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~~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,~~16, 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~~expands 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~~was 2,940MW with a total cost of ~~$54~~$53 million. ~~For Phase II,~~

The PUCT engaged an independent consultant, E3, to evaluate various resource adequacy proposals and recommend a policy direction to increase incentives for investment in dispatchable generation in ERCOT. On November 10, 2022, the ~~PUCT Chair endorsed~~independent consultant provided a ~~version of NRG's Load-Serving~~report including various market design options such as a Forward Reliability Market, Load Servicing Entity Reliability Obligation ~~("LSERO") idea; that retailers~~ and ~~other LSEs should~~a new concept called a Performance Credit Mechanism ("PCM"). The PCM measures real-time contribution to system reliability and provides compensation for resources to 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.~~available. 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") hasstaff filed a ~~proposal to create a net-load based capacity market that allocates costs to loads, renewables~~summary of comments and ~~thermal resources with forced outages. A broad group of stakeholders, including NRG, have expressed~~their recommendations, which support PCM. On January 19, 2023, the Commission approved an order adopting the PCM as their policy direction for resource adequacy in ERCOT, however, implementation is delayed until 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.legislature reviews.

~~Activity~~Ruling on ~~Securitization and ERCOT~~ Pricing during Winter Storm Uri — On March 17, 2023, the Third Court of Appeals issued a ruling in Luminant Energy Co. v. PUCT, which is an appeal relating to the validity of two orders issued by the PUCT on February 15 and 16, 2021, respectively, governing scarcity pricing in the ERCOT wholesale electricity market during Winter Storm Uri. The Third Court found that the PUCT exceeded its statutory authority by ordering the market price of energy to be set at the high system wide offer cap due to scarcity conditions as a result of firm load shed occurring in ERCOT. The Third Court reversed the PUCT's orders and remanded the case. At the March 23, 2023 open meeting, the PUCT voted to appeal the Third Court's ruling to the Supreme Court of Texas. The outcome of this case could require a repricing of the market prices during that time.

Voluntary Mitigation ("VMP") Changes — On March 13, 2023, the PUCT Staff determined that a portion of NRG's VMP should be terminated due to the increase in procurement of ancillary services by ERCOT, specifically non-spin reserve services, following Winter Storm Uri. As such, PUCT Staff terminated part of the VMP for NRG which provides protection from wholesale market power abuse accusations related to offers for ancillary services. NRG agreed with these changes to the VMP. At the March 23, 2023 open meeting, the PUCT approved the amended VMP.

PJM

PJM Delays Base Residual Auction Results and Files to Update Tariff — The ~~Texas Legislature acted~~Base Residual Auction for the 2024/2025 delivery year commenced on December 7, 2022 and closed on December 13, 2022. On December 19, 2022, PJM announced that it would delay the publication of the auction results. On December 23, 2022, PJM made a filing at FERC to ~~pass~~revise the definition of Locational Deliverability Area Reliability Requirement in the Tariff. This would allow PJM to exclude certain resources from the calculation of the Local Deliverability Area Reliability Requirement. On February 21, 2023, FERC accepted PJM's filing. Multiple parties, including NRG, have filed for rehearing. The price of the auction cleared was significantly lower as a ~~variety~~result of ~~securitization vehicles to finance exceptionally high power~~the PJM Tariff change.

Capacity Performance Penalties and ~~gas costs~~Bonuses from Winter Storm ~~Uri, including HB 4492. ERCOT subsequently filed two applications requesting the PUCT~~Elliott — PJM experienced approximately 23 hours of Capacity Performance events from December 23-24, 2022 across PJM's entire footprint. The Company will be subject 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~~penalty or bonus payments ~~and reimburse congestion revenue right account holders for amount~~ related to the ~~default of~~events with settlements to occur in 2023. PJM anticipates that certain market participants who incurred penalties may encounter challenges in paying penalties levied upon them. This may result in bonus payments being prorated. On February 2, 2023, PJM made a filing at FERC that, if approved, would give PJM the ability to extend the payment period for PJM members who incurred penalties for an additional 9 months. On April 3, 2023, FERC approved PJM's request to allow Winter Storm Elliott penalty payments to be spread over 9 months (with interest) and allow future penalties to have a 9 month window to be satisfied without interest. In addition, multiple generators filed various complaints against PJM at FERC alleging that PJM violated its Tariff in, among other ~~than electric cooperatives Brazos Electric Cooperative Inc. ("Brazos") and Rayburn Country Electric Cooperative, Inc. ("Rayburn"),~~things, the manner in which ~~are discussed below (the "Default Securitization") and $2.1 billion related to highly priced ancillary service and ORPDA~~it operated the system during Winter Storm ~~Uri (the "Uplift Securitization").~~Elliott and the resulting assessment of capacity performance penalties.

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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~~PJM Files at FERC to Delay the ~~rulemaking on June 23, 2022. On September 29, 2022, the PUCT adopted the Phase II Weatherization Standards.~~

~~PJM~~

~~Indian River RMR Proceeding~~Upcoming Base Residual Auctions — 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,~~11, 2023, PJM filed ~~a proposed tariff change at FERC~~ to ~~largely eliminate~~delay 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,~~Auctions for the 2025/2026 to 2028/2029 delivery years. PJM ~~proposed energy and reserve~~proposes to develop 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 atimprove 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 rehearingoperation of the ~~December 2021 order, FERC issued~~capacity market, and plans to make a ~~notice denying~~filing regarding those reforms by October 1, 2023. PJM proposes to restart the ~~rehearings by operation of law and providing for further consideration~~auctions after FERC's ruling 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 accreditationthese 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~~changes.

~~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,~~2023, with recent staff proposals recommending an extension of these order through 2025. Further procurement order in this docket issued in February 2023 directed LSEs to procure an additional four GW of clean resources in the ~~CPUC approved a decision that raises the reserve~~2026 to 2028 timeframe. Reserve margin increased 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. Recently opened rulemaking will determine how the resource adequacy from the extension will be treated. Finally, the CPUC released a proposed order in March 2023 regarding details for implementation of a new Resource Adequacy ("RA") program beginning in 2025 which will require procurement to meet needs during every hour of the day. The result of these changes will likely keep ~~Resource Adequacy ("RA")~~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 and continue to be revised 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~~2022 Form 10-K in Item 1, Business - Environmental Matters and Item 1A, Risk Factors. These matters have been updated in Note ~~18,~~17, Environmental Matters, to the condensed consolidated financial statements of this Form 10-Q and as follows.

Air

The CAA and ~~the resulting~~related regulations (as well as similar state and local requirements) have the potential to affect air emissions, operating practices and pollution control equipment required at power plants. Under the CAA, the EPA sets NAAQS for certain pollutants including 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. In January 2023, the EPA proposed increasing the stringency of the PM2.5 NAAQS. The Company maintains a comprehensive compliance strategy to address continuing and new requirements. Complying with increasingly stringent air regulations could require the installation of additional emissions control equipment at some NRG facilities or retiring of units if installing such controls is not economic. Significant changes to air regulatory programs affecting the Company are described below.

