NRG Energy Inc.
11/09/2026 | Press release | Distributed by Public on 11/09/2026 15:37
Quarterly Report for Quarter Ending September 30, 2026 (Form 10-Q)
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The discussion and analysis below has been organized as follows:
•Executive summary, including introduction and overview, business strategy, and changes to the business environment during the period, including environmental and regulatory matters;
•Known trends that may affect NRG's results of operations and financial condition in the future;
•Results of operations; and
•Liquidity and capital resources including liquidity position, material cash requirements and commitments, and other obligations.
As you read this discussion and analysis, refer to NRG's condensed consolidated statements of operations to this Form 10-Q, which present the results of operations for the three and nine months ended September 30, 2026 and 2025. Also refer to NRG's 2025 Form 10-K, which includes detailed discussions of various items impacting the Company's business, results of operations and financial condition, including: General section; Strategy section; Business Overview section, including how regulation, weather, and other factors affect NRG's business; and Critical Accounting Estimates section.
Executive Summary
Introduction and Overview
NRG Energy, Inc., or NRG or the Company, provides electricity, natural gas, and smart-home technology solutions to approximately 8 million residential customers (comprised of 6 million retail energy and 2 million smart home), in addition to large commercial and industrial, data center, and wholesale customers. Across North America, NRG is redefining customers' experience with energy under brand names such as NRG, Reliant, Direct Energy, Green Mountain Energy, and Vivint. As of September 30, 2026, the Company's core power and natural gas business consists of approximately 25 GW of competitive power generation, including approximately 13 GW from the LSP Portfolio, and a natural gas portfolio that serves approximately 1,900 MMDth annually.
Strategy
NRG's strategy is to maximize shareholder value by delivering integrated energy and smart home solutions, supported by an owned generation fleet and a diversified supply strategy. The Company generates power and sells electricity and natural gas to residential, commercial, industrial, and wholesale customers in the markets it serves. The Company also provides smart home security and automation services that deepen customer relationships and support long-term engagement. NRG operates a customer-first platform that promotes reliability and affordability amid rapid transformation in the energy sector. The Company is advancing opportunities to meet growing demand, including from data centers, other large load customers, and electrification. This includes (i) flexible load products such as demand response and virtual power plants ("VPP"), which help manage costs and improve affordability for customers, (ii) completing the Texas Development Projects, (iii) long-term, contract-backed generation and related infrastructure, supported by strategic partnerships with equipment manufacturers and engineering, procurement, and construction companies, and (iv) increasing capacity at existing facilities. The Company's differentiated model is built to meet North America's evolving needs while delivering affordable, reliable solutions for customers and long-term growth for shareholders. This strategy is intended to generate recurring cash flow, strengthen earnings and cost competitiveness, and reduce risk and volatility.
To effectuate the Company's strategy, NRG is focused on: (i) serving the energy needs of residential, commercial and industrial, and wholesale counterparties in competitive markets and optimizing on additional revenue opportunities through its multiple brands and channels; (ii) offering a variety of energy products and smart home products and services that are differentiated by innovative, value-additive features, premium service, integrated platforms, sustainability, loyalty/affinity programs, and affordability; (iii) excellence in operating performance of its assets; (iv) achieving the optimal mix of supply to serve its customer load requirements through a diversified supply strategy, including expanding its operational capacity to meet growing retail power supply needs; and (v) engaging in disciplined and transparent capital allocation.
Beginning in the first quarter of 2026, the operations acquired from LS Power were integrated into the Company's existing segment structure, enhancing scale and portfolio optimization across the platform. In Texas, the Company's generation portfolio is fully integrated with its retail load and, in early 2026, the Company adopted an integrated strategy in the East, expanding this model across a broader geographic footprint. The integrated model strategically aligns generation and retail, enabling the Company to supply a portion of its retail customers with electricity from Company-owned assets, thereby reducing reliance to procure electricity from other institutions and intermediaries and supporting more stable earnings and cash flows, lower transaction costs, and reduced credit exposure. The integrated model also results in a reduction in actual and contingent collateral requirements, improving capital efficiency and further limiting transactions with third parties.
Energy Regulatory Matters
The Company's regulatory matters are described in the Company's 2025 Form 10-K in Item 1, Business - Regulatory Matters. These matters have been updated below and in Note 15, Regulatory Matters.
As participants in wholesale and retail energy markets and owners and operators of power plants, certain NRG entities are subject to regulation by various federal and state government agencies. These include the CFTC, FERC and the PUCT, as well as other public utility commissions in certain states where NRG's generation or distributed generation assets are located. In addition, NRG is subject to the market rules, procedures and protocols of the various ISO and RTO markets in which it participates. Likewise, certain NRG entities participating in the retail markets are subject to rules and regulations established by the states and provinces in which NRG entities are licensed to sell at retail. NRG must also comply with the mandatory reliability requirements imposed by NERC and the regional reliability entities in the regions where NRG operates.
NRG's operations within the ERCOT footprint are not subject to rate regulation by FERC, as they are deemed to operate solely within the ERCOT market and not in interstate commerce. These operations are subject to regulation by the PUCT.
State and Provincial Energy Regulation
Maryland Legislation - On May 9, 2024, Maryland Governor Wes Moore signed Senate Bill ("SB") 1 into law, which restricts the competitive retail electric and natural gas market in Maryland, affecting residential customers but not commercial and industrial customers. Key provisions of the law took effect on January 1, 2025. The legislation imposes a price cap on residential contracts tied to a trailing 12-month historical average of utility rates, with only a limited exception for renewable power products. Renewable products must now have their price pre-approved by the Maryland Public Service Commission and source their renewable electricity certificates from within the PJM region. The law also requires that any variable-price contract not contain a change in price more than once a year, except time-of-use contracts, and limits contract terms to 12 months. It requires affirmative consent for the renewal of customer contracts for renewable power products. The law also imposes licensing requirements on energy salespeople. While the law states that it does not impair existing contracts, the Maryland Public Service Commission has ruled that grandfathering of existing contracts will end as of December 31, 2025, and that suppliers must issue separate bills for their charges for all new and renewing contracts as of January 1, 2026. On October 1, 2024, Green Mountain Energy Company, NRG's renewable electricity provider, along with a retail trade association to which NRG belongs, filed a lawsuit in federal court challenging the constitutionality of SB 1. On November 18, 2024, the trial court denied the plaintiffs' motion for a preliminary injunction and plaintiffs appealed. On May 15, 2026, the Court of Appeals for the Fourth Circuit reversed the district court's ruling in part and remanded the case with instructions to (i) enjoin the part of the law relating to renewable power products and (ii) conduct further proceedings on the constitutionality of required customer disclosures. The provisions mandating a price cap on non-renewable power products, limiting price changes throughout the year, restricting energy sales people, and billing customers separately were not impacted by the ruling and remain in effect while the litigation continues.
Regional Regulatory Developments
NRG is affected by rule/tariff changes that occur in the ISO regions. For further discussion on regulatory developments, see Item 1 - Note 15, Regulatory Matters, to the condensed consolidated financial statements.
ERCOT/PUCT
PUCT's Actions with Respect to Wholesale Pricing and Market Design - The PUCT continues to analyze and implement multiple options for promoting increased reliability in the wholesale electric market, including the adoption of a reliability standard for resource adequacy and market-based mechanisms to achieve this standard. The Commission adopted a reliability standard that became effective in September 2024.
In 2023, the Texas Legislature authorized implementation of the Performance Credit Mechanism ("PCM"), which will measure real-time contribution to system reliability and provide compensation for resources to be available, subject to certain "guardrails" such as an absolute annual net cost cap, as part of its adoption of the PUCT Sunset Bill (House Bill 1500). In December 2024, the PUCT decided to shelve implementation of the PCM indefinitely. The Texas Legislature also directed the PUCT to implement a new ancillary service called Dispatchable Reliability Reserve Service ("DRRS") to further increase ERCOT's capability to manage net load variability and firming requirements for new generation resources which penalize poor performance during periods of low grid reserves. In November 2025, ERCOT published an updated design proposal for DRRS that includes the ability for the PUCT to configure it to support resource adequacy through stronger financial incentives for dispatchable thermal generation. In July 2026, the PUCT approved an initial design that does not include a resource adequacy mechanism, but may further refine the final design of DRRS as part of the review of the reliability standard. The PUCT adopted a final rule to implement the firming requirement in December 2025, which requires new generation resources with signed interconnection agreements on or after January 1, 2027, to acquire additional capacity to meet a minimum requirement during low reserve hours on the ERCOT system.
Texas Energy Fund - Through SB 2627, the Texas Legislature created the TEF, to provide grants and low-interest loans (3%) to incentivize the development of more dispatchable generation and smaller backup generation in ERCOT. The PUCT also adopted a rule for the completion bonus grant program in April 2024, which provides for opportunities for grants of $120,000 per MW for dispatchable generation projects interconnected before June 1, 2026, or $80,000 per MW for dispatchable generation projects interconnected on or after June 1, 2026 but before June 1, 2029, subject to performance requirements. The 89th Texas Legislature passed SB 2268, which separated the 10,000 MW collective cap on the ERCOT loan and grant programs resulting in a 10,000 MW cap for the loan program and a separate 10,000 MW cap for the completion bonus grant program.
NRG, through its subsidiaries, filed and received approval from the PUCT for loan proceeds for three separate projects, totaling more than 1,500 MWs of capacity. Specifically, on July 31, 2025, the Company entered into a $216 million loan agreement with the PUCT under the TEF to support the development of T.H. Wharton, a 415 MW facility. On September 26, 2025, the Company entered into a $562 million loan agreement with the PUCT under the TEF to support the development of Cedar Bayou 5, a 689 MW facility. Lastly, on November 20, 2025, the Company entered into a $370 million loan agreement with the PUCT under the TEF to support the development of Greens Bayou 6, a 443 MW facility. Cedar Bayou 5 and Greens Bayou 6 are currently under construction. Commercial operations at T.H. Wharton commenced on May 26, 2026. On June 17, 2026, the Company entered into a completion bonus grant agreement with the PUCT for T.H. Wharton for up to $54.72 million, to be paid in ten annual installments, subject to performance of the facility. T. H. Wharton's first test period runs from June 1, 2026 through May 31, 2027, after which the Company will be eligible for its first grant payment.
Senate Bill 6 - On June 20, 2025, Governor Abbot, the Governor of Texas, signed SB 6 into law, which includes various provisions that concern how ERCOT, transmission and distribution utilities, and power generation companies plan for and serve large loads (defined as 75 MWs and above) in the ERCOT market, including provisions relating to forecasting accuracy, large load interconnection standards, processes and incentives for curtailment, PUCT review of certain proposed co-locations, and an investigation of transmission cost allocation and rate design. The PUCT has adopted final rules related to load forecasting accuracy, co-location, and large load interconnection standards, but the rulemaking process for cost allocation and rate design, as well as incentives or requirements to curtail operations, are in progress. With respect to large load interconnection standards, on September 18, 2026, the PUCT adopted a final rule, which establishes the standards and criteria to interconnect a large load customer to the ERCOT system, including required posting of financial security. ERCOT has also developed revisions to the interconnection study process to more efficiently review large load interconnection requests, which the PUCT approved on June 18, 2026.
Governor Abbott's August 3, 2026 Directive - On August 3, 2026, Governor Abbott directed the PUCT and ERCOT to complete a verification and audit of all data centers advancing through the interconnection process. ERCOT has issued requests for information on projects in batch zero. ERCOT plans to file its batch zero eligibility verification report and its community impact review report with the PUCT in December 2026.
PJM
Revisions to PJM Locational Deliverability Area ("LDA") Reliability Requirement - PJM delayed publication of the Base Residual Auction ("BRA") results for the 2024/2025 delivery year and filed at FERC to revise the definition of the LDA Reliability Requirement in the Tariff to allow PJM to exclude certain resources from the calculation of the LDA Reliability Requirement, which FERC accepted on February 21, 2023. Multiple parties, including NRG, filed for rehearing and subsequently appealed to the Court of Appeals for the Third Circuit. On March 12, 2024, the court vacated the portion of the FERC orders permitting application of the revised LDA Reliability Requirement to the 2024/2025 BRA. Following additional proceedings, FERC directed PJM to recalculate the BRA results using the original LDA Reliability Requirements and to rerun the Third Incremental Auction, and PJM published revised results on May 8, 2024, and May 23, 2024, respectively. On July 9, 2024, FERC denied a related complaint filed on April 22, 2024 (the "April 2024 Complaint") which was appealed to the Court of Appeals for the D.C. Circuit on November 5, 2024. On January 13, 2026, the Court of Appeals for the D.C. Circuit issued a decision vacating FERC's order denying the April 2024 Complaint and remanding the case to FERC for a ruling on the substance of the complaint. The remanded complaint is pending at FERC.
PJM Base Residual Auction Revisions and Delay - In November 2024, at PJM's request, FERC approved delays to future BRAs. The 2028/2029 BRA was the last delayed auction affected. On July 14, 2026, PJM announced the results of its BRA for the 2028/2029 delivery year. The price came in at the FERC-approved cap of $325/MW-day for the entire PJM footprint of which NRG cleared approximately 6,839 MW's from the Company's PJM generation fleet. NRG's expected capacity revenues from the Company's PJM generation fleet for the 2028/2029 delivery year is approximately $811 million.
PJM's Reforms to Large Load Additions - On September 15, 2025, PJM began a formal stakeholder process called the Critical Issue Fast Path ("CIFP") to address needed reforms to accommodate large load additions. On January 16, 2026, the National Energy Dominance Council within the White House released a Statement of Principles, signed by all 13 governors in the PJM region, urging PJM to address revenue certainty for new generation through an auction process for new capacity,
allocate the costs of these new resources to data centers, improve load forecasting, and accelerate ongoing generation interconnection studies. Also on January 16, 2026, the PJM Board issued a decisional letter on the CIFP process. The Board letter directed PJM staff to implement changes to load forecasting, implement a bring your own new generation program and associated expedited interconnection track, initiate immediately a Reliability Backstop Auction to obtain commitments of additional generation for a longer term, and undertake a holistic review of the PJM markets to analyze how they can evolve to provide appropriate incentives for investment and performance. On February 27, 2026, PJM made two filings at FERC. In its first filing, PJM proposed an expedited interconnection track for up to ten qualified large load projects, which was approved by FERC on June 9, 2026. In its second filing, PJM proposed an extension of the price cap and price floor for all capacity auctions through the 2028/2029 and 2029/2030 delivery years, which was approved by FERC on April 28, 2026.
On May 27, 2026, PJM published a revised Reliability Backstop Procurement proposal in response to the January 16, 2026 Board directive. PJM proposes a one-time, transitional procurement of capacity through two parallel processes. On June 9, 2026, Charles River Associates, on behalf of PJM, issued a Request for Proposals to facilitate bilateral contracting between large loads and eligible supply. On July 31, 2026, PJM filed at FERC to implement the Reliability Backstop Procurement proposal, under which there would be a central procurement process to procure capacity for the approximately 6,800 MW shortfall identified in the 2028/2029 BRA. On September 29, 2026, FERC accepted PJM's proposed Reliability Backstop Procurement tariff revisions for filing, suspended them for five months to become effective February 28, 2027, subject to refund and further Commission order, and established paper-hearing procedures to further develop the record regarding issues raised by the proposal. As a result, the procurement will not proceed according to the schedule originally proposed by PJM.
