Entergy Arkansas, LLC: Form 10-K for the period ended Dec 31, 2025

RISK FACTORS SUMMARY

Entergy’s business is subject to numerous risks and uncertainties that could affect its ability to successfully implement its business strategy and affect its financial results. Carefully consider all of the information in this report and, in particular, the following principal risks and all of the other specific factors described in Part I, Item 1A of this report, “Risk Factors,” before deciding whether to invest in Entergy or the Registrant Subsidiaries.

Utility Regulatory Risks

• The terms and conditions of service, including electric rates, of the Registrant Subsidiaries are determined through regulatory approval proceedings that can be lengthy and subject to appeal, potentially resulting in lengthy litigation and uncertainty as to ultimate results.
• Entergy’s business could experience adverse effects related to changes to state or federal legislation or regulation, including increased tariffs, as well as changes to governmental policies and programs, including tax credits, loans, grants, guarantees, and other subsidies, or experience risks associated with participation in the MISO markets and allocation of transmission upgrade costs.
• The Utility operating companies recover fuel, purchased power, and associated costs through rate mechanisms that are subject to risks of delay or disallowance in regulatory proceedings.
• A delay or failure in recovering amounts for storm restoration costs incurred as a result of severe weather could have material effects on Entergy and its Utility operating companies affected by severe weather.
• Weather, economic conditions, technological developments, and other factors may have a material impact on electricity usage and otherwise materially affect the Utility operating companies’ results of operations.

Nuclear Operating, Shutdown, and Regulatory Risks

• The results of operations, financial condition, and liquidity of Entergy Arkansas, Entergy Louisiana, and System Energy could be materially affected by the following:
• inability to consistently operate their nuclear power plants at high capacity factors;
• refueling outages that last materially longer than anticipated or unplanned outages;
• risks related to the purchase of uranium fuel (and its conversion, enrichment, and fabrication);
• the risk that the NRC will change or modify its regulations, suspend or revoke their licenses, or increase oversight of their nuclear plants;
• risks and costs related to operating and maintaining their nuclear power plants;
• the costs associated with the storage of the spent nuclear fuel, as well as the costs of and their ability to fully decommission their nuclear power plants;
• the potential requirement to pay substantial retrospective premiums and/or assessments imposed under the Price-Anderson Act and/or by Nuclear Electric Insurance Limited (NEIL) in the event of a nuclear incident, and losses not covered by insurance;
• the risk that the decommissioning trust fund assets may not be adequate to meet decommissioning obligations if market performance and other changes decrease the value of assets in the decommissioning trusts and/or actual decommissioning costs are higher than estimated; and
• new or existing safety concerns regarding operating nuclear power plants and nuclear fuel.

Business Risks

• Entergy and the Registrant Subsidiaries depend on access to the capital markets and, at times, may face potential liquidity constraints. Disruptions in the capital and credit markets or a downgrade in Entergy’s or its Registrant Subsidiaries’ credit ratings could, among other things, adversely affect their ability to meet liquidity needs, or to access capital to operate and grow their businesses, and the cost of capital.
• The reputation of Entergy or its Registrant Subsidiaries may be materially adversely affected by negative publicity or the inability to meet their stated goals, among other potential causes.
• Changes in tax legislation and taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact Entergy’s and the Registrant Subsidiaries’ results of operations, financial condition, and liquidity.
• Entergy and its subsidiaries’ ability to successfully execute on their business strategies, including their ability to execute on their growth strategies and to complete strategic transactions, is subject to significant risks, and, as a result, they may be unable to achieve some or all of the anticipated results of such strategies.
• The success of certain Utility operating companies’ investments in new generation and transmission assets to support large-scale data centers depends on a limited number of such customers, the continued demand for electricity to power data centers and the successful completion of the associated generation and transmission projects. Any reduction in the demand for electricity to power data centers or delays or unexpected costs associated with such projects may harm the growth prospects, future operating results and financial condition of Entergy and these Utility operating companies.
• Entergy may not be able to attract, retain, and manage an appropriately staffed and qualified workforce, which could negatively affect Entergy or its subsidiaries’ results of operations.
• Entergy and its subsidiaries, including the Utility operating companies and System Energy, may incur substantial costs (i) to fulfill their obligations related to environmental and other matters or (ii) related to reliability standards.
• Entergy could be negatively affected by the effects of climate change, including physical risks, such as increased frequency and intensity of hurricanes, availability of water, droughts, and other severe weather and wildfires, and transition risks, such as environmental and regulatory obligations intended to combat the effects of climate change, including by compelling greenhouse gas emission reductions or reporting, or increasing clean or renewable energy requirements, or placing a price on greenhouse gas emissions.
• Market performance, interest rate changes, and other changes may decrease the value of employee benefit plan assets, which then could require additional funding of such benefit plans and result in increased benefit plan costs.
• The litigation environment in the states in which the Registrant Subsidiaries operate poses a significant risk to those businesses.
• Terrorist attacks and sabotage, physical attacks, cyber attacks, system failures, data breaches or other disruptions of Entergy’s and its subsidiaries’ or their suppliers’ physical infrastructure or technology systems may adversely affect Entergy’s business and results of operations.
• Entergy and the Registrant Subsidiaries are subject to risks associated with their ability to obtain adequate insurance at acceptable costs.
• Significant increases in commodity prices, other materials and supplies, and operation and maintenance expenses may adversely affect Entergy’s results of operations, financial condition, and liquidity.
• System Energy owns and, through an affiliate, operates a single nuclear generating facility, and it is dependent on sales to affiliated companies for all of its revenues. Certain contractual arrangements relating to System Energy, such affiliated companies, and these revenues are the subject of ongoing and potential future litigation and regulatory proceedings.
• As a holding company, Entergy Corporation depends on cash distributions from its subsidiaries to meet its debt service and other financial obligations and to pay dividends on its common stock, and has provided, and may continue to provide, capital contributions or debt financing to its subsidiaries, which would reduce the funds available to meet its other financial obligations.
• The hazardous activities associated with power generation and delivery could adversely impact our results of operations and financial condition.

ENTERGY’S BUSINESS

Entergy is an integrated energy company engaged primarily in electric power production and energy delivery to retail customers. Entergy owns and operates power plants with approximately 25,000 MW of electric generating capacity. Entergy delivers electricity to approximately 3.1 million Utility customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy had annual revenues of $12.9 billion in 2025 and had approximately 12,000 employees as of December 31, 2025.

Entergy operates primarily through a single reportable segment, Utility. The Utility segment includes the generation, transmission, distribution, and sale of electric power in portions of Arkansas, Mississippi, Texas, and Louisiana, including the City of New Orleans. Louisiana operations, including New Orleans, operated small natural gas distribution businesses through June 30, 2025. See “Dispositions - Natural Gas Distribution Businesses” in Note 14 to the financial statements for discussion of the sale of the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses on July 1, 2025. See Note 13 to the financial statements for discussion of and financial information regarding Entergy’s reportable segment.

Strategy

Entergy’s strategy is to operate and grow its utility business designed to understand and meet customer needs, creating value for all of its key stakeholders, including customers, communities, employees, and owners. Entergy is focused on keeping costs for customers as low as possible while providing reliable energy that communities count on. Entergy invests significant capital to support customer growth as well as reliability and resilience. Entergy is also investing in clean energy to meet customer demands. Entergy manages risks by ensuring its Utility investments are customer-driven, supported by robust analysis, inclusive of broad stakeholder outreach, and executed with disciplined project management.

Utility

The Utility segment includes five retail electric utility subsidiaries: Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas. These companies generate, transmit, distribute, and sell electric power to retail and wholesale customers in Arkansas, Louisiana, Mississippi, and Texas. Prior to the sale of the Entergy Louisiana and Entergy New Orleans natural gas distribution businesses on July 1, 2025, Entergy Louisiana and Entergy New Orleans also provided natural gas utility services to customers in and around Baton Rouge, Louisiana, and New Orleans, Louisiana, respectively. See “Dispositions - Natural Gas Distribution Businesses” in 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. Also included in the Utility is System Energy, a wholly-owned subsidiary of Entergy Corporation that owns or leases 90 percent of Grand Gulf. System Energy sells its power and capacity from Grand Gulf at wholesale to Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans. The five retail utility subsidiaries are each regulated by the FERC and by state utility commissions, or, in the case of Entergy New Orleans, the City Council. System Energy is regulated by the FERC because all of its transactions are at wholesale. The Utility has a diverse power generation portfolio including nuclear, hydroelectric, solar, and highly efficient natural gas.

Customers

As of December 31, 2025, the Utility operating companies provided retail electric service to customers in Arkansas, Louisiana, Mississippi, and Texas, as follows:

(In Thousands)

Prior to the sale of the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses on July 1, 2025, Entergy New Orleans and Entergy Louisiana provided both retail electric and gas service to customers. See “Dispositions - Natural Gas Distribution Businesses” in Note 14 to the financial statements for discussion of the sale of the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses.

Electric and Natural Gas Energy Sales

Electric Energy Sales

The total electric energy sales of the Utility operating companies are subject to seasonal fluctuations, with the peak sales period normally occurring during the third quarter of each year. On July 22, 2025, Entergy reached a 2025 peak demand of 23,624 MWh, compared to the 2024 peak of 22,697 MWh recorded on August 6, 2024. Selected electric energy sales data for 2025 is shown in the table below:

(a) Includes the effect of intercompany eliminations.

The following table illustrates the Utility operating companies’ 2025 combined electric sales volume as a percentage of total electric sales volume, and 2025 combined electric revenues as a percentage of total 2025 electric revenue, each by customer class.

(a) Major industrial customers are primarily in the petroleum refining and chemical industries.

Natural Gas Energy Sales

Prior to the sale of the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses on July 1, 2025, Entergy New Orleans and Entergy Louisiana provided both electric power and natural gas to retail customers. See “Dispositions - Natural Gas Distribution Businesses” in Note 14 to the financial statements for discussion of the sale of the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses.

Retail Rate Regulation

General (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, System Energy)

Each Utility operating company regularly participates in retail rate proceedings. The status of material retail rate proceedings is described in Note 2 to the financial statements. Certain aspects of the Utility operating companies and System Energy’s retail rate mechanisms are discussed below.

251

Entergy Corporation, Utility operating companies, and System Energy

(a) Based on 2026 test year.

(b) Based on $2.2 billion in accumulated deferred income taxes at a 0% cost rate included in the weighted-average cost of capital calculation.

(c) Based on December 31, 2024 test year and excludes approximately $200 million of transmission plant investment included in the transmission recovery mechanism and approximately $400 million of distribution plant investment included in the distribution recovery mechanism, as well as approximately $400 million of transmission and distribution plant investment included in the resilience plan cost recovery rider.

(d) Based on 2025 forward test year.

(e) Based on December 31, 2024 test year and known and measurables through December 31, 2025.

(f) In October 2023 the City Council approved a three-year extension of Entergy New Orleans’s formula rate plan, modified to reflect a 55% equity ratio for rate setting purposes.

(g) Based on December 31, 2021 test year and excludes $0.9 billion in cost recovery riders.

(h) Based on calculation as of December 31, 2025 for Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans. Effective July 2022, Entergy Mississippi’s bills from System Energy reflect a rate base reduction for the advance collection of sale-leaseback rental costs, resulting in a calculation of $1.78 billion as of December 31, 2025. See Note 2 to the financial statements for discussion of the System Energy settlement agreements.

Entergy Arkansas

Formula Rate Plan

Between base rate cases, Entergy Arkansas is able to adjust base rates annually, subject to certain caps, through formula rate plans that utilize a forward test year. Entergy Arkansas is subject to a maximum rate change of 4% of the filing year total retail revenue. In addition, Entergy Arkansas is subject to a true-up of projection to actuals netted with future projection. In response to Entergy Arkansas’s application for a general change in rates in 2015, the APSC approved the formula rate plan tariff proposed by Entergy Arkansas including its use of a projected year test period and an initial five-year term. The initial five-year term expired in 2021. As granted by Arkansas law, Entergy Arkansas obtained APSC approval of the extension of the formula rate plan tariff for an additional five-year term, through 2026. As part of the settlement of the 2023 formula rate plan proceeding, Entergy Arkansas agreed to file its next base rate case no later than February 27, 2026. As part of Entergy Arkansas’s base rate case in 2026, Entergy Arkansas will include a request for continued regulation under a formula rate review mechanism.

Fuel and Purchased Power Cost Recovery

Entergy Arkansas’s rate schedules include an energy cost recovery rider to recover fuel and purchased power costs in monthly bills. The rider utilizes prior calendar year energy costs and projected energy sales for the twelve-month period commencing on April 1 of each year to develop an energy cost rate, which is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery, including carrying charges, of the energy cost for the prior calendar year. The energy cost recovery rider tariff also allows an interim rate request depending upon the level of over- or under-recovery of fuel and purchased energy costs. In December 2007 the APSC issued an order stating that Entergy Arkansas’s energy cost recovery rider will remain in effect, and any future termination of the rider would be subject to eighteen months advance notice by the APSC, which would occur following notice and hearing.

Production Cost Allocation Rider

Entergy Arkansas has in place an APSC-approved production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of System Agreement proceedings.

Generating Arkansas Jobs Act of 2025

In March 2025 the State of Arkansas passed the Generating Arkansas Jobs Act of 2025, now Act 373 (Act 373), that authorizes the recovery of financing costs during construction of generation and transmission investments through a rider separate from the formula rate plan. Act 373 also permits cost recovery of those investments, when completed and in service, either through the next general rate case proceeding or under the formula rate plan. Act 373 streamlines and simplifies the regulatory approval process and provides increased timeliness and certainty of cost recovery.

In July 2025, Entergy Arkansas submitted a tariff filing with the APSC requesting approval of a strategic investment recovery rider, consistent with the provisions of Act 373. In October 2025 the APSC issued an order approving the proposed rider with several revisions, including elimination of an annual true-up adjustment, a change in cost allocation methodology, the removal of excess and deficient accumulated deferred income taxes to a separate rider, and the addition of reporting requirements. As directed by the order, in October 2025, Entergy Arkansas made a compliance filing. In November 2025, the APSC general staff recommended additional updates to the compliance filing, including limiting the accumulated deferred income tax adjustment to excess accumulated deferred income taxes. Also, in November 2025, Entergy Arkansas filed a second compliance filing, which was approved by the APSC.

