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, 2022 and 2021. Also refer to NRG's 2021 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 Estimates section.

Executive Summary

Introduction and Overview

NRG is a consumer services company built on dynamic retail brands. NRG brings the power of energy to customers by producing and selling energy and related products and services, nation-wide in the U.S. and Canada in a manner that delivers value to all of NRG's stakeholders. The Company sells power, natural gas, home and power services, and develops innovative, sustainable solutions, predominately under the brand names NRG, Reliant, Direct Energy, Green Mountain Energy, Stream, and XOOM Energy. The Company has a customer base that includes approximately 5.5 million Home customers as well as commercial, industrial, and wholesale customers, supported by approximately 16 GW of generation as of September 30, 2022.

Strategy

NRG's strategy is to maximize stockholder value through the safe production and sale of reliable electricity and natural gas to its customers in the markets it serves, while 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. Sustainability is a philosophy that underpins and facilitates value creation across our business for our stakeholders. It is an integral piece of NRG's strategy and ties directly to business success, reduced risks and enhanced reputation.

To effectuate the Company’s strategy, NRG is focused on: (i) serving the energy needs of end-use residential, commercial and industrial, and wholesale customers in competitive markets through multiple brands and channels; (ii) offering a variety of energy products and services, including renewable energy solutions, that are differentiated by innovative features, premium service, sustainability, and loyalty/affinity programs; (iii) excellence in operating performance of its assets; (iv) optimal hedging of its portfolio; and (v) engaging in disciplined and transparent capital allocation.

The Company implemented a four-year plan that began in 2022 to spend $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.

Energy Regulatory Matters

The Company’s regulatory matters are described in the Company’s 2021 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

Inflation Reduction Act — The IRA allocates $369 billion in spending for energy security and addressing climate change. Much of these investments come through the tax code in the form of clean energy tax credits. In the past, investment tax credits and production tax credits have played a vital role in the growth of wind and solar projects around the U.S., but they have had short lifespans, phaseouts and uncertainty of extensions. The IRA provides 10-year extensions on these tax credits, which will provide more certainty needed for investment decisions to build out these projects in the long-term. With new renewable generation coming online, renewable energy supply costs will likely become cheaper and more plentiful. NRG Home can also benefit from increased residential usage to charge electric vehicles ("EV") and special EV products. The IRA also introduced new tax provisions including a corporate book minimum tax and an excise tax on net stock repurchases with both taxes effective beginning in fiscal year 2023 for NRG. Additionally, the IRA establishes a tax credit associated with existing nuclear facilities which begins in 2024 and terminates at the end of 2031. The tax credit will fully apply when gross revenues are at or below $25 per MWh and phases out completely at $43.75 per MWh. The U.S. Treasury is now taking comments on what should be included in the definition of gross revenues.

State and Provincial Energy Regulation

Illinois Legislation — Illinois enacted the Climate and Equitable Jobs Act ("CEJA") on September 15, 2021, which targets 100% clean energy by 2050. CEJA focuses on (i) decarbonization, (ii) incentives to transition coal plants into clean energy facilities and (iii) nuclear subsidies. A component of CEJA is the Coal-to-Solar Energy Storage Grant Program. On June 1, 2022, the Illinois Department of Commerce and Economic Opportunity announced that NRG is eligible to receive almost $160 million over 10 years to develop battery storage at both the Waukegan and Will County power plant sites.

Regional Regulatory Developments

NRG is affected by rule/tariff changes that occur in the ISO regions. For further discussion on regulatory developments see Note 17, Regulatory Matters.

Texas

Public Utility Commission of Texas’ Actions with Respect to Wholesale Pricing and Market Design — In September 2021, the PUCT opened a rulemaking project to evaluate whether it should amend its rules to modify the High System Wide Offer cap ("HCAP") and the ORDC, which is intended to ensure prices in the competitive market appropriately reflect the value of operating reserves as the system approaches scarcity conditions. This rulemaking project concluded in December 2021, resulting in a rule amendment that lowered the HCAP to $5,000 per MWh and which expanded the minimum contingency level to 3,000 MW in Phase I. These two changes are broadly offsetting in their effect on overall average energy prices. In 2022, the PUCT has focused on the development of a winter firm fuel product. The PUCT directed ERCOT to issue a Request for Proposal to procure dual fuel capability with on-site fuel storage as part of the initial firm fuel procurement for the winter of 2022 and 2023. The procurement amount will be 3,000MW to 4,000MW and capped at a cost of $54 million. For Phase II, the PUCT Chair endorsed a version of NRG's Load-Serving Entity Reliability Obligation ("LSERO") idea; that retailers and other LSEs should be obliged to purchase an amount of physical reliability resources at critical hours commensurate with the state's newly cautious view of planning for tail events. The PUCT is also considering the development of a Backstop Reserve Service prior to implementation of an LSERO. ERCOT resource constraints will delay implementation, including Phase II items, by 12 to 24 months. Recently, the South Texas Electric Cooperative ("STEC") has filed a proposal to create a net-load based capacity market that allocates costs to loads, renewables and thermal resources with forced outages. A broad group of stakeholders, including NRG, have expressed support for the PUCT to include the STEC proposal in the blueprint for further review alongside the LSERO even though there is opposition for the specific cost allocation mechanism. The PUCT contracted with consulting firm E3 to develop design details and implementation specifics for the Phase II proposals due in the fourth quarter of 2022.

Activity on Securitization and ERCOT Pricing during Winter Storm Uri — The Texas Legislature acted to pass a variety of securitization vehicles to finance exceptionally high power and gas costs from Winter Storm Uri, including HB 4492. ERCOT subsequently filed two applications requesting the PUCT to issue Debt Obligation Orders ("DOOs") based on the legislation. On October 13, 2021, the PUCT issued DOOs authorizing ERCOT's securitization of $800 million to cover short payments and reimburse congestion revenue right account holders for amount related to the default of market participants other than electric cooperatives Brazos Electric Cooperative Inc. ("Brazos") and Rayburn Country Electric Cooperative, Inc. ("Rayburn"), which are discussed below (the "Default Securitization") and $2.1 billion related to highly priced ancillary service and ORPDA during Winter Storm Uri (the "Uplift Securitization").

The DOOs required ERCOT to issue loans or securitized bonds through a bankruptcy remote special purpose entity as the borrower and distribute the proceeds to affected market participants for default-related short payments and to LSEs for certain ancillary-service and ORDPA costs using an allocation of proceeds based on an LSE's exposure to relevant costs as calculated by the LSE's prevailing load-ratio share during the period of Winter Storm Uri, and a further redistribution of proceeds initially allocated to other LSEs and customers who opt-out of securitization. In turn, ERCOT charges non-bypassable fees related to the Default Securitization and Uplift Securitization to all qualified scheduling entities and to all LSEs (other than those that have opted-out), respectively. The Uplift Securitization provided for a one-time opt-out for certain LSEs or individual transmission-level customers who in exchange for foregoing any securitization-related proceeds likewise avoid future fees assessed by ERCOT for the use of repaying ERCOT's debt obligations. However, nearly all competitive REPs were required by the law to participate, ensuring the charge established by the law is competitively neutral. The $2.1 billion Uplift Securitization was disbursed by ERCOT in June 2022, with NRG's LSEs collectively receiving $689 million. NRG LSEs that assessed customers certain ancillary-service and ORDPA costs during the period of Winter Storm Uri provided a refund or credit to those customers proportionate to the LSE's total recovery. The $800 million Default Securitization was disbursed by ERCOT in November 2021, with NRG receiving $12 million.

Electric Cooperative Bankruptcy and Securitization — Of the defaults in the ERCOT market, the majority is attributable to Brazos. Brazos currently is in bankruptcy. NRG and ERCOT have both filed a proof of claim in the bankruptcy proceeding of Brazos, and Brazos has challenged ERCOT's claim in a manner that may prejudice NRG's claims against Brazos. During the fourth quarter of 2021, ERCOT filed a motion to dismiss Brazos' complaint relating to ERCOT's proof of claim, which NRG joined in support, but this motion was denied by the Bankruptcy Court, and ERCOT, NRG and certain other parties appealed. On January 11, 2022, the United States District Court for the Southern District of Texas entered an order allowing the appellants to seek direct review from the Fifth Circuit Court of Appeals of the Bankruptcy Court's decision on the motion to dismiss. On January 18, 2022, ERCOT, NRG and certain other parties filed a petition for direct review by the United States Court of Appeals for the Fifth Circuit. The Court of Appeals granted the petition on February 4, 2022, and such appeal remains pending. On February 7, 2022, the Bankruptcy Court entered an order granting summary judgment in favor of Brazos on whether ERCOT's sales to Brazos were in the ordinary course of Brazos' business. The Bankruptcy Court ruled that the portion of ERCOT's claims for charges incurred by Brazos after the intervention of the PUCT and ERCOT were not in the ordinary course and thus are not entitled to administrative expense status under the Bankruptcy Code. The amount and priority of ERCOT's claim for amounts incurred prior to such intervention or after such intervention ceased are issues to be determined at trial. The Bankruptcy Court's summary judgment ruling may also apply to NRG's claims against Brazos. To the extent the Bankruptcy Court reduces or disallows claims against Brazos, this presents risk for NRG.

Trial on the merits of the ERCOT proof of claim and Brazos' complaint commenced before the Bankruptcy Court on February 22, 2022. On the eighth day of trial, the parties agreed to suspend the trial and pursue mediation. On March 25, 2022, the Bankruptcy Court entered an order that appointed a mediator and abated the trial for the duration of the mediation. NRG thereafter participated in the mediation process with ERCOT, Brazos and various other parties in interest which culminated in the negotiation of a settlement between Brazos and ERCOT to be implemented under a chapter 11 plan and a related ERCOT market settlement process. On September 1, 2022, Brazos filed such chapter 11 plan, and on September 20, 2022, Brazos amended the plan and distributed it to certain creditors to solicit their acceptance. A hearing with the Bankruptcy Court regarding the potential confirmation of the plan is currently set for November 14, 2022. With respect to the pending appeal of the Bankruptcy Court's ruling on the motion to dismiss, on September 19, 2022, the Fifth Circuit Court of Appeals entered an order abating all deadlines pending confirmation of Brazos' chapter 11 plan.

