have a material impact on the Company's profitability. The competitiveness of NRG's retail operations partially depends on regulatory policies that establish the structure, rules, terms and conditions on which services are offered to retail customers. These policies can include, among other things, controls on the retail rates that NRG can charge, the imposition of additional costs on sales, restrictions on the Company's ability to obtain new customers through various marketing channels and disclosure requirements. The Company's retail operations may be materially impacted by rules or regulations that allow regulated utilities to participate in competitive retail markets or own and operate facilities that could be provided by competitive market participants. Additionally, state, federal or provincial imposition of net metering or RPS programs can make it more or less expensive for retail customers to supplement or replace their reliance on grid power. The Company's international operations are exposed to political and economic risks, commercial instability and events beyond the Company's control in the countries in which it operates, which risks may negatively impact the Company's business. The Company's international operations depend on products manufactured, purchased and sold in the U.S. and internationally. In some cases, these countries have greater political and economic volatility and greater vulnerability to infrastructure and labor disruptions than in NRG's other markets. Operating a business in a number of different regions and countries exposes the Company to a number of risks, including: multiple and potentially conflicting laws, regulations and policies that are subject to change; imposition of currency restrictions on repatriation of earnings or other restraints; imposition of burdensome tariffs or quotas; national and international conflict, including terrorist acts; and political and economic instability or civil unrest that may severely disrupt economic activity in affected countries. The occurrence of one or more of these events may negatively impact the Company's business, results of operations and financial condition. Risks Related to Public Health Threats Public health threats or outbreaks of communicable diseases could have a material adverse effect on the Company’s operations and financial results . The Company may face risks related to public health threats or outbreaks of communicable diseases. A widespread healthcare crisis, such as an outbreak of a communicable disease, could adversely affect the global economy and the Company’s ability to conduct its business for an indefinite period of time. For example, the ongoing global COVID-19 pandemic negatively impacted local and global economies, disrupted financial markets and international trade, resulted in increased unemployment levels and impacted local and global supply chains, all of which negatively impact the electricity industry and the Company’s business. Federal, state, and local governments had implemented various mitigation measures, including travel restrictions, border closings, restrictions on public gatherings, shelter-in-place orders and limitations on business activities. Although the operations of the Company are considered an essential service, some of these measures may adversely impact the ability of NRG employees, contractors, suppliers, customers, and other business partners to conduct 35 business activities. This could have a material adverse effect on the Company’s results of operations, financial condition, risk exposure and liquidity. In particular, the continued spread of COVID-19 and efforts to contain the virus could: • adversely impact demand for the Company’s electricity services and other products and services and the ability of customers to pay their bills; • cause an increase in costs for the Company as a result of emergency measures taken by state and local regulatory authorities in response to the COVID-19 crisis, including regulatory changes prohibiting customer disconnects and late fees; • impact the ability of the Company's partners or counterparties to perform their obligations under existing arrangements, including development projects, power purchase and sale arrangements, hedging arrangements or other commercial activities; and • cause other unpredicted events which may have an adverse impact on the Company’s results of operations, financial condition, risk exposure and liquidity. The situation surrounding COVID-19 remains fluid and the potential for a material impact on the Company’s results of operations, financial condition, risk exposure and liquidity increases the longer the virus, or any variants thereof, impacts the level of economic activity in the United States and abroad. NRG cannot reasonably estimate with any degree of certainty the future impact of COVID-19, or any resurgence of COVID-19 or other pandemic may have on the Company’s results of operations, financial position, risk exposure and liquidity. Risks Related to the Economic and Financial Market Conditions, and the Company's Indebtedness NRG's level of indebtedness could adversely affect its ability to raise additional capital to fund its operations or return capital to stockholders. It could also expose it to the risk of increased interest rates and limit its ability to react to changes in the economy or its industry. NRG's substantial debt could have negative consequences, including: • increasing NRG's vulnerability to general economic and industry conditions; • requiring a substantial portion of NRG's cash flow from operations to be dedicated to the payment of principal and interest on its indebtedness, therefore reducing NRG's ability to pay dividends or to use its cash flow to fund its operations, capital expenditures and future business opportunities; • limiting NRG's ability to enter into long-term power sales or fuel purchases which require credit support; • limiting NRG's ability to obtain additional financing for working capital including collateral postings, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes; • limiting NRG's ability to adjust to changing market conditions and placing it at a competitive disadvantage compared to its competitors who have less debt; and • exposing NRG to the risk of increased interest rates because certain of its borrowings are at variable rates of interest, primarily through its Revolving Credit Facility. The Company’s credit documents contain financial and other restrictive covenants that may limit the Company's ability to return capital to stockholders or otherwise engage in activities that may be in its long-term best interests. NRG's failure to comply with those covenants could result in an event of default which, if not cured or waived, could result in the acceleration of all of the Company's indebtedness. The Company's corporate credit agreement includes a sustainability-linked metric and sustainability-linked bonds, which could result in increased interest expense to the Company if the sustainability metrics set forth therein are not met. Furthermore, financial and other restrictive covenants contained in any project level subsidiary debt may limit the ability of NRG to receive distributions from such subsidiary. In addition, NRG's ability to arrange financing, either at the corporate level, a non-recourse project-level subsidiary or otherwise, and the costs of such capital, are dependent on numerous factors, including: general economic and capital market conditions; credit availability from banks and other financial institutions; investor confidence in NRG, its partners and the regional wholesale power markets; NRG's financial performance and the financial performance of its subsidiaries; NRG's level of indebtedness and compliance with covenants in debt agreements; maintenance of acceptable credit ratings; cash flow; and provisions of tax and securities laws that may impact raising capital. NRG may not be successful in obtaining additional capital for these or other reasons. The failure to obtain additional capital from time to time may have a material adverse effect on its business and operations. 36 Adverse economic conditions could adversely affect NRG’s business, financial condition, results of operations and cash flows. Adverse economic conditions and declines in wholesale energy prices, partially resulting from adverse economic conditions, may impact NRG's results of operations. The breadth and depth of negative economic conditions may have a wide-ranging impact on the U.S. business environment. In addition, adverse economic conditions also reduce the demand for energy commodities. Reduced demand from negative economic conditions continues to impact the key domestic wholesale energy markets NRG serves. In general, economic and commodity market conditions will continue to impact NRG’s unhedged future energy margins, liquidity, earnings growth and overall financial condition. In addition, adverse economic conditions, declines in wholesale energy prices, reduced demand for energy and other factors may negatively impact the trading price of NRG’s common stock and impact forecasted cash flows, which may require NRG to evaluate its goodwill and other long-lived assets for impairment. Any such impairment could have a material impact on NRG’s financial statements. Goodwill and other intangible assets that NRG has recorded in connection with its acquisitions are subject to impairment evaluations and, as a result, the Company could be required to write off some or all of this goodwill and other intangible assets, which may adversely affect the Company's financial condition and results of operations. Goodwill is not amortized but is reviewed annually or more frequently for impairment. Other intangibles are also reviewed at least annually or more frequently, if certain conditions exist, and are amortized. Any reduction in or impairment of the value of goodwill or other intangible assets will result in a charge against earnings, which could materially adversely affect NRG's reported results of operations and financial position in future periods. 37 CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION This Annual Report on Form 10-K of NRG Energy, Inc., or NRG or the Company, includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or Exchange Act. The words "believes," "projects," "anticipates," "plans," "expects," "intends," "estimates" and similar expressions are intended to identify forward-looking statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause NRG's actual results, performance and achievements, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. These factors, risks and uncertainties include the factors described under Item 1A — Risk Factors and the following: • Business uncertainties related to the integration of the operations of Direct Energy with its own; • NRG's ability to obtain and maintain retail market share; • General economic conditions, changes in the wholesale power and gas markets and fluctuations in the cost of fuel; • Volatile power and gas supply costs and demand for power and gas; • Changes in law, including judicial and regulatory decisions; • Hazards customary to the power production industry and power generation operations, such as fuel and electricity price volatility, unusual weather conditions, catastrophic weather-related or other damage to facilities, unscheduled generation outages, maintenance or repairs, unanticipated changes to fuel supply costs or availability due to higher demand, shortages, transportation problems or other developments, environmental incidents, or electric transmission or gas pipeline system constraints and the possibility that NRG may not have adequate insurance to cover losses as a result of such hazards; • The effectiveness of NRG's risk management policies and procedures and the ability of NRG's counterparties to satisfy their financial commitments; • NRG's ability to enter into contracts to sell power or gas and procure fuel on acceptable terms and prices; • NRG's inability to estimate with any degree of certainty the future impact that COVID-19, any resurgence of COVID-19, or other pandemic may have on NRG's results of operations, financial position, risk exposure and liquidity; • NRG's ability to successfully integrate, realize cost savings and manage any acquired businesses; • NRG's ability to engage in successful acquisitions and divestitures, as well as other mergers and acquisitions activity; • Cyber terrorism and inadequate cybersecurity, data breaches or the occurrence of a catastrophic loss and the possibility that NRG may not have adequate insurance to cover losses resulting from such hazards or the inability of NRG's insurers to provide coverage; • Counterparties' collateral demands and other factors affecting NRG's liquidity position and financial condition; • NRG's ability to operate its businesses efficiently and generate earnings and cash flows from its asset-based businesses in relation to its debt and other obligations; • The liquidity and competitiveness of wholesale markets for energy commodities; • Government regulation, including changes in market rules, rates, tariffs and environmental laws; • NRG's ability to develop and innovate new products, as retail and wholesale markets continue to change and evolve; • Price mitigation strategies and other market structures employed by ISOs or RTOs that result in a failure to adequately and fairly compensate NRG's generation units; • NRG's ability to mitigate forced outage risk; • NRG's ability to borrow funds and access capital markets, as well as NRG's substantial indebtedness and the possibility that NRG may incur additional indebtedness in the future; • Operating and financial restrictions placed on NRG and its subsidiaries that are contained in NRG's corporate credit agreements, and in debt and other agreements of certain of NRG subsidiaries and project affiliates generally; • The ability of NRG and its counterparties to develop and build new power generation facilities; • NRG's ability to implement its strategy of finding ways to meet the challenges of climate change, clean air and protecting natural resources, while taking advantage of business opportunities; • NRG's ability to increase cash from operations through operational and market initiatives, corporate efficiencies, asset strategy, and a range of other programs throughout NRG to reduce costs or generate revenues; • NRG's ability to successfully evaluate investments and achieve intended financial results in new business and growth initiatives; 38 • NRG's ability to develop and maintain successful partnering relationships as needed. Forward-looking statements speak only as of the date they were made, and NRG undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors that could cause NRG's actual results to differ materially from those contemplated in any forward-looking statements included in this Annual Report on Form 10-K should not be construed as exhaustive. Item 1B — Unresolved Staff Comments None. 39 Item 2 — Properties Listed below are descriptions of NRG's interests in facilities, operations and/or projects owned or leased as of December 31, 2021. The rated MW capacity figures provided represent nominal summer MW capacity of power generated. Net MW capacity is adjusted for the Company's owned or leased interest as of December 31, 2021. The Company believes its existing facilities, operations and/or projects are suitable for the conduct of its business. The following table summarizes NRG's power production and cogeneration facilities by region: Name of Facility Power Market Plant Type Primary Fuel Location Rated MW Capacity (a) Net MW Capacity (b) % Owned Texas Cedar Bayou ERCOT Fossil Natural Gas TX 1,494 1,494 100.0 Cedar Bayou 4 ERCOT Fossil Natural Gas TX 504 252 50.0 Elbow Creek ERCOT Other Battery Storage TX 2 2 100.0 Greens Bayou ERCOT Fossil Natural Gas TX 330 330 100.0 Gregory ERCOT Fossil Natural Gas TX 385 385 100.0 Limestone (c) ERCOT Fossil Coal TX 1,660 1,660 100.0 Petra Nova Cogen ERCOT Fossil Natural Gas TX 68 34 50.0 San Jacinto ERCOT Fossil Natural Gas TX 160 160 100.0 South Texas Project ERCOT Nuclear Uranium TX 2,572 1,132 44.0 T.H. Wharton ERCOT Fossil Natural Gas TX 1,002 1,002 100.0 W.A. Parish ERCOT Fossil Coal TX 2,514 2,514 100.0 W.A. Parish ERCOT Fossil Natural Gas TX 1,118 1,118 100.0 Total Texas 11,809 10,083 East Astoria Turbines (e) NYISO Fossil Natural Gas NY 420 420 100.0 Chalk Point PJM Fossil Natural Gas MD 80 80 100.0 Fisk PJM Fossil Oil IL 171 171 100.0 Indian River (f) PJM Fossil Coal DE 410 410 100.0 Indian River PJM Fossil Oil DE 16 16 100.0 Joliet PJM Fossil Natural Gas IL 1,381 1,381 100.0 Powerton PJM Fossil Coal IL 1,538 1,538 100.0 Vienna PJM Fossil Oil MD 167 167 100.0 Waukegan (f) PJM Fossil Coal IL 682 682 100.0 Waukegan PJM Fossil Oil IL 101 101 100.0 Will County (f) PJM Fossil Coal IL 510 510 100.0 Total East 5,476 5,476 West/Other Cottonwood MISO Fossil Natural Gas TX 1,177 1,177 ___(d) Gladstone Fossil Coal AUS 1,613 605 37.5 Ivanpah CAISO Renewable Solar CA 393 214 54.5 Midway-Sunset CAISO Fossil Natural Gas CA 226 113 50.0 Stadiums and Other Renewable Solar various 5 5 100.0 Watson CAISO Fossil Natural Gas CA 416 204 49.0 Total West/Other 3,830 2,318 Total Fleet 21,115 17,877 (a) MW capacity of the facility without taking into account NRG ownership percentage (b) Actual capacity can vary depending on factors including weather conditions, operational conditions, and other factors. Additionally, ERCOT and PJM require periodic demonstration of capability, and the capacity may vary individually and in the aggregate from time to time (c) In early July 2021, Limestone Unit 1 came offline as a result of damage to the duct work associated with the flue gas desulfurization system. Based on management's current assessment of necessary remediation efforts, Unit 1 is expected to remain on an outage until the second quarter of 2022 (d) NRG leases 100% interests in the Cottonwood facility through a facility lease agreement expiring in May 2025 and operates the Cottonwood facility (e) On February, 22, 2022, NRG submitted deactivation notices to the NYISO for the Astoria facility, with a planned retirement date of 2023 40 (f) 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 as detailed bellow: Name of Facility Power Market Primary Fuel Net MW Capacity Retirement Date Indian River 4 PJM Coal 410 June 2022* Waukegan 7 PJM Coal 328 June 2022 Waukegan 8 PJM Coal 354 June 2022 Will County PJM Coal 510 June 2022 Total 1,602 * 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. Other Properties NRG owns several real properties and facilities related to its generation assets, other vacant real property unrelated to its generation assets, and properties not used for operational purposes. NRG believes it has satisfactory title to its plants and facilities in accordance with standards generally accepted in the electric power industry, subject to exceptions that, in the Company's opinion, would not have a material adverse effect on the use or value of its portfolio. NRG leases its operational and corporate headquarters at 910 Louisiana Street, Houston, Texas, its financial and commercial corporate offices at 804 Carnegie Center, Princeton, New Jersey, as well as its retail operations offices, call centers, and various other office space. Item 3 — Legal Proceedings See Item 15 — Note 23, Commitments and Contingencies , to the Consolidated Financial Statements for discussion of the material legal proceedings to which NRG is a party. Item 4 — Mine Safety Disclosures There have been no events that are required to be reported under this Item. 41 PART II Item 5 — Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. Market Information and Holders NRG's common stock trades on the New York Stock Exchange under the symbol "NRG." NRG's authorized capital stock consists of 500,000,000 shares of common stock and 10,000,000 shares of preferred stock. A total of 25,000,000 shares of the Company's common stock are authorized for issuance under the NRG LTIP. For more information about the NRG LTIP and the NRG GenOn LTIP, refer to Item 12 — S ecurity Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters and Item 15 — Note 21, Stock-Based Compensation , to the Consolidated Financial Statements . As of January 31, 2022, there were 16,501 common stockholders of record. NRG increased the annual dividend to $1.30 from $1.20 per share beginning in the first quarter of 2021 and further increased the annual dividend by 8% to $1.40 per share beginning in the first quarter of 2022 . NRG expects to target an annual dividend growth rate of 7-9% per share in subsequent years. Issuer Purchases of Equity Securities The table below sets forth the information with respect to purchases made by or on behalf of NRG or any "affiliated purchaser" (as defined in Rule 10b-18(a)(3) under the Exchange Act) of NRG's common stock during the quarter ended December 31, 2021. For the three months ended December 31, 2021 Total Number of Shares Purchased Average Price Paid per Share (b) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (a)(c) Month #1 (October 1, 2021 to October 31, 2021 — $ — — $ — Month #2 (November 1, 2021 to November 30, 2021, — $ — — $ — Month #3 (December 1, 2021 to December 31, 2021) 1,084,752 $ 40.85 1,084,752 $ 955,665,275 Total at December 31, 2021 1,084,752 $ 40.85 1,084,752 (a) 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 December 2021 and will continue throughout 2022 (b) The average price paid per share excludes commissions of $0.02 per share paid in connection with the open market share repurchases (c) Includes commissions of $0.02 per share paid in connection with the open market share repurchases 42 Stock Performance Graph The performance graph below compares the cumulative total stockholder return on NRG's common stock for the period December 31, 2016 through December 31, 2021 with the cumulative total return of the Standard & Poor's 500 Composite Stock Price Index, or S&P 500, and the Philadelphia Utility Sector Index, or UTY. The performance graph shown below is being furnished and compares each period assuming that $100 was invested on December 31, 2016, in each of the common stock of NRG, the stocks included in the S&P 500 and the stocks included in the UTY, and that all dividends were reinvested. Comparison of Cumulative Total Return 12/31/2016 12/31/2017 12/31/2018 12/31/2019 12/31/2020 12/31/2021 NRG Energy, Inc. $ 100.00 $ 233.70 $ 326.22 $ 328.47 $ 321.43 $ 381.07 S&P 500 100.00 121.83 116.49 153.17 181.35 233.41 UTY 100.00 112.82 116.79 148.11 152.14 179.90 Item 6 — Reserved 43 Item 7 — Management's Discussion and Analysis of Financial Condition and Results of Operations The discussion and analysis below has been organized as follows: • Executive Summary, including the business environment in which the Company operates, a discussion of regulation, weather, competition and other factors that affect the business, and other significant events that are important to understanding the results of operations and financial condition; • Results of operations for the years ended December 31, 2021 and December 31, 2020, including an explanation of significant differences between the periods in the specific line items of NRG's Consolidated Statements of Operations; • Financial condition addressing credit ratings, liquidity position, sources and uses of cash, capital resources and requirements, contractual obligations and market commitments, and off-balance sheet arrangements; and • Critical accounting estimates that are most important to both the portrayal of the Company's financial condition and results of operations, and require management's most difficult, subjective, or complex judgments. As you read this discussion and analysis, refer to NRG's Consolidated Statements of Operations in this Form 10-K, which present the results of the Company's operations for the years ended December 31, 2021 and 2020, and also refer to Item 1 to this Form 10-K for more detail discussion about the Company's business. A discussion and analysis of fiscal year 2019 may be found in Part II, Item 7 — Management's Discussion and Analysis of Financial Condition and Results of Operations of the Annual Report on Form 10-K for the fiscal year ended December 31, 2020. As further described in Item 15 — Note 4, Acquisitions, Discontinued Operations and Dispositions , to the Consolidated Financial Statements, the Company determined in prior years that the following businesses were discontinued operations and recast to present their results in the corporate segment: • South Central Portfolio • NRG Yield, Inc. and its Renewables Platform • Carlsbad Executive Summary 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 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 as of December 31, 2021. Business Environment The industry dynamics and external influences affecting the Company, its businesses, and the retail energy and power generation industry in 2021 and for the future medium term include: Market Dynamics — The price of natural gas plays an important role in setting the price of electricity in many of the regions where NRG operates. Natural gas prices are driven by variables including demand from the industrial, residential, and electric sectors, productivity across natural gas supply basins, costs of natural gas production, changes in pipeline infrastructure, and the financial and hedging profile of natural gas customers and producers. In 2021, the average natural gas price at Henry Hub was 85% higher than in 2020. NRG may experience impacts to gross margins due to significant, rapid changes in current natural gas prices and the lag in our ability to make a corresponding adjustment to the retail rates we charge customers on term and month to month contracts. The Company hedges its load commitments in order to mitigate the impact of changes in commodity prices, and as a result, these gross margin impacts would be realized in future periods until we are able to make the corresponding adjustments to the retail customer rates. Natural gas prices are a primary driver of coal demand. Coal commodity prices increased significantly in 2021, which is partly due to supply chain disruptions, as further discussed below in Global Supply Chain Disruptions , as well as stressed coal equities, which has led coal suppliers to file for bankruptcy protection, launch debt exchanges, rationalize assets, and cut production. 