Other

In June 2022 the APSC approved Entergy Arkansas’s compliance tariff filing for a proposed green tariff designed to help participating customers meet their renewable and sustainability goals and to enhance economic development efforts in Arkansas. The APSC has approved offerings of 280 MW of solar capacity to be made available under this tariff.

In June 2023 the APSC approved Entergy Arkansas’s Go ZERO tariff, which provides participating industrial and commercial customers the opportunity to choose from a number of clean energy options to help them achieve their sustainability goals. The APSC has approved offerings of 240 MW to be made available under this tariff.

Entergy Louisiana

Formula Rate Plan

Entergy Louisiana historically sets electric base rates annually through a formula rate plan using a historic test year. The form of the formula rate plan, on a combined basis, was approved in connection with the business combination of Entergy Louisiana and Entergy Gulf States Louisiana and largely followed the formula rate plans that were approved by the LPSC in connection with the full electric base rate cases filed by those companies in February 2013. In 2021 the LPSC approved a settlement extending the formula rate plan for test years 2020, 2021, and 2022. Certain modifications were made in that extension, including a decrease to the allowed return on equity, narrowing of the earnings “dead band” around the mid-point allowed return on equity, elimination of sharing above and below the earnings “dead band,” and the addition of a distribution cost recovery mechanism. The formula rate plan continues to include exceptions from the rate cap and sharing requirements for certain large capital investment projects, including acquisition or construction of generating facilities and purchase power agreements approved by the LPSC, certain transmission investments, and certain distribution investments, among other items. In August 2024 the LPSC approved a settlement further extending the formula rate plan for test years 2023, 2024, and 2025. Certain modifications were made in that extension, including expansion of the tax adjustment mechanism (formerly the tax reform adjustment mechanism), a more streamlined and defined process for resolving formula rate plan test years, a narrowed “earnings” dead band, removal of certain legacy provisions that pre-dated the business combination, and the addition of a dedicated cost recovery mechanism for renewable resources.

Fuel and Purchased Power Cost Recovery

Entergy Louisiana’s rate schedules include a fuel adjustment clause designed to recover the cost of fuel and purchased power costs. The fuel adjustment clause contains a surcharge or credit for deferred fuel expense and related carrying charges arising from the monthly reconciliation of actual fuel costs incurred with fuel cost revenues billed to customers, including carrying charges. See Note 2 to the financial statements for a discussion of proceedings related to audits of Entergy Louisiana’s fuel adjustment clause filings.

To help stabilize electricity costs, Entergy Louisiana received approval from the LPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Louisiana historically hedged approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity was reviewed on an annual basis. In November 2018, Entergy Louisiana received approval from the LPSC to suspend these seasonal hedging programs and implement financial hedges with terms up to five years for a portion of its natural gas exposure. In May 2024, following the conclusion of its five-year hedging program, Entergy Louisiana filed an application with the LPSC for a permanent hedging program. The permanent gas hedging program would also utilize financial hedges for a portion of Entergy Louisiana’s non-industrial natural gas exposure. In February 2025, Entergy Louisiana filed a motion to suspend the procedural schedule to allow for the parties to discuss settlement. The motion was granted. The parties remain engaged in settlement discussions with a status conference scheduled in March 2026.

Storm Cost Recovery

See Note 2 to the financial statements for a discussion of Entergy Louisiana’s filings to recover storm-related costs.

In March 2025, Entergy Louisiana filed an application asking that the LPSC issue an order establishing a presumption, in future proceedings involving Entergy Louisiana’s petition for a financing order allowing securitization of storm costs, that the LPSC will enter a decision on the request for a financing order within 120 days from the date of the filing of the petition, while preserving the LPSC’s jurisdiction to complete its full prudence review. The filing was rejected on procedural grounds. In June 2025 the LPSC approved a directive providing, among other things, that any utility seeking securitization for storm costs in 2025 must file a proposed financing order with its application and that the LPSC staff must use best efforts to deliver the financing order to the LPSC for consideration at the next available Business and Executive meeting after the application is filed.

Other

In March 2016 the LPSC opened two dockets to examine, on a generic basis, issues that it identified in connection with its review of Cleco Corporation’s acquisition by third party investors. The first docket is captioned “In re: Investigation of double leveraging issues for all LPSC-jurisdictional utilities,” and the second is captioned “In re: Investigation of tax structure issues for all LPSC-jurisdictional utilities.” In April 2016 the LPSC clarified that the concerns giving rise to the two dockets arose as a result of its review of the structure of the Cleco-Macquarie transaction and that the specific intent of the directives is to seek more information regarding intra-corporate debt financing of a utility’s capital structure as well as the use of investment tax credits to mitigate the tax obligation at the parent level of a consolidated entity. No schedule has been set for either docket, and limited discovery has occurred.

In September 2019 the LPSC issued an order modifying its rule regarding net metering installations. Among other things, the rule provides for 2-channel billing for net metering with excess energy put to the grid being compensated at the utility’s avoided cost. However, the rule does provide that net meter installations in place as of December 31, 2019 will be subject to 1:1 net metering with excess energy put to the grid being compensated at the full retail rate for a period of 15 years (through December 31, 2034), after which those installations will be subject to 2-channel billing. The rule also eliminates the existing limit on the cumulative number of net meter installations.

In 2023, Entergy Louisiana made a filing to seek approval from the LPSC for an alternative to the requests for proposals (RFP) process that would enable the acquisition of up to 3 GW of solar resources on a faster timeline than the then-current RFP and certification processes could allow. The initial phase of the filing established the need for the acquisition of additional resources and the need for an alternative to the RFP process. The second phase of the filing contained the details of the proposal for the alternative competitive procurement process and the information necessary to support certification. In addition to the acquisition of up to 3 GW of solar resources, the filing also sought approval of a new renewable energy credits-based tariff, the Geaux ZERO rider. In June 2024 the LPSC issued an order approving the application. In August 2025 the LPSC issued an order accepting a settlement in a proceeding addressing Entergy Louisiana’s request for certification of generation and transmission resources in connection with extending service to a data center customer in north Louisiana. The settlement provides for Entergy Louisiana, within six months of the order accepting the settlement, to make a filing with the LPSC seeking to modify its expedited procurement process to include additional clean resource types (including onshore wind) and additional changes (including modifications to the breakeven parameters established in connection with the order approving the alternative competitive procurement process). The settlement does not purport to impose any obligation upon the LPSC to act on the required filing, and all parties reserve their rights with respect to such filing.

In May 2025, Entergy Louisiana filed an application seeking authorization to implement, over a five-year period, a suite of proposed demand response (DR) offerings and a new tariff (Schedule DRP) providing customer incentive levels to participate in such programs. The proposed programs consist of: (1) for residential customers, smart thermostat DR, battery energy storage DR, and an electric vehicle behavioral charging offering; (2) for agricultural customers, an Agricultural Irrigation Load Control program; and (3) for commercial and industrial customers, an aggregated capacity DR offering. Entergy Louisiana anticipates registering certain of the DR resources with MISO and further estimates that the total costs of implementing the programs over the full, five-year period from 2026 through 2030 will be up to approximately $81 million. In January 2026, Entergy Louisiana filed an unopposed motion to suspend the procedural schedule in this proceeding to allow the parties to engage in settlement negotiations, and the ALJ granted the motion and suspended the procedural schedule. In February 2026, Entergy Louisiana and the LPSC staff filed a joint motion seeking approval of an uncontested stipulated settlement agreement supporting approval of the propose DR programs subject to various terms. The proposed stipulated settlement agreement will be considered by the ALJ in first quarter 2026.

Entergy Mississippi

Formula Rate Plan

Since the conclusion in 2015 of Entergy Mississippi’s most recent base rate case, Entergy Mississippi has set electric base rates annually through a formula rate plan. Between base rate cases, Entergy Mississippi is able to adjust base rates annually, subject to certain caps, through formula rate plans that utilize forward-looking features. In addition, Entergy Mississippi is subject to an annual “look-back” evaluation. Entergy Mississippi is allowed a maximum rate increase of 4% of each test year’s retail revenue. Any increase above 4% requires a base rate case. If Entergy Mississippi’s formula rate plan were terminated without replacement, it would revert to the more traditional rate case environment or seek approval of a new formula rate plan.

In August 2012 the MPSC opened inquiries to review whether the then-current formulaic methodology used to calculate the return on common equity in both Entergy Mississippi’s formula rate plan and Mississippi Power Company’s annual formula rate plan was still appropriate or could be improved to better serve the public interest. The intent of this inquiry and review was for informational purposes only; the evaluation of any recommendations for changes to the existing methodology would take place in a general rate case or in the existing formula rate plan proceeding. In March 2013 the Mississippi Public Utilities Staff filed its consultant’s report which noted the return on common equity estimation methods used by Entergy Mississippi and Mississippi Power Company are commonly used throughout the electric utility industry. The report suggested ways in which the methods used by Entergy Mississippi and Mississippi Power Company might be improved, but did not recommend specific changes in the return on common equity formulas or calculations at that time. In June 2014 the MPSC expanded the scope of the August 2012 inquiry to study the merits of adopting a uniform formula rate plan that could be applied, where possible in whole or in part, to both Entergy Mississippi and Mississippi Power Company in order to achieve greater consistency in the plans. The MPSC directed the Mississippi Public Utilities Staff to investigate and review Entergy Mississippi’s formula rate plan rider schedule and Mississippi Power Company’s Performance Evaluation Plan by considering the merits and deficiencies and possibilities for improvement of each and then to propose a uniform formula rate plan that, where possible, could be applicable to both companies. No procedural schedule has been set. In October 2014 the Mississippi Public Utilities Staff conducted a public technical conference to discuss performance benchmarking and its potential application to the electric utilities’ formula rate plans. The docket remains open.

In December 2019 the MPSC approved Entergy Mississippi’s proposed revisions to its formula rate plan to provide for a mechanism in the formula rate plan, the interim capacity rate adjustment mechanism, to recover the non-fuel related costs of additional owned capacity acquired by Entergy Mississippi as well as to allow similar cost recovery treatment for other capacity acquisitions that are approved by the MPSC. The MPSC must approve recovery through the interim capacity rate adjustment for each new resource. In addition, the MPSC approved revisions to the formula rate plan which allows Entergy Mississippi to begin billing rate adjustments effective April 1 of the filing year on a temporary basis subject to refund or credit to customers, subject to final MPSC order. The MPSC also authorized Entergy Mississippi to remove vegetation management costs from the formula rate plan and recover these costs through the establishment of a vegetation management rider, which was superseded in June 2024 with the approval of the storm damage mitigation and restoration rider. See Note 2 to the financial statements for a discussion of proceedings regarding recovery of Entergy Mississippi’s storm-related costs.

In November 2020 the MPSC approved Entergy Mississippi’s revisions to its formula rate plan providing for the realignment of energy efficiency costs to its formula rate plan, the deferral of energy efficiency expenditures into a regulatory asset, and the elimination of its energy efficiency cost recovery rider effective with the January 2022 billing cycle.

In June 2023 the MPSC approved Entergy Mississippi’s revisions to its formula rate plan to realign the recovery of certain long-term service agreement and conductor handling costs to the annual power management and grid modernization riders effective January 2023.

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 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.

Fuel and Purchased Power Cost Recovery

Entergy Mississippi’s rate schedules include energy cost recovery riders to recover fuel and purchased power costs. The energy cost rate for each calendar year is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery of the energy costs as of the 12-month period ended September 30. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC. The energy cost recovery riders allow interim rate adjustments depending on the level of over- or under-recovery of fuel and purchased energy costs.

To help stabilize electricity costs, Entergy Mississippi received approval from the MPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Mississippi hedges approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity is reviewed on an annual basis.

Storm Cost Recovery

See Note 2 to the financial statements for a discussion of proceedings regarding recovery of Entergy Mississippi’s storm-related costs.

Other

In October 2022 the MPSC adopted the Distributed Generation Rule. The Distributed Generation Rule maintains the 3% net metering participation cap. The Distributed Generation Rule grandfathers a 2.5 cents per kWh distributed generation benefits adder for 25 years and expands eligibility for the 2 cents per kWh low-income benefits adder to households up to 225% of the federal poverty level and grandfathers that adder for 25 years. The Distributed Generation Rule also directs utilities to make rate filings implementing up-front incentives for distributed generating systems and demand response battery systems, and to establish a public K-12 solar for schools program. In August 2023 the MPSC approved Entergy Mississippi’s proposed solar for schools rate schedule under the Distributed Generation Rule. In June 2025 the MPSC initiated a rulemaking proceeding in which it sought to amend the Distributed Generation Rule, in part, to delete the solar for schools program. The MPSC subsequently issued an order staying the program pending the outcome of the rulemaking docket. Entergy Mississippi and twelve other intervenors submitted public comments in the docket. There has been no further action to date.

In December 2022 the MPSC approved Entergy Mississippi’s RenewABLE Community Option (Schedule RCO), an offering for qualifying non-residential customers to subscribe to renewable resource capacity to satisfy their environmental, sustainability, and governance goals. Registration for the Schedule RCO launched in May 2023.

Entergy New Orleans

Formula Rate Plan

As part of its determination of rates in the base rate case filed by Entergy New Orleans in 2018, in November 2019, the City Council issued a resolution resolving the rate case, with rates to become effective retroactive to August 2019. The resolution allows Entergy New Orleans to implement a three-year formula rate plan, beginning with the 2019 test year as adjusted for forward-looking known and measurable changes, with the filing for the first test year to be made in 2020. In October 2020 the City Council approved an agreement in principle filed by Entergy New Orleans that results in Entergy New Orleans forgoing its 2020 formula rate plan filing and shifting the three-year formula rate plan to filings in 2021, 2022, and 2023. In September 2023, Entergy New Orleans filed a motion seeking City Council approval of a three-year extension of Entergy New Orleans’s electric and gas formula rate plans, for filings in 2024, 2025, and 2026. In October 2023 the City Council granted Entergy New Orleans’s request for an extension, subject to minor modifications.

Fuel and Purchased Power Cost Recovery

Entergy New Orleans’s electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges.

