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.

Current wording

•Liquidity and capital resources including liquidity position, 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 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.

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 nine months ended September 30, 2026 and 2025. Also refer to NRG’s 2025 Form 10-K, which includes detailed discussions of various items impacting the Company’s business, results of operations and financial condition, including: General section; Strategy section; Business Overview section, including how regulation, weather, and other factors affect NRG’s business; and Critical Accounting Estimates section.

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) 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.

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 such as demand response and virtual power plants (“VPP”), which help manage costs and improve affordability for customers, (ii) completing the Texas Development Projects, (iii) long-term, contract-backed generation and related infrastructure, supported by strategic partnerships with equipment manufacturers and engineering, procurement, and construction companies, and (iv) increasing capacity at existing facilities. The Company’s differentiated model is built to meet North America’s evolving needs while delivering affordable, reliable solutions for customers and long-term growth for shareholders. This strategy is intended to generate recurring cash flow, strengthen earnings and cost competitiveness, and reduce risk and volatility.

Previous wording

In the first quarter of 2026, the operations acquired from LS Power were integrated into the Company’s existing segment structure, enhancing scale and portfolio optimization across the platform. In Texas, the Company’s generation portfolio is fully integrated with its retail load and in early 2026, the Company adopted an integrated strategy in the East, expanding this model across a broader geographic footprint. The integrated model strategically aligns generation and retail, enabling the Company to supply a portion of its retail customers with electricity from Company-owned assets, thereby reducing reliance to procure electricity from other institutions and intermediaries and supporting more stable earnings and cash flows, lower transaction costs, and reduced credit exposure. The integrated model also results in a reduction in actual and contingent collateral requirements, improving capital efficiency and further limiting transactions with third parties.

Current wording

Beginning in the first quarter of 2026, the operations acquired from LS Power were integrated into the Company’s existing segment structure, enhancing scale and portfolio optimization across the platform. In Texas, the Company’s generation portfolio is fully integrated with its retail load and, in early 2026, the Company adopted an integrated strategy in the East, expanding this model across a broader geographic footprint. The integrated model strategically aligns generation and retail, enabling the Company to supply a portion of its retail customers with electricity from Company-owned assets, thereby reducing reliance to procure electricity from other institutions and intermediaries and supporting more stable earnings and cash flows, lower transaction costs, and reduced credit exposure. The integrated model also results in a reduction in actual and contingent collateral requirements, improving capital efficiency and further limiting transactions with third parties.

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. 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.

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. 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

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.

Current wording

Senate Bill 6— On June 20, 2025, Governor Abbot, the Governor of Texas, signed SB 6 into law, which includes various provisions that concern how ERCOT, transmission and distribution utilities, and power generation companies plan for and serve large loads (defined as 75 MWs and above) in the ERCOT market, including provisions relating to forecasting accuracy, large load interconnection standards, processes and incentives for curtailment, PUCT review of certain proposed co-locations, and an investigation of transmission cost allocation and rate design. The PUCT has adopted final rules related to load forecasting accuracy, co-location, and large load interconnection standards, but the rulemaking process for cost allocation and rate design, as well as incentives or requirements to curtail operations, are in progress. With respect to large load interconnection standards, on September 18, 2026, the PUCT adopted a final rule, which establishes the standards and criteria to interconnect a large load customer to the ERCOT system, including required posting of financial security. ERCOT has also developed revisions to the interconnection study process to more efficiently review large load interconnection requests, which the PUCT approved on June 18, 2026.

Previous 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.

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. On July 31, 2026, PJM filed at FERC to implement the Reliability Backstop Procurement proposal, under which there would be a central procurement process to procure capacity for the approximately 6,800 MW shortfall identified in the 2028/2029 BRA. On September 29, 2026, FERC accepted PJM’s proposed Reliability Backstop Procurement tariff revisions for filing, suspended them for five months to become effective February 28, 2027, subject to refund and further Commission order, and established paper-hearing procedures to further develop the record regarding issues raised by the proposal. As a result, the procurement will not proceed according to the schedule originally proposed by PJM.

Previous wording

Indian River RMR Proceeding — On June 29, 2021, Indian River notified PJM that it intended to retire Unit 4. PJM identified reliability violations resulting from the proposed deactivation of Unit 4. The Company filed a cost based RMR rate schedule at FERC. The Company reached settlement with a number of the intervening parties and the settlement agreement was filed. On January 16, 2025, FERC issued an order approving the settlement agreement. Indian River Unit 4 retired on February 23, 2025. On May 19, 2025, Maryland Office of People’s Counsel filed an appeal to the Court of Appeals for the Fourth Circuit of FERC’s denial on its request for rehearing. On August 22, 2025, NRG filed a motion to transfer venue. On November 12, 2025, the motion to transfer venue was granted and the appeal was transferred to the Court of Appeals for the D.C. Circuit. The appeal is pending.