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~~vacate the repeal of the CPP). On June 30, 2022, the U.S. Supreme Court held that the "generation shifting" approach in the CPP exceeded the powers granted to the EPA by Congress. The Court did not address the related issues of whether the EPA may adopt only

measures applied at each source. 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,~~On March 15, 2023, the EPA ~~proposed revising~~signed and released a prepublication of a final rule that if and when published in the Federal Register would have significantly revised the CSAPR to address the ~~good-neighbor provisions~~good-

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neighbor obligations of the 2015 ozone ~~NAAQS. If~~NAAQS for 23 states after earlier having disapproved numerous state plans to address the issue. Several states, including Texas, challenged the EPA's disapproval of their state plans. On May 1, 2023, the United States Court of Appeals for the Fifth Circuit stayed the EPA's disapproval of Texas' and Louisiana's state plans, which disapprovals are a condition precedent to the EPA imposing its plan on Texas and Louisiana. Accordingly, the EPA may not publish this rule in the Federal Register or if it does publish the rule, ~~were finalized as proposed,~~ it would ~~apply~~be ineffective in Texas and Louisiana while the stay is pending. The rule would have decreased over time the ozone-season NOx allowances allocated to ~~25 states (including Texas) beginning in 2023. In 2023, the revised Group 3 trading program (previously established~~generators in the ~~Revised CSAPR Update Rule)~~23 states beginning this summer by assuming that participants in this cap-and-trade program had or would ~~have emission budgets based on~~optimize existing NOx ~~emission rates that the EPA says are achievable by existing~~ controls ~~at power plants. Starting in 2026, the~~and later install additional 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~~of: (i) the legal challenges ~~after~~to the various state disapprovals; (ii) whether the EPA will proceeds with publication in the Federal Register; and (iii) legal challenges to the final rule if it is ~~finalized.~~published in the Federal Register.

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.~~surface impoundments. 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. NRG anticipates further rulemaking related to the Federal Permit Program and legacy surface impoundments.

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~~four times through addendums to cover payments through December 31, ~~2022.~~2025. 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;

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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~~On March 29, 2023, the EPA ~~will release a~~ proposed ~~rule in~~revisions to the ~~first quarter of~~ELG and is accepting comments on the proposal until May 30, 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~~required 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.

Houston Nonattainment for 2008 Ozone Standard — During the fourth quarter of 2022, the EPA changed the Houston area's classification from Serious to Severe nonattainment for the 2008 Ozone Standard. Accordingly, Texas is required to develop a new control strategy and submit it to the EPA.

Significant Events

The following significant events have occurred during ~~2022~~2023 as further described within this Management's Discussion and Analysis and the condensed consolidated financial statements:

Vivint Acquisition

On March 10, 2023, the Company completed the acquisition of Vivint. The Company paid $12 per share, or $2.6 billion in cash. For further discussion, see Note 4, Acquisitions and Dispositions.

Series A Preferred Stock

On March 9, 2023, the Company issued 650,000 shares of 10.25% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock. The proceeds, net of issuance costs, of $636 million were used to fund the Vivint acquisition. For further discussion, see Note 10, Changes in Capital Structure.

Issuance of 2033 Senior Secured First Lien Notes

On March 9, 2023, the Company issued $740 million of aggregate principal amount of 7.000% senior secured first lien notes due 2023. The net proceeds of $724 million, net of issuance costs, were used to fund the Vivint acquisition. For further discussion, see Note 8, Long-term Debt and Finance Leases.

Astoria

On ~~September 9, 2022,~~January 6, 2023, NRG closed on the ~~Company entered into a definitive purchase agreement to sell~~sale of 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~~transaction fees of $3 million and certain ~~other~~ indemnifications. NRG recognized a gain on the sale of $199 million. As part of the transaction, NRG ~~will enter~~entered into an agreement to lease the land back for the purpose of operating the Astoria ~~facility through the planned April 30, 2023 retirement date.~~gas turbines. The ~~operating~~ lease agreement is expected to terminate by the end ~~six months after~~of 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.~~year.

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,~~work completed to date, 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,~~2023, NRG increased the annual dividend to ~~$1.40~~$1.51 from ~~$1.30~~$1.40 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.~~2022. 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 Renewable PPAs totaling approximately ~~2.4~~1.9 GW with third-party project developers and other counterparties, of which approximately ~~45%~~1.1 GW are ~~operational.~~operational as of April 30, 2023. The average ~~tenor~~tenure of these agreements is ~~twelve~~eleven years. The Company expects to continue evaluating and executing similar agreements that support the needs of the business. The total GW procured through Renewable 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.48

~~COVID-19~~

Draft 4 04/21/2023

~~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~~2022 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,								Three months ended March 31,
(In millions, except as otherwise noted)	(In millions, except as otherwise noted)	2022		2021		Change			2022		2021		Change			(In millions, except as otherwise noted)	2023		2022		Change
Revenue	Revenue															Revenue
Retail revenue	Retail revenue	$	7,858	$	5,951	$	1,907		$	22,379	$	16,929	$	5,450		Retail revenue	$	7,363	$	7,570	$	(207)
Energy revenue(a)	Energy revenue(a)	450		336		114			1,034		989		45			Energy revenue(a)	128		278		(150)
Capacity revenue(a)	Capacity revenue(a)	38		189		(151)			244		615		(371)			Capacity revenue(a)	42		116		(74)
Mark-to-market for economic hedging activities	Mark-to-market for economic hedging activities	33		3		30			(248)		(99)		(149)			Mark-to-market for economic hedging activities	91		(133)		224
Contract amortization	Contract amortization	(6)		(3)		(3)			(28)		(19)		(9)			Contract amortization	(11)		(9)		(2)
Other revenues(a)(b)	Other revenues(a)(b)	137		133		4			307		1,528		(1,221)			Other revenues(a)(b)	109		74		35
Total revenue	Total revenue	8,510		6,609		1,901			23,688		19,943		3,745			Total revenue	7,722		7,896		(174)
Operating Costs and Expenses	Operating Costs and Expenses															Operating Costs and Expenses
Cost of fuel	Cost of fuel	742		466		(276)			1,603		1,530		(73)			Cost of fuel	163		329		166
Purchased energy and other cost of sales(c)	Purchased energy and other cost of sales(c)	6,494		4,641		(1,853)			18,757		14,774		(3,983)			Purchased energy and other cost of sales(c)	6,002		6,452		450

Mark-to-market for economic hedging activities	Mark-to-market for economic hedging activities	122		(1,782)		(1,904)			(3,155)		(4,122)		(967)			Mark-to-market for economic hedging activities	2,035		(2,410)		(4,445)
Contract and emissions credit amortization(c)	Contract and emissions credit amortization(c)	(16)		(45)		(29)			87		19		(68)			Contract and emissions credit amortization(c)	108		138		30
Operations and maintenance	Operations and maintenance	359		332		(27)			1,049		1,036		(13)			Operations and maintenance	385		336		(49)
Other cost of operations	Other cost of operations	101		80		(21)			278		259		(19)			Other cost of operations	85		85		—
Cost of operations (excluding depreciation and amortization shown below)	Cost of operations (excluding depreciation and amortization shown below)	7,802		3,692		(4,110)			18,619		13,496		(5,123)			Cost of operations (excluding depreciation and amortization shown below)	8,778		4,930		(3,848)
Depreciation and amortization	Depreciation and amortization	145		199		54			485		569		84			Depreciation and amortization	190		183		(7)
Impairment losses		43		—		(43)			198		306		108

Selling, general and administrative costs	Selling, general and administrative costs	326		318		(8)			973		973		—			Selling, general and administrative costs	426		347		(79)
Provision for credit losses		52		64		12			103		715		612

Acquisition-related transaction and integration costs	Acquisition-related transaction and integration costs	8		17		9			26		81		55			Acquisition-related transaction and integration costs	71		8		(63)
Total operating costs and expenses	Total operating costs and expenses	8,376		4,290		(4,086)			20,404		16,140		(4,264)			Total operating costs and expenses	9,465		5,468		(3,997)