If the Brazos' chapter 11 plan is confirmed and becomes effective, it and the related ERCOT settlement would provide market participants a recovery of funds that were short-paid in relation to Brazos. In October 2022, NRG elected the accelerated cash recovery option and will recover 65% of the $68 million, 43% of which was short-paid will be recovered on or around the effective date of the bankruptcy plan and another 22% will be recovered over the following 12-year period. The plan and ERCOT settlement also contemplate and would provide that there be no default uplift under the current ERCOT protocols in relation to the Brazos short payments. NRG's discounted market share of the default uplift is $9 million and is recorded as an other liability.

In February 2022, Rayburn successfully completed a securitization transaction and fully paid its outstanding obligations to ERCOT.

Reliability and Plant Operations Standards — The PUCT created a rulemaking to establish weatherization standards and issued a notice for comments in response to provisions of Texas Senate Bill 3 ("SB3") that require mandatory standards for power generators and others within the electric-power sector. On October 21, 2021, Commissioners of the PUCT voted to adopt Phase 1 of the rule without substantial modifications from the proposal, and those rules are now in effect. On May 26, 2022, the PUCT issued a proposal for publication to repeal Phase I rules and implement Phase 2 rules. The new rules entail conducting a weather study by ERCOT and the State Climatologist to create a percentile-based standard of weatherization and implementing

weatherization plan audits based on weather related outages that occur during weather emergencies. NRG filed comments to the rulemaking on June 23, 2022. On September 29, 2022, the PUCT adopted the Phase II Weatherization Standards.

PJM

Indian River RMR Proceeding — On June 29, 2021, Indian River notified PJM that it intended to retire Unit 4, effective May 31, 2022, due to expected uneconomic operations. On July 30, 2021, PJM responded to the deactivation notice and stated that PJM had identified reliability violations resulting from the proposed deactivation of Unit 4. NRG filed a cost based RMR rate schedule at FERC on April 1, 2022. FERC accepted the rate schedule with a June 1, 2022 effective date, subject to refund and established hearing and settlement procedures. Multiple parties protested. Parties are currently in settlement negotiations.

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 and ultimately appealed to the federal court of appeals. On December 21, 2021 and December 30, 2021, respectively, the Third Circuit Court of Appeals and the Seventh Circuit Court of Appeals issued an order holding the appeals in abeyance. The Seventh Court appeal is being held in abeyance while the appeal in the Third Court is moving forward with briefing. Any changes to the PJM capacity market construct may impact the outcome of future Base Residual Auctions.

PJM's ORDC Filing and Compliance Directives — On May 21, 2020, PJM proposed energy and reserve market reforms to enhance price formation in reserve markets, which includes modifying its ORDC and aligning market-based reserve products in Day-Ahead and Real-Time markets. In addition to approving PJM's proposal, FERC also directed PJM to implement a forward-looking Energy and Ancillary Services Offset to be used in PJM's capacity markets. After multiple compliance filings, parties filed appeals at the Court of Appeals for the D.C. Circuit of FERC’s orders, and on August 13, 2021, FERC filed a motion and was granted a voluntary remand the case back to the agency. On December 22, 2021, FERC issued its order on voluntary remand affirming in part and reversing in part FERC's determination. Specifically, FERC reversed itself and ordered PJM to: (i) eliminate the more robust ORDC curves and reserve penalty adders and maintain the existing (lower) curves and (lower) penalty adders and (ii) restore its tariff provisions related to its prior backward-looking Energy and Ancillary Services Offset. In response to requests for rehearing of the December 2021 order, FERC issued a notice denying the rehearings by operation of law and providing for further consideration on February 22, 2022. Multiple parties filed appeals in various appellate courts and are now all before the Sixth Circuit Court of Appeals for consideration.

Independent Market Monitor Market Seller Offer Cap Complaint — On March 18, 2021, finding that the calculation of the default Market Seller Offer Cap was unjust and unreasonable, the Order permitted the current PJM May 2021 capacity auction for the 2022/2023 delivery rule to continue under the existing rules and set a procedural schedule for parties to file briefs with possible solutions. On September 2, 2021, FERC issued an order in response to a complaint filed by the PJM Independent Market Monitor's proposal, which eliminates the Cost of New Entry-based Market Seller Offer Cap and implements a limited default cap for certain asset classes based on going-forward costs and provides for unit specific cost review by the Independent Market Monitor for all other non-zero offers into the auctions. As required by the Order, PJM submitted its compliance tariff on October 4, 2021. On October 4, 2021, certain parties filed a motion for rehearing, which was denied by operation of law. On February 18, 2022, FERC addressed the arguments raised on rehearing and rejected the rehearing requests. Multiple parties filed appeals at the Court of Appeals for the D.C. Circuit. Briefing is underway.

Generator Interconnection Process Reform — On June 14, 2022, PJM filed proposed tariff revisions at FERC regarding its interconnection process to provide for a more efficient process and address the backlog in interconnection service requests. The filing would transition the interconnect process from a "first-come, first-served" queue approach to a "first-ready, first-served" cluster/cycle approach. Additionally, project developers would be required to provide more significant financial deposits and meet other thresholds in order to move forward in the process. The filing is pending at FERC.

On June 16, 2022, FERC issued a Notice of Proposed Rulemaking to reform the generator interconnection procedures across the ISOs/RTOs. The matter is pending at FERC.

New York

NYISO's Revisions to the Buyer-Side Mitigation Rules — On January 5, 2022, the NYISO filed its Comprehensive Mitigation Review proposing changes to the buyer-side mitigation rules. The proposal would remove certain facilities to be reviewed under the buyer-side mitigation rules to serve the goals of New York's Climate Leadership and Community Protection Act, adopt a marginal capacity accreditation market design and adjust the rules surrounding installed and unforced capacity. On February 9, 2022, FERC issued a deficiency notice, focusing on capacity accreditation issues, which NYISO responded. On

May 10, 2022, FERC issued an order accepting the NYISO's Comprehensive Mitigation Review. Changes to NYISO's Buyer Side Mitigation rules may impact the outcome of future capacity auctions.

California

California Resource Adequacy Proceedings — As part of the Integrated Resource Procurement docket, the CPUC approved a decision on June 24, 2021 that requires all LSEs to procure a pro rata share of 11.5 GW of new non-fossil resource adequacy from 2023 to 2026. In that same docket, the CPUC ordered the state's major investor-owned utilities to procure additional summer reliability resources through 2023. On June 23, 2022, the CPUC approved a decision that raises the reserve margin from 15 percent to 16 percent in 2023 and at least 17 percent in 2024. Finally, SB846 establishes a pathway for PG&E's Diablo Canyon Nuclear power plant, which units are scheduled to close in 2024 and 2025, to remain open for at least five additional years. The result of these changes will likely keep Resource Adequacy ("RA") prices elevated in the near term and if LSEs cannot meet their RA obligations, penalties may be issued.

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 RMR resource conditioned on execution of a RMR contract. On January 29, 2021, MSCC made its RMR filing at FERC. Multiple parties filed protests and on March 16, 2021, MSCC filed a response to those protests. On April 2, 2021, FERC accepted the RMR filing, suspended it to become effective February 1, 2021 subject to refund and established hearing and settlement judge proceedings. On September 27, 2021, the CAISO gave notice to MSCC extending the term of the reliability designation through December 31, 2022. On April 29, 2022, the participants in the settlement proceeding filed a Joint Offer of Settlement with the FERC, which was approved by FERC on July 28, 2022.

Environmental Regulatory Matters

NRG is subject to numerous environmental laws in the development, construction, ownership and operation of power plants. These laws generally require that governmental permits and approvals be obtained before construction and maintained during operation of power plants. Federal and state environmental laws historically have become more stringent over time. Future laws may require the addition of emissions controls or other environmental controls or impose restrictions on the Company's operations. Complying with environmental laws often involves specialized human resources and significant capital and operating expenses, as well as occasionally curtailing operations. NRG decides to invest capital for environmental controls based on the relative certainty of the requirements, an evaluation of compliance options, and the expected economic returns on capital.

A number of regulations that affect the Company have been revised recently by the EPA, including ash storage and disposal requirements, NAAQS revisions and implementation and effluent limitation guidelines. Some of these recent revisions may, in turn, be revised by the current U.S. presidential administration. NRG will evaluate the impact of these regulations as they are revised but cannot fully predict the impact of each until anticipated revisions and legal challenges are resolved. The Company’s environmental matters are described in the Company’s 2021 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 have vacated the repeal of the CPP). On June 30, 2022, the U.S. Supreme Court held that the "generation shifting" approach in the CPP exceeded the powers granted to the EPA by Congress. The Court did not address the related issues of whether the EPA may adopt only

measures applied at each source. The Company anticipates that there will be additional proceedings at the D.C. Circuit and additional rulemaking by the EPA over the next several years.

Cross-State Air Pollution Rule ("CSAPR") — In April 2022, the EPA proposed revising the CSAPR to address the good-neighbor provisions of the 2015 ozone NAAQS. If the rule were finalized as proposed, it would apply to 25 states (including Texas) beginning in 2023. In 2023, the revised Group 3 trading program (previously established in the Revised CSAPR Update Rule) would have emission budgets based on NOx emission rates that the EPA says are achievable by existing controls at power plants. Starting in 2026, the NOx budgets would be reduced significantly based on levels achievable if SCR controls were installed at coal-fueled power plants that do not currently have such controls. Starting in 2025, the budgets would be updated annually to account for retirements, changes to operations, and new units. The proposal also contemplates heightened surrender requirements for units that exceed certain NOx emission rate thresholds. Comments on the proposed rule were due in June 2022 and numerous detailed comments were submitted. The Company cannot predict the outcome of this proposed revision and anticipates that this rulemaking will be subject to legal challenges after it is finalized.

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.