44 Electricity Prices — The price of electricity is a key determinant of the profitability of the Company. Many variables such as the price of different fuels, weather, load growth and unit availability all coalesce to impact the final price for electricity and the Company's profitability. An increase in supply cost volatility in the competitive retail markets may result in smaller companies choosing to exit the market, which may result in further consolidation in the competitive retail space. The following table summarizes average on-peak power prices for each of the major markets in which NRG operates for the years ended December 31, 2021 and 2020. The average on-peak power prices increased significantly in Texas due to the impact from Winter Storm Uri. The average on-peak power prices increased in East and West/Services/Other due to higher natural gas prices. Average On-Peak Power Price ($/MWh) Year Ended December 31, 2021 vs 2020 Region 2021 2020 Change % Texas (a) ERCOT - Houston (a) $ 192.17 $ 27.65 595 % ERCOT - North (a) 189.05 25.85 631 % East NY J/NYC (b) 48.71 24.55 98 % NEPOOL (b) 51.81 26.52 95 % COMED (PJM) (b) 41.33 22.48 84 % PJM West Hub (b) 45.67 24.49 86 % West CAISO - SP15 (b) 53.53 38.15 40 % MISO - Louisiana Hub (b) 43.05 24.43 76 % (a) Average on-peak power prices based on real time settlement prices as published by the respective ISOs (b) Average on-peak power prices based on day-ahead settlement prices as published by the respective ISOs The following table summarizes average realized power prices for NRG, including the impact of settled hedges, for the years ended December 31, 2021 and 2020: Average Realized Power Price ($/MWh) Year Ended December 31, 2021 vs 2020 Segment 2021 2020 Change % East (a) $ 36.33 $ 34.92 4 % West/Services/Other 43.63 34.80 25 % (a) Average Realized Power Price reflects energy sales from the generation fleet, including sales to the retail component of the East Segment. Intercompany financial transactions hedging generation with the retail operations make up ($8.03)/MWh in the year ended December 31, 2021 and $12.18/MWh in the year ended December 31, 2020 The average realized power prices increased less than average on peak power prices for the year ended December 31, 2021, as compared to the same period in 2020, due to the Company's multi-year hedging program impacting average realized power prices, while on peak power prices increased due to increased natural gas prices and warmer June temperatures in California. Increased Awareness of, and Action to Combat, Climate Change — Diverse groups of stakeholders, including investors, asset managers, financial institutions, non-government organizations, industry coalitions, individual companies, consumer groups and academic institutions, are increasingly engaged in efforts to limit global warming in the post-industrial era to well below 2 degrees Celsius. As a result, policymakers and regulators at regional, national, sub-national and local levels of government, both in the United States and other parts of the world, are increasingly focused on actions to combat climate change. NRG actively monitors climate change related developments that could impact its business and regularly engages with a diverse set of stakeholders on these issues. Such engagement helps the Company identify and pursue potential opportunities both to decarbonize its business and better serve its customers. NRG is committed to providing transparent disclosures of its climate risks and opportunities to stakeholders. The Company became an early supporter of the Task Force on Climate-related Financial Disclosures ("TCFD") recommendations after they were issued in 2017, published a TCFD mapping disclosure in December 2020 and issued a stand-alone TCFD report in December 2021. 45 Lower Carbon Infrastructure Development — Policy mechanisms at the state and federal level, including production and investment tax credits, cash grants, loan guarantees, accelerated depreciation tax benefits, RPS, and carbon trading plans, have supported and continue to support the development of renewable generation, demand-side and smart grid, and other lower carbon infrastructure technologies. In addition, the costs associated with the development of lower carbon infrastructure, such as wind and solar generating facilities, continue to decline. These factors continue to drive increases in the development of lower carbon infrastructure in the markets where the Company participates, which may impact the ability of the Company's generating facilities to participate in those markets. According to ERCOT, 39% of 2021 energy consumption in the ERCOT market was generated from carbon emission-free resources, with wind power contributing 24%. In addition, subsidies and incentives have contributed to the increase in renewable power sources, and customer awareness and preferences are shifting toward sustainable solutions. Increased demand for sustainable energy products from both residential and commercial customers creates opportunities for diversified product offerings in competitive retail markets. Digitization and Customization — The electric industry is experiencing major technology changes in the way power is distributed and used by end-use customers. The electric grid is shifting from a centralized analog system, where power is generated from limited sources and flows in one direction, to a decentralized multidirectional system, where power can be generated from a number of distributed resources and stored or dispatched on an as-needed basis. In addition, customers are seeking new ways to engage with their power providers. Technologies like smart thermostats, appliances and electric vehicles are giving individuals more choice and control over their electricity usage. Weather — Weather conditions in the regions of the U.S. in which NRG conducts business influence the Company's financial results. Weather conditions can affect the supply and demand for electricity and fuels and may also impact the availability of the Company's generating assets. Changes in energy supply and demand may impact the price of these energy commodities in both the spot and forward markets, which may affect the Company's results in any given period. Typically, demand for and the price of electricity is higher in the summer and the winter seasons, when temperatures are more extreme. The demand for and price of natural gas is also generally higher in the winter. However, all regions of the U.S. typically do not experience extreme weather conditions at the same time, thus NRG's operations are typically not exposed to the effects of extreme weather in all parts of its business at once. A significant portion of the Company's business is located within Texas, and extreme weather conditions occurring in Texas may have a material impact on the Company's financial position. For discussion of the recent weather event in Texas, see Significant Events - Extreme Weather Event in Texas During February 2021 and expected Uplift Securitization Proceeds below. Global Supply Chain Disruptions — There are currently global supply chain disruptions impacting natural gas, coal and other fuels and materials necessary for the production and sale of electricity to our retail customers. These supply chain disruptions are due in part to increased demand driven by a number of factors outside the Company's control including the COVID-19 pandemic, labor shortages and extreme weather events in the U.S. These factors are impacting the dispatch of generation facilities, as well as the costs to serve our retail customers. The Company expects supply chain disruptions will continue throughout the remainder of 2022. We are working closely with our suppliers and customers to minimize any potential adverse impacts of these events. We will continue to actively monitor all direct and indirect potential impacts of the supply chain disruptions, and will seek to mitigate and minimize their impact on our business. Other Factors — A number of other factors significantly influence the level and volatility of prices for energy commodities and related derivative products for NRG's business. These factors include: • seasonal, daily and hourly changes in demand; • extreme peak demands; • available supply resources; • transportation and transmission availability and reliability within and between regions; • location of NRG's generating facilities relative to the location of its load-serving opportunities; • procedures used to maintain the integrity of the physical electricity system during extreme conditions; and • changes in the nature and extent of federal and state regulations. These factors can affect energy commodity and derivative prices in different ways and to different degrees. These effects may vary throughout the country as a result of regional differences in: • weather conditions; • market liquidity; • capability and reliability of the physical electricity and gas systems; • local transportation systems; and • the nature and extent of electricity deregulation. 46 Environmental Matters, Regulatory Matters and Legal Proceedings — Details of environmental matters are presented in Item 15 — Note 25, Environmental Matters , to the Consolidated Financial Statements and Item 1 — Business, Environmental Matters . Details of regulatory matters are presented in Item 15 — Note 24, Regulatory Matters , to the Consolidated Financial Statements and Item 1 — Business, Regulatory Matters . Details of legal proceedings are presented in Item 15 — Note 23, Commitments and Contingencies , to the Consolidated Financial Statements. Some of this information relates to costs that may be material to the Company's financial results. Significant Events The following significant events occurred during 2021 and through the filing date, as further described within this Management's Discussion and Analysis and the consolidated financial statements: Financing Activities On August 23, 2021, the Company issued $1.1 billion of aggregate principal amount at par of 3.875% senior notes due 2032 (the "2032 Senior Notes"). The 2032 Senior Notes are senior unsecured obligations of NRG and are guaranteed by certain of its subsidiaries. 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. During the year ended December 31, 2021, the Company redeemed $1.9 billion in aggregate principal of its Senior Notes for $1.9 billion using the proceeds of the 2032 Senior Notes and cash on hand. Extreme Weather Event in Texas During February 2021 and expected Uplift Securitization proceeds During February 2021, Texas experienced unprecedented cold temperatures for a prolonged duration as a result of Winter Storm Uri, resulting in a power emergency, blackouts, and an estimated all-time peak demand of 77 GW (without load shed). Ahead of the event, NRG launched residential customer communications calling for conservation across all of its brands, and initiated residential and commercial and industrial demand response programs to curtail customer load. The Company maximized available generating capacity and brought in additional resources to supplement in-state staff with technical and operating experts from the rest of its U.S. fleet. The Texas Legislature passed House Bill 4492, which among other things, authorized ERCOT to obtain $2.1 billion of financing to distribute to LSEs that were charged and paid to ERCOT exceptionally highly priced ORDPA and ancillary service costs during Winter Storm Uri. Based on LSE-level detail published by the PUCT on December 7, 2021, NRG will receive $689 million from ERCOT. During the year ended December 31, 2021, Winter Storm Uri's pre-tax financial impact to the Company was a loss of $380 million, which reflects the recovery of $689 million of cost of operations as a result of the proceeds we will receive from the Uplift Securitization discussed above, with receipt expected to occur during the second quarter of 2022. The Company continues to pursue additional mitigants including, but not limited to, customer bad debt mitigation, counterparty default recovery, and additional ERCOT default recovery. Direct Energy Acquisition 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. The acquisition increased NRG's retail portfolio by over 3 million customers and complements its integrated model. It also broadened the Company's presence in the Northeast and into states and locales where it did not previously operate, supporting NRG's objective to diversify its business. See Item 15 — Note 4, Acquisitions, Discontinued Operations and Dispositions , to the Consolidated Financial Statements for further discussion. Limestone Extended Outage In early July 2021, Limestone Unit 1 came offline as a result of damage to the duct work associated with the flue gas desulfurization system. Based on management's current assessment of necessary remediation efforts, Limestone Unit 1 is expected to remain on an outage until the second quarter of 2022. PJM Base Residual Auction results and Planned Retirement of 1,600 MWs of PJM Coal Capacity 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. 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. 47 The Company recorded impairment losses of $271 million and $35 million on the PJM generating assets and Midwest Generation goodwill, respectively, in connection with the decline in PJM capacity prices and the near-term retirement dates of certain assets. 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. Sale of 4.8 GW of Fossil Generation Assets On December 1, 2021, the Company sold approximately 4,850 MWs of fossil generating assets from its East and West regions of operations to Generation Bridge, an affiliate of ArcLight Capital Partners. 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. See Item 15 — Note 4, Acquisitions, Discontinued Operations and Dispositions , to the Consolidated Financial Statements for further discussion. Sale of Agua Caliente On February 3, 2021, the Company completed the sale of its 35% ownership in Agua Caliente to Clearway Energy, Inc. for $202 million. NRG recognized a gain on the sale of $17 million, including cash disposed of $7 million. Share Repurchases In December 2021, the Company's board of directors authorized the Company to repurchase $1.0 billion of its common stock. Through December 31, 2021, the Company completed $53 million of share repurchases at an average price of $40.22 per share, including $9 million of equivalent shares purchased in lieu of tax withholdings on equity compensation issuances. Through February 24, 2022, an additional $82 million of share repurchases were executed at an average price of $40.26 per share, including $6 million of equivalent shares purchased in lieu of tax withholdings on equity compensation issuances. See Item 15 - Note 16, Capital Structure , to the Consolidated Financial Statements for additional discussion. Renewable Power Purchase Agreements The Company's strategy is to procure mid to long-term generation through power purchase agreements. As of December 31, 2021, NRG has entered into PPAs totaling approximately 2.6 GW with third-party project developers and other counterparties. The average tenor of these agreements is twelve years. The Company expects to continue evaluating and executing similar agreements that support the needs of the business. The total GW entered into through PPAs may be impacted by contract terminations when they occur. Dividend Increase In the first quarter of 2021, NRG increased the annual dividend to $1.30 from $1.20 per share. In 2022, NRG further increased the annual dividend to $1.40 per share, representing an 8% increase from 2021. The Company expects to target an annual dividend growth rate of 7-9% per share in subsequent years. COVID-19 While the pandemic presented risks, as further described in Part II, Item 1A — Risk Factors of this Form 10-K, to the Company’s business, there was not a material adverse impact on the Company’s results of operations for the years ended December 31, 2021 and 2020. 48 Consolidated Results of Operations for the years ended December 31, 2021 and 2020 The following table provides selected financial information for the Company: Year Ended December 31, (In millions, except otherwise noted) 2021 2020 Change Operating Revenues Retail revenue $ 23,561 $ 7,460 $ 16,101 Energy revenue (a) 1,215 539 676 Capacity revenue (a) 775 680 95 Mark-to-market for economic hedging activities (164) 95 (259) Contract amortization (30) — (30) Other revenues (a)(b) 1,632 319 1,313 Total operating revenues 26,989 9,093 17,896 Operating Costs and Expenses Cost of fuel 1,844 851 (993) Purchased energy and other cost of sales (c) 19,766 4,069 (15,697) Mark-to-market for economic hedging activities (2,880) 214 3,094 Contract and emissions credit amortization (c) 43 5 (38) Operations and maintenance 1,370 1,129 (241) Other cost of operations 339 272 (67) Cost of operations (excluding depreciation and amortization shown below) 20,482 6,540 (13,942) Depreciation and amortization 785 435 (350) Impairment losses 544 75 (469) Selling, general and administrative costs 1,293 810 (483) Provision for credit losses 698 108 (590) Acquisition-related transaction and integration costs 93 23 (70) Total operating costs and expenses 23,895 7,991 (15,904) Gain on sale of assets 247 3 244 Operating Income 3,341 1,105 2,236 Other Income/(Expense) Equity in earnings of unconsolidated affiliates 17 17 — Impairment losses on investments — (18) 18 Other income, net 63 67 (4) Loss on debt extinguishment, net (77) (9) (68) Interest expense (485) (401) (84) Total other expenses (482) (344) (138) Income Before Income Taxes 2,859 761 2,098 Income tax expense 672 251 421 Net Income $ 2,187 $ 510 $ 1,677 Business Metrics Average natural gas price — Henry Hub ($/MMBtu) $ 3.84 $ 2.08 85 % (a) Includes realized gains and losses from financially settled transactions (b) Includes trading gains and losses and ancillary revenues (c) Includes amortization of SO 2 and NO x credits and excludes amortization of RGGI credits Gross Margin The Company calculates gross margin in order to evaluate operating performance as operating revenues less cost of fuel, purchased energy and other costs of sales, mark-to-market for economic hedging activities, contract and emission credit amortization and depreciation and amortization. 