Gain on sale of assets		22		—		22			51		17		34
Operating Income		156		2,319		(2,163)			3,335		3,820		(485)
Gain/(loss) on sale of assets																Gain/(loss) on sale of assets	199		(3)		202
Operating (Loss)/Income																Operating (Loss)/Income	(1,544)		2,425		(3,969)
Other Income/(Expense)	Other Income/(Expense)															Other Income/(Expense)
Equity in earnings of unconsolidated affiliates		11		15		(4)			—		23		(23)
Equity in earnings/(losses) of unconsolidated affiliates																Equity in earnings/(losses) of unconsolidated affiliates	5		(15)		20

Other income, net	Other income, net	21		8		13			33		42		(9)			Other income, net	16		—		16
Loss on debt extinguishment		—		(57)		57			—		(57)		57

Interest expense	Interest expense	(105)		(122)		17			(313)		(374)		61			Interest expense	(148)		(103)		(45)
Total other expense	Total other expense	(73)		(156)		83			(280)		(366)		86			Total other expense	(127)		(118)		(9)
Income Before Income Taxes		83		2,163		(2,080)			3,055		3,454		(399)
Income tax expense		16		545		529			739		840		101
(Loss)/Income Before Income Taxes																(Loss)/Income Before Income Taxes	(1,671)		2,307		(3,978)
Income tax (benefit)/expense																Income tax (benefit)/expense	(336)		571		907

Net Income		$	67	$	1,618	$	(1,551)		$	2,316	$	2,614	$	(298)
Net (Loss)/Income																Net (Loss)/Income	$	(1,335)	$	1,736	$	(3,071)

Business Metrics	Business Metrics															Business Metrics
Average natural gas price — Henry Hub ($/MMBtu)	Average natural gas price — Henry Hub ($/MMBtu)	$	8.20	$	4.01	104		%	$	6.77	$	3.18	113		%	Average natural gas price — Henry Hub ($/MMBtu)	$	3.42	$	4.95	(31)		%

(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

4649

Draft 4 04/21/2023

Management’s discussion of the results of operations for the three months ended ~~September 30,~~March 31, 2023 and 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~~March 31, 2023 and ~~2021.~~2022. Texas, East and West average on-peak power prices ~~increased~~decreased for the three months ended ~~September 30, 2022~~March 31, 2023 as compared to the same period in ~~2021~~2022 as a result of ~~higher~~lower natural gas ~~prices.~~prices, while average CAISO on-peak power prices increased primarily driven by colder winter weather in California in 2023.


		Average on Peak Power Price ($/MWh)							Average on Peak Power Price ($/MWh)
		Three months ended September 30,							Three months ended March 31,
Region	Region	2022		2021		Change %		Region	2023		2022		Change %
Texas	Texas							Texas
ERCOT - Houston(a)	ERCOT - Houston(a)	$	128.61	$	47.11	173	%	ERCOT - Houston(a)	$	26.98	$	48.69	(45)	%
ERCOT - North(a)	ERCOT - North(a)	131.62		46.16		185	%	ERCOT - North(a)	26.72		46.27		(42)	%

East	East							East
NY J/NYC(b)	NY J/NYC(b)	$	109.43	$	54.75	100	%	NY J/NYC(b)	$	45.40	$	104.26	(56)	%
NEPOOL(b)	NEPOOL(b)	99.14		52.57		89	%	NEPOOL(b)	52.63		116.48		(55)	%
COMED (PJM)(b)	COMED (PJM)(b)	101.00		48.36		109	%	COMED (PJM)(b)	29.78		44.69		(33)	%
PJM West Hub(b)	PJM West Hub(b)	110.99		51.32		116	%	PJM West Hub(b)	36.49		58.33		(37)	%

West	West							West
MISO - Louisiana Hub(b)	MISO - Louisiana Hub(b)	$	90.32	$	44.95	101	%	MISO - Louisiana Hub(b)	$	29.78	$	43.49	(32)	%
CAISO - SP15(b)	CAISO - SP15(b)	110.03		72.02		53	%	CAISO - SP15(b)	92.54		45.20		105	%


Delaware						41-1724239
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification No.)


910 Louisiana Street	Houston	Texas	77002
(Address of principal executive offices)			(Zip Code)


Title of Each Class	Trading Symbol(s)	Name of Exchange on Which Registered
Common Stock, par value $0.01	NRG	New York Stock Exchange


CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION			3
GLOSSARY OF TERMS			5
PART I — FINANCIAL INFORMATION			8
ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES			8
ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			3844
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			7366
ITEM 4 — CONTROLS AND PROCEDURES			7568
PART II — OTHER INFORMATION			7669
ITEM 1 — LEGAL PROCEEDINGS			7669
ITEM 1A — RISK FACTORS			7669
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			7683
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES			7683
ITEM 4 — MINE SAFETY DISCLOSURES			7683
ITEM 5 — OTHER INFORMATION			7683
ITEM 6 — EXHIBITS			7784
SIGNATURES			7886


~~2021~~2022 Form 10-K						NRG’s Annual Report on Form 10-K for the year ended December 31, ~~2021~~2022
ACE						Affordable Clean Energy
AESO						Alberta Electric System Operator
~~Agua Caliente~~						~~Agua Caliente Solar Project, a 290 MW photovoltaic power station located in Yuma County, Arizona in which NRG owned a 35% interest~~
ARO						Asset Retirement Obligation
ASC						The FASB Accounting Standards Codification, which the FASB established as the source of authoritative GAAP
ASU						Accounting Standards Updates - updates to the ASC
~~Average realized power prices~~						~~Volume-weighted average power prices, net of average fuel costs and reflecting the impact of settled hedges~~
BTU						British Thermal Unit
Business						NRG Business, which serves business customers
CAA						Clean Air Act
CAISO						California Independent System Operator
~~CARES Act~~						~~Coronavirus Aid, Relief, and Economic Security Act of 2020~~
CDD						Cooling Degree Day
CFTC						U.S. Commodity Futures Trading Commission

~~Centrica~~						~~Centrica plc~~
CO2						Carbon Dioxide
Company						NRG Energy, Inc.
Convertible Senior Notes						As of ~~September 30, 2022,~~March 31, 2023, consists of NRG’s $575 million unsecured 2.75% Convertible Senior Notes due 2048
Cottonwood						Cottonwood Generating Station, a ~~1,177 MW~~ natural gas-fueled plant
~~COVID-19~~						~~Coronavirus Disease 2019~~ located in Deweyville, Texas in which NRG is leasing back through May 2025
CPP						Clean Power Plan
CPUC						California Public Utilities Commission
CWA						Clean Water Act
D.C. Circuit						U.S. Court of Appeals for the District of Columbia Circuit
Dth						Dekatherms
Economic gross margin						Sum of retail revenue, energy revenue, capacity revenue and other revenue, less cost of fuels and purchased energy and other cost of sales
EGU						Electric Generating Unit
EPA						U.S. Environmental Protection Agency
ERCOT						Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas
ESPP						NRG Energy, Inc. Amended and Restated Employee Stock Purchase Plan
Exchange Act						The Securities Exchange Act of 1934, as amended
FASB						Financial Accounting Standards Board
FERC						Federal Energy Regulatory Commission
FGD						Flue gas desulfurization
FTRs						Financial Transmission Rights
GAAP						Generally accepted accounting principles in the U.S.
GHG						Greenhouse Gas
Green Mountain Energy						Green Mountain Energy Company
GW						Gigawatts
GWh						Gigawatt Hour
HDD						Heating Degree Day


