Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The discussion and analysis below has been organized as follows:

• Executive summary, including introduction and overview, business strategy, and changes to the business environment

during the period, including environmental and regulatory matters;

• Results of operations;

• Financial condition, addressing liquidity position, sources and uses of liquidity, capital resources and requirements,

commitments, and off-balance sheet arrangements; and

• Known trends that may affect NRG's results of operations and financial condition in the future.

As you read this discussion and analysis, refer to NRG's Condensed Consolidated Statements of Operations to this Form 10-Q, which present the results of operations for the three and nine months ended September 30, 2021 and 2020. Also refer to NRG's 2020 Form 10-K, which includes detailed discussions of various items impacting the Company's business, results of operations and financial condition, including: General section; Strategy section; Business Overview section, including how regulation, weather, and other factors affect NRG's business; and Critical Accounting Policies and Estimates section.

Executive Summary

Introduction and Overview

NRG is a consumer services company built on dynamic retail brands with diverse generation assets. NRG brings the power of energy to customers by producing and selling energy and related products and services, nation-wide in the U.S. and Canada in a manner that delivers value to all of NRG's stakeholders. The Company sells energy, services, and innovative, sustainable solutions and advisory services to approximately 6 million Home customers under the names NRG, Reliant, Direct Energy, Green Mountain Energy, Stream, and XOOM Energy, as well as other brand names owned by NRG, supported by approximately 23,000 MW of generation, including approximately 4,850 MW of fossil generation assets held for sale as of September 30, 2021 and approximately 1,600 MW of its PJM coal fleet with a retirement date of June 2022.

Strategy

NRG's strategy is to maximize stockholder value through the safe production and sale of reliable power and gas to its customers in the markets it serves, while positioning the Company to provide innovative solutions to the end-use energy or service consumer. This strategy is intended to enable the Company to optimize the integrated model to generate stable and predictable cash flow, significantly strengthen earnings and cost competitiveness, and lower risk and volatility.

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 existing assets; (iv) optimal hedging of NRG's portfolio; and (v) engaging in disciplined and transparent capital allocation.

The Company is implementing a four-year plan beginning in 2022 to invest $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 our core network in both power and home services.

Sustainability is an integral part of NRG's strategy and ties directly to business success, reduced risks and brand value. In 2019, NRG announced the acceleration of its science-based GHG emissions reduction goals to align with prevailing climate science, which seeks to limit global warming in the post-industrial era to 1.5 degrees Celsius. NRG is targeting a 50% reduction by 2025, from its current 2014 baseline, and net-zero emissions by 2050.

Energy Regulatory Matters

The Company’s regulatory matters are described in the Company’s 2020 Form 10-K in Item 1, Business — Regulatory Matters. These matters have been updated below and in Note 17, 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. The framework 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. "Build Back Better" is currently on two tracks in Congress, with a bipartisan, $1.2 trillion "core infrastructure" bill that is awaiting a vote in the U.S. House of Representatives and a budget reconciliation bill to address additional priorities that is still being drafted by both Chambers. Both are expected to come to a vote by the end of the year, if not before. NRG is closely monitoring both legislative and executive agency action and expects to be an active participant as these legislative proposals are shaped and finalized.

On April 22, 2021, the President announced that the United States' Nationally Defined Contribution to the international Paris Climate Agreement will be an economy-wide reduction in greenhouse gas emissions of 50-52% by 2030, relative to 2005 levels. Further regulatory climate-related announcements are likely from the Biden Administration in the lead up to the Conference of the Parties 26 meeting being held in early November in Glasgow, Scotland.

State and Provincial Energy Regulation

Illinois Legislation — Illinois Governor J.B. Pritzker signed the Climate and Equitable Jobs Act (Public Act 102-0662) into law on September 15, 2021, which targets 100% clean energy by 2050. Three key provisions of the new law are decarbonization, incentives to transition coal plants into clean energy facilities and nuclear subsidies. The new law will require non-public coal or oil electric generating units larger than 25 MWs to permanently reduce all CO2e and copollutant emissions to zero no later than January 1, 2030. Non-public electric generating units that use gas as a fuel must permanently reduce all CO2e and copollutant emissions to zero, 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 an environmental justice community. The new energy law also provides $173 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 and tariff changes that occur in the ISO regions. For further discussion on regulatory developments see Note 17, Regulatory Matters.

Texas

Legislative Activity Post-Winter Storm Uri — The Texas Legislature has conducted committee hearings during its Special Sessions to continue to evaluate the design of the ERCOT wholesale market and the weatherization of sources of power and fuel supply and related infrastructure. The PUCT is engaged in extensive rulemaking proposals to implement legislation passed during the Regular Session, most notably in response to Senate Bill ("SB") 3, the comprehensive package of electric industry reforms passed in the wake of Winter Storm Uri.

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 adjust the High System Wide Offer cap ("HCAP") from $9,000 MWh to $4,500 MWh. Several stakeholders have filed comments advocating that any adjustment to the HCAP should be implemented in connection with reforms to the Operating Reserves Demand Curve ("ORDC") to ensure prices in the competitive market appropriately reflect the value of operating reserves. This rulemaking project is currently pending, with an expected resolution either at the end of 2021 or early 2022.

In accordance with SB3, Chairman Lake, has announced that he intends to release a "blueprint" for ERCOT market design reforms this fall. Stakeholders filed proposed market-design revisions on September 30, 2021. Proposals include extensions of the ORDC, the introduction of new reserves products for dispatchable capacity and winter fuel, and the institution of a load-serving entity reliability obligation that would require forward bilateral contracting during seasons of projected resource inadequacy.

Activity on Securitization and ERCOT Pricing during Winter Storm Uri — The Texas Legislature acted to pass a variety of securitization vehicles, including House Bill ("HB") 4492, to finance exceptionally high power and gas costs from Winter Storm Uri. HB4492 provides for approximately $800 million in financing to cover short payments resulting from defaults and up to $2.1 billion for highly priced ancillary service and operating reserve deployment adders ("ORDPA") during the event.

On July 16, 2021, ERCOT filed two applications requesting the PUCT to issue Debt Obligation Orders (DOOs") in relation to these two categories of cost in Docket No. 52321 and 52322. On September 20, 2021, an unopposed partial settlement was filed in Docket No. 52322, related to ERCOT's application for the $2.1 billion in ancillary service and ORDPA charges. On October 13, 2021, the PUCT issued an Order adopting the settlement's methodology for allocation of proceeds based on a load serving entity's ("LSEs") 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. The PUCT also issued an Order on October 13, 2021 to approve ERCOT's application for financing of $800 million in default costs under Docket No. 52321.

Under the DOOs, loans or securitized bonds would be issued by ERCOT through a bankruptcy remote special purpose entity as the borrower. The proceeds of these borrowings then would be paid to affected market participants for default-related short payments and to load-serving entities for certain ancillary-servicing and ORDPA costs. In turn, ERCOT would charge non-bypassable fees to all qualified scheduling entities and to all load-serving entities. With respect to ancillary services and ORDPA securitization, HB4492 does provide for a one-time opt-out for certain load-serving entities 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 are required by the law to participate, ensuring the charge established by the law is competitively neutral.

All opt-outs must be filed no later than 45 days following the Commission's October 13, 2021 order. Approximately 55 days after the Commission's order, ERCOT will file with the PUCT a calculation of LSEs' share of proceeds based on the settlement methodology, and LSEs will have 70 days from the date of the Commission's order to validate or challenge this calculation. The opt-outs and calculations noted above will be processed in the PUCT's parallel securitization proceeding, Docket No. 52364. NRG will be obligated to refund or provide invoice adjustments for a portion of whatever it receives to customers to whom relevant costs are passed-through.

With respect to Docket No. 52321, the $800 million proceeds will pay those short-paid market participants and reimburse congestion revenue rights account holders for amounts related to the default of market participants other than electric co-operatives Brazos Electric Power Cooperative, Inc. ("Brazos") and Rayburn Country Electric Cooperative, Inc. ("Rayburn"), which are dealt with separately and discussed below. 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 co-operative utilities, and financial traders. However, the total amount of this uplift is limited by ERCOT's current protocols to $2.5 million per month. Consequently, it would take approximately 99 years for the current net short-pay balance to be uplifted to the market under the current market rules. NRG's undiscounted share of the uplift based on its current market share is estimated to be approximately $189 million and has been short-paid $83 million. The remaining $106 million has been discounted based on the 99 year repayment term and present value of $12 million was recorded as an additional liability. Taken together, HB4492 and SB1580, discussed below, provide an avenue for the complete resolution of market participant defaults and resulting short payments in ERCOT resulting from Winter Storm Uri.

Electric Co-operative Bankruptcy and Securitization — SB1580 provides for and purports to require electric co-operatives with large unpaid balances to ERCOT to securitize those debts and promptly repay ERCOT. If they do not, the law would require the PUCT to order ERCOT to suspend their participation in the wholesale market. To date, the PUCT as not taken an action in this regard.

Of the defaults in the ERCOT market, two electric co-operatives, Brazos and Rayburn, constitute the vast majority. Brazos currently is in bankruptcy. On June 14, 2021, NRG filed a proof of claim in the bankruptcy proceeding of Brazos. On August 18, 2021, Brazos initiated an adversary proceeding challenging ERCOT's claim. To the extent the Bankruptcy Court reduces or disallows ERCOT's claims against Brazos, this could impose a risk on NRG with respect to its claims. Therefore, on September 17, 2021, NRG and similarly situated parties filed a motion in the adversary proceeding. The Bankruptcy Court conducted a hearing on NRG's proposed intervention on October 18, 2021. Trial in the adversary proceeding is currently scheduled for February 21, 2022.

Meanwhile, Rayburn announced in the context of PUCT Docket No. 52322 that it intended to securitize the amounts owed to ERCOT, and as part of the PUCT order in that proceeding, was acknowledged to have opted out of the HB4492 securitization related to ancillary services an ORDPA costs, in view of its intentions to securitize the much larger amount that it continues to owe ERCOT.

Reliability and Plant Operations Standards — The PUCT established Project 51840, a rulemaking to establish weatherization standards, and issued a notice for comments in response to provisions of 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 July 19, 2021, the PUCT filed draft

weatherization standards for discussion purposes, and on July 30,2021, NRG filed comments in response to the draft standards. On August 24, 2021, Commission Staff issued a proposal 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.