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 ELG for Steam Electric Generating Facilities, which imposed more stringent requirements (as individual permits were renewed) for wastewater streams from FGD, fly ash,

bottom ash and flue gas mercury control. On September 18, 2017, the EPA promulgated a final rule that, among other things, postponed the compliance dates to preserve the status quo for FGD wastewater and bottom ash transport water by two years to November 2020 until the EPA amended the rule. On October 13, 2020, the EPA amended the 2015 ELG rule by: (i) altering the stringency of certain limits for FGD wastewater; (ii) relaxing the zero-discharge requirement for bottom ash transport water; and (iii) changing several deadlines. On July 26, 2021, the EPA announced that it is initiating a new rulemaking to evaluate revising the ELG rule. While the EPA is developing the new rule, the existing rule (as amended in 2020) will stay in place, and the EPA expects permitting authorities to continue to implement the current regulation. The Company anticipates that the EPA will release a proposed rule in the first quarter of 2023. In October 2021, NRG informed its regulators that the Company intends to comply with the ELG by ceasing combustion of coal by the end of 2028 at its domestic coal units outside of Texas, and installing appropriate controls by the end of 2025 at its two plants that have coal-fired units in Texas.

Regional Environmental Developments

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. NRG has applied for initial operating permits and has begun to apply for construction permits (for closure) as required by the regulation.

Significant Events

The following significant events have occurred during 2022 as further described within this Management's Discussion and Analysis and the condensed consolidated financial statements:

Astoria

On September 9, 2022, the Company entered into a definitive purchase agreement to sell land and related assets from the Astoria site, within the East region of operations, for initial proceeds of $212 million subject to purchase price adjustments and certain other indemnifications. As part of the transaction, NRG will enter into an agreement to lease the land back for the purpose of operating the Astoria facility through the planned April 30, 2023 retirement date. The operating lease agreement is expected to end six months after the facility's actual retirement date. The transaction is expected to close in the fourth quarter of 2022 and is subject to various closing conditions.

W.A. Parish Extended Outage

In May 2022, W.A. Parish Unit 8 came offline as a result of damage to certain components of the steam turbine/generator. Based on management's current assessment of necessary restoration efforts, the Company is targeting to return the unit to service by the end of the second quarter of 2023.

Retirement of Joliet

During the second quarter of 2022, the results of the PJM Base Residual Auction for the 2023/2024 delivery year were released leading the Company to revise its long-term view of certain facilities and announce the planned retirement of the Joliet generating facility in May 2023. Impairment losses of $20 million and $130 million were recorded on the PJM generating assets and Midwest Generation goodwill, respectively.

ERCOT Securitization Proceeds

During 2021, the Texas Legislature passed HB 4492 for ERCOT to mitigate exceptionally high price adders and ancillary service costs incurred by LSEs during Winter Storm Uri. HB 4492 authorized ERCOT to obtain $2.1 billion of financing to distribute to LSEs that were charged and paid to ERCOT those highly priced ancillary service and ORDPA during Winter Storm Uri. In December 2021, the Company accounted for the proceeds as a reduction to cost of operations within its consolidated statements of operations in the 2021 annual period for which the proceeds were intended to compensate. The Company received proceeds of $689 million from ERCOT in June 2022.

Sale of Watson

On June 1, 2022, the Company closed on the sale of its 49% ownership in the Watson natural gas generating facility for $59 million. NRG recognized a gain on the sale of $46 million.

Share Repurchases

In December 2021, the Company's board of directors authorized the Company to repurchase $1.0 billion of its common stock, of which $44 million was completed in 2021. During the nine months ended September 30, 2022, the Company completed $489 million of share repurchases at an average price of $40.07 per share, including $6 million of equivalent shares purchased in lieu of tax withholdings on equity compensation issuances.Through October 31, 2022, an additional $76 million of share repurchases were executed at an average price of $41.71 per share. In October 2022, the Board of Directors approved an additional $600 million in share repurchases.

Dividend Increase

In the first quarter of 2022, NRG increased the annual dividend to $1.40 from $1.30 per share, representing an 8% increase from 2021. Beginning in the first quarter of 2023, NRG will increase the annual dividend by 8% to $1.51 per share. The Company expects to target an annual dividend growth rate of 7-9% per share in subsequent years.

Renewable Power Purchase Agreements

The Company's strategy is to procure mid to long-term generation through power purchase agreements. As of September 30, 2022, NRG has entered into PPAs totaling approximately 2.4 GW with third-party project developers and other counterparties, of which approximately 45% are operational. The average tenor of these agreements is twelve years. The Company expects to continue evaluating and executing similar agreements that support the needs of the business. The total GW procured through PPAs may be impacted by contract terminations when they occur.

Limestone Unit 1 Return to Service

In early July 2021, Limestone Unit 1 came offline as a result of damage to the duct work associated with the FGD system. The extended forced outage ended in April of 2022 and the unit has returned to service.

COVID-19

While the pandemic presents risks to the Company's business, as further described in the Company’s 2021 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, 2022 and 2021.

Trends Affecting Results of Operations and Future Business Performance

The Company’s trends are described in the Company’s 2021 Form 10-K in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations - Business Environment.

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)			2022						2021						Change						2022						2021						Change
Revenue
Retail revenue			$	7,858					$	5,951					$	1,907					$	22,379					$	16,929					$	5,450
Energy revenue(a)			450						336						114						1,034						989						45
Capacity revenue(a)			38						189						(151)						244						615						(371)
Mark-to-market for economic hedging activities			33						3						30						(248)						(99)						(149)
Contract amortization			(6)						(3)						(3)						(28)						(19)						(9)
Other revenues(a)(b)			137						133						4						307						1,528						(1,221)
Total revenue			8,510						6,609						1,901						23,688						19,943						3,745
Operating Costs and Expenses
Cost of fuel			742						466						(276)						1,603						1,530						(73)
Purchased energy and other cost of sales(c)			6,494						4,641						(1,853)						18,757						14,774						(3,983)
Mark-to-market for economic hedging activities			122						(1,782)						(1,904)						(3,155)						(4,122)						(967)
Contract and emissions credit amortization(c)			(16)						(45)						(29)						87						19						(68)
Operations and maintenance			359						332						(27)						1,049						1,036						(13)
Other cost of operations			101						80						(21)						278						259						(19)
Cost of operations (excluding depreciation and amortization shown below)			7,802						3,692						(4,110)						18,619						13,496						(5,123)
Depreciation and amortization			145						199						54						485						569						84
Impairment losses			43						—						(43)						198						306						108
Selling, general and administrative costs			326						318						(8)						973						973						—
Provision for credit losses			52						64						12						103						715						612
Acquisition-related transaction and integration costs			8						17						9						26						81						55
Total operating costs and expenses			8,376						4,290						(4,086)						20,404						16,140						(4,264)
Gain on sale of assets			22						—						22						51						17						34
Operating Income			156						2,319						(2,163)						3,335						3,820						(485)
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates			11						15						(4)						—						23						(23)
Other income, net			21						8						13						33						42						(9)
Loss on debt extinguishment			—						(57)						57						—						(57)						57
Interest expense			(105)						(122)						17						(313)						(374)						61
Total other expense			(73)						(156)						83						(280)						(366)						86
Income Before Income Taxes			83						2,163						(2,080)						3,055						3,454						(399)
Income tax expense			16						545						529						739						840						101
Net Income			$	67					$	1,618					$	(1,551)					$	2,316					$	2,614					$	(298)
Business Metrics
Average natural gas price — Henry Hub ($/MMBtu)			$	8.20					$	4.01					104		%				$	6.77					$	3.18					113		%

(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, 2022 and 2021

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, 2022 and 2021. Texas, East and West average on-peak power prices increased for the three months ended September 30, 2022 as compared to the same period in 2021 as a result of higher natural gas prices.

			Average on Peak Power Price ($/MWh)
			Three months ended September 30,
Region			2022						2021						Change %
Texas
ERCOT - Houston(a)			$	128.61					$	47.11					173		%
ERCOT - North(a)			131.62						46.16						185		%
East
NY J/NYC(b)			$	109.43					$	54.75					100		%
NEPOOL(b)			99.14						52.57						89		%
COMED (PJM)(b)			101.00						48.36						109		%
PJM West Hub(b)			110.99						51.32						116		%
West
MISO - Louisiana Hub(b)			$	90.32					$	44.95					101		%
CAISO - SP15(b)			110.03						72.02						53		%

(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, 2022 and 2021:

			Average Realized Power Price ($/MWh)
			Three months ended September 30,
Segment			2022						2021						Change %
East(a)			$	58.95					$	37.26					58		%
West/Services/Other			96.93						50.31						93		%

(a)Average Realized Power Price reflects energy sales from the generation fleet, including sales to the retail component of the East Segment. Intercompany financial transactions hedging generation with the retail business make up ($5.47)/MWh in the three months ended September 30, 2022 and ($9.84)/MWh in the three months ended September 30, 2021

The average realized power prices increased in the East and West/Services/Other segments for the three months ended September 30, 2022 as compared to the same period in 2021, as a result of higher natural gas prices. Average power prices increased less than average on peak power prices due to the impact of the Company's multi-year hedging program.