Heat Rate						A measure of thermal efficiency computed by dividing the total BTU content of the fuel burned by the resulting kWhs generated. Heat rates can be expressed as either gross or net heat rates, depending upon whether the electricity output measured is gross or net generation. Heat rates are generally expressed as BTU per net kWh
Home						NRG Home, which serves residential customers
HLW						High-level radioactive waste
ICE						Intercontinental Exchange


IESO						Independent Electricity System Operator
ISO						Independent System Operator, also referred to as RTOs
ISO-NE						ISO New England Inc.
Ivanpah						Ivanpah Solar Electric Generation Station, a ~~393 MW~~ solar thermal power plant located in California's Mojave Desert in which NRG owns 54.5% interest
kWh						Kilowatt-hour
LaGen						Louisiana Generating, LLC
LIBOR						London Inter-Bank Offered Rate
LSEs						Load Serving Entities
LTIPs						Collectively, the NRG long-term incentive plan ("LTIP") and the NRG ~~GenOn~~Vivint LTIP
MDth						Thousand Dekatherms
Midwest Generation						Midwest Generation, LLC
MISO						Midcontinent Independent System Operator, Inc.
MMBtu						Million British Thermal Units
MW						Megawatts
MWh						Saleable megawatt hour net of internal/parasitic load megawatt-hour
NAAQS						National Ambient Air Quality Standards
NEPOOL						New England Power Pool
NERC						North American Electric Reliability Corporation

Net Exposure						Counterparty credit exposure to NRG, net of collateral
Net Revenue Rate						Sum of retail revenues less TDSP transportation charges
Nodal						Nodal Exchange is a derivatives exchange
NOL						Net Operating Loss
NOx						Nitrogen Oxides
NPNS						Normal Purchase Normal Sale
NRC						U.S. Nuclear Regulatory Commission
NRG						NRG Energy, Inc.


Nuclear Decommissioning Trust Fund						NRG's nuclear decommissioning trust fund assets, which are for the Company's portion of the decommissioning of the STP, Units 1 & 2
Nuclear Waste Policy Act						U.S. Nuclear Waste Policy Act of 1982
NYISO						New York Independent System Operator
NYMEX						New York Mercantile Exchange

OCI/OCL						Other Comprehensive Income/(Loss)
ORDC						Operating Reserve Demand Curve
~~ORDPA~~						~~Online Reliability Deployment Price Adder~~
~~Petra Nova~~						~~Petra Nova Parish Holdings, LLC~~
PG&E						Pacific Gas and Electric Company
PJM						PJM Interconnection, LLC
PM2.5						Particulate Matter that has a diameter of less than 2.5 micrometers
PPA						Power Purchase Agreement
PUCT						Public Utility Commission of Texas
RCRA						Resource Conservation and Recovery Act of 1976


Receivables Facility						NRG Receivables LLC, a bankruptcy remote, special purpose, wholly-owned indirect subsidiary of the Company's $1.0 billion accounts receivables securitization facility due 2023, which was last amended on ~~July 26, 2021 and~~ July 26, 2022
Receivables Securitization Facilities						Collectively, the Receivables Facility and the Repurchase Facility
Renewable PPA						A third-party PPA entered into directly with a renewable generation facility for the offtake of the Renewable Energy Certificates or other similar environmental attributes generated by such facility, couple with the associated power generated by that facility
REP						Retail electric provider
Repurchase Facility						NRG's $150 million uncommitted repurchase facility related to the Receivables Facility due 2023, which was last amended on July 26, ~~2021, February 9,~~ 2022 ~~and July 26, 2022~~


Revolving Credit Facility						The Company's ~~$3.7~~$4.3 billion revolving credit facility due ~~2024,~~2028, was last amended on ~~May 28, 2019 and August 20, 2020~~March 13, 2023
RGGI						Regional Greenhouse Gas Initiative
~~RMR~~						~~Reliability Must-Run~~
RTO						Regional Transmission Organization, also referred to as ISOs
SEC						U.S. Securities and Exchange Commission
Securities Act						The Securities Act of 1933, as amended
Senior Notes						As of ~~September 30, 2022,~~March 31, 2023, NRG's $4.6 billion outstanding unsecured senior notes consisting of $375 million of the 6.625% senior notes due 2027, $821 million of 5.75% senior notes due 2028, $733 million of the 5.25% senior notes due 2029, $500 million of the 3.375% senior notes due 2029, $1.0 billion of the 3.625% senior notes due 2031 and $1.1 billion of the 3.875% senior notes due 2032
Senior Secured First Lien Notes						As of ~~September 30, 2022,~~March 31, 2023, NRG’s ~~$2.5~~$3.4 billion outstanding Senior Secured First Lien Notes consists of $600 million of the 3.75% Senior Secured First Lien Notes due 2024, $500 million of the 2.0% Senior Secured First Lien Notes due 2025, $900 million of the 2.45% Senior Secured First Lien Notes due 2027, ~~and~~ $500 million of the 4.45% Senior Secured First Lien Notes due 2029 and $740 million of the 7.000% Senior Secured First Lien Notes due 2033
Services						NRG Services, which primarily includes the services businesses acquired in the Direct Energy ~~Acquisition~~acquisition and the Goal Zero business

SNF						Spent Nuclear Fuel
SO2						Sulfur Dioxide
SOFR						Secured overnight financing rate
South Central Portfolio						NRG's South Central Portfolio, which owned and operated a portfolio of generation assets consisting of Bayou Cove, Big Cajun-I, Big Cajun-II, Cottonwood and Sterlington, was sold on February 4, 2019. NRG is leasing back the Cottonwood facility through May 2025
STP						South Texas Project — nuclear generating facility located near Bay City, Texas in which NRG owns a 44% interest
STPNOC						South Texas Project Nuclear Operating Company

TDSP						Transmission/distribution service provider

U.S.						United States of America
U.S. DOE						U.S. Department of Energy
VaR						Value at Risk
VIE						Variable Interest Entity
Vivint						Vivint Smart Home, Inc.
Winter Storm Elliott						A major winter storm that had impacts across the majority of the United States and parts of Canada occurring in December 2022
Winter Storm Uri						A major winter and ice storm that had widespread impacts across North America occurring in February 2021


	Three months ended September 30,				Nine months ended September 30,
(In millions)	2022		2021		2022		2021
Net Income	$	67	$	1,618	$	2,316	$	2,614
Other Comprehensive (Loss)/Income

Foreign currency translation adjustments	(32)		(11)		(45)		(6)

Defined benefit plans	(2)		1		17		20
Other comprehensive (loss)/income	(34)		(10)		(28)		14
Comprehensive Income	$	33	$	1,608	$	2,288	$	2,628


	September 30, 2022		December 31, 2021
(In millions, except share data)	(Unaudited)		(Audited)
ASSETS
Current Assets
Cash and cash equivalents	$	333	$	250
Funds deposited by counterparties	3,134		845
Restricted cash	46		15
Accounts receivable, net	4,061		3,245
Uplift securitization proceeds receivable from ERCOT	—		689
Inventory	772		498
Derivative instruments	9,938		4,613
Cash collateral paid in support of energy risk management activities	262		291

Prepayments and other current assets	417		395


Total current assets	18,963		10,841
Property, plant and equipment, net	1,598		1,688
Other Assets
Equity investments in affiliates	126		157