Concurrently, FERC Staff and NERC issued preliminary findings of a report entitled February 2021 Cold Weather Grid Operations at the September 23, 2021 FERC open meeting. The agency announced it expects a final report by winter 2021-22. Preliminary recommendations include requiring generation owners subject to NERC reliability standards to meet certain weatherization standards for cold weather. It is not clear how such reliability standards will interact with state-level requirements, or when they would be promulgated through the NERC and FERC regulatory process.

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 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 court upheld PJM’s use of a greenfield gas-fired combustion turbine as the reference unit to establish 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. The outcome could affect PJM’s capacity market prices.

PJM Revisions to Minimum Offer Price Rule — On July 30, 2021, PJM filed a proposed tariff change 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. 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. On October 25, 2021, FERC accepted PJM's request for a delay of the Base Residual Auction for the 2023/2024 Delivery Year from December 1, 2021 until January 25, 2022.

PJM's ORDC Filing and Compliance Directives — On March 29, 2019, PJM proposed energy and reserve market reforms to enhance price formation in reserve markets, which includes modifying its ORDC and aligning market-based reserve products in Day-Ahead and Real-Time markets. On May 21, 2020, FERC approved PJM's proposed energy and reserve market reforms. FERC also directed PJM to implement a forward-looking Energy and Ancillary Services Offset to be used in PJM's capacity markets. PJM submitted a compliance filing to revise its tariff on August 5, 2020. On November 12, 2020, FERC approved two PJM compliance filings regarding PJM's reserve markets and the forward-looking Energy and Ancillary Services Offset. 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 to voluntary remand the case back to the agency. PJM has delayed the implementation of the forward-looking Energy and Ancillary Services Offset until October 1, 2022.

Independent Market Monitor Market Seller Offer Cap Complaint — On February 21, 2019, the Independent Market Monitor filed a complaint alleging that the current Market Seller Offer Cap is too high. A number of parties, including PJM, filed protests to the filing arguing that, among other things, the Market Monitor failed to support its claim that the expected number of performance hours used to calculate the cap is overstated. 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 adopting the PJM Independent Market Monitor's proposal, which effectively eliminates the Market Seller Offer Cap except in very limited situations and requires unit specific cost review by the Independent Market Monitor for the majority of 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. The removal of the Offer Caps may impact the outcome of future Base Residual Auctions.

Indiana Municipal Power Agency and City of Lawrenceburg, Indiana Complaint on Station Power — On September 17, 2020, FERC issued an order in response to a complaint and request for declaratory judgement challenging the station power wholesale netting provisions in PJM's tariff. FERC found that it does not have jurisdiction over the supply of station power and the provision of station power is a retail sale subject to state jurisdiction. The order established a Section 206 proceeding and required PJM to submit a filing to show why the station service netting provisions of its tariff are just and reasonable. Lawrenceburg Power, LLC filed for rehearing, which was denied by operation of law on November 19, 2020 and they subsequently appealed to the D.C. Circuit. The matter is pending. On November 23, 2020, PJM submitted its station power compliance filing to FERC. In an April 27, 2021 Order, FERC found that PJM's Tariff regarding station power netting was unjust and unreasonable, but accepted in part and rejected in part PJM's compliance filing, and required PJM to make an

additional compliance filing within 30 days of the Order. On May 27, 2021, PJM made an additional compliance filing. This decision could affect the rates that plants pay for station power.

New England

Changes to Capacity Markets — FERC held a technical conference on Modernizing Electric Market Design for the New England markets on May 25, 2021. ISO-NE leadership represented that they would work on Minimum Offer Price Rule and other related matters with the expectation of making a filing for FERC's consideration in early 2022. ISO-NE and market participants continue to discuss ISO-NE's proposal to eliminate the Minimum Offer Price Rule in the stakeholder process. Changes to the Forward Capacity Market's mitigation rules may impact the outcome of future Forward Capacity Auctions.

New York

Changes to Capacity Markets — The NYISO and stakeholders are discussing potential capacity market rule changes that may significantly alter the applicability of existing Buyer Side Mitigation rules as well as capacity accreditation. The NYISO plans to file a proposal regarding the capacity market mitigation reforms by late 2021. Changes to NYISO's Buyer Side Mitigation rules may impact the outcome of future capacity auctions.

California

California Resource Adequacy Proceedings — Since a summer 2020 heat storm that resulted in emergency load curtailments, the State of California and CAISO have embarked on numerous new regulatory activities while redirecting existing proceedings related to the topic of resource adequacy. 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. The CPUC and CAISO are also proposing major structural reforms of 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 September 27, 2021, the CAISO gave notice to MSCC extending the term of the RMR Agreement through December 31, 2022. 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.

Canada

Alberta Energy Market — In December 2020, prior to its acquisition by NRG, Direct Energy filed a Non-Energy Rate Application with the Alberta Utilities Commission ("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. The COVID-19 pandemic may prevent the Company from complying with certain of its environmental requirements, which federal and state regulators have recognized. 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 new 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. The Company’s environmental matters are described in the Company’s 2020 Form 10-K in Item 1, Business - Environmental Matters and Item 1A, Risk Factors. These matters have been updated in Note 18, Environmental Matters, to the condensed consolidated financial statements of this Form 10-Q and as follows.

Air

The CAA and the resulting regulations (as well as similar state and local requirements) have the potential to affect air emissions, operating practices and pollution control equipment required at power plants. Under the CAA, the EPA sets NAAQS for certain pollutants including SO2, ozone, and PM2.5. Many of the Company's facilities are located in or near areas that are classified by the EPA as not achieving certain NAAQS (non-attainment areas). The relevant NAAQS 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 CO2 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 CO2 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.

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 2015 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. The Company has updated its estimates of required environmental capital expenditures to address this revised rule.

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 Note 16, Commitments and Contingencies, to the condensed consolidated financial statements.

Nuclear Waste — The federal government's program to construct a nuclear waste repository at Yucca Mountain, Nevada was discontinued in 2010. Since 1998, the U.S. DOE has been in 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.

Effluent Limitations Guidelines — In November 2015, the EPA revised the Effluent Limitations Guidelines for Steam Electric Generating Facilities, which imposed more stringent requirements (as individual permits were renewed) for wastewater streams from FGD, fly ash, bottom ash, and flue gas mercury control. On 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.

Significant Events

The following significant events have occurred during 2021 as further described within this Management's Discussion and Analysis and the condensed consolidated financial statements:

Financing Activities

On August 23, 2021, the Company issued $1,100 million 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.

On August 24, 2021, the Company redeemed $1,355 million in aggregate principal of its Senior Notes for $1,425 million using the proceeds of the 2032 Senior Notes and cash on hand, resulting in total deleveraging of $255 million. In connection with the redemptions, a $57 million loss on debt extinguishment was recorded, which included the write-off of previously deferred financing costs of $9 million, during the nine months ended September 30, 2021. As a result of these financing activities, annualized interest savings are expected to be approximately $53 million. The Company redeemed an additional $500 million of its 6.625% Senior Notes due 2027 during October 2021.

Extreme Weather Event in Texas During February 2021

During February 2021, Texas experienced unprecedented cold temperatures for a prolonged duration, 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.

During the nine months ended September 30, 2021, Winter Storm Uri's financial impact to loss before income taxes was a loss of $1.1 billion. A number of factors may mitigate or increase the financial impact, such as recently passed regulatory securitization packages, finalizing meter and settlement data, potential customer and counterparty risk including ERCOT's shortfall payments and uplift charges, and one-time cost savings.

Direct Energy Acquisition

On January 5, 2021, the Company acquired Direct Energy, 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.

The Company paid an aggregate purchase price of $3.625 billion in cash and an initial 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 purchase price adjustment resulted in a reduction of $3 million, which is in negotiation with Centrica. The Company expects to receive this payment from Centrica during 2021. NRG expects to realize annual synergies of $175 million, $225 million, and $300 million in 2021, 2022, and 2023, respectively.

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, Unit 1 is expected to remain on an outage until the second quarter of 2022.

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. 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, Note 8, Impairments. The Company is continuing to evaluate the viability of the remaining PJM generating assets in light of the auction results.

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. On October 21, 2019, the Company had repaid the Agua Caliente Borrower 1 notes associated with the project of $83 million.

Sale of 4.8 GW of Fossil Generation Assets

On February 28, 2021, the Company entered into a definitive purchase agreement with Generation Bridge, an affiliate of ArcLight Capital Partners, to sell approximately 4,850 MW of fossil generating assets from its East and West regions of operations for total proceeds of $760 million, subject to standard purchase price adjustments and certain other indemnifications. The purchase price adjustments will include a working capital 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 cash flows generated during the year. As part of the transaction, NRG is entering into a tolling agreement for its 866 MW Arthur Kill plant in New York City through April 2025.

The transaction is expected to close by the end of 2021 and is subject to various closing conditions, approvals and consents, including approval from the NYPSC. The transaction has received FERC approval and approval under the Hart-Scott-Rodino Act.

Renewable Power Purchase Agreements

The Company's strategy is to procure mid to long-term generation through power purchase agreements. As of September 30, 2021, NRG has entered into PPAs totaling approximately 2.7 GW with third-party project developers and other counterparties. The tenor of these agreements is an average of twelve years. The Company expects to continue evaluating and executing similar agreements that support the needs of the business.

COVID-19

As the COVID-19 pandemic continues, NRG remains focused on protecting the health and well-being of its employees, while supporting its customers and the communities in which it operates and assuring the continuity of its operations. During 2020, NRG migrated a substantial portion of its employees to a remote work environment. The first COVID-19 vaccine became available in the United States in December 2020. Vaccines have become increasingly accessible since the initial rollout and all adults across the nation became eligible to receive a vaccine as of April 19, 2021. The Company has completed its phased approach to return employees to the offices following a set of safety protocols to ensure employee well-being.