Gross Margin

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

Economic Gross Margin

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

The below tables present the composition and reconciliation of gross margin and economic gross margin for the three months ended September 30, 2022 and 2021:

			Three months ended September 30, 2022
($ In millions)			Texas						East						West/Services/Other															Corporate/Eliminations						Total
Retail revenue			$	3,005					$	3,863					$	990														$	—					$	7,858
Energy revenue			48						212						180															10						450
Capacity revenue			—						38						—															—						38
Mark-to-market for economic hedging activities			4						32						(7)															4						33
Contract amortization			—						(10)						4															—						(6)
Other revenue(a)			92						45						2															(2)						137
Total revenue			3,149						4,180						1,169															12						8,510
Cost of fuel			(489)						(140)						(113)															—						(742)
Purchased energy and other cost of sales(b)(c)(d)			(2,012)						(3,609)						(865)															(8)						(6,494)
Mark-to-market for economic hedging activities			(600)						423						59															(4)						(122)
Contract and emission credit amortization			(4)						29						(9)															—						16
Depreciation and amortization			(77)						(39)						(22)															(7)						(145)
Gross margin			$	(33)					$	844					$	219														$	(7)					$	1,023
Less: Mark-to-market for economic hedging activities, net			(596)						455						52															—						(89)
Less: Contract and emission credit amortization, net			(4)						19						(5)															—						10
Less: Depreciation and amortization			(77)						(39)						(22)															(7)						(145)
Economic gross margin			$	644					$	409					$	194														$	—					$	1,247
(a) Includes trading gains and losses and ancillary revenues
(b) Includes capacity and emissions credits
(c) Includes $846 million and $184 million of TDSP expense in Texas and West/Services/Other, respectively. TDSP expense in the East was immaterial due to the impact of certain provisions of the CEJA in Illinois, which took effect in June 2022
(d) Excludes depreciation and amortization shown separately
Business Metrics			Texas						East						West/Services/Other															Corporate/Eliminations						Total
Retail sales
Home power sales volume (GWh)			14,053						3,838						533															—						18,424
Business power sales volume (GWh)			11,006						12,753						3,194															—						26,953
Home natural gas sales volume (MDth)			—						6,070						5,345															—						11,415
Business natural gas sales volume (MDth)			—						314,094						30,602															—						344,696
Average retail Home customer count (in thousands) (a)(b)			2,977						1,794						786															—						5,557
Ending retail Home customer count (in thousands) (a)(b)			2,903						1,788						784															—						5,475
Power generation
GWh sold			11,921						3,291						1,858															—						17,070
GWh generated(c)
Coal			5,448						1,532						—															—						6,980
Gas			3,960						323						1,860															—						6,143
Nuclear			2,513						—						—															—						2,513
Oil			—						3						—																					3
Renewables			—						—						2															—						2
Total			11,921						1,858						1,862															—						15,641
(a) Home customer count includes recurring residential customers, services customers and municipal aggregations
(b) The whole home warranty business was sold in January 2022
(c) Includes owned and leased generation, excludes tolled generation and equity investments

			Three months ended September 30, 2021
($ In millions)			Texas						East						West/Services/Other												Corporate/Eliminations						Total
Retail revenue			$	2,503					$	2,698					$	749											$	1					$	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
Total revenue			2,635						3,077						883												14						6,609
Cost of fuel			(305)						(93)						(68)												—						(466)
Purchased energy and other cost of sales(b)(c)(d)			(1,492)						(2,500)						(647)												(2)						(4,641)
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)						(87)						(21)												(7)						(199)
Gross margin			$	666					$	2,244					$	228											$	(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)						(87)						(21)												(7)						(199)
Economic gross margin			$	839					$	494					$	170											$	(1)					$	1,502
(a) Includes trading gains and losses and ancillary revenues
(b) Includes capacity and emissions credits
(c) Includes $802 million, $38 million and $197 million of TDSP expense in Texas, East, and West/Services/Other, respectively
(d) Excludes depreciation and amortization shown separately
Business Metrics			Texas						East						West/Services/Other												Corporate/Eliminations						Total
Retail sales
Home power sales volume (GWh)			13,486						4,032						512												—						18,030
Business power 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)(b)			3,030						1,819						960												—						5,809
Ending retail Home customer count (in thousands)(a)(b)			3,043						1,784						954												—						5,781
Power generation
GWh sold			11,841						4,267						2,246												—						18,354
GWh generated(c)
Coal			5,558						2,375						—												—						7,933
Gas(d)			3,756						750						1,970												—						6,476
Nuclear			2,527						—						—												—						2,527
Oil(e)			—						106						—												—						106
Total			11,841						3,231						1,970												—						17,042
(a) Home customer count includes recurring residential customers, services customers and municipal aggregations
(b) Includes 143 thousand whole home warranty customers in West/Services/Other. The whole home warranty business was sold in January 2022
(c) Includes owned and leased generation, excludes tolled generation and equity investments
(d) Includes 410 GWh and 947 GWh in East and West/Services/Other, respectively, that was sold to Generation Bridge in December 2021
(e) Includes 103 GWh in East that was sold to Generation Bridge in December 2021

The table below represents the weather metrics for the three months ended September 30, 2022 and 2021:

			Three months ended September 30,
Weather Metrics			Texas						East						West/Services/Other (b)
2022
CDDs (a)			1,789						874						1,268
HDDs (a)			—						54						3
2021
CDDs			1,589						784						1,134
HDDs			—						38						5
10-year average
CDDs			1,659						819						1,159
HDDs			6						53						11

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

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

Gross Margin and Economic Gross Margin

Gross margin decreased $2.1 billion and economic gross margin decreased $255 million during the three months ended September 30, 2022, compared to the same period in 2021.

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 in 2021, primarily due to ERCOT 180 day settlements in the third quarter of 2021			$	(13)
The following explanations exclude the impact of Winter Storm Uri:
Higher gross margin due to an increase in load of 1.4 million MWhs due to weather			46
Lower gross margin due to the net effect of: •a 58%, or $527 million, increase in overall average costs to serve the retail load, driven by increases in power, ancillary, and fuel costs and the extended outage at W.A. Parish Unit 8 that began in the second quarter of 2022; and •increased net revenue rates of $14.85 per MWh, or $323 million, primarily driven by changes in customer mix			(204)
Lower gross margin from market optimization activities			(28)
Other			4
Decrease in economic gross margin			$	(195)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges			(514)
Decrease in contract and emission credit amortization			3
Decrease in depreciation and amortization			7
Decrease in gross margin			$	(699)

East

						(In millions)
Lower gross margin due to the sale of fossil generating assets to Generation Bridge in December 2021						$	(61)
Lower gross margin due to a decrease in generation and capacity as a result of Midwest Generation asset retirements in the second quarter of 2022						(47)
Lower gross margin primarily due to a 65% decrease in PJM capacity prices						(34)
Lower electric gross margin due to attrition and decreased load due to changes in customer mix and attrition						(27)
Lower gross margin at Midwest Generation (excluding the impact of asset retirements) due to higher supply costs partially offset by a 36% increase in average realized pricing and an increase in generation volumes due to dark spread expansion						(21)
Higher retail electric gross margin due to higher net revenue rates as a result of changes in customer term, product and mix of $12.25 per MWh, or $203 million, partially offset by higher supply costs of $8.25 per MWh, driven primarily by increases in power prices, totaling $134 million						69
Higher natural gas gross margin due to higher net revenue rates as a result of changes in customer term, product and mix of $3.69 per Dth, totaling $1.2 billion, partially offset by higher supply costs of $3.62 per Dth, or $1.2 billion						23
Higher gross margin from sales of NOx emission credits						12
Other						1
Decrease in economic gross margin						$	(85)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges						(1,328)
Increase in contract amortization						(35)
Decrease in depreciation and amortization						48
Decrease in gross margin						$	(1,400)

West/Services/Other

			(In millions)
Lower gross margin due to the sale of fossil generating assets to Generation Bridge in December 2021			$	(24)
Lower gross margin due to the sale of the whole home warranty business in the first quarter of 2022			(7)
Higher gross margin at Cottonwood due to a 129% increase in average realized power prices partially offset by increased commodity costs			34
Higher gross margin primarily due to increased revenue at Airtron			14
Higher gross margin from market optimization activities			7
Increase in economic gross margin			$	24
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges			(32)
Increase in depreciation and amortization			(1)
Decrease in gross margin			$	(9)

Mark-to-Market for Economic Hedging Activities

Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges. Total net mark-to-market results decreased by $1.9 billion during the three months ended September 30, 2022, compared to the same period in 2021.

The breakdown of gains and losses included in revenues and operating costs and expenses by segment was as follows:

			Three months ended September 30, 2022
(In millions)			Texas						East						West/Services/Other												Eliminations						Total
Mark-to-market results in revenue
Reversal of previously recognized unrealized losses on settled positions related to economic hedges			$	1					$	12					$	2											$	(2)					$	13
Reversal of acquired (gain) positions related to economic hedges			—						(2)						—												—						(2)
Net unrealized gains/(losses) on open positions related to economic hedges			3						22						(9)												6						22
Total mark-to-market gains/(losses) in revenue			$	4					$	32					$	(7)											$	4					$	33
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges			$	(191)					$	(151)					$	(60)											$	2					$	(400)
Reversal of acquired (gain)/loss positions related to economic hedges			(16)						18						(15)												—						(13)
Net unrealized (losses)/gains on open positions related to economic hedges			(393)						556						134												(6)						291
Total mark-to-market (losses)/gains in operating costs and expenses			$	(600)					$	423					$	59											$	(4)					$	(122)

			Three months ended September 30, 2021
(In millions)			Texas						East						West/Services/Other												Eliminations						Total
Mark-to-market results in revenue
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) in revenue			$	(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 gains in operating costs and expenses			$	(81)					$	1,786					$	90											$	(13)					$	1,782

`

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, 2022, the $33 million gain in revenues from economic hedge positions was driven primarily by an increase in the value of open positions due to newly executed transactions during the quarter and the reversal of previously recognized unrealized losses on contracts that settled during the period. The $122 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 natural gas and power prices.

For the three months ended September 30, 2021, the $3 million gain in 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.

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, 2022 and 2021. The realized and unrealized financial and physical trading results are included in revenue. The Company's trading activities are subject to limits based on the Company's Risk Management Policy.

