The report should be read in its entirety as it pertains to each respective reporting company.  No one section of the report deals with all aspects of the subject matter.  Separate Item 7 and 8 sections are provided for each reporting company, except for the Notes to the financial statements.  The Notes to the financial statements for all of the reporting companies are combined.  All Items other than 7 and 8 are combined for the reporting companies.

iii

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FORWARD-LOOKING INFORMATION (Continued)

•the performance of and deliverability of power from Entergy’s generation resources, including the capacity factors at Entergy’s nuclear generating facilities;•increases in costs and capital expenditures that could result from changing regulatory requirements, changing governmental policies, priorities, programs, and actions, including as a result of tariffs, shifts in international trade policies, and other measures, changing or volatile economic conditions, disruptions to pre-existing supply chains and vendor relations, and emerging operating and industry issues, such as anticipated growth in demand from large-scale data centers, and the risks related to recovery of these costs and capital expenditures from Entergy’s customers (especially in an increasing cost environment);•the commitment of substantial human and capital resources required for the safe and reliable operation and maintenance of Entergy’s utility system, including its nuclear generating facilities;•Entergy’s ability to develop and execute on a point of view regarding future prices of electricity, natural gas, and other energy-related commodities;•the prices and availability of fuel and power Entergy must purchase for its Utility customers, particularly given the recent and ongoing significant growth in liquified natural gas exports and the associated significantly increased demand for natural gas and resulting fluctuation in natural gas prices, increasing challenges with respect to natural gas transportation arrangements, and Entergy’s ability to meet credit support requirements for fuel and power supply contracts;•volatility and changes in markets for electricity, natural gas, uranium, emissions allowances, and other energy-related commodities, including as a result of trade-related governmental actions, such as tariffs and other measures, and the effect of those changes on Entergy and its customers;•changes in environmental laws and regulations, agency positions, or associated litigation, including requirements for reduced emissions of sulfur dioxide, nitrogen oxide, greenhouse gases, mercury, particulate matter and other regulated air emissions, heat and other regulated discharges to water, waste management and disposal, remediation of contaminated sites, wetlands protection and permitting, and reporting, and changes in costs of compliance with environmental laws and regulations, as well as changes to federal, state, or local laws and regulations, including the One Big Beautiful Bill Act of 2025, and governmental policies incentivizing the development or utilization of alternative sources of generation;•changes in laws and regulations, agency positions, or associated litigation related to protected species and associated critical habitat designations;•the effects of changes in federal, state, or local laws and regulations, such as the One Big Beautiful Bill Act of 2025, and other governmental actions or policies, including changes in monetary, fiscal, tax, environmental, trade/tariff, domestic purchase requirements, or energy (including, among other things, data center energy use, efficiency standards, and sources of power) policies and related laws, regulations, and other governmental actions, including as a result of prolonged litigation over proposed legislation or regulatory actions;•the effects of full or partial shutdowns of the federal government or delays in obtaining government or regulatory actions or decisions;•uncertainty regarding the establishment of interim or permanent sites for spent nuclear fuel and nuclear waste storage and disposal and the level of spent fuel and nuclear waste disposal fees charged by the U.S. government or other providers related to such sites;•variations in weather and the occurrence of hurricanes and other storms and disasters, including uncertainties associated with efforts to remediate the effects of hurricanes, ice storms, floods, wildfires, or other weather events and the recovery of costs associated with restoration, including the ability to access funded storm reserves, federal and local cost recovery mechanisms, securitization, and insurance, as well as any related unplanned outages;•effects of climate change, including the potential for increases in the frequency or severity of extreme weather events, such as hurricanes, heat waves, floods, drought or wildfires, and rising sea levels or coastal land and wetland loss, and Entergy’s ability to effectively prepare for such effects and events, including through accelerated resilience plans and projects, and any challenges in execution thereof and/or in obtaining any necessary regulatory approvals for appropriate scope and timing of such plans and projects now and in the future;

v

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FORWARD-LOOKING INFORMATION (Continued)

•the risk that as a result of Entergy’s membership in Nuclear Electric Insurance Limited (NEIL), an incident at a NEIL member-insured nuclear generation facility could lead to a significant retrospective assessment;•the risk that an incident at a nuclear generation facility participating in a secondary financial protection system could lead to a significant retrospective insurance premium;•changes in the quality and availability of water supplies and the related regulation of water use and diversion;•Entergy’s ability to manage and execute on its capital projects, including any capital projects to serve the growing demand for electricity driven in part by the anticipated development of large-scale data centers, and to complete such capital projects timely and within budget, to obtain the anticipated performance or other benefits of such capital projects, and to manage its capital and operation and maintenance costs;•the effects of supply chain disruptions, including those driven by geopolitical developments or trade-related governmental actions, including tariffs and other measures, and labor pressures, including from increased demand in the electric sector, on Entergy’s ability to complete its capital projects in a timely and cost-effective manner;•Entergy’s ability to purchase and sell assets at attractive prices and on other attractive terms;•the economic climate, and particularly economic conditions in the Utility service area and events and circumstances that could influence economic conditions in those areas, including power prices and inflation, and the risk that anticipated load growth may not materialize;•changes to or the repeal of federal income tax laws, regulations, and interpretive guidance and policies, including the One Big Beautiful Bill Act of 2025 and the continuing impact of the Inflation Reduction Act of 2022 and the Tax Cuts and Jobs Act of 2017, and any related intended or unintended consequences on financial results and future cash flows;•the effects of Entergy’s strategies to reduce tax payments;•the effect of interest rate volatility and other changes in the financial markets, federal law, including the One Big Beautiful Bill Act of 2025, and regulatory requirements for the issuance of securities, particularly as they affect access to and cost of capital and Entergy’s ability to refinance existing securities and fund investments and acquisitions;•actions of rating agencies, including changes in the ratings of debt and preferred stock, changes in general corporate ratings, and changes in the rating agencies’ ratings criteria;•changes in inflation and interest rates and the impacts of inflation or a recession on Entergy’s customers;•the effects of government investigations, proceedings, or audits;•changes in technology, including (i) Entergy’s ability to effectively assess, acquire, implement, and manage new or emerging technologies, including its ability to maintain and protect personally identifiable information while doing so; (ii) the emergence of artificial intelligence (including machine learning), which may present increased electricity demand, as well as ethical, security, legal, operational, or regulatory challenges; (iii) advances in artificial intelligence (including machine learning) technologies that could reduce the expected electricity demand for these technologies and data centers; (iv) the impact of changes relating to new, developing, or alternative sources of generation such as distributed energy and energy storage, renewable energy, energy efficiency, demand side management, and other measures that reduce load and government policies impacting development or utilization of the foregoing; and (v) competition from other companies offering products and services to Entergy’s customers based on new or emerging technologies or alternative sources of generation;•Entergy’s ability to effectively formulate and implement plans to reduce emissions of greenhouse gases associated with climate change and increase carbon-free energy generation capacity, including its goal to achieve net-zero carbon emissions by 2050, the potential impact on its business and financial condition of attempting to achieve such objectives, and Entergy’s ability to make measurable progress toward any climate goals due to expected load growth or other factors;•the effects, including increased security costs, of threatened or actual terrorism, cyber attacks or data security breaches, physical attacks on or other interference with facilities or infrastructure, natural or man-made electromagnetic pulses that affect transmission or generation infrastructure, accidents, and war or a catastrophic event such as a nuclear accident or a natural gas pipeline explosion;

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FORWARD-LOOKING INFORMATION (Concluded)

•impacts of perceived or actual cybersecurity or data security threats or events on Entergy and its subsidiaries, its vendors, suppliers or other third parties interconnected through the grid, which could, among other things, result in disruptions to its operations, including but not limited to, the loss of operational control, temporary or extended outages, or loss of data, including but not limited to, sensitive customer, employee, financial or operations data;•the effects of a catastrophe, pandemic (or other health-related event), or a global or geopolitical event such as escalating trade tensions between the United States and China or the military activities between Russia and Ukraine, or in the Middle East, including resultant economic and societal disruptions; fuel procurement disruptions; volatility in the capital markets (and any related increased cost of capital or any inability to access the capital markets or draw on available bank credit facilities); reduced demand for electricity, particularly from commercial and industrial customers; increased or unrecoverable costs; supply chain, vendor, and contractor disruptions, including as a result of trade-related sanctions; delays in completion of capital or other construction projects, maintenance, and other operations activities, including prolonged or delayed outages; impacts to Entergy’s workforce availability, health, or safety; increased cybersecurity risks as a result of many employees telecommuting and/or working partially remotely; increased late or uncollectible customer payments; regulatory delays; executive orders affecting, or increased regulation of, Entergy’s business; changes in credit ratings or outlooks as a result of any of the foregoing; or other adverse impacts on Entergy’s ability to execute on its business strategies and initiatives or, more generally, on Entergy’s results of operations, financial condition, and liquidity;•Entergy’s ability to attract and retain talented management, directors, and employees with specialized skills, institutional knowledge, capacity, and abilities, including the ability to effectively execute on Entergy’s growth strategy;•Entergy’s ability to attract, retain, and manage an appropriately qualified and sufficiently staffed workforce;•changes in accounting standards and corporate governance best practices;•declines in the market prices of marketable securities and changes in interest rates and resulting pension and retiree welfare plan funding requirements and the effects on benefits costs for Entergy’s defined benefit pension and other postretirement benefits plans;•future wage and employee benefits costs, including changes in discount rates and returns on benefit plan assets and fluctuating costs to provide employee and retiree health benefits;•changes in decommissioning trust fund values or earnings or in the timing of, requirements for, or cost to decommission Entergy’s nuclear plant sites and the implementation of decommissioning of such sites following shutdown;•the effectiveness of Entergy’s risk management policies and procedures and the ability and willingness of its counterparties, such as lending, hedging, credit support, and major customer counterparties, including counterparties to data center electric service agreements, to satisfy their financial and performance commitments;•reductions in the demand for electricity to power large-scale data centers and other large customers and the potential for stranded assets;•concentration of business and credit risk with a small number of customers in an industry based on emerging technologies, including artificial intelligence and machine learning; and•Entergy and its subsidiaries’ ability to successfully execute on their business strategies, including their ability to complete strategic transactions that they may undertake, and their ability to meet the rapidly growing demand for electricity, including from large-scale data center and other large customers, and to manage the impacts of growth in demand for electricity on customers and Entergy’s business.

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DEFINITIONS (Continued)

[Table with ~30 rows, ~8 numbers, and 2775 characters.]

ix

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DEFINITIONS (Concluded)

[Table with ~8 rows, ~6 numbers, and 1131 characters.]

x

x

Winter Storm Fern

In January 2026, portions of Entergy’s service territory experienced the effects of Winter Storm Fern, including prolonged freezing temperatures, heavy ice accumulation, and wind, which caused severe damage to Entergy’s infrastructure. Entergy’s preliminary estimate for the cost of mobilizing crews and restoring power is approximately $460 million to $560 million, primarily at Entergy Louisiana and Entergy Mississippi, with the majority of the costs being capital. There are well-established mechanisms and precedent for addressing these catastrophic events and providing the process for regulatory review of storm costs for prudence and for recovery of prudently incurred storm costs in accordance with applicable regulatory and legal principles.The severe weather event also affected the market for natural gas due to the effects of severe cold on the gas supply system and increased demand for gas to support electricity loads. Natural gas purchases for January 2026 for Entergy were $483 million, including $74 million for Entergy Arkansas, $256 million for Entergy Louisiana, $85 million for Entergy Mississippi, $20 million for Entergy New Orleans, and $48 million for Entergy Texas. This compares to natural gas purchases for January 2025 for Entergy of $207 million, including $25 million for Entergy Arkansas, $115 million for Entergy Louisiana, $28 million for Entergy Mississippi, $4 million for Entergy New Orleans, and $35 million for Entergy Texas. The Utility operating companies each have fuel recovery mechanisms in place to recover their natural gas costs. With the potential effect of the higher natural gas costs on customers, the Utility operating companies plan to work with their retail regulators to recover these costs in a manner that mitigates the effects on customer bills.Following are income statement variances for Utility, Parent & Other, and Entergy comparing 2025 to 2024 showing how much the line item increased or (decreased) in comparison to the prior period. [Table with ~15 rows, ~45 numbers, and 928 characters.] (a)Parent & Other includes eliminations, which are primarily intersegment activity.Results of operations for 2024 include: (1) a $320 million ($253 million net-of-tax) settlement charge, reflected in Parent & Other above, recognized as a result of a group annuity contract purchased in 2024 to settle certain pension liabilities; (2) expenses of $151 million ($112 million net-of-tax), recorded at Utility in second quarter 2024, primarily consisting of regulatory charges to reflect the effects of an agreement in principle between Entergy Louisiana and the LPSC staff and the intervenors in July 2024 to renew Entergy Louisiana’s formula rate plan and resolve a number of other retail dockets and matters, including all formula rate plan test years prior to 2023; (3) a $132 million ($97 million net-of-tax) charge, recorded at Utility, to reflect the write-off of a previously recorded regulatory asset as a result of an adverse decision in the Entergy Arkansas opportunity sales proceeding in March 2024; and (4) a $78 million ($57 million net-of-tax) regulatory charge, recorded at Utility in first quarter 2024, primarily to reflect a settlement in principle between Entergy New Orleans and the City Council in April 2024 for additional sharing with customers of income tax benefits from the resolution of the 2016-2018 IRS audit. See Note 11 to the financial statements for discussion of the group annuity contract and settlement charge. See Note 2 to the financial statements for discussion of the Entergy Louisiana agreement in principle and the subsequently filed global stipulated settlement agreement. See Note 2 to the financial statements for discussion of the Entergy Arkansas opportunity sales proceeding. See Note 3 to the financial statements for discussion of the Entergy New Orleans April 2024 settlement in principle and discussion of the resolution of the 2016-2018 IRS audit.Utility [Table with ~8 rows, ~10 numbers, and 369 characters.] The Utility operating companies’ results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.The volume/weather variance is primarily due to an increase in industrial usage and the effect of more favorable weather on residential sales. The increase in industrial usage is primarily due to an increase in demand from large industrial customers, primarily in the primary metals, petroleum refining, chlor-alkali, and technology industries.The retail electric price variance is primarily due to:•an increase in Entergy Arkansas’s formula rate plan rates effective January 2025;•a decrease in Entergy Louisiana’s formula rate plan revenues for a two month period beginning in September 2025, resulting from earnings above the authorized return on common equity for the 2024 test year, partially offset by increases in Entergy Louisiana’s formula rate plan revenues, including an increase in the distribution recovery mechanism, effective September 2024;•increases in Entergy Mississippi’s formula rate plan rates effective April 2024 and July 2024 and an increase in Entergy Mississippi’s formula rate plan rates resulting from an increase in interim facilities rate adjustment revenues effective January 2025; and•the implementation of the distribution cost recovery factor rider effective with the first billing cycle in October 2024 and increases in the distribution cost recovery factor rider effective in December 2024 and June 2025, each at Entergy Texas.See Note 2 to the financial statements for further discussion of the regulatory proceedings discussed above.The retail one-time bill credit variance represents the disbursement of settlement proceeds in the form of a one-time bill credit provided to Entergy Arkansas’s retail customers during the August 2024 billing cycle through the Grand Gulf credit rider as a result of the System Energy settlement with the APSC. There is no effect on net income because Entergy previously recorded a regulatory liability at the time of the global black box settlement reached between System Energy and the MPSC in June 2022. See Note 2 to the financial statements for discussion of the System Energy settlements with the APSC and the MPSC and discussion of Entergy Arkansas’s Grand Gulf credit rider.The return on construction work in progress for certain utility plant investments variance represents the revenue related to the amortization of certain customer advances designed to provide a return on investment in construction work in progress for certain utility plant investments, which is recognized as the related costs are incurred.The effect of sale of natural gas distribution businesses variance represents the decrease in operating revenues resulting from the absence of natural gas revenues at Entergy Louisiana and Entergy New Orleans following the sale of the Entergy Louisiana and Entergy New Orleans natural gas distribution businesses on July 1, 2025. See Note 14 to the financial statements for discussion of the sale of the Entergy Louisiana and Entergy New Orleans natural gas distribution businesses on July 1, 2025.Total electric energy sales for Utility for the years ended December 31, 2025 and 2024 are as follows: [Table with ~7 rows, ~23 numbers, and 212 characters.] See Note 19 to the financial statements for additional discussion of operating revenues.

Other Income Statement Items

UtilityPurchased power includes an increase in 2025 of $34 million in costs, at Entergy Texas, related to the procurement of capacity through MISO’s annual planning resource auction, including the effect of a significant increase in MISO’s seasonal auction clearing price, due in part to the implementation of a reliability-based demand curve, for capacity transactions during the summer months. Although Entergy Texas does not have the ability to recover its MISO capacity costs incurred to date beyond the level included in base rates, in June 2025, Texas legislation established a capacity cost recovery rider mechanism that would allow for the recovery of costs related to the procurement of capacity through MISO’s annual planning resource auction outside of base rates, through a rider that is updated annually. Entergy Texas plans in second quarter 2026 to file for such a rider to recover future capacity procurement costs.Other operation and maintenance expenses increased from $2,851 million for 2024 to $3,013 million for 2025 primarily due to:•an increase of $76 million in power delivery expenses primarily due to higher vegetation maintenance costs;•an increase of $33 million in loss provisions;•an increase of $31 million in bad debt expense;•an increase of $29 million in non-nuclear generation expenses primarily due to a higher scope of work performed during plant outages in 2025 as compared to 2024;•an increase of $12 million in transmission costs allocated by MISO. See Note 2 to the financial statements for discussion of the recovery of these costs;•the expensing of $11 million at Entergy Louisiana of project costs associated with the Bayou Power Station project following Entergy Louisiana’s election in third quarter 2025 to cancel the project and evaluate an alternative transmission solution. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources” below for discussion of Entergy Louisiana’s Bayou Power Station project; and•several individually insignificant items.•contract costs of $47 million in 2024 related to operational performance, customer service, and organizational health initiatives;•a $15 million gain resulting from the sale of the Entergy Louisiana and Entergy New Orleans natural gas distribution businesses on July 1, 2025, which included the derecognition of $7 million of goodwill attributed to the businesses sold; and•a decrease of $11 million in gas operation expenses resulting from the absence of expenses following the sale of the Entergy Louisiana and Entergy New Orleans natural gas distribution businesses on July 1, 2025.See Note 14 to the financial statements for discussion of the sale of the Entergy Louisiana and Entergy New Orleans natural gas distribution businesses on July 1, 2025.Asset write-offs, impairments, and related charges (credits) includes:•a $132 million charge, recorded in first quarter 2024 at Entergy Arkansas, to reflect the write-off of a previously recorded regulatory asset as a result of an adverse decision in the Entergy Arkansas opportunity sales proceeding in March 2024. See Note 2 to the financial statements for discussion of the Entergy Arkansas opportunity sales proceeding; and•a $13 million charge, recorded in third quarter 2025 at Entergy New Orleans, to reflect the write-off of retained natural gas plant assets that were not included in the sale of Entergy New Orleans’s natural gas distribution business on July 1, 2025, and which will not be recovered. See Note 14 to the financial statements for discussion of the sale of Entergy New Orleans’s natural gas distribution business on July 1, 2025.Taxes other than income taxes increased primarily due to increases in ad valorem taxes resulting from higher assessments and millage rate increases and increases in local franchise fees as a result of higher retail revenues in 2025 as compared to 2024.Depreciation and amortization expenses increased primarily due to additions to plant in service and increases in nuclear depreciation rates at Entergy Louisiana effective September 2024 and September 2025 in accordance with the global stipulated settlement agreement approved by the LPSC in August 2024. The increase was partially offset by the recognition of $28 million in depreciation expense in 2024 at Entergy Texas for the 2022 base rate case relate back period, effective over six months beginning January 2024. The recognition of depreciation expense for the relate back period was effective over the same period as collections from the relate back surcharge rider and resulted in no effect on net income. See Note 2 to the financial statements for discussion of the Entergy Louisiana global stipulated settlement agreement. See Note 2 to the financial statements for discussion of the 2022 base rate case at Entergy Texas.Other regulatory charges (credits) - net includes:•the reversal in third quarter 2024 of a $92 million regulatory liability recognized for Entergy Arkansas’s obligation to return to customers the refund from the System Energy settlement with the APSC. The reversal of the regulatory liability offsets a reduction in gross revenues from the retail one-time bill credits provided to customers in the August 2024 billing cycle through the Grand Gulf credit rider. See Note 2 to the financial statements for discussion of the System Energy settlement with the APSC and discussion of Entergy Arkansas’s Grand Gulf credit rider;•a regulatory credit of $16 million, recorded by Entergy Arkansas in fourth quarter 2024, to reflect the amount of the 2023 historical year netting adjustment to be collected from its customers during the 2025 rate effective period as included in the 2024 formula rate plan filing. See Note 2 to the financial statements for discussion of the Entergy Arkansas 2024 formula rate plan filing;•a regulatory credit of $28 million, recorded by Entergy Arkansas in fourth quarter 2025, to reflect the amount of the 2024 historical year netting adjustment to be collected from its customers during the 2026 rate effective period as included in the 2025 formula rate plan filing. See Note 2 to the financial statements for discussion of the Entergy Arkansas 2025 formula rate plan filing;•regulatory charges of $150 million, recorded by Entergy Louisiana in second quarter 2024, to reflect the effects of an agreement in principle between Entergy Louisiana and the LPSC staff and the intervenors in July 2024 to renew Entergy Louisiana’s formula rate plan and resolve a number of other retail dockets and matters, including all formula rate plan test years prior to 2023. The customer rate credits agreed to in the global stipulated settlement began in September 2024. See Note 2 to the financial statements for discussion of the Entergy Louisiana agreement in principle and the subsequently filed global stipulated settlement agreement; and•a regulatory charge of $78 million, recorded by Entergy New Orleans in first quarter 2024, primarily to reflect a settlement in principle between Entergy New Orleans and the City Council in April 2024 for additional sharing with customers of income tax benefits from the resolution of the 2016-2018 IRS audit. See Note 3 to the financial statements for discussion of the April 2024 settlement in principle and discussion of the resolution of the 2016-2018 IRS audit.In addition, Entergy records a regulatory charge or credit for the difference between asset retirement obligation-related expenses and nuclear decommissioning trust earnings plus asset retirement obligation-related costs collected in revenue.Other income (deductions) increased primarily due to:•an increase of $65 million in the amortization of tax gross ups on customer advances, including customer advances for construction;•an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2025, including the Orange County Advanced Power Station project, the Legend Power Station project, and the Lone Star Power Station project, each at Entergy Texas;•an increase of $22 million in interest earned on money pool investments; and•a $17 million true-up of Entergy Louisiana’s MISO cost recovery mechanism over-recovery balance to the 2024 formula rate plan filing, which was filed with the LPSC in May 2025. See Note 2 to the financial statements for discussion of the 2024 formula rate plan filing.The increase was partially offset by a decrease of $17 million in intercompany dividend income from affiliated preferred membership interests related to storm cost securitizations. The intercompany dividend income on the affiliated preferred membership interests is eliminated for consolidation purposes and has no effect on net income since the investment is in another Entergy subsidiary. See Note 2 to the financial statements for discussion of Entergy Louisiana’s storm cost securitizations.Interest expense increased primarily due to:•the issuance by Entergy Arkansas of $400 million of 5.45% Series mortgage bonds in May 2024 and an additional $300 million in a reopening of the same series in May 2025;•the issuance by Entergy Louisiana of $700 million of 5.15% Series mortgage bonds in August 2024;•the issuance by Entergy Louisiana of $750 million of 5.80% Series mortgage bonds in January 2025;•the issuance by Entergy Mississippi of $600 million of 5.80% Series mortgage bonds in March 2025;•the issuance by Entergy Texas of $350 million of 5.55% Series mortgage bonds in August 2024;•the issuance by Entergy Texas of $500 million of 5.25% Series mortgage bonds in February 2025;•the issuance by System Energy of $300 million of 5.30% Series mortgage bonds in December 2024 and an additional $240 million in a reopening of the same series in May 2025; and•an increase of $51 million in carrying costs on customer advances, including customer advances for construction.The increase was partially offset by an increase in the allowance for borrowed funds used during construction due to higher construction work in progress in 2025, including the Orange County Advanced Power Station project, the Legend Power Station project, and the Lone Star Power Station project, each at Entergy Texas.See Note 5 to the financial statements for a discussion of long-term debt.Other expenses decreased primarily due to decreased nuclear refueling outage expenses due to the amortization of lower costs associated with the most recent outages as compared to previous outages.Parent and OtherAsset write-offs, impairments, and related charges (credits) includes the effects of recording a favorable final judgment of $20 million in fourth quarter 2024 to resolve claims in the Northstar Vermont Yankee, LLC (previously Entergy Nuclear Vermont Yankee) final round Vermont Yankee damages case against the DOE and the effects of recording a favorable final judgment of $7 million in fourth quarter 2024 to resolve claims in the Holtec Palisades, LLC (previously Entergy Nuclear Palisades) final round Palisades damages case against the DOE. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.Other income (deductions) increased primarily due to a $320 million ($253 million net-of-tax) non-cash settlement charge recognized as a result of a group annuity contract purchased in 2024 to settle certain pension liabilities. See Note 11 to the financial statements for discussion of the group annuity contract and settlement charge.

