NRG ENERGY, INC.

Previous wording

As you read this discussion and analysis, refer to NRG's condensed consolidated statements of operations to this Form 10-Q, which present the results of operations for the three and nine months ended September 30, 2025 and 2024. Also refer to NRG's 2024 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.

Current wording

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 months ended March 31, 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.

Previous wording

NRG Energy, Inc., or NRG or the Company, is a leading energy and smart home company powering a brighter, smarter future. The Company provides gas, electricity, and smart home solutions to approximately 8 million residential customers (comprised of 6 million retail energy customers and 2 million smart home customers) in addition to large commercial and industrial, hyperscaler, and wholesale customers. Across the U.S. and Canada, NRG is redefining customer’s experience with energy under brand names such as NRG, Reliant, Direct Energy, Green Mountain Energy, and Vivint. As of September 30, 2025, the Company’s core power and natural gas business consists of approximately 12 GW of competitive power generation, primarily in Texas, and a natural gas portfolio that serves approximately 1,800 MMDth annually.

Current wording

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 March 31, 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.

Previous wording

To effectuate the Company’s strategy, NRG is focused on: (i) serving the energy needs of end-use 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 features, premium service, integrated platforms, sustainability, and loyalty/affinity programs; (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; and (v) engaging in disciplined and transparent capital allocation.

Current wording

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.

Previous wording

As participants in wholesale and retail energy markets and owners and operators of power plants, certain NRG entities are subject to regulation by various federal and state government agencies. These include the CFTC, FERC, NRC and the PUCT, as well as other public utility commissions in certain states where NRG's generation or distributed generation assets are located. In addition, NRG is subject to the market rules, procedures and protocols of the various ISO and RTO markets in which it participates. Likewise, certain NRG entities participating in the retail markets are subject to rules and regulations established by the states and provinces in which NRG entities are licensed to sell at retail. NRG must also comply with the mandatory reliability requirements imposed by NERC and the regional reliability entities in the regions where NRG operates.

Current wording

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.

Previous wording

Maryland Legislation — On May 9, 2024, Maryland Governor Wes Moore signed Senate Bill 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, 2025. 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 Senate Bill 1. On November 18, 2024, the trial court denied the plaintiffs' motion for a preliminary injunction. The plaintiffs, including Green Mountain, filed an appeal to this denial in the Fourth Circuit Court of Appeals and oral argument occurred on October 24, 2025.

Current wording

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. The plaintiffs, including Green Mountain, filed an appeal to this denial in the Court of Appeals for the Fourth Circuit and oral argument occurred on October 24, 2025. The appeal is pending.

Previous wording

Public Utility Commission of Texas’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.

Current wording

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.

Previous wording

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 for the time being. The Texas Legislature also directed the PUCT to implement additional market design changes such as the creation of 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. The PUCT directed ERCOT to implement DRRS as a standalone product which will delay implementation until 2026 or 2027. Both DRRS and a firming requirement are currently in the design phase with final rules yet to be adopted.

Current wording

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. The PUCT will evaluate the final design of DRRS as part of the review of the reliability standard in 2026. 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.

Previous wording

Texas Energy Fund —Through Senate Bill 2627, the Texas Legislature created the TEF, which received voter approval in November 2023, and will provide grants and low-interest loans (3%) to incentivize the development of more dispatchable generation and smaller backup generation in ERCOT. The PUCT adopted a rule in March 2024, which establishes the application and participation requirements and the process by which the TEF loan proceeds for dispatchable generation in ERCOT will be distributed. The initial window for submitting loan applications was opened on June 1, 2024 and closed on July 27, 2024. NRG, through its subsidiaries, filed for loan proceeds for three separate projects, totaling more than 1,500 MWs of capacity. 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. In January 2025, the PUCT began accepting applications for completion bonus grants, and NRG, through its subsidiaries, has filed applications for each of the three projects referenced above. The 89th Texas Legislature passed Senate Bill 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.

Current wording

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

Previous wording

Senate Bill 6 (“SB 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 requires load forecasting 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. PUCT rulemaking is in progress.

Current wording

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 in the third quarter of 2026. ERCOT is also developing revisions to the interconnection study process to more efficiently review large load interconnection requests.

