NRG ENERGY, INC.

Previous wording

•Liquidity and capital resources including liquidity position, financial condition addressing credit ratings, material cash requirements and commitments, and other obligations; and

Current wording

•Liquidity and capital resources including liquidity position, financial condition addressing credit ratings, material cash requirements and commitments, and other obligations.

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, 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 and six months ended June 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.

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 delivers 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 March 31, 2025, the Company’s core power and natural gas business consists of approximately 13 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, is a leading energy and smart home company powering a brighter, smarter future. The Company delivers 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 June 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.

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.

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 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.

Previous wording

Texas Energy Fund —Through Senate Bill 2627, the Texas Legislature created the Texas Energy Fund, 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 Texas Energy Fund 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. Availability of grant funds may be impacted by the 10,000 MW collective cap on the ERCOT loan and grant program.

Current 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 Texas Energy Fund 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.

Previous wording

On August 29, 2024, the PUCT approved an initial portfolio of projects to move into a due diligence process with its third-party administrator. NRG THW GT LLC's 415 MW gas peaking unit, which is projected to become commercially operational in 2026, was among the projects selected to move into due diligence, and that process is underway. On December 12, 2024, the PUCT approved Cedar Bayou Unit 5’s 689 MW combined cycle generating facility project to move into due diligence. On March 13, 2025, the PUCT approved Greens Bayou Unit 6’s 448 MW gas peaking unit project to move into due diligence. Cedar Bayou Unit 5 and Greens Bayou Unit 6 are projected to become commercially operational in 2028. Approximately 9,218 MWs of projects overall are currently approved to undergo due diligence.

Current wording

On August 29, 2024, the PUCT approved an initial portfolio of projects to move into a due diligence process with its third-party administrator. T.H. Wharton generation facility's 415 MW gas peaking unit, which is projected to become commercially operational in 2026, was among the projects selected to move into due diligence, and that process is underway. On December 12, 2024, the PUCT approved Cedar Bayou Unit 5’s 689 MW combined cycle generating facility project to move into due diligence. On March 13, 2025, the PUCT approved Greens Bayou Unit 6’s 443 MW gas peaking unit project to move into due diligence. Cedar Bayou Unit 5 and Greens Bayou Unit 6 are projected to become commercially operational in 2028.

Previous wording

Real-time Co-optimization of Energy and Ancillary Services ("RTC") — ERCOT is progressing with a multi-year project to upgrade its systems to co-optimize the dispatch of energy and ancillary services in real-time. The RTC project will also replace the Operating Reserve Demand Curve with demand curves for each ancillary service product which will act as the primary scarcity pricing mechanism when energy or ancillary services are in shortage. ERCOT anticipates commencing market trials for testing the RTC project in Spring 2025 with production to go-live on December 5, 2025.

Current wording

Real-time Co-optimization of Energy and Ancillary Services (“RTC”) — ERCOT is progressing with a multi-year project to upgrade its systems to co-optimize the dispatch of energy and ancillary services in real-time. The RTC project will also replace the Operating Reserve Demand Curve with demand curves for each ancillary service product which will act as the primary scarcity pricing mechanism when energy or ancillary services are in shortage. ERCOT has commenced market trials for testing the RTC project which began in Spring 2025 and will continue through Fall 2025 with production to go-live on December 5, 2025.

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. Multiple parties, including NRG, filed for rehearing. Rehearing was denied by operation of law, and multiple parties, including the Company, filed appeals to the Third Circuit Court of Appeals. On March 12, 2024, the court vacated the portion of the FERC orders that allow PJM to apply the LDA Reliability Requirement to the 2024/2025 capacity auction. On March 29, 2024, PJM filed a petition seeking confirmation as to the capacity commitments rules for the 2024/2025 auction. On April 22, 2024, multiple parties filed a complaint seeking to find the revised rate unjust and unreasonable and implement rates consistent with FERC's February 2023 decision, which was denied on July 9, 2024. Those parties filed an appeal to the Court of Appeals for the D.C. Circuit on November 5, 2024.