49 Economic Gross Margin In addition to gross margin, the Company evaluates its operating performance using the measure of economic gross margin, which is not a GAAP measure and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Economic gross margin should be viewed as a supplement to and not a substitute for the Company's presentation of gross margin, which is the most directly comparable GAAP measure. Economic gross margin is not intended to represent gross margin. The Company believes that economic gross margin is useful to investors as it is a key operational measure reviewed by the Company's chief operating decision maker. Economic gross margin is defined as the sum of retail revenue, energy revenue, capacity revenue and other revenue, less cost of fuels, purchased energy and other cost of sales. Economic gross margin does not include mark-to-market gains or losses on economic hedging activities, contract amortization, emission credit amortization, depreciation and amortization, operations and maintenance, or other costs of operations. The tables below present the composition and reconciliation of gross margin and economic gross margin for the years ended December 31, 2021 and 2020: Year Ended December 31, 2021 ($ in millions, except otherwise noted) Texas East West/Services/Other Corporate/Eliminations Total Retail revenue $ 8,410 $ 11,862 $ 3,290 $ (1) $ 23,561 Energy revenue 329 508 371 7 1,215 Capacity revenue — 718 57 — 775 Mark-to-market for economic hedging activities (3) (88) (86) 13 (164) Contract amortization — (26) (4) — (30) Other revenue 1,557 59 25 (9) 1,632 Operating revenue (a) 10,293 13,033 3,653 10 26,989 Cost of fuel (1,424) (196) (224) — (1,844) Purchased energy and other costs of sales (b)(c)(d) (6,108) (10,775) (2,882) (1) (19,766) Mark-to-market for economic hedging activities 988 1,803 102 (13) 2,880 Contract and emission credit amortization 2 (28) (17) — (43) Depreciation and amortization (331) (338) (88) (28) (785) Gross margin $ 3,420 $ 3,499 $ 544 $ (32) $ 7,431 Less: Mark-to-market for economic hedging activities, net 985 1,715 16 — 2,716 Less: Contract and emission credit amortization, net 2 (54) (21) — (73) Less: Depreciation and amortization (331) (338) (88) (28) (785) Economic gross margin $ 2,764 $ 2,176 $ 637 $ (4) $ 5,573 (a) Includes trading gains and losses and ancillary revenues (b) Includes capacity and emissions credits (c) Includes $2,648 million, $183 million and $1,033 million of TDSP expense in Texas, East, and West/Services/Other respectively (d) Excludes depreciation and amortization shown separately Business Metrics Texas East West/Services/Other Corporate/Eliminations Total Home electricity sales volume (GWh) 42,397 14,108 2,252 — 58,757 Business electricity sales volume (GWh) 34,367 53,204 10,625 — 98,196 Home natural gas retail sales volumes (MDth) — 74,920 97,272 — 172,192 Business natural gas retail sales volumes (MDth) — 1,595,533 109,021 — 1,704,554 Average retail Home customer count (in thousands) (a) 3,055 1,844 962 — 5,861 Ending retail Home customer count (in thousands) (a) 3,024 1,766 932 — 5,722 GWh sold 36,920 11,452 8,503 — 56,875 GWh generated (b) (c) 36,920 7,494 7,949 — 52,363 (a) Home customer count includes recurring residential customers, services customers and municipal aggregations (b) Includes owned and leased generation, excludes tolled generation and equity investments (c) Includes 1,054 GWh and 2,445 GWh in East and West/Services/Other respectively that was sold to Generation Bridge in December 2021 50 Year Ended December 31, 2020 ($ in millions, except otherwise noted) Texas East West/Services/Other (a) Corporate/Eliminations Total Retail revenue $ 6,061 $ 1,305 $ 96 $ (2) $ 7,460 Energy revenue 24 183 333 (1) 539 Capacity revenue — 620 61 (1) 680 Mark-to-market for economic hedging activities 2 88 (3) 8 95 Other revenue 222 62 43 (8) 319 Operating revenue 6,309 2,258 530 (4) 9,093 Cost of fuel (546) (151) (154) — (851) Purchased energy and other costs of sales (a)(b)(c) (3,110) (876) (89) 6 (4,069) Mark-to-market for economic hedging activities (211) 5 — (8) (214) Contract and emission credit amortization (5) — — — (5) Depreciation and amortization (227) (138) (36) (34) (435) Gross margin $ 2,210 $ 1,098 $ 251 $ (40) $ 3,519 Less: Mark-to-market for economic hedging activities, net (209) 93 (3) — (119) Less: Contract and emission credit amortization (5) — — — (5) Less: Depreciation and amortization (227) (138) (36) (34) (435) Economic gross margin $ 2,651 $ 1,143 $ 290 $ (6) $ 4,078 (a) Includes capacity and emissions credits (b) Includes $1,967 million and $10 million of electric TDSP charges for Texas and East, respectively (c) Excludes depreciation and amortization shown separately Business Metrics Texas East West/Services/Other Corporate/Eliminations Total Home electricity sales volume (GWh) 38,473 10,221 — — 48,694 Business electricity sales volume (GWh) 17,928 1,596 — — 19,524 Natural gas retail sales volumes (MDth) — 23,509 — — 23,509 Average retail Home customer count (in thousands) (a) 2,449 1,175 — — 3,624 Ending retail Home customer count (in thousands) (a) 2,451 1,136 — — 3,587 GWh sold 31,385 8,136 9,569 — 49,090 GWh generated (b)(c) 31,385 4,102 9,171 — 44,658 (a) Home customer count includes recurring residential customers and municipal aggregations (b) Includes owned and leased generation, excludes tolled generation and equity investments (c) Includes 1,192 GWh and 3,002 GWh in East and West/Services/Other respectively that was sold to Generation Bridge in December 2021 51 The table below represents the weather metrics for 2021 and 2020: Year ended December 31, Quarter ended December 31, Quarter ended September 30, Quarter ended June 30, Quarter ended March 31, Weather Metrics Texas East West/Services/Other (a) Texas East West/Services/Other (a) Texas East West/Services/Other (a) Texas East West/Services/Other (a) Texas East West/Services/Other (a) 2021 CDDs (b) 2,960 1,275 1,877 386 91 185 1,589 784 1,134 899 362 521 86 38 37 HDDs (b) 1,562 4,306 2,060 360 1,377 662 — 38 5 82 541 192 1,120 2,350 1,201 2020 CDDs 3,102 1,362 1,971 280 79 181 1,640 874 1,152 1,012 353 562 170 56 76 HDDs 1,501 4,268 1,939 634 1,517 763 6 72 4 70 634 178 791 2,045 994 10-year average CDDs 3,090 1,297 1,924 281 85 157 1,690 818 1,159 1,003 356 557 116 38 51 HDDs 1,691 4,558 2,044 693 1,584 774 2 56 10 59 521 193 937 2,397 1,067 (a) The West/Services/Other weather metrics are comprised of the average of the CDD and HDD regional results for the West - California and West - South Central regions (b) National Oceanic and Atmospheric Administration-Climate Prediction Center - A Cooling Degree Day, or CDD, represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. A Heating Degree Day, or HDD, represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period Winter Storm Uri During the year ended December 31, 2021, Winter Storm Uri's pre-tax financial impact to the Company was a loss of $380 million, which reflects the recovery of $689 million of cost of operations as a result of the expected proceeds from the Uplift Securitization. The following impacts are further discussed in the related sections below: (In millions) Gross margin - Texas $ 88 Gross margin - East 146 Gross margin - West/Services/Other 13 Total gross margin 247 Operations and maintenance expense (2) Selling, general and administrative costs (29) Provision for credit losses (596) Total impact to loss before income taxes $ (380) The Company continues to pursue additional mitigants including, but not limited to, customer bad debt mitigation, counterparty default recovery, and additional ERCOT default recovery. 52 Gross margin and economic gross margin Gross margin increased $3.9 billion and economic gross margin increased $1.5 billion, both of which include intercompany sales, during the year ended December 31, 2021, compared to the same period in 2020. The detail by segment is as follows: Texas (In millions) Higher gross margin due to Winter Storm Uri, primarily driven by hedging optimization, partially offset by the negative impact of an increase in unhedgeable ancillary and operating reserve demand curve, net of securitization proceeds of $689 million $ 88 The following explanations exclude the impact of Winter Storm Uri: Higher gross margin due to increased volumes from the acquisition of Direct Energy in January 2021 280 Higher gross margin due to market optimization activities 9 Lower gross margin due to a 22% increase in overall average costs to serve the retail load, driven primarily by increases in power, ancillary, fuel costs and the effect of the current year Limestone Unit 1 extended forced outage, totaling $349 million, partially offset by higher net revenue primarily driven by increased net revenue rates as a result of changes in customer term, product and mix of $2.50 per MWh, or $156 million (193) Lower net revenue due to a decrease in load of 834,000 MWhs from weather (72) Lower net revenue due to attrition and customer mix (5) Other 6 Increase in economic gross margin $ 113 Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges 1,194 Decrease in contract and emission credit amortization 7 Increase in depreciation and amortization (104) Increase in gross margin $ 1,210 East (In millions) Higher gross margin due to Winter Storm Uri, primarily driven by natural gas optimization during volatile pricing that occurred during the weather event $ 146 The following explanations exclude the impact of Winter Storm Uri: Higher gross margin due to increased volumes from the acquisition of Direct Energy in January 2021, including $503 million from natural gas activity and $436 million from power activity 939 Higher business demand response gross margin primarily from the early settlement of capacity obligations in 2021 compared to the same period in 2020 of $63 million and higher volumes sold in 2021 of $10 million 73 Higher gross margin due to a lower of cost or market adjustment on oil inventory in 2020 29 Lower gross margin from higher supply costs of $8.25 per MWh, or $78 million and lower volumes due to attrition, weather and customer mix of $45 million, partially offset by higher revenue of $3 per MWh, or $29 million (94) Lower gross margin due to a 20% decrease in average realized pricing primarily at Midwest Generation (39) Lower gross margin due to the sale of fossil generating assets to Generation Bridge in December 2021 (16) Lower gross margin from market optimization activities (5) Increase in economic gross margin $ 1,033 Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges 1,622 Increase in contract amortization (54) Increase in depreciation and amortization (200) Increase in gross margin $ 2,401 53 West/Services/Other (In millions) Higher gross margin due to Winter Storm Uri, driven by optimization during volatility in gas pricing $ 13 The following explanations exclude the impact of Winter Storm Uri: Higher gross margin due to the acquisition of Direct Energy in January 2021 425 Lower gross margin primarily at Cottonwood driven by an 83% increase in fuel cost, partially offset by a 41% increase in realized power prices. (31) Lower gross margin primarily due to prior year MISO uplift payments resulting from out-of-market dispatch during Hurricane Laura (29) Lower gross margin from generation outage insurance proceeds received in 2020 for forced outages in 2019, partially offset by Sunrise business interruption proceeds received in 2021 for forced outages in 2019 (22) Lower gross margin from market optimization activities (9) Lower gross margin due to the sale of fossil generating assets to Generation Bridge in December 2021 (7) Other 7 Increase in economic gross margin $ 347 Increase in mark-to-market for economic hedges primarily due to net unrealized gains/losses on open positions related to economic hedges 19 Increase in contract amortization (21) Increase in depreciation and amortization (52) Increase in gross margin $ 293 Mark-to-market for Economic Hedging Activities Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges. Total net mark-to-market results increased by $2.8 billion during the year ended December 31, 2021, compared to the same period in 2020. The breakdown of gains and losses included in operating revenues and operating costs and expenses by segment was as follows: Year Ended December 31, 2021 (In millions) Texas East West/Services/Other Eliminations Total Mark-to-market results in operating revenues Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges $ — $ (34) $ (4) $ (2) $ (40) Reversal of acquired (gain) positions related to economic hedges — (6) — — $ (6) Net unrealized (losses) on open positions related to economic hedges (3) (48) (82) 15 (118) Total mark-to-market (losses) in operating revenues $ (3) $ (88) $ (86) $ 13 $ (164) Mark-to-market results in operating costs and expenses Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges $ (3) $ — $ — $ 2 $ (1) Reversal of acquired loss/(gain) positions related to economic hedges 42 235 (15) — 262 Net unrealized gains on open positions related to economic hedges 949 1,568 117 (15) 2,619 Total mark-to-market gains in operating costs and expenses $ 988 $ 1,803 $ 102 $ (13) $ 2,880 54 Year Ended December 31, 2020 (In millions) Texas East West/Services/Other Eliminations Total Mark-to-market results in operating revenues Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges $ 1 $ 33 $ (7) $ 4 $ 31 Net unrealized gains on open positions related to economic hedges 1 55 4 4 64 Total mark-to-market gains/(losses) in operating revenues $ 2 $ 88 $ (3) $ 8 $ 95 Mark-to-market results in operating costs and expenses Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges $ (87) $ 5 $ — $ (4) $ (86) Reversal of acquired loss positions related to economic hedges. 2 2 — — 4 Net unrealized (losses) on open positions related to economic hedges (126) (2) — (4) (132) Total mark-to-market (losses)/gains in operating costs and expenses $ (211) $ 5 $ — $ (8) $ (214) Mark-to-market results consist of unrealized gains and losses on contracts that are yet to be settled. The settlement of these transactions is reflected in the same revenue or cost caption as the items being hedged. The reversals of acquired gain or loss positions were valued based upon the forward prices on the acquisition date. For the year ended December 31, 2021 the $164 million loss in operating revenues from economic hedge positions was driven primarily by a decrease in the value of open positions as a result of increases in East and West/Services/Other power prices, as well as the reversal of previously recognized unrealized gains on contracts that settled during the period. The $2.9 billion gain in operating costs and expenses from economic hedge positions was driven primarily by an increase in the value of open positions as a result of increases in natural gas and power prices across all segments as well as the reversal of acquired contracts that settled during the year. For the year ended December 31, 2020 the $95 million gain in operating revenues from economic hedge positions was driven primarily by an increase in the value of open positions as a result of decreases in New York capacity prices, as well as the reversal of previously recognized unrealized losses on contracts that settled during the period. The $214 million loss in operating costs and expenses from economic hedge positions was driven primarily by a decrease in the value of open positions as a result of decreases in ERCOT power prices and heat rate contraction, as well as the reversal of previously recognized unrealized gains on contracts that settled during the period. In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the years ended December 31, 2021 and 2020. The realized and unrealized financial and physical trading results are included in operating revenue. The Company's trading activities are subject to limits within the Company's Risk Management Policy. Year ended December 31, (In millions) 2021 2020 Trading gains/(losses) Realized $ 124 $ 41 Unrealized (32) (5) Total trading gains $ 92 $ 36 Operations and Maintenance Expenses Operations and maintenance expenses are comprised of the following: (In millions) Texas East West/Services/Other Corporate Eliminations Total Year Ended December 31, 2021 $ 703 $ 452 $ 218 $ 2 $ (5) $ 1,370 Year Ended December 31, 2020 651 371 104 9 (6) 1,129 55 Operations and maintenance expenses increased by $241 million for the year ended December 31, 2021 compared to the same period in 2020, due to the following: (In millions) Increase due to the acquisition of Direct Energy in January 2021 $ 257 Increase in major maintenance primarily due to the duration and scope of planned and forced outages in Texas during 2021 27 Increase in variable operation and maintenance expense at the PJM coal facilities associated with increased generation in 2021 23 Increase driven by higher maintenance resulting from the impacts of Winter Storm Uri 2 Decrease driven by lower retail operations costs (29) Decrease in lease expense primarily driven by the buyout of the Midwest Generation lease in 2020 (16) Decrease due to the sale of fossil generating assets to Generation Bridge in December 2021 (11) Decrease due to prior year suspended plant project and prior year reserves for obsolete inventory (9) Other (3) Increase in operations and maintenance expense $ 241 Other Cost of Operations Other Cost of operations are comprised of the following: (In millions) Texas East West/Services/Other Total Year Ended December 31, 2021 $ 194 $ 129 $ 16 $ 339 Year Ended December 31, 2020 163 91 18 272 Other cost of operations increased by $67 million for the year ended December 31, 2021 compared to the same period in 2020, due to the following: (In millions) Increase due to the acquisition of Direct Energy in January 2021 $ 83 Decrease primarily due to ARO expense in 2020 at Jewett Mine and Joliet as a result of regulatory requirements (15) Other (1) Increase in other cost of operations $ 67 Depreciation and Amortization Depreciation and amortization expenses are comprised of the following: (In millions) Texas East West/Services/Other Corporate Total Year Ended December 31, 2021 $ 331 $ 338 $ 88 $ 28 $ 785 Year Ended December 31, 2020 227 138 36 34 435 Depreciation and amortization expense increased by $350 million for the year ended December 31, 2021 compared to the same period in 2020, primarily due to amortization of acquired intangibles in connection with the acquisition of Direct Energy in January 2021. Impairment Losses During the year ended December 31, 2021, the Company recorded impairment losses of $544 million, of which $306 million was recorded in the second quarter related to the decline in capacity prices and the planned retirement of a significant portion of the PJM coal fleet, $213 million in the fourth quarter 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, and $25 million related to various other power plants. During the year ended December 31, 2020, the Company recorded impairment losses of $75 million primarily related to the Cottonwood facility and the Home Solar business. Refer to Item 15 — Note 11, Asset Impairments , to the Consolidated Financial Statements for further discussion . 56 Selling, General and Administrative Costs Selling, general and administrative costs are comprised of the following: (In millions) Texas East West/Services/Other Corporate Total Year Ended December 31, 2021 $ 574 $ 472 $ 198 $ 49 $ 1,293 Year Ended December 31, 2020 467 260 56 27 810 Selling, general and administrative costs increased by $483 million for the year ended December 31, 2021 compared to the same period in 2020, due to the following: (In millions) Increase due to the acquisition of Direct Energy in January 2021 $ 460 Increase due to Winter Storm Uri, including charitable giving, legal and other costs of $20 million and ERCOT default charges of $9 million 29 Increase due to higher consulting, service and insurance costs 26 Decrease due to lower employee costs (23) Decrease due to the favorable resolution of a legal matter (15) Other 6 Increase in selling, general and administrative costs $ 483 Provision for Credit Losses Provision for credit losses are comprised of the following: (In millions) Texas East West/Services/Other Total Year Ended December 31, 2021 $ 678 $ 8 $ 12 $ 698 Year Ended December 31, 2020 94 14 — 108 Provision for credit losses increased by $590 million for the year ended December 31, 2021, compared to the same period in 2020, due to the following: (In millions) Increase due to Winter Storm Uri, including: Increase of $403 million related to bilateral financial hedging risk Increase of $126 million related to counterparty credit risk Increase of $67 million related to ERCOT default shortfall payments $ 596 Decrease due to improved collections in the legacy brands, partially offset by the acquisition and integration of Direct Energy in January 2021 (6) Increase in provision for credit losses $ 590 Acquisition-Related Transaction and Integration Costs Acquisition-related transaction and integration costs increased by $70 million when compared to the same period in 2020. Acquisition-related transaction costs increased by $8 million, primarily related to the Direct Energy acquisition. Integration costs increased by $62 million, primarily related to employee costs, software costs and consulting services for the Direct Energy acquisition. Gain on Sale of Assets The gain on sale of assets of $247 million was recorded for the year ended December 31, 2021 includes a $210 million gain on the sale of 4,850 MW of fossil generating assets in December 2021, a $20 million gain on the sale of a deactivated site in November 2021, and a $17 million due to the sale of Agua Caliente in February 2021. The gain on the sale of assets of $3 million for the year ended December 31, 2020 was related to the sale of land and investments in January 2020, partially offset by the disposition of the Home Solar business. Impairment Losses on Investments During the year ended December 31, 2020, the Company recorded other-than-temporary impairment losses on the Company's investment in Petra Nova Parish Holdings of $18 million, as further described in Item 15 — Note 11, Asset Impairments , to the Consolidated Financial Statements. 