While the pandemic presents risks to the Company's business, as further described in the Company’s 2020 Form 10-K in Part II, Item 1A — Risk Factors, there was not a material adverse impact on the Company’s results of operations for the nine months ended September 30, 2021. NRG believes it has sufficient liquidity on hand to continue business operations in light of current circumstances posed by the pandemic. As disclosed in the Liquidity and Capital Resources section, the Company has total available liquidity of $3.3 billion as of September 30, 2021, consisting of cash on hand, its Revolving Credit Facility, and additional facilities.

The situation surrounding COVID-19 remains fluid and the potential for a material adverse impact on the Company exists as long as the virus impacts the level of economic activity in the United States and abroad. While the Company expects the risk to decrease as vaccinations continue to be administered, NRG cannot reasonably estimate with any degree of certainty the full impact COVID-19, nor any resurgence of COVID-19, may have on the Company’s results of operations, financial position, and liquidity. The extent to which the COVID-19 pandemic may impact the Company’s business, operating results, financial condition, risk exposure or liquidity will depend on future developments, including the duration of the pandemic, travel restrictions, business and workforce disruptions, any resurgence of the pandemic and the effectiveness of actions taken to contain, mitigate and treat the disease.

Trends Affecting Results of Operations and Future Business Performance

Except as set forth below, the Company’s trends are described in the Company’s 2020 Form 10-K in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations - Business Environment.

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 United States. These factors are impacting the dispatch of generation facilities, as well as the costs to serve our retail customers in the markets in which we operate. The Company expects supply chain disruptions will continue throughout the remainder of 2021 and into 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.

Changes in Accounting Standards

See Note 2, Summary of Significant Accounting Policies, for a discussion of recent accounting developments.

Consolidated Results of Operations

The following table provides selected financial information for the Company:

			Three months ended September 30,																		Nine months ended September 30,
(In millions, except as otherwise noted)			2021						2020						Change						2021						2020						Change
Operating Revenues
Retail revenue			$	5,951					$	2,302					$	3,649					$	16,929					$	5,795					$	11,134
Energy revenue(a)			336						222						114						989						429						560
Capacity revenue(a)			189						174						15						615						518						97
Mark-to-market for economic hedging activities			3						39						(36)						(99)						78						(177)
Contract amortization			(3)						—						(3)						(19)						—						(19)
Other revenues(a)(b)			133						72						61						1,528						246						1,282
Total operating revenues			6,609						2,809						3,800						19,943						7,066						12,877
Operating Costs and Expenses
Cost of fuel			465						300						(165)						1,530						666						(864)
Purchased power			3,212						439						(2,773)						9,039						1,162						(7,877)
Other cost of sales (c)			1,430						776						(654)						5,735						1,971						(3,764)
Mark-to-market for economic hedging activities			(1,782)						157						1,939						(4,122)						65						4,187
Contract and emissions credit amortization (c)			(45)						2						47						19						4						(15)
Operations and maintenance			332						265						(67)						1,036						837						(199)
Other cost of operations			80						95						15						259						220						(39)
Cost of operations (excluding depreciation and amortization shown below)			3,692						2,034						(1,658)						13,496						4,925						(8,571)
Depreciation and amortization			199						99						(100)						569						318						(251)
Impairment losses			—						29						29						306						29						(277)
Selling, general and administrative costs			318						216						(102)						973						592						(381)
Provision for credit losses			64						26						(38)						715						74						(641)
Acquisition-related transaction and integration costs			17						12						(5)						81						13						(68)
Total operating costs and expenses			4,290						2,416						(1,874)						16,140						5,951						(10,189)
Gain on sale of assets			—						—						—						17						6						11
Operating Income			2,319						393						1,926						3,820						1,121						2,699
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates			15						36						(21)						23						37						(14)
Impairment losses on investments			—						—						—						—						(18)						18
Other income, net			8						11						(3)						42						52						(10)
Loss on debt extinguishment, net			(57)						—						(57)						(57)						(1)						(56)
Interest expense			(122)						(99)						(23)						(374)						(292)						(82)
Total other expense			(156)						(52)						(104)						(366)						(222)						(144)
Income Before Income Taxes			2,163						341						1,822						3,454						899						2,555
Income tax expense			545						92						(453)						840						216						(624)
Net Income			$	1,618					$	249					$	1,369					$	2,614					$	683					$	1,931
Business Metrics
Average natural gas price — Henry Hub ($/MMBtu)			$	4.01					$	1.98					103		%				$	3.18					$	1.88					69		%

(a) Includes gains and losses from financially settled transactions

(b) Includes trading gains and losses and ancillary revenues

(c) Includes amortization of SO2 and NOx credits and excludes amortization of RGGI credits

Management’s discussion of the results of operations for the three months ended September 30, 2021 and 2020

Electricity Prices

The following table summarizes average on peak power prices for each of the major markets in which NRG operates for the three months ended September 30, 2021 and 2020. The average on-peak power prices increased across the regions for the three months ended September 30, 2021 as compared to the same period in 2020 as a result of higher natural gas prices.

			Average on Peak Power Price ($/MWh)
			Three months ended September 30,
Region			2021						2020						Change %
Texas
ERCOT - Houston(a)			$	47.11					$	28.59					65		%
ERCOT - North(a)			46.16						27.91						65		%
East
NY J/NYC(b)			$	54.75					$	27.32					100		%
NEPOOL(b)			52.57						27.20						93		%
COMED (PJM)(b)			48.36						25.82						87		%
PJM West Hub(b)			51.32						28.24						82		%
West
MISO - Louisiana Hub(b)			$	44.95					$	24.83					81		%
CAISO - SP15(b)			72.02						61.94						16		%

(a) Average on peak power prices based on real time settlement prices as published by the respective ISOs

(b) Average on peak power prices based on day ahead settlement prices as published by the respective ISOs

The following table summarizes average realized power prices for NRG, including the impact of settled hedges, for the three months ended September 30, 2021 and 2020:

			Average Realized Power Price ($/MWh)
			Three months ended September 30,
Segment			2021						2020						Change %
East(a)			$	37.26					$	31.23					19		%
West/Services/Other			50.31						48.39						4		%

(a) Average Realized Power Price reflects energy sales from the generation fleet, omitting sales to the retail component of the East Segment. Intercompany financial transactions hedging generation with the retail business make up ($9.84)/MWh in the three months ended September 30, 2021 and $4.09/MWh in the three months ended September 30, 2020

The average realized power prices increased in East and West/Services/Other for the three months ended September 30, 2021 as compared to the same period in 2020, as a result of the Company's multi-year hedging program and higher natural gas prices.

Gross Margin

The Company calculates gross margin in order to evaluate operating performance as operating revenues less cost of fuel, purchased power, other costs of sales, mark-to-market for economic hedging activities, contract and emission credit amortization and depreciation and amortization.

Economic Gross Margin

In addition to gross margin, the Company evaluates its operating performance using the measure of economic gross margin, which is not a GAAP measure and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Economic gross margin should be viewed as a supplement to and not a substitute for the Company's presentation of gross margin, which is the most directly comparable GAAP measure. Economic gross margin is not intended to represent gross margin. The Company believes that economic gross margin is useful to investors as it is a key operational measure reviewed by the Company's chief operating decision maker. Economic gross margin is defined as the sum of energy revenue, capacity revenue, retail revenue and other revenue, less cost of fuel, purchased power and other cost of sales. Economic gross margin does not include mark-to-market gains or losses on economic hedging

activities, contract and emissions credit amortization, or depreciation and amortization, operations and maintenance, or other cost of operations.

The below tables present the composition and reconciliation of gross margin and economic gross margin for the three months ended September 30, 2021 and 2020:

			Three months ended September 30, 2021
($ In millions)			Texas						East						West/Services/Other															Corporate/Eliminations						Total
Retail revenue			$	2,503					$	2,698					$	750														$	—					$	5,951
Energy revenue			18						201						113															4						336
Capacity revenue			—						172						17															—						189
Mark-to-market for economic hedging activities			(1)						(3)						(6)															13						3
Contract amortization			—						(7)						4															—						(3)
Other revenue(a)			115						16						6															(4)						133
Operating revenue			2,635						3,077						884															13						6,609
Cost of fuel			(305)						(93)						(69)															1						(466)
Purchased power			(583)						(2,295)						(331)															(2)						(3,211)
Other cost of sales(b)(c)(d)			(909)						(194)						(327)															—						(1,430)
Mark-to-market for economic hedging activities			(81)						1,786						90															(13)						1,782
Contract and emission credit amortization			(7)						61						(9)															—						45
Depreciation and amortization			(84)						(88)						(20)															(7)						(199)
Gross margin			$	666					$	2,254					$	218														$	(8)					$	3,130
Less: Mark-to-market for economic hedging activities, net			(82)						1,783						84															—						1,785
Less: Contract and emission credit amortization, net			(7)						54						(5)															—						42
Less: Depreciation and amortization			(84)						(88)						(20)															(7)						(199)
Economic gross margin			$	839					$	505					$	159														$	(1)					$	1,502
(a) Includes trading gains and losses and ancillary revenues
(b) Includes capacity and emissions credits
(c) Includes $802 million and $8 million of TDSP expense in Texas and East, respectively
(d) Excludes depreciation and amortization shown separately
Business Metrics
Retail sales
Home electricity sales volume (GWh)			13,486						4,032						512																					18,030
Business electricity sales volume (GWh)			10,583						14,794						2,672																					28,049
Home natural gas sales volume (MDth)			—						5,148						6,580																					11,728
Business natural gas sales volume (MDth)			—						334,503						20,666																					355,169
Average retail Home customer count (in thousands) (a)			3,030						1,819						960																					5,809
Ending retail Home customer count (in thousands) (a)			3,043						1,784						954																					5,781
Power generation
GWh sold			11,841						4,267						2,246																					18,354
GWh generated:(b)
Coal			5,558						2,375						—																					7,933
Gas			3,756						750						1,970																					6,476
Nuclear			2,527						—						—																					2,527
Oil			—						106						—																					106
Total			11,841						3,231						1,970																					17,042
(a) Home customer count includes recurring residential customers and municipal aggregations, as well as recurring Services customers
(b) Includes owned and leased generation, as well as tolls, and excludes equity investments