Current 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. Multiple parties, including NRG, filed for rehearing. Rehearing was denied by operation of law, and multiple parties, including the Company, filed appeals to the Third Circuit Court of Appeals. On March 12, 2024, the court vacated the portion of the FERC orders that allow PJM to apply the LDA Reliability Requirement to the 2024/2025 capacity auction. On March 29, 2024, PJM filed a petition seeking confirmation as to the capacity commitments rules for the 2024/2025 auction. On April 22, 2024, multiple parties filed a complaint seeking to find the revised rate unjust and unreasonable and implement rates consistent with

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. The 2026/2027 BRA is currently scheduled for July 2025.

Current 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.

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. Federal and state environmental laws generally have become more stringent over time. Future laws may require the addition of emissions controls or other environmental controls or impose restrictions on the Company's operations 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 support existing generation with less burdensome regulation that will affect the outcome of the rulemakings 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 impose restrictions on the Company's operations 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 ease the regulatory burden on the electric generation industry, which may 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.

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 U.S. presidential administration evaluates the rule. The court granted the motion on February 19, 2025.

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 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.

Previous wording

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' 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’ 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: (i) various state disapprovals; (ii) the final rule promulgated on June 5, 2023; and (iii) the interim final rule promulgated on July 31, 2023 that seeks to address the judicial orders.

Current wording

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' 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’ 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.

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. Accordingly, 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. Accordingly, the outcome of this rulemaking is uncertain. The Company anticipates that the U.S. presidential administration will substantively revise this rule.

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. In 2017, the EPA promulgated a final rule that, among other things, postponed the compliance dates to preserve the status quo for FGD wastewater and bottom ash transport water by two years to November 2020 until the EPA amended the rule. On October 13, 2020, the EPA amended the 2015 ELG rule by: (i) altering the stringency of certain limits for FGD wastewater; (ii) relaxing the zero-discharge requirement for bottom ash transport water; and (iii) changing several deadlines. In October 2021, NRG informed its regulators that the Company intends to comply with the ELG by ceasing combustion of coal by the end of 2028 at its domestic coal units outside of Texas, and installing appropriate controls by the end of 2025 at its two plants that have coal-fired units in Texas. On May 9, 2024, the EPA promulgated a rule that 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 have been 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.

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. In 2017, the EPA promulgated a final rule that, among other things, postponed the compliance dates to preserve the status quo for FGD wastewater and bottom ash transport water by two years to November 2020 until the EPA amended the rule. On October 13, 2020, the EPA amended the 2015 ELG rule by: (i) altering the stringency of certain limits for FGD wastewater; (ii) relaxing the zero-discharge requirement for bottom ash transport water; 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 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 have been 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. During the second quarter of 2025, the EPA announced its intent to update the 2024 rule to advance the goals of the current U.S.

Previous wording

On May 12, 2025, NRG entered into a definitive agreement with LS Power to acquire a power portfolio including 13 GW of natural gas-fired generation facilities and the C&I VPP platform with 6 GW of capacity. The consideration will consist of 24.25 million shares of NRG common stock, $6.4 billion in cash, and the assumption of $3.2 billion of debt, in addition to working capital. The acquisition is targeted to close in the first quarter of 2026, and is subject to the satisfaction or waiver of specified closing conditions, consents and regulatory approvals, including HSR, FERC, DOJ, and NYSPSC. For further discussion, see Note 4, Acquisitions.

Current wording

On May 12, 2025, NRG entered into a definitive agreement with LS Power to acquire a power portfolio including 13 GW of natural gas-fired generation facilities and the C&I VPP platform with 6 GW of capacity. The consideration will consist of 24.25 million shares of NRG common stock and $6.4 billion in cash, subject to working capital adjustments as set forth in the purchase agreement. As part of the transaction, NRG will also assume $3.2 billion of debt. The acquisition is expected to close in the first quarter of 2026, and is subject to the satisfaction or waiver of specified closing conditions, consents and regulatory approvals, including HSR, FERC, DOJ, and NYSPSC. For further discussion, see Note 4, Acquisitions.