			Three months ended September 30,
(In millions)			2022						2021
Trading gains
Realized			$	1					$	31
Unrealized			9						8
Total trading gains			$	10					$	39

Operations and Maintenance Expense

Operations and maintenance expense are comprised of the following:

(In millions)			Texas						East						West/Services/Other												Eliminations						Total
Three months ended September 30, 2022			$	213					$	91					$	55											$	—					$	359
Three months ended September 30, 2021			160						121						52												(1)						332

Operations and maintenance expense increased by $27 million for the three months ended September 30, 2022, compared to the same period in 2021, due to the following:

			(In millions)
Decrease due to the sale of fossil generating assets to Generation Bridge in December 2021			$	(21)
Decrease due to Midwest Generation asset retirements in the second quarter of 2022			(10)
Increase due to the W.A. Parish restoration efforts associated with the May 2022 extended outage			25
Increase due to the duration and scope of outages at the Texas nuclear, coal and gas facilities in 2022			17
Increase driven by higher retail operations costs			8
Increase in the estimate of environmental remediation costs at a deactivated site in the East			7
Increase in variable operation and maintenance expense at the PJM coal facilities associated with increased generation in 2022 as compared to 2021			5
Other			(4)
Increase in operations and maintenance expense			$	27

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, 2022			$	60					$	38					$	3					$	101
Three months ended September 30, 2021			47						31						2						80

Other costs of operations increased by $21 million for the three months ended September 30, 2022, compared to the same period in 2021, due to the following:

			(In millions)
Decrease due to the sale of fossil generating assets to Generation Bridge in December 2021			$	(8)
Increase in retail gross receipt taxes due to higher revenues			21
Increase due to higher property insurance premiums			7
Other			1
Increase in other cost of operations			$	21

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, 2022			$	77					$	39					$	22					$	7					$	145
Three months ended September 30, 2021			84						87						21						7						199

Depreciation and amortization decreased by $54 million for the three months ended September 30, 2022, compared to the same period in 2021, primarily due to lower depreciation at Midwest Generation as a result of asset impairments and retirements.

Impairment Losses

Impairment losses of $43 million were recorded during the three months ended September 30, 2022 primarily related to the purchase and sale agreement for the sale of the land and related assets at the Astoria generating site and the planned withdrawal and cancellation of its proposed Astoria redevelopment project. Refer to Note 8, Impairments for further discussion.

Selling, General and Administrative Costs

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

(In millions)			Texas						East						West/Services/Other						Corporate												Total
Three months ended September 30, 2022			$	150					$	108					$	60					$	8											$	326
Three months ended September 30, 2021			148						109						45						16												318

Selling, general and administrative costs increased by $8 million for the three months ended September 30, 2022, compared to the same period in 2021, due to the following:

			(In millions)
Increase due to the favorable resolution of a legal matter in 2021			$	15
Increase in broker fee expenses, partially offset by lower commissions expenses			4
Decrease due to lower marketing and media spend			(15)
Decrease due to Winter Storm Uri, primarily due to legal expenses in 2021			(2)
Other			6
Increase in selling, general and administrative costs			$	8

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, 2022			$	41					$	7					$	4											$	52
Three months ended September 30, 2021			58						3						3												64

Provision for credit losses decreased by $12 million for the three months ended September 30, 2022, compared to the same period in 2021, due to the following:

			(In millions)
Decrease due to Winter Storm Uri, related to counterparty credit risk in 2021			$	(32)
Increase due to higher revenues and deteriorated customer payment behavior			20
Decrease in provision for credit losses			$	(12)

Acquisition-Related Transaction and Integration Costs

Acquisition-related transaction and integration costs of $8 million and $17 million were incurred during the three months ended September 30, 2022, and 2021, which are comprised primarily of integration costs related to Direct Energy.

Gain on Sale of Assets

The gain on sale of assets of $22 million for the three months ended September 30, 2022 was due to the sale of the Company's 50% ownership interest in Petra Nova.

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 the 2026 Senior Notes and the partial redemption of the 2027 Senior Notes in the third quarter of 2021.

Interest Expense

Interest expense decreased by $17 million for the three months ended September 30, 2022, compared to the same period in 2021, primarily due to debt reduction and the refinancing of debt to lower interest rates in the second half of 2021.

Income Tax Expense

For the three months ended September 30, 2022, income tax expense of $16 million was recorded on pre-tax income of $83 million. For the same period in 2021, income tax expense of $545 million was recorded on pre-tax income of $2.2 billion. The effective tax rates were 19.3% and 25.2% for the three months ended September 30, 2022 and 2021, respectively.

For the three months ended September 30, 2022, the effective tax rate was lower than the statutory rate of 21% primarily due to the benefit resulting from carbon capture tax credits and the reduction in statutory state tax rates. For the same period in 2021, the effective tax rate was higher than the statutory rate of 21% primarily due to state tax expense.

Management’s discussion of the results of operations for the nine months ended September 30, 2022 and 2021

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, 2022 and 2021. The average on-peak power prices decreased significantly in Texas due to Winter Storm Uri's impact on 2021 pricing. East and West average on-peak power prices increased for the nine months ended September 30, 2022 as compared to the same period in 2021 as a result of higher natural gas prices.

			Average on Peak Power Price ($/MWh)
			Nine months ended September 30,
Region			2022						2021						Change %
Texas
ERCOT - Houston (a)			$	101.20					$	240.14					(58)		%
ERCOT - North(a)			85.68						236.75						(64)		%
East
NY J/NYC(b)			$	98.34					$	45.04					118		%
NEPOOL(b)			96.30						47.17						104		%
COMED (PJM)(b)			76.82						38.00						102		%
PJM West Hub(b)			87.44						40.04						118		%
West
MISO - Louisiana Hub(b)			$	75.26					$	40.11					88		%
CAISO - SP15(b)			71.86						51.22						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, 2022 and 2021:

			Average Realized Power Price ($/MWh)
			Nine months ended September 30,
Segment			2022						2021						Change %
East(a)			$	53.96					$	37.70					43		%
West/Services/Other			69.79						39.97						75		%

(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 ($5.70)/MWh in the nine months ended September 30, 2022 and ($5.10)/MWh in the nine months ended September 30, 2021

The average realized power prices increased in the East and West/Services/Other segments for the nine months ended September 30, 2022, as compared to the same period in 2021, as a result of higher natural gas prices. Average power prices increase less than average on peak power prices due to impact of the Company's multi-year hedging program.

Gross Margin

The Company calculates gross margin in order to evaluate operating performance as revenues less cost of fuel, purchased energy and other costs of sales, mark-to-market for economic hedging activities, 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 energy 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, 2022 and 2021:

			Nine months ended September 30, 2022
($ In millions)			Texas						East						West/Services/Other												Corporate/Eliminations						Total
Retail revenue			$	7,528					$	11,784					$	3,068											$	(1)					$	22,379
Energy revenue			101						544						365												24						1,034
Capacity revenue			—						242						2												—						244
Mark-to-market for economic hedging activities			1						(204)						(63)												18						(248)
Contract amortization			—						(30)						2												—						(28)
Other revenue (a)			238						78						3												(12)						307
Total revenue			7,868						12,414						3,377												29						23,688
Cost of fuel			(1,018)						(315)						(270)												—						(1,603)
Purchased energy and other cost of sales(b)(c)(d)			(4,980)						(11,040)						(2,724)												(13)						(18,757)
Mark-to-market for economic hedging activities			662						2,241						270												(18)						3,155
Contract and emission credit amortization			—						(73)						(14)												—						(87)
Depreciation and amortization			(230)						(167)						(65)												(23)						(485)
Gross margin			$	2,302					$	3,060					$	574											$	(25)					$	5,911
Less: Mark-to-market for economic hedging activities, net			663						2,037						207												—						2,907
Less: Contract and emission credit amortization, net			—						(103)						(12)												—						(115)
Less: Depreciation and amortization			(230)						(167)						(65)												(23)						(485)
Economic gross margin			$	1,869					$	1,293					$	444											$	(2)					$	3,604
(a) Includes trading gains and losses and ancillary revenues
(b) Includes capacity and emissions credits
(c) Includes $2.3 billion, $106 million and $848 million of TDSP expense in Texas, East, and West/Services/Other, respectively
(d) Excludes depreciation and amortization shown separately
Business Metrics			Texas						East						West/Services/Other												Corporate/Eliminations						Total
Retail sales
Home electricity sales volume (GWh)			34,879						10,298						1,629												—						46,806
Business electricity sales volume (GWh)			29,859						37,110						7,753												—						74,722
Home natural gas sales volume (MDth)			—						58,909						58,963												—						117,872
Business natural gas sales volume (MDth)			—						1,166,896						110,396												—						1,277,292
Average retail Home customer count (in thousands)(a)(b)			3,006						1,785						788												—						5,579
Ending retail Home customer count (in thousands)(a)(b)			2,903						1,788						784												—						5,475
Power generation
GWh sold			29,976						9,118						5,230												—						44,324
GWh generated (c)
Coal			14,765						5,361						—												—						20,126
Gas			7,628						475						5,236												—						13,339
Nuclear			7,583						—						—												—						7,583
Renewables			—						—						7												—						7
Oil			—						2						—												—						2
Total			29,976						5,838						5,243												—						41,057
(a) Home customer count includes recurring residential customers, services customers and municipal aggregations
(b) The whole home warranty business was sold in January 2022
(c) Includes owned and leased generation, excludes tolled generation and equity investments

			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
Total revenue			8,362						9,002						2,564												15						19,943
Cost of fuel			(1,243)						(155)						(132)												—						(1,530)
Purchased energy and other cost of sales(b)(c)(d)			(5,548)						(7,206)						(2,019)												(1)						(14,774)
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)						(237)						(66)												(21)						(569)
Gross margin			$	2,398					$	4,245					$	556											$	(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)						(237)						(66)												(21)						(569)
Economic gross margin			$	1,576					$	1,709					$	477											$	(5)					$	3,757
(a) Includes trading gains and losses and ancillary revenues
(b) Includes capacity and emissions credits
(c) Includes $2.0 billion, $138 million and $731 million of TDSP expense in Texas, East and West/Services/Other, respectively
(d) Excludes depreciation and amortization shown separately
Business Metrics			Texas						East						West/Services/Other												Corporate/Eliminations						Total
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))b)			3,059						1,871						968												—						5,898
Ending retail Home customer count (in thousands)(a)(b)			3,043						1,784						954												—						5,781
Power generation
GWh sold			29,020						10,000						5,954												—						44,974
GWh generated (c)
Coal			14,188						4,887						—												—						19,075
Gas(d)			7,789						1,324						5,606												—						14,719
Nuclear			7,043						—						—												—						7,043
Oil(e)			—						189						—												—						189
Total			29,020						6,400						5,606												—						41,026
(a) Home customer count includes recurring residential customers, services customers and municipal aggregations
(b) Includes 143 thousand whole home warranty customers in West/Services/Other. The whole home warranty business was sold in January 2022
(c) Includes owned and leased generation, excludes tolled generation and equity investments
(d) Includes 794 GWh and 1,867 GWh in East and West/Services/Other, respectively, that was sold to Generation Bridge in December 2021
(e) Includes 183 GWh in East that was sold to Generation Bridge in December 2021

The table below represents the weather metrics for the nine months ended September 30, 2022 and 2021:

			Nine months ended September 30,
Weather Metrics			Texas						East						West/Services/Other (b)
2022
CDDs (a)			3,141						1,267						1,974
HDDs (a)			1,202						2,944						1,347
2021
CDDs			2,574						1,184						1,693
HDDs			1,202						2,929						1,398
10-year average
CDDs			2,741						1,214						1,758
HDDs			1,007						2,922						1,256

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

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

Gross Margin and Economic Gross Margin

Gross margin decreased $1.3 billion and economic gross margin decreased $153 million, both of which include intercompany sales, during the nine months ended September 30, 2022, compared to the same period in 2021.