On August 13, 2026, PJM filed at FERC proposed revisions to its tariff to establish an Interim Resource Adequacy Service ("IRAS") and a Large Load Registry. The proposal is intended to address resource adequacy concerns associated with the rapid growth of large loads, including data centers, by requiring load serving entities supporting certain new large loads to secure sufficient new capacity or otherwise be subject to curtailment requirements during periods of resource scarcity. The proposal would also establish a registry to track existing and new large loads within the PJM footprint and create mechanisms for new large loads to satisfy resource adequacy requirements through qualifying new capacity arrangements. On October 9, 2026, FERC rejected the proposed IRAS framework and related new capacity arrangements, while accepting PJM's proposed definition of Large Load and Large Load Registry. FERC's rejection does not prevent PJM from submitting a modified IRAS proposal in a future filing.
Indian River RMR Proceeding - On June 29, 2021, Indian River notified PJM that it intended to retire Unit 4. PJM identified reliability violations resulting from the proposed deactivation of Unit 4. The Company filed a cost based RMR rate schedule at FERC. The Company reached settlement with a number of the intervening parties and the settlement agreement was filed. On January 16, 2025, FERC issued an order approving the settlement agreement. Indian River Unit 4 retired on February 23, 2025. On May 19, 2025, Maryland Office of People's Counsel filed an appeal to the Court of Appeals for the Fourth Circuit of FERC's denial on its request for rehearing. On August 22, 2025, NRG filed a motion to transfer venue. On November 12, 2025, the motion to transfer venue was granted and the appeal was transferred to the Court of Appeals for the D.C. Circuit. The appeal is pending, and briefing is underway.
Generator Complaint Against PJM - On October 6, 2026, Monongahela Power Company ("Mon Power") filed a complaint at FERC challenging PJM's advance commitment and dispatch of natural gas-fired generation during Winter Storm Fern in January 2026. Mon Power alleges that these practices increased congestion and energy prices, resulting in in additional costs to its customers, and requests hearing procedures to further examine PJM's actions. The complaint is pending at FERC. Multiple intervenors are opposed to Mon Power's complaint, including NRG's trade organization which filed comments requesting denial of the complaint on October 26, 2026.
Exelon Complaint Against PJM - On November 3, 2026, Exelon filed a complaint at FERC against PJM that asks the Commission to find PJM's three-year forward capacity auction schedule unjust and unreasonable and to replace it with an auction held two months prior to each Delivery Year, beginning with the 2030/2031 Base Residual Auction. If accepted, this could change the capacity market construct and affect future Base Residual Auctions.
Other Regulatory Matters
From time to time, NRG entities may be subject to examinations, investigations and/or enforcement actions by federal, state and provincial licensing and regulatory agencies and may face the risk of penalties for violation of financial services, consumer protections and other applicable laws and regulations.
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. In general, the electric generation industry has faced increasingly stringent requirements
regarding air quality, GHG emissions, combustion byproducts, water use and discharge, and threatened and endangered species including several rules promulgated in 2024. Future laws may require the addition of emissions controls or other environmental controls or to impose additional restrictions on the operations of the Company's facilities including unit retirements or impose obligations related to historic coal ash use, storage and disposal. At the federal level, the President has issued several Executive Orders that indicate that the current administration intends to relax or rescind some previously promulgated regulations. The EPA has proposed several and finalized some rules that relax and/or rescind regulations previously promulgated. 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.
Several regulations that affect the Company have been and continue to be revised by the EPA, including requirements regarding coal ash, GHG emissions, NAAQS revisions and implementation and effluent limitation guidelines. NRG will evaluate the impact of these regulations as they are revised but cannot fully predict the impact of each until anticipated revisions, legal challenges and reconsiderations are resolved. The Company's environmental matters are described in the Company's 2025 Form 10-K in Item 1, Business - Environmental Matters and Item 1A, Risk Factors. These matters have been updated in Note 16, Environmental Matters, to the condensed consolidated financial statements of this Form 10-Q and as follows.
Air
The CAA and related regulations (as well as similar state and local requirements) have the potential to affect air emissions, operating practices and pollution control equipment required at power plants. Under the CAA, the EPA sets NAAQS for certain pollutants including 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 March 2024, the EPA increased the stringency of the PM2.5 NAAQS and numerous legal challenges were filed in the D.C. Circuit. In November 2025, the EPA asked the DC Circuit to vacate the March 2024 rule. On June 26, 2026, the D.C. Circuit upheld the March 2024 Rule denying the legal challenges and the EPA's request to vacate the rule. The Company maintains a comprehensive compliance strategy to address continuing and new requirements. Complying with increasingly stringent requirements 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 2019, the EPA promulgated the ACE rule, which rescinded the CPP, which had sought to broadly regulate CO2 emissions from the power sector. On January 19, 2021, the D.C. Circuit vacated the ACE rule (but on February 22, 2021, at the EPA's request, stayed the issuance of the portion of the mandate that would vacate the repeal of the CPP). On 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. On May 9, 2024, the EPA promulgated a rule that repealed the ACE rule and significantly revised the manner in which new combustion-turbine and existing steam EGU's GHG emissions would be regulated including capturing and storing/sequestering CO2 in some instances. This rule was challenged by numerous parties in the D.C. Circuit including 27 states with 22 states intervening in support of the rule. The D.C. Circuit held oral arguments related to this rule in December 2024. In February 2025, the court granted a motion the DOJ filed asking the court to hold proceedings in abeyance while the EPA evaluated the rule. On September 17, 2026, the EPA finalized a rule repealing many of the provisions of the 2024 Carbon Pollution Standards applicable to fossil fuel-fired EGUs and proposed rescinding the remaining GHG emission requirements for fossil fuel-fired power plants. On the same day, the rule was challenged in the DC Circuit and the outcome of the legal challenges is uncertain.
CSAPR - On March 15, 2023, the EPA signed and released a prepublication version of a final rule that sought to significantly revise the CSAPR to address the good-neighbor obligations of the 2015 ozone NAAQS for 23 states (a Federal Implementation Plan or "FIP") 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 Fifth Circuit stayed the EPA's disapproval of Texas's and Louisiana's state plans, which disapprovals are a condition precedent to the EPA imposing its plan on Texas and Louisiana. On March 25, 2025, the Fifth Circuit upheld the EPA's disapproval of Texas's and Louisiana's state plans but did not address the FIP. On May 9, 2025, Texas and other parties petitioned the Fifth Circuit for a rehearing with the whole court. On March 13, 2026, the Fifth Circuit issued a revised opinion vacating and remanding the EPA's disapproval of Texas's interstate transport plan. On June 5, 2023, the EPA promulgated the FIP. On June 27, 2024, the U.S. Supreme Court stayed the FIP in the 11 states where the rule had not already been stayed. On April 14, 2025, the D.C. Circuit granted the EPA's request to hold the legal challenges in abeyance while the EPA revisits the rule. On January 30, 2026, the EPA proposed a Phase 1 reconsideration rule covering Alabama, Arizona, Iowa, Kansas, Kentucky, Minnesota, Mississippi, Nevada, New Mexico and Tennessee. The EPA intends to address additional states in a separate action. The Company cannot predict the outcome of the legal challenges to the various state disapprovals and the final rule promulgated on June 5, 2023.
Regional Haze - In May 2023, the EPA proposed to withdraw the existing Texas Sulfur Dioxide Trading Program and replace it with unit-specific SO2 limits for 12 units in Texas to address requirements to improve visibility at National Parks and Wilderness areas. On December 5, 2025, the EPA approved Texas's plans to address the Regional Haze rule.
MATS - On May 7, 2024, the EPA promulgated a final rule that amended the MATS rule by, among other things, increasing the stringency of the filterable particulate matter standard at coal-burning units. The deadline for complying with this more stringent standard had been 2027. On April 8, 2025, the President signed a Proclamation that created a 2-year exemption for compliance beginning on July 8, 2027 and ending on July 8, 2029 for certain coal units including those owned by the Company. Twenty-three states have challenged this rule in the D.C. Circuit. On February 24, 2026, the EPA promulgated a final rule repealing the majority of the 2024 rule amending the MATS rule, which also has been challenged in the D.C. Circuit.
Water
The Company is required under the Clean Water Act 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.
ELG - In 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 October 13, 2020, the EPA amended the 2015 ELG rule by: (i) altering the stringency of certain limits for FGD wastewater; (ii) relaxing the zero-discharge requirement for bottom ash transport water; and (iii) changing several deadlines. In 2021, NRG informed its regulators that the Company intended 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, which the Company completed by the end of 2025. However, PJM has requested that two coal-fueled units at Powerton continue to operate until at least May 31, 2031 to address reliability concerns. On May 9, 2024, the EPA promulgated a rule that again revises the ELG by, among other things, further restricting the discharge of (i) FGD wastewater, (ii) bottom ash transport water, and (iii) combustion residual leachate. The rule was challenged in numerous courts, but the cases were consolidated in the U.S. Court of Appeals for the Eighth Circuit. The outcome of the legal challenges is uncertain. On February 19, 2025, the DOJ filed a motion asking the court to hold proceedings in abeyance while the U.S. presidential administration evaluates the rule, which the court granted. On December 31, 2025, the EPA promulgated a rule that extends several deadlines and provides greater flexibility regarding decisions to invest in more stringent controls.
Byproducts
In 2015, the EPA finalized the rule regulating byproducts of coal combustion (e.g., ash and gypsum) as solid wastes under the RCRA. On August 21, 2018, the D.C. Circuit found, among other things, that the EPA had not adequately regulated unlined ponds and legacy 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. On May 8, 2024, the EPA promulgated a rule that establishes requirements for: (i) inactive (or legacy) surface impoundments at inactive facilities and (ii) CCR management units (regardless of how or when the CCR was placed) at regulated facilities. The rule also creates an obligation to conduct site assessments (at all active and certain inactive facilities) to determine whether CCR management units are present. On February 10, 2026, the EPA promulgated a rule extending certain deadlines in the 2024 rule. On April 13, 2026, the EPA proposed further amendments to the CCR that if finalized would provide industry greater compliance flexibility. The rule has been challenged in the D.C. Circuit and the outcome of the legal challenges is uncertain.
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.
Regional Environmental Developments
Ash Regulation in Illinois - On July 30, 2019, Illinois enacted legislation that 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 construction permits (for closure and retrofits) as required by the regulation and is waiting for most of its permits to be issued by the Illinois EPA.
Illinois GHG Regulation - Illinois enacted the Climate and Equitable Jobs Act ("CEJA") in 2021, which, among other things, established a schedule for eliminating GHGs from the production of electricity. CEJA required the Company's EGUs in Illinois (including those recently acquired from LS Power) to retire on January 1, 2030 subject to certain reliability exceptions. However, on July 2, 2026, PJM invoked these reliability exceptions and extended the CEJA deadlines to May 31, 2031.
Houston Nonattainment for 2008 Ozone Standard - In 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.
Virginia Rejoining the Regional Greenhouse Gas Initiative ("RGGI") - On February 20, 2026, Virginia enacted legislation to rejoin the RGGI. During the second quarter of 2026, Virginia promulgated the implementing regulations, which require participation in RGGI as of July 1, 2026. Virginia's decision to rejoin RGGI coincided with a significant increase in the price of RGGI allowances.
Significant Events
The following significant events have occurred during 2026 as further described within this Management's Discussion and Analysis and the condensed consolidated financial statements:
Anticipated Sale of 4.9 GW of Generation Assets
On November 9, 2026, the Company entered into a definitive agreement with LS Power to sell six natural-gas fired generation assets totaling 4.9 GW from the Texas and East segments for cash proceeds of $4 billion, subject to working capital and other closing adjustments. The transaction is targeted to close in the second quarter of 2027, and is subject to customary closing conditions and regulatory approvals, including HSR, FERC and NYSPSC. The sale retains the entire PJM portfolio and CPower acquired by the Company in January 2026. The Company plans to use the remaining proceeds, after debt reduction of $2 billion, for $1 billion of share repurchases and $1 billion for either contracted growth investments or additional debt reduction. For further discussion, see Note 4, Acquisitions and Dispositions.
Texas Energy Fund (TEF)
The Company achieved commercial operations at its first project, the 415 MW T.H. Wharton facility, in May 2026.
Acquisition of LSP Portfolio
On January 30, 2026, NRG completed the acquisition of the LSP Portfolio from LS Power. The acquisition doubles NRG's generation capacity with the addition of 18 natural gas-fired and dual fuel facilities totaling approximately 13 GW. In addition, NRG acquired CPower, a leading demand response platform, which operates in all the country's deregulated energy markets and has more than 2,000 commercial and industrial customers. The consideration consisted of 24.25 million shares of NRG common stock and $6.4 billion in cash, plus working capital and certain other adjustments of $472 million. The Company funded the cash consideration using a portion of the net proceeds of $4.4 billion from the 5.750% 2034 Senior Notes, the 2036 Senior Notes, Senior Secured First Lien Notes, due 2030 and the Senior Secured First Lien Notes, due 2035 and proceeds of $2.5 billion from the Company's Revolving Credit Facility. For further discussion, see Note 4, Acquisitions and Dispositions.
Capital Allocation
During the nine months ended September 30, 2026, the Company completed $963 million of share repurchases at an average price of $154.45 per share. Through October 31, 2026, an additional $14 million of share repurchases were executed at an average price of $99.62 per share. On November 6, 2026, in connection with its approval of the sale of 4.9 GW of generation assets to LS Power, the Board of Directors approved an additional $1.0 billion of share repurchases. See Note 9, Changes in Capital Structure for additional discussion.
In the first quarter of 2026, NRG increased the annual common stock dividend to $1.90 from $1.76 per share, representing an 8% increase from 2025. Beginning in the first quarter of 2027, NRG will increase the annual dividend by 8% to $2.05 per share. The Company targets an annual dividend growth rate of 7-9% per share in subsequent years.
Term Loan B Incurrence
On April 28, 2026, the Company and APX Group LLC, as borrowers, and certain of the Company's subsidiaries, as guarantors, entered into the Sixteenth Amendment to the Credit Agreement to establish new term loans in aggregate principal amount of $900 million. For further discussion, see Note 7, Long-term Debt and Finance Leases.
Issuance of Unsecured Notes and Secured Notes
On April 28, 2026, the Company issued $2.1 billion in aggregate principal amount of the New Unsecured Notes. The New Unsecured Notes are senior unsecured obligations of the Company and are guaranteed by its wholly-owned U.S. subsidiaries that guarantee the loans under the Senior Credit Facility. For further discussion, see Note 7, Long-term Debt and Finance Leases.
On April 28, 2026, the Company also issued $500 million aggregate principal amount of the New 2031 Notes. The New 2031 Notes are senior secured obligations of the Company and are guaranteed by its wholly-owned U.S. subsidiaries that guarantee the loans under the Senior Credit Facility. For further discussion, see Note 7, Long-term Debt and Finance Leases.
Bilateral Letter of Credit Facilities
In January and February 2026, the Company and certain of its subsidiaries, as guarantors, entered into amendments to its existing bilateral letter of credit facilities to increase the size of its bilateral credit facilities by $410 million and $90 million, respectively, to provide additional liquidity. As of September 30, 2026, $655 million was issued under these facilities.
Lightning Notes and Lightning Tender Offer and Redemption
On the Acquisition Closing Date, Lightning remained the issuer of the Lightning 2032 Notes issued pursuant to the Lightning Indenture, by and among Lightning, Lightning's subsidiaries that are guarantors from time to time party thereto, and the Lightning Notes Trustee.
During the second quarter of 2026, Lightning completed the Tender Offer and Redemption. For further discussion, see Note 7, Long-term Debt and Finance Leases.