Current wording

Indian River RMR Proceeding — On June 29, 2021, Indian River notified PJM that it intended to retire Unit 4. PJM identified reliability violations resulting from the proposed deactivation of Unit 4. The Company filed a cost based RMR rate schedule at FERC. The Company reached settlement with a number of the intervening parties and the settlement agreement was filed. On January 16, 2025, FERC issued an order approving the settlement agreement. Indian River Unit 4 retired on February 23, 2025. On May 19, 2025, Maryland Office of People’s Counsel filed an appeal to the Court of Appeals for the Fourth Circuit of FERC’s denial on its request for rehearing. On August 22, 2025, NRG filed a motion to transfer venue. On November 12, 2025, the motion to transfer venue was granted and the appeal was transferred to the Court of Appeals for the D.C. Circuit. The appeal is pending, and briefing is underway.

Previous wording

NRG is subject to numerous environmental laws in the development, construction, ownership and operation of power plants. These laws generally require that governmental permits and approvals be obtained before construction and maintained during operation of power plants. In general, the electric generation industry has faced increasingly stringent requirements regarding air quality, GHG emissions, combustion byproducts, water use and discharge, and threatened and endangered species including several rules promulgated in 2024. Future laws may require the addition of emissions controls or other environmental controls or to impose additional restrictions the operations of the Company’s facilities including unit retirements or impose obligations related to historic coal ash use, storage and disposal. At the federal level, the President has issued several Executive Orders that indicate that the current administration intends to relax or rescind some previously promulgated regulations. The EPA has proposed several and finalized some rules that relax and/or rescind regulations previously promulgated. Complying with environmental laws often involves specialized human resources and significant capital and operating expenses, as well as occasionally curtailing operations. NRG decides to invest capital for environmental controls based on the relative certainty of the requirements, an evaluation of compliance options and the expected economic returns on capital.

Current wording

NRG is subject to numerous environmental laws in the development, construction, ownership and operation of power plants. These laws generally require that governmental permits and approvals be obtained before construction and maintained during operation of power plants. In general, the electric generation industry has faced increasingly stringent requirements regarding air quality, GHG emissions, combustion byproducts, water use and discharge, and threatened and endangered species including several rules promulgated in 2024. Future laws may require the addition of emissions controls or other environmental controls or to impose additional restrictions on the operations of the Company’s facilities including unit retirements or impose obligations related to historic coal ash use, storage and disposal. At the federal level, the President has issued several Executive Orders that indicate that the current administration intends to relax or rescind some previously promulgated regulations. The EPA has proposed several and finalized some rules that relax and/or rescind regulations previously promulgated. Complying with environmental laws often involves specialized human resources and significant capital and operating expenses, as well as occasionally curtailing operations. NRG decides to invest capital for environmental controls based on the relative certainty of the requirements, an evaluation of compliance options and the expected economic returns on capital.

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 would be regulated including capturing and storing/sequestering CO 2 in some instances. This rule has been challenged by numerous parties in the D.C. Circuit including 27 states with 22 states intervening in support of the rule. The D.C. Circuit held oral arguments related to this rule in December 2024. In February 2025, the court granted a motion the DOJ filed asking the court to hold proceedings in abeyance while the EPA evaluates the rule. On June 17, 2025, the EPA proposed to repeal all GHG emission standards for fossil fuel-fired power plants under Section 111 of the CAA. The EPA is proposing to conclude that GHG emissions from domestic fossil fuel-fired EGUs do not contribute to dangerous air pollution at a level sufficient to invoke the EPA’s authority under CAA Section 111. In addition to its primary proposal to repeal all GHG emission standards for the power sector promulgated in both 2015 and 2024, the EPA has included an alternative proposal to repeal just specific portions. On February 18, 2026, the EPA rescinded the 2009 GHG Endangerment Finding related to motor vehicle emissions. Although this rescission does not directly alter the GHG regulations related to power plants, the Company believes that the EPA may amend such regulations this year.

