NRG

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, financial condition addressing credit ratings, 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 six months ended June 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 customer’s experience with energy under brand names such as NRG, Reliant, Direct Energy, Green Mountain Energy, and Vivint. As of June 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 like 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. 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. 51 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 be the end of the year. 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. 52 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, the Governor of Texas signed SB 6 into law, which includes various provisions that concern how both 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. SB 6 improves load forecasting accuracy by requiring criteria for inclusion into the forecast and by requiring financial commitments upon a request for a large load customer seeking interconnection to begin engineering studies. In addition, SB 6 includes processes by which large loads should be required or incentivized to curtail their operations. At the same time, SB 6 establishes a PUCT regulatory procedure to minimize potential reliability and stranded-cost impacts that may be associated with new large load co-locations with power generators that were interconnected to ERCOT and operating as stand-alone generators as of September 1, 2025. Generators connected to the grid after this date are exempt from this procedure. Finally, SB 6 requires the PUCT to investigate revising the cost allocation and rate design that governs the ERCOT transmission system. The PUCT rulemaking process for these components of SB 6 is in progress. On March 27, 2026, the PUCT published its proposed rule relating to large load interconnection standards, which establishes the standards and criteria to interconnect a large load customer to the ERCOT system, as well as the financial security large load customers would need to provide. A final rule is anticipated by the end of the third quarter of 2026. 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. 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 53 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, through March 2027. On July 27, 2026, the PJM Board issued a decisional letter on the Reliability Backstop Procurement proposal and directed PJM to make a filing at FERC to implement the necessary changes. Specifically, from September 30, 2026 through October 21, 2026, PJM will open a central procurement window to procure capacity for the approximately 6,800 MW shortfall identified in 2028/2029 BRA, with the selection process and release of results occurring from October 22, 2026 and December 2, 2026. On July 31, 2026, PJM filed at FERC to implement these changes, following an abbreviated stakeholder process. The implementation of these market changes could have material impacts on the PJM market. Consumer Advocates Complaint — On April 14, 2025, various state consumer advocates filed a complaint with FERC asking FERC to reprice the 2025/2026 PJM capacity auction results. If FERC were to grant the request, the capacity prices for the 2025/2026 delivery year would be expected to change. The complaint is pending at FERC. 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. 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 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. 54 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 has been 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 evaluates the rule. On June 17, 2025, the EPA proposed to repeal all GHG emission standards for fossil fuel-fired power plants under Section 111 of the CAA. The EPA is proposing to conclude that GHG emissions from domestic fossil fuel-fired EGUs do not contribute to dangerous air pollution at a level sufficient to invoke the EPA’s authority under CAA Section 111. In addition to its primary proposal to repeal all GHG emission standards for the power sector promulgated in both 2015 and 2024, the EPA has included an alternative proposal to repeal just specific portions. On February 18, 2026, the EPA rescinded the 2009 GHG Endangerment Finding related to motor vehicle emissions. Although this rescission does not directly alter the GHG regulations related to power plants, the Company believes that the EPA may amend such regulations this year. 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. The Company does not expect this proposal to be finalized during the current U.S. presidential administration. 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. 55 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 September 2030 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. 56 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: 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 preliminary working capital and certain other adjustments of $483 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. Capital Allocation During the six months ended June 30, 2026, the Company completed $921 million of share repurchases at an average price of $156.52 per share. Through July 31, 2026, an additional $14 million of share repurchases were executed at an average price of $136.23 per share. 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. 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. 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 June 30, 2026, $784 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. 57 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, have contributed to elevated and volatile oil prices and could, over time, put upward pressure on U.S. natural gas. 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. 