Income Taxes

The effective income tax rates were 21.9% for 2025 and 26.4% for 2024. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates and for additional discussion regarding income taxes.See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of Entergy’s Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 18, 2025, for discussion of results of operations for 2024 compared to 2023.On July 4, 2025, the One Big Beautiful Bill Act (OBBBA) was enacted. The OBBBA is a wide ranging update to U.S. tax and spending policy. In particular, the OBBBA modified and extended various clean energy tax incentives relevant to electric utilities, preserving production tax credits under Internal Revenue Code section 45U for existing nuclear facilities through 2032 and generally maintaining the existing phase-out schedule for new nuclear and battery storage under Internal Revenue Code sections 45Y (clean electricity production credit) or Internal Revenue Code section 48E (clean electricity investment credit). In addition, the OBBBA preserved the tax credits for carbon capture and sequestration facilities that meet the requirements of Internal Revenue Code section 45Q. The OBBBA also retained full transferability of all credits and preserved five-year modified accelerated cost recovery system treatment for eligible Internal Revenue Code section 45Y and 48E assets.In contrast, the OBBBA significantly shortened the time period for solar and wind facilities to claim clean energy tax incentives. In general, solar and wind facilities must be placed in service by December 31, 2027 to qualify for the tax credits, unless construction begins by July 3, 2026, and certain safe harbor requirements are met.In addition, the OBBBA adopted new foreign entity of concern (FEOC) rules designed to deny clean energy tax incentives to all clean energy projects beginning construction after December 31, 2025 that use equipment beyond statutory guidelines from prohibited foreign entities (entities with ties to China, Russia, Iran, or North Korea). The FEOC rules also deny these incentives to taxpayers that rely beyond certain thresholds on equity or debt held by or sold to specified foreign entities or that make payments to specified foreign entity counterparties under contracts or licensing agreements that give such counterparties “effective control” over an eligible project. These taxpayer FEOC rules will apply to taxpayers in their first taxable year following enactment of the OBBBA.On July 7, 2025, an executive order was issued directing the U.S. Treasury to issue, among other things, new safe harbor guidance, particularly with respect to wind and solar facilities. On August 15, 2025, in response to the executive order, the U.S. Treasury released Notice 2025-42, which provides updated guidance regarding the beginning of construction requirements and termination of the wind and solar energy tax credits under sections 45Y and 48E. Notice 2025-42 provides additional guidance on these safe harbor provisions, clarifying the criteria for beginning construction and offering examples of equipment and contractual terms that will qualify a project for safe harbor treatment under the OBBBA. Notice 2025-42 states that the U.S. Treasury and the IRS are currently drafting additional guidance to address the FEOC rules.The changes in law and federal energy policy reflected in the OBBBA could have a material effect on Entergy’s current and future resource planning, including particularly solar and wind resources, and on its results of operations, cash flows, or financial condition. Entergy may not be able to realize the anticipated benefits of federal tax credits for certain of its planned solar and battery facilities to the extent that these projects do not meet the safe harbor requirements set forth in the OBBBA. In addition, as the policy changes reflected in the OBBBA and anticipated related guidance disfavor certain renewable resource development as compared to prior law, Entergy may not be successful in achieving current or future carbon emission goals. Provisions of the OBBBA may also affect customer decisions relating to major new projects in Entergy’s service area, to the extent that project economics or the achievement of customer sustainability objectives are affected by the changes in the OBBBA.The Inflation Reduction Act of 2022 (IRA), signed into law on August 16, 2022, significantly expanded federal tax incentives for clean energy production, including the extension of production tax credits to solar projects and certain qualified nuclear power facilities. Additionally, the IRA enacted a 1% excise tax on the buyback of public company stock and a new corporate alternative minimum tax (CAMT). Effective for tax years beginning after December 31, 2022, the CAMT imposes a 15% tax on the Adjusted Financial Statement Income (AFSI) on each corporation in a group of corporations that averages greater than $1 billion in AFSI over a three-year period. Taxpayers subject to the CAMT regime must pay the greater of 15% of AFSI or their regular federal tax liability. In September 2024 the IRS issued proposed regulations regarding the application of the CAMT. Entergy and the Registrant Subsidiaries are closely monitoring any potential impact associated with the expansion of federal tax incentives, the 1% excise tax, and CAMT. Based on current IRS guidance and internal forecasts, Entergy and the Registrant Subsidiaries may become subject to the CAMT beginning in the next one to three years. The U.S. Treasury is expected to issue further guidance that will clarify how the tax credit provisions and CAMT provisions will be interpreted and applied. This guidance will determine the amount of tax credits and incremental cash tax payments Entergy expects in the future as a result of the legislation. Prior to receiving this guidance, Entergy cannot adequately assess the expected future effects on its results of operations, financial position, and cash flows. Entergy is not able to predict the effects of any change to or repeal of the above tax legislation, including any federal tax incentives or tax credits, on its or the Registrant Subsidiaries’ results of operations, financial position, and cash flows.In April 2023 the IRS issued Revenue Procedure 2023-15, which provides a safe harbor method of accounting that taxpayers may use to determine whether expenses to repair, maintain, replace, or improve natural gas transmission and distribution property must be capitalized and provides procedures for taxpayers to obtain automatic consent to change their method of accounting. Entergy adopted this new method of income tax accounting beginning with the 2023 federal income tax return utilizing the safe harbor method in accordance with Revenue Procedure 2023-15. The additional temporary deductions taken using the new method resulted in the recognition of deferred tax liabilities of $14.2 million for Entergy, $7.6 million for Entergy Louisiana, and $6.6 million for Entergy New Orleans in 2024.This section discusses Entergy’s capital structure, capital spending plans and other uses of capital, sources of capital, and the cash flow activity presented in the cash flow statement.Recent announcements of changes to international trade policy and tariffs and further similar changes may impact Entergy’s business, operations, results of operations, and liquidity and capital resources. Potential impacts may include increases in costs associated with Entergy’s capital investments or operation and maintenance expenses; operational impacts, such as supply chain, manufacturing, cost and availability of qualified, skilled labor, or raw materials sourcing disruptions which may affect Entergy’s ability to make planned capital investments as and when expected and needed; legal uncertainties, such as potential legal or other challenges to presidential tariff authority; or broader economic risks, including changes to domestic monetary policy, shifting customer demand, impacts on customer investment decisions, and volatile or uncertain credit and capital markets, which may affect Entergy’s ability to access needed capital. The nature and extent of any such effects will depend on, among other things, the specifics of the changes that are ultimately implemented both domestically and internationally, the responses of vendors, suppliers, and other counterparties to those changes, indirect effects on the price and availability of non-tariffed goods, and the effectiveness of mitigation measures.The Registrant Subsidiaries have incurred incremental cost increases due to certain tariff-exposed inputs, including select equipment, components, or underlying raw materials. As of the date of this Form 10-K, such increases have not had a material effect on such Registrant Subsidiaries' capital spending plans. Entergy is not able to predict any further effects of such tariffs or the effects of potential changes in regulation and law, changes to governmental programs, such as loans, grants, guarantees, and other subsidies, and trade-related governmental actions, such as tariffs and other measures, on such capital spending plans.Entergy’s debt to capital ratio is shown in the following table. [Table with ~5 rows, ~12 numbers, and 299 characters.] (a)Calculation excludes the Texas securitization bonds, which are non-recourse to Entergy Texas.As of December 31, 2025, 20.4% of the debt outstanding is at the parent company, Entergy Corporation, and 79.6% is at the Utility segment. Net debt consists of debt less cash and cash equivalents. Debt consists of notes payable and commercial paper, finance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt, equity, and subsidiaries’ preferred stock without sinking fund. Net capital consists of capital less cash and cash equivalents. The debt to capital ratio excluding securitization bonds and net debt to net capital ratio excluding securitization bonds are non-GAAP measures. Entergy uses the debt to capital ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy’s financial condition because the securitization bonds are non-recourse to Entergy, as more fully described in Note 5 to the financial statements. Entergy also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy’s financial condition because net debt indicates Entergy’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.The Utility operating companies and System Energy seek to optimize their capital structures in accordance with regulatory requirements and to control their cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that their operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend to their parent, to the extent funds are legally available to do so, or both, in appropriate amounts to maintain the capital structure. To the extent that their operating cash flows are insufficient to support planned investments, the Utility operating companies and System Energy may issue incremental debt or reduce dividends, or both, to maintain their capital structures. In addition, Entergy may make equity contributions to the Utility operating companies and System Energy to maintain their capital structures in certain circumstances such as financing of large transactions or payments that would materially alter the capital structure if financed entirely with debt and reduced dividends.Long-term debt, including the currently maturing portion, makes up most of Entergy’s total debt outstanding. Following are Entergy’s long-term debt principal maturities and estimated interest payments as of December 31, 2025. To estimate future interest payments for variable rate debt, Entergy used the rate as of December 31, 2025. The amounts below include payments on System Energy’s Grand Gulf sale-leaseback transaction, which are included in long-term debt on the balance sheet. [Table with ~4 rows, ~20 numbers, and 223 characters.] See Note 5 to the financial statements for further details of long-term debt.Entergy Corporation has in place a credit facility that has a borrowing capacity of $3 billion and expires in June 2030. The facility includes fronting commitments for the issuance of letters of credit against $20 million of the total borrowing capacity of the credit facility. The commitment fee is currently 0.225% of the undrawn commitment amount. Commitment fees and interest rates on loans under the credit facility can fluctuate depending on the senior unsecured debt ratings of Entergy Corporation. Although there were no borrowings under the facility for the year ended December 31, 2025, the estimated interest rate for the year ended December 31, 2025 that would have been applied to outstanding borrowings under the facility was 5.32%. The following is a summary of the amounts outstanding and capacity available under the credit facility as of December 31, 2025: [Table with ~3 rows, ~3 numbers, and 83 characters.] Entergy Corporation’s credit facility includes a covenant requiring Entergy to maintain a consolidated debt ratio, as defined, of 65% or less of its total capitalization.  The calculation of this debt ratio under Entergy Corporation’s credit facility is different than the calculation of the debt to capital ratio above. Entergy is currently in compliance with the covenant and expects to remain in compliance with this covenant. If Entergy fails to meet this ratio, or if Entergy Corporation or one of the Registrant Subsidiaries (except Entergy New Orleans and System Energy) defaults on other indebtedness or is in bankruptcy or insolvency proceedings, an acceleration of the Entergy Corporation credit facility’s maturity date may occur. See Note 4 to the financial statements for additional discussion of the Entergy Corporation credit facility and discussion of the Registrant Subsidiaries’ credit facilities.Entergy Corporation has a commercial paper program with a Board-approved program limit of $2 billion. As of December 31, 2025, Entergy Corporation had $637.8 million of commercial paper outstanding. The weighted-average interest rate for the year ended December 31, 2025 was 4.58%.Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each had credit facilities available as of December 31, 2025 as follows: [Table with ~7 rows, ~21 numbers, and 448 characters.] (a)The interest rate is the estimated interest rate as of December 31, 2025 that would have been applied to outstanding borrowings under the facility.(b)Borrowings under this Entergy Arkansas credit facility may be secured by a security interest in its accounts receivable at Entergy Arkansas’s option.(c)The credit facility includes fronting commitments for the issuance of letters of credit against a portion of the borrowing capacity of the facility as follows: $5 million for Entergy Arkansas; $15 million for Entergy Louisiana; $5 million for Entergy Mississippi; $10 million for Entergy New Orleans; and $25 million for Entergy Texas.Each of the credit facilities requires the Registrant Subsidiary borrower to maintain a debt ratio, as defined, of 65% or less of its total capitalization. Each Registrant Subsidiary is in compliance with this covenant.In addition, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each has one or more uncommitted standby letter of credit facilities as a means to post collateral to support their obligations to MISO and for other purposes. The following is a summary of the uncommitted standby letter of credit facilities as of December 31, 2025: [Table with ~10 rows, ~27 numbers, and 515 characters.] (a)As of December 31, 2025, letters of credit posted with MISO covered financial transmission rights exposure of $0.1 million for Entergy Arkansas, $0.8 million for Entergy Louisiana, $0.8 million for Entergy Mississippi, and $0.1 million for Entergy Texas. See Note 15 to the financial statements for discussion of financial transmission rights.(b)As of December 31, 2025, the letters of credit issued for Entergy Mississippi under this facility include $43.1 million in MISO letters of credit and $1.3 million in non-MISO letters of credit outstanding.Finance lease obligations are a minimal part of Entergy’s overall capital structure. Following are Entergy’s payment obligations under those leases. 2026202720282029-2030after 2030 (In Millions)Finance lease payments$25$23$20$28$53Finance leases are discussed in Note 10 to the financial statements.

Operating Lease Obligations and Guarantees of Unconsolidated Obligations

Entergy has a minimal amount of operating lease obligations and guarantees in support of unconsolidated obligations. Entergy’s guarantees in support of unconsolidated obligations are not likely to have a material effect on Entergy’s financial condition, results of operations, or cash flows. Following are Entergy’s payment obligations as of December 31, 2025 on non-cancelable operating leases with a term over one year: 2026202720282029-2030after 2030 (In Millions)Operating lease payments $78$66$54$63$52Operating leases are discussed in Note 10 to the financial statements.Entergy currently expects to contribute approximately $200 million to its qualified pension plans and approximately $40.9 million to its other postretirement plans in 2026, although the 2026 required pension contributions will be known with more certainty when the January 1, 2026 valuations are completed, which is expected by April 1, 2026. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.Entergy has $808 million of unrecognized tax benefits net of unused tax attributes plus interest for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.See below for discussion of the Entergy Texas build-to-suit lease arrangement for the Legend Power Station.In addition, the Registrant Subsidiaries enter into fuel and purchased power agreements that contain minimum purchase obligations. The Registrant Subsidiaries each have rate mechanisms in place to recover fuel, purchased power, and associated costs incurred under these purchase obligations.

Other Income Statement Items

UtilityPurchased power includes an increase in 2025 of $34 million in costs, at Entergy Texas, related to the procurement of capacity through MISO’s annual planning resource auction, including the effect of a significant increase in MISO’s seasonal auction clearing price, due in part to the implementation of a reliability-based demand curve, for capacity transactions during the summer months. Although Entergy Texas does not have the ability to recover its MISO capacity costs incurred to date beyond the level included in base rates, in June 2025, Texas legislation established a capacity cost recovery rider mechanism that would allow for the recovery of costs related to the procurement of capacity through MISO’s annual planning resource auction outside of base rates, through a rider that is updated annually. Entergy Texas plans in second quarter 2026 to file for such a rider to recover future capacity procurement costs.Other operation and maintenance expenses increased from $2,851 million for 2024 to $3,013 million for 2025 primarily due to:•an increase of $76 million in power delivery expenses primarily due to higher vegetation maintenance costs;•an increase of $33 million in loss provisions;•an increase of $31 million in bad debt expense;•an increase of $29 million in non-nuclear generation expenses primarily due to a higher scope of work performed during plant outages in 2025 as compared to 2024;•an increase of $12 million in transmission costs allocated by MISO. See Note 2 to the financial statements for discussion of the recovery of these costs;•the expensing of $11 million at Entergy Louisiana of project costs associated with the Bayou Power Station project following Entergy Louisiana’s election in third quarter 2025 to cancel the project and evaluate an alternative transmission solution. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources” below for discussion of Entergy Louisiana’s Bayou Power Station project; and•several individually insignificant items.•contract costs of $47 million in 2024 related to operational performance, customer service, and organizational health initiatives;•a $15 million gain resulting from the sale of the Entergy Louisiana and Entergy New Orleans natural gas distribution businesses on July 1, 2025, which included the derecognition of $7 million of goodwill attributed to the businesses sold; and•a decrease of $11 million in gas operation expenses resulting from the absence of expenses following the sale of the Entergy Louisiana and Entergy New Orleans natural gas distribution businesses on July 1, 2025.See Note 14 to the financial statements for discussion of the sale of the Entergy Louisiana and Entergy New Orleans natural gas distribution businesses on July 1, 2025.Asset write-offs, impairments, and related charges (credits) includes:•a $132 million charge, recorded in first quarter 2024 at Entergy Arkansas, to reflect the write-off of a previously recorded regulatory asset as a result of an adverse decision in the Entergy Arkansas opportunity sales proceeding in March 2024. See Note 2 to the financial statements for discussion of the Entergy Arkansas opportunity sales proceeding; and•a $13 million charge, recorded in third quarter 2025 at Entergy New Orleans, to reflect the write-off of retained natural gas plant assets that were not included in the sale of Entergy New Orleans’s natural gas distribution business on July 1, 2025, and which will not be recovered. See Note 14 to the financial statements for discussion of the sale of Entergy New Orleans’s natural gas distribution business on July 1, 2025.Taxes other than income taxes increased primarily due to increases in ad valorem taxes resulting from higher assessments and millage rate increases and increases in local franchise fees as a result of higher retail revenues in 2025 as compared to 2024.Depreciation and amortization expenses increased primarily due to additions to plant in service and increases in nuclear depreciation rates at Entergy Louisiana effective September 2024 and September 2025 in accordance with the global stipulated settlement agreement approved by the LPSC in August 2024. The increase was partially offset by the recognition of $28 million in depreciation expense in 2024 at Entergy Texas for the 2022 base rate case relate back period, effective over six months beginning January 2024. The recognition of depreciation expense for the relate back period was effective over the same period as collections from the relate back surcharge rider and resulted in no effect on net income. See Note 2 to the financial statements for discussion of the Entergy Louisiana global stipulated settlement agreement. See Note 2 to the financial statements for discussion of the 2022 base rate case at Entergy Texas.Other regulatory charges (credits) - net includes:•the reversal in third quarter 2024 of a $92 million regulatory liability recognized for Entergy Arkansas’s obligation to return to customers the refund from the System Energy settlement with the APSC. The reversal of the regulatory liability offsets a reduction in gross revenues from the retail one-time bill credits provided to customers in the August 2024 billing cycle through the Grand Gulf credit rider. See Note 2 to the financial statements for discussion of the System Energy settlement with the APSC and discussion of Entergy Arkansas’s Grand Gulf credit rider;•a regulatory credit of $16 million, recorded by Entergy Arkansas in fourth quarter 2024, to reflect the amount of the 2023 historical year netting adjustment to be collected from its customers during the 2025 rate effective period as included in the 2024 formula rate plan filing. See Note 2 to the financial statements for discussion of the Entergy Arkansas 2024 formula rate plan filing;•a regulatory credit of $28 million, recorded by Entergy Arkansas in fourth quarter 2025, to reflect the amount of the 2024 historical year netting adjustment to be collected from its customers during the 2026 rate effective period as included in the 2025 formula rate plan filing. See Note 2 to the financial statements for discussion of the Entergy Arkansas 2025 formula rate plan filing;•regulatory charges of $150 million, recorded by Entergy Louisiana in second quarter 2024, to reflect the effects of an agreement in principle between Entergy Louisiana and the LPSC staff and the intervenors in July 2024 to renew Entergy Louisiana’s formula rate plan and resolve a number of other retail dockets and matters, including all formula rate plan test years prior to 2023. The customer rate credits agreed to in the global stipulated settlement began in September 2024. See Note 2 to the financial statements for discussion of the Entergy Louisiana agreement in principle and the subsequently filed global stipulated settlement agreement; and•a regulatory charge of $78 million, recorded by Entergy New Orleans in first quarter 2024, primarily to reflect a settlement in principle between Entergy New Orleans and the City Council in April 2024 for additional sharing with customers of income tax benefits from the resolution of the 2016-2018 IRS audit. See Note 3 to the financial statements for discussion of the April 2024 settlement in principle and discussion of the resolution of the 2016-2018 IRS audit.In addition, Entergy records a regulatory charge or credit for the difference between asset retirement obligation-related expenses and nuclear decommissioning trust earnings plus asset retirement obligation-related costs collected in revenue.Other income (deductions) increased primarily due to:•an increase of $65 million in the amortization of tax gross ups on customer advances, including customer advances for construction;•an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2025, including the Orange County Advanced Power Station project, the Legend Power Station project, and the Lone Star Power Station project, each at Entergy Texas;•an increase of $22 million in interest earned on money pool investments; and•a $17 million true-up of Entergy Louisiana’s MISO cost recovery mechanism over-recovery balance to the 2024 formula rate plan filing, which was filed with the LPSC in May 2025. See Note 2 to the financial statements for discussion of the 2024 formula rate plan filing.The increase was partially offset by a decrease of $17 million in intercompany dividend income from affiliated preferred membership interests related to storm cost securitizations. The intercompany dividend income on the affiliated preferred membership interests is eliminated for consolidation purposes and has no effect on net income since the investment is in another Entergy subsidiary. See Note 2 to the financial statements for discussion of Entergy Louisiana’s storm cost securitizations.Interest expense increased primarily due to:•the issuance by Entergy Arkansas of $400 million of 5.45% Series mortgage bonds in May 2024 and an additional $300 million in a reopening of the same series in May 2025;•the issuance by Entergy Louisiana of $700 million of 5.15% Series mortgage bonds in August 2024;•the issuance by Entergy Louisiana of $750 million of 5.80% Series mortgage bonds in January 2025;•the issuance by Entergy Mississippi of $600 million of 5.80% Series mortgage bonds in March 2025;•the issuance by Entergy Texas of $350 million of 5.55% Series mortgage bonds in August 2024;•the issuance by Entergy Texas of $500 million of 5.25% Series mortgage bonds in February 2025;•the issuance by System Energy of $300 million of 5.30% Series mortgage bonds in December 2024 and an additional $240 million in a reopening of the same series in May 2025; and•an increase of $51 million in carrying costs on customer advances, including customer advances for construction.The increase was partially offset by an increase in the allowance for borrowed funds used during construction due to higher construction work in progress in 2025, including the Orange County Advanced Power Station project, the Legend Power Station project, and the Lone Star Power Station project, each at Entergy Texas.See Note 5 to the financial statements for a discussion of long-term debt.Other expenses decreased primarily due to decreased nuclear refueling outage expenses due to the amortization of lower costs associated with the most recent outages as compared to previous outages.Parent and OtherAsset write-offs, impairments, and related charges (credits) includes the effects of recording a favorable final judgment of $20 million in fourth quarter 2024 to resolve claims in the Northstar Vermont Yankee, LLC (previously Entergy Nuclear Vermont Yankee) final round Vermont Yankee damages case against the DOE and the effects of recording a favorable final judgment of $7 million in fourth quarter 2024 to resolve claims in the Holtec Palisades, LLC (previously Entergy Nuclear Palisades) final round Palisades damages case against the DOE. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.Other income (deductions) increased primarily due to a $320 million ($253 million net-of-tax) non-cash settlement charge recognized as a result of a group annuity contract purchased in 2024 to settle certain pension liabilities. See Note 11 to the financial statements for discussion of the group annuity contract and settlement charge.