Current wording

CPP/ACE Rules— The attention in recent years on GHG emissions has resulted in federal and state regulations. In 2019, the EPA promulgated the ACE rule, which rescinded the CPP, which had sought to broadly regulate CO 2 emissions from the power sector. On January 19, 2021, the D.C. Circuit vacated the ACE rule (but on February 22, 2021, at the EPA’s request, stayed the issuance of the portion of the mandate that would vacate the repeal of the CPP). On June 30, 2022, the U.S. Supreme Court held that the “generation shifting” approach in the CPP exceeded the powers granted to the EPA by Congress. On May 9, 2024, the EPA promulgated a rule that repealed the ACE rule and significantly revised the manner in which new combustion-turbine and existing steam EGU’s GHG emissions would be regulated including capturing and storing/sequestering CO 2 in some instances. This rule was challenged by numerous parties in the D.C. Circuit including 27 states with 22 states intervening in support of the rule. The D.C. Circuit held oral arguments related to this rule in December 2024. In February 2025, the court granted a motion the DOJ filed asking the court to hold proceedings in abeyance while the EPA evaluated the rule. On September 17, 2026, the EPA finalized a rule repealing many of the provisions of the 2024 Carbon Pollution Standards applicable to fossil fuel-fired EGUs and proposed rescinding the remaining GHG emission requirements for fossil fuel-fired power plants. On the same day, the rule was challenged in the DC Circuit and the outcome of the legal challenges is uncertain.

Previous wording

Regional Haze — In May 2023, the EPA proposed to withdraw the existing Texas Sulfur Dioxide Trading Program and replace it with unit-specific SO 2 limits for 12 units in Texas to address requirements to improve visibility at National Parks and Wilderness areas. The Company does not expect this proposal to be finalized during the current U.S. presidential administration. On December 5, 2025, the EPA approved Texas’s plans to address the Regional Haze rule.

Current wording

Regional Haze — In May 2023, the EPA proposed to withdraw the existing Texas Sulfur Dioxide Trading Program and replace it with unit-specific SO 2 limits for 12 units in Texas to address requirements to improve visibility at National Parks and Wilderness areas. On December 5, 2025, the EPA approved Texas’s plans to address the Regional Haze rule.

Previous wording

On January 30, 2026, NRG completed the acquisition of the LSP Portfolio from LS Power. The acquisition doubles NRG’s generation capacity with the addition of 18 natural gas-fired and dual fuel facilities totaling approximately 13 GW. In addition, NRG acquired CPower, a leading demand response platform, which operates in all the country’s deregulated energy markets and has more than 2,000 commercial and industrial customers. The consideration consisted of 24.25 million shares of NRG common stock and $6.4 billion in cash, plus preliminary working capital and certain other adjustments of $483 million. The Company funded the cash consideration using a portion of the net proceeds of $4.4 billion from the 5.750% 2034 Senior Notes, the 2036 Senior Notes, Senior Secured First Lien Notes, due 2030 and the Senior Secured First Lien Notes, due 2035 and proceeds of $2.5 billion from the Company’s Revolving Credit Facility. For further discussion, see Note 4, Acquisitions.

Current wording

On January 30, 2026, NRG completed the acquisition of the LSP Portfolio from LS Power. The acquisition doubles NRG’s generation capacity with the addition of 18 natural gas-fired and dual fuel facilities totaling approximately 13 GW. In addition, NRG acquired CPower, a leading demand response platform, which operates in all the country’s deregulated energy markets and has more than 2,000 commercial and industrial customers. The consideration consisted of 24.25 million shares of NRG common stock and $6.4 billion in cash, plus working capital and certain other adjustments of $472 million. The Company funded the cash consideration using a portion of the net proceeds of $4.4 billion from the 5.750% 2034 Senior Notes, the 2036 Senior Notes, Senior Secured First Lien Notes, due 2030 and the Senior Secured First Lien Notes, due 2035 and proceeds of $2.5 billion from the Company’s Revolving Credit Facility. For further discussion, see Note 4, Acquisitions and Dispositions.

Previous 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.

Current wording

During the nine months ended September 30, 2026, the Company completed $963 million of share repurchases at an average price of $154.45 per share. Through October 31, 2026, an additional $14 million of share repurchases were executed at an average price of $99.62 per share. On November 6, 2026, in connection with its approval of the sale of 4.9 GW of generation assets to LS Power, the Board of Directors approved an additional $1.0 billion of share repurchases. See Note 9, Changes in Capital Structure for additional discussion.

Previous wording

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

Current wording

In the first quarter of 2026, NRG increased the annual common stock dividend to $1.90 from $1.76 per share, representing an 8% increase from 2025. Beginning in the first quarter of 2027, NRG will increase the annual dividend by 8% to $2.05 per share. The Company targets an annual dividend growth rate of 7-9% per share in subsequent years.