58 Consolidated Results of Operations The following table provides selected financial information for the Company: Three months ended June 30, Six months ended June 30, (In millions) 2026 2025 Change 2026 2025 Change Revenue Retail revenue $ 6,686 $ 6,519 $ 167 $ 16,186 $ 14,735 $ 1,451 Energy revenue(a) 301 99 202 776 344 432 Capacity revenue(a) 392 61 331 631 108 523 Mark-to-market for economic hedging activities 18 (1) 19 (24) (16) (8) Contract amortization 14 — 14 20 (5) 25 Other revenues(a)(b) 70 62 8 148 159 (11) Total revenue 7,481 6,740 741 17,737 15,325 2,412 Operating Costs and Expenses Cost of fuel 311 251 (60) 755 585 (170) Purchased energy and other cost of sales(c) 4,849 4,541 (308) 12,546 10,723 (1,823) Mark-to-market for economic hedging activities (271) 282 553 (108) (64) 44 Contract and emissions credit amortization(c) 6 3 (3) 23 28 5 Operations and maintenance 462 434 (28) 895 722 (173) Other cost of operations 113 118 5 217 196 (21) Cost of operations (excluding depreciation and amortization shown below) 5,470 5,629 159 14,328 12,190 (2,138) Depreciation and amortization 494 344 (150) 926 670 (256) Selling, general and administrative costs (excluding amortization of customer acquisition costs of $93, $68, $180, and $133 respectively, which are included in depreciation and amortization shown separately above) 562 724 162 1,155 1,273 118 Acquisition-related transaction and integration costs 16 43 27 61 51 (10) Total operating costs and expenses 6,542 6,740 198 16,470 14,184 (2,286) Gain/(Loss) on sale of assets 37 — 37 37 (7) 44 Operating Income 976 — 976 1,304 1,134 170 Other Income/(Expense) Other income, net 6 5 1 46 19 27 Loss on debt extinguishment (9) (10) 1 (9) (10) 1 Interest expense (310) (148) (162) (595) (311) (284) Total other expense (313) (153) (160) (558) (302) (256) Income/(Loss) Before Income Taxes 663 (153) 816 746 832 (86) Income tax expense/(benefit) 157 (49) (206) 115 186 71 Net Income/(Loss) $ 506 $ (104) $ 610 $ 631 $ 646 $ (15) (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 59 Management’s discussion of the results of operations for the three months ended June 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 June 30, 2026 and 2025: Average on Peak Power Price ($/MWh) Three months ended June 30, Region 2026 2025 Change % Texas ERCOT - Houston(a) $ 37.01 $ 44.41 (17) % ERCOT - North(a) 33.08 37.86 (13) % East NY J/NYC(b) $ 52.09 $ 51.20 2 % NEPOOL(b) 52.78 45.85 15 % COMED (PJM)(b) 37.98 40.96 (7) % PJM - West Hub(b) 65.46 52.75 24 % PJM - APS(b) 58.93 50.04 18 % PJM - DOMINION(b) 97.02 77.79 25 % West MISO - Louisiana Hub(b) $ 34.96 $ 48.40 (28) % CAISO - SP15(b) 5.61 16.85 (67) % (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 June 30, 2026 and 2025: Three months ended June 30, 2026 2025 Change % ($/MMBtu) $ 2.90 $ 3.44 (16) % 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. 60 The following tables present the composition and reconciliation of gross margin and economic gross margin for the three months ended June 30, 2026 and 2025: Three months ended June 30, 2026 ($ In millions) Texas East West/Other Vivint Smart Home Corporate/Eliminations Total Retail revenue $ 2,699 $ 2,770 $ 636 $ 587 $ (6) $ 6,686 Energy revenue 14 287 — — — 301 Capacity revenue — 392 6 — (6) 392 Mark-to-market for economic hedging activities — 14 — — 4 18 Contract amortization — 14 — — — 14 Other revenue(a) 34 35 2 — (1) 70 Total revenue 2,747 3,512 644 587 (9) 7,481 Cost of fuel (194) (117) — — — (311) Purchased energy and other cost of sales(b)(c)(d) (1,692) (2,565) (538) (60) 6 (4,849) Mark-to-market for economic hedging activities 56 166 53 — (4) 271 Contract and emissions credit amortization (1) (4) (1) — — (6) Depreciation and amortization (123) (134) (7) (216) (14) (494) Gross margin $ 793 $ 858 $ 151 $ 311 $ (21) $ 2,092 Less: Mark-to-market for economic hedging activities, net 56 180 53 — — 289 Less: Contract and emissions credit amortization, net (1) 10 (1) — — 8 Less: Depreciation and amortization (123) (134) (7) (216) (14) (494) Economic gross margin $ 861 $ 802 $ 106 $ 527 $ (7) $ 2,289 (a) Includes trading gains and losses and ancillary revenues (b) Includes capacity and emissions credits (c) Includes $859 million, $22 million and $228 million of TDSP expense in Texas, East and West/Other, respectively (d) Excludes depreciation and amortization shown separately Business Metrics Texas East West/Other Vivint Smart Home Corporate/Eliminations Total Retail sales Home electricity sales volume (GWh) 9,381 3,540 590 — — 13,511 Business electricity sales volume (GWh) 10,234 11,398 2,890 — — 24,522 Home natural gas sales volume (MDth) — 5,724 10,615 — — 16,339 Business natural gas sales volume (MDth) — 358,740 46,000 — — 404,740 Average retail Home customer count (in thousands)(a) 2,832 2,174 644 — — 5,650 Ending retail Home customer count (in thousands)(a) 2,824 2,209 642 — — 5,675 Average Vivint Smart Home customer count (in thousands)(b) — — — 2,461 — 2,461 Ending Vivint Smart Home customer count (in thousands) (b)(c) — — — 2,521 — 2,521 Power generation GWh sold(d) 6,743 4,593 — — — 11,336 GWh generated Coal 3,867 423 — — — 4,290 Gas 2,876 3,920 — — — 6,796 Oil — 2 — — — 2 Renewables — — — — — — Total 6,743 4,345 — — — 11,088 (a) Home customer count includes recurring residential customers and community choice (b) Vivint Smart Home includes customers that also purchase other NRG products such as electricity (c) Vivint Smart Home includes 71 thousand Home Protection (non-Vivint) customers (d) Includes GWh sold from owned and tolled generation, excludes equity investments. Cottonwood lease ended in May 2025 61 Three months ended June 30, 2025 ($ In millions) Texas East West/Other Vivint Smart Home Corporate/Eliminations Total Retail revenue $ 2,779 $ 2,608 $ 615 $ 522 $ (5) $ 6,519 Energy revenue 15 64 20 — — 99 Capacity revenue — 55 6 — — 61 Mark-to-market for economic hedging activities — 3 (2) — (2) (1) Contract amortization — — — — — — Other revenue(a) 52 8 5 — (3) 62 Total revenue 2,846 2,738 644 522 (10) 6,740 Cost of fuel (201) (35) (15) — — (251) Purchased energy and other cost of sales(b)(c)(d) (1,645) (2,332) (511) (55) 2 (4,541) Mark-to-market for economic hedging activities (6) (391) 113 — 2 (282) Contract and emissions credit amortization (3) 2 (2) — — (3) Depreciation and amortization (93) (36) (9) $ (195) (11) (344) Gross margin $ 898 $ (54) $ 220 $ 272 $ (17) $ 1,319 Less: Mark-to-market for economic hedging activities, net (6) (388) 111 — — (283) Less: Contract and emissions credit amortization, net (3) 2 (2) — — (3) Less: Depreciation and amortization (93) (36) (9) (195) (11) (344) Economic gross margin $ 1,000 $ 368 $ 120 $ 467 $ (6) $ 1,949 (a) Includes trading gains and losses and ancillary revenues (b) Includes capacity and emissions credits (c) Includes $861 million, $66 million and $196 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) 10,094 3,443 542 — — 14,079 Business electricity sales volume (GWh) 10,137 11,055 2,742 — — 23,934 Home natural