Income Taxes

The effective income tax rates were 21.9% for 2025 and 26.4% for 2024. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates and for additional discussion regarding income taxes.See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of Entergy’s Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 18, 2025, for discussion of results of operations for 2024 compared to 2023.On July 4, 2025, the One Big Beautiful Bill Act (OBBBA) was enacted. The OBBBA is a wide ranging update to U.S. tax and spending policy. In particular, the OBBBA modified and extended various clean energy tax incentives relevant to electric utilities, preserving production tax credits under Internal Revenue Code section 45U for existing nuclear facilities through 2032 and generally maintaining the existing phase-out schedule for new nuclear and battery storage under Internal Revenue Code sections 45Y (clean electricity production credit) or Internal Revenue Code section 48E (clean electricity investment credit). In addition, the OBBBA preserved the tax credits for carbon capture and sequestration facilities that meet the requirements of Internal Revenue Code section 45Q. The OBBBA also retained full transferability of all credits and preserved five-year modified accelerated cost recovery system treatment for eligible Internal Revenue Code section 45Y and 48E assets.In contrast, the OBBBA significantly shortened the time period for solar and wind facilities to claim clean energy tax incentives. In general, solar and wind facilities must be placed in service by December 31, 2027 to qualify for the tax credits, unless construction begins by July 3, 2026, and certain safe harbor requirements are met.In addition, the OBBBA adopted new foreign entity of concern (FEOC) rules designed to deny clean energy tax incentives to all clean energy projects beginning construction after December 31, 2025 that use equipment beyond statutory guidelines from prohibited foreign entities (entities with ties to China, Russia, Iran, or North Korea). The FEOC rules also deny these incentives to taxpayers that rely beyond certain thresholds on equity or debt held by or sold to specified foreign entities or that make payments to specified foreign entity counterparties under contracts or licensing agreements that give such counterparties “effective control” over an eligible project. These taxpayer FEOC rules will apply to taxpayers in their first taxable year following enactment of the OBBBA.On July 7, 2025, an executive order was issued directing the U.S. Treasury to issue, among other things, new safe harbor guidance, particularly with respect to wind and solar facilities. On August 15, 2025, in response to the executive order, the U.S. Treasury released Notice 2025-42, which provides updated guidance regarding the beginning of construction requirements and termination of the wind and solar energy tax credits under sections 45Y and 48E. Notice 2025-42 provides additional guidance on these safe harbor provisions, clarifying the criteria for beginning construction and offering examples of equipment and contractual terms that will qualify a project for safe harbor treatment under the OBBBA. Notice 2025-42 states that the U.S. Treasury and the IRS are currently drafting additional guidance to address the FEOC rules.The changes in law and federal energy policy reflected in the OBBBA could have a material effect on Entergy’s current and future resource planning, including particularly solar and wind resources, and on its results of operations, cash flows, or financial condition. Entergy may not be able to realize the anticipated benefits of federal tax credits for certain of its planned solar and battery facilities to the extent that these projects do not meet the safe harbor requirements set forth in the OBBBA. In addition, as the policy changes reflected in the OBBBA and anticipated related guidance disfavor certain renewable resource development as compared to prior law, Entergy may not be successful in achieving current or future carbon emission goals. Provisions of the OBBBA may also affect customer decisions relating to major new projects in Entergy’s service area, to the extent that project economics or the achievement of customer sustainability objectives are affected by the changes in the OBBBA.The Inflation Reduction Act of 2022 (IRA), signed into law on August 16, 2022, significantly expanded federal tax incentives for clean energy production, including the extension of production tax credits to solar projects and certain qualified nuclear power facilities. Additionally, the IRA enacted a 1% excise tax on the buyback of public company stock and a new corporate alternative minimum tax (CAMT). Effective for tax years beginning after December 31, 2022, the CAMT imposes a 15% tax on the Adjusted Financial Statement Income (AFSI) on each corporation in a group of corporations that averages greater than $1 billion in AFSI over a three-year period. Taxpayers subject to the CAMT regime must pay the greater of 15% of AFSI or their regular federal tax liability. In September 2024 the IRS issued proposed regulations regarding the application of the CAMT. Entergy and the Registrant Subsidiaries are closely monitoring any potential impact associated with the expansion of federal tax incentives, the 1% excise tax, and CAMT. Based on current IRS guidance and internal forecasts, Entergy and the Registrant Subsidiaries may become subject to the CAMT beginning in the next one to three years. The U.S. Treasury is expected to issue further guidance that will clarify how the tax credit provisions and CAMT provisions will be interpreted and applied. This guidance will determine the amount of tax credits and incremental cash tax payments Entergy expects in the future as a result of the legislation. Prior to receiving this guidance, Entergy cannot adequately assess the expected future effects on its results of operations, financial position, and cash flows. Entergy is not able to predict the effects of any change to or repeal of the above tax legislation, including any federal tax incentives or tax credits, on its or the Registrant Subsidiaries’ results of operations, financial position, and cash flows.In April 2023 the IRS issued Revenue Procedure 2023-15, which provides a safe harbor method of accounting that taxpayers may use to determine whether expenses to repair, maintain, replace, or improve natural gas transmission and distribution property must be capitalized and provides procedures for taxpayers to obtain automatic consent to change their method of accounting. Entergy adopted this new method of income tax accounting beginning with the 2023 federal income tax return utilizing the safe harbor method in accordance with Revenue Procedure 2023-15. The additional temporary deductions taken using the new method resulted in the recognition of deferred tax liabilities of $14.2 million for Entergy, $7.6 million for Entergy Louisiana, and $6.6 million for Entergy New Orleans in 2024.This section discusses Entergy’s capital structure, capital spending plans and other uses of capital, sources of capital, and the cash flow activity presented in the cash flow statement.Recent announcements of changes to international trade policy and tariffs and further similar changes may impact Entergy’s business, operations, results of operations, and liquidity and capital resources. Potential impacts may include increases in costs associated with Entergy’s capital investments or operation and maintenance expenses; operational impacts, such as supply chain, manufacturing, cost and availability of qualified, skilled labor, or raw materials sourcing disruptions which may affect Entergy’s ability to make planned capital investments as and when expected and needed; legal uncertainties, such as potential legal or other challenges to presidential tariff authority; or broader economic risks, including changes to domestic monetary policy, shifting customer demand, impacts on customer investment decisions, and volatile or uncertain credit and capital markets, which may affect Entergy’s ability to access needed capital. The nature and extent of any such effects will depend on, among other things, the specifics of the changes that are ultimately implemented both domestically and internationally, the responses of vendors, suppliers, and other counterparties to those changes, indirect effects on the price and availability of non-tariffed goods, and the effectiveness of mitigation measures.The Registrant Subsidiaries have incurred incremental cost increases due to certain tariff-exposed inputs, including select equipment, components, or underlying raw materials. As of the date of this Form 10-K, such increases have not had a material effect on such Registrant Subsidiaries' capital spending plans. Entergy is not able to predict any further effects of such tariffs or the effects of potential changes in regulation and law, changes to governmental programs, such as loans, grants, guarantees, and other subsidies, and trade-related governmental actions, such as tariffs and other measures, on such capital spending plans.Entergy’s debt to capital ratio is shown in the following table. [Table with ~5 rows, ~12 numbers, and 299 characters.] (a)Calculation excludes the Texas securitization bonds, which are non-recourse to Entergy Texas.As of December 31, 2025, 20.4% of the debt outstanding is at the parent company, Entergy Corporation, and 79.6% is at the Utility segment. Net debt consists of debt less cash and cash equivalents. Debt consists of notes payable and commercial paper, finance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt, equity, and subsidiaries’ preferred stock without sinking fund. Net capital consists of capital less cash and cash equivalents. The debt to capital ratio excluding securitization bonds and net debt to net capital ratio excluding securitization bonds are non-GAAP measures. Entergy uses the debt to capital ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy’s financial condition because the securitization bonds are non-recourse to Entergy, as more fully described in Note 5 to the financial statements. Entergy also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy’s financial condition because net debt indicates Entergy’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.The Utility operating companies and System Energy seek to optimize their capital structures in accordance with regulatory requirements and to control their cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that their operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend to their parent, to the extent funds are legally available to do so, or both, in appropriate amounts to maintain the capital structure. To the extent that their operating cash flows are insufficient to support planned investments, the Utility operating companies and System Energy may issue incremental debt or reduce dividends, or both, to maintain their capital structures. In addition, Entergy may make equity contributions to the Utility operating companies and System Energy to maintain their capital structures in certain circumstances such as financing of large transactions or payments that would materially alter the capital structure if financed entirely with debt and reduced dividends.Long-term debt, including the currently maturing portion, makes up most of Entergy’s total debt outstanding. Following are Entergy’s long-term debt principal maturities and estimated interest payments as of December 31, 2025. To estimate future interest payments for variable rate debt, Entergy used the rate as of December 31, 2025. The amounts below include payments on System Energy’s Grand Gulf sale-leaseback transaction, which are included in long-term debt on the balance sheet. [Table with ~4 rows, ~20 numbers, and 223 characters.] See Note 5 to the financial statements for further details of long-term debt.Entergy Corporation has in place a credit facility that has a borrowing capacity of $3 billion and expires in June 2030. The facility includes fronting commitments for the issuance of letters of credit against $20 million of the total borrowing capacity of the credit facility. The commitment fee is currently 0.225% of the undrawn commitment amount. Commitment fees and interest rates on loans under the credit facility can fluctuate depending on the senior unsecured debt ratings of Entergy Corporation. Although there were no borrowings under the facility for the year ended December 31, 2025, the estimated interest rate for the year ended December 31, 2025 that would have been applied to outstanding borrowings under the facility was 5.32%. The following is a summary of the amounts outstanding and capacity available under the credit facility as of December 31, 2025: [Table with ~3 rows, ~3 numbers, and 83 characters.] Entergy Corporation’s credit facility includes a covenant requiring Entergy to maintain a consolidated debt ratio, as defined, of 65% or less of its total capitalization.  The calculation of this debt ratio under Entergy Corporation’s credit facility is different than the calculation of the debt to capital ratio above. Entergy is currently in compliance with the covenant and expects to remain in compliance with this covenant. If Entergy fails to meet this ratio, or if Entergy Corporation or one of the Registrant Subsidiaries (except Entergy New Orleans and System Energy) defaults on other indebtedness or is in bankruptcy or insolvency proceedings, an acceleration of the Entergy Corporation credit facility’s maturity date may occur. See Note 4 to the financial statements for additional discussion of the Entergy Corporation credit facility and discussion of the Registrant Subsidiaries’ credit facilities.Entergy Corporation has a commercial paper program with a Board-approved program limit of $2 billion. As of December 31, 2025, Entergy Corporation had $637.8 million of commercial paper outstanding. The weighted-average interest rate for the year ended December 31, 2025 was 4.58%.Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each had credit facilities available as of December 31, 2025 as follows: [Table with ~7 rows, ~21 numbers, and 448 characters.] (a)The interest rate is the estimated interest rate as of December 31, 2025 that would have been applied to outstanding borrowings under the facility.(b)Borrowings under this Entergy Arkansas credit facility may be secured by a security interest in its accounts receivable at Entergy Arkansas’s option.(c)The credit facility includes fronting commitments for the issuance of letters of credit against a portion of the borrowing capacity of the facility as follows: $5 million for Entergy Arkansas; $15 million for Entergy Louisiana; $5 million for Entergy Mississippi; $10 million for Entergy New Orleans; and $25 million for Entergy Texas.Each of the credit facilities requires the Registrant Subsidiary borrower to maintain a debt ratio, as defined, of 65% or less of its total capitalization. Each Registrant Subsidiary is in compliance with this covenant.In addition, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each has one or more uncommitted standby letter of credit facilities as a means to post collateral to support their obligations to MISO and for other purposes. The following is a summary of the uncommitted standby letter of credit facilities as of December 31, 2025: [Table with ~10 rows, ~27 numbers, and 515 characters.] (a)As of December 31, 2025, letters of credit posted with MISO covered financial transmission rights exposure of $0.1 million for Entergy Arkansas, $0.8 million for Entergy Louisiana, $0.8 million for Entergy Mississippi, and $0.1 million for Entergy Texas. See Note 15 to the financial statements for discussion of financial transmission rights.(b)As of December 31, 2025, the letters of credit issued for Entergy Mississippi under this facility include $43.1 million in MISO letters of credit and $1.3 million in non-MISO letters of credit outstanding.Finance lease obligations are a minimal part of Entergy’s overall capital structure. Following are Entergy’s payment obligations under those leases. 2026202720282029-2030after 2030 (In Millions)Finance lease payments$25$23$20$28$53Finance leases are discussed in Note 10 to the financial statements.

Operating Lease Obligations and Guarantees of Unconsolidated Obligations

Entergy has a minimal amount of operating lease obligations and guarantees in support of unconsolidated obligations. Entergy’s guarantees in support of unconsolidated obligations are not likely to have a material effect on Entergy’s financial condition, results of operations, or cash flows. Following are Entergy’s payment obligations as of December 31, 2025 on non-cancelable operating leases with a term over one year: 2026202720282029-2030after 2030 (In Millions)Operating lease payments $78$66$54$63$52Operating leases are discussed in Note 10 to the financial statements.Entergy currently expects to contribute approximately $200 million to its qualified pension plans and approximately $40.9 million to its other postretirement plans in 2026, although the 2026 required pension contributions will be known with more certainty when the January 1, 2026 valuations are completed, which is expected by April 1, 2026. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.Entergy has $808 million of unrecognized tax benefits net of unused tax attributes plus interest for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.See below for discussion of the Entergy Texas build-to-suit lease arrangement for the Legend Power Station.In addition, the Registrant Subsidiaries enter into fuel and purchased power agreements that contain minimum purchase obligations. The Registrant Subsidiaries each have rate mechanisms in place to recover fuel, purchased power, and associated costs incurred under these purchase obligations.

Capital Expenditure Plans and Other Uses of Capital

Following are the amounts of Entergy’s planned construction and other capital investments for 2026 through 2029. [Table with ~6 rows, ~24 numbers, and 250 characters.] Planned construction and capital investments refer to amounts Entergy plans to spend on routine capital projects that are necessary to support reliability of its service, equipment, or systems and to support normal customer growth. In addition to routine capital projects, they also refer to amounts Entergy plans to spend on non-routine capital investments for which Entergy is either contractually obligated, has Board approval, or otherwise expects to make to satisfy regulatory or legal requirements. Amounts include the following types of construction and capital investments:•investments in generation projects to modernize, decarbonize, expand, and diversify the Utility operating companies’ portfolios, as well as to support customer growth, including Ironwood Power Station (formerly Lake Catherine Unit 5), Jefferson Power Station, Arkansas Cypress Solar, Segno Solar, Votaw Solar, Bogalusa West Solar, Cypress Harvest Solar, Franklin Farms Power Station Units 1 and 2, Waterford 5 Power Station, Cottonwood Power Station, Westlake Power Station, Delta Blues Advanced Power Station, Delta Solar, Penton Solar, Traceview Advanced Power Station, Vicksburg Advanced Power Station, Orange County Advanced Power Station, Lone Star Power Station, Legend Power Station, and potential construction of additional generation;•investments in the Utility nuclear fleet;•transmission spending to improve reliability and resilience while also supporting renewables expansion and customer growth; and•distribution and Utility support spending to improve reliability, resilience, and customer experience through projects focused on asset renewals and enhancements and grid stability.The Utility’s owned and contracted generating capacity is planned on a long-term basis with an aim to enable the Utility operating companies to meet MISO target reserve requirements; however, MISO has implemented changes to its resource adequacy construct that generally move from an annual to a seasonal design and that changes the way that resources are assigned capacity credit. MISO has also recently obtained FERC approval to implement additional changes that further affect the assignment of capacity credit to resources. As a result of these changes, there may be seasonal variations in the capacity credit afforded to the Utility operating companies’ resources by MISO, and some resource types generally may be assigned less capacity credit than they have historically. MISO continues to pursue market design changes related to its resource adequacy construct. The FERC recently approved a reliability-based demand curve that, along with a tighter balance of supply and demand, has had the effect of increasing the clearing prices in the MISO planning resource auction. MISO has also received approval from the FERC for changes to the market rules governing load modifying resources, which could affect the accreditation of these resources and, as a result, the capacity positions of the Utility operating companies. These market design changes may have an effect on both the Utility operating companies’ liquidity and the capital investment needed for long-term resources. Entergy is monitoring the evolution and application of these rules, which may require the Utility operating companies to procure additional capacity credits from the MISO market and in the longer-term may impact the incremental additional supply resources needed. The Utility’s supply plan initiative will continue to seek to transform its generation portfolio with new generation resources.  Opportunities resulting from the supply plan initiative, including new projects or the exploration of alternative financing sources, could result in increases or decreases in the capital expenditure estimates given above. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of business restructuring, regulatory constraints and requirements, governmental actions, including trade-related governmental actions, such as tariffs and other measures, environmental regulations, business opportunities, market volatility, economic trends, changes in project plans, and the ability to access capital, including any changes to governmental programs, such as loans, grants, guarantees, and other subsidies. Entergy is not able to predict the effect of potential changes in regulation and law, changes to governmental programs, such as loans, grants, guarantees, and other subsidies, and trade-related governmental actions, such as tariffs and other measures, on its current and planned capital projects.

Renewables

Entergy Arkansas Special Rate Contract and Arkansas Cypress SolarIn September 2025, Entergy Arkansas filed an application with the APSC seeking approval of a long-term special rate contract between Altitude, LLC, a subsidiary of Alphabet, Inc. (Google) and Entergy Arkansas for the sale of electricity to a new large-scale data center in West Memphis, Arkansas. In October 2025 the APSC general staff filed testimony finding that based on its evaluation of Entergy Arkansas’s application and the results of the ratepayer impact measure test, the special rate contract meets the requirements of the APSC’s promotional practice rules and is in the public interest. No other parties filed testimony. In December 2025 the APSC issued an order approving the special rate contract but denying the requested ratemaking treatment of Google’s upfront payments and deferring a decision on the treatment under the contract pricing providing for the deferral and amortization of the investment tax credits from the Arkansas Cypress Solar facility (discussed below). Also in December 2025, Entergy Arkansas filed a petition with the APSC regarding these findings, noting that they would require renegotiation of the special rate contract. In January 2026 the APSC issued an order maintaining its position on the ratemaking treatment of Google’s upfront payments but reversing itself on the treatment of the Arkansas Cypress Solar facility investment tax credits and allowing those to be used in the pricing of the Arkansas Cypress Solar facility to Google as provided for in the contract.In September 2025, Entergy Arkansas filed an application with the APSC seeking a certificate of environmental compatibility and public need for the construction and operation of the Arkansas Cypress Solar facility, a planned 600 MW solar photovoltaic array with a 350 MW battery energy storage system and associated transmission facilities interconnecting at Entergy Arkansas’s White Bluff substation. The estimated cost of the project is $1,602 million. Entergy Arkansas is seeking public interest and prudence findings from the APSC no later than 180 days from the filing, pursuant to Act 373 of 2025, to construct the Arkansas Cypress Solar facility in support of its long-term special rate contract with Google. In October 2025 the APSC general staff and the Arkansas Attorney General filed responsive testimony opposing the project cost and seeking additional information. Subsequently, the APSC general staff submitted supplemental testimony to update its initial conclusion and recommendations, noting that the Arkansas Cypress Solar facility is a reasonable project and recommending the APSC approve the project under certain conditions. Entergy Arkansas proposes to recover the costs of constructing the Arkansas Cypress Solar facility through the Generating Arkansas Jobs Act rider. A hearing was held in December 2025, and an APSC decision is due in March 2026. Subject to receipt of required regulatory approval and other conditions, the facility is expected to be in service by the end of 2028. See “Retail Rate Proceedings – Filings with the APSC (Entergy Arkansas) – Retail Rates - Generating Arkansas Jobs Act Rider” in Note 2 to the financial statements for discussion of the Generating Jobs Act rider, which was approved by the APSC in October 2025.Bogalusa West Solar In July 2025, Entergy Louisiana filed an application seeking LPSC approval and certification of the Bogalusa West Solar facility, a 200 MW single axis tracking solar photovoltaic power facility in Washington Parish, Louisiana. In October 2025 the LPSC voted to grant Entergy Louisiana’s application and approve the Bogalusa West Solar facility. The facility is expected to be in service by 2028.Cypress Harvest SolarIn February 2026, Entergy Louisiana filed an application seeking LPSC approval and certification for the Cypress Harvest Solar facility, a 200 MW solar facility to be located in Iberville Parish. Entergy Louisiana requested that the LPSC consider the request at its April 2026 meeting.Delta SolarIn December 2024 the Bolivar County Board of Supervisors approved Entergy Mississippi’s plans to construct, own, and operate the Delta Solar facility, an 80 MW solar facility to be located in Bolivar County, Mississippi. The Delta Solar facility is estimated to cost $157.2 million, inclusive of estimated transmission interconnection costs. Construction of the Delta Solar facility qualifies for pre-certification under Mississippi legislation providing for the pre-certification of construction of certain types of facilities that directly or indirectly provide electric service to customers who own certain data processing center projects as specified in the legislation. The project costs will be reviewed for prudence by the MPSC following the completion of construction. Construction is in progress, and the Delta Solar facility is expected to be in service by the end of 2027.Penton SolarIn May 2025 the DeSoto County Board of Supervisors approved Entergy Mississippi’s plans to construct, own, and operate the Penton Solar facility, a 190 MW solar facility to be located in DeSoto County, Mississippi. The Penton Solar facility is estimated to cost $327.2 million, inclusive of estimated transmission interconnection and upgrade costs. Construction of the Penton Solar facility qualifies for pre-certification under Mississippi legislation providing for the pre-certification of construction of certain types of facilities that directly or indirectly provide electric service to customers who own certain data processing center projects as specified in the legislation. The project costs will be reviewed for prudence by the MPSC following the completion of construction. Construction is in progress, and the Penton Solar facility is expected to be in service by early 2028.Segno Solar and Votaw SolarIn July 2024, Entergy Texas filed an application seeking PUCT approval to amend Entergy Texas’s certificate of convenience and necessity to construct, own, and operate the Segno Solar facility, a 170 MW solar facility to be located in Polk County, Texas, and the Votaw Solar facility, a 141 MW solar facility to be located in Hardin County, Texas. In August 2025, Entergy Texas filed, and the ALJs with the State Office of Administrative Hearings granted, an unopposed motion to withdraw the application. In September 2025, Entergy Texas and Entergy Louisiana entered into assignment and assumption agreements pursuant to which Entergy Texas assigned, and Entergy Louisiana assumed, certain interests in the Segno Solar and Votaw Solar facilities, and the associated assets were transferred in third quarter 2025 from Entergy Texas to Entergy Louisiana for approximately $42.1 million, which included adjustments per the assignment and assumption agreements.In December 2025, Entergy Louisiana filed an application with the LPSC seeking approval and certification to construct the Segno Solar facility and Votaw Solar facility. The application asks that the LPSC approve, subject to certain ongoing discussions, allocation of the two facilities to a designated renewable resources subscription to Entergy Louisiana’s Rider Geaux Zero, and further asserts that the two solar resources fall below certain breakeven parameters established in connection with the LPSC’s order allowing Entergy Louisiana to procure up to 3 GW of solar resources, thus supporting that the resources should be certified as being in the public interest. The application requests consideration by the LPSC at or before its August 2026 meeting. A procedural schedule has been set with a hearing scheduled for July 2026. The Segno Solar facility and the Votaw Solar facility are expected to be in service by 2029.