Operating lease right-of-use assets, net	236		271
Goodwill	1,650		1,795
Intangible assets, net	2,227		2,511
Nuclear decommissioning trust fund	789		1,008
Derivative instruments	4,914		2,527
Deferred income taxes	1,516		2,155
Other non-current assets	224		229


Total other assets	11,682		10,653
Total Assets	$	32,243	$	23,182

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities

Current portion of long-term debt and finance leases	$	62	$	4

Current portion of operating lease liabilities	82		81
Accounts payable	2,871		2,274

Derivative instruments	6,841		3,387
Cash collateral received in support of energy risk management activities	3,134		845
Accrued expenses and other current liabilities	1,376		1,324



Total current liabilities	14,366		7,915
Other Liabilities
Long-term debt and finance leases	7,974		7,966
Non-current operating lease liabilities	197		236
Nuclear decommissioning reserve	335		321
Nuclear decommissioning trust liability	433		666

Derivative instruments	2,802		1,412
Deferred income taxes	84		73
Other non-current liabilities	922		993


Total other liabilities	12,747		11,667
Total Liabilities	27,113		19,582

Commitments and Contingencies
Stockholders' Equity
Common stock; $0.01 par value; 500,000,000 shares authorized; 423,894,539 and 423,547,174 shares issued and 232,125,137 and 243,753,899 shares outstanding at September 30, 2022 and December 31, 2021, respectively	4		4
Additional paid-in-capital	8,450		8,531
Retained earnings	2,584		464
Treasury stock, at cost 191,769,402 and 179,793,275 shares at September 30, 2022 and December 31, 2021, respectively	(5,754)		(5,273)
Accumulated other comprehensive loss	(154)		(126)

Total Stockholders' Equity	5,130		3,600
Total Liabilities and Stockholders' Equity	$	32,243	$	23,182


	March 31, 2023		December 31, 2022
(In millions, except share data and liquidation preference on preferred stock)	(Unaudited)		(Audited)
ASSETS
Current Assets
Cash and cash equivalents	$	407	$	430
Funds deposited by counterparties	330		1,708
Restricted cash	32		40
Accounts receivable, net	3,519		4,773

Inventory	722		751
Derivative instruments	4,400		7,886
Cash collateral paid in support of energy risk management activities	293		260

Prepayments and other current assets	505		383


Total current assets	10,208		16,231
Property, plant and equipment, net	1,835		1,692
Other Assets
Equity investments in affiliates	136		133

Operating lease right-of-use assets, net	247		225
Goodwill	5,343		1,650
Intangible assets, net	4,419		2,132
Nuclear decommissioning trust fund	879		838
Derivative instruments	3,350		4,108
Deferred income taxes	2,925		1,881
Other non-current assets	354		256


Total other assets	17,653		11,223
Total Assets	$	29,696	$	29,146


(In millions)	Common Stock		Additional Paid-In Capital		Retained Earnings		Treasury Stock		Accumulated Other Comprehensive Loss		Total Stock-holders' Equity
Balance at December 31, 2021	$	4	$	8,531	$	464	$	(5,273)	$	(126)	$	3,600
Net income					1,736						1,736
Other comprehensive income									8		8


Share repurchases							(187)				(187)
Equity-based awards activity, net(a)			2								2

Common stock dividends and dividend equivalents declared(b)					(86)						(86)
Adoption of ASU 2020-06			(100)		57						(43)





Balance at March 31, 2022	$	4	$	8,433	$	2,171	$	(5,460)	$	(118)	$	5,030
Net income					513						513
Other comprehensive loss									(2)		(2)
Shares reissuance for ESPP			1				2				3
Share repurchases							(168)				(168)
Equity-based awards activity, net			8								8

Common stock dividends and dividend equivalents declared(b)					(84)						(84)

Balance at June 30, 2022	$	4	$	8,442	$	2,600	$	(5,626)	$	(120)	$	5,300
Net income					67						67
Other comprehensive loss									(34)		(34)
Share repurchases							(128)				(128)
Equity-based awards activity, net			8								8

Common stock dividends and dividend equivalents declared(b)					(83)						(83)
Balance at September 30, 2022	$	4	$	8,450	$	2,584	$	(5,754)	$	(154)	$	5,130


(In millions)	Preferred Stock		Common Stock		Additional Paid-In Capital		Retained Earnings/(Accumulated deficit)		Treasury Stock		Accumulated Other Comprehensive Loss		Total Stock-holders' Equity
Balance at December 31, 2022	$	—	$	4	$	8,457	$	1,408	$	(5,864)	$	(177)	$	3,828
Net loss							(1,335)						(1,335)
Issuance of Series A Preferred Stock	650				(14)								636
Other comprehensive income											1		1



Equity-based awards activity, net(a)					38								38

Common stock dividends and dividend equivalents declared(b)							(88)						(88)






Balance at March 31, 2023	$	650	$	4	$	8,481	$	(15)	$	(5,864)	$	(176)	$	3,080


		Three months ended September 30, 2022											Three months ended March 31, 2023
(In millions)	(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total		(In millions)	Texas		East		West/Services/Other		Vivint(a)		Corporate/Eliminations		Total
Retail revenue:	Retail revenue:											Retail revenue:
Home~~(a)~~(b)	Home~~(a)~~(b)	$	2,074	$	546	$	429	$	—	$	3,049	Home~~(a)~~(b)	$	1,236	$	651	$	625	$	148	$	—	$	2,660
Business	Business	931		3,317		561		—		4,809		Business	722		3,365		616		—		—		4,703
Total retail revenue~~(b)~~(c)	Total retail revenue~~(b)~~(c)	3,005		3,863		990		—		7,858		Total retail revenue~~(b)~~(c)	1,958		4,016		1,241		148		—		7,363
Energy revenue~~(b)~~(c)	Energy revenue~~(b)~~(c)	48		212		180		10		450		Energy revenue~~(b)~~(c)	4		74		48		—		2		128
Capacity revenue~~(b)~~(c)	Capacity revenue~~(b)~~(c)	—		38		—		—		38		Capacity revenue~~(b)~~(c)	—		41		1		—		—		42
Mark-to-market for economic hedging activities~~(c)~~(d)	Mark-to-market for economic hedging activities~~(c)~~(d)	4		32		(7)		4		33		Mark-to-market for economic hedging activities~~(c)~~(d)	—		35		67		—		(11)		91
Contract amortization	Contract amortization	—		(10)		4		—		(6)		Contract amortization	—		(11)		—		—		—		(11)
Other revenue~~(b)~~(c)	Other revenue~~(b)~~(c)	92		45		2		(2)		137		Other revenue~~(b)~~(c)	72		21		17		—		(1)		109
Total revenue	Total revenue	3,149		4,180		1,169		12		8,510		Total revenue	2,034		4,176		1,374		148		(10)		7,722
Less: Revenues accounted for under topics other than ASC 606 and ASC 815	Less: Revenues accounted for under topics other than ASC 606 and ASC 815	—		3		14		(1)		16		Less: Revenues accounted for under topics other than ASC 606 and ASC 815	—		(1)		9		—		—		8
Less: Realized and unrealized ASC 815 revenue	Less: Realized and unrealized ASC 815 revenue	15		93		13		14		135		Less: Realized and unrealized ASC 815 revenue	(2)		113		97		—		(9)		199
Total revenue from contracts with customers	Total revenue from contracts with customers	$	3,134	$	4,084	$	1,142	$	(1)	$	8,359	Total revenue from contracts with customers	$	2,036	$	4,064	$	1,268	$	148	$	(1)	$	7,515
(a) Home includes Services
(b) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 and included in the amounts above:
(a) Vivint includes results of operations following the acquisition date of March 10, 2023												(a) Vivint includes results of operations following the acquisition date of March 10, 2023
(b) Home includes Services and Vivint												(b) Home includes Services and Vivint
(c) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 and included in the amounts above:												(c) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 and included in the amounts above:
(In millions)	(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total		(In millions)	Texas		East		West/Services/Other		Vivint		Corporate/Eliminations		Total
Retail revenue	Retail revenue	$	—	$	90	$	—	$	—	$	90	Retail revenue	$	—	$	27	$	—	$	—	$	—	$	27
Energy revenue	Energy revenue	—		(39)		27		11		(1)		Energy revenue	—		47		17		—		2		66
Capacity revenue	Capacity revenue	—		7		—		—		7		Capacity revenue	—		6		—		—		—		6
Other revenue	Other revenue	11		3		(7)		(1)		6		Other revenue	(2)		(2)		13		—		—		9
(c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815
(d) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815												(d) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815