gas sales volume (MDth) — 6,218 8,565 — — 14,783 Business natural gas sales volume (MDth) — 308,979 40,580 — — 349,559 Average retail Home customer count (in thousands)(a) 2,949 2,189 651 — — 5,789 Ending retail Home customer count (in thousands)(a) 2,904 2,164 650 — — 5,718 Average Vivint Smart Home customer count (in thousands)(b) — — — 2,278 — 2,278 Ending Vivint Smart Home customer count (in thousands)(b)(c) — — — 2,329 — 2,329 Power generation GWh sold(d) 6,940 940 572 — — 8,452 GWh generated Coal 5,205 487 — — — 5,692 Gas 1,735 1 571 — — 2,307 Oil — 4 — — — 4 Renewables — — 1 — — 1 Total 6,940 492 572 — — 8,004 (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 61 thousand Home Protection (non-Vivint) customers (d) Includes GWh sold from owned, tolled and leased generation, excludes equity investments 62 The following table represents the weather metrics for the three months ended June 30, 2026 and 2025: Three months ended June 30, Weather Metrics Texas East(b) West/Other(c) 2026 CDDs(a) 1,073 308 583 HDDs(a) 42 534 165 2025 CDDs 1,102 326 592 HDDs 49 568 195 10-year average CDDs 1,035 319 569 HDDs 56 586 196 (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 $773 million and economic gross margin increased $340 million during the three months ended June 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) Lower gross margin due to the net effect of:•a 13%, or $101 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•an increase in net revenue rates of $24 million, primarily driven by changes in customer term, product and mix $ (77) Lower gross margin due to a decrease in load driven by changes in customer mix and attrition, as well as weather (45) Other (17) Decrease in economic gross margin $ (139) Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges 62 Decrease in contract and emissions credit amortization 2 Increase in depreciation and amortization (30) Decrease in gross margin $ (105) 63 East (In millions) Higher electric gross margin due to the net effect of:•an increase in net revenue rates of $160 million, primarily driven by changes in customer term, product and mix•a 3%, or $32 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 $ 128 Higher electric gross margin primarily due to changes in customer mix and attrition, as well as an increase in load attributed to weather 25 Lower natural gas gross margin due to lower net revenue rates of $201 million, from changes in customer term, product, and mix, partially offset by lower supply costs of $140 million including the impact of transportation and storage contract optimization (61) Higher natural gas gross margin from an increase in load due to a change in customer mix 15 Higher gross margin due to an increase in capacity from the acquisition of the LSP Portfolio and at Midwest Generation 264 Higher gross margin due to an increase in demand response activities, including the acquisition of CPower and higher PJM auction prices in 2026 61 Other 2 Increase in economic gross margin $ 434 Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges 568 Decrease in contract amortization 8 Increase in depreciation and amortization (98) Increase in gross margin $ 912 West/Other (In millions) Lower electric gross margin due to lower net revenue rates of $38 million, partially offset by lower supply costs of $18 million and changes in customer mix of $7 million $ (13) Other (1) Decrease in economic gross margin $ (14) Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges (58) Decrease in contract amortization 1 Decrease in depreciation and amortization 2 Decrease in gross margin $ (69) Vivint Smart Home (In millions) Higher gross margin primarily driven by growth in customers of $40 million and higher monthly revenue of $19 million $ 59 Higher gross margin in home protection due to increased sales volume 4 Other (3) Increase in economic gross margin $ 60 Increase in depreciation and amortization (21) Increase in gross margin $ 39 64 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 $572 million during the three months ended June 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 June 30, 2026 (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 $ — $ — $ — $ 1 $ 1 Reversal of acquired gain positions related to economic hedges — (1) — — (1) Net unrealized gains on open positions related to economic hedges — 15 — 3 18 Total mark-to-market gains in revenue $ — $ 14 $ — $ 4 $ 18 Mark-to-market results in operating costs and expenses Reversal of previously recognized unrealized losses on settled positions related to economic hedges(a) $ 52 $ 73 $ 56 $ (1) $ 180 Reversal of acquired loss positions related to economic hedges 2 5 — — 7 Net unrealized gains/(losses) on open positions related to economic hedges 2 88 (3) (3) 84 Total mark-to-market gains in operating costs and expenses $ 56 $ 166 $ 53 $ (4) $ 271 (a)Includes $38 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 June 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 $ — $ (6) $ 1 $ — $ (5) Net unrealized gains/(losses) on open positions related to economic hedges — 9 (3) (2) 4 Total mark-to-market gains/(losses) in revenue $ — $ 3 $ (2) $ (2) $ (1) Mark-to-market results in operating costs and expenses Reversal of previously recognized unrealized losses on settled positions related to economic hedges(a) $ 8 $ 58 $ 59 $ — $ 125 Reversal of acquired loss positions related to economic hedges 6 3 — — 9 Net unrealized (losses)/gains on open positions related to economic hedges (20) (452) 54 2 (416) Total mark-to-market (losses)/gains in operating costs and expenses $ (6) $ (391) $ 113 $ 2 $ (282) (a)Includes $30 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 June 30, 2026, the $18 million gain in revenues from economic hedge positions was driven primarily by an increase in the value of open positions in East as a result of decreases in NYISO capacity prices. The $271 million gain in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized losses on contracts that settled during the period as well as an increase in the value of open positions in East as a result of increases in RGGI prices. 