Trends Affecting Results of Operations and Future Business Performance
The Company's trends are described in the Company's 2025 Form 10-K in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Business Environment, except for the update below:
Geopolitical Developments - The ongoing geopolitical conflicts, including hostilities with Iran and conflicts in the Middle East, and the potential for further escalation and disruption, have contributed to elevated and volatile oil prices and could, over time, put upward pressure on U.S. natural gas prices. Prolonged market volatility could result in increased collateral requirements and heighten counterparty credit exposure under NRG's hedging arrangements.
Changes in Accounting Standards
See Note 2, Summary of Significant Accounting Policies, for a discussion of recent accounting developments.
Consolidated Results of Operations
The following table provides selected financial information for the Company:
| Three months ended September 30, | Nine months ended September 30, | ||||||||||||||||||||||||||||||||||
| (In millions) | 2026 | 2025 | Change | 2026 | 2025 | Change | |||||||||||||||||||||||||||||
| Revenue | |||||||||||||||||||||||||||||||||||
| Retail revenue | $ | 8,193 | $ | 7,282 | $ | 911 | $ | 24,379 | $ | 22,017 | $ | 2,362 | |||||||||||||||||||||||
|
Energy revenue(a)
|
780 | 148 | 632 | 1,530 | 492 | 1,038 | |||||||||||||||||||||||||||||
|
Capacity revenue(a)
|
359 | 87 | 272 | 1,016 | 195 | 821 | |||||||||||||||||||||||||||||
| Mark-to-market for economic hedging activities | (2) | 34 | (36) | (26) | 18 | (44) | |||||||||||||||||||||||||||||
| Contract amortization | 10 | 1 | 9 | 30 | (4) | 34 | |||||||||||||||||||||||||||||
|
Other revenues(a)(b)
|
126 | 83 | 43 | 274 | 242 | 32 | |||||||||||||||||||||||||||||
| Total revenue | 9,466 | 7,635 | 1,831 | 27,203 | 22,960 | 4,243 | |||||||||||||||||||||||||||||
| Operating Costs and Expenses | |||||||||||||||||||||||||||||||||||
| Cost of fuel | 598 | 343 | (255) | 1,353 | 928 | (425) | |||||||||||||||||||||||||||||
|
Purchased energy and other cost of sales(c)
|
5,878 | 4,975 | (903) | 18,424 | 15,698 | (2,726) | |||||||||||||||||||||||||||||
| Mark-to-market for economic hedging activities | 153 | 410 | 257 | 45 | 346 | 301 | |||||||||||||||||||||||||||||
|
Contract and emissions credit amortization(c)
|
20 | 15 | (5) | 43 | 43 | - | |||||||||||||||||||||||||||||
| Operations and maintenance | 460 | 396 | (64) | 1,355 | 1,118 | (237) | |||||||||||||||||||||||||||||
| Other cost of operations | 129 | 102 | (27) | 346 | 298 | (48) | |||||||||||||||||||||||||||||
| Cost of operations (excluding depreciation and amortization shown below) | 7,238 | 6,241 | (997) | 21,566 | 18,431 | (3,135) | |||||||||||||||||||||||||||||
| Depreciation and amortization | 510 | 360 | (150) | 1,436 | 1,030 | (406) | |||||||||||||||||||||||||||||
| Selling, general and administrative costs (excluding amortization of customer acquisition costs of $101, $78, $281, and $211 respectively, which are included in depreciation and amortization shown separately above) | 619 | 612 | (7) | 1,774 | 1,885 | 111 | |||||||||||||||||||||||||||||
| Acquisition-related transaction and integration costs | 16 | 8 | (8) | 77 | 59 | (18) | |||||||||||||||||||||||||||||
| Total operating costs and expenses | 8,383 | 7,221 | (1,162) | 24,853 | 21,405 | (3,448) | |||||||||||||||||||||||||||||
| Gain/(Loss) on sale of assets | 1 | - | 1 | 38 | (7) | 45 | |||||||||||||||||||||||||||||
| Operating Income | 1,084 | 414 | 670 | 2,388 | 1,548 | 840 | |||||||||||||||||||||||||||||
| Other (Expense)/Income | |||||||||||||||||||||||||||||||||||
| Other (expense)/income, net | (3) | 11 | (14) | 43 | 30 | 13 | |||||||||||||||||||||||||||||
| Loss on debt extinguishment | - | - | - | (9) | (10) | 1 | |||||||||||||||||||||||||||||
| Interest expense | (302) | (187) | (115) | (897) | (498) | (399) | |||||||||||||||||||||||||||||
| Total other expense | (305) | (176) | (129) | (863) | (478) | (385) | |||||||||||||||||||||||||||||
| Income Before Income Taxes | 779 | 238 | 541 | 1,525 | 1,070 | 455 | |||||||||||||||||||||||||||||
| Income tax expense | 218 | 86 | (132) | 333 | 272 | (61) | |||||||||||||||||||||||||||||
| Net Income | $ | 561 | $ | 152 | $ | 409 | $ | 1,192 | $ | 798 | $ | 394 | |||||||||||||||||||||||
(a)Includes gains and losses from financially settled transactions
(b)Includes trading gains and losses and ancillary revenues
(c)Includes amortization of SO2 and NOx credits and excludes amortization of RGGI credits
Management's discussion of the results of operations for the three months ended September 30, 2026 and 2025
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, 2026 and 2025:
| Average on Peak Power Price ($/MWh) | |||||||||||||||||
| Three months ended September 30, | |||||||||||||||||
| Region | 2026 | 2025 | Change % | ||||||||||||||
| Texas | |||||||||||||||||
|
ERCOT - Houston(a)
|
$ | 39.68 | $ | 38.68 | 3 | % | |||||||||||
|
ERCOT - North(a)
|
38.97 | 36.94 | 5 | % | |||||||||||||
| East | |||||||||||||||||
|
NY J/NYC(b)
|
$ | 71.12 | $ | 66.57 | 7 | % | |||||||||||
|
NEPOOL(b)
|
62.82 | 62.77 | - | % | |||||||||||||
|
COMED (PJM)(b)
|
72.19 | 55.33 | 30 | % | |||||||||||||
|
PJM - West Hub(b)
|
99.44 | 61.48 | 62 | % | |||||||||||||
|
PJM - APS(b)
|
92.00 | 56.64 | 62 | % | |||||||||||||
|
PJM - DOMINION(b)
|
110.81 | 77.59 | 43 | % | |||||||||||||
| West | |||||||||||||||||
|
MISO - Louisiana Hub(b)
|
$ | 51.70 | $ | 40.93 | 26 | % | |||||||||||
|
CAISO - SP15(b)
|
41.11 | 36.34 | 13 | % | |||||||||||||
(a)Average on peak power prices based on real time settlement prices as published by the respective ISOs
(b)Average on peak power prices based on day ahead settlement prices as published by the respective ISOs
Natural Gas Prices
The following table summarizes the average Henry Hub natural gas price for the three months ended September 30, 2026 and 2025:
| Three months ended September 30, | |||||||||||||||||
| 2026 | 2025 | Change % | |||||||||||||||
|
($/MMBtu)
|
$ | 2.95 | $ | 3.07 | (4) | % | |||||||||||
Gross Margin
The Company calculates gross margin in order to evaluate operating performance as revenues less cost of fuel, purchased energy and other costs of sales, mark-to-market for economic hedging activities, contract and emissions credit amortization and depreciation and amortization.
Economic Gross Margin
In addition to gross margin, the Company evaluates its operating performance using the measure of economic gross margin, which is not a GAAP measure and may not be comparable to other companies' presentations or deemed more useful than the GAAP information provided elsewhere in this report. Economic gross margin should be viewed as a supplement to and not a substitute for the Company's presentation of gross margin, which is the most directly comparable GAAP measure. Economic gross margin is not intended to represent gross margin. The Company believes that economic gross margin is useful to investors as it is a key operational measure reviewed by the Company's management. Economic gross margin is defined as the sum of retail revenue, energy revenue, capacity revenue and other revenue, less cost of fuel, purchased energy and other cost of sales. Economic gross margin does not include mark-to-market gains or losses on economic hedging activities, contract amortization, emissions credit amortization, depreciation and amortization, operations and maintenance, or other cost of operations.
The following tables present the composition and reconciliation of gross margin and economic gross margin for the three months ended September 30, 2026 and 2025:
| Three months ended September 30, 2026 | |||||||||||||||||||||||||||||||||||
|
($ In millions)
|
Texas | East |
West/Other
|
Vivint Smart Home | Corporate/Eliminations | Total | |||||||||||||||||||||||||||||
| Retail revenue | $ | 3,701 | $ | 3,223 | $ | 667 | $ | 609 | $ | (7) | $ | 8,193 | |||||||||||||||||||||||
| Energy revenue | - | 780 | - | - | - | 780 | |||||||||||||||||||||||||||||
| Capacity revenue | - | 359 | 20 | - | (20) | 359 | |||||||||||||||||||||||||||||
| Mark-to-market for economic hedging activities | - | (2) | - | - | - | (2) | |||||||||||||||||||||||||||||
| Contract amortization | - | 10 | - | - | - | 10 | |||||||||||||||||||||||||||||
|
Other revenue(a)
|
27 | 94 | 5 | - | - | 126 | |||||||||||||||||||||||||||||
| Total revenue | 3,728 | 4,464 | 692 | 609 | (27) | 9,466 | |||||||||||||||||||||||||||||
| Cost of fuel | (366) | (232) | - | - | - | (598) | |||||||||||||||||||||||||||||
|
Purchased energy and other cost of sales(b)(c)(d)
|
(1,821) | (3,424) | (593) | (60) | 20 | (5,878) | |||||||||||||||||||||||||||||
| Mark-to-market for economic hedging activities | (287) | 43 | 91 | - | - | (153) | |||||||||||||||||||||||||||||
| Contract and emissions credit amortization | (6) | (11) | (3) | - | - | (20) | |||||||||||||||||||||||||||||
| Depreciation and amortization | (133) | (125) | (7) | (231) | (14) | (510) | |||||||||||||||||||||||||||||
| Gross margin | $ | 1,115 | $ | 715 | $ | 180 | $ | 318 | $ | (21) | $ | 2,307 | |||||||||||||||||||||||
| Less: Mark-to-market for economic hedging activities, net | (287) | 41 | 91 | - | - | (155) | |||||||||||||||||||||||||||||
| Less: Contract and emissions credit amortization, net | (6) | (1) | (3) | - | - | (10) | |||||||||||||||||||||||||||||
| Less: Depreciation and amortization | (133) | (125) | (7) | (231) | (14) | (510) | |||||||||||||||||||||||||||||
| Economic gross margin | $ | 1,541 | $ | 800 | $ | 99 | $ | 549 | $ | (7) | $ | 2,982 | |||||||||||||||||||||||
| (a) Includes trading gains and losses and ancillary revenues | |||||||||||||||||||||||||||||||||||
|
(b) Includes capacity and emissions credits
|
|||||||||||||||||||||||||||||||||||
|
(c) Includes $1.2 billion, $66 million and $228 million of TDSP expense in Texas, East and West/Other, respectively
|
|||||||||||||||||||||||||||||||||||
|
(d) Excludes depreciation and amortization shown separately
|
|||||||||||||||||||||||||||||||||||
| Business Metrics | Texas | East |
West/Other
|
Vivint Smart Home | Corporate/Eliminations | Total | |||||||||||||||||||||||||||||
| Retail sales | |||||||||||||||||||||||||||||||||||
| Home electricity sales volume (GWh) | 13,538 | 4,635 | 646 | - | - | 18,819 | |||||||||||||||||||||||||||||
| Business electricity sales volume (GWh) | 11,811 | 13,111 | 3,449 | - | - | 28,371 | |||||||||||||||||||||||||||||
| Home natural gas sales volume (MDth) | - | 2,533 | 5,504 | - | - | 8,037 | |||||||||||||||||||||||||||||
| Business natural gas sales volume (MDth) | - | 375,685 | 38,877 | - | - | 414,562 | |||||||||||||||||||||||||||||
|
Average retail Home customer count (in thousands)(a)
|
2,802 | 2,159 | 638 | - | - | 5,599 | |||||||||||||||||||||||||||||
|
Ending retail Home customer count (in thousands)(a)
|
2,776 | 2,109 | 635 | - | - | 5,520 | |||||||||||||||||||||||||||||
|
Average Vivint Smart Home customer count (in thousands)(b)
|
- | - | - | 2,557 | - | 2,557 | |||||||||||||||||||||||||||||
|
Ending Vivint Smart Home customer count (in thousands) (b)(c)
|
- | - | - | 2,593 | - | 2,593 | |||||||||||||||||||||||||||||
| Power generation | |||||||||||||||||||||||||||||||||||
|
GWh sold(d)
|
13,381 | 9,997 | 1 | - | - | 23,379 | |||||||||||||||||||||||||||||
| GWh generated | |||||||||||||||||||||||||||||||||||
| Coal | 6,121 | 1,772 | - | - | - | 7,893 | |||||||||||||||||||||||||||||
| Gas | 7,260 | 7,690 | - | - | - | 14,950 | |||||||||||||||||||||||||||||
| Oil | - | 14 | - | - | - | 14 | |||||||||||||||||||||||||||||
| Renewables | - | - | 1 | - | - | 1 | |||||||||||||||||||||||||||||
|
Total
|
13,381 | 9,476 | 1 | - | - | 22,858 | |||||||||||||||||||||||||||||
| (a) Home customer count includes recurring residential customers and community choice | |||||||||||||||||||||||||||||||||||
| (b) Vivint Smart Home includes customers that also purchase other NRG products such as electricity | |||||||||||||||||||||||||||||||||||
|
(c) Vivint Smart Home includes 67 thousand Home Protection (non-Vivint) customers
|
|||||||||||||||||||||||||||||||||||
|
(d) Includes GWh sold from owned and tolled generation, excludes equity investments
|
|||||||||||||||||||||||||||||||||||
| Three months ended September 30, 2025 | |||||||||||||||||||||||||||||||||||
|
($ In millions)
|
Texas | East | West/Other | Vivint Smart Home | Corporate/Eliminations | Total | |||||||||||||||||||||||||||||
| Retail revenue | $ | 3,300 | $ | 2,766 | $ | 668 | $ | 552 | $ | (4) | $ | 7,282 | |||||||||||||||||||||||
| Energy revenue | 16 | 132 | - | - | - | 148 | |||||||||||||||||||||||||||||
| Capacity revenue | - | 87 | - | - | - | 87 | |||||||||||||||||||||||||||||
| Mark-to-market for economic hedging activities | - | 28 | 6 | - | - | 34 | |||||||||||||||||||||||||||||
| Contract amortization | - | 1 | - | - | - | 1 | |||||||||||||||||||||||||||||
|
Other revenue(a)
|
63 | 16 | 6 | - | (2) | 83 | |||||||||||||||||||||||||||||
| Total revenue | 3,379 | 3,030 | 680 | 552 | (6) | 7,635 | |||||||||||||||||||||||||||||
| Cost of fuel | (274) | (60) | (9) | - | - | (343) | |||||||||||||||||||||||||||||
|
Purchased energy and other cost of sales(b)(c)(d)
|
(1,775) | (2,552) | (591) | (58) | 1 | (4,975) | |||||||||||||||||||||||||||||
| Mark-to-market for economic hedging activities | (407) | 37 | (40) | - | - | (410) | |||||||||||||||||||||||||||||
