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 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.

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 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.

Previous wording

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) 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.

Current wording

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.

Previous 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.

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 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.

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 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.

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. 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.

Previous 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

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 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.

Previous wording

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 December 12, 2025, the PUCT approved the notice of eligibility for the completion bonus grant for T.H. Wharton. 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. All three projects are currently under construction. Commercial operations at T.H. Wharton is expected by the end of May 2026.

Current wording

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.

Previous 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.

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 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.

Previous 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.

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 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.

Previous wording

PJM’s Reforms to Large Load Additions — On September 15, 2025, PJM began a formal stakeholder process called the Critical Issue Fast Path (“CIFP”) to address needed reforms to accommodate large load additions. On January 16, 2026, the National Energy Dominance Council within the White House released a Statement of Principles, signed by all 13 governors in the PJM region, urging PJM to address revenue certainty for new generation through an auction process for new capacity, allocate the costs of these new resources to data centers, improve load forecasting, and accelerate ongoing generation interconnection studies. Also on January 16, 2026, the PJM Board issued a decisional letter on the CIFP process. The Board letter directed PJM staff to implement changes to load forecasting, implement a bring your own new generation program and associated expedited interconnection track, initiate immediately a Reliability Backstop Auction to obtain commitments of additional generation for a longer term, and undertake a holistic review of the PJM markets to analyze how they can evolve to provide appropriate incentives for investment and performance. On February 27, 2026, PJM made two filings at FERC. In its first filing, PJM proposed an expedited interconnection track for up to ten qualified large load projects. This filing is pending at FERC. 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. On April 28, 2026, FERC approved PJM’s second filing to extend the price cap and price floor.

Current wording

PJM’s Reforms to Large Load Additions — On September 15, 2025, PJM began a formal stakeholder process called the Critical Issue Fast Path (“CIFP”) to address needed reforms to accommodate large load additions. On January 16, 2026, the National Energy Dominance Council within the White House released a Statement of Principles, signed by all 13 governors in the PJM region, urging PJM to address revenue certainty for new generation through an auction process for new capacity, allocate the costs of these new resources to data centers, improve load forecasting, and accelerate ongoing generation interconnection studies. Also on January 16, 2026, the PJM Board issued a decisional letter on the CIFP process. The Board letter directed PJM staff to implement changes to load forecasting, implement a bring your own new generation program and associated expedited interconnection track, initiate immediately a Reliability Backstop Auction to obtain commitments of additional generation for a longer term, and undertake a holistic review of the PJM markets to analyze how they can evolve to provide appropriate incentives for investment and performance. On February 27, 2026, PJM made two filings at FERC. In its first filing, PJM proposed an expedited interconnection track for up to ten qualified large load projects, which was approved by FERC on June 9, 2026. In its second filing, PJM proposed an extension of the price cap and price floor for all capacity auctions through the 2028/2029 and 2029/2030 delivery years, which was approved by FERC on April 28, 2026.

Previous wording

On April 10, 2026, PJM published a Reliability Backstop Procurement proposal in response to the January 16, 2026 Board directive. PJM proposes a one-time, transitional procurement of capacity in two-stages. An initial process for facilitating bilateral contracts between large loads and eligible supply, beginning in September 2026 and ending in March 2027, followed by a central procurement process to commence in March 2027. PJM expects to file at FERC to implement these changes in June 2026, following an abbreviated stakeholder process. The implementation of these market changes could have material impacts on the PJM market.

Current wording

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.

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 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.

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 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.

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. On February 24, 2026, the EPA promulgated a final rule repealing the majority of the 2024 rule amending the MATS rule.

Current wording

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.

Previous 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

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 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.

Previous wording

Virginia Rejoining the Regional Greenhouse Gas Initiative (“RGGI”)— On February 20, 2026, Virginia enacted legislation to rejoin the RGGI. Virginia is working on promulgating the implementing regulations and is seeking to require compliance beginning on July 1, 2026.

Current wording

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.

Previous 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.

Current wording

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.

Previous wording

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 March 31, 2026, $739 million was issued under these facilities.

Current wording

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.

Previous wording

On the Acquisition Closing Date, Lightning remained the issuer of the Lightning Senior Secured 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. For further discussion, see Note 7, Long-term Debt and Finance Leases.

Current wording

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.

Previous 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.

Current wording

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.

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 $536 million during the three months ended March 31, 2026, compared to the same period in 2025.

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 increased by $572 million during the three months ended June 30, 2026, compared to the same period in 2025.

Previous 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.

Current wording

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.

Previous 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:

Current wording

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:

Previous 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:

Current wording

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:

Previous 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:

Current wording

Acquisition-related transaction and integration costs of $16 million and $43 million for the three months ended June 30, 2026 and 2025, respectively, include:

Previous 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.

Current wording

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.

Previous 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.

Current wording

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.

Previous wording

Other income, net increased by $26 million for the three months ended March 31, 2026, compared to the same period in 2025, primarily driven by higher interest income.

Current wording

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.

Previous 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.

Current wording

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.

Previous 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:

Current wording

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:

Previous wording

(b) Total capacity of Revolving Credit Facility and collective collateral facilities was $9.3 billion and $7.7 billion as of March 31, 2026 and December 31, 2025, respectively

Current wording

(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

Previous wording

For the three months ended March 31, 2026, total liquidity, excluding funds deposited by counterparties, was approximately $3.3 billion, which is $6.4 billion lower than December 31, 2025, primarily driven by the use of cash and borrowings under the Revolving Credit Facility to fund the acquisition of LSP Portfolio. Changes in cash and cash equivalent balances are further discussed under the heading Cash Flow Discussion. Cash and cash equivalents at March 31, 2026 were predominantly held in bank deposits.

Current wording

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.

Previous wording

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, 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. As part of the acquisition of the LSP Portfolio on January 30, 2026, NRG acquired existing debt, which includes the Lightning Senior Secured Notes, Lightning Term Loan, and Lightning Revolving Facility.

Current wording

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.

Previous wording

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 March 31, 2026, $739 million was issued under these facilities.

Current wording

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.

Previous wording

As of March 31, 2026, $3.0 billion of borrowings were outstanding. As of April 30, 2026, $1.5 billion of borrowings were outstanding.

Current wording

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.

Previous wording

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 March 31, 2026, there were no outstanding borrowings and there were $105 million in letters of credit issued under the Lightning Revolving Facility. For further discussion, see Note 7, Long-term Debt and Finance Leases.

Current wording

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.

Previous wording

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 March 31, 2026, market operations had total cash collateral outstanding of $606 million and $3.0 billion outstanding in letters of credit to third parties primarily to support its market activities. As of March 31, 2026, total funds deposited by counterparties were $176 million in cash and $371 million of letters of credit.

Current wording

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.

Previous wording

As of March 31, 2026, counterparties’ net exposure to NRG of approximately $203 million on out-of-the-money hedges was secured by the first lien structure.

Current wording

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.

Previous wording

The following table summarizes the Company’s capital expenditures for maintenance, environmental and investments and integration for the three months ended March 31, 2026, and the estimated forecast for the remainder of the year.

Current wording

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.

Previous wording

Investments and Integration for the three months ended March 31, 2026 include growth expenditures, integration, small book acquisitions and other investments.

Current wording

Investments and Integration for the six months ended June 30, 2026 include growth expenditures, integration, small book acquisitions and other investments.

Previous wording

NRG estimates that environmental capital expenditures from 2026 through 2030 required to comply with environmental laws will be approximately $33 million, primarily driven by the cost of complying with ELG at the Company’s coal units in Texas.

Current wording

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.

Previous 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.

Current wording

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.