			Three months ended September 30, 2020
($ In millions)			Texas						East						West/Services/Other												Corporate/Eliminations						Total
Retail revenue			$	1,921					$	354					$	27											$	—					$	2,302
Energy revenue			11						93						117												1						222
Capacity revenue			—						158						16												—						174
Mark-to-market for economic hedging activities			1						43						(10)												5						39
Other revenue			59						18						(1)												(4)						72
Operating revenue			1,992						666						149												2						2,809
Cost of fuel			(206)						(58)						(36)												—						(300)
Purchased power			(287)						(140)						(13)												1						(439)
Other cost of sales(a)(b)(c)			(647)						(103)						(26)												—						(776)
Mark-to-market for economic hedging activities			(153)						2						(1)												(5)						(157)
Contract and emission credit amortization			(2)						—						—												—						(2)
Depreciation and amortization			(49)						(33)						(10)												(7)						(99)
Gross margin			$	648					$	334					$	63											$	(9)					$	1,036
Less: Mark-to-market for economic hedging activities, net			(152)						45						(11)												—						(118)
Less: Contract and emission credit amortization, net			(2)						—						—												—						(2)
Less: Depreciation and amortization			(49)						(33)						(10)												(7)						(99)
Economic gross margin			$	851					$	322					$	84											$	(2)					$	1,255
(a) Includes capacity and emissions credits
(b) Includes $595 million and $3 million of TDSP expense in Texas and East, respectively
(c) Excludes depreciation and amortization shown separately
Business Metrics
Retail sales
Home electricity sales volume (GWh)			12,849						3,028						—																		15,877
Business electricity sales volume (GWh)			4,886						439						—																		5,325
Home natural gas sales volume (MDth)			—						1,850						—																		1,850
Average retail Home customer count (in thousands)(a)			2,452						1,154						—																		3,606
Ending retail Home customer count (in thousands)(a)			2,460						1,139						—																		3,599
Power generation
GWh sold			11,294						3,426						2,418																		17,138
GWh generated(b)
Coal			5,265						1,110						—																		6,375
Gas			3,102						1,089						2,200																		6,391
Nuclear			2,531						—						—																		2,531
Oil			—						174						—																		174
Total			10,898						2,373						2,200																		15,471
(a) Home customer count includes recurring residential customers and municipal aggregations
(b) Includes owned and leased generation, and excludes equity investments

The table below represents the weather metrics for the three months ended September 30, 2021 and 2020:

			Three months ended September 30,
Weather Metrics			Texas						East						West/Services/Other (b)
2021
CDDs (a)			1,589						784						1,134
HDDs (a)			—						38						5
2020
CDDs			1,640						874						1,152
HDDs			6						72						4
10-year average
CDDs			1,690						818						1,159
HDDs			2						56						10

(a) National Oceanic and Atmospheric Administration-Climate Prediction Center - A Cooling Degree Day, or CDD, represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. A Heating Degree Day, or HDD, represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period

(b) The West/Services/Other weather metrics are comprised of the average of the CDD and HDD regional results for the West - California and West - South Central regions

Gross Margin and Economic Gross Margin

Gross margin increased $2.1 billion and economic gross margin increased $247 million during the three months ended September 30, 2021, compared to the same period in 2020.

The tables below describe the changes in gross margin and economic gross margin by segment:

Texas

			(In millions)
Higher gross margin due to Winter Storm Uri, primarily due to ERCOT 180 day settlements			$	13
The following explanations exclude the impact of Winter Storm Uri:
Lower gross margin primarily due to a 20% increase in overall average costs to serve the retail load, driven primarily by increases in power and fuel costs of $110 million; partially offset by increased net revenue rates as a result of changes in customer term, product and mix of $0.60 per MWh, or $12 million			(98)
Lower net revenue due to a decrease in load of 290,000 MWhs from weather			(24)
Higher gross margin due to increased volumes from the acquisition of Direct Energy in January 2021			59
Higher gross margin from market optimization activities			29
Higher net revenue due to customer mix			4
Other			5
Decrease in economic gross margin			$	(12)
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges			70
Increase in contract and emission credit amortization			(5)
Increase in depreciation and amortization			(35)
Increase in gross margin			$	18

East

						(In millions)
Higher gross margin due to increased volumes from the acquisition of Direct Energy in January 2021, including $153 million from power and $59 million from natural gas						$	212
Higher gross margin from market optimization activities						6
Higher gross margin due to an 18% increase in PJM capacity volumes, partially offset by a 12% decrease in New England capacity prices and a 5% decrease in New York realized capacity prices						5
Lower gross margin from higher supply costs of $11.75 per MWh, or $39 million and lower volumes due to attrition, weather and customer mix of $22 million, partially offset by higher revenue of $5.75 per MWh, or $19 million						(42)
Other						2
Increase in economic gross margin						$	183
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges						1,738
Decrease in contract amortization						54
Increase in depreciation and amortization						(55)
Increase in gross margin						$	1,920

West/Services/Other

			(In millions)
Higher gross margin due to increased volumes from the acquisition of Direct Energy in January 2021			$	104
Higher gross margin due to commercial optimization activities			12
Lower gross margin primarily due to prior year MISO uplift payments resulting from out-of-market dispatch during Hurricane Laura			(30)
Lower gross margin at the gas plants due to a 111% increase in fuel cost while realized power prices remained constant			(15)
Other			4
Increase in economic gross margin			$	75
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges			95
Increase in contract amortization			(5)
Increase in depreciation and amortization			(10)
Increase in gross margin			$	155

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 $1.9 billion during the three months ended September 30, 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:

			Three months ended September 30, 2021
(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					$	(1)					$	2											$	(1)					$	1
Reversal of acquired (gain) positions related to economic hedges			—						(2)						—												—						(2)
Net unrealized (losses)/gains on open positions related to economic hedges			(2)						—						(8)												14						4
Total mark-to-market (losses)/gains in operating revenues			$	(1)					$	(3)					$	(6)											$	13					$	3
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges			$	(99)					$	(2)					$	2											$	1					$	(98)
Reversal of acquired (gain)/loss positions related to economic hedges			(47)						31						(24)												—						(40)
Net unrealized gains on open positions related to economic hedges			65						1,757						112												(14)						1,920
Total mark-to-market (losses)/gains in operating costs and expenses			$	(81)					$	1,786					$	90											$	(13)					$	1,782

			Three months ended September 30, 2020
(In millions)			Texas						East						West/Services/Other												Eliminations						Total
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized losses on settled positions related to economic hedges			$	2					$	25					$	1											$	1					$	29
Net unrealized (losses)/gains on open positions related to economic hedges			(1)						18						(11)												4						10
Total mark-to-market gains/(losses) in operating revenues			$	1					$	43					$	(10)											$	5					$	39
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges			$	(128)					$	(1)					$	—											$	(1)					$	(130)
Reversal of acquired (gain)/loss positions related to economic hedges			(3)						1						—												—						(2)
Net unrealized (losses)/gains on open positions related to economic hedges			(22)						2						(1)												(4)						(25)
Total mark-to-market (losses)/gains in operating costs and expenses			$	(153)					$	2					$	(1)											$	(5)					$	(157)

`

Mark-to-market results consist of unrealized gains and losses on contracts that are not yet settled. The settlement of these transactions is reflected in the same revenue or cost caption as the items being hedged.

For the three months ended September 30, 2021, the $3 million gain in operating revenues from economic hedge positions was driven primarily by an increase in the value of open positions. The $1.8 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 Northeast power prices, partially offset by the reversal of previously recognized unrealized gains on contracts that settled during the period and acquired contracts that settled during the period.

For the three months ended September 30, 2020, the $39 million gain in operating revenues from economic hedge positions was driven primarily by the reversal of previously recognized unrealized losses on contracts that settled during the period as well as an increase in the value of open positions as a result of decreases in New York capacity prices. The $157 million loss in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period as well as a decrease in the value of open positions as a result of increases in natural gas prices and ERCOT heat rate contraction.

In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the three months ended September 30, 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 based on the Company's Risk Management Policy.

			Three months ended September 30,
(In millions)			2021						2020
Trading gains/(losses)
Realized			$	31					$	3
Unrealized			8						(5)
Total trading gains/(losses)			$	39					$	(2)

Operations and Maintenance Expense

Operations and maintenance expense are comprised of the following:

(In millions)			Texas						East						West/Services/Other						Corporate						Eliminations						Total
Three months ended September 30, 2021			$	160					$	121					$	52					$	—					$	(1)					$	332
Three months ended September 30, 2020			147						94						23						2						(1)						265

Operations and maintenance expense increased by $67 million for the three months ended September 30, 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			$	66
Increase in major maintenance primarily due to the duration and scope of forced outages in Texas during the third quarter of 2021			9
Increase in variable operations and maintenance expense driven by higher generation at the PJM coal facilities in the third quarter of 2021			7
Decrease driven by lower retail operations costs			(8)
Decrease in lease expense primarily driven by the buyout of the lease at Midwest Generation in 2020			(6)
Other			(1)
Increase in operations and maintenance expense			$	67

Other Cost of Operations

Other cost of operations are comprised of the following:

(In millions)			Texas						East						West/Services/Other						Total
Three months ended September 30, 2021			$	47					$	31					$	2					$	80
Three months ended September 30, 2020			63						24						8						95

Other costs of operations decreased by $15 million for the three months ended September 30, 2021, compared to the same period in 2020, due to the following:

			(In millions)
Decrease primarily due to ARO expense in 2020 at Jewett Mine as a result of regulatory requirements			$	(21)
Decrease due to lower gross receipt taxes driven by lower retail revenues in legacy brands			(5)
Increase due to the acquisition of Direct Energy in January 2021			16
Other			(5)
Decrease in other cost of operations			$	(15)

Depreciation and Amortization

Depreciation and amortization are comprised of the following:

(In millions)			Texas						East						West/Services/Other						Corporate						Total
Three months ended September 30, 2021			$	84					$	88					$	20					$	7					$	199
Three months ended September 30, 2020			49						33						10						7						99

Depreciation and amortization increased by $100 million primarily due to amortization of acquired intangibles in connection with the acquisition of Direct Energy in January 2021.

Impairment Losses

Impairment losses of $29 million were recorded during the three months ended September 30, 2020 related to advanced negotiations to sell the Home Solar business, as further discussed in Note 8*, Impairments*.