Other Generation and Transmission

Ironwood Power StationIn November 2024, Entergy Arkansas filed an application with the APSC seeking a certificate of environmental compatibility and public need for the construction and operation of Ironwood Power Station (formerly Lake Catherine Unit 5), a 446 MW simple cycle natural gas combustion turbine facility to be located at the existing Lake Catherine facility site in Hot Spring County, Arkansas. The facility will primarily be powered by natural gas, and it will also be enabled for future carbon capture and storage and for hydrogen co-firing optionality. In December 2024 other parties, including the APSC general staff, filed testimony opposing the resource, although the APSC general staff recognized the capacity need for the resource. Entergy Arkansas filed testimony in January 2025 further supporting its application, and in February 2025 the opposing parties filed responsive rebuttal testimony continuing to dispute the estimated costs and to dispute that Entergy Arkansas performed a market solicitation sufficient to demonstrate that this resource is the most reasonable option for customers. Also in February 2025, Entergy Arkansas filed surrebuttal testimony responding to the opposing parties’ testimony. A hearing was held in March 2025, and in April 2025 the APSC issued an order approving certification of the facility. The order also provided a presumption of prudence finding with respect to a benchmark project cost. In May 2025, Entergy Arkansas filed a motion for clarification concerning the appropriate calculation of the benchmark that was below the estimated cost of Ironwood Power Station and was based upon older technology and dated pricing. Entergy Arkansas will have the opportunity to present later all actual costs to the APSC for review and a prudence determination of final costs, including costs incremental to the benchmark. In June 2025, Entergy Arkansas filed its independent monitor proposal with the APSC and is awaiting direction on the proposal and the motion for clarification. Entergy Arkansas proposes to recover the costs of constructing Ironwood Power Station through the Generating Arkansas Jobs Act rider. The facility is expected to be in service by the end of 2028. See “Retail Rate Proceedings – Filings with the APSC (Entergy Arkansas) – Retail Rates - Generating Arkansas Jobs Act Rider” in Note 2 to the financial statements for discussion of the Generating Jobs Act rider, which was approved by the APSC in October 2025.Jefferson Power StationIn August 2025, Entergy Arkansas filed an application with the APSC seeking a certificate of environmental compatibility and public need for the construction and operation of Jefferson Power Station, an approximately 754 MW natural gas-fired combined cycle combustion turbine facility to be located in Jefferson County, Arkansas. The facility will primarily be powered by natural gas, and it will also be enabled for future carbon capture and storage and for hydrogen co-firing optionality. The estimated cost of the project is $1,602 million. In September 2025 other parties, including the APSC general staff, filed testimony opposing the resource pending further information, although the APSC general staff recognized the capacity need for the resource and that Entergy Arkansas had satisfied the statutory requirements for a certificate of environmental compatibility and public need. Much of the opposition focused on the fact that the resource was not identified through a competitive solicitation. Entergy Arkansas filed testimony further supporting its application in September and October 2025. A hearing was held in October 2025 and November 2025. In January 2026 the APSC issued its order finding that Entergy Arkansas had demonstrated a need for the resource but had not met its burden with respect to supporting the prudence of the costs to construct the resource. The APSC acknowledged that the costs would be greater if Entergy Arkansas waited to pursue the resource. The APSC authorized Entergy Arkansas to proceed with Jefferson Power Station as a strategic investment with estimated costs set at a benchmark, which the APSC erroneously believed reflected the current cost estimate but is, in fact, $90 million below the cost presented. Entergy Arkansas is evaluating whether to make a request for rehearing to correct the benchmark. Additionally, the APSC found that Entergy Arkansas should conduct all-source competitive solicitations moving forward with a limited exception for certain resources associated with customer growth projects. Entergy Arkansas proposes to recover the costs of constructing Jefferson Power Station through the Generating Arkansas Jobs Act rider. Subject to receipt of required regulatory approval and other conditions, the facility is expected to be in service by the end of 2029. See “Retail Rate Proceedings – Filings with the APSC (Entergy Arkansas) – Retail Rates - Generating Arkansas Jobs Act Rider” in Note 2 to the financial statements for discussion of the Generating Jobs Act rider, which was approved by the APSC in October 2025.Bayou Power StationIn March 2024, Entergy Louisiana filed an application seeking LPSC approval and certification that the public convenience and necessity would be served by the construction of the Bayou Power Station, a 112 MW aggregated capacity floating natural gas power station with black-start capability in Leeville, Louisiana and an associated microgrid that would serve nearby areas, including Port Fourchon, Golden Meadow, Leeville, and Grand Isle. In its application, Entergy Louisiana noted that the estimated cost of the Bayou Power Station was $411 million, including estimated costs of transmission interconnection and other related costs. In October 2024, Entergy Louisiana filed a motion to suspend the procedural schedule in this proceeding in order to evaluate certain recent developments related to the project including potential changes to the estimated cost of the project. In October 2025, Entergy Louisiana filed with the LPSC a motion to dismiss its application without prejudice, noting that this project has been canceled and that Entergy Louisiana is evaluating an alternative transmission solution. In November 2025 the LPSC granted the motion and dismissed the application, without prejudice. In third quarter 2025, Entergy Louisiana expensed $10.8 million of project costs related to the Bayou Power Station project.Entergy Louisiana Additional Generation and Transmission ResourcesIn October 2024, Entergy Louisiana filed an application with the LPSC seeking approval of a variety of generation and transmission resources proposed in connection with establishing service to a new data center to be developed by a subsidiary of Meta Platforms, Inc. in north Louisiana, for which an electric service agreement has been executed. The filing requested LPSC certification of three new combined cycle combustion turbine generation resources totaling 2,262 MW, each of which will be enabled for future carbon capture and storage, a new 500 kV transmission line, and 500 kV substation upgrades. Two of the new combined cycle combustion turbine generation resources are to be located at Franklin Farms in north Louisiana (Franklin Farms Power Station Units 1 and 2). The application also requested approval to implement a corporate sustainability rider applicable to the new customer. The corporate sustainability rider contemplates the new customer contributing to the costs of the future addition of 1,500 MW of new solar and energy storage resources, agreements involving carbon capture and storage at Entergy Louisiana’s existing Lake Charles Power Station, and potential future wind and nuclear resources. The combined cost of Franklin Farms Power Station Units 1 and 2 is estimated to be approximately $2,387 million. In testimony filed with its application, Entergy Louisiana noted that the third new generation resource, Waterford 5 Power Station, is expected to have an estimated cost similar to the cost of each of Franklin Farms Power Station Units 1 and 2. Also in its testimony, Entergy Louisiana noted that the cost of the new 500 kV transmission line is estimated to be $546 million. Entergy Louisiana anticipates funding the incremental cost to serve the customer through direct financial contributions from the customer and the revenues it expects to earn under the electric service agreement. The electric service agreement also contains provisions for termination payments that will help ensure that there is no harm to Entergy Louisiana and its customers in the event of early termination. A directive was issued at the LPSC’s November 2024 meeting for the matter to be decided by October 2025. In February 2025 intervenors filed a motion asking the LPSC to deny Entergy Louisiana’s requested exemption from the LPSC’s order addressing competitive solicitation procedures and further asking the LPSC to dismiss the application. The ALJ issued an order denying the motion to dismiss the application and deferring the LPSC’s consideration of the motion regarding the competitive solicitation procedures until the hearing. In March 2025 the same intervenors filed a motion requesting the LPSC to require the customer and its parent company to be joined as parties to the proceeding or dismiss the application. In April 2025 the ALJ issued an order denying the March 2025 motion, and the moving parties filed a motion asking the LPSC to review and reverse the ALJ’s decision.In February 2025, Entergy Louisiana filed supplemental testimony with the LPSC stating that the third combined cycle combustion turbine resource presented in the October 2024 application (Waterford 5 Power Station) would be sited at Entergy Louisiana’s Waterford site in Killona, Louisiana, alongside existing Entergy Louisiana generation resources. The testimony also notes that Entergy Louisiana is negotiating with the customer in response to the customer’s request to increase the load associated with its project in north Louisiana. The testimony indicates further that the additional load can be served without additional generation capacity beyond what was presented in the October 2024 application, but that additional transmission facilities, which will be funded directly by the customer, are needed to serve this additional load.In April 2025 and May 2025 the LPSC staff and certain intervenors each filed their direct testimony and cross-answering testimony, respectively. The LPSC staff’s testimony discussed the significant projected benefits associated with the data center project; however, both the LPSC staff and such intervenors also identified purported risks associated with constructing the requested resources based on the terms and conditions under which the customer would be taking service. Both the LPSC staff and such intervenors also recommended that the LPSC impose certain conditions on its approval which, if adopted, would support approval of Entergy Louisiana’s application. The LPSC staff’s recommendations included a condition that would require, under specified circumstances, certain sharing of net revenues from service to the project with Entergy Louisiana’s other customers. The LPSC staff also recommended that the LPSC deny approval of the corporate sustainability rider terms providing for the customer to supply funding toward the cost of installing carbon capture and storage infrastructure at Entergy Louisiana’s Lake Charles Power Station. The Louisiana Energy Users Group and other intervenors recommended that the LPSC require various changes to the terms of the electric service agreement with the customer that would shift additional risk and cost to the customer rather than Entergy Louisiana’s broader customer base. Certain intervenors also challenged approval on the basis that Entergy Louisiana did not conduct a request for proposals to procure the proposed generation resources to serve the customer’s project; these intervenors also advocated that Entergy Louisiana be required to procure more renewable generation and evaluate transmission alternatives rather than proceeding with development of all of the proposed new generation resources. In May 2025, Entergy Louisiana filed its rebuttal testimony responding to the direct and cross-answering testimony of the LPSC staff and intervenors. The rebuttal testimony expressed support for or no opposition to the LPSC’s adoption of certain of the proposed recommendations and identified why other proposed recommendations should not be adopted. In addition, the rebuttal testimony stated that the negotiations related to the increase in the load amount for the customer’s project had concluded and that a rider to the electric service agreement reflecting this increase had been executed. In advance of the July 2025 hearing, Entergy Louisiana reached a settlement agreement with the LPSC staff and three separate intervenors. In August 2025 the LPSC issued an order accepting the settlement agreement. Franklin Farms Power Station Units 1 and 2 are expected to be in service in 2028, and Waterford 5 Power Station is expected to be in service in 2029. In January 2026, several months after the LPSC order became final, certain intervenors filed a motion asking the LPSC to investigate the financing arrangements that the customer implemented for its data center project and to initiate a prudence review. The motion questions whether the credit protections for the customer’s obligations under the electric service agreement are adversely affected by the change in the customer’s financial structure and asks the LPSC to initiate a review of whether Entergy Louisiana withheld relevant information from the LPSC at the time of the LPSC’s order. Entergy Louisiana filed its opposition to the motion in February 2026.Amite South Transmission ProjectsIn March 2024, Entergy Louisiana filed an application seeking an exemption determination, or alternatively, a certificate of public convenience and necessity, for a transmission project that includes a new 500 kV/230 kV Commodore substation and an approximately 60-mile 230 kV line connecting the new Commodore substation to the Waterford substation. The project, which was approved by MISO in the 2023 MISO Transmission Expansion Plan, also includes certain common elements with, and right-of-way acquisition for, a future transmission project in the same area consisting of 500 kV elements. The estimated cost of the project is $498.8 million. In February 2025, Entergy Louisiana and the LPSC staff jointly filed, for consideration by the LPSC, an uncontested stipulated settlement agreement resolving all issues in the proceeding. In the motion requesting approval of the uncontested stipulated settlement agreement, the parties requested a settlement hearing in March 2025. The LPSC approved the uncontested stipulated settlement agreement in March 2025 and thereby granted certification of the project.In December 2024, Entergy Louisiana filed an application with the LPSC seeking a certificate of public convenience and necessity for a 500 kV transmission project that includes the construction of a new 84-mile Commodore to Churchill 500 kV transmission line, the expansion of the Waterford 500 kV substation, the construction of a new Churchill 500 kV substation and improvements to the Churchill 230 kV substation, and the conversion of the existing 230 kV Waterford to Churchill transmission line to 500 kV, forming a 500 kV loop into the Downstream of Gypsy load pocket. The project, which was approved by MISO in the 2023 MISO Transmission Expansion Plan, shares common elements with a future transmission project in the same area consisting of 230 kV elements. The estimated cost of the project is $954.7 million. In April 2025 the LPSC staff and the Louisiana Energy Users Group, an intervenor, filed direct testimony. The LPSC staff’s testimony recommends LPSC approval of the project. The Louisiana Energy Users Group’s testimony opines that Entergy Louisiana has shown that there is a need for additional transmission investment in the West Bank area of Amite South but recommends that the LPSC withhold approval pending further analysis, including analysis of potential lower cost alternatives to the proposed project, and also pending Entergy Louisiana demonstrating that it has contributions in aid of construction from the customers whose block load additions would be enabled by the proposed transmission project in amounts sufficient to substantially, if not fully, cover the revenue requirement of the proposed project. In June 2025, Entergy Louisiana filed rebuttal testimony. A hearing was held in August 2025. In November 2025 the presiding ALJ issued a proposed recommendation granting the application and the requested certification. The Louisiana Energy Users Group filed exceptions to the proposed recommendation, and the LPSC staff and Entergy Louisiana filed responses in opposition to those exceptions. In December 2025 the ALJ issued a final recommendation granting the application and the requested certification. In December 2025 the LPSC issued an order adopting the final recommendation granting the application and the requested certification.Cottonwood Power StationIn December 2025, Entergy Louisiana filed an application seeking LPSC approval and a certificate of convenience and necessity to acquire the Cottonwood combined cycle combustion turbine facility, a 1,263 MW combined cycle facility in Deweyville, Texas that was originally placed in commercial service in 2003. The filing seeks findings from the LPSC that the costs of the acquisition, including the approximately $1.5 billion purchase price and $309.3 million in capital upgrades and maintenance items needed to bring Cottonwood into alignment with Entergy Louisiana’s fleet standards with respect to operations and safety, are eligible for recovery in customer rates. The application requests an LPSC decision by October 2026. A procedural schedule has been set with a hearing scheduled for September 2026. The acquisition is currently targeted to occur in January 2027.Babel - Webre 500 kV Transmission ProjectIn December 2025, Entergy Louisiana filed an application with the LPSC seeking a certificate of public convenience and necessity for a 500 kV transmission project that includes the construction of a new 147-mile Babel to Webre 500 kV transmission line, the reconstruction of the Webre 500 kV switching station in Louisiana, and coordination with Entergy Texas of the construction of an approximately 4-mile 500 kV transmission line in Texas. The project was approved by MISO in the 2025 MISO Transmission Expansion Plan and has an estimated cost of $1,238 million and an estimated in-service date of August 2029. The application requests an LPSC decision by June 2026.Waterford 6 Power Station and Westlake Power StationIn February 2026, Entergy Louisiana filed an application seeking LPSC approval and certification to construct two 754 MW combined cycle combustion turbine generators, the Waterford 6 Power Station and the Westlake Power Station, to be located at Entergy Louisiana’s existing Waterford site near Killona, Louisiana and existing Roy S. Nelson site in Westlake, Louisiana, respectively. In its application, Entergy Louisiana noted the estimated costs are approximately $2,027 million for the Waterford 6 Power Station and $2,091 million for the Westlake Power Station. Entergy Louisiana asked that the LPSC consider the requests in the application at or before its December 2026 meeting. The estimated in-service dates for the Waterford 6 Power Station and Westlake Power Station are July 2030 and October 2030, respectively. Entergy Mississippi Additional Generation and Transmission ResourcesIn March 2024, Entergy Mississippi executed a large customer supply and service agreement to serve two data center campuses located in Madison County, Mississippi in which Amazon Web Services is investing. In February 2025, Entergy Mississippi also executed a large customer supply and service agreement to serve a data center campus located in Warren County, Mississippi in which Amazon Web Services is investing. Entergy Mississippi will need generation and transmission resources to reliably serve all Entergy Mississippi customers, including the data centers. The large customer supply and service agreements also contain provisions which cover Entergy Mississippi’s incremental investment costs in the event of early termination. Entergy Mississippi anticipates recovering the incremental cost to serve the customer through the revenues it is collecting under the large customer supply and service agreements.In May 2024 the MPSC approved Entergy Mississippi’s revisions to its formula rate plan to comply with state legislation passed in January 2024 allowing Entergy Mississippi to make interim rate adjustments, including the collection of a return on construction work in progress on a cash basis, to recover the non-fuel related annual ownership cost of certain facilities that directly or indirectly provide service to customers who own certain data processing center projects as specified in the legislation.Delta Blues Advanced Power StationIn September 2024, Entergy Mississippi announced plans to construct, own, and operate the Delta Blues Advanced Power Station, a 754 MW combined cycle combustion turbine facility, to be located in Washington County, Mississippi. The facility will primarily be powered by natural gas, and it will also be enabled for future carbon capture and storage and for hydrogen co-firing optionality. The Delta Blues Advanced Power Station is estimated to cost $1.2 billion. Construction of the Delta Blues Advanced Power Station qualifies for pre-certification under Mississippi legislation providing for the pre-certification of construction of certain types of facilities that directly or indirectly provide electric service to customers who own certain data processing center projects as specified in the legislation. As provided for in this legislation, Entergy Mississippi began recovery of certain costs of construction of the Delta Blues Advanced Power Station through the interim facilities rate adjustments provision of its formula rate plan rider. Non-fuel revenue collected from the data center customer will be included in the formula rate plan to offset the facility’s revenue requirement. The project costs will be reviewed for prudence by the MPSC following the completion of construction. Construction is in progress, and the facility is expected to be in service by May 2028.Traceview Advanced Power StationEntergy Mississippi is constructing a 754 MW combined cycle combustion turbine facility located in the City of Ridgeland, Madison County, Mississippi. The facility will be powered primarily by natural gas, and it will also be enabled for future carbon capture and storage and for hydrogen co-firing optionality. The project is estimated to cost in excess of $1 billion. Construction of the Traceview Advanced Power Station qualifies for pre-certification under Mississippi legislation providing for the pre-certification of construction of certain types of facilities that directly or indirectly provide electric service to customers who own certain data processing center projects as specified in the legislation. As provided for in this legislation, Entergy Mississippi will begin recovery of certain costs of construction of the Traceview Advanced Power Station through the interim facilities rate adjustments provision of its formula rate plan rider. Non-fuel revenue collected from the data center customer will be included in the formula rate plan to offset the facility’s revenue requirement. The project costs will be reviewed for prudence by the MPSC following the completion of construction. The facility is expected to be in service in 2029.Vicksburg Advanced Power StationIn October 2025, Entergy Mississippi announced plans to construct, own, and operate the Vicksburg Advanced Power Station, a 754 MW combined cycle combustion turbine facility, to be located in the City of Vicksburg, Warren County, Mississippi. The facility will be powered primarily by natural gas, and it will also be enabled for future carbon capture and storage and for hydrogen co-firing optionality. The Vicksburg Advanced Power Station is estimated to cost $1.2 billion. Construction of the Vicksburg Advanced Power Station qualifies for pre-certification under Mississippi legislation providing for the pre-certification of construction of certain types of facilities that directly or indirectly provide electric service to customers who own certain data processing center projects as specified in the legislation. As provided for in this legislation, Entergy Mississippi will begin recovery of certain costs of construction of the Vicksburg Advanced Power Station through the interim facilities rate adjustments provision of its formula rate plan rider. Non-fuel revenue collected from the data center customer will be included in the formula rate plan to offset the facility’s revenue requirement. The project costs will be reviewed for prudence by the MPSC following the completion of construction. Construction is in progress, and the facility is expected to be in service in August 2028.Orange County Advanced Power StationIn September 2021, Entergy Texas filed an application seeking PUCT approval to amend Entergy Texas’s certificate of convenience and necessity to construct, own, and operate the Orange County Advanced Power Station, a new 1,215 MW combined cycle combustion turbine facility to be located in Bridge City, Texas at an initially-estimated expected total cost of $1.2 billion inclusive of the estimated costs of the generation facilities, transmission upgrades, contingency, an allowance for funds used during construction, and necessary regulatory expenses, among others. The project includes combustion turbine technology with dual fuel capability, able to co-fire up to 30% hydrogen by volume upon commercial operation and upgradable to support 100% hydrogen operations in the future. In December 2021 the PUCT referred the proceeding to the State Office of Administrative Hearings. In March 2022 certain intervenors filed testimony opposing the hydrogen co-firing component of the proposed project and others filed testimony opposing the project outright. Also in March 2022 the PUCT staff filed testimony opposing the hydrogen co-firing component of the proposed project, but otherwise taking no specific position on the merits of the project. The PUCT staff also proposed that the PUCT establish a maximum amount that Entergy Texas may recover in rates attributable to the project. In April 2022, Entergy Texas filed rebuttal testimony addressing and rebutting these various arguments. The hearing on the merits was held in June 2022, and post-hearing briefs were submitted in July 2022. In September 2022 the ALJs with the State Office of Administrative Hearings issued a proposal for decision recommending the PUCT approve Entergy Texas’s application for certification of Orange County Advanced Power Station subject to certain conditions, including a cap on cost recovery at $1.37 billion, the exclusion of investment associated with co-firing hydrogen, weatherization requirements, and customer receipt of any contractual benefits associated with the facility’s guaranteed heat rate. In October 2022 the parties in the proceeding filed exceptions and replies to exceptions to the proposal for decision. Also in October 2022, Entergy Texas filed with the PUCT information regarding a new fixed pricing option for an estimated project cost of approximately $1.55 billion associated with Entergy Texas’s issuance of limited notice to proceed by mid-November 2022. In November 2022 the PUCT issued a final order approving the requested amendment to Entergy Texas’s certificate of convenience and necessity to construct, own, and operate the Orange County Advanced Power Station without the investment associated with hydrogen co-firing capability, without a cap on cost recovery, and subject to certain conditions, including weatherization requirements and customer receipt of any contractual benefits associated with the facility’s guaranteed heat rate.In December 2022, Texas Industrial Energy Consumers and Sierra Club filed motions for rehearing of the PUCT’s final order alleging the PUCT erred in granting the certification of the Orange County Advanced Power Station, in not imposing a cost cap, in including certain findings related to the reasonableness of Entergy Texas’s request for proposals from which the Orange County Advanced Power Station was selected, and in other regards. Also in December 2022, Entergy Texas filed a response to the motions for rehearing refuting the points raised therein. In January 2023 the PUCT issued letters noting that it voted to consider Texas Industrial Energy Consumers’ motion for rehearing at its upcoming January 2023 open meeting and voted not to consider Sierra Club’s motion for rehearing at an open meeting. At the January 2023 open meeting, the PUCT voted to grant Texas Industrial Energy Consumers’ motion for rehearing for the limited purpose of issuing an order on rehearing that excludes three findings related to Entergy Texas’s request for proposals. The order on rehearing does not change the PUCT’s certification of the Orange County Advanced Power Station or the conditions placed thereon in the PUCT’s November 2022 final order. Construction is in progress, and subject to receipt of required permits, the facility is expected to be in service by mid-2026.Legend Power Station and Lone Star Power StationIn June 2024, Entergy Texas filed an application seeking PUCT approval to amend Entergy Texas’s certificate of convenience and necessity to construct, own, and operate the Legend Power Station, a 754 MW combined cycle combustion turbine facility, which will be enabled for future carbon capture and storage and for hydrogen co-firing optionality, to be located in Jefferson County, Texas, and the Lone Star Power Station, a 453 MW simple cycle combustion turbine facility, which will be enabled with hydrogen co-firing optionality, to be located in Liberty County, Texas. In its application, Entergy Texas noted that the Legend Power Station was expected to cost an estimated $1.46 billion and the Lone Star Power Station was expected to cost an estimated $735.3 million, in each case inclusive of the estimated costs of the generation facilities, interconnection costs, transmission network upgrades, and an allowance for funds used during construction. In July 2024 the PUCT referred the proceeding to the State Office of Administrative Hearings and, also in July 2024, the ALJ with the State Office of Administrative Hearings adopted a procedural schedule, with a hearing on the merits scheduled to begin in October 2024. In September 2024, Entergy Texas filed, and the ALJ with the State Office of Administrative Hearings granted, a motion to extend the procedural schedule in this proceeding in order to address certain developments relating to the cost and scope of the Legend Power Station and the Lone Star Power Station. In December 2024, Entergy Texas filed supplemental testimony and exhibits addressing the cost and scope developments associated with the Legend Power Station and the Lone Star Power Station in further support of its application. The cost and scope developments include cost estimate increases of $139 million for Legend Power Station and $63.7 million for Lone Star Power Station and the consideration of an alternate site for Lone Star Power Station, which would reduce the estimated cost increase of the Lone Star Power Station to $36.2 million. In March 2025, Entergy Texas filed testimony explaining that Entergy Texas planned to move forward with building the Lone Star Power Station on a more cost-effective alternative site in San Jacinto County, Texas. A hearing on the merits was held in April 2025. Also in April 2025, Entergy Texas, intervenors, and the PUCT staff filed initial briefs. In its initial brief, the PUCT staff recommended denial of Entergy Texas’s application or, in the alternative, approval subject to conditions that include a prudence review by an external consultant if actual project costs exceed estimated costs by more than 10%, transmission cost reporting, and weatherization of both the Legend Power Station and the Lone Star Power Station. Certain intervenors requested that the PUCT impose various conditions upon the approval of the resources, including, among others, cost recovery limitations, a direction that Entergy Texas initiate a competitive tariff proceeding to facilitate industrial sleeving, a requirement for additional regulatory approvals related to hydrogen or carbon capture and storage implementation, limits on the recovery of supplemental filing costs, and calculation of AFUDC based on an adjusted weighted average cost of capital. Reply briefs were filed in May 2025. In June 2025 the ALJs with the State Office of Administrative Hearings issued a proposal for decision, in which they recommended rejection of Entergy Texas’s application to construct the Legend Power Station and the Lone Star Power Station based upon their finding that Entergy Texas did not demonstrate the resources to be cost-effective alternatives to address the uncontested need for additional generation. In the alternative, the ALJs recommended that if the PUCT approves the resources, that conditions be imposed, including a deferral of the finding that the resources were prudently selected until Entergy Texas’s next rate case, a prudence review by an external consultant if actual project costs exceed estimated costs by more than 10%, weatherization requirements, and a requirement that Entergy Texas obtain additional regulatory approvals prior to implementing hydrogen co-firing or carbon capture and storage. The ALJs’ proposal for decision was an interim step in the certification process and was not binding upon the PUCT. Entergy Texas filed exceptions in July 2025. In September 2025 the PUCT issued a decision granting the application, subject to conditions that include a cost cap at Entergy Texas’s previously-filed modified estimated costs of $1.6 billion for the Legend Power Station and $799 million for the Lone Star Power Station, weatherization requirements, environmental compliance requirements, and a requirement to request additional authorization prior to implementing hydrogen co-firing or carbon capture and storage. In October 2025 an intervenor filed a motion for rehearing requesting that the PUCT modify the Lone Star Power Station cost cap to reflect the estimated project costs associated with a new project site, clarify that the cost cap is inclusive of transmission upgrades, and reconsider the intervenor’s prior proposal for a “soft cost cap” below the estimated project costs, and that Entergy Texas be directed to initiate a competitive tariff proceeding to facilitate industrial sleeving of purchased power. Entergy Texas filed a response to the motion for rehearing in October 2025. In December 2025 the PUCT issued an order on rehearing modifying the Lone Star Power Station cost cap to $771.5 million to reflect the estimated project costs associated with a new project site and clarifying that the cost cap is inclusive of transmission upgrades, but denying the other relief requested in the motion for rehearing. See Note 8 to the financial statements for discussion of the build-to-suit lease arrangement for the Legend Power Station. Construction is underway, and subject to receipt of required permits and other conditions, both facilities are expected to be in service by mid-2028.Southeast Texas Area Reliability Project (SETEX)In February 2025, Entergy Texas filed an application seeking PUCT approval to amend Entergy Texas’s certificate of convenience and necessity to construct, own, and operate a new single-circuit 500 kV transmission line and associated stations and 138/230 kV facilities. The transmission line is expected to be approximately 131 to 160 miles in length and the estimated cost of the project ranges from $1.3 billion to $1.5 billion, depending upon the route ultimately approved by the PUCT. Also in February 2025 the PUCT referred the proceeding to the State Office of Administrative Hearings. A hearing on the merits was held in May 2025. In July 2025 the ALJs with the State Office of Administrative Hearings issued a proposal for decision recommending the PUCT approve Entergy Texas’s application to construct SETEX and recommending the PUCT’s approval include selection of a specific route with an estimated cost of $1.4 billion. In October 2025 the PUCT issued a final order approving the requested amendment to Entergy Texas’s certificate of convenience and necessity to construct, own, and operate the new single-circuit 500 kV transmission line and associated stations and 138/230 kV facilities, and selecting the final route for the project, which has an estimated cost of $1.36 billion. In November 2025, multiple parties filed motions for rehearing primarily challenging the routing of the transmission line. In December 2025 the PUCT issued an order on rehearing reaffirming and providing additional support for its initial decision. Subject to receipt of required permits and other conditions, the facility is expected to be in service by the end of 2029.Cypress to Legend 500 kV Transmission LineIn May 2025, Entergy Texas filed an application seeking PUCT approval to amend Entergy Texas’s certificate of convenience and necessity to construct, own, and operate a new single-circuit 500 kV transmission line. The transmission line is expected to be approximately 40 to 49 miles in length and the estimated cost of the project ranges from $392.7 million to $436.2 million, depending on the route ultimately approved by the PUCT. In June 2025 the PUCT referred the proceeding to the State Office of Administrative Hearings and a hearing on the merits was held in August 2025. In October 2025 the ALJs with the State Office of Administrative Hearings issued a proposal for decision recommending the PUCT approve Entergy Texas’s application to construct the transmission line and recommending the PUCT’s approval include selection of a specific route with an estimated cost of $398.7 million. In December 2025 the PUCT issued a final order approving the requested amendment to Entergy Texas’s certificate of convenience and necessity to construct, own, and operate the new single-circuit 500 kV transmission line, and selecting the final route previously recommended. In February 2026, landowners not party to the PUCT proceeding filed in the 345th District Court of Travis County, Texas a petition for declaratory relief and temporary and permanent injunction against the PUCT’s final order. The petition, which names the PUCT, its commissioners, and Entergy Texas as defendants, challenges Entergy Texas’s notice, the application of the PUCT’s notice rule, and the PUCT order’s approval of a route the petitioner’s assert was not adequately noticed. Entergy Texas expects to file an answer disputing all aspects of the petition by the applicable deadline. Subject to receipt of required permits and other conditions, the facility is expected to be in service by the end of 2028.

Resilience and Grid Hardening

Entergy LouisianaIn December 2022, Entergy Louisiana filed an application with the LPSC seeking a public interest finding regarding Phase I of Entergy Louisiana’s Future Ready resilience plan and approval of a rider mechanism to recover the program’s costs. Phase I in the December 2022 application reflected the first five years of a ten-year resilience plan and included investment of approximately $5 billion, including hardening investment, transmission dead-end structures, enhanced vegetation management, and telecommunications improvement. In April 2024 the LPSC approved a framework which includes an initial five-year resilience plan providing for an investment of approximately $1.9 billion with cost recovery via a forward-looking rider with semi-annual true-ups. The plan is subject to specified reporting requirements and includes a performance review of the hardened assets. The LPSC order approving the framework does not include any restrictions on Entergy Louisiana’s ability to file applications for approval of additional investments in resilience.The LPSC had previously opened a formal rulemaking proceeding in December 2021 to investigate efforts to improve resilience of electric utility infrastructure. In April 2023 the LPSC staff issued a draft rule in the rulemaking proceeding related to a requirement to file a grid resilience plan. The procedural schedule entered in the rulemaking proceeding contemplated adoption of a final rule in October 2023, but this did not occur, and a new date has not been set.The LPSC also has pending rulemakings addressing issues related to pole viability and grid maintenance practices. In December 2023, in those rulemakings, the LPSC staff issued a report and recommendation proposing to impose significant new reporting and compliance obligations related to jurisdictional utilities’ distribution and transmission operations, including new obligations related to grid hardening plans, pole inspections, pole replacement, vegetation management, storm restoration plans, new reliability metrics, software for handling customer complaints and complaint resolution, required use of drone technology, and new penalties and incentives for reliability performance and for compliance with the new obligations. In February 2024, Entergy Louisiana and other parties filed comments on the LPSC staff’s report. These rulemakings were formally closed in August 2025 without the adoption of any rules or obligations being promulgated by the LPSC.In October 2021 the City Council passed a resolution and order establishing a docket and procedural schedule with respect to system resiliency and storm hardening. In July 2022, Entergy New Orleans filed with the City Council a response identifying a preliminary plan for storm hardening and resiliency projects, including microgrids, to be implemented over ten years at an approximate cost of $1.5 billion. In February 2023 the City Council approved a revised procedural schedule requiring Entergy New Orleans to make a filing in April 2023 containing a narrowed list of proposed hardening projects. In April 2023, Entergy New Orleans filed the required application and supporting testimony seeking City Council approval of the first phase (five years and $559 million) of a ten-year infrastructure hardening plan totaling approximately $1 billion. Entergy New Orleans also sought, among other relief, City Council approval of a resilience and storm hardening cost recovery rider to recover from customers the costs of the infrastructure hardening plan. In February 2024 the City Council approved a resolution authorizing Entergy New Orleans to implement a resilience project to be partially funded by $55 million of matching funding through the DOE’s Grid Resilience and Innovation Partnerships program. The resolution also required Entergy New Orleans to submit, no later than July 2024, a revised resilience plan consisting of projects over a three-year period. In March 2024, Entergy New Orleans filed with the City Council for approval the requested three-year resilience plan, which included $168 million in hardening projects. The three-year resilience plan was to be in addition to the previously authorized resilience project to be partially funded by the DOE’s Grid Resilience and Innovation Partnerships program. In October 2024 the City Council approved a resolution authorizing a two-year resilience plan totaling $100 million and approved the requested resilience and storm hardening cost recovery rider. In December 2024, Entergy New Orleans notified the City Council of the subset of hardening projects from the revised three-year resilience plan to be included in the two-year resilience plan. Entergy New Orleans implemented the approved resilience and storm hardening cost recovery rider effective with the first billing cycle of January 2025. In December 2025, the City Council issued a resolution establishing certain metrics and reporting requirements for the approved hardening projects. Also in December 2025, Entergy New Orleans filed an application and supporting testimony seeking the City Council’s approval of the second phase of its infrastructure hardening plan totaling approximately $400 million over a five-year period (2027 to 2031). Entergy New Orleans also sought, among other relief, the City Council’s approval to continue to use the resilience and storm hardening cost recovery rider to recover from customers the costs of the plan. Entergy New Orleans requested the City Council approve the application by October 2026.Entergy TexasIn June 2024, Entergy Texas filed an application with the PUCT requesting approval of Phase I of its Texas Future Ready Resiliency Plan, a set of measures to begin accelerating the resiliency of Entergy Texas’s transmission and distribution system. Phase I is comprised of projects totaling approximately $335.1 million, including approximately $137 million of projects to be funded by Entergy Texas and approximately $198 million of projects contingent upon Entergy Texas’s receipt of grant funds in that amount from the Texas Energy Fund. The projects in Phase I include distribution and transmission hardening and modernization projects and targeted vegetation management projects to mitigate the risk of wildfire. These projects are expected to be implemented within approximately three years of PUCT approval. In January 2025 the PUCT unanimously approved Phase I of Entergy Texas’s Texas Future Ready Resiliency Plan, including the approximately $137 million of projects to be funded by Entergy Texas and application of performance metrics consistent with the unopposed settlement. The PUCT clarified that, while not part of Entergy Texas’s Phase I plan, Entergy Texas is permitted to pursue the remaining $198 million of identified projects and Texas Energy Fund grant funding for those projects. In February 2025 the PUCT issued an order adopting a new rule establishing the procedures for application to the grant fund. In July 2025, Entergy Texas submitted an application for approximately $200 million in grant funding from the Texas Energy Fund to implement the resilience projects originally included in its Texas Future Ready Resiliency Plan. In October 2025 the PUCT voted to approve the approximately $200 million grant request in full. The portion of the projects funded by Entergy Texas will be eligible for recovery through Entergy Texas’s transmission or distribution cost recovery factor riders, as applicable.