57 Loss on Debt Extinguishment A loss on debt extinguishment of $77 million was recorded for the year ended December 31, 2021, driven by the redemption of senior notes as further discussed in Item 15 — Note 13, Long-term Debt and Finance Leases, to the Consolidated Financial Statements . A loss on debt extinguishment of $9 million was recorded for the year ended December 31, 2020, driven by the debt extinguished in connection with the sale of Home Solar and the redemptions of the Indian River and Dunkirk bonds. Interest Expense Interest expense increased by $84 million for the year ended December 31, 2021 compared to the same period in 2020, primarily due to financings entered into in connection with the Direct Energy acquisition. Income Tax Expense For the year ended December 31, 2021, NRG recorded income tax expense of $672 million on pre-tax income of $2.9 billion. For the same period in 2020, NRG recorded an income tax expense of $251 million on pre-tax income of $761 million. The effective tax rate was 23.5% and 33.0% for the years ended December 31, 2021 and 2020, respectively. For the year ended December 31, 2021, NRG's overall effective 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. Year Ended December 31, (In millions, except effective income tax rate) 2021 2020 Income from continuing operations before income taxes $ 2,859 $ 761 Tax at federal statutory tax rate 600 160 Foreign rate differential (3) — State taxes 111 18 Deferred impact of state tax rate changes (10) 2 Changes in valuation allowance (29) 24 Permanent differences 8 8 Return to provision adjustments 5 36 Recognition of uncertain tax benefits (10) 3 Income tax expense $ 672 $ 251 Effective income tax rate 23.5 % 33.0 % The effective income tax rate may vary from period to period depending on, among other factors, the geographic and business mix of earnings and losses and changes in valuation allowances in accordance with ASC 740, Income Taxes, or ASC 740. These factors and others, including the Company's history of pre-tax earnings and losses, are taken into account in assessing the ability to realize deferred tax assets. Liquidity and Capital Resources Liquidity Position As of December 31, 2021 and 2020, NRG's liquidity, excluding collateral funds deposited by counterparties, was approximately $2.7 billion and $7.0 billion, respectively, comprised of the following: As of December 31, (In millions) 2021 2020 Cash and cash equivalents: $ 250 $ 3,905 Restricted cash - operating 4 3 Restricted cash - reserves (a) 11 3 Total 265 3,911 Total availability under Revolving Credit Facility and collective collateral facilities (b) 2,421 3,129 Total liquidity, excluding collateral funds deposited by counterparties $ 2,686 $ 7,040 (a) Includes reserves primarily for debt service, performance obligations and capital expenditures (b) Total capacity of Revolving Credit Facility and collective collateral facilities was $5.9 billion and $4.0 billion as of December 31, 2021 and December 31, 2020, respectively 58 As of December 31, 2021, total liquidity, excluding collateral funds deposited by counterparties, decreased by $4.4 billion. The decrease was primarily driven by the closing of the Direct Energy acquisition and the impact of Winter Storm Uri. Changes in cash and cash equivalent balances are further discussed under the heading Cash Flow Discussion . Cash and cash equivalents at December 31, 2021 were predominantly held in money market funds invested in treasury securities, treasury repurchase agreements or government agency debt. Management believes that the Company's liquidity position and cash flows from operations will be adequate to finance operating and maintenance capital expenditures, to fund dividends to NRG's common stockholders, and to fund other liquidity commitments. Management continues to regularly monitor the Company's ability to finance the needs of its operating, financing and investing activity within the dictates of prudent balance sheet management. Credit Ratings On March 17, 2021, following Winter Storm Uri, Standard & Poor's placed NRG's issuer credit rating of BB+ on CreditWatch with negative implications. On May 12, 2021, Standard & Poor's affirmed NRG's issuer credit rating of BB+ with a stable outlook. On March 19, 2021, Moody's changed NRG's rating outlook from positive to stable. At the same time, Moody's affirmed NRG's corporate family rating of Ba1. The following table summarizes the Company's current credit ratings: S&P Moody's NRG Energy, Inc. BB+ Stable Ba1 Stable 3.75% Senior Secured Notes, due 2024 BBB- Baa3 2.00% Senior Secured Notes, due 2025 BBB- Baa3 2.45% Senior Secured Notes, due 2027 BBB- Baa3 6.625% Senior Notes, due 2027 BB+ Ba2 5.75% Senior Notes, due 2028 BB+ Ba2 3.375% Senior Notes, due 2029 BB+ Ba2 4.45% Senior Secured Notes, due 2029 BBB- Baa3 5.25% Senior Notes, due 2029 BB+ Ba2 3.625% Senior Notes, due 2031 BB+ Ba2 3.875% Senior Notes, due 2032 BB+ Ba2 Revolving Credit Facility, due 2024 BBB- Baa3 Liquidity The principal sources of liquidity for NRG's operating and capital expenditures are expected to be derived from cash on hand, cash flows from operations and financing arrangements. As described in Item 15 — Note 13, Long-term Debt and Finance Leases, to the Consolidated Financial Statements, the Company's financing arrangements consist mainly of the Senior Notes, Convertible Senior Notes, Senior Secured First Lien Notes, Revolving Credit Facility, and tax-exempt bonds. The Company's requirements for liquidity and capital resources, other than for operating its facilities, can generally be categorized by the following: (i) market operations activities; (ii) debt service obligations, as described more fully in Item 15 — Note 13, Long-term Debt and Finance Leases , to the Consolidated Financial Statements; (iii) capital expenditures, including maintenance, repowering, development, and environmental; and (iv) allocations in connection with acquisition opportunities, debt repayments, share repurchases and dividend payments to stockholders, as described in Item 15 — Note 16, Capital Structure , to the Consolidated Financial Statements. Direct Energy Acquisition 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. The Company paid an aggregate purchase price of $3.625 billion in cash, subject to a purchase price adjustment of $77 million. 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 to Centrica in December 2021. 59 Collateral Facility Increases The following table presents increases to the Company's liquidity and collateral facilities in connection with the Direct Energy acquisition: (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 Revolving accounts receivable financing facility 750 Repurchase facility 75 Bilateral letter of credit facilities 475 Total Increases to Liquidity and Collateral Facilities $ 3,399 Planned Debt Reduction In light of the impact of Winter Storm Uri, the Company's deleveraging program will extend to 2023. The Company remains committed to maintaining a strong balance sheet and continues to work to achieve investment grade credit metrics. Issuance of 2032 Senior Notes On August 23, 2021, the Company issued $1.1 billion of aggregate principal amount at par of 3.875% senior notes due 2032 (the "2032 Senior Notes"). The 2032 Senior Notes are senior unsecured obligations of NRG and are guaranteed by certain of its subsidiaries. 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. Senior Note Redemptions During the year ended December 31, 2021, the Company redeemed $1.9 billion in aggregate principal of its Senior Notes for $1.9 billion using the proceeds of the 2032 Senior Notes and cash on hand. In connection with the redemptions, a $77 million loss on debt extinguishment was recorded. Receivables Facility On July 26, 2021, NRG Receivables LLC, a wholly-owned indirect subsidiary of the Company, renewed its existing accounts receivable securitized borrowings facility (the "Receivables Facility") to, among others, (i) increase the facility size to $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. 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 July 26, 2021, the Company renewed its existing uncommitted repurchase facility ("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. Sale of 4.8 GW of Fossil Generation 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. At Closing, NRG received $623 million of net proceeds, after working capital and other adjustments, including a deduction for cash flows generated of approximately $11 million per month from the beginning of the year until the closing of the transaction, in lieu of 60 cash flows generated during the year. 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. 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. CARES Act On March 27, 2020, the U.S. government enacted the CARES Act, which provides, among other things: (i) the option to defer payments of certain 2019 employer payroll taxes incurred after the date of enactment; and (ii) allows NOLs from tax years 2018, 2019, and 2020 to be carried back five years. The total benefit to the Company due to the CARES Act was $35 million. Of this amount, $13 million was paid to social security in 2021 and $13 million will be payable in 2022. Pension Plan Contribution The American Rescue Plan Act ("ARPA") was enacted on March 11, 2021 to provide economic relief related to the COVID-19 pandemic. ARPA provided pension funding relief for single employer plans, among other provisions. As a result, NRG reduced its 2021 planned cash contribution by approximately $23 million. Pension and Other postretirement benefits minimum funding requirements As of December 31, 2021, the Company does not have estimated minimum pension contributions required under the Pension Protection Act of 2006 for the next 5 years. As of December 31, 2021, the Company’s estimated Other postretirement benefits minimum funding requirements for the next 5 years were $33 million, of which $7 million are required to be made within the next 12 months. These amounts represent estimates based on assumptions that are subject to change. For further discussion, see Item 15 — Note 15, Benefit Plans and Other Postretirement Benefits , to the Consolidated Financial Statements. Debt Service Obligations Principal payments on debt and finance leases as of December 31, 2021 are due in the following periods: (In millions) Description 2022 2023 2024 2025 2026 Thereafter Total Recourse Debt: Senior notes, due 2027 $ — $ — $ — $ — $ — $ 375 $ 375 Senior notes, due 2028 — — — — — 821 821 Senior notes, due 2029 — — — — — 733 733 Senior notes, due 2029 — — — — — 500 500 Senior notes, due 2031 — — — — — 1,030 1,030 Senior Notes, due 2032 — — — — — 1,100 1,100 Convertible Senior Notes, due 2048 — — — — — 575 575 Senior Secured First Lien Notes, due 2024 — — 600 — — — 600 Senior Secured First Lien Notes, due 2025 — — — 500 — — 500 Senior Secured First Lien Notes, due 2027 — — — — — 900 900 Senior Secured First Lien Notes, due 2029 — — — — — 500 500 Tax-exempt bonds — — — — — 466 466 Subtotal Recourse Debt — — 600 500 — 7,000 8,100 Finance Leases: Finance leases 4 3 3 2 — 1 13 Subtotal Finance Leases 4 3 3 2 — 1 13 Total Debt and Finance Leases $ 4 $ 3 $ 603 $ 502 $ — $ 7,001 $ 8,113 Interest Payments $ 385 $ 383 $ 363 $ 352 $ 334 $ 1,224 $ 3,041 For further discussion, see Item 15 — Note 13, Long-term Debt and Finance Leases . 61 Market Operations The Company's market operations activities require a significant amount of liquidity and capital resources. These liquidity requirements are primarily driven by: (i) margin and collateral posted with counterparties; (ii) margin and collateral required to participate in physical markets and commodity exchanges; (iii) timing of disbursements and receipts (e.g. buying fuel before receiving energy revenues); and (iv) initial collateral for large structured transactions. As of December 31, 2021, market operations had total cash collateral outstanding of $291 million and $3.5 billion outstanding in letters of credit to third parties primarily to support its market activities. As of December 31, 2021, total funds deposited by counterparties were $845 million in cash and $429 million of letters of credit. The Company 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 had minimum payment obligations under such outstanding agreements of $378 million, with $122 million payable within the next 12 months. Additionally, the Company 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. As of December 31, 2021, the Company had minimum purchased energy commitments of $5.0 billion, with $1.6 billion payable within the next 12 months. For further discussion, see Item 15 — Note 23, Commitments and Contingencies . Future liquidity requirements may change based on the Company's hedging activities and structures, fuel purchases, and future market conditions, including forward prices for energy and fuel and market volatility. In addition, liquidity requirements are dependent on the Company's credit ratings and general perception of its creditworthiness. First Lien Structure NRG has granted first liens to certain counterparties on a substantial portion of the Company's assets, subject to various exclusions including NRG's assets that have project-level financing and the assets of certain non-guarantor subsidiaries, to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or MWh equivalents. The first lien program does not limit the volume that can be hedged or the value of underlying out-of-the-money positions. The first lien program also does not require NRG to post collateral above any threshold amount of exposure. The first lien structure is not subject to unwind or termination upon a ratings downgrade of a counterparty and has no stated maturity date. The Company's first lien counterparties may have a claim on its assets to the extent market prices exceed the hedged prices. As of December 31, 2021, all hedges under the first liens were out-of-the-money on a counterparty aggregate basis. The following table summarizes the amount of MW hedged against the Company's coal and nuclear assets and as a percentage relative to the Company's coal and nuclear capacity under the first lien structure as of December 31, 2021: Equivalent Net Sales Secured by First Lien Structure (a) 2022 2023 In MW 653 738 As a percentage of total net coal and nuclear capacity (b) 15% 17% (a) Equivalent Net Sales include natural gas swaps converted using a weighted average heat rate by region (b) Net coal and nuclear capacity represents 80% of the Company's total coal and nuclear assets eligible under the first lien, which excludes coal assets acquired in the Midwest Generation acquisition Capital Expenditures The following table summarizes the Company's capital expenditures for maintenance, environmental, and growth investments for the year ended December 31, 2021: (In millions) Maintenance Environmental Growth Investments (a) Total Texas $ (127) $ (1) $ (25) $ (153) East (23) (1) (26) (50) West/Services/Other (21) — — (21) Corporate (4) — (41) (45) Total cash capital expenditures for 2021 (175) (2) (92) (269) Investments — — (47) (47) Total capital expenditures and investments $ (175) $ (2) $ (139) $ (316) (a) Includes other investments, acquisitions, digital NRG and integration projects 62 Growth investments in East for the year ended December 31, 2021 include the Astoria generating facility, for which the Company has proposed to replace existing units with a single, new state-of-the-art Simple Cycle Combustion Turbine having a total generating capacity of 437 MW. On October 27, 2021, the NYSDEC Staff denied the Company's application for an air permit. On November 26, 2021, Astoria Gas Turbine Power LLC filed a Request for Adjudicatory Hearing on the NYSDEC's denial. To date, the Company has spent approximately $42 million on the Astoria project. Additionally, included in Investments are expenditures for Encina site improvements classified as ARO payments. Demolition of Encina is underway and is expected to be completed in the first half of 2022. The Company expects to begin marketing the site in 2022. Environmental Capital Expenditures Estimate NRG estimates that environmental capital expenditures from 2022 through 2026 required to comply with environmental laws will be approximately $56 million. The largest component is the cost of complying with ELG at our coal units in Texas. The table below summarizes the status of NRG's coal fleet with respect to air quality controls. NRG uses an integrated approach to fuels, controls and emissions markets to meet environmental requirements. SO 2 NO x Mercury Particulate Units State Control Equipment Install Date Control Equipment Install Date Control Equipment Install Date Control Equipment Install Date Indian River 4 DE CDS 2011 LNBOFA/SCR 1999/2011 ACI/CDS/FF 2008/2011 ESP/FF 1980/2011 Limestone 1-2 TX FGD 1985-86 LNBOFA 2002/2003 ACI 2015 ESP 1985-1986 Powerton 5 IL DSI 2016 OFA/SNCR 2003/2012 ACI 2009 ESP/upgrade 1973/2016 Powerton 6 IL DSI 2014 OFA/SNCR 2002/2012 ACI 2009 ESP/upgrade 1976/2014 W.A. Parish 5, 6, 7 TX FF co-benefit 1988 SCR 2004 ACI 2015 FF 1988 W.A. Parish 8 TX FGD 1982 SCR 2004 ACI 2015 FF 1988 Waukegan 7 IL DSI 2014 LNBOFA 2002 ACI 2008 ESP/upgrade 1958/2002, 2014 Waukegan 8 IL DSI 2015 LNBOFA 1999 ACI 2008 ESP/upgrade 1962/1999, 2015 Will County 4 IL DSI 2017 LNBOFA 1999,2000 ACI 2009 ESP/upgrade 1963,72/ 2000 ACI - Activated Carbon Injection CDS - Circulating Dry Scrubber DSI - Dry Sorbent Injection with Trona ESP - Electrostatic Precipitator FGD - Flue Gas Desulfurization (wet) FF- Fabric Filter LNBOFA - Low NO x Burner with Overfire Air OFA - Overfire Air SCR - Selective Catalytic Reduction SNCR - Selective Non-Catalytic Reduction The following table summarizes the estimated environmental capital expenditures by year: (In millions) Total 2022 $ 8 2023 1 2024 22 2025 22 2026 3 Total $ 56 63 Share Repurchases In December 2021, the Company's board of directors authorized the Company to repurchase $1.0 billion of its common stock. Through December 31, 2021, the Company completed $53 million of share repurchases at an average price of $40.22 per share, including $9 million of equivalent shares purchased in lieu of tax withholdings on equity compensation issuances. Through February 24, 2022, an additional $82 million of share repurchases were executed at an average price of $40.26 per share, including $6 million of equivalent shares purchased in lieu of tax withholdings on equity compensation issuances. See Item 15 - Note 16, Capital Structure , to the Consolidated Financial Statements for additional discussion. Dividend Increase In the first quarter of 2021, NRG increased the annual dividend to $1.30 from $1.20 per share. The Company returned $320 million of capital to shareholders in the year ended 2021 through a $1.30 dividend per common share. In 2022, NRG further increased the annual dividend to $1.40 per share, representing an 8% increase from 2021. The Company expects to target an annual dividend growth rate of 7-9% per share in subsequent years. On January 21, 2022, NRG declared a quarterly dividend on the Company's common stock of $0.35 per share, or $1.40 per share on an annualized basis, payable on February 15, 2022, to stockholders of record as of February 1, 2022. The Company's common stock dividends are subject to available capital, market conditions, and compliance with associated laws and regulations. Additional Material Cash Requirements Not Discussed Above Operating leases — The Company leases generating facilities, land, office and equipment, railcars, fleet vehicles and storefront space at retail stores. As of December 31, 2021, the Company had lease payment obligations of $372 million, of which $96 million is payable within the next 12 months. For further discussion, see Item 15 — Note 10, Leases. Other liabilities — Other liabilities includes water right agreements, service and maintenance agreements, stadium naming rights, stadium sponsorships, LTSA commitments and other contractual obligations. As of December 31, 2021, the Company had total of $210 million under such commitments, of which $41 million are payable within the next 12 months. Contingent obligations for guarantees — NRG and its subsidiaries enter into various contracts that include indemnifications and guarantee provisions as a routine part of the Company’s business activities. For further discussion, see Item 15 —Note 27, Guarantees. Obligations Arising Out of a Variable Interest in an Unconsolidated Entity Variable interest in Equity investments — As of December 31, 2021, NRG has several investments with an ownership interest percentage of 50% or less in energy and energy-related entities that are accounted for under the equity method of accounting. Ivanpah is considered a variable interest entity for which NRG is not the primary beneficiary. NRG's pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $535 million as of December 31, 2021. This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to NRG. See also Item 15 — Note 17, Investments Accounted for by the Equity Method and Variable Interest Entities, to the Consolidated Financial Statements for additional discussion. Cash Flow Discussion 2021 compared to 2020 The following table reflects the changes in cash flows for the comparative years: Year ended December 31, (In millions) 2021 2020 Change Net cash provided by operating activities $ 493 $ 1,837 $ (1,344) Net cash used by investing activities (3,039) (494) (2,545) Net cash (used)/provided by financing activities (272) 2,204 (2,476) 64 Net Cash (Used)/Provided By Operating Activities Changes to net cash (used)/provided by operating activities were driven by: (In millions) Decrease in working capital related to accounts receivable primarily driven by milder weather in 2020, the impact of Winter Storm Uri and additional early settlement of capacity obligations in 2021 $ (1,232) Decrease in operating income adjusted for other non-cash items (1,235) Changes in cash collateral in support of risk management activities due to change in commodity prices 670 Increase in working capital related to accounts payable primarily driven by increases in gas purchases and bilateral physical settlements driven by price and volume in ERCOT 532 Decrease in working capital related to inventory due to replenishing natural gas inventory at significantly higher prices (88) Other changes in working capital 9 $ (1,344) Net Cash (Used)/Provided By Investing Activities Changes to net cash (used)/provided by investing activities were driven by: (In millions) Increase in cash paid for acquisitions of assets primarily for Direct Energy $ (3,275) Increase in proceeds from sale of assets primarily due to the fossil generating assets and Agua Caliente 749 Decrease in capital expenditures (39) Increase in proceeds from sales of investments in nuclear decommissioning trust fund securities, net of purchases 12 Increase in sales of emissions allowances, net of purchases 10 Other (2) $ (2,545) Net Cash (Used)/Provided By Financing Activities Changes in net cash (used)/provided by financing activities were driven by: (In millions) Decrease in proceeds from issuance of long-term debt $ (2,134) Increase in payments of long-term debt (1,526) Increase in net receipts from settlement of acquired derivatives 945 Decrease in payments for share repurchase activity 181 Increase in proceeds from Revolving Credit Facility and Receivables Securitization Facilities 83 Increase in payments of dividends to common stockholders (24) Other (1) $ (2,476) NOLs, Deferred Tax Assets and Uncertain Tax Position Implications For the year ended December 31, 2021, the Company had domestic pre-tax book income of $2.8 billion and foreign pre-tax book income of $100 million. For the year ended December 31, 2021, the Company utilized U.S. federal NOLs of $1.6 billion due to current year taxable income. As of December 31, 2021, the Company has cumulative U.S. federal NOL carryforwards of $8.4 billion, of which $11 million were generated prior to Tax Cuts and Jobs Act and will begin expiring in 2031 and cumulative state NOL carryforwards of $5.2 billion for financial statement purposes. NRG also has cumulative foreign NOL carryforwards of $383 million, which do not have an expiration date. In addition to the above NOLs, NRG has a $20 million indefinite carryforward for interest deductions, as well as $384 million of tax credits to be utilized in future years. As a result of the Company's tax position, including the utilization of federal and state NOLs, and based on current forecasts, the Company anticipates income tax payments, due to federal, state and foreign jurisdictions, of up to $58 million in 2022. 