| Contract and emissions credit amortization | (7) | (5) | (3) | - | - | (15) | |||||||||||||||||||||||||||||
| Depreciation and amortization | (95) | (37) | (6) | $ | (211) | (11) | (360) | ||||||||||||||||||||||||||||
| Gross margin | $ | 821 | $ | 413 | $ | 31 | $ | 283 | $ | (16) | $ | 1,532 | |||||||||||||||||||||||
| Less: Mark-to-market for economic hedging activities, net | (407) | 65 | (34) | - | - | (376) | |||||||||||||||||||||||||||||
| Less: Contract and emissions credit amortization, net | (7) | (4) | (3) | - | - | (14) | |||||||||||||||||||||||||||||
| Less: Depreciation and amortization | (95) | (37) | (6) | (211) | (11) | (360) | |||||||||||||||||||||||||||||
| Economic gross margin | $ | 1,330 | $ | 389 | $ | 74 | $ | 494 | $ | (5) | $ | 2,282 | |||||||||||||||||||||||
| (a) Includes trading gains and losses and ancillary revenues | |||||||||||||||||||||||||||||||||||
| (b) Includes capacity and emissions credits | |||||||||||||||||||||||||||||||||||
| (c) Includes $970 million, $56 million and $198 million of TDSP expense in Texas, East, and West/Other, respectively | |||||||||||||||||||||||||||||||||||
| (d) Excludes depreciation and amortization shown separately | |||||||||||||||||||||||||||||||||||
| Business Metrics | Texas | East | West/Other | Vivint Smart Home | Corporate/Eliminations | Total | |||||||||||||||||||||||||||||
| Retail sales | |||||||||||||||||||||||||||||||||||
| Home electricity sales volume (GWh) | 12,462 | 4,175 | 621 | - | - | 17,258 | |||||||||||||||||||||||||||||
| Business electricity sales volume (GWh) | 10,990 | 12,477 | 3,759 | - | - | 27,226 | |||||||||||||||||||||||||||||
| Home natural gas sales volume (MDth) | - | 2,699 | 4,440 | - | - | 7,139 | |||||||||||||||||||||||||||||
| Business natural gas sales volume (MDth) | - | 298,222 | 37,449 | - | - | 335,671 | |||||||||||||||||||||||||||||
|
Average retail Home customer count (in thousands)(a)
|
2,873 | 2,125 | 651 | - | - | 5,649 | |||||||||||||||||||||||||||||
|
Ending retail Home customer count (in thousands)(a)
|
2,844 | 2,115 | 651 | - | - | 5,610 | |||||||||||||||||||||||||||||
|
Average Vivint Smart Home customer count (in thousands)(b)
|
- | - | - | 2,379 | - | 2,379 | |||||||||||||||||||||||||||||
|
Ending Vivint Smart Home customer count (in thousands)(b)(c)
|
- | - | - | 2,414 | - | 2,414 | |||||||||||||||||||||||||||||
| Power generation | |||||||||||||||||||||||||||||||||||
|
GWh sold(d)
|
9,299 | 1,941 | 1 | - | - | 11,241 | |||||||||||||||||||||||||||||
| GWh generated | |||||||||||||||||||||||||||||||||||
| Coal | 6,287 | 1,249 | - | - | - | 7,536 | |||||||||||||||||||||||||||||
| Gas | 3,012 | 3 | - | - | - | 3,015 | |||||||||||||||||||||||||||||
| Oil | - | 8 | - | - | - | 8 | |||||||||||||||||||||||||||||
| Renewables | - | - | 1 | - | - | 1 | |||||||||||||||||||||||||||||
|
Total
|
9,299 | 1,260 | 1 | - | - | 10,560 | |||||||||||||||||||||||||||||
| (a) Home customer count includes recurring residential customers and community choice | |||||||||||||||||||||||||||||||||||
| (b) Vivint Smart Home includes customers that also purchase other NRG products such as electricity | |||||||||||||||||||||||||||||||||||
|
(c) Vivint Smart Home includes 63 thousand Home Protection (non-Vivint) customers
|
|||||||||||||||||||||||||||||||||||
|
(d) Includes GWh sold from owned, tolled and leased generation, excludes equity investments
|
|||||||||||||||||||||||||||||||||||
The following table represents the weather metrics for the three months ended September 30, 2026 and 2025:
| Three months ended September 30, | |||||||||||||||||
| Weather Metrics | Texas |
East(b)
|
West/Other(c)
|
||||||||||||||
| 2026 | |||||||||||||||||
|
CDDs(a)
|
1,959 | 762 | 1,330 | ||||||||||||||
|
HDDs(a)
|
- | 52 | 6 | ||||||||||||||
| 2025 | |||||||||||||||||
| CDDs | 1,659 | 710 | 1,123 | ||||||||||||||
| HDDs | - | 47 | 3 | ||||||||||||||
| 10-year average | |||||||||||||||||
| CDDs | 1,718 | 753 | 1,189 | ||||||||||||||
| HDDs | 5 | 51 | 9 | ||||||||||||||
(a) National Oceanic and Atmospheric Administration-Climate Prediction Center - A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. A HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period
(b) The East weather metrics are comprised of the average of the CDD and HDD regional results for the Northeast and East - Midwest regions
(c) The West/Other weather metrics are comprised of the average of the CDD and HDD regional results for the West - California and West - South Central regions
Gross Margin and Economic Gross Margin
Gross margin increased $775 million and economic gross margin increased $700 million during the three months ended September 30, 2026, compared to the same period in 2025.
The following tables describe the changes in gross margin and economic gross margin by segment:
Texas
| (In millions) | |||||
|
Higher gross margin due:
•a 16%, or $150 million decrease in cost to serve the retail load, driven by lower realized power prices associated with the Company's diversified supply strategy, including the assets acquired from the LSP Portfolio
•an increase in net revenue rates of $44 million, primarily driven by changes in customer term, product and mix
|
$ | 194 | |||
| Higher gross margin due to an increase in load attributed to weather, partially offset by lower gross margin driven by changes in customer mix and attrition | 52 | ||||
| Lower gross margin due to the impact of market optimization activities | (35) | ||||
|
Increase in economic gross margin
|
$ | 211 | |||
|
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges
|
120 | ||||
| Decrease in contract and emissions credit amortization | 1 | ||||
| Increase in depreciation and amortization | (38) | ||||
|
Increase in gross margin
|
$ | 294 | |||
East
| (In millions) | ||||||||
|
Higher electric gross margin due to the net effect of:
•an increase in net revenue rates of $158 million, primarily driven by changes in customer term, product and mix
•a 4%, or $54 million increase in cost to serve the retail load, driven by higher realized power prices associated with the Company's diversified supply strategy, including the assets acquired from the LSP Portfolio
|
$ | 104 | ||||||
| Higher electric gross margin from an increase in load due to a change in customer mix | 32 | |||||||
| Lower natural gas gross margin due to lower net revenue rates of $74 million from changes in customer term, product, and mix, partially offset by lower supply costs of $57 million, including the impact of transportation and storage contract optimization | (17) | |||||||
| Higher natural gas gross margin from an increase in load due to a change in customer mix | 14 | |||||||
| Higher gross margin due to an increase in capacity from the acquisition of the LSP Portfolio and at Midwest Generation | 243 | |||||||
| Higher gross margin due to an increase in demand response activities, including the acquisition of CPower and higher PJM auction prices in 2026 | 30 | |||||||
| Other | 5 | |||||||
|
Increase in economic gross margin
|
$ | 411 | ||||||
|
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges
|
(24) | |||||||
| Decrease in contract amortization | 3 | |||||||
| Increase in depreciation and amortization | (88) | |||||||
|
Increase in gross margin
|
$ | 302 | ||||||
West/Other
| (In millions) | |||||
| Lower electric gross margin due to lower net revenue rates of $42 million, partially offset by lower supply costs of $35 million and changes in customer mix of $2 million | $ | (5) | |||
| Higher gross margin at Cottonwood driven by the termination of the facility lease in May 2025 | 29 | ||||
| Other | 1 | ||||
|
Increase in economic gross margin
|
$ | 25 | |||
|
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges
|
125 | ||||
| Increase in depreciation and amortization | (1) | ||||
|
Increase in gross margin
|
$ | 149 | |||
Vivint Smart Home
| (In millions) | |||||
| Higher gross margin primarily driven by growth in customers of $41 million and higher monthly revenue of $11 million | $ | 52 | |||
| Higher gross margin in home protection due to increased sales volume | 4 | ||||
| Other | (1) | ||||
|
Increase in economic gross margin
|
$ | 55 | |||
| Increase in depreciation and amortization | (20) | ||||
|
Increase in gross margin
|
$ | 35 | |||
Mark-to-Market for Economic Hedging Activities
Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges. Total net mark-to-market results increased by $221 million during the three months ended September 30, 2026, compared to the same period in 2025.
The breakdown of gains and losses included in revenues and operating costs and expenses, by segment, was as follows:
| Three months ended September 30, 2026 | |||||||||||||||||||||||||||||
| (In millions) | Texas | East | West/Other |
Eliminations
|
Total | ||||||||||||||||||||||||
|
Mark-to-market results in revenue
|
|||||||||||||||||||||||||||||
|
Reversal of previously recognized unrealized gains on settled positions related to economic hedges
|
$ | - | $ | (2) | $ | - | $ | - | $ | (2) | |||||||||||||||||||
|
Reversal of acquired loss positions related to economic hedges
|
- | 5 | - | - | 5 | ||||||||||||||||||||||||
|
Net unrealized losses on open positions related to economic hedges
|
- | (5) | - | - | (5) | ||||||||||||||||||||||||
|
Total mark-to-market losses in revenue
|
$ | - | $ | (2) | $ | - | $ | - | $ | (2) | |||||||||||||||||||
|
Mark-to-market results in operating costs and expenses
|
|||||||||||||||||||||||||||||
|
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges(a)
|
$ | (208) | $ | (25) | $ | 35 | $ | - | $ | (198) | |||||||||||||||||||
|
Reversal of acquired (gain)/loss positions related to economic hedges
|
(16) | 161 | - | - | 145 | ||||||||||||||||||||||||
|
Net unrealized (losses)/gains on open positions related to economic hedges
|
(63) | (93) | 56 | - | (100) | ||||||||||||||||||||||||
|
Total mark-to-market (losses)/gains in operating costs and expenses
|
$ | (287) | $ | 43 | $ | 91 | $ | - | $ | (153) | |||||||||||||||||||
(a)Includes $(138) million, within the Texas segment, related to derivative contracts that were elected as NPNS on October 1, 2024 and are no longer valued at fair value on a recurring basis
| Three months ended September 30, 2025 | |||||||||||||||||||||||||||||
| (In millions) | Texas | East | West/Other |
Eliminations
|
Total | ||||||||||||||||||||||||
|
Mark-to-market results in revenue
|
|||||||||||||||||||||||||||||
|
Reversal of previously recognized unrealized losses on settled positions related to economic hedges
|
$ | - | $ | - | $ | 8 | $ | - | $ | 8 | |||||||||||||||||||
|
Net unrealized gains/(losses) on open positions related to economic hedges
|
- | 28 | (2) | - | 26 | ||||||||||||||||||||||||
|
Total mark-to-market gains in revenue
|
$ | - | $ | 28 | $ | 6 | $ | - | $ | 34 | |||||||||||||||||||
|
Mark-to-market results in operating costs and expenses
|
|||||||||||||||||||||||||||||
|
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges(a)
|
$ | (361) | $ | (31) | $ | 30 | $ | - | $ | (362) | |||||||||||||||||||
|
Reversal of acquired loss positions related to economic hedges
|
14 | 2 | - | - | 16 | ||||||||||||||||||||||||
|
Net unrealized (losses)/gains on open positions related to economic hedges
|
(60) | 66 | (70) | - | (64) | ||||||||||||||||||||||||
|
Total mark-to-market (losses)/gains in operating costs and expenses
|
$ | (407) | $ | 37 | $ | (40) | $ | - | $ | (410) | |||||||||||||||||||
(a)Includes $(266) million, within the Texas segment, related to derivative contracts that were elected as NPNS on October 1, 2024 and are no longer valued at fair value on a recurring basis
Mark-to-market results consist of unrealized gains and losses on contracts that are not yet settled. The settlement of these transactions is reflected in the same revenue or cost caption as the items being hedged.
The reversals of acquired gain or loss positions were valued based upon the forward prices on the acquisition date.
For the three months ended September 30, 2026, the $2 million loss in revenues from economic hedge positions was driven primarily by a decrease in the value of open positions as a result of increases in PJM power prices as well as the reversal of previously recognized unrealized gains on contracts that settled during the period, largely offset by the reversal of acquired loss positions related to economic hedges. The $153 million loss in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period as well as a decrease in the value of open positions driven by decreases in natural gas prices, partially offset by the reversal of acquired loss positions related to economic hedges.
For the three months ended September 30, 2025, the $34 million gain in revenues from economic hedge positions was driven primarily by an increase in the value of open positions as a result of decreases in natural gas prices and the reversal of previously recognized unrealized losses on contracts that settled during the period. The $410 million loss in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period and a decrease in the value of open positions in West as a result of decreases in CAISO power prices.
In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the three months ended September 30, 2026 and 2025. The realized and unrealized financial and physical trading results are included in revenue. The Company's trading activities are subject to limits based on the Company's Risk Management Policy.