65 For the three months ended June 30, 2025, the $1 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, largely offset by an increase in the value of open positions in East as a result of decreases in Northeast power prices. The $282 million loss in operating costs and expenses from economic hedge positions was driven primarily by a decrease in the value of open positions in East as a result of decreases in natural gas prices and Northeast power prices, partially offset by the reversal of previously recognized unrealized losses on contracts that settled during the period. In accordance with ASC 815, the following table represents the results of the Company’s financial and physical trading of energy commodities for the three months ended June 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 June 30, (In millions) 2026 2025 Trading (losses)/gains Realized $ (10) $ (3) Unrealized (2) 14 Total trading (losses)/gains $ (12) $ 11 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 June 30, 2026 $ 242 $ 137 $ 10 $ 74 $ (1) $ 462 Three months ended June 30, 2025 235 97 40 60 2 434 Operations and maintenance expense increased by $28 million for the three months ended June 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 $ 105 Decrease driven by the expiration of the Cottonwood facility lease in May 2025 (27) Decrease in reserves primarily for legal matters in the East (33) Decrease due to timing of planned major maintenance expenditures at Powerton and in Texas (19) Decrease driven by lower retail operations costs (4) Increase driven by higher Vivint Smart Home operations costs 11 Other (5) Increase in operations and maintenance expense $ 28 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 June 30, 2026 $ 61 $ 50 $ 1 $ 1 $ 113 Three months ended June 30, 2025 70 44 3 1 118 Other cost of operations for the three months ended June 30, 2026 decreased by $5 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 $ 12 Increase in gross receipts taxes due to higher revenue in the East 5 Decrease primarily due to changes in prior year ARO cost estimates (20) Other (2) Decrease in other cost of operations $ (5) 66 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 June 30, 2026 $ 123 $ 134 $ 7 $ 216 $ 14 $ 494 Three months ended June 30, 2025 93 36 9 195 11 344 Depreciation and amortization increased by $150 million for the three months ended June 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 $ 120 Increase in amortization of capitalized contract costs primarily in the Vivint Smart Home segment 51 Decrease in amortization driven by the expected roll off of the acquired Vivint Smart Home intangibles (25) Other 4 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 June 30, 2026 $ 201 $ 159 $ 29 $ 164 $ 9 $ 562 Three months ended June 30, 2025 211 151 35 326 1 724 Selling, general and administrative costs decreased by $162 million for the three months ended June 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 $ (167) Increase due to the acquisition of the LSP Portfolio in January 2026 6 Increase in broker fee and commissions expenses 6 Decrease in personnel costs (13) Other 6 Decrease in selling, general and administrative costs $ (162) Acquisition-Related Transaction and Integration Costs Acquisition-related transaction and integration costs of $16 million and $43 million for the three months ended June 30, 2026 and 2025, respectively, include: Three months ended June 30, (In millions) 2026 2025 LSP Portfolio acquisition costs $ 3 $ 23 LSP Portfolio integration costs 10 — Other acquisition and integration costs, primarily related to Vivint Smart Home 3 20 Acquisition-related transaction and integration costs $ 16 $ 43 Interest Expense Interest expense increased by $162 million for the three months ended June 30, 2026, compared to the same period in 2025. The incremental interest expense is primarily attributable to the LSP acquisition, including the borrowing to finance the acquisition, the assumption of Lightning debt, and the refinancing activity occurred during the three months ended June 30, 2026. For further discussion, see Note 4, Acquisitions and Note 7, Long-term Debt and Finance Leases. 67 Income Tax Expense/(Benefit) For the three months ended June 30, 2026, income tax expense of $157 million was recorded on pre-tax income of $663 million. For the same period in 2025, an income tax benefit of $49 million was recorded on pre-tax loss of $153 million. The effective tax rates were 23.7% and 32.0% for the three months ended June 30, 2026 and 2025, respectively. For the three months ended June 30, 2026 the effective tax rate was higher than the statutory rate of 21%, primarily due to the state tax expense, partially offset with favorable permanent differences. For the same period in 2025, NRG's effective tax rate was higher than the statutory rate of 21%, primarily due to the state tax benefit and permanent differences. 68 Management’s discussion of the results of operations for the six months ended June 30, 2026 and 2025 Electricity Prices The following table summarizes average on peak power prices for each of the major markets in which NRG operates for the six months ended June 30, 2026 and 2025: Average on Peak Power Price ($/MWh) Six months ended June 30, Region 2026 2025 Change % Texas ERCOT - Houston (a) $ 33.02 $ 38.84 (15) % ERCOT - North(a) 30.27 36.62 (17) % East NY J/NYC(b) $ 93.38 $ 80.82 16 % NEPOOL(b) 87.73 77.34 13 % COMED (PJM)(b) 48.91 41.59 18 % PJM - West Hub(b) 84.42 56.46 50 % PJM - APS(b) 80.84 53.78 50 % PJM - DOMINION(b) 103.92 71.06 46 % West MISO - Louisiana Hub(b) $ 42.64 $ 47.77 (11) % CAISO - SP15(b) 13.83 21.66 (36) % (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 six months ended June 30, 2026 and 2025: Six months ended June 30, 2026 2025 Change % ($/MMBtu) $ 3.97 $ 3.55 12 % 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. 