Dividends and Stock Repurchases

Declarations of dividends on Entergy Corporation common stock are made at the discretion of the Board. Among other things, the Board evaluates the level of Entergy Corporation common stock dividends based upon earnings per share from the Utility segment and the Parent and Other portion of the business, financial strength, and future investment opportunities. In January 2026 the Board declared a dividend of $0.64 per share. Entergy paid $1,074 million in 2025, $982 million in 2024, and $918 million in 2023 in cash dividends on its common stock.In accordance with Entergy’s stock-based compensation plans, Entergy periodically grants stock options, restricted stock, performance units, and restricted stock units to key employees, which may be exercised to obtain shares of Entergy Corporation common stock. According to the plans, these shares can be newly issued shares, treasury stock, or shares purchased on the open market. Entergy’s management has been authorized by the Board to repurchase on the open market shares up to an amount sufficient to fund the exercise of grants under the plans.In addition to the authority to fund grant exercises, the Board has authorized share repurchase programs to enable opportunistic purchases in response to market conditions. In October 2010 the Board granted authority for a $500 million share repurchase program. As of December 31, 2025, $350 million of authority remains under the $500 million share repurchase program. The amount of repurchases may vary as a result of material changes in business results or capital spending or new investment opportunities, or if limitations in the credit markets continue for a prolonged period.Entergy’s sources to meet its capital requirements and to fund potential investments include:•cash on hand ($1,929 million as of December 31, 2025);•storm reserve escrow accounts;•debt and equity issuances in the capital markets, including debt issuances to refund or retire currently outstanding or maturing indebtedness;•bank financing under new or existing facilities or commercial paper; and•sales of assets.Circumstances such as weather patterns, fuel and purchased power price fluctuations, and unanticipated expenses, including unscheduled plant outages and storms, could affect the timing and level of internally generated funds in the future. In addition to the financings necessary to meet capital requirements and contractual obligations, the Registrant Subsidiaries expect to continue, when economically feasible, to retire higher-cost debt and replace it with lower-cost debt if market conditions permit.Provisions within the organizational documents relating to preferred stock or membership interests of certain of Entergy Corporation’s subsidiaries could restrict the payment of cash dividends or other distributions on their common and preferred equity. All debt and preferred equity issuances by the Registrant Subsidiaries require prior regulatory approval and their debt issuances are also subject to requirements set forth in bond indentures and other agreements. Entergy believes that the Registrant Subsidiaries have sufficient capacity under these tests to meet foreseeable capital needs for the next twelve months and beyond.The FERC has jurisdiction over securities issuances by the Utility operating companies and System Energy. The City Council has concurrent jurisdiction over Entergy New Orleans’s securities issuances with maturities longer than one year. The APSC has concurrent jurisdiction over Entergy Arkansas’s issuances of securities secured by Arkansas property, including first mortgage bond issuances. No regulatory approvals are necessary for Entergy Corporation to issue securities. The current FERC-authorized short-term borrowing limits and long-term financing authorization for Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are effective through January 2027. The current FERC-authorized short-term borrowing limit and long-term financing authorization for Entergy Arkansas is effective through February 2028. Entergy Arkansas has obtained first mortgage bond/secured financing authorization from the APSC that extends through December 2027. Entergy New Orleans also has obtained long-term financing authorization from the City Council that extends through December 2027. Entergy Louisiana and System Energy each has obtained long-term financing authorization from the FERC that extends through January 2027 for issuances by the nuclear fuel company variable interest entities. Entergy Arkansas has obtained long-term financing authorization from the FERC that extends through February 2028 for issuances by its nuclear fuel company variable interest entity. In addition to borrowings from commercial banks, the Registrant Subsidiaries may also borrow from the Entergy system money pool and from other internal short-term borrowing arrangements. The money pool is an intercompany cash management program that makes possible intercompany borrowing and lending arrangements, and the money pool and the other internal borrowing arrangements are designed to reduce Entergy’s subsidiaries’ dependence on external short-term borrowings. Borrowings from internal and external short-term borrowings combined may not exceed the FERC-authorized limits. See Notes 4 and 5 to the financial statements for further discussion of Entergy’s borrowing limits, authorizations, and amounts outstanding.

Equity Issuances and Equity Distribution Program

In January 2021, Entergy Corporation entered into an equity distribution sales agreement with several counterparties establishing an at the market equity distribution program, pursuant to which Entergy Corporation may offer and sell from time to time shares of its common stock. The sales agreement provides that, in addition to the issuance and sale of shares of Entergy Corporation common stock, Entergy Corporation may enter into forward sale agreements for the sale of its common stock. The aggregate number of shares of common stock sold under this sales agreement and under any forward sale agreement may not exceed an aggregate gross sales price of $4.5 billion. As of December 31, 2025, Entergy Corporation has utilized the equity distribution program either to sell or to enter into forward sale agreements with respect to shares of common stock with an aggregate gross sales price of approximately $2.8 billion, of which approximately $2.6 billion of aggregate gross sales price was the subject of forward sale agreements, subject to adjustment pursuant to the forward sale agreements. Entergy Corporation settled certain of its then-outstanding forward sale agreements for cash proceeds of $131 million in 2023 and $1,138 million in 2025. There were no settlements of forward sale agreements for the year ended December 31, 2024.In March 2025, Entergy Corporation marketed an equity offering of 17.8 million shares of Entergy Corporation common stock. In lieu of issuing equity at the time of the offering, Entergy Corporation entered into forward sale agreements with several forward counterparties. The forward sale agreements require Entergy Corporation to, at its election on or prior to September 30, 2026, either (1) physically settle the transactions by issuing the total of 17.8 million shares of its common stock to the forward counterparties in exchange for net proceeds at the then-applicable forward sale price specified by the agreements (initially $81.87 per share) or (2) net settle the transactions in whole or in part through the delivery or receipt of cash or shares. The forward sale price is subject to adjustment on a daily basis based on a floating interest rate factor and will decrease by other fixed amounts specified in the agreements.In February 2026, Entergy Corporation physically settled a portion of its obligations under certain of its outstanding forward sale agreements under its at the market equity distribution program for cash proceeds of $346 million.Entergy Corporation currently expects to issue approximately $4.4 billion of equity through 2029, which it may issue under its at the market equity distribution program or otherwise, with approximately $1.9 billion already contracted under forward sale agreements as of December 31, 2025, including under its at the market equity distribution program ($346 million of which were settled in February 2026 as described above) and the March 2025 equity offering described above. See Note 7 to the financial statements for discussion of the forward sale agreements and common stock issuances and sales under the equity distribution program.

Entergy Texas Build-to-Suit Lease Arrangement for the Legend Power Station

In December 2025, Entergy Texas entered into a build-to-suit lease arrangement for the Legend Power Station as the lessee with a consortium of investors (the Investors). Under the terms of the arrangement, the Investors purchased the in-process Legend Power Station construction project from Entergy Texas at a cost of $359 million and will spend up to $1.45 billion (including the initial purchase price) to construct the Legend Power Station project as designed by Entergy Texas. Entergy Texas is engaged to serve as the construction agent for the Legend Power Station project. The Investors, however, control the asset during construction. If Entergy Texas defaults in its role as construction agent, the Investors have various options available to remedy the default, including by accelerating the lease balance payable by Entergy Texas, causing a sale of the Legend Power Station project to a third party, or certain other options. If there are certain changes to the terms of the PUCT approval of the Legend Power Station project or certain other circumstances outside of Entergy Texas’s control, then either the Investors or Entergy Texas could exercise the right to terminate the arrangement, in which case Entergy Texas would be required to purchase the in-process Legend Power Station project from the Investors at an amount equal to their costs incurred to date, including carrying costs. Since Entergy Texas does not control the in-process construction project, it will not recognize the asset (i.e., construction work in progress) or an associated liability during construction.Upon the Legend Power Station’s readiness for first synchronization to the grid, expected in early 2028, a triple-net lease will commence under which Entergy Texas will have control of the Legend Power Station and receive all output from the plant. The initial term of the lease will end seven years from the closing of the arrangement, or approximately five years after the Legend Power Station’s expected readiness for first synchronization to the grid. The lease cost will be equal to the Secured Overnight Financing Rate plus a margin which is based on the credit rating of Entergy Texas, multiplied by the total costs (including carrying costs) incurred by the Investors as of the commencement of the lease. Entergy Texas will have the option to purchase the Legend Power Station at any time during the lease term at a price equal to the total cost of the plant to the Investors, plus any fees and carrying charges owed to the Investors. If the purchase price option is exercised within two years of commencement of the triple-net lease, Entergy Texas must enter into a secured note payable to the Investors for the amount of the purchase price. The note payable would be due at the end of the initial lease term, but may be prepaid at any time beginning two years after the commencement date of the lease. The note will be secured by the Legend Power Station and related equipment and collateral.At the end of the initial lease term, Entergy Texas must exercise one of the following options: 1) renew the lease for an additional five year term, subject to unanimous consent of the Investors, 2) purchase the plant at a price equal to the total cost of the plant to Investors, plus any fees and carrying charges owed to the Investors, or 3) sell the plant on behalf of the Investors. If Entergy Texas chooses the third option, then it will owe or be owed any difference between the total cost of the plant to Investors and the sale price.

Renewables

Entergy Arkansas Special Rate Contract and Arkansas Cypress SolarIn September 2025, Entergy Arkansas filed an application with the APSC seeking approval of a long-term special rate contract between Altitude, LLC, a subsidiary of Alphabet, Inc. (Google) and Entergy Arkansas for the sale of electricity to a new large-scale data center in West Memphis, Arkansas. In October 2025 the APSC general staff filed testimony finding that based on its evaluation of Entergy Arkansas’s application and the results of the ratepayer impact measure test, the special rate contract meets the requirements of the APSC’s promotional practice rules and is in the public interest. No other parties filed testimony. In December 2025 the APSC issued an order approving the special rate contract but denying the requested ratemaking treatment of Google’s upfront payments and deferring a decision on the treatment under the contract pricing providing for the deferral and amortization of the investment tax credits from the Arkansas Cypress Solar facility (discussed below). Also in December 2025, Entergy Arkansas filed a petition with the APSC regarding these findings, noting that they would require renegotiation of the special rate contract. In January 2026 the APSC issued an order maintaining its position on the ratemaking treatment of Google’s upfront payments but reversing itself on the treatment of the Arkansas Cypress Solar facility investment tax credits and allowing those to be used in the pricing of the Arkansas Cypress Solar facility to Google as provided for in the contract.In September 2025, Entergy Arkansas filed an application with the APSC seeking a certificate of environmental compatibility and public need for the construction and operation of the Arkansas Cypress Solar facility, a planned 600 MW solar photovoltaic array with a 350 MW battery energy storage system and associated transmission facilities interconnecting at Entergy Arkansas’s White Bluff substation. The estimated cost of the project is $1,602 million. Entergy Arkansas is seeking public interest and prudence findings from the APSC no later than 180 days from the filing, pursuant to Act 373 of 2025, to construct the Arkansas Cypress Solar facility in support of its long-term special rate contract with Google. In October 2025 the APSC general staff and the Arkansas Attorney General filed responsive testimony opposing the project cost and seeking additional information. Subsequently, the APSC general staff submitted supplemental testimony to update its initial conclusion and recommendations, noting that the Arkansas Cypress Solar facility is a reasonable project and recommending the APSC approve the project under certain conditions. Entergy Arkansas proposes to recover the costs of constructing the Arkansas Cypress Solar facility through the Generating Arkansas Jobs Act rider. A hearing was held in December 2025, and an APSC decision is due in March 2026. Subject to receipt of required regulatory approval and other conditions, the facility is expected to be in service by the end of 2028. See “Retail Rate Proceedings – Filings with the APSC (Entergy Arkansas) – Retail Rates - Generating Arkansas Jobs Act Rider” in Note 2 to the financial statements for discussion of the Generating Jobs Act rider, which was approved by the APSC in October 2025.Bogalusa West Solar In July 2025, Entergy Louisiana filed an application seeking LPSC approval and certification of the Bogalusa West Solar facility, a 200 MW single axis tracking solar photovoltaic power facility in Washington Parish, Louisiana. In October 2025 the LPSC voted to grant Entergy Louisiana’s application and approve the Bogalusa West Solar facility. The facility is expected to be in service by 2028.Cypress Harvest SolarIn February 2026, Entergy Louisiana filed an application seeking LPSC approval and certification for the Cypress Harvest Solar facility, a 200 MW solar facility to be located in Iberville Parish. Entergy Louisiana requested that the LPSC consider the request at its April 2026 meeting.Delta SolarIn December 2024 the Bolivar County Board of Supervisors approved Entergy Mississippi’s plans to construct, own, and operate the Delta Solar facility, an 80 MW solar facility to be located in Bolivar County, Mississippi. The Delta Solar facility is estimated to cost $157.2 million, inclusive of estimated transmission interconnection costs. Construction of the Delta Solar facility qualifies for pre-certification under Mississippi legislation providing for the pre-certification of construction of certain types of facilities that directly or indirectly provide electric service to customers who own certain data processing center projects as specified in the legislation. The project costs will be reviewed for prudence by the MPSC following the completion of construction. Construction is in progress, and the Delta Solar facility is expected to be in service by the end of 2027.Penton SolarIn May 2025 the DeSoto County Board of Supervisors approved Entergy Mississippi’s plans to construct, own, and operate the Penton Solar facility, a 190 MW solar facility to be located in DeSoto County, Mississippi. The Penton Solar facility is estimated to cost $327.2 million, inclusive of estimated transmission interconnection and upgrade costs. Construction of the Penton Solar facility qualifies for pre-certification under Mississippi legislation providing for the pre-certification of construction of certain types of facilities that directly or indirectly provide electric service to customers who own certain data processing center projects as specified in the legislation. The project costs will be reviewed for prudence by the MPSC following the completion of construction. Construction is in progress, and the Penton Solar facility is expected to be in service by early 2028.Segno Solar and Votaw SolarIn July 2024, Entergy Texas filed an application seeking PUCT approval to amend Entergy Texas’s certificate of convenience and necessity to construct, own, and operate the Segno Solar facility, a 170 MW solar facility to be located in Polk County, Texas, and the Votaw Solar facility, a 141 MW solar facility to be located in Hardin County, Texas. In August 2025, Entergy Texas filed, and the ALJs with the State Office of Administrative Hearings granted, an unopposed motion to withdraw the application. In September 2025, Entergy Texas and Entergy Louisiana entered into assignment and assumption agreements pursuant to which Entergy Texas assigned, and Entergy Louisiana assumed, certain interests in the Segno Solar and Votaw Solar facilities, and the associated assets were transferred in third quarter 2025 from Entergy Texas to Entergy Louisiana for approximately $42.1 million, which included adjustments per the assignment and assumption agreements.In December 2025, Entergy Louisiana filed an application with the LPSC seeking approval and certification to construct the Segno Solar facility and Votaw Solar facility. The application asks that the LPSC approve, subject to certain ongoing discussions, allocation of the two facilities to a designated renewable resources subscription to Entergy Louisiana’s Rider Geaux Zero, and further asserts that the two solar resources fall below certain breakeven parameters established in connection with the LPSC’s order allowing Entergy Louisiana to procure up to 3 GW of solar resources, thus supporting that the resources should be certified as being in the public interest. The application requests consideration by the LPSC at or before its August 2026 meeting. A procedural schedule has been set with a hearing scheduled for July 2026. The Segno Solar facility and the Votaw Solar facility are expected to be in service by 2029.