Previous wording

Revisions to PJM Locational Deliverability Area ("LDA") Reliability Requirement — The Base Residual Auction ("BRA") for the 2024/2025 delivery year commenced on December 7, 2022 and closed on December 13, 2022. On December 19, 2022, PJM announced that it would delay the publication of the auction results. On December 23, 2022, PJM made a filing at FERC to revise the definition of LDA Reliability Requirement in the Tariff. This would allow PJM to exclude certain resources from the calculation of the LDA Reliability Requirement. On February 21, 2023, FERC accepted PJM's filing.

Current wording

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.

Previous wording

PJM Base Residual Auction Revisions and Delay —On October 13, 2023, PJM made two filings at FERC. In the first filing, PJM proposed revisions to the Market Seller Offer Cap, which FERC rejected on February 6, 2024. The second filing proposed to make changes to PJM’s resource adequacy risk modeling and capacity accreditation processes, which FERC approved, with condition, on January 20, 2024. The approved changes were in effect for the 2025/2026 BRA that occurred in July 2024. In November 2024, at PJM’s request, FERC approved delays to future BRAs.

Current wording

PJM Base Residual Auction Revisions and Delay — In November 2024, at PJM’s request, FERC approved delays to future BRAs. The 2028/2029 BRA is scheduled to occur in May 2026 and is the last delayed auction affected.

Previous wording

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 Fourth Circuit Court of Appeals of FERC’s denial on its request for rehearing. On August 22, 2025, NRG filed a motion to transfer venue. The appeal is pending.

Current wording

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.

Previous wording

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. In general, future laws are expected to 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 and the EPA has proposed rules that indicate that the current administration intends to relax or rescind some recently promulgated regulations, which will affect the outcome of the rulemakings and related legal challenges described below. 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.

Current wording

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.

Previous wording

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 SO 2, 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. The Company maintains a comprehensive compliance strategy to address continuing and new requirements. Complying with increasingly stringent air regulations could require the installation of additional emissions control equipment at some NRG facilities or retiring of units if installing such controls is not economic. Significant changes to air regulatory programs affecting the Company are described below.

Current wording

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 SO 2, 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 but in November 2025, the EPA asked the DC Circuit to vacate the March 2024 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.

Previous wording

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 CO 2 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 will be regulated including capturing and storing/sequestering CO 2 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. On February 5, 2025, the DOJ filed a motion asking the court to hold proceedings in abeyance while the EPA evaluates the rule. The court granted the motion on February 19, 2025. 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.

Current wording

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 CO 2 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 CO 2 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.

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CSAPR— On March 15, 2023, the EPA signed and released a prepublication version of a 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 U.S. Court of Appeals for 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 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. The Company cannot predict the outcome of the legal challenges to the various state disapprovals and the final rule promulgated on June 5, 2023.

Current wording

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.

Previous wording

Regional Haze Proposal — In May 2023, the EPA proposed to withdraw the existing Texas Sulfur Dioxide Trading Program and replace it with unit-specific SO 2 limits for 12 units in Texas to address requirements to improve visibility at National Parks and Wilderness areas. If finalized as proposed, the rule would result in more stringent SO 2 limits for two of the Company's coal-fired units in Texas. The Company cannot predict the outcome of this proposal. On October 2, 2025, the EPA published an ANPRM announcing plans to revise the Regional Haze Rule and seeking public input on streamlining the requirements.

Current wording

Regional Haze — In May 2023, the EPA proposed to withdraw the existing Texas Sulfur Dioxide Trading Program and replace it with unit-specific SO 2 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.

Previous wording

MATS— On May 7, 2024, the EPA promulgated a final rule that amends 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 creates 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 June 17, 2025, the EPA proposed to repeal the majority of the 2024 final rule amending the MATS rule. The outcome of this rulemaking is uncertain. The Company anticipates that the U.S. presidential administration will substantively revise this rule.

Current wording

MATS— On May 7, 2024, the EPA promulgated a final rule that amends 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 creates 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 June 17, 2025, the EPA proposed to repeal the majority of the 2024 final rule amending the MATS rule. On February 24, 2026, the EPA promulgated a final rule repealing the majority of the 2024 rule amending the MATS rule.