69 The following tables present the composition and reconciliation of gross margin and economic gross margin for the six months ended June 30, 2026 and 2025: Six months ended June 30, 2026 ($ In millions) Texas(a) East(a) West/Other Vivint Smart Home Corporate/Eliminations Total Retail revenue $ 5,034 $ 8,507 $ 1,498 $ 1,165 $ (18) $ 16,186 Energy revenue 22 754 — — — 776 Capacity revenue — 631 6 — (6) 631 Mark-to-market for economic hedging activities — (30) — — 6 (24) Contract amortization — 20 — — — 20 Other revenue(b) 84 62 4 — (2) 148 Total revenue 5,140 9,944 1,508 1,165 (20) 17,737 Cost of fuel (408) (346) (1) — — (755) Purchased energy and other cost of sales(c)(d)(e) (3,186) (8,007) (1,248) (112) 7 (12,546) Mark-to-market for economic hedging activities 5 110 (1) — (6) 108 Contract and emissions credit amortization (3) (18) (2) — — (23) Depreciation and amortization (231) (236) (15) $ (416) (28) (926) Gross margin $ 1,317 $ 1,447 $ 241 $ 637 $ (47) $ 3,595 Less: Mark-to-market for economic hedging activities, net 5 80 (1) — — 84 Less: Contract and emissions credit amortization, net (3) 2 (2) — — (3) Less: Depreciation and amortization (231) (236) (15) (416) (28) (926) Economic gross margin $ 1,546 $ 1,601 $ 259 $ 1,053 $ (19) $ 4,440 (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 $1.6 billion, $80 million and $501 million of TDSP expense in Texas, East, and West/Other, respectively (e) Excludes depreciation and amortization shown separately Business Metrics Texas East West/Other Vivint Smart Home Corporate/Eliminations Total Retail sales Home electricity sales volume (GWh) 16,764 7,665 1,310 — — 25,739 Business electricity sales volume (GWh) 19,098 22,391 6,021 — — 47,510 Home natural gas sales volume (MDth) — 28,109 43,100 — — 71,209 Business natural gas sales volume (MDth) — 892,225 104,296 — — 996,521 Average retail Home customer count (in thousands)(a) 2,841 2,152 646 — — 5,639 Ending retail Home customer count (in thousands)(a) 2,824 2,209 642 — — 5,675 Average Vivint Smart Home customer count (in thousands)(b) — — — 2,434 — 2,434 Ending Vivint Smart Home customer count (in thousands)(b)(c) — — — 2,521 — 2,521 Power generation GWh sold(d) 12,180 9,024 1 — — 21,205 GWh generated Coal 7,706 1,151 — — — 8,857 Gas 4,474 7,145 — — — 11,619 Oil — 20 — — — 20 Renewables — — 1 — — 1 Total 12,180 8,316 1 — — 20,497 (a) Home customer count includes recurring residential customers and community choice (b) Vivint Smart Home includes customers that also purchase other NRG products such as electricity (c) Vivint Smart Home includes 71 thousand Home Protection (non-Vivint) customers (d) Includes GWh sold from owned and tolled generation, excludes equity investments. Cottonwood lease ended in May 2025 70 Six months ended June 30, 2025 ($ In millions) Texas East West/Other Vivint Smart Home Corporate/Eliminations Total Retail revenue $ 5,166 $ 6,958 $ 1,587 $ 1,033 $ (9) $ 14,735 Energy revenue 22 222 101 — (1) 344 Capacity revenue — 95 14 — (1) 108 Mark-to-market for economic hedging activities — (16) — — — (16) Contract amortization — (5) — — — (5) Other revenue(a) 93 61 12 — (7) 159 Total revenue 5,281 7,315 1,714 1,033 (18) 15,325 Cost of fuel (378) (143) (64) — — (585) Purchased energy and other cost of sales(b)(c)(d) (3,166) (6,084) (1,387) (91) 5 (10,723) Mark-to-market for economic hedging activities 32 (83) 115 — — 64 Contract and emissions credit amortization (4) (22) (2) — — (28) Depreciation and amortization (176) (73) (18) $ (381) (22) (670) Gross margin $ 1,589 $ 910 $ 358 $ 561 $ (35) $ 3,383 Less: Mark-to-market for economic hedging activities, net 32 (99) 115 — — 48 Less: Contract and emissions credit amortization, net (4) (27) (2) — — (33) Less: Depreciation and amortization (176) (73) (18) (381) (22) (670) Economic gross margin $ 1,737 $ 1,109 $ 263 $ 942 $ (13) $ 4,038 (a) Includes trading gains and losses and ancillary revenues (b) Includes capacity and emissions credits (c) Includes $1.7 billion, $130 million and $619 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) 18,559 7,600 1,223 — — 27,382 Business electricity sales volume (GWh) 19,065 22,150 5,656 — — 46,871 Home natural gas sales volume (MDth) — 32,858 43,669 — — 76,527 Business natural gas sales volume (MDth) — 809,558 94,650 — — 904,208 Average retail Home customer count (in thousands)(a) 2,930 2,196 650 — — 5,776 Ending retail Home customer count (in thousands)(a) 2,904 2,164 650 — — 5,718 Average Vivint Smart Home customer count (in thousands)(b) — — — 2,254 — 2,254 Ending Vivint Smart Home customer count (in thousands)(b)(c) — — — 2,329 — 2,329 Power generation GWh sold(d) 12,581 2,863 2,116 — — 17,560 GWh generated Coal 10,015 1,696 — — — 11,711 Gas 2,566 2 2,114 — — 4,682 Oil — 7 — — — 7 Renewables — — 2 — — 2 Total 12,581 1,705 2,116 — — 16,402 (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 61 thousand Home Protection (non-Vivint) customers (d) Includes GWh sold from owned, tolled and leased generation, excludes equity investments 71 The following table represents the weather metrics for the six months ended June 30, 2026 and 2025: Six months ended June 30, Weather Metrics Texas East(b) West/Other(c) 2026 CDDs(a) 1,301 331 701 HDDs(a) 752 3,313 990 2025 CDDs 1,254 343 657 HDDs 1,063 3,325 1,376 10-year average CDDs 1,163 342 626 HDDs 968 3,200 1,291 (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 $212 million and economic gross margin increased $402 million, both of which include intercompany sales, during the six months ended June 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) Lower gross margin due to the net effect of:•a 12%, or $178 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•an increase in net revenue rates of $106 million, primarily driven by changes in customer term, product and mix $ (72) Lower gross margin due to a decrease in load driven by changes in customer mix and attrition, as well as weather (100) Other (19) Decrease in economic gross margin $ (191) Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges (27) Decrease in contract and emissions credit amortization 1 Increase in depreciation and amortization (55) Decrease in gross margin $ (272) 72 East (In millions) Higher electric gross margin due to the net effect of:•an increase in net revenue rates of $421 million, primarily driven by changes in customer term, product and mix•a 17%, or $407 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 $ 14 Higher electric gross margin primarily due an increase in load driven by changes in customer mix and attrition, as well as an increase in load attributed to weather 38 Lower natural gas gross margin due to higher supply costs of $858 million including the impact of transportation and storage contract optimization, partially offset by higher net revenue rates of $775 million, from changes in customer term, product, and mix (83) Higher natural gas gross margin from an increase in load due to a change in customer mix 30 Higher gross margin due to an increase in capacity from the acquisition of the LSP Portfolio and Midwest Generation 414 Higher gross margin due to an increase in demand response activities, including the acquisition of CPower and higher PJM auction prices in 2026 87 Lower gross margin due to the deactivation of Indian River