Other Generation and Transmission

Ironwood Power StationIn November 2024, Entergy Arkansas filed an application with the APSC seeking a certificate of environmental compatibility and public need for the construction and operation of Ironwood Power Station (formerly Lake Catherine Unit 5), a 446 MW simple cycle natural gas combustion turbine facility to be located at the existing Lake Catherine facility site in Hot Spring County, Arkansas. The facility will primarily be powered by natural gas, and it will also be enabled for future carbon capture and storage and for hydrogen co-firing optionality. In December 2024 other parties, including the APSC general staff, filed testimony opposing the resource, although the APSC general staff recognized the capacity need for the resource. Entergy Arkansas filed testimony in January 2025 further supporting its application, and in February 2025 the opposing parties filed responsive rebuttal testimony continuing to dispute the estimated costs and to dispute that Entergy Arkansas performed a market solicitation sufficient to demonstrate that this resource is the most reasonable option for customers. Also in February 2025, Entergy Arkansas filed surrebuttal testimony responding to the opposing parties’ testimony. A hearing was held in March 2025, and in April 2025 the APSC issued an order approving certification of the facility. The order also provided a presumption of prudence finding with respect to a benchmark project cost. In May 2025, Entergy Arkansas filed a motion for clarification concerning the appropriate calculation of the benchmark that was below the estimated cost of Ironwood Power Station and was based upon older technology and dated pricing. Entergy Arkansas will have the opportunity to present later all actual costs to the APSC for review and a prudence determination of final costs, including costs incremental to the benchmark. In June 2025, Entergy Arkansas filed its independent monitor proposal with the APSC and is awaiting direction on the proposal and the motion for clarification. Entergy Arkansas proposes to recover the costs of constructing Ironwood Power Station through the Generating Arkansas Jobs Act rider. The facility is expected to be in service by the end of 2028. See “Retail Rate Proceedings – Filings with the APSC (Entergy Arkansas) – Retail Rates - Generating Arkansas Jobs Act Rider” in Note 2 to the financial statements for discussion of the Generating Jobs Act rider, which was approved by the APSC in October 2025.Jefferson Power StationIn August 2025, Entergy Arkansas filed an application with the APSC seeking a certificate of environmental compatibility and public need for the construction and operation of Jefferson Power Station, an approximately 754 MW natural gas-fired combined cycle combustion turbine facility to be located in Jefferson County, Arkansas. The facility will primarily be powered by natural gas, and it will also be enabled for future carbon capture and storage and for hydrogen co-firing optionality. The estimated cost of the project is $1,602 million. In September 2025 other parties, including the APSC general staff, filed testimony opposing the resource pending further information, although the APSC general staff recognized the capacity need for the resource and that Entergy Arkansas had satisfied the statutory requirements for a certificate of environmental compatibility and public need. Much of the opposition focused on the fact that the resource was not identified through a competitive solicitation. Entergy Arkansas filed testimony further supporting its application in September and October 2025. A hearing was held in October 2025 and November 2025. In January 2026 the APSC issued its order finding that Entergy Arkansas had demonstrated a need for the resource but had not met its burden with respect to supporting the prudence of the costs to construct the resource. The APSC acknowledged that the costs would be greater if Entergy Arkansas waited to pursue the resource. The APSC authorized Entergy Arkansas to proceed with Jefferson Power Station as a strategic investment with estimated costs set at a benchmark, which the APSC erroneously believed reflected the current cost estimate but is, in fact, $90 million below the cost presented. Entergy Arkansas is evaluating whether to make a request for rehearing to correct the benchmark. Additionally, the APSC found that Entergy Arkansas should conduct all-source competitive solicitations moving forward with a limited exception for certain resources associated with customer growth projects. Entergy Arkansas proposes to recover the costs of constructing Jefferson Power Station through the Generating Arkansas Jobs Act rider. Subject to receipt of required regulatory approval and other conditions, the facility is expected to be in service by the end of 2029. See “Retail Rate Proceedings – Filings with the APSC (Entergy Arkansas) – Retail Rates - Generating Arkansas Jobs Act Rider” in Note 2 to the financial statements for discussion of the Generating Jobs Act rider, which was approved by the APSC in October 2025.Bayou Power StationIn March 2024, Entergy Louisiana filed an application seeking LPSC approval and certification that the public convenience and necessity would be served by the construction of the Bayou Power Station, a 112 MW aggregated capacity floating natural gas power station with black-start capability in Leeville, Louisiana and an associated microgrid that would serve nearby areas, including Port Fourchon, Golden Meadow, Leeville, and Grand Isle. In its application, Entergy Louisiana noted that the estimated cost of the Bayou Power Station was $411 million, including estimated costs of transmission interconnection and other related costs. In October 2024, Entergy Louisiana filed a motion to suspend the procedural schedule in this proceeding in order to evaluate certain recent developments related to the project including potential changes to the estimated cost of the project. In October 2025, Entergy Louisiana filed with the LPSC a motion to dismiss its application without prejudice, noting that this project has been canceled and that Entergy Louisiana is evaluating an alternative transmission solution. In November 2025 the LPSC granted the motion and dismissed the application, without prejudice. In third quarter 2025, Entergy Louisiana expensed $10.8 million of project costs related to the Bayou Power Station project.Entergy Louisiana Additional Generation and Transmission ResourcesIn October 2024, Entergy Louisiana filed an application with the LPSC seeking approval of a variety of generation and transmission resources proposed in connection with establishing service to a new data center to be developed by a subsidiary of Meta Platforms, Inc. in north Louisiana, for which an electric service agreement has been executed. The filing requested LPSC certification of three new combined cycle combustion turbine generation resources totaling 2,262 MW, each of which will be enabled for future carbon capture and storage, a new 500 kV transmission line, and 500 kV substation upgrades. Two of the new combined cycle combustion turbine generation resources are to be located at Franklin Farms in north Louisiana (Franklin Farms Power Station Units 1 and 2). The application also requested approval to implement a corporate sustainability rider applicable to the new customer. The corporate sustainability rider contemplates the new customer contributing to the costs of the future addition of 1,500 MW of new solar and energy storage resources, agreements involving carbon capture and storage at Entergy Louisiana’s existing Lake Charles Power Station, and potential future wind and nuclear resources. The combined cost of Franklin Farms Power Station Units 1 and 2 is estimated to be approximately $2,387 million. In testimony filed with its application, Entergy Louisiana noted that the third new generation resource, Waterford 5 Power Station, is expected to have an estimated cost similar to the cost of each of Franklin Farms Power Station Units 1 and 2. Also in its testimony, Entergy Louisiana noted that the cost of the new 500 kV transmission line is estimated to be $546 million. Entergy Louisiana anticipates funding the incremental cost to serve the customer through direct financial contributions from the customer and the revenues it expects to earn under the electric service agreement. The electric service agreement also contains provisions for termination payments that will help ensure that there is no harm to Entergy Louisiana and its customers in the event of early termination. A directive was issued at the LPSC’s November 2024 meeting for the matter to be decided by October 2025. In February 2025 intervenors filed a motion asking the LPSC to deny Entergy Louisiana’s requested exemption from the LPSC’s order addressing competitive solicitation procedures and further asking the LPSC to dismiss the application. The ALJ issued an order denying the motion to dismiss the application and deferring the LPSC’s consideration of the motion regarding the competitive solicitation procedures until the hearing. In March 2025 the same intervenors filed a motion requesting the LPSC to require the customer and its parent company to be joined as parties to the proceeding or dismiss the application. In April 2025 the ALJ issued an order denying the March 2025 motion, and the moving parties filed a motion asking the LPSC to review and reverse the ALJ’s decision.In February 2025, Entergy Louisiana filed supplemental testimony with the LPSC stating that the third combined cycle combustion turbine resource presented in the October 2024 application (Waterford 5 Power Station) would be sited at Entergy Louisiana’s Waterford site in Killona, Louisiana, alongside existing Entergy Louisiana generation resources. The testimony also notes that Entergy Louisiana is negotiating with the customer in response to the customer’s request to increase the load associated with its project in north Louisiana. The testimony indicates further that the additional load can be served without additional generation capacity beyond what was presented in the October 2024 application, but that additional transmission facilities, which will be funded directly by the customer, are needed to serve this additional load.In April 2025 and May 2025 the LPSC staff and certain intervenors each filed their direct testimony and cross-answering testimony, respectively. The LPSC staff’s testimony discussed the significant projected benefits associated with the data center project; however, both the LPSC staff and such intervenors also identified purported risks associated with constructing the requested resources based on the terms and conditions under which the customer would be taking service. Both the LPSC staff and such intervenors also recommended that the LPSC impose certain conditions on its approval which, if adopted, would support approval of Entergy Louisiana’s application. The LPSC staff’s recommendations included a condition that would require, under specified circumstances, certain sharing of net revenues from service to the project with Entergy Louisiana’s other customers. The LPSC staff also recommended that the LPSC deny approval of the corporate sustainability rider terms providing for the customer to supply funding toward the cost of installing carbon capture and storage infrastructure at Entergy Louisiana’s Lake Charles Power Station. The Louisiana Energy Users Group and other intervenors recommended that the LPSC require various changes to the terms of the electric service agreement with the customer that would shift additional risk and cost to the customer rather than Entergy Louisiana’s broader customer base. Certain intervenors also challenged approval on the basis that Entergy Louisiana did not conduct a request for proposals to procure the proposed generation resources to serve the customer’s project; these intervenors also advocated that Entergy Louisiana be required to procure more renewable generation and evaluate transmission alternatives rather than proceeding with development of all of the proposed new generation resources. In May 2025, Entergy Louisiana filed its rebuttal testimony responding to the direct and cross-answering testimony of the LPSC staff and intervenors. The rebuttal testimony expressed support for or no opposition to the LPSC’s adoption of certain of the proposed recommendations and identified why other proposed recommendations should not be adopted. In addition, the rebuttal testimony stated that the negotiations related to the increase in the load amount for the customer’s project had concluded and that a rider to the electric service agreement reflecting this increase had been executed. In advance of the July 2025 hearing, Entergy Louisiana reached a settlement agreement with the LPSC staff and three separate intervenors. In August 2025 the LPSC issued an order accepting the settlement agreement. Franklin Farms Power Station Units 1 and 2 are expected to be in service in 2028, and Waterford 5 Power Station is expected to be in service in 2029. In January 2026, several months after the LPSC order became final, certain intervenors filed a motion asking the LPSC to investigate the financing arrangements that the customer implemented for its data center project and to initiate a prudence review. The motion questions whether the credit protections for the customer’s obligations under the electric service agreement are adversely affected by the change in the customer’s financial structure and asks the LPSC to initiate a review of whether Entergy Louisiana withheld relevant information from the LPSC at the time of the LPSC’s order. Entergy Louisiana filed its opposition to the motion in February 2026.Amite South Transmission ProjectsIn March 2024, Entergy Louisiana filed an application seeking an exemption determination, or alternatively, a certificate of public convenience and necessity, for a transmission project that includes a new 500 kV/230 kV Commodore substation and an approximately 60-mile 230 kV line connecting the new Commodore substation to the Waterford substation. The project, which was approved by MISO in the 2023 MISO Transmission Expansion Plan, also includes certain common elements with, and right-of-way acquisition for, a future transmission project in the same area consisting of 500 kV elements. The estimated cost of the project is $498.8 million. In February 2025, Entergy Louisiana and the LPSC staff jointly filed, for consideration by the LPSC, an uncontested stipulated settlement agreement resolving all issues in the proceeding. In the motion requesting approval of the uncontested stipulated settlement agreement, the parties requested a settlement hearing in March 2025. The LPSC approved the uncontested stipulated settlement agreement in March 2025 and thereby granted certification of the project.In December 2024, Entergy Louisiana filed an application with the LPSC seeking a certificate of public convenience and necessity for a 500 kV transmission project that includes the construction of a new 84-mile Commodore to Churchill 500 kV transmission line, the expansion of the Waterford 500 kV substation, the construction of a new Churchill 500 kV substation and improvements to the Churchill 230 kV substation, and the conversion of the existing 230 kV Waterford to Churchill transmission line to 500 kV, forming a 500 kV loop into the Downstream of Gypsy load pocket. The project, which was approved by MISO in the 2023 MISO Transmission Expansion Plan, shares common elements with a future transmission project in the same area consisting of 230 kV elements. The estimated cost of the project is $954.7 million. In April 2025 the LPSC staff and the Louisiana Energy Users Group, an intervenor, filed direct testimony. The LPSC staff’s testimony recommends LPSC approval of the project. The Louisiana Energy Users Group’s testimony opines that Entergy Louisiana has shown that there is a need for additional transmission investment in the West Bank area of Amite South but recommends that the LPSC withhold approval pending further analysis, including analysis of potential lower cost alternatives to the proposed project, and also pending Entergy Louisiana demonstrating that it has contributions in aid of construction from the customers whose block load additions would be enabled by the proposed transmission project in amounts sufficient to substantially, if not fully, cover the revenue requirement of the proposed project. In June 2025, Entergy Louisiana filed rebuttal testimony. A hearing was held in August 2025. In November 2025 the presiding ALJ issued a proposed recommendation granting the application and the requested certification. The Louisiana Energy Users Group filed exceptions to the proposed recommendation, and the LPSC staff and Entergy Louisiana filed responses in opposition to those exceptions. In December 2025 the ALJ issued a final recommendation granting the application and the requested certification. In December 2025 the LPSC issued an order adopting the final recommendation granting the application and the requested certification.Cottonwood Power StationIn December 2025, Entergy Louisiana filed an application seeking LPSC approval and a certificate of convenience and necessity to acquire the Cottonwood combined cycle combustion turbine facility, a 1,263 MW combined cycle facility in Deweyville, Texas that was originally placed in commercial service in 2003. The filing seeks findings from the LPSC that the costs of the acquisition, including the approximately $1.5 billion purchase price and $309.3 million in capital upgrades and maintenance items needed to bring Cottonwood into alignment with Entergy Louisiana’s fleet standards with respect to operations and safety, are eligible for recovery in customer rates. The application requests an LPSC decision by October 2026. A procedural schedule has been set with a hearing scheduled for September 2026. The acquisition is currently targeted to occur in January 2027.Babel - Webre 500 kV Transmission ProjectIn December 2025, Entergy Louisiana filed an application with the LPSC seeking a certificate of public convenience and necessity for a 500 kV transmission project that includes the construction of a new 147-mile Babel to Webre 500 kV transmission line, the reconstruction of the Webre 500 kV switching station in Louisiana, and coordination with Entergy Texas of the construction of an approximately 4-mile 500 kV transmission line in Texas. The project was approved by MISO in the 2025 MISO Transmission Expansion Plan and has an estimated cost of $1,238 million and an estimated in-service date of August 2029. The application requests an LPSC decision by June 2026.Waterford 6 Power Station and Westlake Power StationIn February 2026, Entergy Louisiana filed an application seeking LPSC approval and certification to construct two 754 MW combined cycle combustion turbine generators, the Waterford 6 Power Station and the Westlake Power Station, to be located at Entergy Louisiana’s existing Waterford site near Killona, Louisiana and existing Roy S. Nelson site in Westlake, Louisiana, respectively. In its application, Entergy Louisiana noted the estimated costs are approximately $2,027 million for the Waterford 6 Power Station and $2,091 million for the Westlake Power Station. Entergy Louisiana asked that the LPSC consider the requests in the application at or before its December 2026 meeting. The estimated in-service dates for the Waterford 6 Power Station and Westlake Power Station are July 2030 and October 2030, respectively. Entergy Mississippi Additional Generation and Transmission ResourcesIn March 2024, Entergy Mississippi executed a large customer supply and service agreement to serve two data center campuses located in Madison County, Mississippi in which Amazon Web Services is investing. In February 2025, Entergy Mississippi also executed a large customer supply and service agreement to serve a data center campus located in Warren County, Mississippi in which Amazon Web Services is investing. Entergy Mississippi will need generation and transmission resources to reliably serve all Entergy Mississippi customers, including the data centers. The large customer supply and service agreements also contain provisions which cover Entergy Mississippi’s incremental investment costs in the event of early termination. Entergy Mississippi anticipates recovering the incremental cost to serve the customer through the revenues it is collecting under the large customer supply and service agreements.In May 2024 the MPSC approved Entergy Mississippi’s revisions to its formula rate plan to comply with state legislation passed in January 2024 allowing Entergy Mississippi to make interim rate adjustments, including the collection of a return on construction work in progress on a cash basis, to recover the non-fuel related annual ownership cost of certain facilities that directly or indirectly provide service to customers who own certain data processing center projects as specified in the legislation.Delta Blues Advanced Power StationIn September 2024, Entergy Mississippi announced plans to construct, own, and operate the Delta Blues Advanced Power Station, a 754 MW combined cycle combustion turbine facility, to be located in Washington County, Mississippi. The facility will primarily be powered by natural gas, and it will also be enabled for future carbon capture and storage and for hydrogen co-firing optionality. The Delta Blues Advanced Power Station is estimated to cost $1.2 billion. Construction of the Delta Blues Advanced Power Station qualifies for pre-certification under Mississippi legislation providing for the pre-certification of construction of certain types of facilities that directly or indirectly provide electric service to customers who own certain data processing center projects as specified in the legislation. As provided for in this legislation, Entergy Mississippi began recovery of certain costs of construction of the Delta Blues Advanced Power Station through the interim facilities rate adjustments provision of its formula rate plan rider. Non-fuel revenue collected from the data center customer will be included in the formula rate plan to offset the facility’s revenue requirement. The project costs will be reviewed for prudence by the MPSC following the completion of construction. Construction is in progress, and the facility is expected to be in service by May 2028.Traceview Advanced Power StationEntergy Mississippi is constructing a 754 MW combined cycle combustion turbine facility located in the City of Ridgeland, Madison County, Mississippi. The facility will be powered primarily by natural gas, and it will also be enabled for future carbon capture and storage and for hydrogen co-firing optionality. The project is estimated to cost in excess of $1 billion. Construction of the Traceview Advanced Power Station qualifies for pre-certification under Mississippi legislation providing for the pre-certification of construction of certain types of facilities that directly or indirectly provide electric service to customers who own certain data processing center projects as specified in the legislation. As provided for in this legislation, Entergy Mississippi will begin recovery of certain costs of construction of the Traceview Advanced Power Station through the interim facilities rate adjustments provision of its formula rate plan rider. Non-fuel revenue collected from the data center customer will be included in the formula rate plan to offset the facility’s revenue requirement. The project costs will be reviewed for prudence by the MPSC following the completion of construction. The facility is expected to be in service in 2029.Vicksburg Advanced Power StationIn October 2025, Entergy Mississippi announced plans to construct, own, and operate the Vicksburg Advanced Power Station, a 754 MW combined cycle combustion turbine facility, to be located in the City of Vicksburg, Warren County, Mississippi. The facility will be powered primarily by natural gas, and it will also be enabled for future carbon capture and storage and for hydrogen co-firing optionality. The Vicksburg Advanced Power Station is estimated to cost $1.2 billion. Construction of the Vicksburg Advanced Power Station qualifies for pre-certification under Mississippi legislation providing for the pre-certification of construction of certain types of facilities that directly or indirectly provide electric service to customers who own certain data processing center projects as specified in the legislation. As provided for in this legislation, Entergy Mississippi will begin recovery of certain costs of construction of the Vicksburg Advanced Power Station through the interim facilities rate adjustments provision of its formula rate plan rider. Non-fuel revenue collected from the data center customer will be included in the formula rate plan to offset the facility’s revenue requirement. The project costs will be reviewed for prudence by the MPSC following the completion of construction. Construction is in progress, and the facility is expected to be in service in August 2028.Orange County Advanced Power StationIn September 2021, Entergy Texas filed an application seeking PUCT approval to amend Entergy Texas’s certificate of convenience and necessity to construct, own, and operate the Orange County Advanced Power Station, a new 1,215 MW combined cycle combustion turbine facility to be located in Bridge City, Texas at an initially-estimated expected total cost of $1.2 billion inclusive of the estimated costs of the generation facilities, transmission upgrades, contingency, an allowance for funds used during construction, and necessary regulatory expenses, among others. The project includes combustion turbine technology with dual fuel capability, able to co-fire up to 30% hydrogen by volume upon commercial operation and upgradable to support 100% hydrogen operations in the future. In December 2021 the PUCT referred the proceeding to the State Office of Administrative Hearings. In March 2022 certain intervenors filed testimony opposing the hydrogen co-firing component of the proposed project and others filed testimony opposing the project outright. Also in March 2022 the PUCT staff filed testimony opposing the hydrogen co-firing component of the proposed project, but otherwise taking no specific position on the merits of the project. The PUCT staff also proposed that the PUCT establish a maximum amount that Entergy Texas may recover in rates attributable to the project. In April 2022, Entergy Texas filed rebuttal testimony addressing and rebutting these various arguments. The hearing on the merits was held in June 2022, and post-hearing briefs were submitted in July 2022. In September 2022 the ALJs with the State Office of Administrative Hearings issued a proposal for decision recommending the PUCT approve Entergy Texas’s application for certification of Orange County Advanced Power Station subject to certain conditions, including a cap on cost recovery at $1.37 billion, the exclusion of investment associated with co-firing hydrogen, weatherization requirements, and customer receipt of any contractual benefits associated with the facility’s guaranteed heat rate. In October 2022 the parties in the proceeding filed exceptions and replies to exceptions to the proposal for decision. Also in October 2022, Entergy Texas filed with the PUCT information regarding a new fixed pricing option for an estimated project cost of approximately $1.55 billion associated with Entergy Texas’s issuance of limited notice to proceed by mid-November 2022. In November 2022 the PUCT issued a final order approving the requested amendment to Entergy Texas’s certificate of convenience and necessity to construct, own, and operate the Orange County Advanced Power Station without the investment associated with hydrogen co-firing capability, without a cap on cost recovery, and subject to certain conditions, including weatherization requirements and customer receipt of any contractual benefits associated with the facility’s guaranteed heat rate.In December 2022, Texas Industrial Energy Consumers and Sierra Club filed motions for rehearing of the PUCT’s final order alleging the PUCT erred in granting the certification of the Orange County Advanced Power Station, in not imposing a cost cap, in including certain findings related to the reasonableness of Entergy Texas’s request for proposals from which the Orange County Advanced Power Station was selected, and in other regards. Also in December 2022, Entergy Texas filed a response to the motions for rehearing refuting the points raised therein. In January 2023 the PUCT issued letters noting that it voted to consider Texas Industrial Energy Consumers’ motion for rehearing at its upcoming January 2023 open meeting and voted not to consider Sierra Club’s motion for rehearing at an open meeting. At the January 2023 open meeting, the PUCT voted to grant Texas Industrial Energy Consumers’ motion for rehearing for the limited purpose of issuing an order on rehearing that excludes three findings related to Entergy Texas’s request for proposals. The order on rehearing does not change the PUCT’s certification of the Orange County Advanced Power Station or the conditions placed thereon in the PUCT’s November 2022 final order. Construction is in progress, and subject to receipt of required permits, the facility is expected to be in service by mid-2026.Legend Power Station and Lone Star Power StationIn June 2024, Entergy Texas filed an application seeking PUCT approval to amend Entergy Texas’s certificate of convenience and necessity to construct, own, and operate the Legend Power Station, a 754 MW combined cycle combustion turbine facility, which will be enabled for future carbon capture and storage and for hydrogen co-firing optionality, to be located in Jefferson County, Texas, and the Lone Star Power Station, a 453 MW simple cycle combustion turbine facility, which will be enabled with hydrogen co-firing optionality, to be located in Liberty County, Texas. In its application, Entergy Texas noted that the Legend Power Station was expected to cost an estimated $1.46 billion and the Lone Star Power Station was expected to cost an estimated $735.3 million, in each case inclusive of the estimated costs of the generation facilities, interconnection costs, transmission network upgrades, and an allowance for funds used during construction. In July 2024 the PUCT referred the proceeding to the State Office of Administrative Hearings and, also in July 2024, the ALJ with the State Office of Administrative Hearings adopted a procedural schedule, with a hearing on the merits scheduled to begin in October 2024. In September 2024, Entergy Texas filed, and the ALJ with the State Office of Administrative Hearings granted, a motion to extend the procedural schedule in this proceeding in order to address certain developments relating to the cost and scope of the Legend Power Station and the Lone Star Power Station. In December 2024, Entergy Texas filed supplemental testimony and exhibits addressing the cost and scope developments associated with the Legend Power Station and the Lone Star Power Station in further support of its application. The cost and scope developments include cost estimate increases of $139 million for Legend Power Station and $63.7 million for Lone Star Power Station and the consideration of an alternate site for Lone Star Power Station, which would reduce the estimated cost increase of the Lone Star Power Station to $36.2 million. In March 2025, Entergy Texas filed testimony explaining that Entergy Texas planned to move forward with building the Lone Star Power Station on a more cost-effective alternative site in San Jacinto County, Texas. A hearing on the merits was held in April 2025. Also in April 2025, Entergy Texas, intervenors, and the PUCT staff filed initial briefs. In its initial brief, the PUCT staff recommended denial of Entergy Texas’s application or, in the alternative, approval subject to conditions that include a prudence review by an external consultant if actual project costs exceed estimated costs by more than 10%, transmission cost reporting, and weatherization of both the Legend Power Station and the Lone Star Power Station. Certain intervenors requested that the PUCT impose various conditions upon the approval of the resources, including, among others, cost recovery limitations, a direction that Entergy Texas initiate a competitive tariff proceeding to facilitate industrial sleeving, a requirement for additional regulatory approvals related to hydrogen or carbon capture and storage implementation, limits on the recovery of supplemental filing costs, and calculation of AFUDC based on an adjusted weighted average cost of capital. Reply briefs were filed in May 2025. In June 2025 the ALJs with the State Office of Administrative Hearings issued a proposal for decision, in which they recommended rejection of Entergy Texas’s application to construct the Legend Power Station and the Lone Star Power Station based upon their finding that Entergy Texas did not demonstrate the resources to be cost-effective alternatives to address the uncontested need for additional generation. In the alternative, the ALJs recommended that if the PUCT approves the resources, that conditions be imposed, including a deferral of the finding that the resources were prudently selected until Entergy Texas’s next rate case, a prudence review by an external consultant if actual project costs exceed estimated costs by more than 10%, weatherization requirements, and a requirement that Entergy Texas obtain additional regulatory approvals prior to implementing hydrogen co-firing or carbon capture and storage. The ALJs’ proposal for decision was an interim step in the certification process and was not binding upon the PUCT. Entergy Texas filed exceptions in July 2025. In September 2025 the PUCT issued a decision granting the application, subject to conditions that include a cost cap at Entergy Texas’s previously-filed modified estimated costs of $1.6 billion for the Legend Power Station and $799 million for the Lone Star Power Station, weatherization requirements, environmental compliance requirements, and a requirement to request additional authorization prior to implementing hydrogen co-firing or carbon capture and storage. In October 2025 an intervenor filed a motion for rehearing requesting that the PUCT modify the Lone Star Power Station cost cap to reflect the estimated project costs associated with a new project site, clarify that the cost cap is inclusive of transmission upgrades, and reconsider the intervenor’s prior proposal for a “soft cost cap” below the estimated project costs, and that Entergy Texas be directed to initiate a competitive tariff proceeding to facilitate industrial sleeving of purchased power. Entergy Texas filed a response to the motion for rehearing in October 2025. In December 2025 the PUCT issued an order on rehearing modifying the Lone Star Power Station cost cap to $771.5 million to reflect the estimated project costs associated with a new project site and clarifying that the cost cap is inclusive of transmission upgrades, but denying the other relief requested in the motion for rehearing. See Note 8 to the financial statements for discussion of the build-to-suit lease arrangement for the Legend Power Station. Construction is underway, and subject to receipt of required permits and other conditions, both facilities are expected to be in service by mid-2028.Southeast Texas Area Reliability Project (SETEX)In February 2025, Entergy Texas filed an application seeking PUCT approval to amend Entergy Texas’s certificate of convenience and necessity to construct, own, and operate a new single-circuit 500 kV transmission line and associated stations and 138/230 kV facilities. The transmission line is expected to be approximately 131 to 160 miles in length and the estimated cost of the project ranges from $1.3 billion to $1.5 billion, depending upon the route ultimately approved by the PUCT. Also in February 2025 the PUCT referred the proceeding to the State Office of Administrative Hearings. A hearing on the merits was held in May 2025. In July 2025 the ALJs with the State Office of Administrative Hearings issued a proposal for decision recommending the PUCT approve Entergy Texas’s application to construct SETEX and recommending the PUCT’s approval include selection of a specific route with an estimated cost of $1.4 billion. In October 2025 the PUCT issued a final order approving the requested amendment to Entergy Texas’s certificate of convenience and necessity to construct, own, and operate the new single-circuit 500 kV transmission line and associated stations and 138/230 kV facilities, and selecting the final route for the project, which has an estimated cost of $1.36 billion. In November 2025, multiple parties filed motions for rehearing primarily challenging the routing of the transmission line. In December 2025 the PUCT issued an order on rehearing reaffirming and providing additional support for its initial decision. Subject to receipt of required permits and other conditions, the facility is expected to be in service by the end of 2029.Cypress to Legend 500 kV Transmission LineIn May 2025, Entergy Texas filed an application seeking PUCT approval to amend Entergy Texas’s certificate of convenience and necessity to construct, own, and operate a new single-circuit 500 kV transmission line. The transmission line is expected to be approximately 40 to 49 miles in length and the estimated cost of the project ranges from $392.7 million to $436.2 million, depending on the route ultimately approved by the PUCT. In June 2025 the PUCT referred the proceeding to the State Office of Administrative Hearings and a hearing on the merits was held in August 2025. In October 2025 the ALJs with the State Office of Administrative Hearings issued a proposal for decision recommending the PUCT approve Entergy Texas’s application to construct the transmission line and recommending the PUCT’s approval include selection of a specific route with an estimated cost of $398.7 million. In December 2025 the PUCT issued a final order approving the requested amendment to Entergy Texas’s certificate of convenience and necessity to construct, own, and operate the new single-circuit 500 kV transmission line, and selecting the final route previously recommended. In February 2026, landowners not party to the PUCT proceeding filed in the 345th District Court of Travis County, Texas a petition for declaratory relief and temporary and permanent injunction against the PUCT’s final order. The petition, which names the PUCT, its commissioners, and Entergy Texas as defendants, challenges Entergy Texas’s notice, the application of the PUCT’s notice rule, and the PUCT order’s approval of a route the petitioner’s assert was not adequately noticed. Entergy Texas expects to file an answer disputing all aspects of the petition by the applicable deadline. Subject to receipt of required permits and other conditions, the facility is expected to be in service by the end of 2028.

Resilience and Grid Hardening

Entergy LouisianaIn December 2022, Entergy Louisiana filed an application with the LPSC seeking a public interest finding regarding Phase I of Entergy Louisiana’s Future Ready resilience plan and approval of a rider mechanism to recover the program’s costs. Phase I in the December 2022 application reflected the first five years of a ten-year resilience plan and included investment of approximately $5 billion, including hardening investment, transmission dead-end structures, enhanced vegetation management, and telecommunications improvement. In April 2024 the LPSC approved a framework which includes an initial five-year resilience plan providing for an investment of approximately $1.9 billion with cost recovery via a forward-looking rider with semi-annual true-ups. The plan is subject to specified reporting requirements and includes a performance review of the hardened assets. The LPSC order approving the framework does not include any restrictions on Entergy Louisiana’s ability to file applications for approval of additional investments in resilience.The LPSC had previously opened a formal rulemaking proceeding in December 2021 to investigate efforts to improve resilience of electric utility infrastructure. In April 2023 the LPSC staff issued a draft rule in the rulemaking proceeding related to a requirement to file a grid resilience plan. The procedural schedule entered in the rulemaking proceeding contemplated adoption of a final rule in October 2023, but this did not occur, and a new date has not been set.The LPSC also has pending rulemakings addressing issues related to pole viability and grid maintenance practices. In December 2023, in those rulemakings, the LPSC staff issued a report and recommendation proposing to impose significant new reporting and compliance obligations related to jurisdictional utilities’ distribution and transmission operations, including new obligations related to grid hardening plans, pole inspections, pole replacement, vegetation management, storm restoration plans, new reliability metrics, software for handling customer complaints and complaint resolution, required use of drone technology, and new penalties and incentives for reliability performance and for compliance with the new obligations. In February 2024, Entergy Louisiana and other parties filed comments on the LPSC staff’s report. These rulemakings were formally closed in August 2025 without the adoption of any rules or obligations being promulgated by the LPSC.In October 2021 the City Council passed a resolution and order establishing a docket and procedural schedule with respect to system resiliency and storm hardening. In July 2022, Entergy New Orleans filed with the City Council a response identifying a preliminary plan for storm hardening and resiliency projects, including microgrids, to be implemented over ten years at an approximate cost of $1.5 billion. In February 2023 the City Council approved a revised procedural schedule requiring Entergy New Orleans to make a filing in April 2023 containing a narrowed list of proposed hardening projects. In April 2023, Entergy New Orleans filed the required application and supporting testimony seeking City Council approval of the first phase (five years and $559 million) of a ten-year infrastructure hardening plan totaling approximately $1 billion. Entergy New Orleans also sought, among other relief, City Council approval of a resilience and storm hardening cost recovery rider to recover from customers the costs of the infrastructure hardening plan. In February 2024 the City Council approved a resolution authorizing Entergy New Orleans to implement a resilience project to be partially funded by $55 million of matching funding through the DOE’s Grid Resilience and Innovation Partnerships program. The resolution also required Entergy New Orleans to submit, no later than July 2024, a revised resilience plan consisting of projects over a three-year period. In March 2024, Entergy New Orleans filed with the City Council for approval the requested three-year resilience plan, which included $168 million in hardening projects. The three-year resilience plan was to be in addition to the previously authorized resilience project to be partially funded by the DOE’s Grid Resilience and Innovation Partnerships program. In October 2024 the City Council approved a resolution authorizing a two-year resilience plan totaling $100 million and approved the requested resilience and storm hardening cost recovery rider. In December 2024, Entergy New Orleans notified the City Council of the subset of hardening projects from the revised three-year resilience plan to be included in the two-year resilience plan. Entergy New Orleans implemented the approved resilience and storm hardening cost recovery rider effective with the first billing cycle of January 2025. In December 2025, the City Council issued a resolution establishing certain metrics and reporting requirements for the approved hardening projects. Also in December 2025, Entergy New Orleans filed an application and supporting testimony seeking the City Council’s approval of the second phase of its infrastructure hardening plan totaling approximately $400 million over a five-year period (2027 to 2031). Entergy New Orleans also sought, among other relief, the City Council’s approval to continue to use the resilience and storm hardening cost recovery rider to recover from customers the costs of the plan. Entergy New Orleans requested the City Council approve the application by October 2026.Entergy TexasIn June 2024, Entergy Texas filed an application with the PUCT requesting approval of Phase I of its Texas Future Ready Resiliency Plan, a set of measures to begin accelerating the resiliency of Entergy Texas’s transmission and distribution system. Phase I is comprised of projects totaling approximately $335.1 million, including approximately $137 million of projects to be funded by Entergy Texas and approximately $198 million of projects contingent upon Entergy Texas’s receipt of grant funds in that amount from the Texas Energy Fund. The projects in Phase I include distribution and transmission hardening and modernization projects and targeted vegetation management projects to mitigate the risk of wildfire. These projects are expected to be implemented within approximately three years of PUCT approval. In January 2025 the PUCT unanimously approved Phase I of Entergy Texas’s Texas Future Ready Resiliency Plan, including the approximately $137 million of projects to be funded by Entergy Texas and application of performance metrics consistent with the unopposed settlement. The PUCT clarified that, while not part of Entergy Texas’s Phase I plan, Entergy Texas is permitted to pursue the remaining $198 million of identified projects and Texas Energy Fund grant funding for those projects. In February 2025 the PUCT issued an order adopting a new rule establishing the procedures for application to the grant fund. In July 2025, Entergy Texas submitted an application for approximately $200 million in grant funding from the Texas Energy Fund to implement the resilience projects originally included in its Texas Future Ready Resiliency Plan. In October 2025 the PUCT voted to approve the approximately $200 million grant request in full. The portion of the projects funded by Entergy Texas will be eligible for recovery through Entergy Texas’s transmission or distribution cost recovery factor riders, as applicable.