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 driven by a decrease in unhedgeable ancillary and operating reserve demand curve(a)						$	560
The following explanations exclude the impact of Winter Storm Uri:
Lower gross margin due to the net effect of: •a 47%, or $952 million increase in overall average costs to serve the retail load, driven by increases in power, ancillary, and fuel costs, extended outages at W.A. Parish Unit 8 and Limestone Unit 1, and the more conservative winter hedge profile in the first quarter of 2022, partially offset by the favorable impact of the early settlement of a solar PPA; and •increased net revenue rates of $9.50 per MWh, or $514 million, and higher gross margin attributable to increased load of 1.4 million MWhs, or $52 million, both primarily driven by changes in customer mix						(386)
Higher power gross margin due to an increase in load of 4.6 million MWhs from weather						157
Lower gross margin from market optimization activities						(42)
Other						4
Increase in economic gross margin						$	293
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges						(404)
Decrease in depreciation and amortization						15
Decrease in gross margin						$	(96)

(a)For further discussion of ERCOT's securitization activity see Regional Regulatory Developments section under Energy Regulatory Matters above and Note 2, Summary of Significant Accounting Policies

East

			(In millions)
Lower gross margin due to the impact of Winter Storm Uri in 2021, 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:
Lower gross margin due to the sale of fossil generating assets to Generation Bridge in December 2021			(178)
Lower gross margin due to a decrease in generation and capacity as a result of Midwest Generation asset retirements in the second quarter of 2022			(55)
Lower retail electric gross margin due to higher supply costs of $16.75 per MWh, driven primarily by increases in power prices, totaling $796 million, partially offset by higher net revenue rates as a result of changes in customer term, product and mix of $14.75 per MWh, or $704 million			(92)
Lower demand response gross margin primarily due to a decrease in early settlements of capacity			(86)
Lower electric gross margin from decreased load of 4.7 TWh due to attrition and change in customer mix			(43)
Lower gross margin due to a decrease of capacity prices of 23% in PJM and 44% in New York			(36)
Higher gross margin primarily at Midwest Generation due to a 51% increase in average realized pricing and an increase in generation volumes due to dark spread expansion, partially offset by increased supply costs			29
Higher natural gas gross margin including the impact of transportation and storage contract optimization, resulting in higher net revenue rates from changes in customer term, product and mix of $3.01 per Dth, or $3.7 billion, partially offset by higher supply costs of $2.86 per Dth or $3.5 billion			177
Higher gross margin from the sales of NOx emission credits			14
Decrease in economic gross margin			$	(416)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges			(759)
Increase in contract amortization			(80)
Decrease in depreciation and amortization			70
Decrease in gross margin			$	(1,185)

West/Services/Other

			(In millions)
Lower gross margin due to the impact of Winter Storm Uri in 2021, primarily driven by natural gas optimization during volatile pricing that occurred during the weather event			$	(13)
The following explanations exclude the impact of Winter Storm Uri:
Lower gross margin due to the sale of fossil generating assets to Generation Bridge in December 2021			(62)
Lower gross margin due to the sale of the whole home warranty business in the first quarter of 2022			(29)
Higher gross margin primarily due to increased revenue at Airtron			31
Higher gross margin at Cottonwood due to a 114% increase in average realized power prices, partially offset by increased commodity costs			39
Higher electric gross margin due to an increase in net revenue rates as a result of changes in customer term, product and mix of $22.13 per MWh, or $207 million, an increase in customer mix of $4 million, partially offset by higher supply costs of $19.71 per MWh, or $185 million			26
Lower natural gas gross margin due to higher supply costs of $2.08 per Dth, or $352 million, partially offset by higher net revenue rates of $1.74 per Dth, or $294 million, and an increase in load due to customer mix of $31 million			(27)
Other			2
Decrease in economic gross margin			$	(33)
Increase in mark-to-market for economic hedges primarily due to net unrealized gains/losses on open positions related to economic hedges			47
Decrease in contract amortization			3
Decrease in depreciation and amortization			1
Increase in gross margin			$	18

Mark-to-Market for Economic Hedging Activities

Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges. Total net mark-to-market results decreased by $1.1 billion during the nine months ended September 30, 2022, compared to the same period in 2021.

The breakdown of gains and losses included in revenues and operating costs and expenses by segment was as follows:

			Nine months ended September 30, 2022
(In millions)			Texas						East						West/Services/Other												Eliminations						Total
Mark-to-market results in revenue
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges			$	2					$	(9)					$	38											$	(6)					$	25
Reversal of acquired (gain) positions related to economic hedges			—						(1)						—												—						(1)
Net unrealized (losses) on open positions related to economic hedges			(1)						(194)						(101)												24						(272)
Total mark-to-market gains/(losses) in revenue			$	1					$	(204)					$	(63)											$	18					$	(248)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges			$	(336)					$	(547)					$	(140)											$	6					$	(1,017)
Reversal of acquired loss/(gain) positions related to economic hedges			15						(25)						(16)												—						(26)
Net unrealized gains on open positions related to economic hedges			983						2,813						426												(24)						4,198
Total mark-to-market gains in operating costs and expenses			$	662					$	2,241					$	270											$	(18)					$	3,155

			Nine months ended September 30, 2021
(In millions)			Texas						East						West/Services/Other												Eliminations						Total
Mark-to-market results in revenue
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 revenue			$	(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

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, 2022, the $248 million loss in revenues from economic hedge positions was driven by a decrease in the value of open positions as a result of increases in power prices across all segments, partially offset by the reversal of previously recognized unrealized losses on contracts that settled during the period. The $3.2 billion gain in operating costs and expenses from economic hedge positions was driven primarily by an increase in the value of open positions as a result of increases in natural gas and power prices across all segments, partially offset by the reversal of previously recognized unrealized gains on contracts that settled during the period.

For the nine months ended September 30, 2021, the $99 million loss in revenues from economic hedge positions was driven by a decrease in the value of open positions as a result of increases in 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.

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, 2022 and 2021. The realized and unrealized financial and physical trading results are included in revenue. The Company's trading activities are subject to limits based on the Company's Risk Management Policy.

			Nine months ended September 30,
(In millions)			2022						2021
Trading gains/(losses)
Realized			$	3					$	99
Unrealized			(7)						2
Total trading (losses)/gains			$	(4)					$	101

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, 2022			$	598					$	306					$	147					$	—					$	(2)					$	1,049
Nine months ended September 30, 2021			524						346						168						2						(4)						1,036

Operations and maintenance expense increased by $13 million for the nine months ended September 30, 2022, compared to the same period in 2021, due to the following:

			(In millions)
Decrease due to the sale of fossil generating assets to Generation Bridge in December 2021			$	(72)
Decrease due to Midwest Generation asset retirements in the second quarter of 2022 as well as spare parts inventory reserves in 2021			(18)
Increase in variable operation and maintenance expense at the PJM coal facilities associated with increased generation during 2022			30
Increase driven by W.A. Parish restoration efforts associated with the May 2022 extended outage			26
Increase in estimates of environmental remediation costs at deactivated sites in the East and West			26
Increase driven by higher retail operations costs			15
Increase due to scope of outages at the Texas coal and gas facilities in 2022 partially offset by a prior year planned outage at STP			14
Decrease driven by current year scrap proceeds associated with the demolition of the Encina site			(8)
Decrease driven by higher maintenance in 2021 resulting from the impacts of Winter Storm Uri			(2)
Other			2
Increase in operations and maintenance expense			$	13

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, 2022			$	153					$	113					$	12																	$	278
Nine months ended September 30, 2021			144						102						13																		259

Other cost of operations increased by $19 million for the nine months ended September 30, 2022, compared to the same period in 2021, due to the following:

			(In millions)
Decrease due to the sale of fossil generating assets to Generation Bridge in December 2021			$	(24)
Increase in retail gross receipt taxes due to higher revenues			32
Increase due to higher property insurance premiums			9
Increase due to changes in current year ARO cost estimates and the timing of ARO spend			3
Other			(1)
Increase in other cost of operations			$	19

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, 2022			$	230					$	167					$	65					$	23					$	485
Nine months ended September 30, 2021			245						237						66						21						569

Depreciation and amortization decreased by $84 million for the nine months ended September 30, 2022, compared to the same period in 2021, primarily due to lower depreciation as a result of asset impairments, sales, and retirements as well as lower amortization as a result of the expected roll off of acquired intangibles.

Impairment Losses

Impairment losses of $198 million were recorded during the nine months ended September 30, 2022 include $155 million primarily related to the decline in PJM capacity prices and the near-term retirement date of Joliet and $43 million primarily related to the purchase and sale agreement for the sale of the land and related assets at the Astoria generating site and the planned withdrawal and cancellation of its proposed Astoria redevelopment project. 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. Refer to Note 8, Impairments for further discussion.