Storm Cost Recovery

In January 2025, Entergy New Orleans filed an application with the City Council requesting the establishment of a standard procedural timeline for consideration of future applications by Entergy New Orleans that seek securitization financing of storm restoration costs, including replenishment of storm recovery reserves, in furtherance of the goals of promoting efficiency of restoration and helping mitigate customer exposure to carrying costs following expenditures for future storm restoration. To support this objective, Entergy New Orleans proposed a procedural schedule that would allow for the issuance of a financing order no later than four months or 120 days from the date that Entergy New Orleans files any future applications seeking securitization financing of storm restoration costs, including storm recovery reserves, with the City Council. Entergy New Orleans also requested that the City Council approve an amendment to the storm recovery reserve escrow agreement to increase flexibility in the timing of certain disbursements of escrow funds to prepare for anticipated storms.

See Note 2 to the financial statements for a discussion of Entergy New Orleans’s filings to recover storm-related costs.

Other

In May 2021 the City Council established the Renewable and Clean Portfolio Standard. The four components implemented were: (1) a mandatory requirement that Entergy New Orleans achieve 100% net zero carbon emissions by 2040; (2) reliance on renewable energy credits purchased without the associated energy for compliance with the standard being phased out over the ten-year period from 2040 to 2050; (3) no carbon-emitting resources in the portfolio of resources Entergy New Orleans uses to serve New Orleans by 2050; and (4) a mechanism to limit costs in any one plan year to no more than one percent of plan year total utility retail sales revenues. In addition, there is an alternative compliance payment value per MWh, which is established with each annual compliance plan submittal. Entergy New Orleans will pay this if it is unable to comply with the Renewable and Clean Portfolio Standard. Such compliance payments are to be paid into a clean energy fund established by the City Council.

Entergy Texas

Base Rates

The base rates of Entergy Texas are established largely in traditional base rate case proceedings. Between base rate proceedings, Entergy Texas has available rate riders to recover the revenue requirements associated with certain incremental costs. Entergy Texas is required to file full base rate case proceedings every four years and within eighteen months of utilizing its generation cost recovery rider for investments above $200 million.

Fuel and Purchased Power Cost Recovery

Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, that are not included in base rates. Historically, semi-annual revisions of the fixed fuel factor have been made in March and September based on the market price of natural gas and changes in fuel mix. The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT. In the course of this reconciliation, the PUCT determines whether eligible fuel and fuel-related expenses and revenues are necessary and reasonable and makes a prudence finding for each of the fuel-related contracts entered into during the reconciliation period. In 2023 the Texas legislature modified the Texas Utilities Code with regard to how material over- and under-recovered fuel balances are to be addressed and directed that fuel reconciliations must be filed at least once every two years. In July 2025 the PUCT initiated a rulemaking to effectuate the new legislation. In December 2025 the PUCT adopted amendments to its fuel rules that maintain a periodic revision to utility fuel factors coupled with accelerated processing of surcharges and refunds to address material over- and under-recovered amounts.

At the PUCT’s April 2013 open meeting, the PUCT Commissioners discussed their view that a purchased power capacity rider was good public policy. The PUCT issued an order in May 2013 adopting the rule allowing for a purchased power capacity rider, subject to an offsetting adjustment for load growth. The rule, as adopted, also includes a process for obtaining pre-approval by the PUCT of purchased power agreements to be recovered through a purchased power capacity rider. No Texas utility, including Entergy Texas, has exercised the option to recover capacity costs under the rider mechanism, but Entergy Texas will continue to evaluate the benefits of utilizing the rider to recover future capacity costs. In 2023 the Texas legislature modified the Texas Utilities Code to permit a utility to seek pre-approval from the PUCT for a purchased power agreement of three years or more if such approval is a precondition to the effectiveness of such agreements, regardless of whether the utility intends to recover costs associated with the purchased power agreement through a purchased power capacity rider. In June 2025 the Texas legislature modified the Texas Utilities Code to establish 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.

Transmission, Distribution, and Generation Cost Recovery

As discussed above, Entergy Texas has available rate riders to recover the revenue requirements associated with certain incremental costs. These riders include a transmission cost recovery factor rider mechanism for the recovery of transmission-related capital investments, a distribution cost recovery factor rider mechanism for the recovery of distribution-related capital investment, and a generation cost recovery rider mechanism for the recovery of generation-related capital investments.

In June 2009 a law was enacted in Texas containing provisions that allow Entergy Texas to take advantage of a cost recovery mechanism that permits annual filings for the recovery of reasonable and necessary expenditures for transmission infrastructure improvement and changes in wholesale transmission charges. This mechanism was previously available to other non-ERCOT Texas utility companies, but not to Entergy Texas.

In September 2011 the PUCT adopted a proposed rule implementing a distribution cost recovery factor to recover capital and capital-related costs related to distribution infrastructure. The distribution cost recovery factor permitted utilities once per year to implement an increase or decrease in rates above or below amounts reflected in base rates to reflect distribution-related depreciation expense, federal income tax and other taxes, and return on investment. In 2023, the Texas Legislature modified the Texas Utilities Code to permit utilities to update their distribution cost recovery factors up to twice per year and to require the PUCT to issue an order on such update applications within 60 days, with a 15-day extension permitted for good cause.

In September 2019 the PUCT initiated a rulemaking to promulgate a generation cost recovery rider rule, implementing legislation passed in the 2019 Texas legislative session intended to allow electric utilities to recover generation investments between base rate proceedings. The PUCT approved the final rule in July 2020.

Other

In January 2022, Entergy Texas filed an application requesting approval to implement two voluntary renewable option tariffs, Rider Small Volume Renewable Option (Rider SVRO) and Rider Large Volume Renewable Option (Rider LVRO). Both tariffs are voluntary offerings that give customers the ability to match some or all of their monthly electricity usage with renewable energy credits that are purchased by Entergy Texas and retired on the customer’s behalf. Voluntary participation in either Rider SVRO or Rider LVRO and the charges assessed under the respective tariff would be in addition to the charges paid by customers under their otherwise applicable rate schedules and riders. In April 2022, Entergy Texas filed on behalf of the parties an unopposed settlement agreement supporting approval of Entergy Texas’s proposed voluntary renewable option tariffs. As part of the settlement agreement, Entergy Texas agreed to revise the cost allocation between the rate tiers of Rider SVRO and committed to collaborating with and considering the input of customers to develop an asset-backed green tariff program. The PUCT approved the settlement agreement in August 2022.

As part of its rate case application filed with the PUCT in July 2022, Entergy Texas requested approval of Schedule Green Future Option (Schedule GFO), an asset-backed green tariff that would allow Entergy Texas’s customers to voluntarily subscribe to a portion of the underlying solar facility’s capacity in exchange for energy credits. In August 2023 the PUCT approved an unopposed settlement in the proceeding that included approval of Schedule GFO.

Electric Industry Restructuring

In June 2009 a law was enacted in Texas that required Entergy Texas to cease all activities relating to Entergy Texas’s transition to competition. The law allows Entergy Texas to remain a part of the SERC Reliability Corporation (SERC) Region, although it does not prevent Entergy Texas from joining another power region. The law provides that proceedings to certify a power region that Entergy Texas belongs to as a qualified power region can be initiated by the PUCT, or on motion by another party, when the conditions supporting such a proceeding exist. Under the law, the PUCT may not approve a transition to competition plan for Entergy Texas until the expiration of four years from the PUCT’s certification of a qualified power region for Entergy Texas.

The law further amended already existing law that had required Entergy Texas to propose for PUCT approval a tariff to allow eligible customers the ability to contract for competitive generation. The amending language in the law provides, among other things, that: (1) the tariff shall not be implemented in a manner that harms the sustainability or competitiveness of manufacturers who choose not to participate in the tariff; (2) Entergy Texas shall “purchase competitive generation service, selected by the customer, and provide the generation at retail to the customer;” and (3) Entergy Texas shall provide and price transmission service and ancillary services under that tariff at a rate that is unbundled from its cost of service. The law directs that the PUCT may not issue an order on the tariff that is contrary to an applicable decision, rule, or policy statement of a federal regulatory agency having jurisdiction. The PUCT determined that unrecovered costs that may be recovered through the rider consist only of those costs necessary to implement and administer the competitive generation program and do not include lost revenues or embedded generation costs. The amount of customer load that may be included in the competitive generation service program is limited to 115 MW.

System Energy

Cost of Service

The rates of System Energy are established by the FERC, and the costs allowed to be charged pursuant to these rates are, in turn, passed through to the participating Utility operating companies through the Unit Power Sales Agreement, which has monthly billings that reflect the current operating costs of, and investment in, Grand Gulf. Retail regulators and other parties may seek to initiate proceedings at FERC to investigate the prudence of costs included in the rates charged under the Unit Power Sales Agreement and examine, among other things, the reasonableness or prudence of the operation and maintenance practices, level of expenditures, allowed rates of return and rate base, and previously incurred capital expenditures, to the extent that claims concerning such issues have not been released by a party to one of the System Energy settlement agreements. Beginning in 2021, System Energy implemented annual billing protocols to provide retail regulators with information regarding rates billed under the Unit Power Sales Agreement. See Note 2 to the financial statements for discussion of the System Energy settlement agreements.

Franchises

Entergy Arkansas holds exclusive franchises to provide electric service in approximately 308 incorporated cities and towns in Arkansas. These franchises generally are unlimited in duration and continue unless the municipalities purchase the utility property. In Arkansas, franchises are considered to be contracts and, therefore, are governed pursuant to the terms of the franchise agreement and applicable statutes.

Entergy Louisiana holds non-exclusive franchises to provide electric service in approximately 175 incorporated municipalities and in the unincorporated areas of approximately 59 parishes of Louisiana. Municipal franchise agreement terms range from 25 to 60 years while parish franchise terms range from 15 to 99 years.

Entergy Mississippi has received from the MPSC certificates of public convenience and necessity to provide electric service to areas within 45 counties, including a number of municipalities, in western Mississippi. Under Mississippi statutory law, such certificates are exclusive. Entergy Mississippi may continue to serve in such municipalities upon payment of a statutory franchise fee, regardless of whether an original municipal franchise is still in existence.

Entergy New Orleans provides electric service in the City of New Orleans pursuant to indeterminate permits set forth in city ordinances. These ordinances contain a continuing option for the City of New Orleans to purchase Entergy New Orleans’s electric utility properties.

Entergy Texas holds a certificate of convenience and necessity from the PUCT to provide electric service to areas within approximately 27 counties in eastern Texas and holds non-exclusive franchises to provide electric service in approximately 70 incorporated municipalities. Entergy Texas typically obtains 25-year franchise agreements as existing agreements expire. Entergy Texas’s electric franchises expire over the period 2026-2058.

The business of System Energy is limited to wholesale power sales. It has no distribution franchises.

Property and Other Generation Resources

Owned Generating Stations

The total capability of the generating stations owned and leased by the Utility operating companies and System Energy as of December 31, 2025 is indicated below:

(a) “Owned and Leased Capability” is the dependable summer load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize.

(b) Represents Simple Cycle Combustion Turbine units and Combined Cycle Gas Turbine units.

(c) The percentage of nuclear and renewable energy includes energy procured or produced for the benefit of certain customers through special tariffs, contracts, or renewable program subscriptions, and those customers retain the exclusive claims to all associated environmental attributes, renewable energy credits, and other relevant clean energy certifications.

Summer peak load for the Utility has averaged 22,168 MW over the previous decade.

The Utility operating companies’ load and capacity projections are reviewed periodically to assess the need and timing for additional generating capacity and interconnections. These reviews consider existing and projected demand, the availability and price of power, the location of new load, the economy, Entergy’s clean energy and other public policy goals, environmental regulations, and the age and condition of Entergy’s existing infrastructure.

The Utility operating companies’ long-term resource strategy (Portfolio Transformation Strategy) calls for the bulk of capacity needs to be met through long-term resources, whether owned or contracted. Over the past decade, the Portfolio Transformation Strategy has resulted in the addition of about 9,430 MW of new long-term resources and the deactivation of about 4,004 MW of legacy generation. As MISO market participants, the Utility operating companies also participate in MISO’s Day Ahead and Real Time Energy and Ancillary Services markets to economically dispatch generation and purchase energy to serve customers reliably and at the lowest reasonable cost.

Other Generation Resources

RFP Procurements

The Utility operating companies from time-to-time issue requests for proposals (RFP) to procure supply-side resources from sources other than the spot market to meet the unique regional needs of the Utility operating companies. The RFPs issued by the Utility operating companies have sought resources needed to meet near-term MISO reliability requirements as well as long-term requirements through a broad range of wholesale power products, including long-term contractual products and asset acquisitions. The RFP process has resulted in selections or acquisitions, including, among other things:

• In June 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Walnut Bend Solar facility, located in Lee County, Arkansas. In July 2021 the APSC issued an order approving the acquisition of the Walnut Bend Solar facility. In February 2024, Entergy Arkansas acquired the facility. The Walnut Bend Solar facility commenced commercial operation in September 2024;
• In September 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 180 MW to-be-constructed solar photovoltaic energy facility, West Memphis Solar facility, located in Crittenden County, Arkansas. In October 2021 the APSC issued an order approving the acquisition of the West Memphis Solar facility. In August 2024, Entergy Arkansas acquired the facility. The West Memphis Solar facility commenced commercial operation in December 2024;
• In December 2020, Entergy Texas selected the 1,158 MW self-build alternative, Orange County Advanced Power Station, out of the 2020 Entergy Texas combined cycle, gas turbine RFP. Regulatory approval was received in November 2022 and construction has commenced. The facility is expected to be in service by mid-2026;
• In August 2022, Entergy Arkansas signed an agreement for the purchase of an approximately 250 MW to-be-constructed solar photovoltaic energy facility, Driver Solar facility, located near Osceola, Arkansas. Also in August 2022, Entergy Arkansas received regulatory approval from the APSC for acquisition of the Driver Solar facility. In August 2024, Entergy Arkansas acquired the facility. The Driver Solar facility commenced commercial operation in December 2024;
• Entergy Louisiana began construction on the 49 MW Sterlington solar project in December 2024, located in Sterlington, Louisiana. The facility achieved commercial operation in January 2026;
• In May 2023, Entergy Mississippi selected the 80 MW Delta Solar facility, to be located in Bolivar County, Mississippi, out of the 2022 Entergy Mississippi fall renewable RFP. Construction is in progress, and the facility is expected to achieve commercial operation by the end of 2027;
• In May 2023, Entergy Mississippi selected the 190 MW Penton Solar facility, to be located in DeSoto County, Mississippi, out of the 2022 Entergy Mississippi fall renewable RFP. Construction is in progress, and the facility is expected to achieve commercial operation by early 2028;
• In July 2025, Entergy Louisiana filed an application with the LPSC seeking regulatory certification of Bogalusa West Solar, a 200 MW single axis tracking solar photovoltaic power facility to be located in Washington Parish, Louisiana. The certification filing was accepted by the LPSC in October 2025 and approved in November 2025. The facility is expected to achieve commercial operation in September 2028;
• In December 2025, Entergy Louisiana filed an application with the LPSC seeking regulatory certification of the Segno Solar and Votaw Solar facilities;
• In February 2026, Entergy Louisiana filed an application with the LPSC for approval and certification to construct the Cypress Harvest Solar facility, a 200 MW solar facility to be located in Iberville Parish; and
• In 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.