Dividends and Stock Repurchases

Declarations of dividends on Entergy Corporation common stock are made at the discretion of the Board. Among other things, the Board evaluates the level of Entergy Corporation common stock dividends based upon earnings per share from the Utility segment and the Parent and Other portion of the business, financial strength, and future investment opportunities. In January 2026 the Board declared a dividend of $0.64 per share. Entergy paid $1,074 million in 2025, $982 million in 2024, and $918 million in 2023 in cash dividends on its common stock.In accordance with Entergy’s stock-based compensation plans, Entergy periodically grants stock options, restricted stock, performance units, and restricted stock units to key employees, which may be exercised to obtain shares of Entergy Corporation common stock. According to the plans, these shares can be newly issued shares, treasury stock, or shares purchased on the open market. Entergy’s management has been authorized by the Board to repurchase on the open market shares up to an amount sufficient to fund the exercise of grants under the plans.In addition to the authority to fund grant exercises, the Board has authorized share repurchase programs to enable opportunistic purchases in response to market conditions. In October 2010 the Board granted authority for a $500 million share repurchase program. As of December 31, 2025, $350 million of authority remains under the $500 million share repurchase program. The amount of repurchases may vary as a result of material changes in business results or capital spending or new investment opportunities, or if limitations in the credit markets continue for a prolonged period.Entergy’s sources to meet its capital requirements and to fund potential investments include:•cash on hand ($1,929 million as of December 31, 2025);•storm reserve escrow accounts;•debt and equity issuances in the capital markets, including debt issuances to refund or retire currently outstanding or maturing indebtedness;•bank financing under new or existing facilities or commercial paper; and•sales of assets.Circumstances such as weather patterns, fuel and purchased power price fluctuations, and unanticipated expenses, including unscheduled plant outages and storms, could affect the timing and level of internally generated funds in the future. In addition to the financings necessary to meet capital requirements and contractual obligations, the Registrant Subsidiaries expect to continue, when economically feasible, to retire higher-cost debt and replace it with lower-cost debt if market conditions permit.Provisions within the organizational documents relating to preferred stock or membership interests of certain of Entergy Corporation’s subsidiaries could restrict the payment of cash dividends or other distributions on their common and preferred equity. All debt and preferred equity issuances by the Registrant Subsidiaries require prior regulatory approval and their debt issuances are also subject to requirements set forth in bond indentures and other agreements. Entergy believes that the Registrant Subsidiaries have sufficient capacity under these tests to meet foreseeable capital needs for the next twelve months and beyond.The FERC has jurisdiction over securities issuances by the Utility operating companies and System Energy. The City Council has concurrent jurisdiction over Entergy New Orleans’s securities issuances with maturities longer than one year. The APSC has concurrent jurisdiction over Entergy Arkansas’s issuances of securities secured by Arkansas property, including first mortgage bond issuances. No regulatory approvals are necessary for Entergy Corporation to issue securities. The current FERC-authorized short-term borrowing limits and long-term financing authorization for Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are effective through January 2027. The current FERC-authorized short-term borrowing limit and long-term financing authorization for Entergy Arkansas is effective through February 2028. Entergy Arkansas has obtained first mortgage bond/secured financing authorization from the APSC that extends through December 2027. Entergy New Orleans also has obtained long-term financing authorization from the City Council that extends through December 2027. Entergy Louisiana and System Energy each has obtained long-term financing authorization from the FERC that extends through January 2027 for issuances by the nuclear fuel company variable interest entities. Entergy Arkansas has obtained long-term financing authorization from the FERC that extends through February 2028 for issuances by its nuclear fuel company variable interest entity. In addition to borrowings from commercial banks, the Registrant Subsidiaries may also borrow from the Entergy system money pool and from other internal short-term borrowing arrangements. The money pool is an intercompany cash management program that makes possible intercompany borrowing and lending arrangements, and the money pool and the other internal borrowing arrangements are designed to reduce Entergy’s subsidiaries’ dependence on external short-term borrowings. Borrowings from internal and external short-term borrowings combined may not exceed the FERC-authorized limits. See Notes 4 and 5 to the financial statements for further discussion of Entergy’s borrowing limits, authorizations, and amounts outstanding.

Equity Issuances and Equity Distribution Program

In January 2021, Entergy Corporation entered into an equity distribution sales agreement with several counterparties establishing an at the market equity distribution program, pursuant to which Entergy Corporation may offer and sell from time to time shares of its common stock. The sales agreement provides that, in addition to the issuance and sale of shares of Entergy Corporation common stock, Entergy Corporation may enter into forward sale agreements for the sale of its common stock. The aggregate number of shares of common stock sold under this sales agreement and under any forward sale agreement may not exceed an aggregate gross sales price of $4.5 billion. As of December 31, 2025, Entergy Corporation has utilized the equity distribution program either to sell or to enter into forward sale agreements with respect to shares of common stock with an aggregate gross sales price of approximately $2.8 billion, of which approximately $2.6 billion of aggregate gross sales price was the subject of forward sale agreements, subject to adjustment pursuant to the forward sale agreements. Entergy Corporation settled certain of its then-outstanding forward sale agreements for cash proceeds of $131 million in 2023 and $1,138 million in 2025. There were no settlements of forward sale agreements for the year ended December 31, 2024.In March 2025, Entergy Corporation marketed an equity offering of 17.8 million shares of Entergy Corporation common stock. In lieu of issuing equity at the time of the offering, Entergy Corporation entered into forward sale agreements with several forward counterparties. The forward sale agreements require Entergy Corporation to, at its election on or prior to September 30, 2026, either (1) physically settle the transactions by issuing the total of 17.8 million shares of its common stock to the forward counterparties in exchange for net proceeds at the then-applicable forward sale price specified by the agreements (initially $81.87 per share) or (2) net settle the transactions in whole or in part through the delivery or receipt of cash or shares. The forward sale price is subject to adjustment on a daily basis based on a floating interest rate factor and will decrease by other fixed amounts specified in the agreements.In February 2026, Entergy Corporation physically settled a portion of its obligations under certain of its outstanding forward sale agreements under its at the market equity distribution program for cash proceeds of $346 million.Entergy Corporation currently expects to issue approximately $4.4 billion of equity through 2029, which it may issue under its at the market equity distribution program or otherwise, with approximately $1.9 billion already contracted under forward sale agreements as of December 31, 2025, including under its at the market equity distribution program ($346 million of which were settled in February 2026 as described above) and the March 2025 equity offering described above. See Note 7 to the financial statements for discussion of the forward sale agreements and common stock issuances and sales under the equity distribution program.

Entergy Texas Build-to-Suit Lease Arrangement for the Legend Power Station

In December 2025, Entergy Texas entered into a build-to-suit lease arrangement for the Legend Power Station as the lessee with a consortium of investors (the Investors). Under the terms of the arrangement, the Investors purchased the in-process Legend Power Station construction project from Entergy Texas at a cost of $359 million and will spend up to $1.45 billion (including the initial purchase price) to construct the Legend Power Station project as designed by Entergy Texas. Entergy Texas is engaged to serve as the construction agent for the Legend Power Station project. The Investors, however, control the asset during construction. If Entergy Texas defaults in its role as construction agent, the Investors have various options available to remedy the default, including by accelerating the lease balance payable by Entergy Texas, causing a sale of the Legend Power Station project to a third party, or certain other options. If there are certain changes to the terms of the PUCT approval of the Legend Power Station project or certain other circumstances outside of Entergy Texas’s control, then either the Investors or Entergy Texas could exercise the right to terminate the arrangement, in which case Entergy Texas would be required to purchase the in-process Legend Power Station project from the Investors at an amount equal to their costs incurred to date, including carrying costs. Since Entergy Texas does not control the in-process construction project, it will not recognize the asset (i.e., construction work in progress) or an associated liability during construction.Upon the Legend Power Station’s readiness for first synchronization to the grid, expected in early 2028, a triple-net lease will commence under which Entergy Texas will have control of the Legend Power Station and receive all output from the plant. The initial term of the lease will end seven years from the closing of the arrangement, or approximately five years after the Legend Power Station’s expected readiness for first synchronization to the grid. The lease cost will be equal to the Secured Overnight Financing Rate plus a margin which is based on the credit rating of Entergy Texas, multiplied by the total costs (including carrying costs) incurred by the Investors as of the commencement of the lease. Entergy Texas will have the option to purchase the Legend Power Station at any time during the lease term at a price equal to the total cost of the plant to the Investors, plus any fees and carrying charges owed to the Investors. If the purchase price option is exercised within two years of commencement of the triple-net lease, Entergy Texas must enter into a secured note payable to the Investors for the amount of the purchase price. The note payable would be due at the end of the initial lease term, but may be prepaid at any time beginning two years after the commencement date of the lease. The note will be secured by the Legend Power Station and related equipment and collateral.At the end of the initial lease term, Entergy Texas must exercise one of the following options: 1) renew the lease for an additional five year term, subject to unanimous consent of the Investors, 2) purchase the plant at a price equal to the total cost of the plant to Investors, plus any fees and carrying charges owed to the Investors, or 3) sell the plant on behalf of the Investors. If Entergy Texas chooses the third option, then it will owe or be owed any difference between the total cost of the plant to Investors and the sale price.

Cash Flow Activity

As shown in Entergy’s Consolidated Statements of Cash Flows, cash flows for the years ended December 31, 2025, 2024, and 2023 were as follows: [Table with ~7 rows, ~21 numbers, and 360 characters.] Net cash flow provided by operating activities increased $662 million in 2025 primarily due to:•higher collections from Utility customers;•the receipt of $547 million in proceeds from the transfer of 2024 nuclear and solar production tax credits to third parties in 2025. See Note 3 to the financial statements for discussion of the nuclear and solar production tax credits;•an increase of $401 million in receipts from advance payments related to customer agreements in 2025, of which $366 million is recorded as current liabilities and included within changes in other working capital accounts; and•one-time bill credits of $92 million in 2024 to Entergy Arkansas’s retail customers through the Grand Gulf credit rider as a result of the System Energy settlement with the APSC. See Note 2 to the financial statements for discussion of the System Energy settlement agreement with the APSC and Entergy Arkansas’s Grand Gulf credit rider.The increase was partially offset by higher fuel and purchased power payments, an increase of $124 million in interest paid, and the timing of payments to vendors. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery.Net cash flow used in investing activities increased $1,260 million in 2025 primarily due to:•an increase of $2,154 million in non-nuclear generation construction expenditures primarily due to higher spending by Entergy Arkansas on the Ironwood Power Station (formerly Lake Catherine Unit 5) project and the Jefferson Power Station project, by Entergy Louisiana on the Franklin Farms Power Station Units 1 and 2 project, by Entergy Mississippi on the Delta Blues Advanced Power Station project, the Vicksburg Advanced Power Station project, the Traceview Advanced Power Station project, and the Penton Solar project, and by Entergy Texas on the Legend Power Station project, the Lone Star Power Station project, and the Orange County Advanced Power Station project;•an increase of $400 million in distribution construction expenditures primarily due to increased investment in the resilience of the Utility distribution system;•an increase of $234 million in transmission construction expenditures primarily due to higher capital expenditures as a result of increased development in the Utility service area and increased spending on various transmission projects in 2025;•an increase of $115 million in nuclear construction expenditures primarily due to increased spending on various nuclear projects in 2025;•a decrease of $79 million in proceeds received in 2025 as compared to 2024 from the DOE resulting from litigation regarding spent nuclear fuel storage costs. See Note 8 to the financial statements for discussion of the spent nuclear fuel storage litigation;•cash collateral of $95 million posted in 2025 to support Entergy Arkansas’s and Entergy Louisiana’s obligations to MISO; and•an increase of $43 million in decommissioning trust fund investment activity.•the receipt of $484 million in proceeds from the sale of the Entergy Louisiana and Entergy New Orleans natural gas distribution businesses on July 1, 2025. See Note 14 to the financial statements for discussion of the sale of the Entergy Louisiana and Entergy New Orleans natural gas distribution businesses on July 1, 2025;•the initial and substantial completion payments totaling approximately $393 million in 2024 for the purchase of the Driver Solar facility by Entergy Arkansas;•the receipt of $359 million in proceeds from the sale of assets related to Entergy Texas’s Legend Power Station project in 2025. See Note 8 to the financial statements for discussion of the Entergy Texas build-to-suit lease arrangement for the Legend Power Station;•the initial and substantial completion payments totaling approximately $240 million in 2024 for the purchase of the West Memphis Solar facility by Entergy Arkansas;•the initial and substantial completion payments totaling approximately $186 million in 2024 for the purchase of the Walnut Bend Solar facility by Entergy Arkansas;•a decrease of $68 million in information technology capital expenditures primarily due to decreased spending on various technology projects in 2025;•a decrease of $57 million in nuclear fuel purchases due to variations from year to year in the timing and pricing of fuel reload requirements, materials and services deliveries, and the timing of cash payments during the nuclear fuel cycle; and•net receipts from storm reserve escrow accounts of $32 million in 2025 compared to net payments to storm reserve escrow accounts of $17 million in 2024.See Note 14 to the financial statements for discussion of the Driver Solar facility, the West Memphis Solar facility, and the Walnut Bend Solar facility purchases.Net cash flow provided by financing activities increased $940 million in 2025 primarily due to:•$1,136 million in net proceeds from the issuance of common stock in settlement of forward contracts under the at the market equity distribution program in 2025. There were no issuances of common stock under the at the market equity distribution program in 2024; and•an increase of $638 million in net customer advances for construction related to transmission, distribution, and generator interconnection agreements.•long-term debt activity providing approximately $2,249 million of cash in 2025 compared to providing approximately $2,845 million of cash in 2024;•a decrease of $100 million in proceeds received from treasury stock issuances in 2025 due to a smaller amount of previously repurchased Entergy Corporation common stock issued in 2025 to satisfy stock option exercises as compared to 2024;•an increase of $92 million in common stock dividends paid in 2025 as a result of an increase in the dividend paid per share in 2025 as compared to 2024 and an increase in the number of shares outstanding; and•an increase of $59 million in net repayments of commercial paper in 2025 as compared to 2024.See Note 7 to the financial statements for discussion of the equity distribution program. See Note 5 to the financial statements for details of long-term debt. See Note 4 to the financial statements for details of Entergy’s commercial paper program.See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow Activity” in Item 7 of Entergy’s Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 18, 2025, for discussion of operating, investing, and financing cash flow activities for 2024 compared to 2023.Entergy’s large industrial and commercial customers continually explore ways to reduce their energy costs. Entergy responds by working with industrial and commercial customers to negotiate electric service contracts with competitive rates that match specific customer needs and load profiles. Additionally, cogeneration is an option available to a portion of Entergy’s industrial customer base. Entergy actively participates in economic development, customer retention, and reclamation activities to increase industrial and commercial demand from both new and existing customers.

Rate, Cost-recovery, and Other Regulation

Rate, Cost-recovery, and Other Regulation

State and Local Rate Regulation and Fuel-Cost Recovery

The rates that the Utility operating companies charge for their services significantly influence Entergy’s financial position, results of operations, and liquidity. These companies are regulated, and the rates charged to their customers are determined in regulatory proceedings. Governmental agencies, including the APSC, the LPSC, the MPSC, the City Council, and the PUCT, are primarily responsible for approval of the rates charged to customers. Following is a summary of the Utility operating companies’ authorized returns on common equity: [Table with ~6 rows, ~5 numbers, and 186 characters.] Rate regulation and related regulatory proceedings and fuel and purchased power cost recovery proceedings for the Utility operating companies are discussed in Note 2 to the financial statements.

Federal Regulation

The FERC regulates wholesale sales of electricity rates and interstate transmission of electricity, including rates for System Energy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. The current return on equity under the Unit Power Sales Agreement is 9.65%. The Unit Power Sales Agreement is discussed in Note 8 to the financial statements.

Market and Credit Risk Sensitive Instruments

Market risk is the risk of changes in the value of commodity and financial instruments, or in future net income or cash flows, in response to changing market conditions. Entergy holds commodity and financial instruments that are exposed to the following significant market risks:•The commodity price risk associated with the sale of electricity by Entergy’s non-utility operations business.•The interest rate and equity price risk associated with Entergy’s investments in qualified pension and other postretirement benefits trust funds. See Note 11 to the financial statements for details regarding Entergy’s qualified pension and other postretirement benefits trust funds.•The interest rate and equity price risk associated with Entergy’s investments in nuclear plant decommissioning trust funds. See Note 16 to the financial statements for details regarding Entergy’s decommissioning trust funds.•The interest rate risk associated with changes in interest rates as a result of Entergy’s outstanding indebtedness. Entergy manages its interest rate exposure by monitoring current interest rates and its debt outstanding in relation to total capitalization, and by hedging some of its exposure to interest rates via derivative instruments. See Notes 4 and 5 to the financial statements for the details of Entergy’s debt outstanding. See Note 15 to the financial statements for further details on Entergy’s derivative instruments and hedging activities.The Utility has limited exposure to the effects of market risk because it operates primarily under cost-based rate regulation. To the extent approved by their retail regulators, the Utility operating companies use commodity and financial instruments to hedge the exposure to price volatility inherent in their purchased power, fuel, and gas purchased for resale costs that are recovered from customers.Entergy’s commodity and financial instruments are also exposed to credit risk. Credit risk is the risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement. Entergy is also exposed to a potential demand on liquidity due to credit support requirements within its supply or sales agreements.Some of the agreements to sell the power produced by Entergy’s non-utility operations business contain provisions that require an Entergy subsidiary to provide credit support to secure its obligations under such agreements. The primary form of credit support used to satisfy these requirements is an Entergy Corporation guarantee.  Cash and letters of credit are also acceptable forms of credit support. At December 31, 2025, based on power prices at that time, Entergy had $4 million of posted cash collateral.In addition to the ability to post cash collateral, each of the Utility operating companies has uncommitted standby letter of credit facilities as a means to post collateral to support its obligations to MISO and for other purposes. See Note 4 to the financial statements for discussion of these letter of credit facilities. As of December 31, 2025, Entergy Arkansas had $37 million of posted cash collateral and Entergy Louisiana had $58 million of posted cash collateral.Entergy’s Utility business includes the ownership and operation of nuclear generating plants and is, therefore, subject to the risks related to such ownership and operation. These include risks related to: the acquisition, use, storage, and handling and disposal of high-level and low-level radioactive materials; the substantial financial requirements, both for capital investments and operational needs, including the financial requirements to address emerging issues related to equipment reliability, to position Entergy’s nuclear fleet to meet its operational goals; the performance and capacity factors of these nuclear plants; regulatory requirements and potential future regulatory changes, including changes affecting the regulations governing nuclear plant ownership, operations, license amendments, and decommissioning; the availability of interim or permanent sites for the disposal of spent nuclear fuel and nuclear waste, including the fees charged for such disposal; the sufficiency of nuclear decommissioning trust fund assets and earnings to complete decommissioning of each site when required; and limitations on the amounts of insurance recoveries for losses in connection with nuclear plant operations and catastrophic events such as a nuclear accident.

Market and Credit Risk Sensitive Instruments

Market risk is the risk of changes in the value of commodity and financial instruments, or in future net income or cash flows, in response to changing market conditions. Entergy holds commodity and financial instruments that are exposed to the following significant market risks:•The commodity price risk associated with the sale of electricity by Entergy’s non-utility operations business.•The interest rate and equity price risk associated with Entergy’s investments in qualified pension and other postretirement benefits trust funds. See Note 11 to the financial statements for details regarding Entergy’s qualified pension and other postretirement benefits trust funds.•The interest rate and equity price risk associated with Entergy’s investments in nuclear plant decommissioning trust funds. See Note 16 to the financial statements for details regarding Entergy’s decommissioning trust funds.•The interest rate risk associated with changes in interest rates as a result of Entergy’s outstanding indebtedness. Entergy manages its interest rate exposure by monitoring current interest rates and its debt outstanding in relation to total capitalization, and by hedging some of its exposure to interest rates via derivative instruments. See Notes 4 and 5 to the financial statements for the details of Entergy’s debt outstanding. See Note 15 to the financial statements for further details on Entergy’s derivative instruments and hedging activities.The Utility has limited exposure to the effects of market risk because it operates primarily under cost-based rate regulation. To the extent approved by their retail regulators, the Utility operating companies use commodity and financial instruments to hedge the exposure to price volatility inherent in their purchased power, fuel, and gas purchased for resale costs that are recovered from customers.Entergy’s commodity and financial instruments are also exposed to credit risk. Credit risk is the risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement. Entergy is also exposed to a potential demand on liquidity due to credit support requirements within its supply or sales agreements.Some of the agreements to sell the power produced by Entergy’s non-utility operations business contain provisions that require an Entergy subsidiary to provide credit support to secure its obligations under such agreements. The primary form of credit support used to satisfy these requirements is an Entergy Corporation guarantee.  Cash and letters of credit are also acceptable forms of credit support. At December 31, 2025, based on power prices at that time, Entergy had $4 million of posted cash collateral.In addition to the ability to post cash collateral, each of the Utility operating companies has uncommitted standby letter of credit facilities as a means to post collateral to support its obligations to MISO and for other purposes. See Note 4 to the financial statements for discussion of these letter of credit facilities. As of December 31, 2025, Entergy Arkansas had $37 million of posted cash collateral and Entergy Louisiana had $58 million of posted cash collateral.Entergy’s Utility business includes the ownership and operation of nuclear generating plants and is, therefore, subject to the risks related to such ownership and operation. These include risks related to: the acquisition, use, storage, and handling and disposal of high-level and low-level radioactive materials; the substantial financial requirements, both for capital investments and operational needs, including the financial requirements to address emerging issues related to equipment reliability, to position Entergy’s nuclear fleet to meet its operational goals; the performance and capacity factors of these nuclear plants; regulatory requirements and potential future regulatory changes, including changes affecting the regulations governing nuclear plant ownership, operations, license amendments, and decommissioning; the availability of interim or permanent sites for the disposal of spent nuclear fuel and nuclear waste, including the fees charged for such disposal; the sufficiency of nuclear decommissioning trust fund assets and earnings to complete decommissioning of each site when required; and limitations on the amounts of insurance recoveries for losses in connection with nuclear plant operations and catastrophic events such as a nuclear accident.

NRC Reactor Oversight Process

The NRC’s Reactor Oversight Process is a program to collect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response. The NRC evaluates plant performance by analyzing two distinct inputs: inspection findings resulting from the NRC’s inspection program and performance indicators reported by the licensee. The evaluations result in the placement of each plant in one of the NRC’s Reactor Oversight Process Action Matrix columns: “licensee response column,” or Column 1, “regulatory response column,” or Column 2, “degraded cornerstone column,” or Column 3, “multiple/repetitive degraded cornerstone column,” or Column 4, and “unacceptable performance,” or Column 5. Plants in Column 1 are subject to normal NRC inspection activities. Plants in Column 2, Column 3, or Column 4 are subject to progressively increasing levels of inspection by the NRC with, in general, progressively increasing levels of associated costs. Continued plant operation is not permitted for plants in Column 5. All of the nuclear generating plants owned and operated by Entergy’s Utility business are currently in Column 1.The preparation of Entergy’s financial statements in conformity with GAAP requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in these assumptions and measurements could produce estimates that would have a material effect on the presentation of Entergy’s financial position, results of operations, or cash flows.