	Three months ended September 30, 2021
(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Retail revenue:
Home(a)	$	1,776	$	470	$	399	$	1	$	2,646
Business	727		2,228		350		—		3,305
Total retail revenue	2,503		2,698		749		1		5,951
Energy revenue(b)	18		201		113		4		336
Capacity revenue(b)	—		172		17		—		189
Mark-to-market for economic hedging activities(c)	(1)		(3)		(6)		13		3
Contract amortization	—		(7)		4		—		(3)
Other revenue(b)	115		16		6		(4)		133
Total revenue	2,635		3,077		883		14		6,609
Less: Revenues accounted for under topics other than ASC 606 and ASC 815	—		(7)		6		—		(1)
Less: Realized and unrealized ASC 815 revenue	38		76		(8)		14		120
Total revenue from contracts with customers	$	2,597	$	3,008	$	885	$	—	$	6,490
(a) Home includes Services
(b) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 and included in the amounts above:
(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Energy revenue	$	—	$	38	$	2	$	1	$	41
Capacity revenue	—		42		—		—		42
Other revenue	39		(1)		(4)		—		34
(c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815


	Nine months ended September 30, 2022
(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Retail revenue:
Home(a)	$	5,024	$	1,674	$	1,663	$	(1)	$	8,360
Business	2,504		10,110		1,405		—		14,019
Total retail revenue(b)	7,528		11,784		3,068		(1)		22,379
Energy revenue(b)	101		544		365		24		1,034
Capacity revenue(b)	—		242		2		—		244
Mark-to-market for economic hedging activities(c)	1		(204)		(63)		18		(248)
Contract amortization	—		(30)		2		—		(28)
Other revenue(b)	238		78		3		(12)		307
Total revenue	7,868		12,414		3,377		29		23,688
Less: Revenues accounted for under topics other than ASC 606 and ASC 815	—		(10)		33		(1)		22
Less: Realized and unrealized ASC 815 revenue	(5)		(96)		(99)		41		(159)
Total revenue from contracts with customers	$	7,873	$	12,520	$	3,443	$	(11)	$	23,825
(a) Home includes Services
(b) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 and included in the amounts above:
(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Retail revenue	$	—	$	90	$	—	$	—	$	90
Energy revenue	—		(13)		(13)		24		(2)
Capacity revenue	—		29		—		—		29
Other revenue	(6)		2		(23)		(1)		(28)
(c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815


		Nine months ended September 30, 2021											Three months ended March 31, 2022
(In millions)	(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total		(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Retail revenue:	Retail revenue:											Retail revenue:
Home(a)	Home(a)	$	4,484	$	1,469	$	1,439	$	(1)	$	7,391	Home(a)	$	1,283	$	579	$	703	$	—	$	2,565
Business	Business	2,091		6,560		887		—		9,538		Business	663		3,942		400		—		5,005
Total retail revenue	Total retail revenue	6,575		8,029		2,326		(1)		16,929		Total retail revenue	1,946		4,521		1,103		—		7,570
Energy revenue~~(c)~~(b)	Energy revenue~~(c)~~(b)	317		428		238		6		989		Energy revenue~~(c)~~(b)	15		204		54		5		278
Capacity revenue~~(c)~~(b)	Capacity revenue~~(c)~~(b)	—		568		47		—		615		Capacity revenue~~(c)~~(b)	—		115		1		—		116
Mark-to-market for economic hedging activities~~(d)~~(c)	Mark-to-market for economic hedging activities~~(d)~~(c)	(5)		(53)		(60)		19		(99)		Mark-to-market for economic hedging activities~~(d)~~(c)	(2)		(130)		(18)		17		(133)
Contract amortization	Contract amortization	—		(15)		(4)		—		(19)		Contract amortization	—		(9)		—		—		(9)
Other revenue~~(c)~~(b)	Other revenue~~(c)~~(b)	1,475		45		17		(9)		1,528		Other revenue~~(c)~~(b)	61		14		4		(5)		74
Total revenue	Total revenue	8,362		9,002		2,564		15		19,943		Total revenue	2,020		4,715		1,144		17		7,896
Less: Revenues accounted for under topics other than ASC 606 and ASC 815	Less: Revenues accounted for under topics other than ASC 606 and ASC 815	—		(14)		1		—		(13)		Less: Revenues accounted for under topics other than ASC 606 and ASC 815	—		(9)		11		—		2
Less: Realized and unrealized ASC 815 revenue	Less: Realized and unrealized ASC 815 revenue	129		193		(73)		20		269		Less: Realized and unrealized ASC 815 revenue	(7)		(66)		(42)		20		(95)
Total revenue from contracts with customers	Total revenue from contracts with customers	$	8,233	$	8,823	$	2,636	$	(5)	$	19,687	Total revenue from contracts with customers	$	2,027	$	4,790	$	1,175	$	(3)	$	7,989
(a) Home includes Services
(b) Other Revenue in Texas includes ancillary revenues of $1.2 billion driven by high pricing during Winter Storm Uri
(c) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 and included in the amounts above:
(b) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 and included in the amounts above:												(b) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 and included in the amounts above:
(In millions)	(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total		(In millions)	Texas		East		West/Services/Other		Corporate/Eliminations		Total
Energy revenue	Energy revenue	$	—	$	122	$	(4)	$	2	$	120	Energy revenue	$	—	$	45	$	(20)	$	4	$	29
Capacity revenue	Capacity revenue	—		119		—		—		119		Capacity revenue	—		13		—		—		13
Other revenue	Other revenue	134		5		(9)		(1)		129		Other revenue	(5)		6		(4)		(1)		(4)
(d) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815
(c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815												(c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815


	(In millions)
Vivint common shares outstanding as of March 10, 2023 of 216,901,639 at $12.00 per share	$	2,603
Other Vivint equity instruments (Cash out RSUs and PSUs, Stock Appreciation Rights, Private Placement Warrants)	6
Total Cash Consideration	$	2,609
Fair value of acquired Vivint equity awards attributable to pre-combination service	14
Total Consideration	$	2,623


		September 30, 2022										March 31, 2023
				Fair Value
(In millions)	(In millions)	Total			Level 1		Level 2		Level 3		(In millions)	Total		Level 1		Level 2		Level 3
Investments in securities (classified within other current and non-current assets)	Investments in securities (classified within other current and non-current assets)	$	19		$	—	$	19	$	—	Investments in securities (classified within other current and non-current assets)	$	19	$	—	$	19	$	—