The RFP process has also resulted in the selection, or confirmation of the economic merits of, long-term purchased power agreements (PPAs), including, among others:

• River Bend’s 30% life-of-unit PPA between Entergy Louisiana and Entergy New Orleans for 100 MW related to Entergy Louisiana’s unregulated portion of the River Bend nuclear station, which portion was formerly owned by Cajun;
• Entergy Arkansas’s wholesale base load capacity life-of-unit PPAs executed in 2003 totaling approximately 220 MW between Entergy Arkansas and Entergy Louisiana (110 MW) and between Entergy Arkansas and

Entergy New Orleans (110 MW) related to the sale of a portion of Entergy Arkansas’s coal and nuclear base load resources (which had not been included in Entergy Arkansas’s retail rates);

• In September 2012, Entergy Gulf States Louisiana and Rain CII Carbon LLC executed a 20-year agreement for 28 MW, with the potential to purchase an additional 9 MW when available, from a petroleum coke calcining facility in Sulphur, Louisiana. The facility began commercial operation in May 2013. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, now holds the agreement with the facility;
• In March 2013, Entergy Gulf States Louisiana and Agrilectric Power Partners, LP executed a 20-year agreement for 8.5 MW from a refurbished rice hull-fueled electric generation facility located in Lake Charles, Louisiana. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, now holds the agreement with Agrilectric;
• Entergy Mississippi’s cost-based purchase, beginning in January 2013, of 90 MW from Entergy Arkansas’s share of Grand Gulf. Cost recovery for the 90 MW was approved by the MPSC in January 2013;
• In April 2015, Entergy Arkansas and Stuttgart Solar, LLC executed a 20-year agreement for 81 MW from a solar photovoltaic electric generation facility located near Stuttgart, Arkansas. The APSC approved the project and deliveries pursuant to that agreement commenced in June 2018;
• In November 2016, Entergy Louisiana and LS Power executed a 10-year agreement for 485 MW from the Carville Energy Center located in St. Gabriel, Louisiana. In November 2019, LS Power sold and transferred the Carville Energy Center and facility to Argo Infrastructure Partners, which included the power purchase agreement. The PPA delivery term began in June 2022;
• In November 2016, Entergy Louisiana and Occidental Chemical Corporation executed a 10-year agreement for 500 MW from the Taft Cogeneration facility located in Hahnville, Louisiana. The transaction received regulatory approval and began in June 2018;
• In June 2017, Entergy Arkansas and Chicot Solar, LLC executed a 20-year agreement for 100 MW from a to-be-constructed solar photovoltaic electric generating facility located in Chicot County, Arkansas. The transaction received regulatory approval and the PPA began in November 2020;
• In February 2018, Entergy Louisiana and LA3 West Baton Rouge, LLC (Capital Region Solar project) executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in West Baton Rouge Parish, Louisiana. The transaction received regulatory approval in February 2019 and the PPA began in October 2020;
• In July 2018, Entergy New Orleans and St. James Solar, LLC executed a 20-year agreement for 20 MW from a to-be-constructed solar photovoltaic electric generating facility located in St. James Parish, Louisiana. The transaction received regulatory approval in July 2019 and the PPA began in February 2023 after the facility reached commercial operation in March 2023;
• In August 2018, Entergy Louisiana and South Alexander Development I, LLC executed a 5-year agreement for 5 MW from a solar photovoltaic electric generating facility located in Livingston Parish, Louisiana. The PPA began in December 2020 and received regulatory approval in January 2021;
• In February 2019, Entergy New Orleans and Iris Solar, LLC executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in Washington Parish, Louisiana. The transaction received regulatory approval in July 2019 and achieved commercial operation in November 2022;
• In August 2020, Entergy Texas and Umbriel Solar, LLC executed a 20-year agreement for 150 MW from a to-be-constructed solar photovoltaic electric generating facility located in Polk County, Texas. The facility achieved commercial operation in November 2023;
• In June 2021, Entergy Louisiana and Sunlight Road Solar, LLC executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in Washington Parish, Louisiana. The facility achieved commercial operation in November 2024 and the PPA delivery term began in December 2024;
• In October 2022, Entergy Mississippi and Wildwood Solar, LLC executed a 20-year PPA for approximately 100 MW from a to-be-constructed solar photovoltaic energy facility located in Tallahatchie County, Mississippi. In August 2023 the MPSC approved the PPA, and the facility achieved commercial operation in December 2025;
• In October 2022, Entergy Mississippi and Greer Solar, LLC executed a 20-year PPA for approximately 170 MW from a to-be-constructed solar photovoltaic energy facility located in Washington County, Mississippi. In August 2023 the MPSC approved the PPA, and the facility is expected to reach commercial operation as early as December 2026;
• In October 2022, Entergy Arkansas and Flat Fork Solar, LLC executed a 20-year PPA for approximately 200 MW from a to-be-constructed solar photovoltaic energy facility located in St. Francis County, Arkansas. In September 2023 the APSC approved the PPA, and the facility achieved commercial operation in August 2025;
• In October 2022, Entergy Arkansas and Forgeview Solar, LLC executed a 15-year PPA for approximately 200 MW from a to-be-constructed solar photovoltaic energy facility located in Mississippi County, Arkansas. In September 2023 the APSC approved the PPA, and the facility achieved commercial operation in December 2025; and
• In October 2023, Entergy Louisiana and Mondu Solar, LLC executed a 20-year PPA for approximately 100 MW from a to-be-constructed solar photovoltaic energy facility located in Point Coupee Parish, Louisiana. In September 2024 the LPSC approved the PPA, and the facility is expected to reach commercial operation as early as June 2026.

In July 2021, Entergy Services, on behalf of Entergy Texas, issued RFPs for solar generation resources and in October 2022, for solar photovoltaic and wind resource. In July 2024, Entergy Texas filed an application with the PUCT seeking regulatory approval for the owned resources, the 141 MW Votaw Solar facility and the 170 MW Segno Solar facility. To support demand driven by robust industrial growth, in August 2025, Entergy Texas voluntarily withdrew its filing with the PUCT to narrow its focus to dispatchable generation.

In April 2022, Entergy Services, on behalf of Entergy Arkansas, issued an RFP for solar photovoltaic and wind resources. Entergy Arkansas selected a combination of PPA and build-own-transfer resources in February 2023. One PPA project was terminated after failure to reach agreement on terms. During negotiations, a selected build-own-transfer resource, Big Island Solar, was converted to a PPA. In December 2025, Entergy Arkansas and Big Island Solar 1, LLC executed a 20-year PPA for approximately 440 MW from a to-be-constructed solar photovoltaic energy facility located in Mississippi County, Arkansas. In January 2026, Entergy Arkansas filed an application with the APSC seeking regulatory approval for the resource and requested a decision by July 2026. Subject to receipt of required regulatory approval and other conditions, the Big Island Solar facility is expected to be in service as early as July 2028.

In April 2024, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for capacity and energy from existing generation resources. Entergy Louisiana selected a PPA resource in December 2024. During initial negotiations of the proposed PPA, the parties decided to amend the agreement for the Taft Cogeneration facility (discussed above) in lieu of entering into the proposed PPA. Entergy Louisiana expects to file an application with the LPSC in first quarter 2026 seeking regulatory approval to amend the agreement to extend the term by six years. Subject to receipt of required regulatory approval and other conditions, the extended delivery term of the amended agreement will commence immediately after the end of the existing term and will expire in May 2034.

In August 2024, Entergy Services, on behalf of Entergy Louisiana, issued the 3 GW Alternative Market-based Mechanism Process Solar RFP which solicits up to 3,000 MW of solar photovoltaic resources across four procurement windows. Entergy Louisiana selected a combination of PPA, build-own-transfer, and self-build alternative resources. In the first procurement window, as noted above, one of such resources (Bogalusa West) was certified by the LPSC in October 2025. Also in the first procurement window, Entergy Louisiana selected the Cypress Harvest Solar facility, a 200 MW solar facility to be located in Iberville Parish. In February 2026, Entergy Louisiana filed an application with the LPSC for approval and certification and requested LPSC approval by April 2026. Negotiations of definitive agreements for the remaining resources are in progress. The RFP is expected to continue through 2026 with additional selections expected throughout the process at the conclusion of each procurement window, as applicable.

In November 2024, Entergy Services, on behalf of Entergy Louisiana, issued a Combined Cycle Combustion Turbine capacity and energy resources RFP which solicits up to 2,000 MW of generation. Entergy Louisiana selected a combination of resources that included self-build alternatives in August 2025. In 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. Entergy Louisiana has asked that the LPSC consider the requests in the application at or before its December 2026 meeting.

In April 2025, Entergy Services, on behalf of Entergy Mississippi, issued a renewable RFP which solicited up to 250 MW of generation. Selections are under review.

In May 2025, Entergy Services, on behalf of Entergy Arkansas, issued a renewable and storage RFP which solicited up to 1,000 MW of generation. Entergy Arkansas selected a combination of PPA, build-own-transfer, and self-build alternative resources in November 2025. Negotiations of definitive agreements are in progress.

In May 2025, Entergy Services, on behalf of Entergy Arkansas, issued a combined cycle combustion turbine RFP which solicits up to 800 MW of generation. The RFP was updated in September 2025 to include provisions for carbon capture and storage capabilities. Selections are expected in March 2026.

In October 2025, Entergy Services, on behalf of Entergy Texas, issued notice of intent to issue a combined cycle combustion turbine RFP in January 2026. The RFP solicits 650 to 800 MW of generation from eligible developmental resources and/or up to 800 MW of generation from existing, gas-fired resources.

In November 2025, Entergy Services, on behalf of Entergy Louisiana, issued advanced notice to the LPSC of intent to issue an RFP soliciting up to 1,100 MW of battery energy storage resources. Draft documents were issued in December 2025.

Other Procurements From Third Parties

The Utility operating companies have also made resource acquisitions outside of the RFP process and have also entered various limited- and long-term contracts in recent years as a result of bilateral negotiations, including among others:

• In March 2016, Entergy Arkansas (Power Block 2), Entergy Louisiana (Power Blocks 3 and 4), and Entergy New Orleans (Power Block 1) completed their respective acquisitions of the 1,980 MW (summer rating), natural gas-fired, combined cycle gas turbine Union Power Station power blocks, each rated at 495 MW (summer rating). The facility is located near El Dorado, Arkansas and has been in operation since July 2003;
• In October 2019, Entergy Mississippi acquired the Choctaw Generating Station, an 810 MW combined cycle, natural gas-fired power plant. The facility is located in Choctaw County and has been in operation since July 2003;
• In November 2020, Entergy Louisiana acquired the Washington Parish Energy Center, a 361 MW natural gas-fired peaking power plant. The facility is located approximately 60 miles north of New Orleans on a site Entergy Louisiana purchased from Calpine in 2019. Calpine began construction on the plant in early 2019 and Entergy Louisiana purchased the plant upon completion in November 2020;
• In June 2021, Entergy Texas acquired the Hardin County Peaking Facility, an existing 147 MW simple cycle gas-fired peaking power plant in Kountze, Texas, previously owned by East Texas Electric Cooperative. The facility has been in operation since January 2010;
• In November 2021, Entergy Louisiana and Elizabeth Solar, LLC executed a 20-year PPA for approximately 125 MW from a to-be-constructed solar photovoltaic energy facility located in Allen Parish, Louisiana. In September 2022 the LPSC voted to approve this project and in September 2023, Entergy Louisiana reported

to the LPSC that it had entered into amended agreements related to the Elizabeth Solar facility. The facility achieved commercial operation in December 2024;

• In February 2024, Entergy Louisiana and Magnolia Power executed a 10-year Capacity Credit Purchase Agreement (CCPA) for 290 MW of MISO Zone 9 Zonal Resource Credits (ZRC) associated with the Magnolia Power Generating Station. In December 2024 the LPSC approved the CCPA, with the delivery term set to commence on the first day of the 2025-2026 MISO planning year; and
• In May 2024, Entergy Mississippi and Cooperative Energy executed a one-year ZRC Purchase and Sale Agreement for a minimum of 300 MW of MISO Zone 10 ZRCs during the 2025-2026 MISO planning year. This agreement was followed by a similar agreement between the parties in November 2024 for a minimum of 350 MW of MISO Zone 10, ZRCs to be transferred over the 2026-2027, 2027-2028, and 2028-2029 planning years.
• In February 2025, Entergy Texas and Tunica Windpower, LLC executed a 15-year ZRC Purchase and Sale Agreement for the purchase of all accredited MISO Zone 10 ZRCs associated with the Delta Wind Facility located in Tunica County, Mississippi;
• In November 2025, Entergy Louisiana and Cottonwood Energy Company, LP executed an asset purchase agreement for the 1,263 MW combined-cycle natural gas-fired Cottonwood Generating Station located in Deweyville, Texas, including related assets and interests. A certification filing was made with the LPSC in December 2025; and
• In November 2025, Entergy Texas and Bayou Galion Solar Project, LLC executed a six-year ZRC Purchase and Sale Agreement for the purchase of all accredited ZRCs from the Bayou Galion Solar Facility with an expected annual average of approximately 19 MW of MISO Zone 9 ZRCs.