Unit 4 in February 2025 (9) Other 1 Increase in economic gross margin $ 492 Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges 179 Decrease in contract amortization 29 Increase in depreciation and amortization (163) Increase in gross margin $ 537 West/Other (In millions) Higher electric gross margin due to lower supply costs of $53 million and changes in customer mix of $15 million, partially offset by lower net revenue rates of $60 million $ 8 Lower gross margin at Cottonwood driven by the termination of the facility lease in May 2025 (4) Other (8) Decrease in economic gross margin $ (4) Decrease in mark-to-market for economic hedges primarily due to net unrealized gains/losses on open positions related to economic hedges (116) Decrease in depreciation and amortization 3 Decrease in gross margin $ (117) Vivint Smart Home (In millions) Higher gross margin primarily driven by growth in customers of $68 million and higher monthly revenue of $24 million $ 92 Higher gross margin in home protection due to increased sales volume 20 Other (1) Increase in economic gross margin $ 111 Increase in depreciation and amortization (35) Increase in gross margin $ 76 73 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 $36 million during the six months ended June 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: Six months ended June 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 $ — $ (28) $ — $ 2 $ (26) Reversal of acquired gain positions related to economic hedges — (10) — — (10) Net unrealized gains on open positions related to economic hedges — 8 — 4 12 Total mark-to-market losses in revenue $ — $ (30) $ — $ 6 $ (24) Mark-to-market results in operating costs and expenses Reversal of previously recognized unrealized losses on settled positions related to economic hedges(a) $ 9 $ 22 $ 144 $ (2) $ 173 Reversal of acquired loss positions related to economic hedges 1 25 — — 26 Net unrealized (losses)/gains on open positions related to economic hedges (5) 63 (145) (4) (91) Total mark-to-market gains/(losses) in operating costs and expenses $ 5 $ 110 $ (1) $ (6) $ 108 (a)Includes $(13) 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 Six months ended June 30, 2025 (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 $ — $ (7) $ (2) $ — $ (9) Net unrealized (losses)/gains on open positions related to economic hedges — (9) 2 — (7) Total mark-to-market losses in revenue $ — $ (16) $ — $ — $ (16) Mark-to-market results in operating costs and expenses Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges(a) $ (137) $ (65) $ 113 $ — $ (89) Reversal of acquired loss/(gain) positions related to economic hedges 9 (4) — — 5 Net unrealized gains/(losses) on open positions related to economic hedges 160 (14) 2 — 148 Total mark-to-market gains/(losses) in operating costs and expenses $ 32 $ (83) $ 115 $ — $ 64 (a)Includes $(53) 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 six months ended June 30, 2026, the $24 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, partially offset by an increase in the value of open positions in East as a result of decreases in NYISO capacity prices. The $108 million gain in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized losses on contracts that settled during the period, partially offset by a decrease in the value of open positions in West/Other as a result of decreases in natural gas price and CAISO and Alberta power prices. For the six months ended June 30, 2025, the $16 million loss in revenues from economic hedge positions was primarily driven 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 East as a result of increases in Northeast power prices. The $64 million gain in operating costs and expenses from economic hedge positions was driven primarily by an increase in the value of open positions in Texas as a result of increases in ERCOT power prices, partially offset by the reversal of previously recognized unrealized gains on contracts that settled during the period. 74 In accordance with ASC 815, the following table represents the results of the Company’s financial and physical trading of energy commodities for the six months ended June 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. Six months ended June 30, (In millions) 2026 2025 Trading (losses)/gains Realized $ (8) $ 1 Unrealized (9) 10 Total trading (losses)/gains $ (17) $ 11 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 Six months ended June 30, 2026 $ 464 $ 264 $ 23 $ 145 $ (1) $ 895 Six months ended June 30, 2025 329 198 72 122 1 722 (a) Includes results of operations following the acquisition date of the LSP Portfolio of January 30, 2026 Operations and maintenance expense increased by $173 million for the six months ended June 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 $ 164 Increase due to the final property insurance claim for the extended outage at W.A. Parish received in 2025 100 Decrease driven by the expiration of the Cottonwood facility lease in May 2025 (46) Decrease in reserves primarily for legal matters in the East (33) Decrease due to timing of planned major maintenance expenditures at Powerton and in Texas (30) Increase driven by higher Vivint Smart Home operations costs 18 Increase driven by higher retail operations costs 8 Other (8) Increase in operations and maintenance expense $ 173 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 Six months ended June 30, 2026 $ 115 $ 98 $ 2 $ 2 $ 217 Six months ended June 30, 2025 125 63 6 2 196 (a) Includes results of operations following the acquisition date of the LSP Portfolio of January 30, 2026 Other cost of operations increased by $21 million for the six months ended June 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 $ 19 Increase in gross receipts taxes due to higher revenue in the East 8 Decrease primarily due to changes in prior year ARO cost estimates (4) Other (2) Increase in other cost of operations $ 21 75 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 Six months ended June 30, 2026 $ 231 $ 236 $ 15 $ 416 $ 28 $ 926 Six months ended June 30, 2025 176 73 18 381 22 670 (a) Includes results of operations following the acquisition date of the LSP Portfolio of January 30, 2026 Depreciation and amortization increased by $256 million for the six months ended June 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 $ 199 Increase in amortization of capitalized contract costs primarily in the Vivint Smart