Selling, General and Administrative Costs

Selling, general and administrative costs are comprised of the following:

(In millions)			Texas						East						West/Services/Other						Corporate						Total
Three months ended September 30, 2021			$	148					$	110					$	44					$	16					$	318
Three months ended September 30, 2020			129						68						16						3						216

Selling, general and administrative costs increased by $102 million for the three months ended September 30, 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			$	102
Increase due to higher consulting costs			6
Increase due to higher legal expenses related to Winter Storm Uri and medical expenses			5
Decrease due to the favorable resolution of a legal matter			(15)
Other			4
Increase in selling, general and administrative costs			$	102

Provision for Credit Losses

Provision for credit losses are comprised of the following:

(In millions)			Texas						East						West/Services/Other												Total
Three months ended September 30, 2021			$	58					$	3					$	3											$	64
Three months ended September 30, 2020			24						1						1												26

Provision for credit losses increased by $38 million for the three months ended September 30, 2021, compared to the same period in 2020, due to the following:

			(In millions)
Increase due to Winter Storm Uri, related to counterparty credit risk			$	32
Increase due to the acquisition of Direct Energy in January 2021, partially offset by improved collections in the legacy brands			6
Increase in provision for credit losses			$	38

Acquisition-Related Transaction and Integration Costs

Acquisition-related transaction and integration costs increased $5 million for the three months ended September 30, 2021 compared to the three months ended September 30, 2020 primarily due to the integration of Direct Energy in 2021.

Equity in earnings of unconsolidated affiliates

Equity in earnings of unconsolidated affiliates was $21 million lower for the three months ended September 30, 2021 compared to the three months ended September 30, 2020, primarily due to the sale of the Agua Caliente solar project in the first quarter of 2021 and unfavorable weather resulting in decreased earnings at Ivanpah in 2021.

Loss on debt extinguishment, Net

Loss on debt extinguishment of $57 million was recorded for the three months ended September 30, 2021, in connection with the redemption of senior notes, as further discussed in Note 9*, Long-term Debt and Finance Leases.*

Interest Expense

Interest expense increased by $23 million for the three months ended September 30, 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 three months ended September 30, 2021, an income tax expense of $545 million was recorded on a pre-tax income of $2.2 billion. For the same period in 2020, income tax expense of $92 million was recorded on pre-tax income of $341 million. The effective tax rates were 25.2% and 27.0% for the three months ended September 30, 2021 and 2020, respectively.

For the three months ended September 30, 2021, the effective tax rate was higher than the statutory rate of 21% primarily due to state tax expense. For the same period in 2020, the effective tax rate was higher than the statutory rate of 21% due to state tax expense, partially offset by an excess tax benefit related to share-based compensation.

Management’s discussion of the results of operations for the nine months ended September 30, 2021 and 2020

Electricity Prices

The following table summarizes average on peak power prices for each of the major markets in which NRG operates for the nine months ended September 30, 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 gas prices.

			Average on Peak Power Price ($/MWh)
			Nine months ended September 30,
Region			2021						2020						Change %
Texas
ERCOT - Houston (a)			$	240.14					$	26.09					820		%
ERCOT - North(a)			236.75						24.12						882		%
East
NY J/NYC(b)			$	45.04					$	23.38					93		%
NEPOOL(b)			47.17						24.02						96		%
COMED (PJM)(b)			38.00						22.13						72		%
PJM West Hub(b)			40.04						23.84						68		%
West
MISO - Louisiana Hub(b)			$	40.11					$	23.01					74		%
CAISO - SP15(b)			51.22						36.60						40		%

(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 nine months ended September 30, 2021 and 2020:

			Average Realized Power Price ($/MWh)
			Nine months ended September 30,
Segment			2021						2020						Change %
East(a)			$	37.70					$	33.92					11		%
West/Services/Other			39.97						35.18						14		%

(a) Average Realized Power Price reflects energy sales from the generation fleet, omitting sales to the retail component of the East Segment. Intercompany financial transactions hedging generation with the retail business make up ($5.10)/MWh in the nine months ended September 30, 2021 and $12.10/MWh in the nine months ended September 30, 2020

The average realized power prices fluctuated in the East and West/Services/Other at different rates for the nine months ended September 30, 2021, as compared to the same period in 2020, as a result of the Company's multi-year hedging program, increased natural gas prices and warmer June temperatures in California.

Winter Storm Uri

During the nine months ended September 30, 2021, Winter Storm Uri's financial impact to loss before income taxes was a loss of $1.1 billion. The following impacts are further discussed in the related sections below:

(In millions)			Nine months ended September 30, 2021
Gross margin - Texas			$	(560)
Gross margin - East			146
Gross margin - West/Services/Other			13
Total gross margin			(401)
Operations and maintenance expense			(2)
Selling, general and administrative costs			(29)
Provision for credit losses			(638)
Total impact to loss before income taxes			$	(1,070)

A number of factors may mitigate or increase the financial impact, such as recently passed regulatory securitization packages, potential customer and counterparty risk including ERCOT's shortfall payments and uplift charges, and one-time cost savings.

Gross Margin

The Company calculates gross margin in order to evaluate operating performance as operating revenues less cost of fuel, purchased power, other costs of sales, mark-to-market for economic hedging activities, contract and emission credit amortization and depreciation and amortization.

Economic Gross Margin

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

The below tables present the composition and reconciliation of gross margin and economic gross margin for the nine months ended September 30, 2021 and 2020:

			Nine months ended September 30, 2021
($ In millions)			Texas						East						West/Services/Other												Corporate/Eliminations						Total
Retail revenue			$	6,575					$	8,029					$	2,326											$	(1)					$	16,929
Energy revenue			317						428						238												6						989
Capacity revenue			—						568						47												—						615
Mark-to-market for economic hedging activities			(5)						(53)						(60)												19						(99)
Contract amortization			—						(15)						(4)												—						(19)
Other revenue (a)			1,475						45						17												(9)						1,528
Operating revenue			8,362						9,002						2,564												15						19,943
Cost of fuel			(1,243)						(155)						(133)												1						(1,530)
Purchased power			(1,978)						(6,140)						(919)												(2)						(9,039)
Other cost of sales (b)(c)(d)			(3,570)						(1,045)						(1,120)												—						(5,735)
Mark-to-market for economic hedging activities			1,072						2,849						220												(19)						4,122
Contract and emission credit amortization			—						(8)						(11)												—						(19)
Depreciation and amortization			(245)						(238)						(65)												(21)						(569)
Gross margin			$	2,398					$	4,265					$	536											$	(26)					$	7,173
Less: Mark-to-market for economic hedging activities, net			1,067						2,796						160												—						4,023
Less: Contract and emission credit amortization, net			—						(23)						(15)												—						(38)
Less: Depreciation and amortization			(245)						(238)						(65)												(21)						(569)
Economic gross margin			$	1,576					$	1,730					$	456											$	(5)					$	3,757
(a) Includes trading gains and losses and ancillary revenues
(b) Includes capacity and emissions credits
(c) Includes $2.0 billion and $24 million of TDSP expense in Texas and East, respectively
(d) Excludes depreciation and amortization shown separately
Business Metrics
Retail sales
Home electricity sales volume (GWh)			34,304						11,137						1,649																		47,090
Business electricity sales volume (GWh)			25,180						40,373						7,321																		72,874
Home natural gas sales volume (MDth)			—						53,077						62,200																		115,277
Business natural gas sales volume (MDth)			—						1,141,892						79,712																		1,221,604
Average retail Home customer count (in thousands)(a)			3,059						1,871						968																		5,898
Ending retail Home customer count (in thousands)(a)			3,043						1,784						954																		5,781
Power generation
GWh sold			29,020						10,000						5,954																		44,974
GWh generated (b)
Coal			14,188						4,887						—																		19,075
Gas			7,789						1,324						5,606																		14,719
Nuclear			7,043						—						—																		7,043
Oil			—						189						—																		189
Total			29,020						6,400						5,606																		41,026
(a) Home customer count includes recurring residential customers and municipal aggregations, as well as recurring Services customers
(b) Includes owned and leased generation, as well as tolls, and excludes equity investments

			Nine months ended September 30, 2020
($ In millions)			Texas						East						West/Services/Other												Corporate/Eliminations						Total
Retail revenue			$	4,734					$	996					$	66											$	(1)					$	5,795
Energy revenue			21						157						252												(1)						429
Capacity revenue			—						471						47												—						518
Mark-to-market for economic hedging activities			1						63						6												8						78
Other revenue			172						45						36												(7)						246
Operating revenue			4,928						1,732						407												(1)						7,066
Cost of fuel			(432)						(132)						(102)												—						(666)
Purchased Power			(755)						(389)						(22)												4						(1,162)
Other cost of sales (a) (b) (c)			(1,663)						(271)						(37)												—						(1,971)
Mark-to-market for economic hedging activities			(63)						7						(1)												(8)						(65)
Contract and emission credit amortization			(4)						—						—												—						(4)
Depreciation and amortization			(167)						(97)						(28)												(26)						(318)
Gross margin			$	1,844					$	850					$	217											$	(31)					$	2,880
Less: Mark-to-market for economic hedging activities, net			(62)						70						5												—						13
Less: Contract and emission credit amortization, net			(4)						—						—												—						(4)
Less: Depreciation and amortization			(167)						(97)						(28)												(26)						(318)
Economic gross margin			$	2,077					$	877					$	240											$	(5)					$	3,189
(a) Includes capacity and emissions credits
(b) Includes $1.5 billion and $8 million of TDSP expense in Texas and East, respectively
(c) Excludes depreciation and amortization shown separately
Business Metrics
Retail sales
Home electricity sales volume (GWh)			30,360						7,931						—																		38,291
Business electricity sales volume (GWh)			13,555						1,193						—																		14,748
Natural gas sales volume (MDth)			—						15,949						—																		15,949
Average retail Home customer count (in thousands)(a)			2,446						1,188						—																		3,634
Ending retail Home customer count (in thousands)(a)			2,460						1,139						—																		3,599
Power generation
GWh sold			24,868						7,193						7,163																		39,224
GWh generated (b)
Coal			12,102						1,504						—																		13,606
Gas			5,117						1,717						6,801																		13,635
Nuclear			7,093						—						—																		7,093
Oil			—						258						—																		258
Total			24,312						3,479						6,801																		34,592
(a) Home customer count includes recurring residential customers and municipal aggregations
(b) Includes owned and leased generation, and excludes equity investments

The table below represents the weather metrics for the nine months ended September 30, 2021 and 2020:

			Nine months ended September 30,
Weather Metrics			Texas						East						West/Services/Other (b)
2021
CDDs (a)			2,574						1,184						1,693
HDDs (a)			1,202						2,929						1,398
2020
CDDs			2,822						1,283						1,790
HDDs			867						2,751						1,176
10-year average
CDDs			2,809						1,212						1,767
HDDs			998						2,974						1,270

(a) National Oceanic and Atmospheric Administration-Climate Prediction Center - A Cooling Degree Day, or CDD, represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. A Heating Degree Day, or HDD, represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period

(b) The West/Services/Other weather metrics are comprised of the average of the CDD and HDD regional results for the West-California and West-South Central regions

Gross Margin and Economic Gross Margin

Gross margin increased $4.3 billion and economic gross margin increased $568 million, both of which include intercompany sales, during the nine months ended September 30, 2021, compared to the same period in 2020.