Nuclear trust fund investments:	Nuclear trust fund investments:										Nuclear trust fund investments:
Cash and cash equivalents	Cash and cash equivalents	17			17		—		—		Cash and cash equivalents	13		13		—		—
U.S. government and federal agency obligations	U.S. government and federal agency obligations	85			83		2		—		U.S. government and federal agency obligations	98		96		2		—
Federal agency mortgage-backed securities	Federal agency mortgage-backed securities	101			—		101		—		Federal agency mortgage-backed securities	101		—		101		—
Commercial mortgage-backed securities	Commercial mortgage-backed securities	37			—		37		—		Commercial mortgage-backed securities	34		—		34		—
Corporate debt securities	Corporate debt securities	104			—		104		—		Corporate debt securities	113		—		113		—
Equity securities	Equity securities	372			372		—		—		Equity securities	430		430		—		—
Foreign government fixed income securities	Foreign government fixed income securities	2			—		2		—		Foreign government fixed income securities	1		1		—		—
Other trust fund investments (classified within other non-current assets):	Other trust fund investments (classified within other non-current assets):										Other trust fund investments (classified within other non-current assets):
U.S. government and federal agency obligations	U.S. government and federal agency obligations	1			1		—		—		U.S. government and federal agency obligations	1		1		—		—
Derivative assets:	Derivative assets:										Derivative assets:
Foreign exchange contracts	Foreign exchange contracts	30			—		30		—		Foreign exchange contracts	15		—		15		—
Commodity contracts	Commodity contracts	14,822			2,873		10,936		1,013		Commodity contracts	7,725		1,331		5,360		1,034

Interest rate contracts											Interest rate contracts	10		—		10		—

Measured using net asset value practical expedient:	Measured using net asset value practical expedient:										Measured using net asset value practical expedient:
Equity securities — nuclear trust fund investments	Equity securities — nuclear trust fund investments	71									Equity securities — nuclear trust fund investments	89
Equity securities (classified within other non-current assets)	Equity securities (classified within other non-current assets)	6									Equity securities (classified within other non-current assets)	6
Total assets	Total assets	$	15,667		$	3,346	$	11,231	$	1,013	Total assets	$	8,655	$	1,872	$	5,654	$	1,034
Derivative liabilities:	Derivative liabilities:										Derivative liabilities:

Foreign exchange contracts											Foreign exchange contracts	$	1	$	—	$	1	$	—
Commodity contracts	Commodity contracts	9,643			1,228		8,084		331		Commodity contracts	6,116		1,422		4,131		563
Interest rate contracts											Interest rate contracts	15		—		15		—
Consumer Financing Program											Consumer Financing Program	111		—		—		111
Total liabilities	Total liabilities	$	9,643		$	1,228	$	8,084	$	331	Total liabilities	$	6,243	$	1,422	$	4,147	$	674


		Fair Value Measurement Using Significant Unobservable Inputs (Level 3)									Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
		Derivatives(a)									Commodity Derivatives(a)
(In millions)	(In millions)	Three months ended September 30, 2022		Three months ended September 30, 2021		Nine months ended September 30, 2022		Nine months ended September 30, 2021		(In millions)	Three months ended March 31, 2023		Three months ended March 31, 2022

Beginning balance	Beginning balance	$	1,403	$	574	$	293	$	(16)	Beginning balance	$	505	$	293
Contracts added from Direct Energy acquisition		—		—		—		(15)

Total (losses)/gains realized/unrealized — included in earnings		(314)		(175)		145		187

Total (losses)/gains realized/unrealized included in earnings										Total (losses)/gains realized/unrealized included in earnings	(91)		166

Purchases	Purchases	60		—		89		78		Purchases	41		23
Transfers into Level 3(b)	Transfers into Level 3(b)	(466)		(108)		155		64		Transfers into Level 3(b)	24		53
Transfers out of Level 3(b)	Transfers out of Level 3(b)	(1)		20		—		13		Transfers out of Level 3(b)	(8)		(7)
Ending balance	Ending balance	$	682	$	311	$	682	$	311	Ending balance	$	471	$	528
(Losses)/gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of period end		$	(240)	$	(237)	$	294	$	184
(Losses)/Gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of period end										(Losses)/Gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of period end	$	(55)	$	237



	December 31, 2021
	Fair Value						Input/Range
(In millions)	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low		High		Weighted Average
Natural Gas Contracts	$	16	$	1	Discounted Cash Flow	Forward Market Price (per MMBtu)	$	3	$	40	$	15
Power Contracts	392		121		Discounted Cash Flow	Forward Market Price (per MWh)	3		212		35
FTRs	49		42		Discounted Cash Flow	Auction Prices (per MWh)	(122)		43		0
	$	457	$	164


	Net Exposure(a)(b)
Category by Industry Sector	(% of Total)

Utilities, energy merchants, marketers and other	6171	%
Financial institutions	3929

Total as of ~~September 30, 2022~~March 31, 2023	100	%


	Net Exposure (a)(b)
Category by Counterparty Credit Quality	(% of Total)
Investment grade	6855	%
Non-investment grade/non-rated	3245
Total as of ~~September 30, 2022~~March 31, 2023	100	%


	As of September 30, 2022							As of December 31, 2021
(In millions, except maturities)	Fair Value		Unrealized Gains		Unrealized Losses		Weighted-average Maturities (In years)	Fair Value		Unrealized Gains		Unrealized Losses		Weighted-average Maturities (In years)
Cash and cash equivalents	$	17	$	—	$	—	—	$	33	$	—	$	—	—
U.S. government and federal agency obligations	85		—		10		11	112		5		1		10
Federal agency mortgage-backed securities	101		—		12		25	100		2		—		25
Commercial mortgage-backed securities	37		—		4		28	44		1		—		27
Corporate debt securities	104		—		15		13	122		7		1		14
Equity securities	443		301		—		—	593		456		—		—
Foreign government fixed income securities	2		—		—		18	4		—		—		13
Total	$	789	$	301	$	41		$	1,008	$	471	$	2


	As of March 31, 2023							As of December 31, 2022
(In millions, except maturities)	Fair Value		Unrealized Gains		Unrealized Losses		Weighted-average Maturities (In years)	Fair Value		Unrealized Gains		Unrealized Losses		Weighted-average Maturities (In years)
Cash and cash equivalents	$	13	$	—	$	—	—	$	15	$	—	$	—	—
U.S. government and federal agency obligations	98		1		4		11	86		—		5		11
Federal agency mortgage-backed securities	101		—		8		26	101		—		11		26
Commercial mortgage-backed securities	34		—		3		29	35		—		4		30
Corporate debt securities	113		1		9		11	114		—		13		12
Equity securities	519		374		—		—	486		346		3		—
Foreign government fixed income securities	1		—		—		20	1		—		—		17
Total	$	879	$	376	$	24		$	838	$	346	$	36


	Fair Value
	Derivative Assets				Derivative Liabilities
(In millions)	September 30, 2022		December 31, 2021		September 30, 2022		December 31, 2021




Derivatives Not Designated as Cash Flow or Fair Value Hedges:


Foreign exchange contracts - current	$	16	$	—	$	—	$	1
Foreign exchange contracts - long-term	14		1		—		—
Commodity contracts - current	9,922		4,613		6,841		3,386
Commodity contracts - long-term	4,900		2,526		2,802		1,412
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges	$	14,852	$	7,140	$	9,643	$	4,799