Home segment 98 Decrease in amortization driven by the expected roll off of the acquired Vivint Smart Home intangibles (50) Other 9 Increase in depreciation and amortization $ 256 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 Six months ended June 30, 2026 $ 420 $ 335 $ 58 $ 340 $ 2 $ 1,155 Six months ended June 30, 2025 416 294 67 489 7 1,273 (a) Includes results of operations following the acquisition date of the LSP Portfolio of January 30, 2026 Selling, general and administrative costs decreased by $118 million for the six months ended June 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 $ (184) Increase due to the acquisition of the LS Power Portfolio in January 2026 11 Increase in broker fee and commissions expenses 20 Increase in marketing and media expenses 13 Increase in personnel costs 12 Other 10 Decrease in selling, general and administrative costs $ (118) Acquisition-Related Transaction and Integration Costs Acquisition-related transaction and integration costs of $61 million and $51 million for the six months ended June 30, 2026 and 2025, respectively, include: Six months ended June 30, (In millions) 2026 2025 LSP Portfolio acquisition costs $ 41 $ 23 LSP Portfolio integration costs 14 — Other acquisition and integration costs, primarily related to Vivint Smart Home 6 28 Acquisition-related transaction and integration costs $ 61 $ 51 76 Other Income, net Other income, net increased by $27 million for the six months ended June 30, 2026, compared to the same period in 2025, primarily driven by higher interest income. Interest Expense Interest expense increased by $284 million for the six months ended June 30, 2026, compared to the same period in 2025. The incremental interest expense is primarily attributable to the LSP acquisition, including the borrowing to finance the acquisition, the assumption of Lightning debt, and the refinancing activity occurred during the six months ended June 30, 2026. For further discussion, see Note 4, Acquisitions and Note 7, Long-term Debt and Finance Leases. Income Tax Expense For the six months ended June 30, 2026, an income tax expense of $115 million was recorded on a pre-tax income of $746 million. For the same period in 2025, income tax expense of $186 million was recorded on pre-tax income of $832 million. The effective tax rates were 15.4% and 22.4% for the six months ended June 30, 2026 and 2025, respectively. For the six months ended June 30, 2026, NRG’s effective tax rate was lower than the statutory rate of 21%, primarily due to 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 June 30, 2026 and December 31, 2025, NRG’s total liquidity, excluding funds deposited by counterparties, of approximately $5.3 billion and $9.6 billion, respectively, was comprised of the following: (In millions) June 30, 2026 December 31, 2025 Cash and cash equivalents $ 162 $ 4,708 Restricted cash - operating 13 12 Restricted cash - reserves(a) 37 18 Total 212 4,738 Total availability under Revolving Credit Facility and collective collateral facilities(b) 5,068 4,890 Total liquidity, excluding funds deposited by counterparties $ 5,280 $ 9,628 (a) Includes reserves primarily for capital expenditures (b) Total capacity of Revolving Credit Facility and collective collateral facilities was $9.0 billion and $7.7 billion as of June 30, 2026 and December 31, 2025, respectively As of June 30, 2026, total liquidity, excluding funds deposited by counterparties, was approximately $5.3 billion, which is $4.3 billion lower than 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 June 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. 77 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. 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 preliminary working capital and certain other adjustments of $483 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. 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. 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 June 30, 2026, $784 million was issued under these facilities. As of July 31, 2026, $1.1 billion was issued under these facilities. Credit Default Swap Facility On July 21, 2026, the Company entered into a credit agreement, with commitments from lenders not to exceed $250 million, for the issuance of letters of credit to support normal business operations. As of July 31, 2026, there were no letters of credit issued under this facility. Revolving Credit Facility As of June 30, 2026, $1.4 billion of borrowings were outstanding and there were $197 million in letters of credit issued under the Revolving Credit Facility. As of July 31, 2026, $469 million of borrowings were outstanding and there were $200 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 June 30, 2026, there were no outstanding borrowings and there were $991 million in letters of credit issued under the Receivables Facility. As of July 31, 2026, $700 million of borrowings were outstanding and there were $1.2 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. 78 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 June 30, 2026, there were no outstanding borrowings and there were $82 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 June 30, 2026, market operations had total cash collateral outstanding of $441 million and $2.5 billion outstanding in letters of credit to third parties primarily to support its market activities. As of June 30, 2026, total funds deposited by counterparties were $167 million in cash and $308 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 June 30, 2026, counterparties’ net exposure to NRG of approximately $255 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 six months ended June 30, 2026, and the estimated forecast for the remainder of the year. (In millions) Maintenance Environmental Investments and Integration Total Texas $ 115 $ 13 $ 416 $ 544 East 34 — 7 41 West/Other 2 — 2 4 Vivint Smart Home 11 — 2 13 Corporate 11 — 42 53 Total cash capital expenditures for the six months ended June 30, 2026 $ 173 $ 13 $ 469 $ 655 Integration operating expenses and cost to achieve — — 48 48 Investments — — 99 99 Total cash capital expenditures and investments for the six months ended June 30, 2026 $ 173 $ 13 $ 616 $ 802 Estimated cash capital expenditures and investments for the remainder of 2026 292 2 1,148 1,442 Estimated full year 2026 cash capital expenditures and investments $ 465 $ 15 $ 1,764 $ 2,244 Investments and Integration for the six months ended June 30, 2026 include growth expenditures, integration, small book acquisitions and other investments. 