The tables below describe the changes in gross margin and economic gross margin by segment:

Texas

						(In millions)
Lower gross margin due to Winter Storm Uri, primarily driven by an increase in unhedgeable ancillary and operating reserve demand curve						$	(560)
The following explanations exclude the impact of Winter Storm Uri:
Lower gross margin due to a 14% increase in overall average costs to serve the retail load, driven primarily by increases in power and fuel costs, totaling $168 million; partially offset by higher net revenue rates as a result of changes in customer term, product and mix of $2 per MWh, or $96 million						(72)
Lower net revenue due to a decrease in load of 701,000 MWhs from weather						(60)
Lower net revenue due to attrition and customer mix						(52)
Higher gross margin due to increased volumes from the acquisition of Direct Energy in January 2021						227
Higher gross margin due to market optimization activities						14
Other						2
Decrease in economic gross margin						$	(501)
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges						1,129
Decrease in contract and emission credit amortization						4
Increase in depreciation and amortization						(78)
Increase in gross margin						$	554

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 $335 million from power activity and $329 million from natural gas activity			664
Higher business demand response gross margin primarily from the early settlement of capacity obligations in 2021 compared to the same period in 2020			63
Higher gross margin due to a lower of cost or market adjustment on oil inventory in 2020			29
Higher gross margin from market optimization activities			20
Lower gross margin from lower volumes due to attrition, weather and customer mix of $42 million and higher supply costs of $5.50 per MWh, or $41 million, partially offset by higher revenue of $4 per MWh, or $30 million			(53)
Lower gross margin due to a 15% decrease in average realized pricing primarily at Midwest Generation, partially offset by increased volumes due to dark spread expansion in 2021 and planned outages in 2020			(14)
Lower gross margin due to a 20% decrease in New England capacity prices and a 5% decrease in New York capacity volumes, partially offset by a 17% increase in New York realized capacity prices			(7)
Other			5
Increase in economic gross margin			$	853
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges			2,726
Increase in contract amortization			(23)
Increase in depreciation and amortization			(141)
Increase in gross margin			$	3,415

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 increased volumes from the acquisition of Direct Energy in January 2021			304
Lower gross margin primarily at Cottonwood driven by an 84% increase in fuel cost while realized power prices remained constant			(41)
Lower gross margin from generation outage insurance proceeds received in 2020 for forced outages in 2019			(30)
Lower gross margin primarily due to a prior year MISO uplift payments resulting from out-of-market dispatch during Hurricane Laura			(30)
Lower gross margin from market optimization activities			(4)
Other			4
Increase in economic gross margin			$	216
Increase in mark-to-market for economic hedges primarily due to net unrealized gains/losses on open positions related to economic hedges			155
Increase in contract amortization			(15)
Increase in depreciation and amortization			(37)
Increase in gross margin			$	319

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 $4.0 billion during the nine months ended September 30, 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:

			Nine months ended September 30, 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			$	—					$	(20)					$	(2)											$	(2)					$	(24)
Reversal of acquired (gain) positions related to economic hedges			—						(6)						—												—						(6)
Net unrealized (losses) on open positions related to economic hedges			(5)						(27)						(58)												21						(69)
Total mark-to-market (losses) in operating revenues			$	(5)					$	(53)					$	(60)											$	19					$	(99)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges			$	(36)					$	—					$	—											$	2					$	(34)
Reversal of acquired loss/(gain) positions related to economic hedges			20						202						(10)												—						212
Net unrealized gains on open positions related to economic hedges			1,088						2,647						230												(21)						3,944
Total mark-to-market gains in operating costs and expenses			$	1,072					$	2,849					$	220											$	(19)					$	4,122

			Nine months ended September 30, 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					$	29					$	(4)											$	3					$	29
Net unrealized gains on open positions related to economic hedges			—						34						10												5						49
Total mark-to-market gains in operating revenues			$	1					$	63					$	6											$	8					$	78
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges			$	(92)					$	5					$	(1)											$	(3)					$	(91)
Reversal of acquired loss positions related to economic hedges			1						1						—												—						2
Net unrealized gains on open positions related to economic hedges			28						1						—												(5)						24
Total mark-to-market (losses)/gains in operating costs and expenses			$	(63)					$	7					$	(1)											$	(8)					$	(65)

Mark-to-market results consist of unrealized gains and losses on contracts that are not yet settled. The settlement of these transactions is reflected in the same revenue or cost caption as the items being hedged.

For the nine months ended September 30, 2021, the $99 million loss in operating revenues from economic hedge positions was driven by a decrease in the value of open positions as a result of increases in Northeast and West/Other power prices as well as the reversal of previously recognized unrealized gains on contracts that settled during the period. The $4.1 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 period.

For the nine months ended September 30, 2020, the $78 million gain in operating revenues from economic hedge positions was driven by an increase in the value of open positions as a result of decreases in New York capacity and power prices as well as the reversal of previously recognized unrealized losses on contracts that settled during the period. The $65 million loss in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period, partially offset by an increase in the value of open positions as a result of increases in ERCOT power prices.

In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the nine months ended September 30, 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 based on the Company's Risk Management Policy.

			Nine months ended September 30,
(In millions)			2021						2020
Trading gains
Realized			$	99					$	26
Unrealized			2						5
Total trading gains			$	101					$	31

Operations and Maintenance Expense

Operations and maintenance expense are comprised of the following:

(In millions)			Texas						East						West/Services/Other						Corporate						Eliminations						Total
Nine months ended September 30, 2021			$	524					$	346					$	168					$	2					$	(4)					$	1,036
Nine months ended September 30, 2020			480						276						79						6						(4)						837

Operations and maintenance expense increased by $199 million for the nine months ended September 30, 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			$	186
Increase in variable operation and maintenance expense at the PJM coal facilities associated with increased generation in 2021			16
Increase in major maintenance primarily due to the duration and scope of planned and forced outages in Texas during 2021			15
Increase due to spare parts inventory reserves driven by announced retirements of certain PJM coal assets			13
Increase driven by higher maintenance resulting from the impacts of Winter Storm Uri			2
Decrease driven by lower retail operations costs			(18)
Decrease in lease expense primarily driven by the buyout of the Midwest Generation lease in 2020			(16)
Other			1
Increase in operations and maintenance expense			$	199

Other Cost of Operations

Other Cost of operations are comprised of the following:

(In millions)			Texas						East						West/Services/Other																		Total
Nine months ended September 30, 2021			$	144					$	102					$	13																	$	259
Nine months ended September 30, 2020			134						70						16																		220

Other cost of operations increased by $39 million for the nine months ended September 30, 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			$	63
Decrease primarily due to ARO expense in 2020 at Jewett Mine and Joliet as a result of regulatory requirements			(25)
Other			1
Increase in other cost of operations			$	39

Depreciation and Amortization

Depreciation and amortization expenses are comprised of the following:

(In millions)			Texas						East						West/Services/Other						Corporate						Total
Nine months ended September 30, 2021			$	245					$	238					$	65					$	21					$	569
Nine months ended September 30, 2020			167						97						28						26						318

Depreciation and amortization increased by $251 million for the nine months ended September 30, 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

Impairment losses of $306 million were recorded during the nine months ended September 30, 2021, related to the decline in capacity prices and the planned retirement of a significant portion of the PJM coal fleet, as further discussed in Note 8*, Impairments*.

Selling, General and Administrative Costs

Selling, general and administrative costs comprised of the following:

(In millions)			Texas						East						West/Services/Other						Corporate						Eliminations						Total
Nine months ended September 30, 2021			$	435					$	374					$	128					$	37					$	(1)					$	973
Nine months ended September 30, 2020			347						186						40						20						(1)						592

Selling, general and administrative costs increased by $381 million for the nine months ended September 30, 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			$	338
Increase due to Winter Storm Uri, including charitable giving, legal and other costs of $17 million and ERCOT default charges of $12 million			29
Increase due to higher consulting and insurance costs			16
Increase due to higher medical expenses and a reduction of payroll tax benefits			8
Decrease due to the favorable resolution of a legal matter			(15)
Other			5
Increase in selling, general and administrative costs			$	381

Provision for Credit Losses

Provision for credit losses are comprised of the following:

(In millions)			Texas						East						West/Services/Other												Total
Nine months ended September 30, 2021			$	700					$	7					$	8											$	715
Nine months ended September 30, 2020			69						4						1												74

Provision for credit losses increased by $641 million for the nine months ended September 30, 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 $152 million related to counterparty credit risk Increase of $83 million related to ERCOT default shortfall payments			$	638
Increase due to the acquisition of Direct Energy in January 2021, partially offset by improved collections in the legacy brands			3
Increase in provision for credit losses			$	641

Acquisition-Related Transaction and Integration Costs

Acquisition-related transaction and integration costs were $81 million for the nine months ended September 30, 2021. Acquisition-related transaction costs increased $13 million when compared to the same period in 2020, primarily related to the closing of the Direct Energy acquisition. Integration costs increased by $55 million when compared to the same period in 2020, which were primarily related to severance and consulting services for the Direct Energy acquisition.