Nuclear Decommissioning Costs

Certain of the Utility operating companies and System Energy own nuclear generation facilities. Regulations require these Entergy subsidiaries to decommission the nuclear power plants after each facility is taken out of service, and cash is deposited in trust funds during the facilities’ operating lives in order to provide for this obligation. Entergy conducts periodic decommissioning cost studies to estimate the costs that will be incurred to decommission the facilities. The following key assumptions have a significant effect on these estimates.•Timing - In projecting decommissioning costs, two assumptions must be made to estimate the timing of plant decommissioning. First, the date of the plant’s retirement must be estimated for those plants that do not have an announced shutdown date. The estimate may include assumptions regarding the possibility that the plant may have an operating life shorter than the operating license expiration. Second, an assumption must be made regarding whether all decommissioning activity will proceed immediately upon plant retirement, or whether the plant will be placed in SAFSTOR status. SAFSTOR is decommissioning a facility by placing it in a safe, stable condition that is maintained until it is subsequently decontaminated and dismantled to levels that permit license termination, normally within 60 years from permanent cessation of operations. A change of assumption regarding either the period of continued operation, the use of a SAFSTOR period, or whether Entergy will continue to hold the plant or the plant is held for sale can change the present value of the asset retirement obligation.•Cost Escalation Factors - Entergy’s current decommissioning cost studies include an assumption that decommissioning costs will escalate over present cost levels by factors ranging from approximately 2% to 3% annually. A 50-basis point change in this assumption could change the estimated present value of the decommissioning liabilities by approximately 8% to 15%. The timing assumption influences the significance of the effect of a change in the estimated inflation or cost escalation rate because the effect increases with the length of time assumed before decommissioning activity ends.•Spent Fuel Disposal - Federal law requires the DOE to provide for the permanent storage of spent nuclear fuel, and legislation has been passed by Congress to develop a repository at Yucca Mountain, Nevada. The DOE has not yet begun accepting spent nuclear fuel and is in non-compliance with federal law. The DOE continues to delay meeting its obligation and Entergy’s nuclear plant owners are continuing to pursue damage claims against the DOE for its failure to provide timely spent fuel storage. Until a federal site is available, however, nuclear plant operators must provide for interim spent fuel storage on the nuclear plant site, which can require the construction and maintenance of dry cask storage sites or other facilities. The costs of developing and maintaining these facilities during the decommissioning period can have a significant effect (as much as an average of 20% to 30% of total estimated decommissioning costs). Entergy’s decommissioning studies include cost estimates for spent fuel storage. These estimates could change in the future, however, based on the expected timing of when the DOE begins to fulfill its obligation to receive and store spent nuclear fuel. See Note 8 to the financial statements for further discussion of Entergy’s spent nuclear fuel litigation.•Technology and Regulation - Over the past several years, more practical experience with the actual decommissioning of nuclear facilities has been gained and that experience has been incorporated into Entergy’s current decommissioning cost estimates. Given the long duration of decommissioning projects, additional experience, including technological advancements in decommissioning, could be gained and affect current cost estimates. In addition, if regulations regarding nuclear decommissioning were to change, this could affect cost estimates.•Interest Rates - The estimated decommissioning costs that are the basis for the recorded decommissioning liability are discounted to present value using a credit-adjusted risk-free rate. When the decommissioning liability is revised, increases in cash flows are discounted using the current credit-adjusted risk-free rate. Decreases in estimated cash flows are discounted using the credit-adjusted risk-free rate used previously in estimating the decommissioning liability that is being revised. Therefore, to the extent that a revised cost study results in an increase in estimated cash flows, a change in interest rates from the time of the previous cost estimate will affect the calculation of the present value of the revised decommissioning liability.Revisions of estimated decommissioning costs that decrease the liability also result in a decrease in the asset retirement cost asset. Revisions of estimated decommissioning costs that increase the liability result in an increase in the asset retirement cost asset, which is then depreciated over the asset’s remaining economic life. See Note 9 to the financial statements for further discussion of asset retirement obligations.Entergy’s Utility operating companies and System Energy are subject to retail regulation by their respective state and local regulators and to wholesale regulation by the FERC. Because these regulatory agencies set the rates the Utility operating companies and System Energy are allowed to charge customers based on allowable costs, including a reasonable return on equity, the Utility operating companies and System Energy apply accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery from customers through regulated rates. Regulatory liabilities represent (1) revenue or gains that have been deferred because it is probable such amounts will be credited to customers through future regulated rates, (2) billings in advance of expenditures for approved regulatory programs, or (3) refunds ordered by regulators. See Note 2 to the financial statements for a discussion of rate and regulatory matters, including details of Entergy’s and the Registrant Subsidiaries’ regulatory assets and regulatory liabilities.For each regulatory jurisdiction in which they conduct business, the Utility operating companies and System Energy assess whether the regulatory assets and regulatory liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs, and factors such as changes in applicable regulatory and political environments. If the assessments made by the Utility operating companies and System Energy are ultimately different than actual regulatory outcomes, it could materially affect the results of operations, financial position, and cash flows of Entergy or the Registrant Subsidiaries.Management exercises significant judgment in evaluating the potential tax effects of Entergy’s operations, transactions, and other events. Entergy accounts for uncertain income tax positions using a recognition model under a two-step approach with a more likely-than-not recognition threshold and a measurement approach based on the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement. Management evaluates each tax position based on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Significant judgment is required to determine whether available information supports the assertion that the recognition threshold has been met. Additionally, measurement of unrecognized tax benefits to be recorded in the consolidated financial statements is based on the probability of different potential outcomes. Income tax expense and tax positions recorded could be significantly affected by events such as additional transactions contemplated or consummated by Entergy as well as audits by taxing authorities of the tax positions taken in transactions. Management believes that the financial statement tax balances are accounted for and adjusted appropriately each quarter, as necessary, in accordance with applicable authoritative guidance; however, the ultimate outcome of tax matters could result in favorable or unfavorable effects on the consolidated financial statements.Certain Entergy subsidiaries have elected to apply the mark-to-market method of accounting for income tax return purposes to wholesale power purchase agreements as appropriate under the Internal Revenue Code and U.S. Treasury Regulations. The mark-to-market tax gain or loss computed each year is based on an estimated fair market valuation which includes analyses of market prices and conditions. Entergy’s and the Registrant Subsidiaries’ mark-to-market tax position could be affected by the outcome of federal and state income tax audits should taxing authorities challenge such valuations.Entergy’s income taxes, including unrecognized tax benefits, open audits, and other significant tax matters, are discussed in Note 3 to the financial statements. See “Income Tax Legislation and Regulation” above for discussion of income tax legislation and regulation.Entergy sponsors qualified, defined benefit pension plans, including cash balance plans and final average pay plans. Generally, plan participation is determined based on the employee’s most recent date of hire and collective bargaining agreement, where applicable. Additionally, Entergy currently provides other postretirement health care and life insurance benefits for full-time employees whose most recent date of hire or rehire is before July 1, 2014, and who reach retirement age and meet certain eligibility requirements while still working for Entergy.Entergy’s reported costs of providing these benefits, as described in Note 11 to the financial statements, are affected by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate for Entergy and the Registrant Subsidiaries.

Assumptions

Key actuarial assumptions utilized in determining qualified pension and postretirement health care and life insurance costs include discount rates, projected healthcare cost rates, expected long-term rate of return on plan assets, rate of increase in future compensation levels, retirement rates, expected timing and form of payments, and mortality rates.Annually, Entergy reviews and, when necessary, adjusts the assumptions for the qualified pension and other postretirement plans. Every three-to-five years, a formal actuarial assumption experience study that compares assumptions to the actual experience of the qualified pension and postretirement health care and life insurance plans is conducted. The interest rate environment over the past few years and volatility in the financial equity markets have affected Entergy’s funding and reported costs for these benefits.Discount ratesIn selecting an assumed discount rate to calculate benefit obligations, Entergy uses a yield curve based on high-quality corporate debt with cash flows matching the expected plan benefit payments. In estimating the service cost and interest cost components of net periodic benefit cost, Entergy discounts the expected cash flows by the applicable spot rates.Projected health care cost trend ratesEntergy’s health care cost trend is affected by both medical cost inflation and, with respect to capped costs under the plan, the effects of general inflation. Entergy reviews actual recent cost trends and projected future trends in establishing its health care cost trend rates.Expected long-term rate of return on plan assetsIn determining its expected long-term rate of return on plan assets used in the calculation of benefit plan costs, Entergy reviews past performance, current and expected future asset allocations, and capital market assumptions of its investment consultant and some of its investment managers. Entergy conducts periodic asset/liability studies in order to set its target asset allocations.In 2023, Entergy implemented a new asset allocation strategy for its pension assets, based on the funded status of each plan within the trust. The new strategy no longer focuses on targeting an overall asset allocation for the trust, but rather a target asset allocation for each plan within the trust that adjusts dynamically based on the funded status. The ultimate asset allocation for each plan is expected to be attained when the plan is 110% funded. The 2025 weighted-average target pension asset allocation is 30% equity and 70% fixed income securities, of which 66% is long duration fixed income.In 2017, Entergy changed its asset allocation strategy for its non-taxable and taxable other postretirement assets, based on the funded status of each sub-account within each trust. The strategy no longer focuses on targeting an overall asset allocation for each trust, but rather a target asset allocation for each sub-account within each trust that adjusts dynamically based on the funded status. This strategy was reaffirmed based upon an asset/liability study in 2024. The 2025 weighted-average target postretirement asset allocation is 23% equity and 77% fixed income securities.See Note 11 to the financial statements for discussion of the current asset allocations for Entergy’s pension and other postretirement assets.

Costs and Sensitivities

The estimated 2026 and actual 2025 qualified pension and other postretirement costs and related underlying assumptions and sensitivities are shown below: [Table with ~23 rows, ~38 numbers, and 850 characters.] (a)    In 2025, qualified pension cost included settlement costs of $23.9 million and other postretirement income included settlement and curtailment credits of $5.2 million.Actual asset returns have an effect on Entergy’s qualified pension and other postretirement costs. In 2025, Entergy’s actual annual return on qualified pension assets was approximately 12.50% and on other postretirement assets was approximately 11%, as compared to the 2025 expected long-term rates of return discussed above.The following chart reflects the sensitivity of qualified pension cost and qualified pension projected benefit obligation to changes in certain actuarial assumptions (dollars in millions): [Table with ~4 rows, ~10 numbers, and 267 characters.] The following chart reflects the sensitivity of postretirement benefits cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in millions): [Table with ~3 rows, ~8 numbers, and 220 characters.]

Accounting Mechanisms

In accordance with pension accounting standards, Entergy utilizes a number of accounting mechanisms that reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and are amortized into expense only when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-related value of plan assets. If necessary, the excess is amortized over the average remaining service period of active employees. If almost all of the plan participants are inactive, as is the case for certain qualified pension plans, the excess is amortized over the remaining life expectancy of plan participants. Additionally, accounting standards allow for the deferral of prior service costs/credits arising from plan amendments that attribute an increase or decrease in benefits to employee service in prior periods. Prior service costs/credits are then amortized into expense over the average future working life of active employees. Certain decisions, including workforce reductions, plan amendments, and plant shutdowns, may significantly reduce the expense amortization period and result in immediate recognition of certain previously-deferred costs and gains/losses in the form of curtailment gains or losses. Similarly, payments made to settle benefit obligations, including lump sum benefit payments, can also result in accelerated recognition in the form of settlement losses or gains. Several Entergy subsidiaries received regulatory approval to defer the expense portion of settlement charges and amortize into expense over time. See Note 11 to the financial statements for further discussion.Entergy calculates the expected return on pension and other postretirement benefits plan assets by multiplying the long-term expected rate of return on assets by the market-related value (MRV) of plan assets. Entergy determines the MRV of its pension plan assets, except for the long duration fixed income assets, by calculating a value that uses a 20-quarter phase-in of the difference between actual and expected returns. For the long duration fixed income assets in the pension trust and for its other postretirement benefits plan assets, Entergy uses fair value as the MRV.Accounting standards require an employer to recognize in its balance sheet the funded status of its benefit plans. See Note 11 to the financial statements for further discussion of Entergy’s funded status.

Employer Contributions

Entergy contributed $240 million to its qualified pension plans in 2025. Entergy estimates pension contributions will be approximately $200 million in 2026 although the 2026 required pension contributions will be known with more certainty when the January 1, 2026, valuations are completed, which is expected by April 1, 2026.Minimum required funding calculations as determined under Pension Protection Act guidance, as amended by the American Rescue Plan Act of 2021, are performed annually as of January 1 of each year and are based on measurements of the assets and funding liabilities as measured at that date. Any excess of the funding liability over the calculated fair market value of assets results in a funding shortfall that must be funded over a fifteen-year rolling period. The Pension Protection Act also imposes certain plan limitations if the funded percentage, which is based on calculated fair market values of assets divided by funding liabilities, does not meet certain thresholds. For funding purposes, asset gains and losses are smoothed into the calculated fair market value of assets. The funding liability is based upon a weighted-average 24-month corporate bond rate published by the U.S. Treasury which is generally subject to a corridor of the 25-year average of prior segment rates. Periodic changes in asset returns and interest rates can affect funding shortfalls and future cash contributions.Entergy contributed $45.2 million to its other postretirement plans in 2025 and plans to contribute $40.9 million in 2026.As a company with multi-state utility operations, Entergy is subject to a number of federal and state laws and regulations and other factors and conditions in the areas in which it operates, which potentially subjects it to environmental, litigation, and other risks. Entergy periodically evaluates its exposure for such risks and records a provision for those matters which are considered probable and estimable in accordance with GAAP.

Environmental

Entergy must comply with environmental laws and regulations applicable to air emissions, water discharges, solid waste (including coal combustion residuals), hazardous waste, toxic substances, protected species, and other environmental matters. Under these various laws and regulations, Entergy could incur substantial costs to comply or address any impacts to the environment. Entergy conducts studies to determine the extent of any required remediation and has recorded liabilities based upon its evaluation of the likelihood of loss and expected dollar amount for each issue. Additional sites or issues could be identified which require environmental remediation or corrective action for which Entergy could be liable. The amounts of environmental liabilities recorded can be significantly affected by the following external events or conditions.•Changes to existing federal, state, or local regulation or related policies by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters.•The identification of additional impacts, sites, issues, or the filing of other complaints in which Entergy may be asserted to be a potentially responsible party.•The resolution or progression of existing matters through the court system or resolution by the EPA or relevant state or local authority.

Litigation

Entergy is regularly named as a defendant in a number of lawsuits involving employment, customers, and injuries and damages issues, among other matters. Entergy periodically reviews the cases in which it has been named as defendant and assesses the likelihood of loss in each case as probable, reasonably possible, or remote and records liabilities for cases that have a probable likelihood of loss and the loss can be estimated. Given the environment in which Entergy operates, and the unpredictable nature of many of the cases in which Entergy is named as a defendant, the ultimate outcome of the litigation to which Entergy is exposed has the potential to materially affect the results of operations, financial position, and cash flows of Entergy or the Registrant Subsidiaries.See Note 1 to the financial statements for discussion of new accounting pronouncements.

Assumptions

Key actuarial assumptions utilized in determining qualified pension and postretirement health care and life insurance costs include discount rates, projected healthcare cost rates, expected long-term rate of return on plan assets, rate of increase in future compensation levels, retirement rates, expected timing and form of payments, and mortality rates.Annually, Entergy reviews and, when necessary, adjusts the assumptions for the qualified pension and other postretirement plans. Every three-to-five years, a formal actuarial assumption experience study that compares assumptions to the actual experience of the qualified pension and postretirement health care and life insurance plans is conducted. The interest rate environment over the past few years and volatility in the financial equity markets have affected Entergy’s funding and reported costs for these benefits.Discount ratesIn selecting an assumed discount rate to calculate benefit obligations, Entergy uses a yield curve based on high-quality corporate debt with cash flows matching the expected plan benefit payments. In estimating the service cost and interest cost components of net periodic benefit cost, Entergy discounts the expected cash flows by the applicable spot rates.Projected health care cost trend ratesEntergy’s health care cost trend is affected by both medical cost inflation and, with respect to capped costs under the plan, the effects of general inflation. Entergy reviews actual recent cost trends and projected future trends in establishing its health care cost trend rates.Expected long-term rate of return on plan assetsIn determining its expected long-term rate of return on plan assets used in the calculation of benefit plan costs, Entergy reviews past performance, current and expected future asset allocations, and capital market assumptions of its investment consultant and some of its investment managers. Entergy conducts periodic asset/liability studies in order to set its target asset allocations.In 2023, Entergy implemented a new asset allocation strategy for its pension assets, based on the funded status of each plan within the trust. The new strategy no longer focuses on targeting an overall asset allocation for the trust, but rather a target asset allocation for each plan within the trust that adjusts dynamically based on the funded status. The ultimate asset allocation for each plan is expected to be attained when the plan is 110% funded. The 2025 weighted-average target pension asset allocation is 30% equity and 70% fixed income securities, of which 66% is long duration fixed income.In 2017, Entergy changed its asset allocation strategy for its non-taxable and taxable other postretirement assets, based on the funded status of each sub-account within each trust. The strategy no longer focuses on targeting an overall asset allocation for each trust, but rather a target asset allocation for each sub-account within each trust that adjusts dynamically based on the funded status. This strategy was reaffirmed based upon an asset/liability study in 2024. The 2025 weighted-average target postretirement asset allocation is 23% equity and 77% fixed income securities.See Note 11 to the financial statements for discussion of the current asset allocations for Entergy’s pension and other postretirement assets.

Costs and Sensitivities

The estimated 2026 and actual 2025 qualified pension and other postretirement costs and related underlying assumptions and sensitivities are shown below: [Table with ~23 rows, ~38 numbers, and 850 characters.] (a)    In 2025, qualified pension cost included settlement costs of $23.9 million and other postretirement income included settlement and curtailment credits of $5.2 million.Actual asset returns have an effect on Entergy’s qualified pension and other postretirement costs. In 2025, Entergy’s actual annual return on qualified pension assets was approximately 12.50% and on other postretirement assets was approximately 11%, as compared to the 2025 expected long-term rates of return discussed above.The following chart reflects the sensitivity of qualified pension cost and qualified pension projected benefit obligation to changes in certain actuarial assumptions (dollars in millions): [Table with ~4 rows, ~10 numbers, and 267 characters.] The following chart reflects the sensitivity of postretirement benefits cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in millions): [Table with ~3 rows, ~8 numbers, and 220 characters.]

Accounting Mechanisms

In accordance with pension accounting standards, Entergy utilizes a number of accounting mechanisms that reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and are amortized into expense only when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-related value of plan assets. If necessary, the excess is amortized over the average remaining service period of active employees. If almost all of the plan participants are inactive, as is the case for certain qualified pension plans, the excess is amortized over the remaining life expectancy of plan participants. Additionally, accounting standards allow for the deferral of prior service costs/credits arising from plan amendments that attribute an increase or decrease in benefits to employee service in prior periods. Prior service costs/credits are then amortized into expense over the average future working life of active employees. Certain decisions, including workforce reductions, plan amendments, and plant shutdowns, may significantly reduce the expense amortization period and result in immediate recognition of certain previously-deferred costs and gains/losses in the form of curtailment gains or losses. Similarly, payments made to settle benefit obligations, including lump sum benefit payments, can also result in accelerated recognition in the form of settlement losses or gains. Several Entergy subsidiaries received regulatory approval to defer the expense portion of settlement charges and amortize into expense over time. See Note 11 to the financial statements for further discussion.Entergy calculates the expected return on pension and other postretirement benefits plan assets by multiplying the long-term expected rate of return on assets by the market-related value (MRV) of plan assets. Entergy determines the MRV of its pension plan assets, except for the long duration fixed income assets, by calculating a value that uses a 20-quarter phase-in of the difference between actual and expected returns. For the long duration fixed income assets in the pension trust and for its other postretirement benefits plan assets, Entergy uses fair value as the MRV.Accounting standards require an employer to recognize in its balance sheet the funded status of its benefit plans. See Note 11 to the financial statements for further discussion of Entergy’s funded status.

Employer Contributions

Entergy contributed $240 million to its qualified pension plans in 2025. Entergy estimates pension contributions will be approximately $200 million in 2026 although the 2026 required pension contributions will be known with more certainty when the January 1, 2026, valuations are completed, which is expected by April 1, 2026.Minimum required funding calculations as determined under Pension Protection Act guidance, as amended by the American Rescue Plan Act of 2021, are performed annually as of January 1 of each year and are based on measurements of the assets and funding liabilities as measured at that date. Any excess of the funding liability over the calculated fair market value of assets results in a funding shortfall that must be funded over a fifteen-year rolling period. The Pension Protection Act also imposes certain plan limitations if the funded percentage, which is based on calculated fair market values of assets divided by funding liabilities, does not meet certain thresholds. For funding purposes, asset gains and losses are smoothed into the calculated fair market value of assets. The funding liability is based upon a weighted-average 24-month corporate bond rate published by the U.S. Treasury which is generally subject to a corridor of the 25-year average of prior segment rates. Periodic changes in asset returns and interest rates can affect funding shortfalls and future cash contributions.Entergy contributed $45.2 million to its other postretirement plans in 2025 and plans to contribute $40.9 million in 2026.As a company with multi-state utility operations, Entergy is subject to a number of federal and state laws and regulations and other factors and conditions in the areas in which it operates, which potentially subjects it to environmental, litigation, and other risks. Entergy periodically evaluates its exposure for such risks and records a provision for those matters which are considered probable and estimable in accordance with GAAP.

Environmental

Entergy must comply with environmental laws and regulations applicable to air emissions, water discharges, solid waste (including coal combustion residuals), hazardous waste, toxic substances, protected species, and other environmental matters. Under these various laws and regulations, Entergy could incur substantial costs to comply or address any impacts to the environment. Entergy conducts studies to determine the extent of any required remediation and has recorded liabilities based upon its evaluation of the likelihood of loss and expected dollar amount for each issue. Additional sites or issues could be identified which require environmental remediation or corrective action for which Entergy could be liable. The amounts of environmental liabilities recorded can be significantly affected by the following external events or conditions.•Changes to existing federal, state, or local regulation or related policies by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters.•The identification of additional impacts, sites, issues, or the filing of other complaints in which Entergy may be asserted to be a potentially responsible party.•The resolution or progression of existing matters through the court system or resolution by the EPA or relevant state or local authority.

Litigation

Entergy is regularly named as a defendant in a number of lawsuits involving employment, customers, and injuries and damages issues, among other matters. Entergy periodically reviews the cases in which it has been named as defendant and assesses the likelihood of loss in each case as probable, reasonably possible, or remote and records liabilities for cases that have a probable likelihood of loss and the loss can be estimated. Given the environment in which Entergy operates, and the unpredictable nature of many of the cases in which Entergy is named as a defendant, the ultimate outcome of the litigation to which Entergy is exposed has the potential to materially affect the results of operations, financial position, and cash flows of Entergy or the Registrant Subsidiaries.See Note 1 to the financial statements for discussion of new accounting pronouncements.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Rate and Regulatory Matters — Entergy Corporation and Subsidiaries — Refer to Note 2 to the financial statements

The Corporation is subject to rate regulation by their respective state or local utility regulatory agencies and wholesale regulation by the Federal Energy Regulatory Commission (collectively, the “Commissions”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.The Corporation’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the Commissions set the rates, the Corporation is allowed to charge customers based on allowable costs, including a reasonable return on equity, and the Corporation applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Corporation assesses whether the regulatory assets and regulatory liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs, and factors such as changes in applicable regulatory and political environments. While the Corporation has indicated it expects to recover costs from customers through regulated rates, there is a risk that the Commissions will not approve: (1) full recovery of the costs of providing utility service or (2) full recovery of amounts invested in the utility business and a reasonable return on that investment.We identified the impact of rate regulation as a critical audit matter due to the judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of recovery in future rates of incurred costs and the likelihood of refunds to customers. Auditing management’s judgments regarding the outcome of future decisions by the Commissions, recovery in future rates of regulatory assets and refunds or future reductions in rates related to regulatory liabilities involved specialized knowledge of accounting for rate regulation and the rate-setting process due to its inherent complexities and auditor judgment to evaluate management estimates and the subjectivity of audit evidence.Our audit procedures related to the uncertainty of future decisions by the Commissions, recovery in future rates of regulatory assets and refunds or future reductions in rates related to regulatory liabilities included the following, among others:•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of regulatory assets; and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the initial recognition of amounts as regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.•We evaluated the Corporation’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.•We read relevant regulatory orders issued by the Commissions for the Corporation to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. We evaluated external information and compared to management’s recorded regulatory asset and liability balances for completeness.•For regulatory matters in process, we inspected the Corporation’s and intervenors’ filings with the Commissions, initial Administrative Law Judge decisions and orders issued, and settlement offers and agreements with the Commissions for any evidence that might contradict management’s assertions.•We obtained an analysis from management and support from the Corporation’s internal and external legal counsel, as appropriate, regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order, to assess management’s assertion that amounts are probable of recovery or refund or a future reduction in rates.•We obtained representation from management regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities to assess management’s assertion that amounts are probable of recovery, refund, or a future reduction in rates.

Rate and Regulatory Matters — Entergy Corporation and Subsidiaries — Refer to Note 2 to the financial statements

The Corporation is subject to rate regulation by their respective state or local utility regulatory agencies and wholesale regulation by the Federal Energy Regulatory Commission (collectively, the “Commissions”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.The Corporation’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the Commissions set the rates, the Corporation is allowed to charge customers based on allowable costs, including a reasonable return on equity, and the Corporation applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Corporation assesses whether the regulatory assets and regulatory liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs, and factors such as changes in applicable regulatory and political environments. While the Corporation has indicated it expects to recover costs from customers through regulated rates, there is a risk that the Commissions will not approve: (1) full recovery of the costs of providing utility service or (2) full recovery of amounts invested in the utility business and a reasonable return on that investment.We identified the impact of rate regulation as a critical audit matter due to the judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of recovery in future rates of incurred costs and the likelihood of refunds to customers. Auditing management’s judgments regarding the outcome of future decisions by the Commissions, recovery in future rates of regulatory assets and refunds or future reductions in rates related to regulatory liabilities involved specialized knowledge of accounting for rate regulation and the rate-setting process due to its inherent complexities and auditor judgment to evaluate management estimates and the subjectivity of audit evidence.Our audit procedures related to the uncertainty of future decisions by the Commissions, recovery in future rates of regulatory assets and refunds or future reductions in rates related to regulatory liabilities included the following, among others:•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of regulatory assets; and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the initial recognition of amounts as regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.•We evaluated the Corporation’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.•We read relevant regulatory orders issued by the Commissions for the Corporation to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. We evaluated external information and compared to management’s recorded regulatory asset and liability balances for completeness.•For regulatory matters in process, we inspected the Corporation’s and intervenors’ filings with the Commissions, initial Administrative Law Judge decisions and orders issued, and settlement offers and agreements with the Commissions for any evidence that might contradict management’s assertions.•We obtained an analysis from management and support from the Corporation’s internal and external legal counsel, as appropriate, regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order, to assess management’s assertion that amounts are probable of recovery or refund or a future reduction in rates.•We obtained representation from management regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities to assess management’s assertion that amounts are probable of recovery, refund, or a future reduction in rates.