| Three months ended September 30, | |||||||||||
| (In millions) | 2026 | 2025 | |||||||||
| Trading (losses)/gains | |||||||||||
| Realized | $ | (1) | $ | 25 | |||||||
| Unrealized | (23) | (3) | |||||||||
| Total trading (losses)/gains | $ | (24) | $ | 22 | |||||||
Operations and Maintenance Expense
Operations and maintenance expense is comprised of the following:
| (In millions) | Texas | East | West/Other | Vivint Smart Home | Corporate/Eliminations | Total | |||||||||||||||||||||||||||||
| Three months ended September 30, 2026 | $ | 209 | $ | 164 | $ | 10 | $ | 77 | $ | - | $ | 460 | |||||||||||||||||||||||
| Three months ended September 30, 2025 | 205 | 105 | 15 | 67 | 4 | 396 | |||||||||||||||||||||||||||||
Operations and maintenance expense increased by $64 million for the three months ended September 30, 2026, compared to the same period in 2025, due to the following:
| (In millions) | |||||
| Increase primarily due to the acquisition of the LSP Portfolio in January 2026 | $ | 90 | |||
| Decrease due to timing of planned major maintenance expenditures at Powerton and in Texas | (19) | ||||
| Decrease driven by lower retail operations costs | (14) | ||||
| Increase driven by higher Vivint Smart Home operations costs | 7 | ||||
|
Increase in operations and maintenance expense
|
$ | 64 | |||
Other Cost of Operations
Other cost of operations is comprised of the following:
| (In millions) | Texas | East | West/Other | Vivint Smart Home | Total | ||||||||||||||||||||||||
| Three months ended September 30, 2026 | $ | 75 | $ | 51 | $ | 1 | $ | 2 | $ | 129 | |||||||||||||||||||
| Three months ended September 30, 2025 | 67 | 34 | - | 1 | 102 | ||||||||||||||||||||||||
Other cost of operations for the three months ended September 30, 2026 increased by $27 million, when compared to the same period in 2025, due to the following:
| (In millions) | |||||
| Increase due to the acquisition of the LSP Portfolio in January 2026 | $ | 13 | |||
| Increase in gross receipts taxes due to higher revenues in Texas and in the East | 11 | ||||
| Other | 3 | ||||
|
Increase in other cost of operations
|
$ | 27 | |||
Depreciation and Amortization
Depreciation and amortization are comprised of the following:
| (In millions) | Texas | East | West/Other | Vivint Smart Home | Corporate | Total | |||||||||||||||||||||||||||||
| Three months ended September 30, 2026 | $ | 133 | $ | 125 | $ | 7 | $ | 231 | $ | 14 | $ | 510 | |||||||||||||||||||||||
| Three months ended September 30, 2025 | 95 | 37 | 6 | 211 | 11 | 360 | |||||||||||||||||||||||||||||
Depreciation and amortization increased by $150 million for the three months ended September 30, 2026, compared to the same period in 2025, due to the following:
| (In millions) | |||||
| Increase due to the acquisition of the LSP Portfolio in January 2026 | $ | 111 | |||
|
Increase in amortization of capitalized contract costs primarily in the Vivint Smart Home segment
|
50 | ||||
|
Decrease in amortization driven by the expected roll off of the acquired Vivint Smart Home intangibles
|
(25) | ||||
| Other | 14 | ||||
|
Increase in depreciation and amortization
|
$ | 150 | |||
Selling, General and Administrative Costs
Selling, general and administrative costs are comprised of the following:
| (In millions) | Texas | East | West/Other | Vivint Smart Home | Corporate/Elimination | Total | |||||||||||||||||||||||||||||
| Three months ended September 30, 2026 | $ | 262 | $ | 156 | $ | 29 | $ | 165 | $ | 7 | $ | 619 | |||||||||||||||||||||||
| Three months ended September 30, 2025 | 261 | 151 | 36 | 156 | 8 | 612 | |||||||||||||||||||||||||||||
Selling, general and administrative costs increased by $7 million for the three months ended September 30, 2026, compared to the same period in 2025, due to the following:
| (In millions) | |||||
| Increase in broker fee and commissions expenses | $ | 20 | |||
| Increase in provision for credit losses | 18 | ||||
| Increase in technology expenses | 8 | ||||
| Increase due to the acquisition of the LSP Portfolio in January 2026 | 7 | ||||
| Decrease in personnel costs and equity linked compensation | (54) | ||||
| Other | 8 | ||||
|
Increase in selling, general and administrative costs
|
$ | 7 | |||
Acquisition-Related Transaction and Integration Costs
Acquisition-related transaction and integration costs of $16 million and $8 million for the three months ended September 30, 2026 and 2025, respectively, include:
| Three months ended September 30, | |||||||||||
| (In millions) | 2026 | 2025 | |||||||||
| LSP Portfolio acquisition costs | $ | 2 | $ | 2 | |||||||
| LSP Portfolio integration costs | 12 | - | |||||||||
| Other acquisition and integration costs, primarily related to Vivint Smart Home | 2 | 6 | |||||||||
|
Acquisition-related transaction and integration costs
|
$ | 16 | $ | 8 | |||||||
Interest Expense
Interest expense increased by $115 million for the three months ended September 30, 2026, compared to the same period in 2025. The incremental interest expense is primarily attributable to the LSP Portfolio acquisition, including the borrowing to finance the acquisition and the assumption of Lightning debt. For further discussion, see Note 4, Acquisitions and Dispositions and Note 7, Long-term Debt and Finance Leases.
Income Tax Expense
For the three months ended September 30, 2026, income tax expense of $218 million was recorded on pre-tax income of $779 million. For the same period in 2025, an income tax expense of $86 million was recorded on pre-tax income of $238 million. The effective tax rates were 28.0% and 36.1% for the three months ended September 30, 2026 and 2025, respectively.
For the three months ended September 30, 2026 and 2025, the effective tax rate was higher than the statutory rate of 21%, primarily due to the state tax expense.
Management's discussion of the results of operations for the nine months ended September 30, 2026 and 2025
Electricity Prices
The following table summarizes average on peak power prices for each of the major markets in which NRG operates for the nine months ended September 30, 2026 and 2025:
| Average on Peak Power Price ($/MWh) | |||||||||||||||||
| Nine months ended September 30, | |||||||||||||||||
| Region | 2026 | 2025 | Change % | ||||||||||||||
| Texas | |||||||||||||||||
|
ERCOT - Houston (a)
|
$ | 35.24 | $ | 38.79 | (9) | % | |||||||||||
|
ERCOT - North(a)
|
33.17 | 36.73 | (10) | % | |||||||||||||
| East | |||||||||||||||||
|
NY J/NYC(b)
|
$ | 85.96 | $ | 76.07 | 13 | % | |||||||||||
|
NEPOOL(b)
|
79.43 | 72.48 | 10 | % | |||||||||||||
|
COMED (PJM)(b)
|
56.67 | 46.17 | 23 | % | |||||||||||||
|
PJM - West Hub(b)
|
89.42 | 58.13 | 54 | % | |||||||||||||
|
PJM - APS(b)
|
84.56 | 54.73 | 55 | % | |||||||||||||
|
PJM - DOMINION(b)
|
106.21 | 73.23 | 45 | % | |||||||||||||
| West | |||||||||||||||||
|
MISO - Louisiana Hub(b)
|
$ | 45.66 | $ | 45.49 | - | % | |||||||||||
|
CAISO - SP15(b)
|
22.92 | 26.55 | (14) | % | |||||||||||||
(a) Average on peak power prices based on real time settlement prices as published by the respective ISOs
(b) Average on peak power prices based on day ahead settlement prices as published by the respective ISOs
Natural Gas Prices
The following table summarizes the average Henry Hub natural gas price for the nine months ended September 30, 2026 and 2025:
|
Nine months ended September 30,
|
|||||||||||||||||
| 2026 | 2025 | Change % | |||||||||||||||
|
($/MMBtu)
|
$ | 3.63 | $ | 3.39 | 7 | % | |||||||||||
Gross Margin
The Company calculates gross margin in order to evaluate operating performance as revenues less cost of fuel, purchased energy and other costs of sales, mark-to-market for economic hedging activities, contract and emissions credit amortization and depreciation and amortization.
Economic Gross Margin
In addition to gross margin, the Company evaluates its operating performance using the measure of economic gross margin, which is not a GAAP measure and may not be comparable to other companies' presentations or deemed more useful than the GAAP information provided elsewhere in this report. Economic gross margin should be viewed as a supplement to and not a substitute for the Company's presentation of gross margin, which is the most directly comparable GAAP measure. Economic gross margin is not intended to represent gross margin. The Company believes that economic gross margin is useful to investors as it is a key operational measure reviewed by the Company's management. Economic gross margin is defined as the sum of energy revenue, capacity revenue, retail revenue and other revenue, less cost of fuel, purchased energy and other cost of sales. Economic gross margin does not include mark-to-market gains or losses on economic hedging activities, contract and emissions credit amortization, depreciation and amortization, operations and maintenance, or other cost of operations.
The following tables present the composition and reconciliation of gross margin and economic gross margin for the nine months ended September 30, 2026 and 2025:
| Nine months ended September 30, 2026 | |||||||||||||||||||||||||||||||||||
|
($ In millions)
|
Texas(a)
|
East(a)
|
West/Other
|
Vivint Smart Home | Corporate/Eliminations | Total | |||||||||||||||||||||||||||||
| Retail revenue | $ | 8,735 | $ | 11,730 | $ | 2,165 | $ | 1,774 | $ | (25) | $ | 24,379 | |||||||||||||||||||||||
| Energy revenue | 22 | 1,508 | - | - | - | 1,530 | |||||||||||||||||||||||||||||
| Capacity revenue | - | 1,016 | 26 | - | (26) | 1,016 | |||||||||||||||||||||||||||||
| Mark-to-market for economic hedging activities | - | (32) | - | - | 6 | (26) | |||||||||||||||||||||||||||||
| Contract amortization | - | 30 | - | - | - | 30 | |||||||||||||||||||||||||||||
|
Other revenue(b)
|
111 | 156 | 9 | - | (2) | 274 | |||||||||||||||||||||||||||||
| Total revenue | 8,868 | 14,408 | 2,200 | 1,774 | (47) | 27,203 | |||||||||||||||||||||||||||||
| Cost of fuel | (774) | (578) | (1) | - | - | (1,353) | |||||||||||||||||||||||||||||
|
Purchased energy and other cost of sales(c)(d)(e)
|
(5,007) | (11,431) | (1,841) | (172) | 27 | (18,424) | |||||||||||||||||||||||||||||
| Mark-to-market for economic hedging activities | (282) | 153 | 90 | - | (6) | (45) | |||||||||||||||||||||||||||||
| Contract and emissions credit amortization | (9) | (29) | (5) | - | - | (43) | |||||||||||||||||||||||||||||
| Depreciation and amortization | (364) | (361) | (22) | (647) | (42) | (1,436) | |||||||||||||||||||||||||||||
| Gross margin | $ | 2,432 | $ | 2,162 | $ | 421 | $ | 955 | $ | (68) | $ | 5,902 | |||||||||||||||||||||||
| Less: Mark-to-market for economic hedging activities, net | (282) | 121 | 90 | - | - | (71) | |||||||||||||||||||||||||||||
| Less: Contract and emissions credit amortization, net | (9) | 1 | (5) | - | - | (13) | |||||||||||||||||||||||||||||
| Less: Depreciation and amortization | (364) | (361) | (22) | (647) | (42) | (1,436) | |||||||||||||||||||||||||||||
| Economic gross margin | $ | 3,087 | $ | 2,401 | $ | 358 | $ | 1,602 | $ | (26) | $ | 7,422 | |||||||||||||||||||||||
| (a) Includes results of operations following the acquisition date of the LSP Portfolio of January 30, 2026 | |||||||||||||||||||||||||||||||||||
| (b) Includes trading gains and losses and ancillary revenues | |||||||||||||||||||||||||||||||||||
|
(c) Includes capacity and emissions credits
|
|||||||||||||||||||||||||||||||||||
|
(d) Includes $2.8 billion, $145 million and $729 million of TDSP expense in Texas, East, and West/Other, respectively
|
|||||||||||||||||||||||||||||||||||
|
(e) Excludes depreciation and amortization shown separately
|
|||||||||||||||||||||||||||||||||||
| Business Metrics | Texas | East |
West/Other
|
Vivint Smart Home | Corporate/Eliminations | Total | |||||||||||||||||||||||||||||
| Retail sales | |||||||||||||||||||||||||||||||||||
| Home electricity sales volume (GWh) | 30,302 | 12,300 | 1,956 | - | - | 44,558 | |||||||||||||||||||||||||||||
| Business electricity sales volume (GWh) | 30,909 | 35,502 | 9,470 | - | - | 75,881 | |||||||||||||||||||||||||||||
| Home natural gas sales volume (MDth) | - | 30,643 | 48,604 | - | - | 79,247 | |||||||||||||||||||||||||||||
| Business natural gas sales volume (MDth) | - | 1,267,909 | 143,174 | - | - | 1,411,083 | |||||||||||||||||||||||||||||
|
Average retail Home customer count (in thousands)(a)
|
2,828 | 2,155 | 643 | - | - | 5,626 | |||||||||||||||||||||||||||||
|
Ending retail Home customer count (in thousands)(a)
|
2,776 | 2,109 | 635 | - | - | 5,520 | |||||||||||||||||||||||||||||
|
Average Vivint Smart Home customer count (in thousands)(b)
|
- | - | - | 2,475 | - | 2,475 | |||||||||||||||||||||||||||||
|
Ending Vivint Smart Home customer count (in thousands)(b)(c)
|
- | - | - | 2,593 | - | 2,593 | |||||||||||||||||||||||||||||
| Power generation | |||||||||||||||||||||||||||||||||||
|
GWh sold(d)
|
25,561 | 19,021 | 2 | - | - | 44,584 | |||||||||||||||||||||||||||||
|
GWh generated
|
|||||||||||||||||||||||||||||||||||
| Coal | 13,827 | 2,923 | - | - | - | 16,750 | |||||||||||||||||||||||||||||
| Gas | 11,734 | 14,835 | - | - | - | 26,569 | |||||||||||||||||||||||||||||
| Oil | - | 34 | - | - | - | 34 | |||||||||||||||||||||||||||||
| Renewables | - | - | 2 | - | - | 2 | |||||||||||||||||||||||||||||
| Total | 25,561 | 17,792 | 2 | - | - | 43,355 | |||||||||||||||||||||||||||||
| (a) Home customer count includes recurring residential customers and community choice | |||||||||||||||||||||||||||||||||||
| (b) Vivint Smart Home includes customers that also purchase other NRG products such as electricity | |||||||||||||||||||||||||||||||||||
| (c) Vivint Smart Home includes 67 thousand Home Protection (non-Vivint) customers | |||||||||||||||||||||||||||||||||||
| (d) Includes GWh sold from owned and tolled generation, excludes equity investments. Cottonwood lease ended in May 2025 | |||||||||||||||||||||||||||||||||||
| Nine months ended September 30, 2025 | |||||||||||||||||||||||||||||||||||
|
($ In millions)
|
Texas | East |
West/Other
|
Vivint Smart Home | Corporate/Eliminations | Total | |||||||||||||||||||||||||||||
| Retail revenue | $ | 8,466 | $ | 9,724 | $ | 2,255 | $ | 1,585 | $ | (13) | $ | 22,017 | |||||||||||||||||||||||
| Energy revenue | 38 | 354 | 101 | - | (1) | 492 | |||||||||||||||||||||||||||||
| Capacity revenue | - | 182 | 14 | - | (1) | 195 | |||||||||||||||||||||||||||||
| Mark-to-market for economic hedging activities | - | 12 | 6 | - | - | 18 | |||||||||||||||||||||||||||||
| Contract amortization | - | (4) | - | - | - | (4) | |||||||||||||||||||||||||||||
|
Other revenue(a)
|
156 | 77 | 18 | - | (9) | 242 | |||||||||||||||||||||||||||||
| Total revenue | 8,660 | 10,345 | 2,394 | 1,585 | (24) | 22,960 | |||||||||||||||||||||||||||||
| Cost of fuel | (652) | (203) | (73) | - | - | (928) | |||||||||||||||||||||||||||||
|
Purchased energy and other cost of sales(b)(c)(d)
|
(4,941) | (8,636) | (1,978) | (149) | 6 | (15,698) | |||||||||||||||||||||||||||||
| Mark-to-market for economic hedging activities | (375) | (46) | 75 | - | - | (346) | |||||||||||||||||||||||||||||
| Contract and emissions credit amortization | (11) | (27) | (5) | - | - | (43) | |||||||||||||||||||||||||||||
| Depreciation and amortization | (271) | (110) | (24) | $ | (592) | (33) | (1,030) | ||||||||||||||||||||||||||||
| Gross margin | $ | 2,410 | $ | 1,323 | $ | 389 | $ | 844 | $ | (51) | $ | 4,915 | |||||||||||||||||||||||
| Less: Mark-to-market for economic hedging activities, net | (375) | (34) | 81 | - | - | (328) | |||||||||||||||||||||||||||||
| Less: Contract and emissions credit amortization, net | (11) | (31) | (5) | - | - | (47) | |||||||||||||||||||||||||||||
| Less: Depreciation and amortization | (271) | (110) | (24) | (592) | (33) | (1,030) | |||||||||||||||||||||||||||||
| Economic gross margin | $ | 3,067 | $ | 1,498 | $ | 337 | $ | 1,436 | $ | (18) | $ | 6,320 | |||||||||||||||||||||||
| (a) Includes trading gains and losses and ancillary revenues | |||||||||||||||||||||||||||||||||||
|
(b) Includes capacity and emissions credits
|
|||||||||||||||||||||||||||||||||||
|
(c) Includes $2.6 billion, $186 million and $817 million of TDSP expense in Texas, East and West/Other, respectively
|
|||||||||||||||||||||||||||||||||||
|
(d) Excludes depreciation and amortization shown separately
|
|||||||||||||||||||||||||||||||||||
| Business Metrics | Texas | East |
West/Other
|
Vivint Smart Home | Corporate/Eliminations | Total | |||||||||||||||||||||||||||||
| Retail sales | |||||||||||||||||||||||||||||||||||
| Home electricity sales volume (GWh) | 31,021 | 11,775 | 1,844 | - | - | 44,640 | |||||||||||||||||||||||||||||
| Business electricity sales volume (GWh) | 30,055 | 34,627 | 9,415 | - | - | 74,097 | |||||||||||||||||||||||||||||
| Home natural gas sales volume (MDth) | - | 35,557 | 48,109 | - | - | 83,666 | |||||||||||||||||||||||||||||
| Business natural gas sales volume (MDth) | - | 1,107,780 | 132,099 | - | - | 1,239,879 | |||||||||||||||||||||||||||||
|
Average retail Home customer count (in thousands)(a)
|
2,911 | 2,172 | 651 | - | - | 5,734 | |||||||||||||||||||||||||||||
|
Ending retail Home customer count (in thousands)(a)
|
2,844 | 2,115 | 651 | - | - | 5,610 | |||||||||||||||||||||||||||||
|
Average Vivint Smart Home customer count (in thousands)(b)
|
- | - | - | 2,296 | - | 2,296 | |||||||||||||||||||||||||||||
|
Ending Vivint Smart Home customer count (in thousands)(b)(c)
|
- | - | - | 2,414 | - | 2,414 | |||||||||||||||||||||||||||||
| Power generation | |||||||||||||||||||||||||||||||||||
|
GWh sold(d)
|
21,880 | 4,804 | 2,117 | - | - | 28,801 | |||||||||||||||||||||||||||||
| GWh generated | |||||||||||||||||||||||||||||||||||
| Coal | 16,302 | 2,945 | - | - | - | 19,247 | |||||||||||||||||||||||||||||
| Gas | 5,578 | 5 | 2,114 | - | - | 7,697 | |||||||||||||||||||||||||||||
| Oil | - | 15 | - | - | - | 15 | |||||||||||||||||||||||||||||
| Renewables | - | - | 3 | - | - | 3 | |||||||||||||||||||||||||||||
| Total | 21,880 | 2,965 | 2,117 | - | - | 26,962 | |||||||||||||||||||||||||||||
| (a) Home customer count includes recurring residential customers and community choice | |||||||||||||||||||||||||||||||||||
| (b) Vivint Smart Home includes customers that also purchase other NRG products such as electricity | |||||||||||||||||||||||||||||||||||
| (c) Vivint Smart Home includes 63 thousand Home Protection (non-Vivint) customers | |||||||||||||||||||||||||||||||||||
| (d) Includes GWh sold from owned, tolled and leased generation, excludes equity investments | |||||||||||||||||||||||||||||||||||
The following table represents the weather metrics for the nine months ended September 30, 2026 and 2025:
| Nine months ended September 30, | |||||||||||||||||
| Weather Metrics | Texas |
East(b)
|
West/Other(c)
|
||||||||||||||
| 2026 | |||||||||||||||||
|
CDDs(a)
|
3,260 | 1,093 | 2,031 | ||||||||||||||
|
HDDs(a)
|
752 | 3,365 | 997 | ||||||||||||||
| 2025 | |||||||||||||||||
| CDDs | 2,913 | 1,053 | 1,780 | ||||||||||||||
| HDDs | 1,063 | 3,372 | 1,379 | ||||||||||||||
| 10-year average | |||||||||||||||||
| CDDs | 2,881 | 1,095 | 1,815 | ||||||||||||||
| HDDs | 973 | 3,251 | 1,300 | ||||||||||||||
(a) National Oceanic and Atmospheric Administration-Climate Prediction Center - A Cooling Degree Day, or CDD, represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. A Heating Degree Day, or HDD, represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period
(b) The East weather metrics are comprised of the average of the CDD and HDD regional results for the Northeast and East-Midwest regions
(c) The West/Other weather metrics are comprised of the average of the CDD and HDD regional results for the West-California and West-South Central regions
Gross Margin and Economic Gross Margin
Gross margin increased $987 million and economic gross margin increased $1.1 billion, both of which include intercompany sales, during the nine months ended September 30, 2026, compared to the same period in 2025.