Power Through Programs

In December 2020, Entergy Texas filed an application with the PUCT to amend its certificate of convenience and necessity to own and operate up to 75 MW of natural gas-fired distributed generation to be installed at commercial and industrial customer premises. Under this proposal, Entergy Texas would own and operate a fleet of generators ranging from 100 kW to 10 MW that would supply a portion of Entergy Texas’s long-term resource needs and enhance the resiliency of Entergy Texas’s electric grid. This fleet of generators would also be available to customers during outages to supply backup electric service as part of a program known as “Power Through.” In its 2021 session, the Texas legislature modified the Texas Utilities Code to exempt generators under 10 MW from the requirement to obtain a certificate of convenience and necessity. In addition, the PUCT announced an intent to conduct a broad rulemaking related to distributed generation and recommended that utilities with pending applications addressing distributed generation withdraw them. Accordingly, Entergy Texas withdrew its application for a certificate of convenience and necessity and associated tariff from the PUCT without prejudice to refiling. Entergy Texas continues to deploy certain customer-sited distributed generators under an existing PUCT-approved tariff. In August 2022, Entergy Texas filed an application for PUCT approval of voluntary Rate Schedule Utility Owned Distributed Generation through which it would charge host customers for back-up service from customer-sited Power Through generators. Based on the exemption enacted by the Texas legislature in 2021, Entergy Texas’s application was not required to, and did not, seek an amendment to its certificate of convenience and necessity in order to continue deploying Power Through generators. In October 2022 two intervenors filed requests for a hearing on Entergy Texas’s application. In October 2022 the PUCT staff filed a request that the proceeding be referred to the State Office of Administrative Hearings. In January 2023 the PUCT announced an intent to develop certain broadly applicable reliability metrics against which to measure distributed generation resources and directed Entergy Texas to withdraw its application. However, the PUCT did allow Entergy Texas to continue its pilot program for Power Through generators. Entergy Texas withdrew its application. In its 2023 session, the Texas legislature modified the Texas Utilities Code to confirm Entergy Texas’s ability to provide back-up generation service using customer-sited utility-owned distributed generation and directing the PUCT to approve rates for such service upon application by Entergy Texas. In February 2024, Entergy Texas resubmitted its application for PUCT approval of voluntary Rate Schedule Utility Owned Distributed Generation. Texas cities, the Office of Public Utility Counsel, Texas Industrial Energy Consumers, and Wal-Mart, Inc. have intervened as parties. In July 2024 the proceeding was referred to the State Office of Administrative Hearings and a procedural schedule was established. In November 2024, Entergy Texas filed an unopposed settlement agreement consistent with its as-filed request and a motion to admit evidence and remand the proceeding to the PUCT. Also in November 2024, the ALJ with the State Office of Administrative Hearings granted the motion and remanded the proceeding to the PUCT. In December 2024 the PUCT’s Office of Policy and Docket Management filed a proposed order for the PUCT’s consideration that would adopt the unopposed settlement, which was approved by the PUCT in February 2025.

In July 2021, Entergy Louisiana filed with the LPSC an application for authority to deploy natural gas-fired distributed generation. The application was supported by a number of letters of interest from Entergy Louisiana customers. In June 2022 the parties reached an uncontested settlement which, among other things, recommended approval of 120 MW of natural gas fired distributed generation and an additional 30 MW of solar and battery distributed generation, for a total distributed generation program of 150 MW. Pursuant to the terms of the settlement agreement, Entergy Louisiana may seek to expand the distributed generation program following the earlier of two years after issuance of an order approving the settlement or the installation of 60 MW of distributed generation pursuant to this program. The settlement was approved by the LPSC in November 2022.

In August 2021, Entergy Arkansas filed with the APSC an application seeking authority for a “Power Through” offering to deploy natural gas-fired distributed generation to provide backup generation for certain customers. The application was supported by a number of letters of interest from Entergy Arkansas customers. In May 2023 the APSC issued an order approving the Power Through offering with some modifications. In December 2023 the APSC approved a streamlined approval process for the individual Power Through generators. In July 2024, Entergy Arkansas filed tariff revisions to comply with the APSC’s order. In November 2024 the APSC approved Entergy Arkansas’s compliance tariff. In October 2025 the APSC approved Entergy Arkansas’s first Power Through project.

In October 2023, Entergy Mississippi proposed implementation of commercial scale, natural gas-fired resilient distributed generation, to be installed in front of the meter at commercial and industrial customer premises. The offering was approved by the MPSC in December 2023 along with an associated rate schedule, the Resiliency as a Service Rider Schedule. Entergy Mississippi can dispatch the units at times of peak demand, which can mitigate the typically higher energy and capacity costs borne by all customers during times of peak energy usage.

Provision of Service to Large-Scale Data Center Customers

Subject to pending regulatory approvals, certain Utility operating companies are planning to make significant infrastructure investments in new solar projects, natural gas power plants, and other transmission and generation assets to power new large-scale data centers. These infrastructure investments are being made primarily in connection with electric service agreements with a small number of new customers to provide power for new data centers being constructed to support artificial intelligence and other technology capabilities.

In March 2024, Entergy Mississippi executed a large customer supply and service agreement to serve two data centers 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. See the “Liquidity and Capital Resources – Uses of Capital – Additional Generation and Transmission Resources” section of Management’s Financial Discussion and Analysis for Entergy Mississippi for additional discussion of the agreements and the investments proposed in connection with service to these facilities.

In October 2024, Entergy Louisiana filed an application with the LPSC requesting approval of certain generation and transmission assets proposed in connection with service to a new large-scale data center being developed by a subsidiary of Meta Platforms, Inc. in north Louisiana. See the “Liquidity and Capital Resources – Uses of Capital – Additional Generation and Transmission Resources” section of Management’s Financial

Discussion and Analysis for Entergy Louisiana for additional discussion of this filing and the investments proposed in connection with new service to this data center facility.

In 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. See the “Liquidity and Capital Resources – Uses of Capital – Special Rate Contract and Arkansas Cypress Solar” section of Management’s Financial Discussion and Analysis for Entergy Arkansas for additional discussion of the filing and the investments proposed in connection with service to data center facility.

In addition, some of the Utility operating companies are engaged in discussions with prospective customers concerning potential service to other data center projects. Because of the significant demand and energy needs associated with these facilities, which generally involve large levels of maximum demand for sustained periods throughout the day and throughout the year, extending service to these facilities often requires investment in incremental generation and transmission facilities, with a resulting risk of stranded costs if expected demand does not materialize and this risk is not mitigated through appropriate commercial terms, which are subject to negotiations with the customer. Often it is therefore necessary and appropriate for the Utility operating companies, in the electric service agreements negotiated with these customers, to include terms that provide for the prospective customer to contribute significant funds, through contributions in aid of construction or through minimum bill revenues, toward the cost of these incremental investments and that include other terms and safeguards to balance reasonably the interests of existing customers with the interests of the prospective customer. Such safeguards take many forms but may include minimum payment obligations, lengthy contract durations, customer advances for construction, and credit and collateral requirements, among other terms. Extending service to large-scale data center customers also may carry significant potential benefits to the Utility operating companies’ existing customer base as well as significant economic development benefits for the states and communities in which the new data centers are sited. These benefits include the potential for substantial contributions to the Utility operating companies’ fixed costs, which may have the effect of reducing electricity rates for all customers, as well as creating new jobs, tax revenues to local governments, indirect economic benefits, and similar benefits. Investments in significant new generation and transmission assets, such as those necessary to serve proposed large-scale data center customers, are often subject to the requirement of receiving applicable regulatory approvals from the APSC, the LPSC, the MPSC, the City Council, or the PUCT, depending on applicable regulatory rules and laws and the circumstances of the proposed investments.

Large-scale data center customers often have sustainability goals and commitments that may require the sourcing of power for these facilities from renewable or emissions-free resources, such as solar, wind, or nuclear resources, or installation of carbon capture or other technologies to reduce emissions. Many of these data center customers are willing to contribute a significant portion of the cost of these facilities in order to access these sustainable or emissions-free resources, including through subscriptions to renewable tariff offerings by the Utility operating companies, which arrangements have the potential to lower the costs of such resources as reflected in the rates of the Utility operating companies to the benefit of their other customers. This interest of prospective large-scale data center customers in sustainable and clean generating resources coincides with Entergy’s own sustainability objectives and informs the Utility operating companies’ strategies and resource planning solutions to serve these prospective customers’ needs. There can be no assurance that prospective large-scale data center customers will continue to prioritize sustainability or clean generating resources, which may affect the Utility operating companies’ strategies in the future.

Interconnections

The Utility operating companies’ generating units are interconnected to the electric system which operates at various voltages up to 500 kV. These generating units consist of steam-turbine generators fueled by natural gas, coal, and pressurized and boiling water nuclear reactors; combustion-turbine generators, combined cycle combustion turbine generators and reciprocating internal combustion engine generators that are fueled by natural gas; and inverter-based resources interconnecting both solar photovoltaic systems and energy storage devices that participate in the MISO wholesale electric market. Additionally, some of the Utility operating companies also offer customer services and products that include load-modifying and demand response resources that are interconnected to both the distribution and transmission systems and that also participate in the wholesale market. Entergy’s Utility operating companies are MISO market participants and the companies’ transmission systems are interconnected with those of many neighboring utilities. MISO is an essential link in the safe, cost-effective delivery of electric power across all or parts of 15 U.S. states and the Canadian province of Manitoba. In addition, the Utility operating companies are members of the SERC Reliability Corporation (SERC), the Regional Entity with delegated authority from the North American Electric Reliability Corporation (NERC) for the purpose of proposing and enforcing Bulk Electric System reliability standards within 16 central and southeastern states.

Title

The Utility operating companies’ generating stations are generally located on properties owned in fee simple. Most of the substations and transmission and distribution lines are constructed on private property or public rights-of-way pursuant to easements, servitudes, or appropriate franchises. Some substation properties are owned in fee simple. The Utility operating companies generally have the right of eminent domain, whereby they may perfect title to, or secure easements or servitudes on, private property for their utility operations.

Substantially all of the physical properties and assets owned by Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are subject to the liens of mortgages securing bonds issued by those companies. The Lewis Creek generating station of Entergy Texas was acquired by merger with a subsidiary of Entergy Texas and is currently not subject to the lien of the Entergy Texas indenture.

Fuel Supply

The average fuel cost per kWh for the Utility operating companies and System Energy for the years 2023-2025 were:

(a) Includes average fuel costs from both owned and purchased power resources.

(b) Includes activity from financial transmission rights. See Note 15 to the financial statements for discussion of financial transmission rights.

(c) Entergy Mississippi’s and Entergy Texas’s purchased power in 2025 includes increased capacity purchases, which increases the average fuel cost per kWh without a corresponding increase in kWh.

Actual 2025 and projected 2026 sources of generation for the Utility operating companies and System Energy, including certain power purchases from affiliates under life of unit power purchase agreements, including the Unit Power Sales Agreement, are:

(a) Capacity and energy from System Energy’s interest in Grand Gulf was allocated as follows under the Unit Power Sales Agreement through September 30, 2025: Entergy Arkansas - 36%; Entergy Louisiana - 14%; Entergy Mississippi - 47%; and Entergy New Orleans - 17%. Effective January 1, 2025, Entergy Louisiana divested all of its 14% share of capacity and energy from Grand Gulf and all of the capacity and energy from Grand Gulf that it purchases from Entergy Arkansas (approximately 2.43%) to Entergy Mississippi. This divestiture was being effectuated initially under a designated PPA between Entergy Louisiana and Entergy Mississippi. Effective October 1, 2025, as approved by the FERC under an amended Unit Power Sales Agreement, capacity and energy from System Energy’s interest in Grand Gulf was allocated as follows: Entergy Arkansas - 24.19%, Entergy Mississippi - 56.38%, and Entergy New Orleans - 19.43%. Pursuant to purchased power agreements, Entergy Arkansas is selling a portion of its owned capacity and energy from Grand Gulf to Entergy Mississippi and Entergy New Orleans. See Note 2 to the financial statements for discussion of proceedings regarding the Unit Power Sales Agreement and see Note 8 to the financial statements for discussion of the amendment to the Unit Power Sales Agreement.

(b) Represents natural gas sourced for Simple Cycle Combustion Turbine units and Combined Cycle Gas Turbine units.

(c) The percentage of nuclear and renewable energy includes energy procured or produced for the benefit of certain customers through special tariffs, contracts, or renewable program subscriptions, and those customers retain the exclusive claims to all associated environmental attributes, renewable energy credits, and other relevant clean energy certifications.

(d) Includes generation from both owned and purchased power resources.

(e) Excludes MISO purchases and renewables purchased through purchased power agreements.

(f) In December 2013, Entergy integrated its transmission system into the MISO RTO. Entergy offers or self-schedules its generation into the MISO energy market on a day-ahead and real-time basis and bids for power in the MISO energy market to serve the demand of its customers. Entergy then operates its generation in accordance with MISO’s dispatch instructions. The MISO purchases metric provided for 2025 is not projected for 2026.

Some of the Utility’s gas-fired plants are also capable of using fuel oil, if necessary. Although based on current economics the Utility does not expect material fuel oil use in 2026, it is possible that various operational events including weather or pipeline maintenance may require the use of fuel oil.

Natural Gas

The Utility operating companies have long-term and short-term firm and interruptible gas contracts for both supply and transportation. Over 90% of the Utility operating companies’ power plants maintain some level of long-term firm transportation. Long-term, short-term, and spot-market purchases satisfy gas requirements. Entergy Texas owns a gas storage facility and Entergy Louisiana has a firm storage service agreement that provide reliable and flexible natural gas service to certain generating stations.

Many factors, including wellhead deliverability, storage, pipeline capacity, and demand requirements of end users, influence the availability and price of natural gas supplies for power plants. Demand is primarily tied to weather conditions as well as to the prices and availability of other energy sources. Pursuant to federal and state regulations, gas supplies to power plants may be interrupted during periods of shortage. To the extent natural gas supplies are disrupted or natural gas prices significantly increase, the Utility operating companies may in some instances use alternate fuels, such as oil when available, or rely to a larger extent on coal, nuclear generation, and purchased power.

Coal

Entergy Arkansas has committed to six one- to three-year contracts that will supply at least 85% of the total coal supply needs in 2026. These contracts are staggered in term so that not all contracts have to be renewed the same year. If needed, additional Powder River Basin (PRB) coal will be purchased through contracts with a term of less than one year to provide the remaining supply needs. Based on the high cost of alternate sources, modes of transportation, and infrastructure improvements necessary for its delivery, no alternative coal consumption is expected at Entergy Arkansas during 2026. Coal will be transported to Arkansas via an existing Union Pacific transportation agreement that is expected to provide all of Entergy Arkansas’s rail transportation requirements for 2026.