Previous wording

On April 28, 2026, the Company and APX Group LLC, as borrowers, and certain of the Company’s subsidiaries, as guarantors, entered into the Sixteenth Amendment to the Credit Agreement. For further discussion, see Note 7, Long-term Debt and Finance Leases.

Current wording

On April 28, 2026, the Company and APX Group LLC, as borrowers, and certain of the Company’s subsidiaries, as guarantors, entered into the Sixteenth Amendment to the Credit Agreement to establish new term loans in aggregate principal amount of $900 million. For further discussion, see Note 7, Long-term Debt and Finance Leases.

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 June 30, 2026, $784 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 September 30, 2026, $655 million was issued under these facilities.

Previous wording

Geopolitical Developments — The ongoing geopolitical conflicts, including hostilities with Iran and conflicts in the Middle East, have contributed to elevated and volatile oil prices and could, over time, put upward pressure on U.S. natural gas. Prolonged market volatility could result in increased collateral requirements and heighten counterparty credit exposure under NRG’s hedging arrangements.

Current wording

Geopolitical Developments — The ongoing geopolitical conflicts, including hostilities with Iran and conflicts in the Middle East, and the potential for further escalation and disruption, have contributed to elevated and volatile oil prices and could, over time, put upward pressure on U.S. natural gas prices. Prolonged market volatility could result in increased collateral requirements and heighten counterparty credit exposure under NRG’s hedging arrangements.

Previous 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.

Current wording

Gross margin increased $775 million and economic gross margin increased $700 million during the three months ended September 30, 2026, compared to the same period in 2025.

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 increased by $572 million during the three months ended June 30, 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 $221 million during the three months ended September 30, 2026, compared to the same period in 2025.

Previous 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.

Current wording

For the three months ended September 30, 2025, the $34 million gain in revenues from economic hedge positions was driven primarily by an increase in the value of open positions as a result of decreases in natural gas prices and the reversal of previously recognized unrealized losses on contracts that settled during the period. The $410 million loss in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period and a decrease in the value of open positions in West as a result of decreases in CAISO power prices.

Previous 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:

Current wording

Other cost of operations for the three months ended September 30, 2026 increased by $27 million, when compared to the same period in 2025, due to the following:

Previous 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:

Current wording

Acquisition-related transaction and integration costs of $16 million and $8 million for the three months ended September 30, 2026 and 2025, respectively, include:

Previous wording

Interest expense increased by $284 million for the six months ended June 30, 2026, compared to the same period in 2025. The incremental interest expense is primarily attributable to the LSP acquisition, including the borrowing to finance the acquisition, the assumption of Lightning debt, and the refinancing activity occurred during the six months ended June 30, 2026. For further discussion, see Note 4, Acquisitionsand Note 7, Long-term Debt and Finance Leases.

Current wording

Interest expense increased by $115 million for the three months ended September 30, 2026, compared to the same period in 2025. The incremental interest expense is primarily attributable to the LSP Portfolio acquisition, including the borrowing to finance the acquisition and the assumption of Lightning debt. For further discussion, see Note 4, Acquisitions and Dispositionsand Note 7, Long-term Debt and Finance Leases.

Previous 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.

Current wording

For the three months ended September 30, 2026, income tax expense of $218 million was recorded on pre-tax income of $779 million. For the same period in 2025, an income tax expense of $86 million was recorded on pre-tax income of $238 million. The effective tax rates were 28.0% and 36.1% for the three months ended September 30, 2026 and 2025, respectively.

Previous wording

For the three months ended June 30, 2026 the effective tax rate was higher than the statutory rate of 21%, primarily due to the state tax expense, partially offset with favorable permanent differences. For the same period in 2025, NRG's effective tax rate was higher than the statutory rate of 21%, primarily due to the state tax benefit and permanent differences.

Current wording

For the three months ended September 30, 2026 and 2025, the effective tax rate was higher than the statutory rate of 21%, primarily due to the state tax expense.

Previous wording

The following table summarizes average on peak power prices for each of the major markets in which NRG operates for the six months ended June 30, 2026 and 2025:

Current wording

The following table summarizes average on peak power prices for each of the major markets in which NRG operates for the nine months ended September 30, 2026 and 2025:

Previous wording

The following table summarizes the average Henry Hub natural gas price for the six months ended June 30, 2026 and 2025:

Current wording

The following table summarizes the average Henry Hub natural gas price for the nine months ended September 30, 2026 and 2025:

Previous wording

The following tables present the composition and reconciliation of gross margin and economic gross margin for the six months ended June 30, 2026 and 2025:

Current wording

The following tables present the composition and reconciliation of gross margin and economic gross margin for the nine months ended September 30, 2026 and 2025:

Previous wording

The following table represents the weather metrics for the six months ended June 30, 2026 and 2025:

Current wording

The following table represents the weather metrics for the nine months ended September 30, 2026 and 2025:

Previous wording

Gross margin increased $212 million and economic gross margin increased $402 million, both of which include intercompany sales, during the six months ended June 30, 2026, compared to the same period in 2025.