	Gross Amounts Not Offset in the Statement of Financial Position
(In millions)	Gross Amounts of Recognized Assets / Liabilities		Derivative Instruments		Cash Collateral (Held) / Posted		Net Amount
As of September 30, 2022
Foreign exchange contracts:

Derivative assets	$	30	$	—	$	—	$	30

Commodity contracts:
Derivative assets	$	14,822	$	(8,987)	$	(3,081)	$	2,754
Derivative liabilities	(9,643)		8,987		29		(627)
Total commodity contracts	$	5,179	$	—	$	(3,052)	$	2,127




Total derivative instruments	$	5,209	$	—	$	(3,052)	$	2,157


(In millions)	Three months ended March 31,
Unrealized mark-to-market results	2023		2022
Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges	$	(846)	$	(408)
Reversal of acquired (gain) positions related to economic hedges	(25)		(60)
Net unrealized (losses)/gains on open positions related to economic hedges	(1,073)		2,745
Total unrealized mark-to-market (losses)/gains for economic hedging activities	(1,944)		2,277
Reversal of previously recognized unrealized losses on settled positions related to trading activity	1		1

Net unrealized gains/(losses) on open positions related to trading activity	11		(15)
Total unrealized mark-to-market gains/(losses) for trading activity	12		(14)
Total unrealized (losses)/gains - commodities and foreign exchange	$	(1,932)	$	2,263


(In millions, except rates)	(In millions, except rates)	September 30, 2022		December 31, 2021		Interest rate %	(In millions, except rates)	March 31, 2023		December 31, 2022		Interest rate %
Recourse debt:	Recourse debt:						Recourse debt:
Senior Notes, due 2027	Senior Notes, due 2027	$	375	$	375	6.625	Senior Notes, due 2027	$	375	$	375	6.625
Senior Notes, due 2028	Senior Notes, due 2028	821		821		5.750	Senior Notes, due 2028	821		821		5.750
Senior Notes, due 2029	Senior Notes, due 2029	733		733		5.250	Senior Notes, due 2029	733		733		5.250
Senior Notes, due 2029	Senior Notes, due 2029	500		500		3.375	Senior Notes, due 2029	500		500		3.375
Senior Notes, due 2031	Senior Notes, due 2031	1,030		1,030		3.625	Senior Notes, due 2031	1,030		1,030		3.625
Senior Notes, due 2032	Senior Notes, due 2032	1,100		1,100		3.875	Senior Notes, due 2032	1,100		1,100		3.875
Convertible Senior Notes, due 2048(a)	Convertible Senior Notes, due 2048(a)	575		575		2.750	Convertible Senior Notes, due 2048(a)	575		575		2.750
Senior Secured First Lien Notes, due 2024	Senior Secured First Lien Notes, due 2024	600		600		3.750	Senior Secured First Lien Notes, due 2024	600		600		3.750
Senior Secured First Lien Notes, due 2025	Senior Secured First Lien Notes, due 2025	500		500		2.000	Senior Secured First Lien Notes, due 2025	500		500		2.000
Senior Secured First Lien Notes, due 2027	Senior Secured First Lien Notes, due 2027	900		900		2.450	Senior Secured First Lien Notes, due 2027	900		900		2.450
Senior Secured First Lien Notes, due 2029	Senior Secured First Lien Notes, due 2029	500		500		4.450	Senior Secured First Lien Notes, due 2029	500		500		4.450

Senior Secured First Lien Notes, due 2033							Senior Secured First Lien Notes, due 2033	740		—		7.000
Revolving Credit Facility							Revolving Credit Facility	725		—		SOFR + 1.720
Receivables Facility							Receivables Facility	150		—		various
Repurchase Facility							Repurchase Facility	75		—		SOFR + 1.300
Tax-exempt bonds	Tax-exempt bonds	466		466		1.250 - 4.750	Tax-exempt bonds	466		466		1.250 - 4.750

Subtotal recourse debt	Subtotal recourse debt	8,100		8,100			Subtotal recourse debt	9,790		8,100

Non-recourse debt:							Non-recourse debt:
Vivint Senior Secured Notes, due 2027							Vivint Senior Secured Notes, due 2027	600		—		6.750
Vivint Senior Notes, due 2029							Vivint Senior Notes, due 2029	800		—		5.750
Vivint Senior Secured Term Loan, due 2028							Vivint Senior Secured Term Loan, due 2028	1,330		—		various
Subtotal all Vivint non-recourse debt							Subtotal all Vivint non-recourse debt	2,730		—
Subtotal long-term debt (including current maturities)							Subtotal long-term debt (including current maturities)	12,520		8,100
Finance leases	Finance leases	12		13		various	Finance leases	19		11		various
Subtotal long-term debt and finance leases (including current maturities)	Subtotal long-term debt and finance leases (including current maturities)	8,112		8,113			Subtotal long-term debt and finance leases (including current maturities)	12,539		8,111
Less current maturities	Less current maturities	(62)		(4)			Less current maturities	(971)		(63)
Less debt issuance costs	Less debt issuance costs	(74)		(83)			Less debt issuance costs	(75)		(70)
Discounts	Discounts	(2)		(60)			Discounts	(161)		(2)
Total long-term debt and finance leases	Total long-term debt and finance leases	$	7,974	$	7,966		Total long-term debt and finance leases	$	11,332	$	7,976


	Issued	Treasury	Outstanding
Balance as of December 31, 2021	423,547,174	(179,793,275)	243,753,899
Shares issued under LTIPs	347,365	—	347,365
Shares issued under ESPP	—	68,941	68,941
Shares repurchased	—	(12,045,068)	(12,045,068)
Balance as of September 30, 2022	423,894,539	(191,769,402)	232,125,137
Shares issued under LTIPs	2,462	—	2,462
Shares issued under ESPP	—	73,884	73,884
Shares repurchased	—	(1,817,278)	(1,817,278)
Balance as of October 31, 2022	423,897,001	(193,512,796)	230,384,205


	Preferred	Common
	Issued and Outstanding	Issued	Treasury	Outstanding
Balance as of December 31, 2022	—	423,897,001	(194,335,971)	229,561,030
Shares issued under LTIPs	—	395,408	—	395,408

Issuance of Series A Preferred Stock	650,000	—	—	—

Balance as of March 31, 2023	650,000	424,292,409	(194,335,971)	229,956,438


	Total number of shares and share equivalents purchased	Average price paid per share and share equivalent	Amounts paid for shares and share equivalents purchased (in millions)
2022 repurchases
Repurchases(a)	12,045,068		$	483
Equivalent shares purchased in lieu of tax withholdings on equity compensation issuances(b)	150,448		6

Total Share Repurchases during the nine months ended September 30, 2022	12,195,516	$40.07	489
Repurchases made during October(a)	1,817,278		$	76
Equivalent shares purchased in October in lieu of tax withholdings on equity compensation issuances(b)	793		—
Total Share Repurchases January 1, 2022 through October 31, 2022	14,013,587	$40.28	$	565


	Three months ended September 30,				Nine months ended September 30,
(In millions, except per share data)	2022		2021		2022		2021
Basic and diluted income per share:
Net income	$	67	$	1,618	$	2,316	$	2,614
Weighted average number of common shares outstanding - basic and diluted	235		245		238		245
Income per weighted average common share — basic and diluted	$	0.29	$	6.60	$	9.73	$	10.67


	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	%