65 The Company has $13 million of tax effected uncertain federal and state tax benefits for which the Company has recorded a non-current tax liability of $14 million (including accrued interest) until such final resolution with the related taxing authority. The Company is no longer subject to U.S. federal income tax examinations for years prior to 2018. With few exceptions, state and Canadian income tax examinations are no longer open for years before 2013. Guarantor Financial Information As of December 31, 2021, the Company's outstanding registered senior notes consisted of $375 million of the 2027 Senior Notes and $821 million of the 2028 Senior Notes, as shown in Note 13, Long-term Debt and Finance Leases . These Senior Notes are guaranteed by certain of NRG's current and future 100% owned domestic subsidiaries, or guarantor subsidiaries (the “Guarantors”). See Exhibit 22.1 for a listing of the Guarantors. These guarantees are both joint and several. NRG conducts much of its business through and derives much of its income from its subsidiaries. Therefore, the Company's ability to make required payments with respect to its indebtedness and other obligations depends on the financial results and condition of its subsidiaries and NRG's ability to receive funds from its subsidiaries. There are no restrictions on the ability of any of the Guarantors to transfer funds to NRG. Other subsidiaries of the Company do not guarantee the registered debt securities of either NRG Energy, Inc. or the Guarantors (such subsidiaries are referred to as the “Non-Guarantors”). The Non-Guarantors include all of NRG's foreign subsidiaries and certain domestic subsidiaries. The tables below present summarized financial information of NRG Energy, Inc. and the Guarantors in accordance with Rule 3-10 under the SEC's Regulation S-X. The financial information may not necessarily be indicative of results of operations or financial position of NRG Energy, Inc. and the Guarantors in accordance with U.S. GAAP. The following table presents the summarized statement of operations: (In millions) For the Year Ended December 31, 2021 (a) Operating revenues $ 23,679 Operating income 3,753 Total other expense (467) Income from continuing operations before income taxes 3,286 Net Income 2,633 (a) Intercompany transactions with Non-Guarantors include operating revenue of $42 million, cost of operations of $(235) million and selling, general and administrative of $108 million The following table presents the summarized balance sheet information: (In millions) December 31, 2021 Current assets (a) $ 9,399 Property, plant and equipment, net 1,324 Non-current assets 11,569 Current liabilities (a) 7,590 Non-current liabilities 11,195 (a) Includes intercompany receivables of $86 million and intercompany payables of $50 million due from Non-Guarantors Fair Value of Derivative Instruments NRG may enter into power purchase and sales contracts, fuel purchase contracts and other energy-related financial instruments to mitigate variability in earnings due to fluctuations in spot market prices and to hedge fuel requirements at power plants or retail load obligations. In addition, in order to mitigate foreign exchange rate risk primarily associated with the purchase of USD denominated natural gas for the Company's Canadian business, NRG enters into foreign exchange contract agreements. 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. 66 The tables below disclose the activities that include both exchange and non-exchange traded contracts accounted for at fair value in accordance with ASC 820, Fair Value Measurements and Disclosures , or ASC 820. Specifically, these tables disaggregate realized and unrealized changes in fair value; disaggregate estimated fair values at December 31, 2021, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at December 31, 2021. For a full discussion of the Company's valuation methodology of its contracts, see Derivative Fair Value Measurements in Item 15 — Note 5, Fair Value of Financial Instruments , to the Consolidated Financial Statements. Derivative Activity (Losses)/Gains (In millions) Fair value of contracts as of December 31, 2020 $ (63) Contracts realized or otherwise settled during the period 190 Contracts acquired from Direct Energy (283) Changes in fair value 2,497 Fair value of contracts as of December 31, 2021 $ 2,341 Fair Value of Contracts as of December 31, 2021 (In millions) Maturity Fair value hierarchy Gains 1 Year or Less Greater Than 1 Year to 3 Years Greater Than 3 Years to 5 Years Greater Than 5 Years Total Fair Value Level 1 $ 134 $ 192 $ 23 $ 6 $ 355 Level 2 941 645 82 25 1,693 Level 3 151 82 16 44 293 Total $ 1,226 $ 919 $ 121 $ 75 $ 2,341 The Company has elected to disclose derivative assets and liabilities on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. Also, collateral received or posted on the Company's derivative assets or liabilities are recorded on a separate line item on the balance sheet. Consequently, the magnitude of the changes in individual current and non-current derivative assets or liabilities is higher than the underlying credit and market risk of the Company's portfolio. As discussed in Item 7A — Quantitative and Qualitative Disclosures About Market Risk, Commodity Price Risk , NRG measures the sensitivity of the Company's portfolio to potential changes in market prices using VaR, a statistical model which attempts to predict risk of loss based on market price and volatility. NRG's risk management policy places a limit on one-day holding period VaR, which limits the Company's net open position. As the Company's trade-by-trade derivative accounting results in a gross-up of the Company's derivative assets and liabilities, the net derivative assets and liability position is a better indicator of NRG's hedging activity. As of December 31, 2021, NRG's net derivative asset was $2.3 billion, an increase to total fair value of $2.4 billion as compared to December 31, 2020. This increase was primarily driven by roll-off trades that settled during the period, as well as gains in fair value. Based on a sensitivity analysis using simplified assumptions, the impact of a $0.50 per MMBtu increase in natural gas prices across the term of the derivative contracts would result in an increase of approximately $1.3 billion in the net value of derivatives as of December 31, 2021. The impact of a $0.50 per MMBtu decrease in natural gas prices across the term of the derivative contracts would result in a decrease of approximately $1.4 billion in the net value of derivatives as of December 31, 2021. Critical Accounting Estimates The Company's discussion and analysis of the financial condition and results of operations are based upon the Consolidated Financial Statements, which have been prepared in accordance with GAAP. The preparation of these financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance as well as the use of estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities. The application of appropriate technical accounting rules and guidance involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges, and the fair value of certain assets and liabilities. These judgments, in and of themselves, could materially affect the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment may also have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the accounting guidance has not changed. 67 NRG evaluates these estimates, on an ongoing basis, utilizing historic experience, consultation with experts and other methods the Company considers reasonable. In any event, actual results may differ substantially from the Company's estimates. Any effects on the Company's business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the information that gives rise to the revision becomes known. The Company identifies its most critical accounting estimates as those that are the most pervasive and important to the portrayal of the Company's financial position and results of operations, and require the most difficult, subjective, and/or complex judgments by management about matters that are inherently uncertain. Such accounting estimates include: Accounting Estimate Judgments/Uncertainties Affecting Application Derivative Instruments Assumptions used in valuation techniques Assumptions used in forecasting generation and retail load Market maturity and economic conditions Contract interpretation Market conditions in the energy industry, especially the effects of price volatility on contractual commitments Income Taxes and Valuation Allowance for Deferred Tax Assets Ability to be sustained upon audit examination of taxing authorities Interpret existing tax statute and regulations upon application to transactions Ability to utilize tax benefits through carry backs to prior periods and carry forwards to future periods Evaluation of Assets for Impairment and Other-Than-Temporary Decline in Value Recoverability of investment through future operations Regulatory and political environments and requirements Estimated useful lives of assets Environmental obligations and operational limitations Estimates of future cash flows Estimates of fair value Judgment about impairment triggering events Goodwill and Other Intangible Assets Estimated useful lives for finite-lived intangible assets Judgment about impairment triggering events Estimates of reporting unit's fair value Fair value estimate of intangible assets acquired in business combinations Business Combinations Fair value of assets acquired and liabilities assumed in business combinations Estimated future cash flow Estimated useful lives of assets Contingencies Estimated financial impact of event(s) Judgment about likelihood of event(s) occurring Regulatory and political environments and requirements Derivative Instruments The Company follows the guidance of ASC 815, Derivatives and Hedging, or ASC 815, to account for derivative instruments. ASC 815 requires the Company to mark-to-market all derivative instruments on the balance sheet and recognize fair value change in earnings, unless they qualify for the NPNS exception. ASC 815 applies to NRG's energy related commodity contracts, interest rate swaps and foreign exchange contracts. For purposes of measuring the fair value of derivative instruments, the Company uses quoted exchange prices and broker quotes. When external prices are not available, NRG uses internal models to determine the fair value. These internal models include assumptions of the future prices of energy commodities based on the specific market in which the energy commodity is being purchased or sold, using externally available forward market pricing curves for all periods possible under the pricing model. These estimations are considered to be critical accounting estimates. 68 During the fourth quarter of 2020, the Company 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. In order to qualify the derivative instruments for hedged transactions prior to termination, NRG estimated the forecasted borrowings for interest rate swaps occurring within a specified time period. In order to mitigate foreign exchange risk primarily associated with the purchase of USD denominated natural gas for the Company's Canadian business, the Company enters into foreign exchange contract agreements. Certain derivative instruments that meet the criteria for derivative accounting treatment also qualify for a scope exception to derivative accounting, as they are considered to be NPNS. The availability of this exception is based upon the assumption that the Company has the ability and it is probable to deliver or take delivery of the underlying item. These assumptions are based on expected load requirements, internal forecasts of sales and generation and historical physical delivery on contracts. Derivatives that are considered to be NPNS are exempt from derivative accounting treatment and are accounted for under accrual accounting. If it is determined that a transaction designated as NPNS no longer meets the scope exception due to changes in estimates, the related contract would be recorded on the balance sheet at fair value combined with the immediate recognition through earnings. Income Taxes and Valuation Allowance for Deferred Tax Assets As of December 31, 2021, NRG’s deferred tax assets were primarily the result of U.S. federal and state NOLs, the difference between book and tax basis in property, plant, and equipment, and tax credit carryforwards. The realization of deferred tax assets is dependent upon the Company's ability to generate sufficient future taxable income during the periods in which those temporary differences become deductible, prior to the expiration of the tax attributes. The evaluation of deferred tax assets requires judgment in assessing the likely future tax consequences of events that have been recognized in the Company's financial statements or tax returns and forecasting future profitability by tax jurisdiction. The Company evaluates its deferred tax assets quarterly on a jurisdictional basis to determine whether adjustments to the valuation allowance are appropriate considering changes in facts or circumstances. As of each reporting date, management considers new evidence, both positive and negative, when determining the future realization of the Company’s deferred tax assets. Given the Company’s current level of pre-tax earnings and forecasted future pre-tax earnings, the Company expects to generate income before taxes in the U.S. in future periods at a level that would fully utilize its U.S. federal NOL carryforwards and the majority of its state NOL carryforwards prior to their expiration. The Company continues to maintain a valuation allowance of approximately $248 million as of December 31, 2021 against deferred tax assets consisting of state net operating losses and foreign NOL carryforwards in jurisdictions where the Company does not currently believe that the realization of deferred tax assets is more likely than not. As of December 31, 2020 the Company's valuation allowance balance was $266 million. Considerable judgment is required to determine the tax treatment of a particular item that involves interpretations of complex tax laws. The Company is subject to examination by taxing authorities for income tax returns filed in the U.S. federal jurisdiction and various state and foreign jurisdictions, including operations located in Australia and Canada. The Company continues to be under audit for multiple years by taxing authorities in various jurisdictions. The Company is no longer subject to U.S. federal income tax examinations for years prior to 2018. With few exceptions, state and and Canadian income tax examinations are no longer open for years before 2013. NRG does not intend, nor currently foresee a need, to repatriate funds held at our international operations into the U.S. These funds are deemed to be indefinitely reinvested in our foreign operations and the Company has not changed its assertion with respect to distributions of funds that would require the accrual of U.S. income tax. 69 Evaluation of Assets for Impairment and Other-Than-Temporary Decline in Value In accordance with ASC 360, Property, Plant, and Equipment , or ASC 360, the Company evaluates property, plant and equipment and certain intangible assets for impairment whenever indicators of impairment exist. Examples of such indicators or events include: • Significant decrease in the market price of a long-lived asset; • Significant adverse change in the manner an asset is being used or its physical condition; • Adverse business climate; • Accumulation of costs significantly in excess of the amounts originally expected for the construction or acquisition of an asset; • Current period loss combined with a history of losses or the projection of future losses; and • Change in the Company's intent about an asset from an intent to hold to a greater than 50% likelihood that an asset will be sold, or disposed of before the end of its previously estimated useful life. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the assets to the future net cash flows expected to be generated by the asset, through considering project specific assumptions for long-term power and natural gas prices, escalated future project operating costs and expected plant operations. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets by factoring in the different courses of action available to the Company. Generally, fair value will be determined using valuation techniques, such as the present value of expected future cash flows. NRG uses its best estimates in making these evaluations and considers various factors, including forward price curves for energy, fuel and operating costs. However, actual future market prices and project costs could vary from the assumptions used in the Company's estimates and the impact of such variations could be material. For assets to be held and used, if the Company determines that the undiscounted cash flows from the asset are less than the carrying amount of the asset, NRG must estimate fair value to determine the amount of any impairment loss. Assets held-for-sale are reported at the lower of the carrying amount or fair value less the cost to sell. The estimation of fair value, whether in conjunction with an asset to be held and used or with an asset held-for-sale, and the evaluation of asset impairment are, by their nature, subjective. The Company considers quoted market prices in active markets to the extent they are available. In the absence of such information, NRG may consider prices of similar assets, consult with brokers, or employ other valuation techniques. The Company will also discount the estimated future cash flows associated with the asset using a single interest rate representative of the risk involved with such an investment or asset. The use of these methods involves the same inherent uncertainty of future cash flows as previously discussed with respect to undiscounted cash flows. Actual future market prices and project costs could vary from those used in NRG's estimates and the impact of such variations could be material. 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. The Company measured the impairment losses on the PJM generation assets and Midwest Generation goodwill as the difference between the carrying amount and the fair value of the PJM generating assets and Midwest Generation reporting unit, respectively. Fair values were determined primarily using an income approach in which the Company applied a discounted cash flow methodology to the long-term budgets for the plants and reporting unit. Significant inputs impacting the income approach include the Company's long-term view of capacity and fuel prices, projected generation, the physical and economic characteristics of each plant, and the discount rate applied to the after-tax cash flow projections. Impairment losses of $271 million and $35 million were recorded in the East segment on the PJM generating assets and Midwest Generation goodwill, respectively. Annually, during the fourth quarter, the Company revises its views of power and fuel prices including the Company's fundamental view for long-term prices, forecasted generation and operating and capital expenditures, in connection with the preparation of its annual budget. Changes to the Company's views of long-term power and fuel prices impact the Company’s projections of profitability, based on management's estimate of supply and demand within the sub-markets for its operations and the physical and economic characteristics of each of its businesses. In the fourth quarter of 2021, 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. The Company recorded additional impairment losses of $16 million and $9 million related to various power plants in the East and West/Services/Other segments, respectively. 70 In the third quarter of 2020, the Company concluded its Home Solar business was held for sale as a result of advanced negotiations to sell the business 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. On November 13, 2020, the Company completed the sale of the Home Solar business for $66 million. In the fourth quarter of 2020, the Company recognized an impairment loss of $32 million in the West/Services/Other segment related to the Cottonwood facility. The impairment was attributable to 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. Additionally, in the fourth quarter of 2020, the Company recorded $14 million of impairment losses related to intangible assets in the Texas segment. Equity Method Investments The Company is also required to evaluate for impairment its equity method investments in accordance with ASC 323, Investments - Equity Method and Joint Ventures , or ASC 323. The standard for determining whether an impairment must be recorded under ASC 323 is whether an observed decline in the value of an equity method investment is considered other-than-temporary. The evaluation and measurement of impairments under ASC 323 involves the same uncertainties as described for long-lived assets that the Company owns directly and accounts for in accordance with ASC 360. Similarly, the estimates that the Company makes with respect to its equity method investments are subjective, and the impact of variations in these estimates could be material. Additionally, if the projects in which the Company holds these investments recognize an impairment under the provisions of ASC 360, the Company would record its proportionate share of that impairment loss and would evaluate its investment for an other-than-temporary decline in value under ASC 323. During the first quarter of 2020, NRG recorded an impairment loss of $18 million in the Texas segment, attributable to its equity method investment in Petra Nova Parish Holdings, which included the anticipated drawdown of the $12 million letter of credit posted in September 2019 to cover certain project debt reserve requirements. Goodwill and Other Intangible Assets At December 31, 2021, the Company reported goodwill of $1.8 billion, consisting of $1.3 billion from the acquisition of Direct Energy in 2021, $130 million associated with the acquisition of Midwest Generation and $414 million for retail operations acquisitions, including Stream Energy, which was acquired in 2019. The Company applies ASC 805, Business Combinations , or ASC 805, and ASC 350, Intangibles-Goodwill and Other, or ASC 350 to account for its goodwill and intangible assets. Under these standards, the Company amortizes all finite-lived intangible assets over their respective estimated weighted-average useful lives, while goodwill has an indefinite life and is not amortized. Goodwill is tested for impairment at least annually, or more frequently whenever an event or change in circumstances occurs that would more likely than not reduce the fair value of a reporting unit below its carrying amount. The Company tests goodwill for impairment at the reporting unit level, which is identified by assessing whether the components of the Company's operating segments constitute businesses for which discrete financial information is available and whether segment management regularly reviews the operating results of those components. The Company performs the annual goodwill impairment assessment as of December 31 or when events or changes in circumstances indicate that the fair value of the reporting unit may be below the carrying amount. The Company first assesses qualitative factors to determine whether it is more likely than not that an impairment has occurred. In the absence of sufficient qualitative factors, the Company performs a quantitative assessment by determining the fair value of the reporting unit and comparing to its book value. If it is determined that the fair value of a reporting unit is below its carrying amount, the Company's goodwill will be impaired at that time. 