The following tables describe the changes in gross margin and economic gross margin by segment:
Texas
| (In millions) | ||||||||
|
Higher gross margin due to the net effect of:
•an increase in net revenue rates of $147 million, primarily driven by changes in customer term, product and mix
•a 1%, or $27 million increase in cost to serve the retail load, driven by higher realized power prices associated with the Company's diversified supply strategy, including the assets acquired from the LSP Portfolio
|
$ | 120 | ||||||
| Lower gross margin due to a decrease in load driven by changes in customer mix and attrition, partially offset by an increase in load attributed to weather | (45) | |||||||
| Lower gross margin due to the impact of market optimization activities | (53) | |||||||
| Other | (2) | |||||||
|
Increase in economic gross margin
|
$ | 20 | ||||||
| Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges | 93 | |||||||
| Decrease in contract and emissions credit amortization | 2 | |||||||
| Increase in depreciation and amortization | (93) | |||||||
|
Increase in gross margin
|
$ | 22 | ||||||
East
| (In millions) | |||||
|
Higher electric gross margin due to the net effect of:
•an increase in net revenue rates of $582 million, primarily driven by changes in customer term, product and mix
•a 12%, or $460 million increase in cost to serve the retail load, driven by higher realized power prices associated with the Company's diversified supply strategy, including the assets acquired from the LSP Portfolio
|
$ | 122 | |||
| Higher electric gross margin from an increase in load due to a change in customer mix | 67 | ||||
| Lower natural gas gross margin due to higher supply costs of $767 million, including the impact of transportation and storage contract optimization, partially offset by higher net revenue rates of $656 million from changes in customer term, product, and mix | (111) | ||||
| Higher natural gas gross margin from an increase in load due to a change in customer mix | 55 | ||||
| Higher gross margin due to an increase in capacity from the acquisition of the LSP Portfolio and Midwest Generation | 657 | ||||
| Higher gross margin due to an increase in demand response activities, including the acquisition of CPower and higher PJM auction prices in 2026 | 117 | ||||
| Lower gross margin due to the deactivation of Indian River Unit 4 in February 2025 | (9) | ||||
| Other | 5 | ||||
|
Increase in economic gross margin
|
$ | 903 | |||
|
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges
|
155 | ||||
| Decrease in contract amortization | 32 | ||||
| Increase in depreciation and amortization | (251) | ||||
|
Increase in gross margin
|
$ | 839 | |||
West/Other
| (In millions) | |||||
| Higher electric gross margin due to lower supply costs of $89 million and changes in customer mix of $17 million, partially offset by lower net revenue rates of $103 million | $ | 3 | |||
| Higher gross margin at Cottonwood driven by the termination of the facility lease in May 2025 | 26 | ||||
| Other | (8) | ||||
|
Increase in economic gross margin
|
$ | 21 | |||
|
Increase in mark-to-market for economic hedges primarily due to net unrealized gains/losses on open positions related to economic hedges
|
9 | ||||
| Decrease in depreciation and amortization | 2 | ||||
|
Increase in gross margin
|
$ | 32 | |||
Vivint Smart Home
| (In millions) | |||||
| Higher gross margin primarily driven by growth in customers of $109 million and higher monthly revenue of $35 million | $ | 144 | |||
| Higher gross margin in home protection due to increased sales volume | 23 | ||||
| Other | (1) | ||||
| Increase in economic gross margin | $ | 166 | |||
| Increase in depreciation and amortization | (55) | ||||
| Increase in gross margin | $ | 111 | |||
Mark-to-Market for Economic Hedging Activities
Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges. Total net mark-to-market results increased by $257 million during the nine months ended September 30, 2026, compared to the same period in 2025.
The breakdown of gains and losses included in revenues and operating costs and expenses by segment was as follows:
| Nine months ended September 30, 2026 | |||||||||||||||||||||||||||||
| (In millions) | Texas | East | West/Other |
Eliminations
|
Total | ||||||||||||||||||||||||
|
Mark-to-market results in revenue
|
|||||||||||||||||||||||||||||
|
Reversal of previously recognized unrealized gains on settled positions related to economic hedges
|
$ | - | $ | (30) | $ | - | $ | 2 | $ | (28) | |||||||||||||||||||
|
Reversal of acquired gain positions related to economic hedges
|
- | (5) | - | - | (5) | ||||||||||||||||||||||||
|
Net unrealized gains on open positions related to economic hedges
|
- | 3 | - | 4 | 7 | ||||||||||||||||||||||||
|
Total mark-to-market losses in revenue
|
$ | - | $ | (32) | $ | - | $ | 6 | $ | (26) | |||||||||||||||||||
|
Mark-to-market results in operating costs and expenses
|
|||||||||||||||||||||||||||||
|
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges(a)
|
$ | (199) | $ | (3) | $ | 179 | $ | (2) | $ | (25) | |||||||||||||||||||
|
Reversal of acquired (gain)/loss positions related to economic hedges
|
(15) | 186 | - | - | 171 | ||||||||||||||||||||||||
|
Net unrealized losses on open positions related to economic hedges
|
(68) | (30) | (89) | (4) | (191) | ||||||||||||||||||||||||
|
Total mark-to-market (losses)/gains in operating costs and expenses
|
$ | (282) | $ | 153 | $ | 90 | $ | (6) | $ | (45) | |||||||||||||||||||
(a)Includes $(151) million, within the Texas segment, related to derivative contracts that were elected as NPNS on October 1, 2024 and are no longer valued at fair value on a recurring basis
| Nine months ended September 30, 2025 | |||||||||||||||||||||||||||||
| (In millions) | Texas | East | West/Other |
Eliminations
|
Total | ||||||||||||||||||||||||
|
Mark-to-market results in revenue
|
|||||||||||||||||||||||||||||
|
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges
|
$ | - | $ | (7) | $ | 6 | $ | - | $ | (1) | |||||||||||||||||||
|
Net unrealized gains on open positions related to economic hedges
|
- | 19 | - | - | 19 | ||||||||||||||||||||||||
|
Total mark-to-market gains in revenue
|
$ | - | $ | 12 | $ | 6 | $ | - | $ | 18 | |||||||||||||||||||
|
Mark-to-market results in operating costs and expenses
|
|||||||||||||||||||||||||||||
|
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges(a)
|
$ | (498) | $ | (96) | $ | 143 | $ | - | $ | (451) | |||||||||||||||||||
|
Reversal of acquired loss/(gain) positions related to economic hedges
|
23 | (2) | - | - | 21 | ||||||||||||||||||||||||
|
Net unrealized gains/(losses) on open positions related to economic hedges
|
100 | 52 | (68) | - | 84 | ||||||||||||||||||||||||
|
Total mark-to-market (losses)/gains in operating costs and expenses
|
$ | (375) | $ | (46) | $ | 75 | $ | - | $ | (346) | |||||||||||||||||||
(a)Includes $(319) million, within the Texas segment, related to derivative contracts that were elected as NPNS on October 1, 2024 and are no longer valued at fair value on a recurring basis
Mark-to-market results consist of unrealized gains and losses on contracts that are not yet settled. The settlement of these transactions is reflected in the same revenue or cost caption as the items being hedged.
For the nine months ended September 30, 2026, the $26 million loss in revenues from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period. The $45 million loss in operating costs and expenses from economic hedge positions was driven primarily by a decrease in the value of open positions as a result of decreases in natural gas prices and Alberta power prices as well as the reversal of previously recognized unrealized gains on contracts that settled during the period, largely offset by the reversal of acquired loss positions related to economic hedges.
For the nine months ended September 30, 2025, the $18 million gain in revenues from economic hedge positions was primarily driven by an increase in the value of open positions as a result of decreases in natural gas prices. The $346 million loss in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period, partially offset by an increase in the value of open positions in Texas as a result of increases in ERCOT power prices.
In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the nine months ended September 30, 2026 and 2025. The realized and unrealized financial and physical trading results are included in revenue. The Company's trading activities are subject to limits based on the Company's Risk Management Policy.
| Nine months ended September 30, | |||||||||||
| (In millions) | 2026 | 2025 | |||||||||
| Trading (losses)/gains | |||||||||||
| Realized | $ | (9) | $ | 26 | |||||||
| Unrealized | (32) | 7 | |||||||||
| Total trading (losses)/gains | $ | (41) | $ | 33 | |||||||
Operations and Maintenance Expense
Operations and maintenance expense are comprised of the following:
| (In millions) |
Texas(a)
|
East(a)
|
West/Other
|
Vivint Smart Home | Corporate/Eliminations | Total | |||||||||||||||||||||||||||||
| Nine months ended September 30, 2026 | $ | 673 | $ | 428 | $ | 33 | $ | 222 | $ | (1) | $ | 1,355 | |||||||||||||||||||||||
| Nine months ended September 30, 2025 | 534 | 303 | 87 | 189 | 5 | 1,118 | |||||||||||||||||||||||||||||
(a) Includes results of operations following the acquisition date of the LSP Portfolio of January 30, 2026
Operations and maintenance expense increased by $237 million for the nine months ended September 30, 2026, compared to the same period in 2025, due to the following:
| (In millions) | |||||
| Increase primarily due to the acquisition of the LSP Portfolio in January 2026 | $ | 254 | |||
| Increase due to the final property insurance claim for the extended outage at W.A. Parish received in 2025 | 100 | ||||
| Increase driven by higher Vivint Smart Home operations costs | 24 | ||||
| Decrease due to timing of planned major maintenance expenditures at Powerton and in Texas | (49) | ||||
| Decrease driven by the expiration of the Cottonwood facility lease in May 2025 | (48) | ||||
| Decrease in reserves primarily for legal matters in the East | (33) | ||||
| Decrease driven by lower retail operations costs | (6) | ||||
| Other | (5) | ||||
|
Increase in operations and maintenance expense
|
$ | 237 | |||
Other Cost of Operations
Other Cost of operations are comprised of the following:
| (In millions) |
Texas(a)
|
East(a)
|
West/Other | Vivint Smart Home | Total | ||||||||||||||||||||||||
| Nine months ended September 30, 2026 | $ | 190 | $ | 149 | $ | 3 | $ | 4 | $ | 346 | |||||||||||||||||||
| Nine months ended September 30, 2025 | 192 | 97 | 6 | 3 | 298 | ||||||||||||||||||||||||
(a) Includes results of operations following the acquisition date of the LSP Portfolio of January 30, 2026
Other cost of operations increased by $48 million for the nine months ended September 30, 2026, compared to the same period in 2025, due to the following:
| (In millions) | |||||
| Increase primarily due to the acquisition of the LSP Portfolio in January 2026 | $ | 32 | |||
| Increase in gross receipts taxes due to higher revenue in the East | 19 | ||||
| Other | (3) | ||||
|
Increase in other cost of operations
|
$ | 48 | |||
Depreciation and Amortization
Depreciation and amortization expenses are comprised of the following:
| (In millions) |
Texas(a)
|
East(a)
|
West/Other | Vivint Smart Home | Corporate | Total | |||||||||||||||||||||||||||||
| Nine months ended September 30, 2026 | $ | 364 | $ | 361 | $ | 22 | $ | 647 | $ | 42 | $ | 1,436 | |||||||||||||||||||||||
| Nine months ended September 30, 2025 | 271 | 110 | 24 | 592 | 33 | 1,030 | |||||||||||||||||||||||||||||
(a) Includes results of operations following the acquisition date of the LSP Portfolio of January 30, 2026
Depreciation and amortization increased by $406 million for the nine months ended September 30, 2026, compared to the same period in 2025, due to the following:
| (In millions) | |||||
| Increase due to the acquisition of the LSP Portfolio in January 2026 | $ | 310 | |||
|
Increase in amortization of capitalized contract costs primarily in the Vivint Smart Home segment
|
148 | ||||
|
Decrease in amortization driven by the expected roll off of the acquired Vivint Smart Home intangibles
|
(75) | ||||
| Other | 23 | ||||
|
Increase in depreciation and amortization
|
$ | 406 | |||
Selling, General and Administrative Costs
Selling, general and administrative costs comprised of the following:
| (In millions) |
Texas(a)
|
East(a)
|
West/Other | Vivint Smart Home | Corporate/Eliminations | Total | |||||||||||||||||||||||||||||
| Nine months ended September 30, 2026 | $ | 682 | $ | 491 | $ | 87 | $ | 505 | $ | 9 | $ | 1,774 | |||||||||||||||||||||||
| Nine months ended September 30, 2025 | 677 | 445 | 103 | 645 | 15 | 1,885 | |||||||||||||||||||||||||||||
(a) Includes results of operations following the acquisition date of the LSP Portfolio of January 30, 2026
Selling, general and administrative costs decreased by $111 million for the nine months ended September 30, 2026, compared to the same period in 2025, due to the following:
| (In millions) | |||||
| Decrease in reserves primarily for legal matters settled in 2025 | $ | (183) | |||
| Decrease in personnel costs and equity linked compensation | (42) | ||||
| Increase in broker fee and commissions expenses | 40 | ||||
| Increase due to the acquisition of the LSP Portfolio in January 2026 | 18 | ||||
| Increase in technology expenses | 18 | ||||
| Increase in marketing and media expenses | 17 | ||||
| Increase in provision for credit losses | 9 | ||||
| Other | 12 | ||||
|
Decrease in selling, general and administrative costs
|
$ | (111) | |||
Acquisition-Related Transaction and Integration Costs
Acquisition-related transaction and integration costs of $77 million and $59 million for the nine months ended September 30, 2026 and 2025, respectively, include:
|
Nine months ended September 30,
|
|||||||||||
| (In millions) | 2026 | 2025 | |||||||||
| LSP Portfolio acquisition costs | $ | 43 | $ | 25 | |||||||
| LSP Portfolio integration costs | 26 | - | |||||||||
| Other acquisition and integration costs, primarily related to Vivint Smart Home | 8 | 34 | |||||||||
|
Acquisition-related transaction and integration costs
|
$ | 77 | $ | 59 | |||||||
Interest Expense
Interest expense increased by $399 million for the nine months ended September 30, 2026, compared to the same period in 2025. The incremental interest expense is primarily attributable to the LSP Portfolio acquisition, including the borrowing to finance the acquisition, the assumption of Lightning debt, and the refinancing activity occurred during the nine months ended September 30, 2026. For further discussion, see Note 4, Acquisitions and Dispositions and Note 7, Long-term Debt and Finance Leases.