Previous wording

On April 10, 2025, the Company acquired all of the ownership interests of six power generation facilities from Rockland Capital, LLC, adding 738 MW of natural gas-fired assets in Texas to its portfolio for $560 million in consideration, subject to working capital adjustments. For further discussion, see Note 4, Acquisitions. As a result, the Company acquired the following generation facilities:

Current wording

On April 10, 2025, the Company acquired all of the ownership interests of six power generation facilities from Rockland Capital, LLC, adding 738 MW of natural gas-fired assets in Texas to its portfolio for $560 million in consideration, less $1 million in initial working capital adjustments. For further discussion, see Note 4, Acquisitions. The Company acquired the following generation facilities:

Previous wording

(a) Actual capacity based on acquisition date and can vary depending on factors including weather conditions, operational conditions, and other factors. Additionally, ERCOT requires periodic demonstration of capability, and the capacity may vary individually and in the aggregate from time to time

Current wording

(a) Capacity is an estimate as of the acquisition date and can vary depending on factors including weather conditions, operational conditions, and other factors. Additionally, ERCOT requires periodic demonstration of capability, and the capacity may vary individually and in the aggregate from time to time

Previous wording

During the three months ended March 31, 2025, the Company completed $320 million of open market share repurchases at an average price of $99.52 per share. Through April 30, 2025, an additional $125 million of share repurchases were executed at an average price of $92.77 per share. As of April 30, 2025, $1.2 billion is remaining under the $3.7 billion authorization. See Note 9, Changes in Capital Structure for additional discussion.

Current wording

During the six months ended June 30, 2025, the Company completed $600 million of open market share repurchases at an average price of $107.14 per share. Through July 31, 2025, an additional $168 million share repurchases were completed. As of July 31, 2025, $857 million is remaining under the $3.7 billion authorization. See Note 9, Changes in Capital Structure for additional discussion.

Previous wording

In March 2025, the PUCT selected the 443 MW Greens Bayou project to advance to the next phase of due diligence, marking the third NRG project chosen under the TEF due diligence process. This project is expected to be operational in 2028.

Current wording

On July 31 2025, NRG entered into a $216 million loan agreement with the PUCT under the TEF to support development at its T.H. Wharton generation facility, which is currently under construction. The TEF loan bears interest at a fixed coupon rate of 3.000% per annum and has a final maturity date of July 31, 2045. The initial disbursement of funds for the TEF loan occurred in July 2025, and commercial operation of the 415 MW facility is expected by summer 2026. In March 2025, the PUCT selected the 443 MW Greens Bayou project to advance to the next phase of due diligence, marking the third NRG project chosen under the TEF due diligence process. This project is expected to be operational in 2028.

Previous wording

The following table summarizes average on peak power prices for each of the major markets in which NRG operates for the three months ended March 31, 2025 and 2024. Texas, East and MISO average on-peak power prices increased for the three months ended March 31, 2025 as compared to the same period in 2024 as a result of higher natural gas prices, while average CAISO on-peak power prices decreased primarily due to mild winter weather in California in 2025.

Current wording

The following table summarizes average on peak power prices for each of the major markets in which NRG operates for the three months ended June 30, 2025 and 2024.

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 $141 million during the three months ended March 31, 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 $1.2 billion during the three months ended June 30, 2025, compared to the same period in 2024.