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, 2022			$	449					$	328					$	162					$	34					$	—					$	973
Nine months ended September 30, 2021			435						371						131						37						(1)						973

Total selling, general and administrative costs in the nine months ended September 30, 2022 were flat, when compared to the same period in 2021, with fluctuations within selling, general and administrative costs shown below:

			(In millions)
Decrease due to Winter Storm Uri, including charitable giving, legal and other costs of $17 million and ERCOT default charges of $12 million in 2021			$	(29)
Decrease in transition service agreement costs related to the Direct Energy acquisition			(16)
Increase due to the favorable resolution of a legal matter in 2021			15
Increase in broker fee expenses, partially offset by lower commissions expenses			14
Increase due to higher legal and consulting expenses including spending related to Company's growth initiatives			11
Other			5
Change in selling, general and administrative costs			$	—

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, 2022			$	53					$	32					$	18											$	103
Nine months ended September 30, 2021			700						7						8												715

Provision for credit losses decreased by $612 million for the nine months ended September 30, 2022, compared to the same period in 2021, due to the following:

			(In millions)
Decrease due to Winter Storm Uri, including: Decrease of $403 million related to bilateral financial hedging risk Decrease of $152 million related to counterparty credit risk Decrease of $83 million related to ERCOT default shortfall payments			$	(638)
Increase due to higher revenues and deteriorated customer payment behavior			26
Decrease in provision for credit losses			$	(612)

Acquisition-Related Transaction and Integration Costs

Acquisition-related transaction and integration costs were $26 million for the nine months ended September 30, 2022, which were primarily integration costs related to Direct Energy. Acquisition-related transaction and integration costs of $81 million were incurred during the nine months ended September 30, 2021, related to Direct Energy, of which $24 million were acquisition-related transaction costs and $57 million were integration costs, primarily related to severance and consulting services.

Gain on Sale of Assets

The gain on sale of assets of $51 million for the nine months ended September 30, 2022 includes a $46 million gain related to the sale of the Company's 49% ownership in the Watson natural gas generating facility and a $22 million due to the sale of the Company's 50% ownership interest in Petra Nova, partially offset by a loss of $14 million on other asset sales and a $3 million adjustment to the proceeds on the sale of fossil generating assets to Generation Bridge in December of 2021. The gain on sale of assets of $17 million for the nine months ended September 30, 2021 was related to the sale of Agua Caliente in February 2021.

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 the 2026 Senior Notes and the partial redemption of the 2027 Senior Notes in the third quarter of 2021.

Interest Expense

Interest expense decreased by $61 million for the nine months ended September 30, 2022, compared to the same period in 2021, primarily due to debt reduction and the refinancing of debt to lower interest rates in the second half of 2021.

Income Tax Expense

For the nine months ended September 30, 2022, income tax expense of $739 million was recorded on pre-tax income of $3.1 billion. For the same period in 2021, income tax expense of $840 million was recorded on pre-tax income of $3.5 billion. The effective tax rates were 24.2% and 24.3% for the nine months ended September 30, 2022 and 2021, respectively.

For the nine months ended September 30, 2022, NRG's overall effective tax rate was higher than the statutory rate of 21% primarily due to state tax expense, partially offset by tax benefit resulting from the release of valuation allowance on state net operating losses and carbon capture tax credits. For the same period in 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.

Liquidity and Capital Resources

Liquidity Position

As of September 30, 2022 and December 31, 2021, NRG's total liquidity, excluding funds deposited by counterparties, of approximately $2.8 billion and $2.7 billion, respectively, was comprised of the following:

(In millions)			September 30, 2022						December 31, 2021
Cash and cash equivalents			$	333					$	250
Restricted cash - operating			6						4
Restricted cash - reserves(a)			40						11
Total			379						265
Total availability under Revolving Credit Facility and collective collateral facilities(b)			2,395						2,421
Total liquidity, excluding funds deposited by counterparties			$	2,774					$	2,686

(a) Includes reserves primarily for performance obligations

(b) Total capacity of Revolving Credit Facility and collective collateral facilities was $6.4 billion and $5.9 billion as of September 30, 2022 and December 31, 2021, respectively

For the nine months ended September 30, 2022, total liquidity, excluding funds deposited by counterparties, increased by $88 million. Changes in cash and cash equivalent balances are further discussed hereinafter under the heading Cash Flow Discussion. Cash and cash equivalents at September 30, 2022 were predominantly held in bank deposits.

Management believes that the Company's liquidity position and cash flows from operations will be adequate to finance operating and maintenance capital expenditures, to fund dividends to NRG's common stockholders, and to fund other liquidity commitments. Management continues to regularly monitor the Company's ability to finance the needs of its operating, financing and investing activity within the dictates of prudent balance sheet management.

The Company remains committed to maintaining a strong balance sheet and continues to work to achieve investment grade credit metrics. The Company expects to grow into its target investment grade metrics primarily through the realization of Direct Energy run-rate earnings and other growth initiatives.

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; as described more fully in Note 9, Long-term Debt and Finance Leases (iii) capital expenditures, including maintenance, repowering, development, and environmental; and (iv) allocations in connection with acquisition opportunities, debt repayments, share repurchases and dividend payments to stockholders, as described in Note 11, Changes in Capital Structure.

ERCOT Securitization Proceeds

During 2021, the Texas Legislature passed HB 4492 for ERCOT to mitigate exceptionally high price adders and ancillary service costs incurred by LSEs during Winter Storm Uri. HB 4492 authorized ERCOT to obtain $2.1 billion of financing to distribute to LSEs that were charged and paid to ERCOT those highly priced ancillary service and ORDPA during Winter Storm Uri. The Company received proceeds of $689 million from ERCOT in June 2022.

Receivables Securitization Facilities

On February 9, 2022, the Company entered into amendments to its existing Repurchase Facility to, among other things, (i) increase the size of the facility from $75 million to $150 million and (ii) replace LIBOR with term SOFR as the benchmark for the pricing rate. The Repurchase Facility has no commitment fee and borrowings will be drawn at SOFR + 1.30%. On July 26, 2022, the Company renewed its existing Repurchase Facility to extend the maturity date to July 26, 2023. As of September 30, 2022, there were no outstanding borrowings.

On July 26, 2022, NRG Receivables LLC, a wholly-owned indirect subsidiary of the Company, entered into an amendment to its Receivables Facility dated September 22, 2020 with a group of conduit lenders and banks and Royal Bank of Canada, as Administrative Agent to, among other things, (i) extend the scheduled termination date by one year, (ii) increase the aggregate commitments from $800 million to $1.0 billion, (iii) increase the letter of credit sublimit to equal the aggregate commitments, (iv) replace LIBOR with Term SOFR as the benchmark for borrowings and (v) add new originators . The weighted average interest rate related to usage under the Receivables Facility as of September 30, 2022 was 0.836%. As of September 30, 2022, there were no outstanding borrowings and there were $884 million in letters of credit issued under the Receivables Facility.

Bilateral Letter of Credit Facilities

On April 29, 2022, May 27, 2022 and October 13, 2022, the Company increased the size of the facilities by $100 million, $50 million and $50 million, respectively, to provide additional liquidity, allowing for the issuance of up to $675 million of letters of credit. As of September 30, 2022, $592 million was issued under these facilities.

Astoria

On September 9, 2022, the Company entered into a definitive purchase agreement to sell land and related assets from the Astoria site, within the East region of operations, for initial proceeds of $212 million subject to purchase price adjustments and certain other indemnifications. As part of the transaction, NRG will enter into an agreement to lease the land back for the purpose of operating the Astoria facility through the planned April 30, 2023 retirement date. The operating lease agreement is expected to end six months after the facility's actual retirement date. The transaction is expected to close in the fourth quarter of 2022 and is subject to various closing conditions.

Sale of Watson

On June 1, 2022, the Company closed on the sale of its 49% ownership in the Watson natural gas generating facility for $59 million. NRG recognized a gain on the sale of $46 million.

CARES Act

On March 27, 2020, the U.S. government enacted the CARES Act, which provides, among other things: (i) the option to defer payments of certain 2019 employer payroll taxes incurred after the date of enactment; and (ii) allows NOLs from tax years 2018, 2019 and 2020 to be carried back five years. The total benefit to the Company due to the CARES Act was $35 million. Of this amount, $13 million related to certain 2019 employer payroll taxes is 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 (e.g., buying energy before receiving retail revenues); and (iv) initial collateral for large structured transactions. As of September 30, 2022, the Company had total cash collateral outstanding of $262 million and $4 billion outstanding in letters of credit to third parties primarily to support its market activities. As of September 30, 2022, total funds deposited by counterparties were $3.1 billion in cash and $717 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. The first lien program does not limit the volume that can be hedged, or the value of underlying out-of-the-money positions. The first lien program also does not require NRG to post collateral above any threshold amount of exposure. The first lien structure is not subject to unwind or termination upon a ratings downgrade of a counterparty and has no stated maturity date.

The Company's first lien counterparties may have a claim on its assets to the extent market prices differ from the hedged prices. As of September 30, 2022, 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, 2022:

Equivalent Net Sales Secured by First Lien Structure**(a)**			2022						2023
In MW			613						713
As a percentage of total net coal and nuclear capacity(b)			18%						16%

(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, 2022, and the estimated capital expenditures forecast for the remainder of 2022.

(In millions)			Maintenance						Environmental						Growth Investments**(a)**						Total
Texas			$	(152)					$	(1)					$	(23)					$	(176)
East			(3)						—						(3)						(6)
West/Services/Other			(17)						—						(10)						(27)
Corporate			(2)						—						(39)						(41)
Total cash capital expenditures for the nine months ended September 30, 2022			(174)						(1)						(75)						(250)
Investments			—						—						(105)						(105)
Total capital expenditures and investments			(174)						(1)						(180)						(355)
Estimated capital expenditures and investments for the remainder of 2022(b)			$	(110)					$	(1)					$	(90)					$	(201)

(a) Includes other investments, acquisitions and integration projects

(b) Estimated capital expenditures related to W.A. Parish do not reflect expected insurance recoveries

Growth investments for the nine months ended September 30, 2022 include expenditures for Encina site improvements classified as ARO payments. NRG has completed its demolition activities at the site and has begun marketing the site.