Entergy Louisiana has committed to four two- to three-year contracts that will supply at least 90% of Nelson Unit 6 coal needs in 2026. If needed, additional PRB coal will be purchased through contracts with a term of less than one year to provide the remaining supply needs. For the same reasons as the Entergy Arkansas plants, no alternative coal consumption is expected at Nelson Unit 6 during 2026. Coal will be transported to Nelson via an existing Union Pacific transportation agreement that is expected to provide all of Entergy Louisiana’s rail transportation requirements for 2026.

For the year ended December 31, 2025, coal transportation delivery rates to Entergy Arkansas- and Entergy Louisiana-operated coal-fired units were able to fully meet supply needs and obligations, and delivery rates in 2026 are expected to continue to be consistent with 2025 delivery rates in meeting supply needs and obligations. Both Entergy Arkansas and Entergy Louisiana control a sufficient number of railcars to satisfy the rail transportation requirement.

The operator of Big Cajun 2 - Unit 3, Pelican Power, has advised Entergy Louisiana and Entergy Texas that it has adequate coal supply, rail car, and barge capacity to meet 2026 obligations.

Nuclear Fuel

The nuclear fuel cycle consists of the following:

• mining and milling of uranium ore to produce a concentrate;
• conversion of the concentrate to uranium hexafluoride gas;
• enrichment of the uranium hexafluoride gas;
• fabrication of nuclear fuel assemblies for use in fueling nuclear reactors; and
• disposal of spent fuel.

The Registrant Subsidiaries that own nuclear plants, Entergy Arkansas, Entergy Louisiana, and System Energy, are responsible through a shared regulated uranium pool for contracts to acquire nuclear material to be used in fueling Entergy’s Utility nuclear units. These companies own the materials and services in this shared regulated uranium pool on a pro rata fractional basis determined by the nuclear generation capability of each company. Any liabilities for obligations of the pooled contracts are on a several but not joint basis. The shared regulated uranium pool maintains inventories of nuclear materials during the various stages of processing. The Registrant Subsidiaries purchase enriched uranium hexafluoride for their nuclear plant reload requirements at the average inventory cost from the shared regulated uranium pool. Entergy Operations, Inc. contracts separately for the fabrication of nuclear fuel as agent on behalf of each of the Registrant Subsidiaries that owns a nuclear plant. All contracts for the disposal of spent nuclear fuel are between the DOE and the owner of a nuclear power plant.

Based upon currently planned fuel cycles, the Utility nuclear units have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable or fixed prices through 2029. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners, including their ability to work through supply disruptions caused by global events, such as the COVID-19 pandemic, or national events, such as political disruption, or trade-related governmental actions, such as tariffs and other measures. There are a number of possible supply alternatives that may be accessed to mitigate any supplier performance failure, including potentially drawing upon Entergy’s inventory intended for later generation periods depending upon its risk management strategy at that time, although the pricing of any alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. In addition, some nuclear fuel contracts are on a non-fixed price basis subject to prevailing prices at the time of delivery.

Entergy’s ability to assure nuclear fuel supply also depends upon the performance reliability of conversion, enrichment, and fabrication services providers. There are fewer of these providers than for uranium. For conversion and enrichment services, Entergy diversifies its supply by supplier and country and may take special measures as needed to ensure supply of enriched uranium for the reliable fabrication of nuclear fuel. For fabrication services, each plant is dependent upon the effective performance of the fabricator of that plant’s nuclear fuel, therefore, Entergy provides additional monitoring, inspection, and oversight for the fabrication process to assure reliability and quality.

The effects of market price changes may be reduced and deferred by risk management strategies, such as negotiation of floor and ceiling amounts for long-term contracts, buying for inventory or entering into forward physical contracts at fixed prices when Entergy believes it is appropriate and useful. Entergy buys uranium and conversion and enrichment services from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the United States.

Entergy Arkansas, Entergy Louisiana, and System Energy each have made arrangements to lease nuclear fuel and related equipment and services. The lessors, which are consolidated in the financial statements of Entergy and the applicable Registrant Subsidiary, finance the acquisition and ownership of nuclear fuel through credit agreements and the issuance of notes. These credit facilities are subject to periodic renewal, and the notes are issued periodically, typically for terms between three and seven years.

Federal Regulation of the Utility

State or local regulatory authorities, as described above, regulate the retail rates of the Utility operating companies. The FERC regulates wholesale sales of electricity rates and interstate transmission of electricity, including 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. See Note 2 to the financial statements for further discussion of federal regulatory proceedings.

Transmission and MISO Markets

In December 2013 the Utility operating companies integrated into the MISO RTO. Although becoming a member of MISO did not affect the ownership by the Utility operating companies of their transmission facilities or the responsibility for maintaining those facilities, MISO maintains functional control over the combined transmission systems of its members and administers wholesale energy and ancillary services markets for market participants in the MISO region, including the Utility operating companies. MISO also exercises functional control of transmission planning and congestion management and provides schedules and pricing for the commitment and dispatch of generation that is offered into MISO’s markets, as well as pricing for load that bids into the markets. The Utility operating companies sell capacity, energy, and ancillary services on a bilateral basis to certain wholesale customers and offer available electricity production of their owned and controlled generating facilities into the MISO resource adequacy construct (the annual Planning Resource Auction), as well as the MISO day-ahead and real-time energy markets pursuant to the MISO tariff and market rules. The resource adequacy construct provided under the MISO tariff confers certain rights and imposes certain obligations upon load-serving entities, including the Utility operating companies, that are served from the transmission systems subject to MISO’s functional control, including the transmission facilities of the Utility operating companies. The MISO tariff is subject to change and has recently undergone significant changes, including changes to its overall capacity accreditation methodology.

MISO administers a process governed by the MISO tariff and subject to the FERC regulation that governs the interconnection of new generation resources to the transmission system under MISO’s functional control. This process generally involves parties that wish to interconnect new generation resources submitting MISO requests to do so, which are then studied and analyzed by MISO, with the participation of its member transmission owners, to determine if the interconnection of such generators requires new transmission facilities to ensure the continued reliable operations of the grid. Under MISO’s current tariff, these requests are studied and considered in clusters, generally in the order in which they are received – a system of priority known as the MISO interconnection queue. In 2025, MISO received approval from the FERC to have an Expedited Resource Addition Study (ERAS) process. ERAS is a temporary process for expediting the study and approval of interconnection projects needed for resource adequacy and/or reliability needs. The Utility operating companies are utilizing the MISO ERAS process to obtain interconnection agreements for fourteen generators on an expedited basis.

Each Utility operating company has its own transmission pricing zone and a formula rate template (included as Attachment O to the MISO tariff) used to establish transmission rates within MISO. The terms and conditions of the MISO tariff, including provisions related to the design and implementation of wholesale markets and the allocation of transmission upgrade costs, are subject to regulation by the FERC.

In addition, orders from each of the Utility operating companies’ respective retail regulators generally require that the Utility operating companies make periodic filings, or generally allow the retail regulator to direct the making of such filings, setting forth the results of analysis of the costs and benefits realized from MISO membership as well as the projected costs and benefits of continued membership in MISO and/or requesting approval of their continued membership in MISO.

System Energy and Related Agreements

System Energy recovers costs related to its interest in Grand Gulf through rates charged to Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans for capacity and energy under the Unit Power Sales Agreement (described below). In 1998 the FERC approved requests by Entergy Arkansas and Entergy Mississippi to accelerate a portion of their Grand Gulf purchased power obligations. Entergy Arkansas’s and Entergy Mississippi’s acceleration of Grand Gulf purchased power obligations ceased effective July 2001 and July 2003, respectively, as approved by the FERC. See Note 2 to the financial statements for discussion of proceedings at the FERC related to System Energy.

Unit Power Sales Agreement

The Unit Power Sales Agreement allocates capacity, energy, and the related costs from System Energy’s ownership and leasehold interests in Grand Gulf. Entergy Arkansas previously entered into multiple life-of-unit designated power purchase agreements, pursuant to which it sold portions of its Unit Power Sales Agreement energy and capacity to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under the MSS-4 replacement tariff. Effective January 1, 2025, Entergy Louisiana divested all of its 14% share of capacity and energy from Grand Gulf pursuant to the Unit Power Sales Agreement and all of the capacity and energy from Grand Gulf that it purchased from Entergy Arkansas (approximately 2.43%) under the MSS-4 replacement tariff to Entergy Mississippi. See Note 8 to the financial statements for discussion of Entergy Louisiana’s divestiture from the Unit Power Sales Agreement. Effective October 1, 2025, the Unit Power Sales Agreement was amended to reflect the divestiture and the amounts of Grand Gulf energy and capacity that were previously re-sold under the MSS-4 replacement tariff, with the associated power purchase agreements being terminated or modified to remove the Grand Gulf sales. The current entitlement percentages under the Unit Power Sales Agreement effective October 1, 2025 are as follows: Entergy Arkansas (24.19%), Entergy Mississippi (56.38%), and Entergy New Orleans (19.43%).

Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans are obligated to make payments to System Energy for their entitlement of capacity and energy on a full cost-of-service basis regardless of the quantity of energy delivered. Payments under the Unit Power Sales Agreement are System Energy’s only source of operating revenue. The financial condition of System Energy depends upon the continued commercial operation of Grand Gulf and the receipt of such payments. Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans generally recover payments made under the Unit Power Sales Agreement through rates charged to their customers.

In the case of Entergy Arkansas, payments are also recovered through sales of electricity from its retained shares of Grand Gulf. Under a settlement agreement entered into with the APSC in 1985 and amended in 1988, Entergy Arkansas retains a 22% share of Grand Gulf-related costs and recovers the remaining 78% of its share in retail rates. In the event that Entergy Arkansas is not able to sell its retained share to third parties, it may sell such energy to its retail customers at a price equal to its avoided cost, which is currently less than Entergy Arkansas’s cost from its retained share.

Availability Agreement

An Availability Agreement among System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans was originally entered into in 1974 in connection with the original financing by System Energy of Grand Gulf (1974 Availability Agreement). In the 1974 Availability Agreement, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans also agreed severally to pay System Energy monthly for the right to receive capacity and energy from Grand Gulf in amounts that (when added to any amounts received by System Energy under the Unit Power Sales Agreement) would at least equal System Energy’s total operating expenses for Grand Gulf (including depreciation at a specified rate and expenses incurred in a permanent shutdown of Grand Gulf) and interest charges.

As discussed in Note 8 to the financial statements, Entergy Louisiana divested all of its rights, entitlements, and interests in such capacity and energy to Entergy Mississippi. Effective October 1, 2025, the 1974 Availability Agreement was terminated and discharged. Immediately following such termination, System Energy, Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans entered into a new Availability Agreement (2025 Availability Agreement). The allocation percentages under the 2025 Availability Agreement are currently fixed as follows: Entergy Arkansas - 24.19%; Entergy Mississippi - 56.38%; and Entergy New Orleans - 19.43%. The allocation percentages under the 2025 Availability Agreement will remain in effect and will govern payments made under such agreement in the event of a shortfall of operating expense funds available to System Energy from other sources, including payments under the Unit Power Sales Agreement.

System Energy had previously assigned its rights to payments and advances from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under the 1974 Availability Agreement as security for all of its outstanding series of first mortgage bonds, as well as for a previously outstanding term loan and the pollution control revenue refunding bonds issued on its behalf. In these assignments, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans further agreed that, in the event they were prohibited by governmental action from making payments under the 1974 Availability Agreement (for example, if the FERC reduced or disallowed such payments as constituting excessive rates), they would then make subordinated advances to System Energy in the same amounts and at the same times as the prohibited payments. System Energy would not be allowed to repay these subordinated advances so long as it remained in default under the related indebtedness or in other similar circumstances. In connection with the termination and discharge of the 1974 Availability Agreement, these assignment agreements were also terminated and discharged. Immediately following such termination, System Energy, Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans entered into new assignment agreements relating to the 2025 Availability Agreement as security for the outstanding series of System Energy’s first mortgage bonds, including those securing the pollution control revenue refunding bonds issued on System Energy’s behalf.

Each of the assignment agreements relating to the 2025 Availability Agreement provides that Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans will make payments directly to System Energy. However, if there is an event of default, those payments must be made directly to the holders of indebtedness that are the beneficiaries of such assignment agreements. The payments must be made pro rata according to the amount of the respective obligations secured.

The obligations of Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans to make payments under the 2025 Availability Agreement are subject to the receipt and continued effectiveness of all necessary regulatory approvals. Sales of capacity and energy under the 2025 Availability Agreement would require that the 2025 Availability Agreement be submitted to the FERC for approval with respect to the terms of such sale. No such filing with the FERC has been made because sales of capacity and energy from Grand Gulf are being made pursuant to the Unit Power Sales Agreement. If, for any reason, sales of capacity and energy are made in the future pursuant to the 2025 Availability Agreement, the jurisdictional portions of the 2025 Availability Agreement would be submitted to the FERC for approval.

Since commercial operation of Grand Gulf began, payments under the Unit Power Sales Agreement to System Energy have exceeded the amounts payable under either version of the Availability Agreement and, therefore, no payments under either version of the Availability Agreement to System Energy have ever been required. The 2025 Availability Agreement may be terminated, and certain amendments or modifications may be made, in each case, by mutual agreement of the parties thereto, without further consent of any assignees or other creditors.

Service Companies

Entergy Services, a limited liability company wholly-owned by Entergy Corporation, provides management, administrative, accounting, legal, engineering, and other services primarily to the Utility operating companies, as well as to Entergy’s non-utility operations business. Entergy Operations is also wholly-owned by Entergy Corporation and provides nuclear management, operations, and maintenance services under contract for ANO, River Bend, Waterford 3, and Grand Gulf, subject to the owner oversight of Entergy Arkansas, Entergy Louisiana, and System Energy, respectively. Entergy Services and Entergy Operations provide their services, under service agreements approved by the FERC, to the Utility operating companies and System Energy on an “at cost” basis, pursuant to cost allocation methodologies.