Previous 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. For further discussion, see Note 6, Accounting for Derivative Instruments and Hedging Activities

Current wording

(a)Includes $30 million, within the Texas segment, related to derivative contracts that were elected as NPNS on October 1, 2024 and are no longer valued at fair value on a recurring basis. For further discussion, see Note 6, Accounting for Derivative Instruments and Hedging Activities

Previous wording

For the three months ended March 31, 2024, the $60 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 and a decrease in the value of East open positions as a result of increases in PJM power prices. The $532 million gain in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized losses on contracts that settled during the period and an increase in the value of open positions in Texas and East as a result of increases in ERCOT and PJM power prices, partially offset by a decrease in the value of open positions in West/Services/Other as a result of decreases in CAISO and Canada 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

Interest expense increased by $11 million for the three months ended March 31, 2025, compared to the same period in 2024, primarily driven by unrealized losses on interest rate swaps for the 2025 period as compared to unrealized gains in the 2024 period.

Current wording

Operations and maintenance expense increased by $11 million for the three months ended June 30, 2025, compared to the same period in 2024, due to the following:

Previous wording

Other cost of operations for the three months ended March 31, 2025 decreased by $9 million, when compared to the same period in 2024, due to the following:

Current wording

Other cost of operations for the three months ended June 30, 2025 increased by $29 million, when compared to the same period in 2024, due to the following:

Previous wording

Depreciation and amortization decreased by $7 million for the three months ended March 31, 2025, compared to the same period in 2024, due to the following:

Current wording

Depreciation and amortization decreased by $16 million for the three months ended June 30, 2025, compared to the same period in 2024, due to the following:

Previous wording

A loss on debt extinguishment of $58 million was recorded for the three months ended March 31, 2024, driven by the repurchase of portion of the Convertible Senior Notes.

Current wording

A loss on debt extinguishment of $202 million was recorded for the three months ended June 30, 2024, driven by the repurchase of a portion of the Convertible Senior Notes.

Previous wording

For the three months ended March 31, 2025, income tax expense of $235 million was recorded on pre-tax income of $985 million. For the same period in 2024, an income tax expense of $184 million was recorded on pre-tax income of $695 million. The effective tax rates were 23.9% and 26.5% for the three months ended March 31, 2025 and 2024, respectively.

Current wording

For the three months ended June 30, 2025, income tax benefit of $49 million was recorded on pre-tax loss of $153 million. For the same period in 2024, an income tax expense of $314 million was recorded on pre-tax income of $1.1 billion. The effective tax rates were 32.0% and 29.8% for the three months ended June 30, 2025 and 2024, respectively.

Previous wording

For the three months ended March 31, 2025 and 2024, the effective tax rate was higher than the statutory rate of 21% primarily due to the state tax expense.

Current wording

For the three months ended June 30, 2025, the effective tax rate was higher than the statutory rate of 21%, primarily due to the state tax benefit and permanent differences. For the same period in 2024, the effective tax rate was higher than the statutory rate of 21% primarily due to the state tax expense and permanent differences.

Previous wording

Gross margin increased $175 million and economic gross margin increased $266 million during the three months ended March 31, 2025, compared to the same period in 2024.

Current wording

Gross margin decreased $989 million and economic gross margin increased $257 million, both of which include intercompany sales, during the six months ended June 30, 2025, compared to the same period in 2024.

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 driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period and a decrease in the value of East open positions 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 Texas open positions 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

Operations and maintenance expense decreased by $80 million for the three months ended March 31, 2025, compared to the same period in 2024, due to the following:

Current wording

Operations and maintenance expense decreased by $69 million for the six months ended June 30, 2025, compared to the same period in 2024, due to the following:

Previous wording

Other income, net decreased by $18 million for the three months ended March 31, 2025, compared to the same period in 2024, primarily due to an indemnity reduction of $12 million recorded in 2024 .

Current wording

Other income, net decreased by $17 million for the six months ended June 30, 2025, compared to the same period in 2024, primarily due to lower interest income in 2025 and an indemnity reduction recorded in 2024.