Gain on Sale of Assets

The gain on sale of assets of $17 million was recorded for the nine months ended September 30, 2021 due to the sale of Agua Caliente in February 2021, compared to the gain on the sale of assets of $6 million for the nine months ended September 30, 2020 related to the sale of land and investments in January 2020.

E****quity in Earnings of Unconsolidated Affiliates

Equity in earnings of unconsolidated affiliates was $14 million lower for the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020, primarily due to the sale of the Agua Caliente solar project and unfavorable weather resulting in decreased earnings at Ivanpah in 2021, partially offset by higher earnings at Watson Cogeneration due to a favorable settlement in 2021.

Impairment Losses on Investments

Impairment losses on investments was $18 million during the nine months ended September 30, 2020 related to the impairment of Petra Nova Parish Holdings, as further discussed in Note 8*, Impairments*.

Other Income, Net

Other income decreased by $10 million for the nine months ended September 30, 2021, compared to the same period in 2020, primarily due to reduced reimbursements received in 2021 of $10 million and dividends received from cost method investments in 2020 of $5 million, partially offset by increased pension income in 2021 of $7 million due to a decrease in discount rates.

Loss on debt extinguishment, Net

Loss on debt extinguishment of $57 million was recorded for the nine months ended September 30, 2021, in connection with the redemption of senior notes, as further discussed in Note 9*, Long-term Debt and Finance Leases.*

Interest Expense

Interest expense increased by $82 million for the nine months ended September 30, 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 nine months ended September 30, 2021, income tax expense of $840 million was recorded on pre-tax income of $3.5 billion. For the same period in 2020, income tax expense of $216 million was recorded on a pre-tax income of $899 million. The effective tax rates were 24.3% and 24.0% for the nine months ended September 30, 2021 and 2020, respectively.

For the nine months ended September 30, 2021, NRG's overall effective tax rate was higher than the statutory rate of 21% primarily due to state tax expense partially offset by one-time tax benefits, as a result of the acquisition of Direct Energy, on revaluation of state deferred tax assets, NOLs and valuation allowance. For the same period in 2020, NRG's overall effective tax rate was higher that the statutory rate of 21% due to state tax expense, partially offset by an excess tax benefit related to share-based compensation.

Liquidity and Capital Resources

Liquidity Position

As of September 30, 2021 and December 31, 2020, NRG's total liquidity, excluding funds deposited by counterparties, of approximately $3.3 billion and $7.0 billion, respectively, was comprised of the following:

(In millions)			September 30, 2021						December 31, 2020
Cash and cash equivalents			$	259					$	3,905
Restricted cash - operating			9						3
Restricted cash - reserves(a)			5						3
Total			273						3,911
Total availability under Revolving Credit Facility and collective collateral facilities(b)			3,041						3,129
Total liquidity, excluding funds deposited by counterparties			$	3,314					$	7,040

(a) Includes reserves primarily for performance obligations and capital expenditures

(b) Total capacity of Revolving Credit Facility and collective collateral facilities was $6.0 billion and $4.0 billion as of September 30, 2021 and December 31, 2020, respectively

For the nine months ended September 30, 2021, total liquidity, excluding funds deposited by counterparties, decreased by $3.7 billion. Changes in cash and cash equivalent balances are further discussed hereinafter under the heading Cash Flow Discussion. Cash and cash equivalents at September 30, 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.

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 to stable from positive. At the same time, Moody's affirmed NRG's corporate family rating of Ba1.

Liquidity

The principal sources of liquidity for NRG's future operating and maintenance capital expenditures are expected to be derived from cash on hand, cash flows from operations, and financing arrangements, as described in Note 9, Long-term Debt and Finance Leases, to this Form 10-Q. 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; (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.

Direct Energy Acquisition

On January 5, 2021, the Company acquired Direct Energy, 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 and an initial purchase price adjustment of $77 million. The Company funded the purchase price using a combination of $715 million 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 purchase price adjustment resulted in a reduction of $3 million, which is in negotiation with Centrica. The Company expects to receive this payment from Centrica in 2021.

Collateral Facility Increases

The following table presents increases to the Company's collective 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 closely with rating agencies to achieve investment grade credit ratings.

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.

On August 24, 2021, the Company redeemed $1,355 million in aggregate principal of its Senior Notes for $1,425 million using the proceeds of the 2032 Senior Notes and cash on hand, resulting in total deleveraging of $255 million. In connection with the redemptions, a $57 million loss on debt extinguishment was recorded, which included the write-off of previously deferred financing costs of $9 million, during the nine months ended September 30, 2021. As a result of the financing activities, annualized interest savings are expected to be approximately $53 million. The Company redeemed an additional $500 million of its 6.625% Senior Notes due 2027 through November 4, 2021.

Receivables Securitization Facilities

On July 26, 2021, NRG Receivables LLC, wholly-owned indirect subsidiary of the Company, renewed its existing 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 September 30, 2021, there were no outstanding borrowings and there were $400 million in letters of credit issued under the Receivables Facility.

On July 26, 2021, the Company renewed its existing Repurchase Facility to, among other things, (i) extend the maturity date to July 26, 2022 and (ii) provide for revised language relating to interest determination based on SOFR in case of a LIBOR cessation or the occurrence of certain other trigger events.

Sale of Agua Caliente

On February 3, 2021, the Company closed on the sale of its 35% ownership in the Agua Caliente solar project to Clearway Energy, Inc. for $202 million. NRG recognized a gain on the sale of $17 million, including cash disposed of $7 million.

Sale of 4.8 GW of Fossil Generation Assets

On February 28, 2021, the Company entered into a definitive purchase agreement with Generation Bridge, an affiliate of ArcLight Capital Partners, to sell approximately 4,850 MW of fossil generating assets from its East and West regions of operations for total proceeds of $760 million, subject to standard purchase price adjustments and certain other indemnifications. The purchase price adjustments will include a working capital 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 cash flows generated during the year. As part of the transaction, NRG is entering into a tolling agreement for its 866 MW Arthur Kill plant in New York City through April 2025.

The transaction is expected to close by the end of 2021 and is subject to various closing conditions, approvals and consents, including approval from the NYPSC. The transaction has received FERC approval and approval under the Hart-Scott-Rodino Act.

Pension Plan Contributions

The American Rescue Plan Act ("ARPA") was enacted on March 11, 2021 to provide economic relief related to the COVID-19 pandemic. ARPA provides pension funding relief for single employer plans, among other provisions. As a result, NRG has reduced its previously planned cash contribution for 2021 by approximately $23 million. NRG’s pension and postretirement benefit plans are further described in Note 16, Benefit Plans and Other Postretirement Benefits, of Part IV, Item 15 of the Company’s 2020 Form 10-K.

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 will be payable to social security in 2021 and $13 million will be payable in 2022.

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 (i.e., buying fuel before receiving energy revenues); and (iv) initial collateral for large structured transactions. As of September 30, 2021, the Company had total cash collateral outstanding of $21 million and $3.0 billion outstanding in letters of credit to third parties primarily to support its market activities. As of September 30, 2021, total funds deposited by counterparties were $1.7 billion in cash and $401 million of letters of credit.

Future liquidity requirements may change based on the Company's hedging activities and structures, fuel purchases, and future market conditions, including forward prices for energy and fuel and market volatility. In addition, liquidity requirements depend 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 September 30, 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 September 30, 2021:

Equivalent Net Sales Secured by First Lien Structure**(a)**			2021						2022						2023
In MW			597						751						745
As a percentage of total net coal and nuclear capacity(b)			15%						18%						18%

(a) Equivalent Net Sales include natural gas swaps converted using a weighted average heat rate by region

(b) Net coal and nuclear capacity represents 80% of the Company’s total coal and nuclear assets eligible under the first lien, which excludes coal assets acquired with Midwest Generation and NRG's assets that have project level financing

Capital Expenditures

The following tables and descriptions summarize the Company's capital expenditures for maintenance, environmental and growth investments for the nine months ended September 30, 2021, and the estimated capital expenditures forecast for the remainder of 2021.

(In millions)			Maintenance						Environmental						Growth Investments**(a)**						Total
Texas			$	(105)					$	(1)					$	(20)					$	(126)
East			(19)						(1)						(23)						(43)
West/Services/Other			(15)						—						—						(15)
Corporate			(3)						—						(32)						(35)
Total cash capital expenditures for the nine months ended September 30, 2021			(142)						(2)						(75)						(219)
Investments			—						—						(28)						(28)
Total capital expenditures and investments			(142)						(2)						(103)						(247)
Estimated capital expenditures and investments for the remainder of 2021			$	(63)					$	(6)					$	(70)					$	(139)

(a) Includes other investments, acquisitions, digital NRG and integration

Growth investments in East for the nine months ended September 30, 2021 include the Astoria generating facility, for which the Company had proposed to replace the 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 New York State Department of Environmental Conservation denied the Company's application for an air permit and we are currently assessing our response to this denial. To date, the Company has spent approximately $38 million on the Astoria project. Additionally, included in Investments are expenditures for Encina site improvements classified as ARO payments. Demolition 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

NRG estimates that environmental capital expenditures from 2021 through 2025 required to comply with environmental laws will be approximately $55 million. The increase of $33 million from the previous quarter is primarily due to the cost of complying with ELG at our coal units in Texas.

Common Stock Dividends

During the first quarter of 2021, NRG increased the annual dividend to $1.30 from $1.20 per share and expects to target an annual dividend growth rate of 7-9% per share in subsequent years. A quarterly dividend of $0.325 per share was paid on the Company's common stock during the three months ended September 30, 2021. On October 15, 2021, NRG declared a quarterly dividend on the Company's common stock of $0.325 per share, payable on November 15, 2021 to stockholders of record as of November 1, 2021. Beginning in the first quarter of 2022, NRG will increase the annual dividend by 8% to $1.40 per share.