Jurisdictional Separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana and Entergy Texas

Effective December 31, 2007, Entergy Gulf States, Inc. completed a jurisdictional separation into two vertically integrated utility companies, one operating under the sole retail jurisdiction of the PUCT, Entergy Texas, and the other operating under the sole retail jurisdiction of the LPSC, Entergy Gulf States Louisiana. Entergy Texas owns all Entergy Gulf States, Inc. distribution and transmission assets located in Texas, the gas-fired generating plants located in Texas, undivided 42.5% ownership shares of Entergy Gulf States, Inc.’s 70% ownership interest in Nelson Unit 6 and 42% ownership interest in Big Cajun 2, Unit 3, which are coal-fired generating plants located in Louisiana, and other assets and contract rights to the extent related to utility operations in Texas. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, owns all of the remaining assets that were owned by Entergy Gulf States, Inc. On a book value basis, approximately 58.1% of the Entergy Gulf States, Inc. assets were allocated to Entergy Gulf States Louisiana and approximately 41.9% were allocated to Entergy Texas.

Entergy Texas purchases from Entergy Louisiana pursuant to a life-of-unit purchased power agreement a 42.5% share of capacity and energy from the 70% of River Bend subject to retail regulation of the depreciation amount in Entergy Texas’s rates and otherwise subject to federal regulation. Entergy Texas was allocated a share of River Bend’s nuclear and environmental liabilities that is identical to the share of the plant’s output purchased by Entergy Texas under the purchased power agreement. In connection with the termination of the System Agreement effective August 31, 2016, the purchased power agreements that were put in place for certain legacy units at the time of the jurisdictional separation were also terminated at that time.

Entergy Louisiana and Entergy Gulf States Louisiana Business Combination

On October 1, 2015, the businesses formerly conducted by Entergy Louisiana (Old Entergy Louisiana) and Entergy Gulf States Louisiana (Old Entergy Gulf States Louisiana) were combined into a single public utility. In order to effect the business combination, under the Texas Business Organizations Code (TXBOC), Old Entergy Louisiana allocated substantially all of its assets to a new subsidiary, Entergy Louisiana Power, LLC, a Texas limited liability company (New Entergy Louisiana), and New Entergy Louisiana assumed the liabilities of Old Entergy Louisiana, in a transaction regarded as a merger under the TXBOC. Under the TXBOC, Old Entergy Gulf States Louisiana allocated substantially all of its assets to a new subsidiary (New Entergy Gulf States Louisiana) and New Entergy Gulf States Louisiana assumed the liabilities of Old Entergy Gulf States Louisiana, in a transaction regarded as a merger under the TXBOC. New Entergy Gulf States Louisiana then merged into New Entergy Louisiana with New Entergy Louisiana surviving the merger. Thereupon, Old Entergy Louisiana changed its name from “Entergy Louisiana, LLC” to “EL Investment Company, LLC” and New Entergy Louisiana changed its name from “Entergy Louisiana Power, LLC” to “Entergy Louisiana, LLC” (Entergy Louisiana). With the completion of the business combination, Entergy Louisiana holds substantially all of the assets, and has assumed the liabilities, of Old Entergy Louisiana and Old Entergy Gulf States Louisiana.

Other Business Activities

Entergy’s non-utility operations business includes the ownership of interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers. Entergy’s non-utility operations business also provides decommissioning-related services to nuclear power plants owned by non-affiliated entities.

Property

Entergy’s non-utility operations business owns interests in the following non-nuclear power plants:

(a) “Net Owned Capacity” refers to the nameplate rating on the generating unit.

(b) The owned MW capacity is the portion of the plant capacity owned by Entergy’s non-utility operations business. For a complete listing of Entergy’s jointly-owned generating stations, refer to “Jointly-Owned Generating Stations” in Note 1 to the financial statements.

All generation owned by Entergy’s non-utility operations business falls under the authority of MISO. Customers for the sale of both energy and capacity from its owned generation and contracted power purchases include retail power providers, utilities, electric power co-operatives, power trading organizations, and other power generation companies. The majority of the non-utility operations businesses’ owned generation and contracted power purchases are sold under a cost-based contract.

TLG Services, a subsidiary in Entergy’s non-utility operations business, offers decommissioning, engineering, and related services to nuclear power plant owners.

Regulation of Entergy’s Business

Federal Power Act

The Federal Power Act provides the FERC the authority to regulate:

• the transmission and wholesale sale of electric energy in interstate commerce;
• the reliability of the high voltage interstate transmission system through reliability standards;
• sale or acquisition of certain assets;
• securities issuances;
• the licensing of certain hydroelectric projects;
• certain other activities, including accounting policies and practices of electric and gas utilities; and
• changes in control of FERC jurisdictional entities or rate schedules.

The Federal Power Act gives the FERC jurisdiction over the rates charged by System Energy for Grand Gulf capacity and energy provided to Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans. The FERC also has jurisdiction over the rates charged by Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas to unaffiliated wholesale customers. In addition, the FERC also regulates wholesale power sales between the Utility operating companies. Moreover, the FERC regulates the MISO RTO, an independent entity that maintains functional control over the combined transmission systems of its members and administers wholesale energy, capacity, and ancillary services markets for market participants in the MISO region, including the Utility operating companies. FERC regulation of the MISO RTO includes regulation of the design and implementation of the wholesale markets administered by the MISO RTO, as well as the rates, terms, and conditions of open access transmission service over the member systems and the allocation of costs associated with transmission upgrades.

Entergy Arkansas holds a FERC license that expires in 2053 for two hydroelectric projects totaling 65 MW of capacity.

State Regulation

Utility

Entergy Arkansas is subject to regulation by the APSC as to the following:

• utility service;
• utility service areas;
• retail rates and charges, including depreciation rates;
• fuel cost recovery, including audits of the energy cost recovery rider;
• terms and conditions of service;
• service standards;
• the acquisition, sale, or lease of any public utility plant or property constituting an operating unit or system;
• certificates of convenience and necessity and certificates of environmental compatibility and public need, as applicable, for generating and transmission facilities;
• avoided cost payments to non-exempt Qualifying Facilities;
• net energy metering;
• integrated resource planning;
• utility mergers and acquisitions and other changes of control; and
• the issuance and sale of certain securities.

Additionally, Entergy Arkansas serves a limited number of retail customers in Tennessee. Pursuant to legislation enacted in Tennessee, Entergy Arkansas is subject to complaints before the Tennessee Regulatory Authority only if it fails to treat its retail customers in Tennessee in the same manner as its retail customers in Arkansas. Additionally, Entergy Arkansas maintains limited facilities in Missouri but does not provide retail electric service to customers in Missouri. Although Entergy Arkansas obtained a certificate with respect to its Missouri facilities, Entergy Arkansas is not subject to retail ratemaking jurisdiction in Missouri.

Entergy Louisiana is subject to regulation by the LPSC as to the following:

• utility service;
• retail rates and charges, including depreciation rates;
• fuel cost recovery, including audits of the fuel adjustment clause, and the environmental adjustment charge;
• terms and conditions of service;
• service standards;
• certification of certain transmission projects;
• certification of capacity acquisitions, both for owned capacity and for purchase power contracts that exceed either 5 MW or one year in term;
• procurement process to acquire generating capacity at or above 50 MW;
• audits of the energy efficiency rider;
• avoided cost payment to non-exempt Qualifying Facilities;
• integrated resource planning;
• net energy metering; and
• utility mergers and acquisitions and other changes of control.

Entergy Mississippi is subject to regulation by the MPSC as to the following:

• utility service;
• utility service areas;
• retail rates and charges, including depreciation rates;
• fuel cost recovery, including audits of the energy cost recovery mechanism;
• terms and conditions of service;
• service standards;
• certification of certain generating facilities, certain transmission projects, and distribution projects with construction costs greater than $10 million;
• avoided cost payments to non-exempt Qualifying Facilities;
• integrated resource planning;
• net energy metering; and
• utility mergers, acquisitions, and other changes of control.

Entergy Mississippi is also subject to regulation by the APSC as to the certificate of environmental compatibility and public need for the Independence Station, which is located in Arkansas.

Entergy New Orleans is subject to regulation by the City Council as to the following:

• utility service;
• retail rates and charges, including depreciation rates;
• fuel cost recovery, including audits of the fuel adjustment charge;
• terms and conditions of service;
• service standards;
• audit of the environmental adjustment charge;
• certification of the construction or extension of any new plant, equipment, property, or facility that comprises more than 2% of the utility’s rate base;
• integrated resource planning;
• net energy metering;
• avoided cost payments to non-exempt Qualifying Facilities;
• issuance and sale of certain securities; and
• utility mergers and acquisitions and other changes of control.

To the extent authorized by governing legislation, Entergy Texas is subject to the original jurisdiction of the municipal authorities of a number of incorporated cities in Texas with appellate jurisdiction over such matters residing in the PUCT. Entergy Texas is also subject to regulation by the PUCT as to the following:

• retail rates and charges, including depreciation rates, and terms and conditions of service in unincorporated areas of its service territory, and in municipalities that have ceded jurisdiction to the PUCT;
• fuel recovery, including reconciliations (audits) of the fuel adjustment charges;
• service standards;
• certification of certain transmission and generation projects;
• utility service areas, including extensions into new areas;
• avoided cost payments to non-exempt Qualifying Facilities;
• net energy metering; and
• utility mergers, sales/acquisitions/leases of plants over $10 million, sales of greater than 50% voting stock of utilities, and transfers of controlling interest in or operation of utilities.

Regulation of the Nuclear Power Industry

Atomic Energy Act of 1954 and Energy Reorganization Act of 1974

Under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974, the operation of nuclear plants is heavily regulated by the NRC, which has broad power to impose licensing and safety-related requirements. The NRC has broad authority to impose civil penalties or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Entergy Arkansas, Entergy Louisiana, and System Energy, as owners of all or portions of ANO, River Bend and Waterford 3, and Grand Gulf, respectively, and Entergy Operations, as the licensee and operator of these units, are subject to the jurisdiction of the NRC.

Nuclear Waste Policy Act of 1982

Spent Nuclear Fuel

Under the Nuclear Waste Policy Act of 1982, the DOE is required, for a specified fee, to construct storage facilities for, and to dispose of, all spent nuclear fuel and other high-level radioactive waste generated by domestic nuclear power reactors. Entergy’s nuclear owner/licensee subsidiaries have been charged fees for the estimated future disposal costs of spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. The affected Entergy companies entered into contracts with the DOE, whereby the DOE is to furnish disposal services at a cost of one mill per net kWh generated and sold after April 7, 1983, plus a one-time fee for generation prior to that date. Entergy Arkansas is the only one of the Utility operating companies that generated electric power with nuclear fuel prior to that date and has a recorded liability as of December 31, 2025 of $225 million for the one-time fee. The fees payable to the DOE may be adjusted in the future to assure full recovery. Entergy considers all costs incurred for the disposal of spent nuclear fuel, except accrued interest, to be proper components of nuclear fuel expense. Provisions to recover such costs have been or will be made in applications to regulatory authorities for the Utility plants. Entergy’s total spent fuel fees to date, including the one-time fee liability of Entergy Arkansas, have surpassed $1.7 billion (exclusive of amounts relating to Entergy plants that were paid or are owed by prior owners of those plants).

The permanent spent fuel repository in the U.S. has been legislated to be Yucca Mountain, Nevada. The DOE is required by law to proceed with the licensing of the Yucca Mountain repository (the DOE filed the license application in June 2008) and, after the license is granted by the NRC, proceed with the repository construction and commencement of receipt of spent fuel. Because the DOE has not begun accepting spent fuel, it is in non-compliance with the Nuclear Waste Policy Act of 1982 and is in partial breach of its spent fuel disposal contracts. The DOE continues to delay meeting its obligation. Specific steps were taken to discontinue the Yucca Mountain project, including a motion to the NRC to withdraw the license application with prejudice and the establishment of a commission to develop recommendations for alternative spent fuel storage solutions. In August 2013 the U.S. Court of Appeals for the D.C. Circuit ordered the NRC to continue with the Yucca Mountain license review, but only to the extent of funds previously appropriated by Congress for that purpose and not yet used. Although the NRC completed the safety evaluation report for the license review in 2015, the previously appropriated funds are not sufficient to complete the review, including required hearings. The government has taken no effective action to date related to the recommendations of the appointed spent fuel study commission. Accordingly, large uncertainty remains regarding the time frame under which the DOE will begin to accept spent fuel from Entergy’s facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at Entergy’s nuclear sites.

Following the defunding of the Yucca Mountain spent fuel repository program, the National Association of Regulatory Utility Commissioners and others sued the government seeking cessation of collection of the one mill per net kWh generated and sold after April 7, 1983 fee. In November 2013 the D.C. Circuit ordered the DOE to submit a proposal to Congress to reset the fee to zero until the DOE complies with the Nuclear Waste Policy Act or Congress enacts an alternative waste disposal plan. In January 2014 the DOE submitted the proposal to Congress under protest, and also filed a petition for rehearing with the D.C. Circuit. The petition for rehearing was denied. The zero spent fuel fee went into effect prospectively in May 2014.

As a result of the DOE’s failure to begin disposal of spent nuclear fuel in 1998 pursuant to the Nuclear Waste Policy Act of 1982 and the spent fuel disposal contracts, Entergy’s nuclear owner/licensee subsidiaries have incurred and will continue to incur damages. These subsidiaries have been, and continue to be, involved in litigation to recover the damages caused by the DOE’s delay in performance. See Note 8 to the financial statements for discussion of final judgments recorded by Entergy in 2023 and 2024 related to Entergy’s nuclear owner/licensee subsidiaries’ litigation with the DOE. Through 2025, Entergy’s subsidiaries have won and collected on judgments against the government totaling approximately $1.2 billion.

Pending DOE acceptance and disposal of spent nuclear fuel, the owners of nuclear plants are providing their own spent fuel storage. Storage capability additions using dry casks began operations at ANO in 1996, at River Bend in 2005, at Grand Gulf in 2006, and at Waterford 3 in 2011. These facilities will be expanded as needed.

Nuclear Plant Decommissioning

Entergy Arkansas, Entergy Louisiana, and System Energy are entitled to recover from customers through electric rates the estimated decommissioning costs for ANO, Waterford 3, and Grand Gulf, respectively. In addition, Entergy Louisiana and Entergy Texas are entitled to recover from customers through electric rates the estimated decommissioning costs for the portion of River Bend subject to retail rate regulation. The collections are deposited in trust funds that can only be used in accordance with NRC and other applicable regulatory requirements. Entergy periodically reviews and updates the estimated decommissioning costs to reflect inflation and changes in regulatory requirements and technology, and then makes applications to the regulatory authorities to reflect, in rates, the changes in projected decommissioning costs.