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. An impairment of $35 million was recorded in Midwest Generation goodwill. For further discussion, see Evaluation of Assets for Impairment and Other-Than-Temporary Decline in Value caption above. During the fourth quarter of 2021, the Company performed its qualitative assessment of macroeconomic, industry and market events and circumstances, and the overall financial performance of the Texas (Texas segment) and East Retail (East segment) reporting units. The Company determined it was more-likely-than not that the fair value of the goodwill attributed to these reporting units were more than their carrying amount and accordingly, no impairment existed for the year ended December 31, 2021. 71 During the fourth quarter of 2021, the Company also performed a quantitative assessment for the Midwest Generation (East segment) and West/Services/Other reporting units. The Company determined the fair value of the reporting units using an income approach. Based on the income approach, the Company estimated the fair value of each reporting units' cash flows exceeded its carrying value and, as such, NRG concluded that the goodwill associated with each reporting unit was not impaired as of December 31, 2021. The Company believes the methodology and assumptions used in its quantitative assessments were consistent with the views of market participants. Significant inputs to the determinations of fair value of the Midwest Generation reporting unit were as follows: • The Company applied a discounted cash flow methodology to the long-term budgets for the Midwest Generation plants, resulting in fair value over the carrying value of the reporting unit of 117%. The significant assumptions used to derive the long-term budgets used in the income approach are affected by the following key inputs: ◦ The Company's views of power, capacity and fuel prices consider market prices for the next five years and the Company's fundamental view for the longer term, driven by the Company's long-term view of the price of natural gas. The Company's fundamental view for the longer term reflects the implied prices and heat rate that would support new build of a combined cycle gas plant. The price of natural gas plays an important role in setting the price of electricity in many of the regions where NRG operates power plants. Hedging is included to the extent of contracts already in place; ◦ The Company's estimate of generation, fuel costs, capital expenditure requirements and the existing and anticipated impact of environmental regulations; ◦ The Company's fundamental view for the longer term, cash flows for the plants in the region were included in the fair value calculation through the end of each plants' estimated useful life; and ◦ Projected generation and resulting energy gross margin in the long-term budgets is based on an hourly dispatch that simulates dispatch of each unit into the power market. The dispatch simulation is based on power prices, fuel prices, and the physical and economic characteristics of each plant. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. As a result, there can be no assurance that the estimates and assumptions made for purposes of the annual goodwill impairment test will prove to be accurate predictions of the future. Business Combinations We account for business acquisitions using the acquisition method of accounting prescribed under ASC 805. Under this method, we are required to record on our Consolidated Balance Sheets the estimated fair values of the acquired company’s assets and liabilities assumed at the acquisition date. The excess of the consideration transferred over the fair value of the net identifiable assets acquired and liabilities assumed is recorded as goodwill. Determining fair values of assets acquired and liabilities assumed requires significant estimates and judgments. We determine fair value based on the estimated price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The acquired assets and assumed liabilities that involved the most subjectivity in determining fair value consisted of the trade names, customer relationships and derivative contracts. The fair value of trade names and customer relationships was measured using income-based valuation methodologies, which include certain assumptions such as forecasted future cash flows, customer attrition rates, royalty rates and discount rates. The trade names are amortized to depreciation and amortization, on a straight line basis. The customer relationships are amortized to depreciation and amortization, ratably based on discounted future cash flows. In measuring the fair value of derivative contracts, a significant portion of the fair value of the derivative portfolio was based on price quotes from brokers in active markets who regularly facilitate those transactions and the Company believes such price quotes are executable. The Company does not use third party sources that derive price based on proprietary models or market surveys. The remainder of the assets and liabilities represents contracts for which external sources or observable market quotes are not available. These contracts were valued based on various valuation techniques including but not limited to internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. The fair value of each contract was discounted using a risk free interest rate. In addition, the Company applied a credit reserve to reflect credit risk. NRG describes in detail its acquisitions in Item 15 — Note 4, Acquisitions, Discontinued Operations and Dispositions , to the Consolidated Financial Statements 72 Contingencies NRG records reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. Gain contingencies are not recorded until management determines it is certain that the future event will become or does become a reality. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events, and estimates of the financial impacts of such events. NRG describes in detail its contingencies in Item 15 — Note 23, Commitments and Contingencies, to the Consolidated Financial Statements. Recent Accounting Developments See Item 15 — Note 2, Summary of Significant Accounting Policies, to the Consolidated Financial Statements for a discussion of recent accounting developments. Item 7A — Quantitative and Qualitative Disclosures About Market Risk NRG is exposed to several market risks in the Company's normal business activities. Market risk is the potential loss that may result from market changes associated with the Company's retail operations, merchant power generation, or with an existing or forecasted financial or commodity transactions. The types of market risks the Company is exposed to are commodity price risk, interest rate risk, liquidity risk, credit risk and currency exchange risk. In order to manage these risks, the Company uses various fixed-price forward purchase and sales contracts, futures and option contracts traded on NYMEX and other exchanges, and swaps and options traded in the over-the-counter financial markets to: • Manage and hedge fixed-price purchase and sales commitments; • Reduce exposure to the volatility of cash market prices, and • Hedge fuel requirements for the Company's generating facilities. Commodity Price Risk Commodity price risks result from exposures to changes in spot prices, forward prices, volatilities, and correlations between various commodities, such as natural gas, electricity, coal, oil, and emissions credits. NRG manages the commodity price risk of the Company's load servicing obligations and merchant generation operations by entering into various derivative or non-derivative instruments to hedge the variability in future cash flows from forecasted sales and purchases of electricity and fuel. NRG measures the risk of the Company's portfolio using several analytical methods, including sensitivity tests, scenario tests, stress tests, position reports and VaR. NRG uses a Monte Carlo simulation based VaR model to estimate the potential loss in the fair value of its energy assets and liabilities, which includes generation assets, gas transportation and storage assets, load obligations and bilateral physical and financial transactions, based on historical and forward values for factors such as customer demand, weather, commodity availability and commodity prices. The Company's VaR model is based on a one-day holding period at a 95% confidence interval for the forward 36 months, not including the spot month. The VaR model is not a complete picture of all risks that may affect the Company's results. Certain events such as counterparty defaults, regulatory changes, and extreme weather and prices that deviate significantly from historically observed values are not reflected in the model. The following table summarizes average, maximum and minimum VaR for NRG's commodity portfolio, calculated using the VaR model for the years ended December 31, 2021 and 2020: (In millions) 2021 2020 VaR as of December 31, (a) $ 30 $ 30 For the year ended December 31, Average (b) $ 35 $ 30 Maximum (b) 53 47 Minimum (b) 23 22 (a) Calculation includes entire NRG portfolio as of December 31, 2021 (b) Calculation is based on NRG generation assets and load obligations excluding the acquisition of Direct Energy assets and load obligations in the first quarter of 2021 In order to provide additional information, the Company also uses VaR to estimate the potential loss of derivative financial instruments that are subject to mark-to-market accounting. These derivative instruments include transactions that were entered into for both asset management and trading purposes. The VaR for the derivative financial instruments calculated using the diversified VaR model for the entire term of these instruments entered into for both asset management and trading was $242 million as of December 31, 2021, primarily driven by asset-backed transactions. The increase in the VaR for derivative financial instruments was primarily due to the acquisition of Direct Energy. 73 Retail Customer Credit Risk NRG is exposed to retail credit risk related to its Business and Home customers. Retail credit risk results in losses when a customer fails to pay for services rendered. The losses may result from both nonpayment of customer accounts receivable and the loss of in-the-money forward value. NRG 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, 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's provision for credit losses resulting from credit risk was $698 million, $108 million and $95 million for the years ending December 31, 2021, 2020 and 2019, respectively. 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. Liquidity Risk Liquidity risk arises from the general funding needs of the Company's activities and the management of the Company's assets and liabilities. The Company is currently exposed to additional collateral posting if natural gas prices decline, primarily due to the long natural gas equivalent position at various exchanges used to hedge NRG's retail supply load obligations. Based on a sensitivity analysis for power and gas positions under marginable contracts as of December 31, 2021, a $0.50 per MMBtu decrease in natural gas prices across the term of the marginable contracts would cause an increase in margin collateral posted of approximately $828 million and a 1.00 MMBtu/MWh decrease in heat rates for heat rate positions would result in an increase in margin collateral posted of approximately $378 million. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of December 31, 2021. Counterparty Credit Risk Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. The Company monitors and manages credit risk through credit policies that include: (i) an established credit approval process; (ii) a daily monitoring of counterparties' credit limits; (iii) the use of credit mitigation measures such as margin, collateral, prepayment arrangements, or volumetric limits; (iv) the use of payment netting agreements; and (v) the use of master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with a single counterparty. Risks surrounding counterparty performance and credit could ultimately impact the amount and timing of expected cash flows. The Company seeks to mitigate counterparty risk by having a diversified portfolio of counterparties. The Company also has credit protection within various agreements to call on additional collateral support if and when necessary. Cash margin is collected and held at the Company to cover the credit risk of the counterparty until positions settle. As of December 31, 2021, counterparty credit exposure, excluding credit exposure from RTOs, ISOs, and registered commodity exchanges and certain long-term agreements, was $2.2 billion, of which the Company 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. Collateral amounts shown include such excess while net exposure shown excludes excess collateral received. Approximately 87% of the Company's exposure before collateral is expected to roll off by the end of 2023. The following table highlights the net counterparty credit exposure by industry sector and by counterparty credit quality. Net counterparty credit exposure is defined as the aggregate net asset position for NRG with counterparties where netting is permitted under the enabling agreement and includes all cash flow, mark-to-market, NPNS, and non-derivative transactions. As of December 31, 2021, the aggregate credit exposure is shown net of collateral held, and includes amounts net of receivables or payables. Category Net Exposure (a) (b) (% of Total) Utilities, energy merchants, marketers and other 67 % Financial institutions 33 Total 100 % 74 Category Net Exposure (a) (b) (% of Total) Investment grade 55 % Non-Investment grade/Non-Rated 45 Total 100 % (a) Counterparty credit exposure excludes uranium and coal transportation contracts because of the unavailability of market prices (b) The figures in the tables above exclude potential counterparty credit exposure related to RTOs, ISOs, registered commodity exchanges and certain long-term contracts The Company has 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. 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 The Company participates in the organized markets of CAISO, ERCOT, ISO-NE, MISO, NYISO and PJM, known as RTOs or ISOs. Trading in these markets is approved by FERC, or in the case of ERCOT, approved by the PUCT and include credit policies that, under certain circumstances, require that losses arising from the default of one member on spot market transactions be shared by the remaining participants. As a result, the counterparty credit risk to these markets is limited to NRG’s applicable share of the overall market and are excluded from the above exposures. Exchange Traded Transactions The Company enters into commodity transactions on registered exchanges, notably ICE, NYMEX and Nodal. These clearinghouses act as the counterparty and transactions are subject to extensive collateral and margining requirements. As a result, these commodity transactions have limited counterparty credit risk. Long-Term Contracts Counterparty credit exposure described above excludes credit risk exposure under certain long-term contracts, primarily solar PPAs. As external sources or observable market quotes are not available to estimate such exposure, the Company values these contracts based on various techniques including, but not limited to, internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. Based on these valuation techniques, as of December 31, 2021, aggregate credit risk exposure managed by NRG to these counterparties was approximately $1.1 billion for the next five years. Interest Rate Risk As of December 31, 2021, the Company's debt fair value was $8.3 billion and carrying value was $8.0 billion. NRG estimates that a 1% decrease in market interest rates would have increased the fair value of the Company's long-term debt by $690 million. Credit Risk Related Contingent Features 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 a net liability position 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. 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. 75 Currency Exchange Risk NRG is subject to transactional exchange rate risk from transactions with customers in countries outside of the United States, primarily within Canada, as well as from intercompany transactions between affiliates. Transactional exchange rate risk arises from the purchase and sale of goods and services in currencies other than our functional currency or the functional currency of an applicable subsidiary. NRG hedges a portion of its forecasted currency transactions with foreign exchange forward contracts. As of December 31, 2021, NRG is exposed to changes in foreign currency primarily associated with the purchase of U.S. dollar denominated natural gas for its Canadian business and entered into foreign exchange contracts with notional amount of $279 million. The Company is subject to translation exchange rate risk related to the translation of the financial statements of its foreign operations into U.S. dollars. Costs incurred and sales recorded by subsidiaries operating outside of the United States are translated into U.S. dollars using exchange rates effective during the respective period. As a result, the Company is exposed to movements in the exchange rates of various currencies against the U.S. dollar, primarily the Canadian and Australian dollars. A hypothetical 10% appreciation in major currencies relative to the U.S. dollar as of December 31, 2021 would have resulted in an increase of $10 million to net income within the Consolidated Statement of Operations. Item 8 — Financial Statements and Supplementary Data The financial statements and schedules are included in Part IV, Item 15 of this Form 10-K. Item 9 — Changes in and Disagreements With Accountants on Accounting and Financial Disclosure None. Item 9A — Controls and Procedures Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures and Internal Control Over Financial Reporting Under the supervision and with the participation of NRG's management, including its principal executive officer, principal financial officer and principal accounting officer, NRG conducted an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures, as such term is defined in Rules 13a-15(e) or 15d-15(e) of the Exchange Act. Based on this evaluation, the Company's principal executive officer, principal financial officer and principal accounting officer concluded that the disclosure controls and procedures were effective as of the end of the period covered by this Annual Report on Form 10-K. Management's report on the Company's internal control over financial reporting and the report of the Company's independent registered public accounting firm are incorporated under the caption "Management's Report on Internal Control over Financial Reporting" and under the caption "Report of Independent Registered Public Accounting Firm" in this Annual Report on Form 10-K for the fiscal year ended December 31, 2021. Changes in 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. 76 Inherent Limitations over Internal Controls NRG's internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with GAAP. The Company's internal control over financial reporting includes those policies and procedures that: 1. Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the Company's assets; 2. Provide reasonable assurance that transactions are recorded as necessary to permit preparation of consolidated financial statements in accordance with GAAP, and that the Company's receipts and expenditures are being made only in accordance with authorizations of its management and directors; and 3. Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the consolidated financial statements. Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations, including the possibility of human error and circumvention by collusion or overriding of controls. Accordingly, even an effective internal control system may not prevent or detect material misstatements on a timely basis. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate. Management's Report on Internal Control over Financial Reporting The Company's management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of the Company's management, including its principal executive officer, principal financial officer and principal accounting officer, the Company conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Company's evaluation under the framework in Internal Control — Integrated Framework (2013) , the Company's management concluded that its internal control over financial reporting was effective as of December 31, 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. 77 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Stockholders NRG Energy, Inc.: Opinion on Internal Control Over Financial Reporting We have audited NRG Energy, Inc. and subsidiaries' (the Company) internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission . In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 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, 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 The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. Definition and Limitations of Internal Control Over Financial Reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. /s/ KPMG LLP Philadelphia, Pennsylvania February 24, 2022 78 Item 9B — Other Information 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. Effective February 24, 2022, Emily C. Picarello, CPA, was named as Principal Accounting Officer of NRG Energy, Inc. Ms. 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. Ms. 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. Prior to Ms. 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. 79 PART III Item 10 — Directors, Executive Officers and Corporate Governance Directors and Executive Officers Information required by this Item is incorporated by reference to the similarly named section of NRG's Definitive Proxy Statement for its 2022 Annual Meeting of Stockholders. Code of Ethics NRG has adopted a code of ethics entitled "NRG Code of Conduct" that applies to directors, officers and employees, including the chief executive officer and senior financial officers of NRG. It may be accessed through the "Governance" section of the Company's website at www.nrg.com. NRG also elects to disclose the information required by Form 8-K, Item 5.05, "Amendments to the Registrant's Code of Ethics, or Waiver of a Provision of the Code of Ethics," through the Company's website, and such information will remain available on this website for at least a 12-month period. A copy of the "NRG Code of Conduct" is available in print to any stockholder who requests it. Other information required by this Item is incorporated by reference to the similarly named section of NRG's Definitive Proxy Statement for its 2022 Annual Meeting of Stockholders. Item 11 — Executive Compensation Information required by this Item is incorporated by reference to the similarly named section of NRG's Definitive Proxy Statement for its 2022 Annual Meeting of Stockholders. Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters Securities Authorized for Issuance under Equity Compensation Plans Plan Category (a) Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights (b) Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights (c) Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a) Equity compensation plans approved by security holders 2,514,828 (1) $ — 11,508,073 Equity compensation plans not approved by security holders 20,131 (2) 20.07 — (4) Total 2,534,959 $ 20.07 11,508,073 (3) (1) Consists of shares issuable under the NRG LTIP and the ESPP. The NRG LTIP became effective upon the Company's emergence from bankruptcy. On April 27, 2017, the NRG LTIP was amended and restated to increase the number of shares available for issuance to 25,000,000. The ESPP, as amended and restated, was approved by the Company's stockholders on April 27, 2017, and became effective April 28, 2017. As of December 31, 2021, there were 2,636,199 shares reserved from the Company's treasury shares for the ESPP (2) Consists of shares issuable under the NRG GenOn LTIP. The plans is listed as “not approved” because it was not subject to separate line item approval by NRG's stockholders when the Merger was approved. See Item 15 — Note 21, Stock-Based Compensation , to Consolidated Financial Statements for a discussion of the NRG GenOn LTIP (3) Consists of 8,871,874 shares of common stock under NRG's LTIP and 2,636,199 shares of treasury stock reserved for issuance under the ESPP. (4) Upon adoption of the NRG Amended and Restated LTIP effective April 27, 2017, no securities remain available for future issuance under the NRG GenOn LTIP. 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. NRG's directors, officers and employees, as well as other individuals performing services for, or to whom an offer of employment has been extended by the Company, are eligible to receive grants under the NRG LTIP. The purpose of the NRG LTIP is to promote the Company's long-term growth and profitability by providing these individuals with incentives to maximize stockholder value and otherwise contribute to the Company's success and to enable the Company to attract, retain and reward the best available persons for positions of responsibility. The Compensation Committee of the Board of Directors administers the NRG LTIP. Other 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. 80 Item 13 — Certain Relationships and Related Transactions, and Director Independence Information required by this Item is incorporated by reference to the similarly named section of NRG's Definitive Proxy Statement for its 2022 Annual Meeting of Stockholders. Item 14 — Principal Accounting Fees and Services Information required by this Item is incorporated by reference to the similarly named section of NRG's Definitive Proxy Statement for its 2022 Annual Meeting of Stockholders. 81 PART IV Item 15 — Exhibits, Financial Statement Schedules (a)(1) Financial Statements The following consolidated financial statements of NRG Energy, Inc. and related notes thereto, together with the reports thereon of KPMG LLP , Philadelphia, PA , Auditor Firm ID: 185 , are included herein: Consolidated Statements of Operations — Years ended December 31, 2021, 2020, and 2019 Consolidated Statements of Comprehensive Income — Years ended December 31, 2021, 2020, and 2019 Consolidated Balance Sheets — As of December 31, 2021 and 2020 Consolidated Statements of Cash Flows — Years ended December 31, 2021, 2020, and 2019 Consolidated Statements of Stockholders' Equity — Years ended December 31, 2021, 2020, and 2019 Notes to Consolidated Financial Statements (a)(2) Financial Statement Schedule The following Consolidated Financial Statement Schedule of NRG Energy, Inc. is filed as part of Item 15 of this report and should be read in conjunction with the Consolidated Financial Statements. Schedule II — Valuation and Qualifying Accounts All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions or are inapplicable, and therefore, have been omitted. (a)(3) Exhibits: See Exhibit Index submitted as a separate section of this report. (b) Exhibits See Exhibit Index submitted as a separate section of this report. (c) Not applicable 82 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Stockholders NRG Energy, Inc.: Opinion on the Consolidated Financial Statements We have audited the accompanying consolidated balance sheets of NRG Energy, Inc. and subsidiaries (the Company) as of December 31, 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). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2021, in conformity with U.S. generally accepted accounting principles. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 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 These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion. Critical Audit Matters The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate. Evaluation of the sufficiency of audit evidence over 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. We identified the evaluation of the sufficiency of audit evidence over operating revenues as a critical audit matter which required a high degree of auditor judgment due to the number of revenue streams and IT systems involved in the revenue recognition process. This included determining the revenue streams over which procedures were to be performed and evaluating the nature and extent of evidence obtained over the individual revenue streams as well as operating revenue in the aggregate. It also included the involvement of IT professionals with specialized skills and knowledge to assist in the performance of certain procedures. 83 The following are the primary procedures we performed to address this critical audit matter. We, with the assistance of IT professionals, applied auditor judgment to determine the revenue streams over which procedures were performed as well as the nature and extent of such procedures. For certain revenue streams, 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. /s/ KPMG LLP We have served as the Company's auditor since 2004. Philadelphia, Pennsylvania February 24, 2022 84 NRG ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS For the Year Ended December 31, (In millions, except per share amounts) 2021 2020 2019 Operating Revenues Total operating revenues $ 26,989 $ 9,093 $ 9,821 Operating Costs and Expenses Cost of operations (excluding depreciation and amortization shown below) 20,482 6,540 7,303 Depreciation and amortization 785 435 373 Impairment losses 544 75 5 Selling, general and administrative costs 1,293 810 760 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 Gain on sale of assets 247 3 7 Operating Income 3,341 1,105 1,290 Other Income/(Expense) Equity in earnings of unconsolidated affiliates 17 17 2 Impairment losses on investments — ( 18 ) ( 108 ) Other income, net 63 67 66 Loss on debt extinguishment ( 77 ) ( 9 ) ( 51 ) Interest expense ( 485 ) ( 401 ) ( 413 ) Total other expense ( 482 ) ( 344 ) ( 504 ) Income from Continuing Operations Before Income Taxes 2,859 761 786 Income tax expense/(benefit) 672 251 ( 3,334 ) Income from Continuing Operations 2,187 510 4,120 Income from discontinued operations, net of income tax — — 321 Net Income 2,187 510 4,441 Less: Net income attributable to redeemable noncontrolling interest — — 3 Net Income Attributable to NRG Energy, Inc. $ 2,187 $ 510 $ 4,438 Income Per Share Attributable to NRG Energy, Inc. Common Stockholders Weighted average number of common shares outstanding — basic 245 245 262 Income from continuing operations per weighted average common share — basic $ 8.93 $ 2.08 $ 15.71 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 Weighted average number of common shares outstanding — diluted 245 246 264 Income from continuing operations per weighted average common share — diluted $ 8.93 $ 2.07 $ 15.59 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 See notes to Consolidated Financial Statements 85 NRG ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME For the Year Ended December 31, (In millions) 2021 2020 2019 Net Income $ 2,187 $ 510 $ 4,441 Other Comprehensive Income/(Loss), net of tax Foreign currency translation adjustments, net of income tax ( 5 ) 8 ( 1 ) Available-for-sale securities, net of income tax — — ( 19 ) Defined benefit plans, net of income tax 85 ( 22 ) ( 78 ) Other comprehensive income/(loss) 80 ( 14 ) ( 98 ) Comprehensive Income 2,267 496 4,343 Less: Net income attributable to redeemable noncontrolling interest — — 3 Comprehensive Income Attributable to NRG Energy, Inc. $ 2,267 $ 496 $ 4,340 See notes to Consolidated Financial Statements 86 NRG ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS As of December 31, (In millions) 2021 2020 ASSETS Current Assets Cash and cash equivalents $ 250 $ 3,905 Funds deposited by counterparties 845 19 Restricted cash 15 6 Accounts receivable, net 3,245 904 Uplift securitization proceeds receivable from ERCOT 689 — Inventory 498 327 Derivative instruments 4,613 560 Cash collateral paid in support of energy risk management activities 291 50 Prepayments and other current assets 395 257 Total current assets 10,841 6,028 Property, plant and equipment, net 1,688 2,547 Other Assets Equity investments in affiliates 157 346 Operating lease right-of-use assets, net 271 301 Goodwill 1,795 579 Intangible assets, net 2,511 668 Nuclear decommissioning trust fund 1,008 890 Derivative instruments 2,527 261 Deferred income taxes 2,155 3,066 Other non-current assets 229 216 Total other assets 10,653 6,327 Total Assets $ 23,182 $ 14,902 See notes to Consolidated Financial Statements 87 NRG ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Continued) As of December 31, (In millions, except share data) 2021 2020 LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities Current portion of long-term debt and finance leases $ 4 $ 1 Current portion of operating lease liabilities 81 69 Accounts payable 2,274 649 Derivative instruments 3,387 499 Cash collateral received in support of energy risk management activities 845 19 Accrued expenses and other current liabilities 1,324 678 Total current liabilities 7,915 1,915 Other Liabilities Long-term debt and finance leases 7,966 8,691 Non-current operating lease liabilities 236 278 Nuclear decommissioning reserve 321 303 Nuclear decommissioning trust liability 666 565 Derivative instruments 1,412 385 Deferred income taxes 73 19 Other non-current liabilities 993 1,066 Total other liabilities 11,667 11,307 Total Liabilities 19,582 13,222 Commitments and Contingencies Stockholders' Equity Common stock; $ 0.01 par value; 500,000,000 shares authorized; 423,547,174 and 423,057,848 shares issued; and 243,753,899 and 244,231,933 shares outstanding at December 31, 2021 and 2020, respectively 4 4 Additional paid-in capital 8,531 8,517 Retained earnings/(accumulated deficit) 464 ( 1,403 ) Treasury stock, at cost; 179,793,275 and 178,825,915 shares at December 31, 2021 and 2020, respectively ( 5,273 ) ( 5,232 ) Accumulated other comprehensive loss ( 126 ) ( 206 ) Total Stockholders' Equity 3,600 1,680 Total Liabilities and Stockholders' Equity $ 23,182 $ 14,902 See notes to Consolidated Financial Statements 88 NRG ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS For the Year Ended December 31, (In millions) 2021 2020 2019 Cash Flows from Operating Activities Net income $ 2,187 $ 510 $ 4,441 Income from discontinued operations, net of income tax — — 321 Income from continuing operations 2,187 510 4,120 Adjustments to reconcile net income to net cash provided by operating activities: Distributions from and equity in earnings of unconsolidated affiliates 20 45 14 Depreciation and amortization 785 435 373 Accretion of asset retirement obligations 30 45 51 Provision for credit losses 698 108 95 Amortization of nuclear fuel 51 54 52 Amortization of financing costs and debt discounts 39 48 26 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 Net gain on sale of assets and disposal of assets ( 261 ) ( 23 ) ( 23 ) Impairment losses 544 93 113 Changes in derivative instruments ( 3,626 ) 137 34 Changes in deferred income taxes and liability for uncertain tax benefits 604 228 ( 3,353 ) Changes in collateral deposits in support of risk management activities 797 127 105 Changes in nuclear decommissioning trust liability 40 51 37 Oil lower of cost or market adjustment — 29 — 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 Inventory ( 61 ) 27 22 Prepayments and other current assets 31 4 29 Accounts payable 476 ( 56 ) ( 177 ) Accrued expenses and other current liabilities ( 55 ) ( 42 ) ( 75 ) Other assets and liabilities ( 89 ) ( 84 ) ( 186 ) Cash provided by continuing operations 493 1,837 1,405 Cash provided by discontinued operations — — 8 Net Cash Provided by Operating Activities $ 493 $ 1,837 $ 1,413 Cash Flows from Investing Activities Payments for acquisitions of assets, businesses and leases $ ( 3,559 ) $ ( 284 ) $ ( 355 ) Capital expenditures ( 269 ) ( 230 ) ( 228 ) Net (purchases)/sales of emissions allowances — ( 10 ) 11 Investments in nuclear decommissioning trust fund securities ( 751 ) ( 492 ) ( 416 ) Proceeds from sales of nuclear decommissioning trust fund securities 710 439 381 Proceeds from sale of assets, net of cash disposed and sale of discontinued operations, net of fees 830 81 1,294 Changes in investments in unconsolidated affiliates — 2 ( 91 ) Net contributions to discontinued operations — — ( 44 ) Other — — 6 Cash (used)/provided by continuing operations ( 3,039 ) ( 494 ) 558 Cash used by discontinued operations — — ( 2 ) Net Cash (Used)/Provided by Investing Activities $ ( 3,039 ) $ ( 494 ) $ 556 89 For the Year Ended December 31, (In millions) 2021 2020 2019 Cash Flows from Financing Activities Proceeds from issuance of long-term debt $ 1,100 $ 3,234 $ 1,833 Payments for short and long-term debt ( 1,861 ) ( 335 ) ( 2,571 ) 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 ) 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 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 (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 (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 90 NRG ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (In millions) Common Stock Additional Paid-In Capital Retained Earnings/ (Accumulated Deficit) Treasury Stock Accumulated Other Comprehensive Loss Total Stock-holders' Equity Balances at December 31, 2018 $ 4 $ 8,510 $ ( 6,022 ) $ ( 3,632 ) $ ( 94 ) $ ( 1,234 ) Net income attributable to NRG Energy, Inc. 4,438 4,438 Other comprehensive loss ( 98 ) ( 98 ) Shares reissuance for ESPP 1 2 3 Share repurchases ( 1,409 ) ( 1,409 ) Equity-based awards activity, net (a) ( 16 ) ( 16 ) Issuance of common stock 6 6 Common stock dividends and dividend equivalents declared (b) ( 32 ) ( 32 ) Balance at December 31, 2019 $ 4 $ 8,501 $ ( 1,616 ) $ ( 5,039 ) $ ( 192 ) $ 1,658 Net income 510 510 Other comprehensive loss ( 14 ) ( 14 ) Repurchase of partners' equity interest in VIE 18 18 Shares reissuance for ESPP 4 4 Share repurchases ( 197 ) ( 197 ) Equity-based awards activity, net (a) ( 3 ) ( 3 ) Issuance of common stock 1 1 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 2,187 2,187 Other comprehensive income 80 80 Shares reissuance for ESPP 1 3 4 Share repurchases ( 44 ) ( 44 ) Equity-based awards activity, net (a) 12 12 Issuance of common stock 1 1 Common stock dividends and dividend equivalents declared (b) ( 320 ) ( 320 ) Balance at December 31, 2021 $ 4 $ 8,531 $ 464 $ ( 5,273 ) $ ( 126 ) $ 3,600 (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 91 NRG ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 1 — Nature of Business General 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 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. 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 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; and • Corporate activities. Note 2 — Summary of Significant Accounting Policies Basis of Presentation and Principles of Consolidation The Company's consolidated financial statements have been prepared in accordance with U.S. GAAP. The ASC, established by the FASB, is the source of authoritative U.S. GAAP to be applied by nongovernmental entities. In addition, the rules and interpretative releases of the SEC under authority of federal securities laws are also sources of authoritative U.S. GAAP for SEC registrants. The consolidated financial statements include NRG's accounts and operations and those of its subsidiaries in which the Company has a controlling interest. All significant intercompany transactions and balances have been eliminated in consolidation. The usual condition for a controlling financial interest is ownership of a majority of the voting interests of an entity. However, a controlling financial interest may also exist through arrangements that do not involve controlling voting 92 interests. As such, NRG applies the guidance of ASC 810, Consolidations, or ASC 810, to determine when an entity that is insufficiently capitalized or not controlled through its voting interests, referred to as a VIE, should be consolidated. Cash and Cash Equivalents Cash and cash equivalents include highly liquid investments with an original maturity of three months or less at the time of purchase. Funds Deposited by Counterparties Funds deposited by counterparties consist of cash held by the Company as a result of collateral posting obligations from its counterparties. 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. 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 On January 1, 2020, the Company adopted ASU No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments , or ASU No. 2016-13, using the modified retrospective approach. Following the adoption of the new standard, the Company’s process of estimating expected credit losses remains materially consistent with its historical practice. Information prior to January 1, 2020, which was previously referred to as the allowance and provision for bad debt, has not been restated and continues to be reported under the accounting standards in effect for that period. Retail trade receivables are reported on the balance sheet net of the allowance for credit losses. The Company accrues an allowance for current expected credit losses based on (i) estimates of uncollectible revenues by analyzing accounts receivable aging and current and reasonable forecasts of expected economic factors including, but not limited to, unemployment rates and weather-related events, (ii) historical collections and delinquencies, and (iii) counterparty credit ratings for commercial and industrial customers. The Company writes off customer contract receivable balances against the allowance for credit losses when it is determined a receivable is uncollectible. The following table represents the activity in the allowance for credit losses for the year ended December 31, 2021: Year Ended December 31, (In millions) 2021 2020 Beginning balance $ 67 $ 43 Acquired balance from Direct Energy 112 — Provision for credit losses (a) 698 108 Write-offs ( 224 ) ( 101 ) Recoveries collected 30 17 Ending balance (a) $ 683 $ 67 (a) Includes bilateral finance hedging risk of $ 403 million accounted for under ASC 815 93 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 The following table provides a reconciliation of cash and cash equivalents, restricted cash and funds deposited by counterparties reported within the consolidated balance sheets that sum to the total of the same such amounts shown in the statements of cash flows. Year Ended December 31, (In millions) 2021 2020 2019 Cash and cash equivalents $ 250 $ 3,905 $ 345 Funds deposited by counterparties 845 19 32 Restricted cash 15 6 8 Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statements of cash flows $ 1,110 $ 3,930 $ 385 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 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 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. Sales of inventory are classified as an operating activity in the consolidated statements of cash flows. Property, Plant and Equipment Property, plant and equipment are stated at cost or, in the case of business acquisitions, fair value; however, impairment adjustments are recorded whenever events or changes in circumstances indicate that their carrying values may not be recoverable. NRG also classifies nuclear fuel related to the Company's 44 % ownership interest in STP as part of the Company's property, plant, and equipment. Significant additions or improvements extending asset lives are capitalized as incurred, while repairs and maintenance that do not improve or extend the life of the respective asset are charged to expense as incurred. Depreciation, other than nuclear fuel, is computed using the straight-line method, while nuclear fuel 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. Asset Impairments Long-lived assets that are held and used are reviewed for impairment whenever events or changes in circumstances indicate carrying values may not be recoverable. Such reviews are performed in accordance with ASC 360. An impairment loss is indicated if the total future estimated undiscounted cash flows expected from an asset are less than its carrying value. An impairment charge is measured by the difference between an asset's carrying amount and fair value with the difference recorded in operating costs and expenses in the consolidated statements of operations. Fair values are determined by a variety of valuation methods, including third-party appraisals, sales prices of similar assets, and present value techniques. Investments accounted for by the equity method are reviewed for impairment in accordance with ASC 323, Investments-Equity Method and Joint Ventures , or ASC 323, which requires that a loss in value of an investment that is an other-than-temporary decline should be recognized. The Company identifies and measures losses in the value of equity method investments based upon a comparison of fair value to carrying value. For further discussion of these matters, refer to Note 11, Asset Impairments . 