Income Tax Expense
For the nine months ended September 30, 2026, an income tax expense of $333 million was recorded on a pre-tax income of $1.5 billion. For the same period in 2025, income tax expense of $272 million was recorded on pre-tax income of $1.1 billion. The effective tax rates were 21.8% and 25.4% for the nine months ended September 30, 2026 and 2025, respectively.
For the nine months ended September 30, 2026, NRG's effective tax rate was higher than the statutory rate of 21%, primarily due to the state tax expense, partially offset by favorable permanent differences related to stock-based compensation and the remeasurement of state net operating losses as a result of the acquisition of the LSP Portfolio. For the same period in 2025, NRG's effective tax rate was higher than the statutory rate of 21%, primarily due to the state tax expense, partially offset with favorable permanent differences.
Liquidity and Capital Resources
Liquidity Position
As of September 30, 2026 and December 31, 2025, NRG's total liquidity, excluding funds deposited by counterparties, of approximately $6.0 billion and $9.6 billion, respectively, was comprised of the following:
| (In millions) | September 30, 2026 | December 31, 2025 | |||||||||
| Cash and cash equivalents | $ | 148 | $ | 4,708 | |||||||
| Restricted cash - operating | 15 | 12 | |||||||||
|
Restricted cash - reserves(a)
|
14 | 18 | |||||||||
| Total | 177 | 4,738 | |||||||||
|
Total availability under Revolving Credit Facility and collective collateral facilities(b)
|
5,850 | 4,890 | |||||||||
| Total liquidity, excluding funds deposited by counterparties | $ | 6,027 | $ | 9,628 | |||||||
(a) Includes reserves primarily for capital expenditures
(b) Total capacity of Revolving Credit Facility and collective collateral facilities was $9.6 billion and $7.7 billion as of September 30, 2026 and December 31, 2025, respectively
As of September 30, 2026, total liquidity, excluding funds deposited by counterparties, decreased $3.6 billion since December 31, 2025, primarily driven by funding of the acquisition of generation assets and CPower from LS Power. Changes in cash and cash equivalent balances are further discussed under the heading Cash Flow Discussion. Cash and cash equivalents at September 30, 2026 were predominantly held in bank deposits.
Management believes that the Company's liquidity position and cash flows from operations will be adequate to finance operating and maintenance capital expenditures, to fund dividends, and to fund other liquidity commitments in the short and long-term. Management continues to regularly monitor the Company's ability to finance the needs of its operating, financing and investing activity within the dictates of prudent balance sheet management.
Liquidity
The principal sources of liquidity for NRG's operating and capital expenditures are expected to be derived from cash on hand, cash flows from operations and financing arrangements. As described in Note 7, Long-term Debt and Finance Leases, to this Form 10-Q, the Company's financing arrangements consist mainly of the Senior Notes, Senior Secured First Lien Notes, Senior Credit Facility, Lightning Term Loan, Lightning Revolving Facility, Receivables Facility, tax-exempt bonds, and TEF Loans. The Company also issues letters of credit through bilateral letter of credit facilities and the pre-capitalized trust securities facility.
The Company's requirements for liquidity and capital resources, other than for operating its facilities, can generally be categorized by the following: (i) market operations activities; (ii) debt service obligations, as described in Note 7, Long-term Debt and Finance Leases; (iii) capital expenditures, including maintenance, environmental, and investments and integration; and (iv) allocations in connection with acquisition opportunities, debt repayments, share repurchases and dividend payments to stockholders, as described in Note 9, Changes in Capital Structure.
Anticipated Sale of 4.9 GW of Generation Assets
On November 9, 2026, the Company entered into a definitive agreement with LS Power to sell six natural-gas fired generation assets totaling 4.9 GW from the Texas and East segments for cash proceeds of $4 billion, subject to working capital and other closing adjustments. The transaction is targeted to close in the second quarter of 2027, and is subject to customary closing conditions and regulatory approvals, including HSR, FERC, and NYSPSC. The sale retains the entire PJM portfolio and CPower acquired by the Company in January 2026. The Company plans to use the remaining proceeds, after debt reduction of $2 billion, for $1 billion of share repurchases and $1 billion for either potential contracted growth investments or additional debt reduction. For further discussion, see Note 4, Acquisitions and Dispositions.
Acquisition of LSP Portfolio
On January 30, 2026, NRG completed the acquisition of the LSP Portfolio from LS Power. The consideration consisted of 24.25 million shares of NRG common stock and $6.4 billion in cash, plus working capital and certain other adjustments of $472 million. The Company funded the cash consideration using a portion of the net proceeds from the 5.750% 2034 Senior Notes, the 2036 Senior Notes, Senior Secured First Lien Notes, due 2030 and the Senior Secured First Lien Notes, due 2035 of $4.4 billion and proceeds of $2.5 billion from the Company's Revolving Credit Facility. For further discussion, see Note 4, Acquisitions and Dispositions.
Term Loan B Incurrence
On April 28, 2026, the Company and APX Group LLC, as borrowers, and certain of the Company's subsidiaries, as guarantors, entered into the Sixteenth Amendment to the Credit Agreement to establish new term loans in aggregate principal amount of $900 million. For further discussion, see Note 7, Long-term Debt and Finance Leases.
Issuance of Unsecured Notes and Secured Notes
On April 28, 2026, the Company issued $2.1 billion in aggregate principal amount of the New Unsecured Notes. The New Unsecured Notes are senior unsecured obligations of the Company and are guaranteed by its wholly-owned U.S. subsidiaries that guarantee the loans under the Senior Credit Facility. For further discussion, see Note 7, Long-term Debt and Finance Leases.
On April 28, 2026, the Company also issued $500 million aggregate principal amount of the New 2031 Notes. The New 2031 Notes are senior secured obligations of the Company and are guaranteed by its wholly-owned U.S. subsidiaries that guarantee the loans under the Senior Credit Facility. For further discussion, see Note 7, Long-term Debt and Finance Leases.
Bilateral Letter of Credit Facilities
In January and February 2026, the Company and certain of its subsidiaries, as guarantors, entered into amendments to its existing bilateral letter of credit facilities to increase the size of its bilateral credit facilities by $410 million and $90 million, respectively, totaling $1.35 billion of available capacity, to provide additional liquidity. As of September 30, 2026, $655 million was issued under these facilities. As of October 31, 2026, $644 million was issued under these facilities.
Credit Default Swap Facility
On July 21, 2026, the Company entered into a credit agreement, with commitments from lenders for up to $250 million of total available capacity, for the issuance of letters of credit to support normal business operations. Annual fees of 1.20% on the facility are paid quarterly in arrears and reflect the costs associated with the credit default swaps supporting the facility. As of September 30, 2026, there were $245 million in letters of credit issued under this facility. As of October 31, 2026, there were $250 million in letters of credit issued under this facility.
Revolving Credit Facility
As of September 30, 2026, $1.0 billion of borrowings were outstanding and there were $207 million in letters of credit issued under the Revolving Credit Facility. As of October 31, 2026, $400 million of borrowings were outstanding and there were $109 million in letters of credit issued under the Revolving Credit Facility.
Receivables Securitization Facilities
On June 18, 2026, NRG Receivables, an indirect wholly-owned subsidiary of the Company, amended its existing Receivables Facility to, among other things, extend the scheduled termination date to June 17, 2027. As of September 30, 2026, there were no outstanding borrowings and there were $1.1 billion in letters of credit issued under the Receivables Facility. As of October 31, 2026, $620 million of borrowings were outstanding and there were $1.1 billion in letters of credit issued under the Receivables Facility.
Lightning Notes and Lightning Tender Offer and Redemption
On the Acquisition Closing Date, Lightning remained the issuer of the Lightning 2032 Notes issued pursuant to the Lightning Indenture, by and among Lightning, Lightning's subsidiaries that are guarantors from time to time party thereto, and the Lightning Notes Trustee.
During the second quarter of 2026, Lightning completed the Tender Offer and Redemption. For further discussion, see Note 7, Long-term Debt and Finance Leases.
Lightning Credit Facility
On the Acquisition Closing Date, Lightning remained party to the Lightning Credit Agreement with Morgan Stanley Senior Funding, Inc. as administrative agent and collateral agent and various lenders and issuing banks from time to time party thereto. The Lightning Credit Agreement consists of the Lightning Term Loan and the Lightning Revolving Facility. As of September 30, 2026, there were no outstanding borrowings and there were $5 million in letters of credit issued under the Lightning Revolving Facility. For further discussion, see Note 7, Long-term Debt and Finance Leases.
Market Operations
The Company's market operations activities require a significant amount of liquidity and capital resources. These liquidity requirements are primarily driven by: (i) margin and collateral posted with counterparties; (ii) margin and collateral required to participate in physical markets and commodity exchanges; (iii) timing of disbursements and receipts (e.g., buying energy before receiving retail revenues); and (iv) initial collateral for large structured transactions. As of September 30, 2026, market operations had total cash collateral outstanding of $501 million and $2.7 billion outstanding in letters of credit to third parties primarily to support its market activities. As of September 30, 2026, total funds deposited by counterparties were $105 million in cash and $306 million of letters of credit.
Future liquidity requirements may change based on the Company's hedging activities and structures, fuel purchases, and future market conditions, including forward prices for energy and fuel and market volatility. In addition, liquidity requirements are dependent on the Company's credit ratings and general perception of its creditworthiness.
First Lien Structure
NRG has the capacity to grant first liens to certain counterparties on a substantial portion of the Company's assets, subject to various exclusions including NRG's assets that have project-level financing and the assets of certain non-guarantor subsidiaries, to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements. The first lien program does not limit the volume that can be hedged, or the value of underlying out-of-the-money positions. The first lien program also does not require NRG to post collateral above any threshold amount of exposure. The first lien structure is not subject to unwind or termination upon a ratings downgrade of a counterparty and has no stated maturity date.
As of September 30, 2026, counterparties' net exposure to NRG of approximately $8 million on out-of-the-money hedges was secured by the first lien structure.
Capital Expenditures
The following table summarizes the Company's capital expenditures for maintenance, environmental and investments and integration for the nine months ended September 30, 2026, and the estimated forecast for the remainder of the year.
| (In millions) | Maintenance | Environmental |
Investments and Integration
|
Total | |||||||||||||||||||
| Texas | $ | 160 | $ | 16 | $ | 852 | $ | 1,028 | |||||||||||||||
| East | 49 | - | 10 | 59 | |||||||||||||||||||
| West/Other | 2 | - | 3 | 5 | |||||||||||||||||||
| Vivint Smart Home | 18 | - | 4 | 22 | |||||||||||||||||||
| Corporate | 19 | - | 48 | 67 | |||||||||||||||||||
|
Total cash capital expenditures for the nine months ended September 30, 2026
|
$ | 248 | $ | 16 | $ | 917 | $ | 1,181 | |||||||||||||||
| Integration operating expenses and cost to achieve | - | - | 78 | 78 | |||||||||||||||||||
| Investments | - | - | 176 | 176 | |||||||||||||||||||
|
Total cash capital expenditures and investments for the nine months ended September 30, 2026
|
$ | 248 | $ | 16 | $ | 1,171 | $ | 1,435 | |||||||||||||||
|
Estimated cash capital expenditures and investments for the remainder of 2026
|
217 | - | 593 | 810 | |||||||||||||||||||
|
Estimated full year 2026 cash capital expenditures and investments
|
$ | 465 | $ | 16 | $ | 1,764 | $ | 2,245 | |||||||||||||||
Investments and Integration for the nine months ended September 30, 2026 include growth expenditures, integration, small book acquisitions and other investments.
Environmental Capital Expenditures Estimate
NRG estimates that environmental capital expenditures from 2026 through 2030 required to comply with environmental laws will be approximately $35 million, primarily driven by the cost of complying with ELG at the Company's coal units in Texas.
Share Repurchases
During the nine months ended September 30, 2026, the Company completed $963 million of share repurchases at an average price of $154.45 per share. Through October 31, 2026, an additional $14 million of share repurchases were executed at an average price of $99.62 per share. On November 6, 2026, in connection with its approval of the sale of 4.9 GW of generation assets to LS Power, the Board of Directors approved an additional $1.0 billion of share repurchases. See Note 9, Changes in Capital Structure for additional discussion.
Common Stock Dividends
During the first quarter of 2026, NRG increased the annual dividend to $1.90 from $1.76 per share. A quarterly dividend of $0.475 per share was paid on the Company's common stock during the three months ended September 30, 2026. On October 19, 2026, NRG declared a quarterly dividend on the Company's common stock of $0.475 per share, payable on November 16, 2026 to stockholders of record as of November 2, 2026. Beginning in the first quarter of 2027, NRG will increase the annual dividend by 8% to $2.05 per share. The Company targets an annual dividend growth rate of 7%-9% per share in subsequent years.