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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 intends to comply with the ELG by ceasing combustion of coal by the end of 2028 at its domestic coal units outside of Texas, and installing appropriate controls by the end of 2025 at its two plants that have coal-fired units in Texas. 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 Eighth Circuit of the U.S. Court of Appeals. 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 October 2, 2025, the EPA proposed to amend the ELG by extending deadlines that were part of the 2024 Rule, updating the transfer provisions to allow facilities to switch between compliance alternatives, and creating authority for alternative applicability dates. The EPA also is seeking comment on issues regarding a separate, future rulemaking on the underlying standards.

Current wording

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 intends to comply with the ELG by ceasing combustion of coal by the end of 2028 at its domestic coal units outside of Texas, and installing appropriate controls by the end of 2025 at its two plants that have coal-fired units in Texas. 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

Previous wording

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. The rule has been challenged in the D.C. Circuit and the outcome of the legal challenges is uncertain. The Company anticipates that the U.S. presidential administration will revisit this rule.

Current wording

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.

Previous wording

During the nine months ended September 30, 2025, the Company completed $971 million of share repurchases at an average price of $119.78 per share. Through October 31, 2025, an additional $129 million of share repurchases were executed at an average price of $167.41 per share. On October 16, 2025, the Board of Directors authorized an additional share repurchase program of up to $3.0 billion, to be executed through 2028. See Note 9, Changes in Capital Structure for additional discussion.

Current wording

During the three months ended March 31, 2026, the Company completed $481 million of share repurchases at an average price of $161.16 per share. Through April 30, 2026, an additional $338 million of share repurchases were executed at an average price of $156.52 per share. See Note 9, Changes in Capital Structure for additional discussion.

Previous wording

In the first quarter of 2025, NRG increased the annual common stock dividend to $1.76 from $1.63 per share, representing an 8% increase from 2024. Beginning in the first quarter of 2026, NRG will increase the annual dividend by 8% to $1.90 per share. The Company targets an annual dividend growth rate of 7-9% per share in subsequent years.

Current wording

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.

Previous wording

On July 22, 2025, the Company and APX Group LLC, as borrowers, and certain subsidiaries of the Company, as guarantors, entered into the Fifteenth Amendment with, among others, the Agent, and certain financial institutions, as lenders, which amended the Credit Agreement by adding a new incremental Term Loan B in an aggregate principal amount of $1.0 billion. For further discussion, see Note 7, Long-term Debt and Finance Leases.

Current wording

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.

Previous wording

On October 8, 2025, the Company issued $3.65 billion and $1.25 billion in aggregate principal amount of the New Unsecured Notes and New Secured Notes, respectively. The New Unsecured Notes are senior unsecured obligations of the Company and are guaranteed by its wholly-owned U.S. subsidiaries that guarantee the term loans under the Senior Credit Facility. The New Secured Notes are senior secured obligations of the Company and are guaranteed by its wholly-owned U.S. subsidiaries that guarantee the term loans under the Senior Credit Facility. For further discussion, see Note 7, Long-term Debt and Finance Leases.

Current wording

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.

Previous wording

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

Current wording

(b) The East weather metrics are comprised of the average of the CDD and HDD regional results for the Northeast and East - Midwest regions

Previous wording

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

Current wording

(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

Previous wording

Gross margin increased $378 million and economic gross margin increased $387 million, both of which include intercompany sales, during the nine months ended September 30, 2025, compared to the same period in 2024.

Current wording

Gross margin decreased $561 million and economic gross margin increased $62 million during the three months ended March 31, 2026, compared to the same period in 2025.

Previous wording

Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges. Total net mark-to-market results decreased by $45 million during the nine months ended September 30, 2025, compared to the same period in 2024.

Current wording

Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges. Total net mark-to-market results decreased by $536 million during the three months ended March 31, 2026, compared to the same period in 2025.