Current wording

Gross margin increased $987 million and economic gross margin increased $1.1 billion, both of which include intercompany sales, during the nine months ended September 30, 2026, compared to the same period in 2025.

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 increased by $36 million during the six months ended June 30, 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 $257 million during the nine months ended September 30, 2026, compared to the same period in 2025.

Previous 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.

Current wording

For the nine months ended September 30, 2026, the $26 million loss in revenues from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period. The $45 million loss in operating costs and expenses from economic hedge positions was driven primarily by a decrease in the value of open positions as a result of decreases in natural gas prices and Alberta power prices as well as the reversal of previously recognized unrealized gains on contracts that settled during the period, largely offset by the reversal of acquired loss positions related to economic hedges.

Previous wording

For the three months ended June 30, 2026, the $18 million gain in revenues from economic hedge positions was driven primarily by an increase in the value of open positions in East as a result of decreases in NYISO capacity prices. The $271 million gain in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized losses on contracts that settled during the period as well as an increase in the value of open positions in East as a result of increases in RGGI prices.

Current wording

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

Previous wording

In accordance with ASC 815, the following table represents the results of the Company’s financial and physical trading of energy commodities for the six months ended June 30, 2026 and 2025. The realized and unrealized financial and physical trading results are included in revenue. The Company’s trading activities are subject to limits based on the Company’s Risk Management Policy.

Current wording

In accordance with ASC 815, the following table represents the results of the Company’s financial and physical trading of energy commodities for the nine months ended September 30, 2026 and 2025. The realized and unrealized financial and physical trading results are included in revenue. The Company’s trading activities are subject to limits based on the Company’s Risk Management Policy.

Previous wording

Other cost of operations increased by $21 million for the six months ended June 30, 2026, compared to the same period in 2025, due to the following:

Current wording

Other cost of operations increased by $48 million for the nine months ended September 30, 2026, compared to the same period in 2025, due to the following:

Previous wording

Depreciation and amortization increased by $256 million for the six months ended June 30, 2026, compared to the same period in 2025, due to the following:

Current wording

Depreciation and amortization increased by $406 million for the nine months ended September 30, 2026, compared to the same period in 2025, due to the following:

Previous wording

Selling, general and administrative costs decreased by $162 million for the three months ended June 30, 2026, compared to the same period in 2025, due to the following:

Current wording

Selling, general and administrative costs decreased by $111 million for the nine months ended September 30, 2026, compared to the same period in 2025, due to the following:

Previous wording

Acquisition-related transaction and integration costs of $61 million and $51 million for the six months ended June 30, 2026 and 2025, respectively, include:

Current wording

Acquisition-related transaction and integration costs of $77 million and $59 million for the nine months ended September 30, 2026 and 2025, respectively, include:

Previous wording

Interest expense increased by $162 million for the three months ended June 30, 2026, compared to the same period in 2025. The incremental interest expense is primarily attributable to the LSP acquisition, including the borrowing to finance the acquisition, the assumption of Lightning debt, and the refinancing activity occurred during the three months ended June 30, 2026. For further discussion, see Note 4, Acquisitionsand Note 7, Long-term Debt and Finance Leases.

Current wording

Interest expense increased by $399 million for the nine months ended September 30, 2026, compared to the same period in 2025. The incremental interest expense is primarily attributable to the LSP Portfolio acquisition, including the borrowing to finance the acquisition, the assumption of Lightning debt, and the refinancing activity occurred during the nine months ended September 30, 2026. For further discussion, see Note 4, Acquisitions and Dispositionsand Note 7, Long-term Debt and Finance Leases.

Previous wording

For the six months ended June 30, 2026, an income tax expense of $115 million was recorded on a pre-tax income of $746 million. For the same period in 2025, income tax expense of $186 million was recorded on pre-tax income of $832 million. The effective tax rates were 15.4% and 22.4% for the six months ended June 30, 2026 and 2025, respectively.

Current wording

For the nine months ended September 30, 2026, an income tax expense of $333 million was recorded on a pre-tax income of $1.5 billion. For the same period in 2025, income tax expense of $272 million was recorded on pre-tax income of $1.1 billion. The effective tax rates were 21.8% and 25.4% for the nine months ended September 30, 2026 and 2025, respectively.