94 Development Costs and Capitalized Interest Development costs include project development costs, which are expensed in the preliminary stages of a project and capitalized when the project is deemed to be commercially viable. Commercial viability is determined by one or a series of actions including, among others, Board of Director approval pursuant to a formal project plan that subjects the Company to significant future obligations that can only be discharged by the use of a Company asset. When a project is available for operations, capitalized interest and capitalized project development costs are reclassified to property, plant and equipment and depreciated on a straight-line basis over the estimated useful life of the project's related assets. Capitalized costs are charged to expense if a project is abandoned or management otherwise determines the costs to be unrecoverable. Interest incurred on funds borrowed to finance capital projects is capitalized until the project under construction is ready for its intended use. The amount of interest capitalized for the years ended December 31, 2021, 2020 and 2019, was $ 2 million, $ 2 million and $ 3 million, respectively. Debt Issuance Costs Debt issuance costs are capitalized and amortized as interest expense on a basis which approximates the effective interest method over the term of the related debt. Debt issuance costs are presented as a direct deduction from the carrying amount of the related debt, or as an asset if the issuance costs relate to revolving debt agreements or certain other financing arrangements. Intangible Assets Intangible assets represent contractual rights held by the Company. The Company recognizes specifically identifiable intangible assets including 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. As of December 31, 2021 and 2020, the Company had accumulated amortization related to its intangible assets of $ 1.6 billion and $ 1.4 billion, respectively. Emission allowances held-for-sale, which are included in other non-current assets on the Company's consolidated balance sheet, are not amortized; they are carried at the lower of cost or fair value and reviewed for impairment in accordance with ASC 360. Goodwill In accordance with ASC 350, Intangibles-Goodwill and Other , or ASC 350, the Company recognizes goodwill for the excess cost of an acquired entity over the net value assigned to assets acquired and liabilities assumed. NRG performs goodwill impairment tests annually, during the fourth quarter, and when events or changes in circumstances indicate that the carrying value may not be recoverable. The Company first assesses qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. The more-likely-than-not threshold is defined as having a likelihood of more than 50 percent. If it is not more-likely-than-not that the fair value of a reporting unit is less than its carrying amount, there is no goodwill impairment. In the absence of sufficient qualitative factors indicating that it is more-likely-than-not that no impairment occurred, the Company performs a quantitative assessment by determining the fair value of the reporting unit and comparing the fair value to its book value. If the fair value of the reporting unit exceeds its book value, goodwill of the reporting unit is not considered impaired. If the book value exceeds fair value, the Company recognizes an impairment loss equal to the difference between book value and fair value. For further discussion of goodwill and goodwill impairment losses recognized refer to Note 12, Goodwill and Other Intangibles. Income Taxes The Company accounts for income taxes using the liability method in accordance with ASC 740, Income Taxes, or ASC 740, which requires that the Company use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences. The Company has two categories of income tax expense or benefit — current and deferred, as follows: • Current income tax expense or benefit consists solely of current taxes payable less applicable tax credits, and • Deferred income tax expense or benefit is the change in the net deferred income tax asset or liability, excluding amounts charged or credited to accumulated other comprehensive income 95 The Company reports some of its revenues and expenses differently for financial statement purposes than for income tax return purposes, resulting in temporary and permanent differences between the Company's financial statements and income tax returns. The tax effects of such temporary differences are recorded as either deferred income tax assets or deferred income tax liabilities in the Company's consolidated balance sheets. The Company measures its deferred income tax assets and deferred income tax liabilities using income tax rates that are expected to be in effect when the deferred tax is realized. The Company accounts for uncertain tax positions in accordance with ASC 740, which applies to all tax positions related to income taxes. Under ASC 740, tax benefits are recognized when it is more-likely-than-not that a tax position will be sustained upon examination by the authorities. The benefit recognized from a position is the amount of benefit that has surpassed the more-likely-than-not threshold, as it is more than 50% likely to be realized upon settlement. The Company recognizes interest and penalties accrued related to uncertain tax benefits as a component of income tax expense. In accordance with ASC 740 and as discussed further in Note 20, Income Taxes , changes to existing net deferred tax assets or valuation allowances or changes to uncertain tax benefits, are recorded to income tax (benefit)/expense. Contract and Emission Credit Amortization Assets and liabilities recognized through acquisitions related to the purchase and sale of energy and energy-related products in future periods for which the fair value has been determined to be significantly less or more than market are amortized to 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 Certain of the Company’s revenues are obtained through leases of rooftop residential solar systems, which are accounted for as operating leases in accordance with ASC 842, Leases. Pursuant to the lease agreements, the customers’ monthly payments are pre-determined fixed monthly amounts and may include an annual fixed percentage escalation to reflect the impact of utility rate increases over the lease term, which is 20 years. The Company records operating lease revenue on a straight-line basis over the life of the lease term. Certain customers made initial down payments that are being amortized over the life of the lease. The difference between the payments received and the revenue recognized is recorded as deferred revenue. Lessor Accounting Certain of the Company's revenues are obtained through PPAs or other contractual agreements. Many of these agreements are accounted for as operating leases under ASC 842 . 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, 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. 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. 96 In estimating supply volumes, the Company considers the effects of historical customer volumes, weather factors and usage by customer class. Transmission and distribution delivery fees are estimated using the same method used for electricity sales and services to retail customers. In addition, ISO fees are estimated based on historical trends, estimated supply volumes and initial ERCOT ISO settlements. Volume estimates are then multiplied by the supply rate and recorded as cost of operations in the applicable reporting period. 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 instruments under ASC 815, they are not recorded at fair value, but on an accrual basis of accounting. If it is determined that a transaction designated as NPNS no longer meets the scope exception, the fair value of the related contract is recorded on the balance sheet and immediately recognized through earnings. NRG's trading activities are subject to limits in accordance with the Company's Risk Management Policy. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative instruments are recognized in earnings. Mark-to-Market for Economic Hedging Activities NRG enters into derivative instruments to manage price and delivery risk, optimize physical and contractual assets in the portfolio and manage working capital requirements. The mark-to-market for economic hedging activities are recognized to cost of operations during the reporting period. Operations and Maintenance and Other Cost of Operations Operations and maintenance costs include major and other routine preventative (planned outage) and corrective (forced outage) maintenance activities to ensure the safe and reliable operation of the Company's generation portfolio in compliance with all local, state and federal requirements. Operations and maintenance costs are also costs associated with retaining and maintaining the Company's customer base, such as call center support, portfolio maintenance and data analytics. Other cost of operations primarily includes gross receipts taxes, insurance, property taxes and asset retirement obligation expense. Foreign Currency Translation and Transaction Gains and Losses The local currencies are generally the functional currency of NRG's foreign operations. Foreign currency denominated assets and liabilities are translated at end-of-period rates of exchange. Revenues, expenses, and cash flows are translated at the weighted-average rates of exchange for the period. The resulting currency translation adjustments are not included in the Company's consolidated statements of operations for the period, but are accumulated and reported as a separate component of stockholders' equity until sale or complete or substantially complete liquidation of the net investment in the foreign entity takes place. Foreign currency transaction gains or losses are reported within other income/(expense) in the Company's consolidated statements of operations. For the years ended December 31, 2021, 2020 and 2019, amounts recognized as foreign currency transaction gains/(losses) were immaterial. The Company's cumulative translation adjustment balances as of December 31, 2021, 2020 and 2019 were $( 8 ) million, $( 2 ) million and $( 13 ) million, respectively. Concentrations of Credit Risk Financial instruments which potentially subject the Company to concentrations of credit risk consist primarily of trust funds, accounts receivable, notes receivable, derivatives, and investments in debt securities. Trust funds are held in accounts managed by experienced investment advisors. Certain accounts receivable, notes receivable, and derivative instruments are concentrated within entities engaged in the energy industry. These industry concentrations may impact the Company's overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. Receivables and other contractual arrangements are subject to collateral requirements under the terms of enabling agreements. However, the Company believes that the credit risk posed by industry concentration is offset by the diversification and creditworthiness of its customer base. See Note 5, Fair Value of Financial Instruments, for a further discussion of derivative concentrations. 97 Fair Value of Financial Instruments The carrying amount of cash and cash equivalents, funds deposited by counterparties, receivables, accounts payable, and accrued liabilities approximate fair value because of the short-term maturity of these instruments. See Note 5, Fair Value of Financial Instruments, for a further discussion of fair value of financial instruments. Asset Retirement Obligations The Company accounts for AROs in accordance with ASC 410-20, Asset Retirement Obligations, or ASC 410-20. Retirement obligations associated with long-lived assets included within the scope of ASC 410-20 are those for which a legal obligation exists under enacted laws, statutes, and written or oral contracts, including obligations arising under the doctrine of promissory estoppel, and for which the timing and/or method of settlement may be conditional on a future event. ASC 410-20 requires an entity to recognize the fair value of a liability for an ARO in the period in which it is incurred and a reasonable estimate of fair value can be made. Upon initial recognition of a liability for an ARO, the Company capitalizes the asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount. Over time, the liability is accreted to its future value, while the capitalized cost is depreciated over the useful life of the related asset. See Note 14, Asset Retirement Obligations, for a further discussion of AROs. Pensions and Other Postretirement Benefits The Company offers pension benefits through a defined benefit pension plan. In addition, the Company provides postretirement health and welfare benefits for certain groups of employees. The Company accounts for pension and other postretirement benefits in accordance with ASC 715, Compensation — Retirement Benefits , or ASC 715 . The Company recognizes the funded status of the Company's defined benefit plans in the statement of financial position and records an offset for gains and losses as well as all prior service costs that have not been included as part of the Company's net periodic benefit cost to other comprehensive income. The determination of the Company's obligation and expenses for pension benefits is dependent on the selection of certain assumptions. These assumptions determined by management include the discount rate, the expected rate of return on plan assets and the rate of future compensation increases. The Company's actuarial consultants assist in determining assumptions for such items as retirement age. The assumptions used may differ materially from actual results, which may result in a significant impact to the amount of pension obligation or expense recorded by the Company. The Company measures the fair value of its pension assets in accordance with ASC 820, Fair Value Measurements and Disclosures, or ASC 820. Stock-Based Compensation The Company accounts for its stock-based compensation in accordance with ASC 718, Compensation — Stock Compensation, or ASC 718 . The fair value of the Company's performance stock units is estimated on the date of grant using a Monte Carlo valuation model. NRG uses the Company's common stock price on the date of grant as the fair value of the Company's deferred stock units. The fair value of the Company's restricted stock units is derived from the closing price of NRG's common stock at the grant date. Forfeiture rates are estimated based on an analysis of the Company's historical forfeitures, employment turnover, and expected future behavior. The Company recognizes compensation expense for both graded and cliff vesting awards on a straight-line basis over the requisite service period for the entire award. Investments Accounted for by the Equity Method The Company has investments in various domestic energy projects, as well as one Australian project. The equity method of accounting is applied to such investments in affiliates, which include joint ventures and partnerships, because the ownership structure prevents the Company from exercising a controlling influence over the operating and financial policies of the projects. Under this method, equity in pre-tax income or losses of domestic partnerships and, generally, in the net income or losses of its Australian project, are reflected as equity in earnings of unconsolidated affiliates. Distributions from equity method investments that represent earnings on the Company's investment are included within cash flows from operating activities and distributions from equity method investments that represent a return of the Company's investment are included within cash flows from investing activities. Tax Equity Arrangements 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. 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 98 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, which was the Company's last remaining tax equity arrangement. Redeemable Noncontrolling Interest The following table reflects the changes in the Company's redeemable noncontrolling interest balance for the years ended December 31, 2020 and 2019. (In millions) Balance as of December 31, 2018 $ 19 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 $ — Sale-Leaseback Arrangements NRG is party to sale-leaseback arrangements that provide for the sale of certain assets to a third party and simultaneously leases back the same asset to the Company. If the seller-lessee transfers control of the underlying assets to the buyer-lessor, the arrangement is accounted for under ASC 842-40, Sale-Leaseback Transactions. These arrangements are classified as operating leases on the Company's consolidated balance sheets. See Note 10, Leases, for further discussion. Marketing and Advertising Costs The Company expenses its marketing and advertising costs as incurred and includes them within selling, general and administrative expenses. The costs of tangible assets used in advertising campaigns are recorded as fixed assets or deferred advertising costs and amortized as advertising costs over the shorter of the useful life of the asset or the advertising campaign. The Company has several long-term sponsorship arrangements. Payments related to these arrangements are deferred and expensed over the term of the arrangement. Advertising expenses for the years ended December 31, 2021, 2020 and 2019 were $ 109 million, $ 74 million and $ 66 million, respectively. Business Combinations The Company accounts for its business combinations in accordance with ASC 805, Business Combinations, or ASC 805, which requires an acquirer to recognize and measure in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at fair value at the acquisition date. The Company also recognizes and measures the goodwill acquired or a gain from a bargain purchase in the business combination. In addition, transaction costs are expensed as incurred. Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates. In recording transactions and balances resulting from business operations, the Company uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, tax provisions, uncollectible accounts, actuarially determined benefit costs, the valuation of energy commodity contracts, environmental liabilities, legal costs incurred in connection with recorded loss contingencies, and assets acquired and liabilities assumed in business combinations, among others. In addition, estimates are used to test long-lived assets and goodwill for impairment and to determine the fair value of impaired assets. As better information becomes available or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates. 99 Reclassifications Certain prior period amounts have been reclassified for comparative purposes. The reclassifications did not affect results from operations, net assets or cash flows. Recent Accounting Developments - Guidance Adopted in 2021 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 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. This ASU also includes guidance to reduce complexity in certain areas, including recognizing deferred taxes for tax goodwill and allocating taxes to members of a consolidated group. ASU 2019-12 is effective for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years. 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. 100 Note 3 — Revenue Recognition The Company's policies with respect to its various revenue streams are detailed below. The Company generally applies the invoicing practical expedient to recognize revenue for the revenue streams detailed below, except in circumstances where the invoiced amount does not represent the value transferred to the customer. Retail Revenue Gross revenues for energy sales and services to retail customers are recognized as the Company transfers the promised goods and services to the customer. For the majority of its electricity and natural gas contracts, the Company’s performance obligation with the customer is satisfied over time and performance obligations for its electricity and natural gas products are recognized as the customer takes possession of the product. The Company also allocates the contract consideration to distinct performance obligations in a contract for which the timing of the revenue recognized is different. Additionally, customer discounts and incentives reduce the contract consideration and are recognized over the term of the contract. Energy sales and services that have been delivered but not billed by period end are estimated. Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter reading provided by the independent system operators, utilities, or electric distribution companies. Volume estimates are based on daily forecasted volumes and estimated customer usage by class. Unbilled revenues are calculated by multiplying these volume estimates by the applicable rate by customer class. Estimated amounts are adjusted when actual usage is known and billed. As contracts for retail electricity and natural gas can be for multi-year periods, the Company has performance obligations under these contracts that have not yet been satisfied. These performance obligations have transaction prices that are both fixed and variable, and that vary based on the contract duration, customer type, inception date and other contract-specific factors. For the fixed price contracts, the amount of any unsatisfied performance obligations will vary based on customer usage, which will depend on factors such as weather and customer activity and therefore it is not practicable to estimate such amounts. Energy Revenue Both physical and financial transactions consist of revenues billed to a third party at either market or negotiated contract terms to optimize the financial performance of the Company's generating facilities. Electric energy revenue is recognized upon transmission to the customer over time, using the output method for measuring progress of satisfaction of performance obligations. Physical transactions, or the sale of generated electricity to meet supply and demand, are recorded on a gross basis in the Company's consolidated statements of operations. The Company applies the invoicing practical expedient in recognizing energy revenue. Under the practical expedient, revenue is recognized based on the invoiced amount which is equal to the value to the customer of NRG’s performance obligation completed to date. Financial transactions used to hedge the sale of electricity are recorded net within 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 The Company's largest sources of capacity revenues are capacity auctions in PJM, ISO-NE and NYISO. Capacity revenues also include revenues billed to a third party at either market or negotiated contract terms for making installed generation and demand response capacity available in order to satisfy system integrity and reliability requirements. Capacity revenues are recognized over time, using the output method for measuring progress of satisfaction of performance obligations. The Company applies the invoicing practical expedient in recognizing capacity revenue. Under the practical expedient, revenue is recognized based on the invoiced amount which is equal to the value to the customer of NRG’s performance obligation completed to date. Performance Obligations As of December 31