Series A Preferred Stock Dividends
During the quarters ended September 30, and March 31, 2026, the Company declared and paid a semi-annual 10.25% dividend of $51.25 per share on its outstanding Series A Preferred Stock, each totaling $33 million.
Obligations under Certain Guarantees
NRG and its subsidiaries enter into various contracts that include indemnifications and guarantee provisions as a routine part of the Company's business activities. For further discussion, see Note 26, Guarantees, to the Company's 2025 Form 10-K.
Obligations Arising Out of a Variable Interest in an Unconsolidated Entity
Variable interest in equity investments - NRG's investment in Ivanpah is a variable interest entity for which NRG is not the primary beneficiary. NRG's pro-rata share of non-recourse debt was approximately $462 million as of September 30, 2026. This indebtedness may restrict the ability of Ivanpah to issue dividends or distributions to NRG.
Contractual Obligations and Market Commitments
NRG has a variety of contractual obligations and other market commitments that represent prospective cash requirements in addition to the Company's capital expenditure programs, as disclosed in the Company's 2025 Form 10-K. See also Note 7, Long-term Debt and Finance Leases, and Note 14, Commitments and Contingencies, to this Form 10-Q for a discussion of new commitments and contingencies that also include contractual obligations and market commitments that occurred during the three and nine months ended September 30, 2026.
Cash Flow Discussion
The following table reflects the changes in cash flows for the nine months ended September 30, 2026 and 2025, respectively:
| Nine months ended September 30, | |||||||||||||||||
| (In millions) | 2026 | 2025 | Change | ||||||||||||||
| Cash provided by operating activities | $ | 2,045 | $ | 1,790 | $ | 255 | |||||||||||
| Cash used in investing activities | (8,191) | (1,340) | (6,851) | ||||||||||||||
| Cash provided by/(used in) financing activities | 1,430 | (540) | 1,970 | ||||||||||||||
Cash provided by operating activities
Changes to cash provided by operating activities were driven by:
| (In millions) | |||||
| Increase in Net Income adjusted for derivatives and other non-cash items | $ | 719 | |||
| Changes in Cash collateral in support of risk management activities due to change in commodity prices | (184) | ||||
| Decrease in working capital primarily due to lower gas and power volumes in Accounts payable partially offset by the timing of receipts | (114) | ||||
| Decrease in working capital related to Inventory primarily driven by an increase in materials | (101) | ||||
| Decrease in other working capital | (65) | ||||
| $ | 255 | ||||
Cash used in investing activities
Changes to cash used in investing activities were driven by:
| (In millions) | |||||
| Increase in cash paid for acquisitions primarily due to the LSP Portfolio in January 2026 | $ | (6,503) | |||
| Increase in capital expenditures | (332) | ||||
| Decrease due to proceeds from insurance recoveries for Property, plant and equipment, net in 2025 | (100) | ||||
| Increase due to higher sales of emissions allowances, net of purchases | 45 | ||||
| Increase in proceeds from sale of assets | 39 | ||||
| $ | (6,851) | ||||
Cash provided by/(used in) financing activities
Changes to cash provided by/(used in) financing activities were driven by:
| (In millions) | |||||
| Increase due to proceeds from issuance of long-term debt in 2026, net of deferred financing costs | $ | 2,349 | |||
| Decrease due to higher repayments of long-term debt | (1,295) | ||||
| Increase due to higher proceeds from credit facilities, including for the acquisition of the LSP Portfolio | 1,016 | ||||
| Increase due to payment for settlement of capped call options in 2025 | 292 | ||||
| Increase in net payments from settlement of acquired derivatives | (219) | ||||
| Decrease due to higher debt extinguishment costs in 2026 | (100) | ||||
| Increase in payments of dividends due to common stock | (43) | ||||
| Decrease due to higher payments for share repurchase activities in 2026 | (30) | ||||
| $ | 1,970 | ||||
NOLs, Deferred Tax Assets and Uncertain Tax Position Implications, under ASC 740
For the nine months ended September 30, 2026, the Company had domestic pre-tax book income of $1.5 billion and foreign pre-tax book income of $55 million. As of December 31, 2025, the Company had cumulative U.S. federal NOL carryforwards of $6.6 billion, of which $5.1 billion do not have an expiration date, and cumulative state NOL carryforwards of $6.1 billion for financial statement purposes. NRG also has cumulative foreign NOL carryforwards of $392 million, most of which do not have an expiration date. In addition to the above NOLs, NRG has a $58 million indefinite carryforward for interest deductions, as well as $288 million of tax credits, inclusive of $92 million CAMT credits to be utilized in future years. As a result of the Company's tax position, including the utilization of federal and state NOLs, and based on current forecasts, the Company anticipates net income tax payments of up to $90 million in 2026. NRG as an applicable corporation is subject to the CAMT, however, there is no impact on the Company's provision for income taxes from the CAMT for the nine months ended September 30, 2026.
As of September 30, 2026, the Company has $49 million of tax-effected uncertain federal, state, and foreign tax benefits, for which the Company has recorded a non-current tax liability of $55 million (inclusive of accrued interest) until final resolution is reached with the related taxing authority.
On December 31, 2021, the OECD released rules which set forth a common approach to a global minimum tax at 15% for multinational companies, which has been enacted into law by certain countries effective for 2024. The Company's preliminary analysis indicates that there is no material impact to the Company's financial statements from these rules.
The Company is no longer subject to U.S. federal income tax examinations for years prior to 2022. With few exceptions, state and Canadian income tax examinations are no longer open for years prior to 2015.
On July 4, 2025, OBBB was enacted into law. The OBBB includes changes to U.S. tax law applicable to NRG beginning in 2025, such as the permanent extension of certain expiring provisions of the TCJA, modifications to the international tax framework and the restoration of favorable tax treatment for certain business provisions. The impact of the OBBB on the Company's consolidated financial statements has been reflected in its current and deferred taxes, however, there is no material impact to the income tax expense/(benefit) for the periods presented.
Deferred tax assets and valuation allowance
Net deferred tax balance - As of September 30, 2026 and December 31, 2025, NRG recorded a net deferred tax asset, excluding valuation allowance, of $1.7 billion and $2.0 billion, respectively. The Company believes certain state net operating losses may not be realizable under the more-likely-than-not measurement and as such, a valuation allowance was recorded as of September 30, 2026 and December 31, 2025 as discussed below.
NOL Carryforwards - As of September 30, 2026, the Company had a tax-effected cumulative U.S. NOLs consisting of carryforwards for federal and state income tax purposes of $1.4 billion and $326 million, respectively. The Company estimates it will generate future taxable income to fully realize the net federal deferred tax asset before the expiration of certain carryforwards commences in 2030. In addition, NRG has tax-effected cumulative foreign NOL carryforwards of $103 million.
Valuation Allowance - As of September 30, 2026 and December 31, 2025, the Company's tax-effected valuation allowance was $145 million and $150 million, respectively consisting of state NOL carryforwards and foreign NOL carryforwards. The valuation allowance was recorded based on the assessment of cumulative and forecasted pre-tax book earnings and the future reversal of existing taxable temporary differences.
Guarantor Financial Information
As of September 30, 2026, the Company's outstanding registered senior notes consisted of $821 million of the 2028 Senior Notes as shown in Note 7, Long-term Debt and Finance Leases. These Senior Notes are guaranteed by certain of NRG's current and future 100% owned domestic subsidiaries, or guarantor subsidiaries (the "Guarantors"). See Exhibit 22.1 to this Form 10-Q for a listing of the Guarantors. These guarantees are both joint and several.
NRG conducts much of its business through and derives much of its income from its subsidiaries. Therefore, the Company's ability to make required payments with respect to its indebtedness and other obligations depends on the financial results and condition of its subsidiaries and NRG's ability to receive funds from its subsidiaries. There are no restrictions on the ability of any of the Guarantors to transfer funds to NRG. Other subsidiaries of the Company do not guarantee the registered debt securities of either NRG Energy, Inc. or the Guarantors (such subsidiaries are referred to as the "Non-Guarantors"). The Non-Guarantors include all of NRG's foreign subsidiaries and certain domestic subsidiaries.
The following tables present summarized financial information of NRG Energy, Inc. and the Guarantors in accordance with Rule 3-10 under the SEC's Regulation S-X. The financial information may not necessarily be indicative of the results of operations or financial position of NRG Energy, Inc. and the Guarantors in accordance with U.S. GAAP.
The following table presents the summarized statement of operations:
| (In millions) |
Nine months ended September 30, 2026
|
||||
|
Revenue(a)
|
$ | 23,449 | |||
|
Operating income(b)
|
1,541 | ||||
| Total other expense | (698) | ||||
| Income before income taxes | 843 | ||||
| Net income | 525 | ||||
(a)Intercompany transactions with Non-Guarantors of $10 million during the nine months ended September 30, 2026
(b)Intercompany transactions with Non-Guarantors including cost of operations of $(248) million and selling, general and administrative of $350 million during the nine months ended September 30, 2026
The following table presents the summarized balance sheet information:
| (In millions) | As of September 30, 2026 | ||||
|
Current assets(a)
|
$ | 6,481 | |||
| Property, plant and equipment, net | 5,310 | ||||
| Non-current assets | 23,573 | ||||
|
Current liabilities(b)
|
8,946 | ||||
| Non-current liabilities | 22,219 | ||||
(a)Includes intercompany receivables due from Non-Guarantors of $284 million as of September 30, 2026
(b)Includes intercompany payables due to Non-Guarantors of $109 million as of September 30, 2026
Fair Value of Derivative Instruments
NRG may enter into power purchase and sales contracts, fuel purchase contracts and other energy-related financial instruments to mitigate variability in earnings due to fluctuations in spot market prices and to hedge fuel requirements at power plants or retail load obligations. In order to mitigate interest rate risk associated with the issuance of the Company's debt, NRG enters into interest rate derivatives. In addition, in order to mitigate foreign exchange rate risk primarily associated with the purchase of U.S. dollar denominated natural gas for the Company's Canadian business, NRG enters into foreign exchange contract agreements.
Under Flex Pay, offered by Vivint Smart Home, customers pay for smart home products by obtaining financing from a third-party financing provider under the Consumer Financing Program. Vivint Smart Home pays certain fees to the financing providers and shares in credit losses depending on the credit quality of the customer.
NRG's trading activities are subject to limits in accordance with the Company's Risk Management Policy. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings.
The following tables disclose the activities that include both exchange and non-exchange traded contracts accounted for at fair value in accordance with ASC 820, Fair Value Measurements and Disclosures ("ASC 820"). Specifically, these tables disaggregate realized and unrealized changes in fair value; disaggregate estimated fair values as of September 30, 2026, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at September 30, 2026. For a full discussion of the Company's valuation methodology of its contracts, see Derivative Fair Value Measurements in Note 5, Fair Value of Financial Instruments.
| Derivative Activity Gains/(Losses) | (In millions) | ||||
|
Fair Value of Contracts as of December 31, 2025(a)
|
$ | 397 | |||
| Contracts realized or otherwise settled during the period | 183 | ||||
| LSP Portfolio contracts acquired during the period | (96) | ||||
| Other changes in fair value | (330) | ||||
|
Fair Value of Contracts as of September 30, 2026(a)
|
$ | 154 | |||
(a)As of December 31, 2025 and September 30, 2026, respectively, includes $484 million and $333 million of derivative contracts that were elected as NPNS on October 1, 2024 and are no longer valued at fair value on a recurring basis
| Fair Value of Contracts as of September 30, 2026 | |||||||||||||||||||||||||||||
| (In millions) | Maturity | ||||||||||||||||||||||||||||
|
Fair Value Hierarchy (Losses)/Gains(a)
|
1 Year or Less | Greater than 1 Year to 3 Years | Greater than 3 Years to 5 Years | Greater than 5 Years |
Total Fair Value |
||||||||||||||||||||||||
| Level 1 | $ | (177) | $ | (38) | $ | 4 | $ | 2 | $ | (209) | |||||||||||||||||||
| Level 2 | 149 | 225 | 11 | (3) | 382 | ||||||||||||||||||||||||
| Level 3 | (255) | (105) | (8) | 16 | (352) | ||||||||||||||||||||||||
| Total | $ | (283) | $ | 82 | $ | 7 | $ | 15 | $ | (179) | |||||||||||||||||||
(a)Excludes $333 million of derivative contracts that were elected as NPNS on October 1, 2024 and are no longer valued at fair value on a recurring basis
The Company has elected to disclose derivative assets and liabilities on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. Also, collateral received or posted on the Company's derivative assets or liabilities are recorded on a separate line item on the balance sheet. Consequently, the magnitude of the changes in individual current and non-current derivative assets or liabilities is higher than the underlying credit and market risk of the Company's portfolio. As discussed in Item 3, Quantitative and Qualitative Disclosures About Market Risk - Commodity Price Risk, to this Form 10-Q, NRG measures the sensitivity of the Company's portfolio to potential changes in market prices using VaR, a statistical model which attempts to predict risk of loss based on market price and volatility. NRG's Risk Management Policy places a limit on one-day holding period VaR, which limits the Company's net open position. As the Company's trade-by-trade derivative accounting results in a gross-up of the Company's derivative assets and liabilities, the net derivative asset and liability position is a better indicator of NRG's hedging activity. As of September 30, 2026, NRG's net derivative asset was $154 million, a decrease of $243 million as compared to December 31, 2025. This decrease was primarily driven by losses in fair value and the LSP Portfolio contracts acquired, partially offset by the roll-off of trades that settled during the period.
Based on a sensitivity analysis using simplified assumptions, the impact of a $0.50 per MMBtu increase in natural gas prices across the term of the derivative contracts would result in an increase of approximately $804 million in the net value of derivatives as of September 30, 2026. The impact of a $0.50 per MMBtu decrease in natural gas prices across the term of the derivative contracts would result in a decrease of approximately $805 million in the net value of derivatives as of September 30, 2026.
Critical Accounting Estimates
NRG's discussion and analysis of the financial condition and results of operations are based upon the condensed consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance as well as the use of estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities. The application of appropriate technical accounting rules and guidance involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges, and the fair value of certain assets and liabilities. These judgments, in and of themselves, could materially affect the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment may also have a significant effect, not only on the operation of the business,
but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies has not changed.
NRG evaluates these estimates, on an ongoing basis, utilizing historic experience, consultation with experts and other methods the Company considers reasonable. In any event, actual results may differ substantially from the Company's estimates. Any effects on the Company's business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the information that gives rise to the revision becomes known.
The Company identifies its most critical accounting estimates as those that are the most pervasive and important to the portrayal of the Company's financial position and results of operations, and require the most difficult, subjective and/or complex judgments by management regarding estimates about matters that are inherently uncertain.
Acquisition of LSP Portfolio
On January 30, 2026, NRG completed the acquisition of the LSP Portfolio. The acquisition has been recorded as a business combination under ASC 805 with identifiable assets acquired and liabilities assumed provisionally recorded at their estimated fair values on the acquisition date. NRG describes the fair value measurements resulting from the acquisition in Note 4, Acquisitions and Dispositions.
The Company's critical accounting estimates are described in Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, in the Company's 2025 Form 10-K. There have been no material changes to the Company's critical accounting estimates since the 2025 Form 10-K.
NRG Energy Inc. published this content on November 09, 2026, and is solely responsible for the information contained herein. Distributed via EDGAR on November 09, 2026 at 21:42 UTC. If you believe the information included in the content is inaccurate or outdated and requires editing or removal, please contact us at [email protected]