Environmental Capital Expenditures

NRG estimates that environmental capital expenditures from 2022 through 2026 required to comply with environmental laws will be approximately $32 million. The decrease of $24 million from the previous quarter is primarily due to changes in assumptions regarding the cost of complying, and recharacterization of the certain cost of complying with, water regulations in Texas.

Share Repurchases

In December 2021, the Company's board of directors authorized the Company to repurchase $1.0 billion of its common stock, of which $44 million was completed in 2021. During the nine months ended September 30, 2022, the Company completed $489 million of share repurchases at an average price of $40.07 per share, including $6 million of equivalent shares purchased in lieu of tax withholdings on equity compensation issuances. Through October 31, 2022, an additional $76 million of share repurchases were executed at an average price of $41.71 per share. In October 2022, the Board of Directors approved an additional $600 million in share repurchases.

Common Stock Dividends

During the first quarter of 2022, NRG increased the annual dividend to $1.40 from $1.30 per share and expects to target an annual dividend growth rate of 7%-9% per share in subsequent years. A quarterly dividend of $0.35 per share was paid on the Company's common stock during the three months ended September 30, 2022. On October 21, 2022, NRG declared a quarterly dividend on the Company's common stock of $0.35 per share, payable on November 15, 2022 to stockholders of record as of November 1, 2022. Beginning in the first quarter of 2023, NRG will increase the annual dividend by 8% to $1.51 per share.

Obligations under Certain Guarantees

NRG and its subsidiaries enter into various contracts that include indemnifications and guarantee provisions as a routine part of the Company’s business activities. For further discussion, see Note 27, Guarantees, to the Company's 2021 Form 10-K.

Obligations Arising Out of a Variable Interest in an Unconsolidated Entity

Variable interest in equity investments — NRG’s investment in Ivanpah is a variable interest entity for which NRG is not the primary beneficiary. See also Note 10, Investments Accounted for Using the Equity Method and Variable Interest Entities, or VIEs. NRG's pro-rata share of non-recourse debt was approximately $492 million as of September 30, 2022. This indebtedness may restrict the ability of Ivanpah to issue dividends or distributions to NRG.

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 2021 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, 2022.

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)			2022						2021						Change
Cash provided by operating activities			$	1,758					$	1,855					$	(97)
Cash used by investing activities			(205)						(3,585)						3,380
Cash provided/(used) by financing activities			855						(177)						1,032

Cash provided by operating activities

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

			(In millions)
Decrease in operating income adjusted for other non-cash items			$	(1,399)
Increase due to receipt of uplift securitization proceeds from ERCOT			689
Increase in working capital primarily attributable to the impact of higher market prices on accounts receivable and accounts payable, partially offset by a decrease working capital related to higher priced natural gas inventory			323
Changes in cash collateral in support of risk management activities due to change in commodity prices			351
Decrease in working capital primarily due to timing of prepaid broker fees			(47)
Other			(14)
			$	(97)

Cash used by investing activities

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

			(In millions)
Decrease in cash paid for acquisitions primarily due to the Direct Energy acquisition in 2021			$	3,474
Decrease in proceeds from sale of assets primarily due to the sale of Agua Caliente in 2021			(91)
Increase in proceeds from sales of investments in nuclear decommissioning trust fund securities, net of purchases			38
Increase in capital expenditures			(31)
Increase in purchases of emissions allowances, net of sales			(10)
			$	3,380

Cash provided/(used) by financing activities

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

			(In millions)
Decrease primarily in payments of long-term debt			$	1,356
Increase in net receipts from settlement of acquired derivatives			1,200
Decrease in proceeds from issuance of long-term debt			(1,100)
Increase in payments for share repurchase activity			(475)
Increase due to payments of debt extinguishment costs and deferred issuance costs in prior year			65
Increase in payments of dividends to common stockholders			(13)
Other			(1)
			$	1,032

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

For the nine months ended September 30, 2022, the Company had domestic pre-tax book income of $2.9 billion and foreign pre-tax book income of $117 million. As of December 31, 2021, the Company had cumulative U.S. Federal NOL carryforwards of $8.4 billion, of which $11 million were generated prior to Tax Cuts and Jobs Act and will begin expiring in 2031, and cumulative state NOL carryforwards of $5.2 billion for financial statement purposes. NRG also has cumulative foreign NOL carryforwards of $383 million, which do not have an expiration date. In addition to the above NOLs, NRG has a $20 million indefinite carryforward for interest deductions, as well as $384 million of tax credits to be utilized in future years. As a result of the Company's tax position, including the utilization of federal and state NOLs, and based on current forecasts, the Company anticipates net income tax payments, due to federal, state and foreign jurisdictions, of up to $59 million in 2022.

As of September 30, 2022, the Company has $22 million of tax-effected uncertain federal and state tax benefits, for which the Company has recorded a non-current tax liability of $23 million (inclusive of accrued interest) until final resolution is reached with the related taxing authority.

The Company is no longer subject to U.S. federal income tax examinations for years prior to 2019. With few exceptions, state and Canadian income tax examinations are no longer open for years prior to 2013.

Deferred tax assets and valuation allowance

Net deferred tax balance — As of September 30, 2022 and December 31, 2021, NRG recorded a net deferred tax asset, excluding valuation allowance, of $1.6 billion and $2.3 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, 2022 as discussed below.

NOL Carryforwards — As of September 30, 2022, the Company had a tax-effected cumulative U.S. NOLs consisting of carryforwards for federal and state income tax purposes of $1.8 billion and $310 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 $92 million with no expiration date.

Valuation Allowance — As of September 30, 2022 and December 31, 2021, the Company’s tax-effected valuation allowance was $207 million and $248 million, respectively, consisting of state NOL carryforwards and foreign NOL carryforwards. The valuation allowance was recorded based on the assessment of cumulative and forecasted pre-tax book earnings and the future reversal of existing taxable temporary differences.

Guarantor Financial Information

As of September 30, 2022, the Company's outstanding registered senior notes consisted of $375 million of the 2027 Senior Notes and $821 million of the 2028 Senior Notes as shown in Note 9, Long-term Debt and Finance Leases. These Senior Notes are guaranteed by certain of NRG's current and future 100% owned domestic subsidiaries, or guarantor subsidiaries (the “Guarantors”). See Exhibit 22.1 for a listing of the Guarantors. These guarantees are both joint and several.

NRG conducts much of its business through and derives much of its income from its subsidiaries. Therefore, the Company's ability to make required payments with respect to its indebtedness and other obligations depends on the financial 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, 2022						Nine months ended September 30, 2021
Revenues(a)			$	20,918					$	17,675
Operating income(b)			3,450						4,144
Total other expense			(252)						(373)
Income from continuing operations before income taxes			3,198						3,771
Net Income			2,486						2,963

(a)Intercompany transactions with Non-Guarantors of $137 million and $77 million during the nine months ended September 30, 2022 and 2021, respectively

(b)Intercompany transactions with Non-Guarantors including cost of operations of $(319) million and $(191) million and selling, general and administrative of $142 million and $76 million during the nine months ended September 30, 2022 and 2021, respectively

The following table presents the summarized balance sheet information:

(In millions)			September 30, 2022						December 31, 2021
Current assets(a)			$	16,856					$	9,399
Property, plant and equipment, net			1,326						1,324
Non-current assets			12,666						11,569
Current liabilities(b)			13,848						7,590
Non-current liabilities			12,459						11,195

(a)Includes intercompany receivables due from Non-Guarantors of $104 million and $86 million as of September 30, 2022 and December 31, 2021, respectively

(b)Includes intercompany payables due from Non-Guarantors of $47 million and $50 million as of September 30, 2022 and December 31, 2021, respectively

Fair Value of Derivative Instruments

NRG may enter into power purchase and sales contracts, fuel purchase contracts and other energy-related financial instruments to mitigate variability in earnings due to fluctuations in spot market prices and to hedge fuel requirements at power plants or retail load obligations. In addition, in order to mitigate foreign exchange rate risk primarily associated with the purchase of USD denominated natural gas for the Company's Canadian business, NRG enters into foreign exchange contract agreements.

NRG's trading activities are subject to limits in accordance with the Company's Risk Management Policy. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings.

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, 2022, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at September 30, 2022. For a full discussion of the Company's valuation methodology of its contracts, see Derivative Fair Value Measurements in Note 5, Fair Value of Financial Instruments.

Derivative Activity Gains/(Losses)			(In millions)
Fair Value of Contracts as of December 31, 2021			$	2,341
Contracts realized or otherwise settled during the period			(1,014)
Changes in fair value			3,882
Fair Value of Contracts as of September 30, 2022			$	5,209

			Fair Value of Contracts as of September 30, 2022
(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			$	984					$	601					$	47					$	13					$	1,645
Level 2			1,706						853						218						105						2,882
Level 3			407						128						35						112						682
Total			$	3,097					$	1,582					$	300					$	230					$	5,209

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, 2022, NRG's net derivative asset was $5.2 billion, an increase to total fair value of $2.9 billion as compared to December 31, 2021. This increase was primarily driven by gains in fair value, partially offset by roll-off of trades that settled 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 $1.3 billion in the net value of derivatives as of September 30, 2022.

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, 2022.

Critical Accounting 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 appropriate technical accounting rules and guidance involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges, and the fair value of certain assets and liabilities. These judgments, in and of themselves, could materially affect the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment may also have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies has not changed.

NRG evaluates these estimates, on an ongoing basis, utilizing historic experience, consultation with experts and other methods the Company considers reasonable. In any event, actual results may differ substantially from the Company's estimates. Any effects on the Company's business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the information that gives rise to the revision becomes known.

The Company identifies its most critical accounting estimates as those that are the most pervasive and important to the portrayal of the Company's financial position and results of operations, and require the most difficult, subjective and/or complex judgments by management regarding estimates about matters that are inherently uncertain.

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 2021 Form 10-K. There have been no material changes to the Company's critical accounting estimates since the 2021 Form 10-K.