79 Environmental Capital Expenditures Estimate NRG estimates that environmental capital expenditures from 2026 through 2030 required to comply with environmental laws will be approximately $39 million, primarily driven by the cost of complying with ELG at the Company’s coal units in Texas. Share Repurchases During the six months ended June 30, 2026, the Company completed $921 million of share repurchases at an average price of $156.52 per share. Through July 31, 2026, an additional $14 million of share repurchases were executed at an average price of $136.23 per share. 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 June 30, 2026. On July 22, 2026, NRG declared a quarterly dividend on the Company’s common stock of $0.475 per share, payable on August 17, 2026 to stockholders of record as of August 3, 2026. The Company targets an annual dividend growth rate of 7%-9% per share in subsequent years. Series A Preferred Stock Dividends During the quarter ended 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, 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 $461 million as of June 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 six months ended June 30, 2026. Cash Flow Discussion The following table reflects the changes in cash flows for the six months ended June 30, 2026 and 2025, respectively: Six months ended June 30, (In millions) 2026 2025 Change Cash provided by operating activities $ 948 $ 1,306 $ (358) Cash used in investing activities (7,709) (1,082) (6,627) Cash provided by/(used in) financing activities 2,140 (755) 2,895 80 Cash provided by operating activities Changes to cash provided by operating activities were driven by: (In millions) Increase in working capital primarily due to timing of receipts partially offset by lower gas volumes in Accounts payable $ 186 Changes in Cash collateral in support of risk management activities due to change in commodity prices (183) Decrease in working capital related to Inventory primarily driven by an increase in fuel and materials (172) Decrease in Net Income adjusted for derivatives and other non-cash items (145) Decrease in other working capital (44) $ (358) 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 $ (6,515) Decrease due to proceeds from insurance recoveries for Property, plant and equipment, net in 2025 (100) Increase in capital expenditures (60) Increase in proceeds from sale of assets 38 Increase due to higher sales of emissions allowances, net of purchases 10 $ (6,627) 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 $ 3,652 Decrease due to higher repayments of long-term debt (1,609) Increase due to higher proceeds from credit facilities, including for the acquisition of the LSP Portfolio 1,314 Decrease primarily due to higher payments for share repurchase activities in 2026 (350) Decrease primarily due to higher deferred debt issuance costs (62) Increase in payments of dividends primarily due to common stock (28) Decrease in net receipts from settlement of acquired derivatives (22) $ 2,895 NOLs, Deferred Tax Assets and Uncertain Tax Position Implications, under ASC 740 For the six months ended June 30, 2026, the Company had domestic pre-tax book income of $715 million and foreign pre-tax book income of $31 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 six months ended June 30, 2026. As of June 30, 2026, the Company has $48 million of tax-effected uncertain federal, state, and foreign tax benefits, for which the Company has recorded a non-current tax liability of $53 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. 81 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 June 30, 2026 and December 31, 2025, NRG recorded a net deferred tax asset, excluding valuation allowance, of $1.9 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 June 30, 2026 and December 31, 2025 as discussed below. NOL Carryforwards — As of June 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 $104 million. Valuation Allowance — As of June 30, 2026 and December 31, 2025, the Company’s tax-effected valuation allowance was $146 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 June 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) Six months ended June 30, 2026 Revenue(a) $ 15,460 Operating income(b) 813 Total other expense (445) Income before income taxes 367 Net income 260 (a)Intercompany transactions with Non-Guarantors of $6 million during the six months ended June 30, 2026 (b)Intercompany transactions with Non-Guarantors including cost of operations of $(70) million and selling, general and administrative of $216 million during the six months ended June 30, 2026 82 The following table presents the summarized balance sheet information: (In millions) As of June 30, 2026 Current assets(a) $ 7,222 Property, plant and equipment, net 5,028 Non-current assets 22,300 Current liabilities(b) 8,706 Non-current liabilities 22,072 (a)Includes intercompany receivables due from Non-Guarantors of $767 million as of June 30, 2026 (b)Includes intercompany payables due to Non-Guarantors of $26 million as of June 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 June 30, 2026, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at June 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 215 LSP Portfolio contracts acquired during the period (96) Other changes in fair value (158) Fair Value of Contracts as of June 30, 2026(a) $ 358 (a)As of December 31, 2025 and June 30, 2026, respectively, includes $484 million and $471 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 June 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 $ (100) $ (47) $ (2) $ (2) $ (151) Level 2 180 102 15 6 303 Level 3 (173) (109) (2) 19 (265) Total $ (93) $ (54) $ 11 $ 23 $ (113) (a)Excludes $471 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, 83 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 June 30, 2026, NRG’s net derivative asset was $358 million, a decrease to total fair value of $39 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 or decrease in natural gas prices across the term of the derivative contracts would result in a change of approximately $879 million in the net value of derivatives as of June 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. 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. 84