Cash Flow Discussion

The following table reflects the changes in cash flows for the comparative nine month periods:

			Nine months ended September 30,
(In millions)			2021						2020						Change
Net Cash Provided by Operating Activities			$	1,855					$	1,386					$	469
Net Cash Used by Investing Activities			(3,585)						(484)						(3,101)
Net Cash Used by Financing Activities			(177)						(567)						390

Net Cash Provided by Operating Activities

Changes to net cash provided/(used) by operating activities were driven by:

			(In millions)
Changes in cash collateral in support of risk management activities due to change in commodity prices			$	1,874
Increase 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			(927)
Decrease in operating income adjusted for other non-cash items			(698)
Increase in working capital primarily due to higher deferred revenues from the impact of Winter Storm Uri and increased accruals for renewable energy credits as a result of the acquisition of Direct Energy			421
Decrease in working capital primarily due to increases in purchases of renewable energy credits due to an increased customer count as a result of the acquisition of Direct Energy			(301)
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			175
Decrease in working capital due to replenishing natural gas inventory at significantly higher prices			(80)
Increase in other working capital			5
			$	469

Net Cash Used by Investing Activities

Changes to net cash (used)/provided by investing activities were driven by:

			(In millions)
Increase in cash paid for acquisitions primarily for Direct Energy			$	(3,257)
Increase in proceeds from sale of assets primarily due to sale of Agua Caliente			183
Increase in capital expenditures			(52)
Increase in sales of emissions allowances, net of purchases			21
Other			4
			$	(3,101)

Net Cash Used by Financing Activities

Changes to net cash (used)/provided by financing activities were driven by:

			(In millions)
Increase in payments of long-term debt			$	(1,298)
Increase in proceeds from issuance of long-term debt			1,041
Increase in net receipts from settlement of acquired derivatives			402
Decrease in payments for share repurchase activity			220
Increase in proceeds from Revolving Credit Facility and Receivables Securitization Facilities			83
Increase in payments of debt extinguishment costs and deferred issuance costs			(42)
Increase in payments of dividends to common stockholders			(18)
Other			2
			$	390

NOLs, Deferred Tax Assets and Uncertain Tax Position Implications, under ASC 740

For the nine months ended September 30, 2021, the Company had domestic pre-tax book income of $3.4 billion and foreign pre-tax book income of $131 million. As of December 31, 2020, the Company had cumulative domestic Federal NOL carryforwards of $10.1 billion, of which $2.3 billion were generated prior to Tax Cuts and Jobs Act and will begin expiring in 2031, and cumulative state NOL carryforwards of $5.4 billion for financial statement purposes. NRG also has cumulative foreign NOL carryforwards of $347 million, which do not have an expiration date. In addition to the above NOLs, NRG has a $14 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, and based on current forecasts, NRG anticipates income tax payments, primarily to state and foreign jurisdictions, of up to $71 million in 2021.

As of September 30, 2021, the Company has $25 million of tax-effected uncertain federal and state tax benefits, for which the Company has recorded a non-current tax liability (inclusive of accrued interest) until final resolution is reached with the related taxing authority.

The Company is no longer subject to U.S. federal income tax examinations for years prior to 2017. With few exceptions, state and local income tax examinations are no longer open for years prior to 2012.

Deferred tax assets and valuation allowance

Net deferred tax balance — As of September 30, 2021 and December 31, 2020, NRG recorded a net deferred tax asset, excluding valuation allowance, of $2.2 billion and $3.3 billion, respectively. The Company believes certain state net operating losses may not be realizable under the more-likely-than-not measurement and as such, a valuation allowance was recorded as of September 30, 2021 as discussed below.

NOL Carryforwards — As of September 30, 2021, the Company had a tax-effected cumulative U.S. NOLs consisting of carryforwards for federal and state income tax purposes of $2.1 billion and $458 million, respectively. The Company estimates it will need to generate future taxable income to fully realize the net federal deferred tax asset before the expiration of certain carryforwards commences in 2031. In addition, NRG has tax-effected cumulative foreign NOL carryforwards of $107 million with no expiration date.

Valuation Allowance — As of September 30, 2021 and December 31, 2020, the Company’s tax-effected valuation allowance was $259 million and $266 million, respectively, consisting of state NOL carryforwards and foreign NOL carryforwards. The valuation allowance was recorded based on the assessment of cumulative and forecasted pre-tax book earnings and the future reversal of existing taxable temporary differences.

Off-Balance Sheet Arrangements

Obligations under Certain Guarantee Contracts

NRG and certain of its subsidiaries enter into guarantee arrangements in the normal course of business to facilitate market transactions with third parties. These arrangements include financial and performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications.

The Company disclosed its Guarantees in Note 28, Guarantees, to the Company's 2020 Form 10-K. As of September 30, 2021, NRG and its consolidated subsidiaries were contingently obligated for a total of $3.6 billion under letters of credit and surety bonds, compared to $1.2 billion as of December 31, 2020. The increase is primarily due to the acquisition of Direct Energy in January 2021. Most of these letters of credit and surety bonds are issued in support of the Company's obligations to perform under commodity agreements and obligations associated with future closure and maintenance of ash sites, as well as for financing or other arrangements. A majority of these letters of credit and surety bonds expire within one year of issuance, and it is typical for the Company to renew them on similar terms.

Retained or Contingent Interests

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

Obligations Arising Out of a Variable Interest in an Unconsolidated Entity

Variable interest in equity investments — As of September 30, 2021, NRG has investments in energy and energy-related entities that are accounted for under the equity method of accounting. NRG’s investment in Ivanpah is a variable interest entity for which NRG is not the primary beneficiary. See also Note 10, Investments Accounted for Using the Equity Method and Variable Interest Entities, or VIEs.

NRG's pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $556 million as of September 30, 2021. This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to NRG. See also Note 15, Investments Accounted for by the Equity Method and Variable Interest Entities, to the Company's 2020 Form 10-K.

Contractual Obligations and Market Commitments

NRG has a variety of contractual obligations and other market commitments that represent prospective cash requirements in addition to the Company's capital expenditure programs, as disclosed in the Company's 2020 Form 10-K. See also Note 9, Long-term Debt and Finance Leases, and Note 16, Commitments and Contingencies, to this Form 10-Q for a discussion of new commitments and contingencies that also include contractual obligations and market commitments that occurred during the three and nine months ended September 30, 2021.

Guarantor Financial Information

As of September 30, 2021, the Company's outstanding registered senior notes consisted of $875 million of the 2027 Senior Notes and $821 million of the 2028 Senior Notes as shown in Note 9, Long-term Debt and Finance Leases. These Senior Notes are guaranteed by certain of NRG's current and future 100% owned domestic subsidiaries, or guarantor subsidiaries (the “Guarantors”). See Exhibit 22.1 for a listing of the Guarantors. These guarantees are both joint and several.

NRG conducts much of its business through and derives much of its income from its subsidiaries. Therefore, the Company's ability to make required payments with respect to its indebtedness and other obligations depends on the financial 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)			Nine months ended September 30, 2021**(a)**
Operating revenues			$	17,675
Operating income			4,144
Total other expense			(373)
Income from Continuing Operations			3,771
Net Income			2,963

(a)Intercompany transactions with Non-Guarantors include operating revenue of $77 million, cost of operations of $(191) million and selling, general and administrative of $76 million

The following table presents the summarized balance sheet information:

(In millions)			September 30, 2021
Current assets(a)			$	14,628
Property, plant and equipment, net			1,353
Non-current assets			12,229
Current liabilities(a)			12,865
Non-current liabilities			11,386

(a)Includes intercompany receivables of $461 million and intercompany payables of $73 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 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.

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 September 30, 2021, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at September 30, 2021. For a full discussion of the Company's valuation methodology of its contracts, see Derivative Fair Value Measurements in Note 5, Fair Value of Financial Instruments.

Derivative Activity (Losses)/Gains			(In millions)
Fair Value of Contracts as of December 31, 2020			$	(63)
Contracts realized or otherwise settled during the period			128
Direct contracts acquired during the period			(283)
Changes in fair value			3,896
Fair Value of Contracts as of September 30, 2021			$	3,678

			Fair Value of Contracts as of September 30, 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			$	459					$	287					$	32					$	7					$	785
Level 2			1,830						628						92						32						2,582
Level 3			207						46						14						44						311
Total			$	2,496					$	961					$	138					$	83					$	3,678

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 3, Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk, to this Form 10-Q, NRG measures the sensitivity of the Company's portfolio to potential changes in market prices using VaR, a statistical model which attempts to predict risk of loss based on market price and volatility. NRG's risk management policy places a limit on one-day holding period VaR, which limits the Company's net open position. As the Company's trade-by-trade derivative accounting results in a gross-up of the Company's derivative assets and liabilities, the net derivative asset and liability position is a better indicator of NRG's hedging activity. As of September 30, 2021, NRG's net derivative asset was $3.7 billion, an increase to total fair value of $3.7 billion as compared to December 31, 2020. This increase was primarily driven by gains in fair value and roll-off of trades that settled during the period, partially offset by Direct Energy contracts acquired during the period.

Based on a sensitivity analysis using simplified assumptions, the impact of a $0.50 per MMBtu increase in natural gas prices across the term of the derivative contracts would result in an increase of approximately $1.2 billion in the net value of derivatives as of September 30, 2021.

The impact of a $0.50 per MMBtu decrease in natural gas prices across the term of derivative contracts would result in a decrease of approximately $1.3 billion in the net value of derivatives as of September 30, 2021.

Critical Accounting Policies and Estimates

NRG's discussion and analysis of the financial condition and results of operations are based upon the condensed consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance as well as the use of estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities. The application of these policies 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 could materially affect the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment may also have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies has not changed.

On an ongoing basis, NRG evaluates these estimates, 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 critical accounting policies 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 regarding estimates about matters that are inherently uncertain. NRG's critical accounting policies include derivative instruments, income taxes and valuation allowance for deferred tax assets, impairment of long-lived assets and investments, goodwill and other intangible assets, and contingencies.

The Company's significant accounting policies are outlined in Note 2, Summary of Significant Accounting Policies, of this Form 10-Q, and in Note 2, Summary of Significant Accounting Policies, under Part IV, Item 15 of the Company's 2020 Form 10-K. The Company's critical accounting estimates are described in Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, in the Company's 2020 Form 10-K. There have been no material changes to the Company's critical accounting policies and estimates since the 2020 Form 10-K.