Previous wording

As of March 31, 2025 and December 31, 2024, NRG's total liquidity, excluding funds deposited by counterparties, of approximately $5.2 billion and $5.4 billion, respectively, was comprised of the following:

Current wording

As of June 30, 2025 and December 31, 2024, NRG's total liquidity, excluding funds deposited by counterparties, of approximately $5.3 billion and $5.4 billion, respectively, was comprised of the following:

Previous wording

(b) Total capacity of Revolving Credit Facility and collective collateral facilities was $7.2 billion and $7.3 billion as of March 31, 2025 and December 31, 2024, respectively

Current wording

(b) Total capacity of Revolving Credit Facility and collective collateral facilities was $7.8 billion and $7.3 billion as of June 30, 2025 and December 31, 2024, respectively

Previous wording

For the three months ended March 31, 2025, total liquidity, excluding funds deposited by counterparties, decreased by $225 million. Changes in cash and cash equivalent balances are further discussed hereinafter under the heading Cash Flow Discussion. Cash and cash equivalents at March 31, 2025 were predominantly held in bank deposits.

Current wording

For the six months ended June 30, 2025, total liquidity, excluding funds deposited by counterparties, decreased by $188 million. Changes in cash and cash equivalent balances are further discussed under the heading Cash Flow Discussion. Cash and cash equivalents at June 30, 2025 were predominantly held in bank deposits.

Previous wording

On May 12, 2025, NRG entered into a definitive agreement with LS Power to acquire a power portfolio including 13 GW of natural gas-fired generation facilities and the C&I VPP platform with 6 GW of capacity. The consideration will consist of 24.25 million shares of NRG common stock, $6.4 billion in cash, and the assumption of $3.2 billion of debt, in addition to working capital. The Company expects to fund the acquisition using a combination of newly-issued secured and unsecured debt, equity issuance and cash on hand. The acquisition is targeted to close in the first quarter of 2026 and is subject to the satisfaction or waiver of specified closing conditions, consents and regulatory approvals, including HSR, FERC, DOJ, and NYSPSC. For further discussion, see Note 4, Acquisitions.

Current wording

On May 12, 2025, NRG entered into a definitive agreement with LS Power to acquire a power portfolio including 13 GW of natural gas-fired generation facilities and the C&I VPP platform with 6 GW of capacity. The consideration will consist of 24.25 million shares of NRG common stock, and $6.4 billion in cash, subject to working capital adjustments as set forth in the purchase agreement. As part of the transaction, NRG will also assume $3.2 billion of debt. The Company expects to fund the cash portion of the consideration using a combination of newly-issued secured debt and cash on hand. The acquisition is expected to close in the first quarter of 2026 and is subject to the satisfaction or waiver of specified closing conditions, consents and regulatory approvals, including HSR, FERC, DOJ, and NYSPSC. For further discussion, see Note 4, Acquisitions.

Previous wording

On April 10, 2025, the Company acquired all of the ownership interests of six power generation facilities from Rockland Capital, LLC, adding 738 MW of natural gas-fired assets in Texas to its portfolio for $560 million in consideration, subject to working capital adjustments. For further discussion, see Note 4, Acquisitions.

Current wording

On April 10, 2025, the Company acquired all of the ownership interests of six power generation facilities from Rockland Capital, LLC, adding 738 MW of natural gas-fired assets in Texas to its portfolio for $560 million in consideration, less $1 million in initial working capital adjustments. For further discussion, see Note 4, Acquisitions.

Previous wording

The Company intends to spend approximately $270 million from cash from operations on liability management during 2025. The Company remains committed to maintaining a strong balance sheet and its targeted credit metrics.

Current wording

The Company has currently spent $263 million and intends to spend approximately $12 million from cash from operations on liability management during the remainder of 2025. The Company remains committed to maintaining a strong balance sheet and its targeted credit metrics.

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, 2025, market operations had total cash collateral outstanding of $217 million and $2.7 billion outstanding in letters of credit to third parties primarily to support its market activities. As of March 31, 2025, total funds deposited by counterparties were $730 million in cash and $653 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, 2025, market operations had total cash collateral outstanding of $361 million and $2.7 billion outstanding in letters of credit to third parties primarily to support its market activities. As of June 30, 2025, total funds deposited by counterparties were $446 million in cash and $454 million of letters of credit.