Previous wording

(a)Includes $(266) million, within the Texas segment, related to derivative contracts that were elected as NPNS on October 1, 2024 and are no longer valued at fair value on a recurring basis. For further discussion, see Note 6, Accounting for Derivative Instruments and Hedging Activities

Current wording

(a)Includes $(51) 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

Previous wording

(a)Includes $(319) million, within the Texas segment, related to derivative contracts that were elected as NPNS on October 1, 2024 and are no longer valued at fair value on a recurring basis. For further discussion, see Note 6, Accounting for Derivative Instruments and Hedging Activities

Current wording

(a)Includes $(83) 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

Previous wording

For the three months ended September 30, 2024, the $8 million gain in revenues from economic hedge positions was driven primarily by the reversal of previously recognized unrealized losses on contracts that settled during the period. The $1.6 billion loss in operating costs and expenses from economic hedge positions was driven primarily by a decrease in the value of open positions as a result of decreases in power prices, as well as the reversal of previously recognized unrealized gains on contracts that settled during the period.

Current wording

For the three months ended March 31, 2026, the $42 million loss in revenues from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period. The $163 million loss in operating costs and expenses from economic hedge positions was driven primarily by a decrease in the value of open positions as a result of decreases in natural gas prices and CAISO and Alberta power prices.

Previous wording

For the nine months ended September 30, 2025, the $18 million gain in revenues from economic hedge positions was driven primarily by an increase in the value of open positions as a result of decreases in natural gas prices. The $346 million loss in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period, partially offset by an increase in the value of Texas open positions as a result of increases in ERCOT power prices.

Current wording

For the three months ended March 31, 2025, the $15 million loss in revenues from economic hedge positions was driven primarily by a decrease in the value of East open positions as a result of increases in Northeast power prices. The $346 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 and East as a result of increases in natural gas prices and ERCOT and Northeast power prices, partially offset by the reversal of previously recognized unrealized gains on contracts that settled during the period.

Previous wording

Other cost of operations for the three months ended September 30, 2025 decreased by $30 million, when compared to the same period in 2024, due to the following:

Current wording

Other cost of operations for the three months ended March 31, 2026 increased by $26 million, when compared to the same period in 2025, due to the following:

Previous wording

Depreciation and amortization increased by $8 million for the three months ended September 30, 2025, compared to the same period in 2024, due to the following:

Current wording

Depreciation and amortization increased by $106 million for the three months ended March 31, 2026, compared to the same period in 2025, due to the following:

Previous wording

Selling, general and administrative costs increased by $146 million for the nine months ended September 30, 2025, compared to the same period in 2024, due to the following:

Current wording

Selling, general and administrative costs increased by $44 million for the three months ended March 31, 2026, compared to the same period in 2025, due to the following:

Previous wording

Acquisition-related transaction and integration costs of $8 million and $7 million for the three months ended September 30, 2025 and 2024, respectively, include:

Current wording

Acquisition-related transaction and integration costs of $45 million and $8 million for the three months ended March 31, 2026 and 2025, respectively, include:

Previous wording

For the three months ended September 30, 2025, income tax expense of $86 million was recorded on pre-tax income of $238 million. For the same period in 2024, an income tax benefit of $247 million was recorded on pre-tax loss of $1.0 billion. The effective tax rates were 36.1% and 24.4% for the three months ended September 30, 2025 and 2024, respectively.

Current wording

For the three months ended March 31, 2026, income tax benefit of $42 million was recorded on pre-tax income of $83 million. For the same period in 2025, an income tax expense of $235 million was recorded on pre-tax income of $985 million. The effective tax rates were (50.6)% and 23.9% for the three months ended March 31, 2026 and 2025, respectively.

Previous wording

For the nine months ended September 30, 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. For the same period in 2024, NRG's effective tax rate was higher than the statutory rate of 21%, primarily due to the state tax expense and permanent differences.

Current wording

For the three months ended March 31, 2026 the 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.

Previous wording

As of September 30, 2025 and December 31, 2024, NRG's total liquidity, excluding funds deposited by counterparties, of approximately $6.5 billion and $5.4 billion, respectively, was comprised of the following:

Current wording

As of March 31, 2026 and December 31, 2025, NRG’s total liquidity, excluding funds deposited by counterparties, of approximately $3.3 billion and $9.6 billion, respectively, was comprised of the following:

Previous wording

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

Current wording

(a) Includes reserves primarily for capital expenditures