In December 2018 the APSC ordered collections in rates for decommissioning ANO 2 and found that ANO 1’s decommissioning was adequately funded without additional collections. In November 2021, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that both ANO 1 and 2 decommissioning trusts were adequately funded without further collections, and in December 2021 the APSC ordered zero collections for ANO 1 and 2 decommissioning. In November 2022, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that ANO 1’s decommissioning trust was adequately funded, but that ANO 2’s fund had a projected shortage as a result of a decline in decommissioning trust fund investment values over the past year. The filing proposed a reinstatement of decommissioning cost recovery for ANO 2. In December 2022 the APSC ordered reinstatement of decommissioning collections for ANO 2 in accordance with the request in the November 2022 filing. In November 2023, Entergy Arkansas filed a further revised decommissioning cost recovery tariff for ANO indicating that ANO 1’s decommissioning trust continued to be adequately funded, but that ANO 2’s fund continued to require collections higher than those in effect. In December 2023 the APSC approved the proposed higher decommissioning collections for ANO 2. In October 2024, Entergy Arkansas filed a revised cost recovery tariff indicating the decommissioning trusts for both ANO 1 and 2 were adequately funded and proposing suspension of decommissioning collections for both ANO 1 and 2. In December 2024 the APSC approved suspension of decommissioning collections for both ANO 1 and 2. In December 2025 the ALJ, to whom the APSC delegated review of ANO decommissioning revenues, approved continuation of the suspension of decommissioning collections for both ANO 1 and 2.

In July 2010 the LPSC approved increased decommissioning collections for Waterford 3 and the Louisiana regulated share of River Bend to address previously identified funding shortfalls. This LPSC decision contemplated that the level of decommissioning collections could be revisited should the NRC grant license extensions for both Waterford 3 and River Bend. In July 2021, Entergy Louisiana made a filing with the LPSC to adjust Waterford 3 and River Bend decommissioning collections based on the latest site-specific decommissioning cost estimates for those plants. The filing sought to increase Waterford 3 decommissioning collections and decrease River Bend decommissioning collections. In August 2023, Entergy Louisiana made another filing with the LPSC requesting to maintain the same total decommissioning funding collections as currently in effect for both Waterford 3 and River Bend combined, but also requesting to reallocate that same amount of funding by increasing the contributions for Waterford 3 and reducing the contributions for River Bend. In August 2024 the LPSC approved a stipulation settling the case involving Waterford 3 and River Bend decommissioning. The stipulation, among other things, increased Waterford 3 decommissioning collections and decreased River Bend decommissioning collections, as requested.

In December 2010 the PUCT approved increased decommissioning collections for the Texas share of River Bend to address previously identified funding shortfalls. In December 2018 the PUCT approved a settlement that eliminated River Bend decommissioning collections for the Texas jurisdictional share of the plant based on a determination by Entergy Texas that the existing decommissioning fund was adequate following license renewal. In July 2022, Entergy Texas filed a base rate case that proposed continuation of the cessation of River Bend decommissioning collections. In May 2023, Entergy Texas filed on behalf of the parties to the base rate case an unopposed settlement, which included an agreement to maintain Entergy Texas’s decommissioning funding for River Bend at a revenue requirement of $0. In August 2023 the PUCT issued an order accepting the unopposed settlement, including the proposed decommissioning funding settlement terms.

In December 2016 the NRC issued a 20-year operating license renewal for Grand Gulf. In a 2017 filing at the FERC, System Energy stated that with the renewed operating license, Grand Gulf’s decommissioning trust was sufficiently funded, and proposed, among other things, to cease decommissioning collections for Grand Gulf effective October 1, 2017. The FERC accepted a settlement including the proposed decommissioning revenue requirement by letter order in August 2018.

Entergy currently believes its decommissioning funding will be sufficient for its nuclear plants subject to retail rate regulation, although decommissioning cost inflation and trust fund performance will ultimately determine the adequacy of the funding amounts.

Plant owners are required to provide the NRC with a biennial report (annually for units that have shut down or will shut down within five years), based on values as of December 31, addressing the owners’ ability to meet the NRC minimum funding levels. Depending on the value of the trust funds, plant owners may be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional contributions to the trusts, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are met. In March 2025 filings with the NRC were made reporting on decommissioning funding for all of Entergy’s subsidiaries’ nuclear plants. Those reports showed that decommissioning funding for each of the nuclear plants met the NRC’s financial assurance requirements.

Additional information with respect to Entergy’s decommissioning costs and decommissioning trust funds is found in Note 9 and Note 16 to the financial statements.

Price-Anderson Act

The Price-Anderson Act requires that reactor licensees purchase and maintain the maximum amount of nuclear liability insurance available and participate in an industry assessment program called Secondary Financial Protection in order to protect the public in the event of a nuclear power plant accident. The costs of this insurance are borne by the nuclear power industry. Congress passed legislation in 2024 extending the Price-Anderson Act for a term through 2065. The Price-Anderson Act limits the contingent liability for a single nuclear incident to a maximum assessment of approximately $165.9 million per reactor (with 95 nuclear industry reactors currently participating). In the case of a nuclear event in which Entergy Arkansas, Entergy Louisiana, or System Energy is liable, protection is afforded through a combination of insurance and the Secondary Financial Protection program. The Price-Anderson Act and insurance applicable to the nuclear programs of Entergy are discussed in more detail in Note 8 to the financial statements.

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.

Environmental Regulation

Entergy’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy’s businesses are in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted below. Because environmental regulations are subject to change, future compliance requirements and costs cannot be precisely estimated. Except to the extent discussed below, at this time compliance with federal, state, and local provisions regulating the discharge of materials into the environment, or otherwise protecting the environment, is incorporated into the routine cost structure of Entergy’s businesses and is not expected to have a material effect on their competitive position, results of operations, cash flows, or financial position.

National Ambient Air Quality Standards

The Clean Air Act requires the EPA to set National Ambient Air Quality Standards (NAAQS) for ozone, carbon monoxide, lead, nitrogen dioxide, particulate matter, and sulfur dioxide and requires periodic review of those standards. When an area fails to meet an ambient standard, it is considered to be in nonattainment and is classified as “marginal,” “moderate,” “serious,” or “severe.” When an area fails to meet the ambient air standard, the EPA requires state regulatory authorities to prepare state implementation plans (SIPs) meant to cause progress toward bringing the area into attainment with applicable standards.

Ozone Nonattainment

Entergy Texas operates two fossil-fueled generating facilities (Lewis Creek and Montgomery County Power Station) in a geographic area that is not in attainment with the applicable NAAQS for ozone. The ozone nonattainment area that affects Entergy Texas is the Houston-Galveston-Brazoria area. Both Lewis Creek and the Montgomery County Power Station hold all necessary permits for operation and comply with applicable air quality program regulations. Measures enacted to return the area to ozone attainment could make these program regulations more stringent. Entergy will continue to work with state environmental agencies on appropriate methods for assessing attainment and nonattainment with the ozone NAAQS.

Revised Fine Particulate (PM2.5) NAAQS

In March 2024 the EPA issued a final rule which revised the primary annual NAAQS for fine particulate matter, also known as PM2.5, from 12 ug/m3 to 9 ug/m3. This new standard was effective May 2024 and initial attainment/nonattainment designations for areas with available information are due by May 2026. A coalition of 24 states challenged the 2024 rule in the D.C. Circuit Court of Appeals; however, that challenge has been held in abeyance pending the agency’s reconsideration of the rule. In November 2025 the EPA filed a motion asking the D.C. Circuit to vacate the agency’s 2024 revision of the PM2.5 NAAQS which lowered the primary standard to 9 ug/m3. Briefing on that motion is complete and the parties are awaiting a ruling. Even if the D.C. Circuit does not grant the motion to vacate the 2024 rule, the EPA is likely to initiate a reconsideration rulemaking given that this rule was listed as one of its 31 deregulatory priorities.

For any areas designated as nonattainment for the 2024 standard, SIPs to address nonattainment requirements will be due within 18 months of the effective date of any initial nonattainment designations. Within the areas in which the Utility operating companies operate, regulatory agency air monitor data from 2022-2024 for Pulaski County and Union County, Arkansas, West Baton Rouge Parish, Louisiana, Harris County and Montgomery County, Texas, and DeSoto County, Mississippi reflect annual average PM2.5 concentrations in excess of this new standard and monitors for several other areas reflect concentrations between 8-9 ug/m3. Initial attainment and nonattainment designations are expected to be based on data from 2022-2024. As of December 31, 2025, none of the states in Entergy’s service area have recommended any areas to be designated as nonattainment with the revised 2024 standard. Entergy will continue to work with state environmental agencies, as appropriate, to assess attainment and nonattainment with this revised fine particulate NAAQS.

Good Neighbor Plan/Cross-State Air Pollution Rule

In March 2005 the EPA finalized the Clean Air Interstate Rule (CAIR), which was intended to reduce sulfur dioxides (SO2) and nitrogen oxides (NOx) emissions from electric generation plants in order to improve air quality in twenty-nine eastern states. The rule required a combination of capital investment to install pollution control equipment and increased operating costs through the purchase of emission allowances. Entergy began implementation in 2007, including installation of controls at several facilities and the development of an emission allowance procurement strategy. Based on several court challenges, CAIR and its subsequent versions, now known as the Cross-State Air Pollution Rule (CSAPR), have been remanded to and modified by the EPA on multiple occasions.

In June 2023 the EPA published its final Federal Implementation Plan (FIP), known as the Good Neighbor Plan, to address interstate transport for the 2015 ozone NAAQS which would increase the stringency of the CSAPR program in all four of the states where the Utility operating companies operate. The FIP would significantly reduce ozone season NOx emission allowance budgets and allocations for electric generating units. Prior to issuance of the FIP, in February 2023 the EPA issued related SIP disapprovals for many states, including the four states in which the Utility operating companies operate, and these SIP disapprovals are the subject of many legal challenges, including a petition for review filed by Entergy Louisiana challenging the disapproval of Louisiana’s SIP. Judicial stays of the SIP disapprovals were granted in all four states in which the Utility operating companies operate. In March 2025 the U.S. Fifth Circuit Court of Appeals concluded that the EPA properly disapproved Texas’s and Louisiana’s SIPs but found that the EPA’s disapproval was unreasonable for Mississippi’s SIP. The U.S. Eighth Circuit Court of Appeals has not issued a merits decision yet in the Arkansas SIP disapproval litigation. The FIP is also subject to numerous legal challenges in various federal circuit courts of appeals, and in June 2024 the U.S. Supreme Court issued an order, in challenges filed in the D.C. Circuit, staying enforcement of the FIP pending the D.C. Circuit’s review of the rule. Following the U.S. Supreme Court stay, the EPA also stayed the FIP. In March 2025 the EPA asked the D.C. Circuit for a voluntary remand to reconsider the FIP. In its declaration, the EPA states that it plans to reconsider, among other things, what states are subject to the FIP. In April 2025 the D.C. Circuit held the cases in abeyance pending further order of the court. The EPA anticipates a new rule by fall 2026. Entergy is monitoring this litigation, any subsequent rulemaking, and assessing its compliance options in the event that the FIP becomes effective.

Hazardous Air Pollutants

The EPA released the final Mercury and Air Toxics Standard (MATS) rule in December 2011, which had a compliance date, with a widely granted one-year extension, of April 2016. The required controls have been installed and are operational at all affected Entergy units. In May 2024 the EPA issued a final rule revising portions of the MATS rule, including a reduction to the emission limit for filterable particulate matter. The revised standard will become effective July 2027 and could require additional capital investment and/or additional other operation and maintenance costs at Entergy’s coal-fired generating units. In March 2025, as part of its deregulatory agenda, the EPA announced that it was reconsidering the May 2024 MATS rule and that sources interested in a presidential exemption (two years, with additional exemptions available) should provide a recommendation to the EPA by March 31, 2025. Clean Air Act Section 112(i)(4) grants the President authority to issue an exemption if he determines that “the technology to implement such standard is not available and that it is in the national security interests of the United States to do so.” Entergy requested and received presidential exemptions for emissions of filterable particulate matter from Nelson Unit 6 and White Bluff Unit 1. The exemption lasts for a period of two years beyond the rule’s compliance date, i.e., from July 8, 2027 through July 8, 2029. Additionally, in June 2025, the EPA proposed to repeal certain aspects of the May 2024 MATS rule including the revised emission limit for filterable particulate matter for which the presidential exemption was granted. Comments on the proposed rule were due in August 2025, and the EPA is expected to finalize the rule in early 2026.

Regional Haze

In June 2005 the EPA issued its final Clean Air Visibility Rule (CAVR) regulations that potentially could result in a requirement to install SO2 and NOx pollution control technology as Best Available Retrofit Control Technology to continue operating certain of Entergy’s fossil generation units. The rule leaves certain CAVR determinations to the states. This rule establishes a series of 10-year planning periods, with states required to develop SIPs for each planning period, with each SIP including such air pollution control measures as may be necessary to achieve the ultimate goal of the CAVR by the year 2064. The various states are currently in the process of developing SIPs to implement the second planning period of the CAVR, which addresses the 2018-2028 planning period.

The second planning period (2018-2028) for the regional haze program requires states to examine sources for impacts on visibility and to prepare SIPs by July 31, 2021 to ensure reasonable progress is being made to attain visibility improvements. Entergy received information collection requests from the Arkansas and Louisiana Departments of Environmental Quality requesting an evaluation of technical and economic feasibility of various NOx and SO2 control technologies for Independence, Nelson 6, NISCO, and Ninemile. Responses to the information collection requests were submitted to the respective state agencies. Louisiana issued its draft SIP which did not propose any additional air emissions controls for the affected Entergy units in Louisiana. Some public commenters, however, believe additional air controls are cost-effective. In August 2024, Louisiana issued a revised SIP proposal for public comment, and following public comment, re-issued the revised SIP proposal in February 2025. The revised proposed SIP would not require any additional pollution control installations on any Entergy-owned units in Louisiana. Comments on the revised SIP were due in April 2025. The Louisiana Department of Environmental Quality (LDEQ), like many other state agencies, did not meet the July 31, 2021 deadline to submit a SIP to the EPA for review.

Similar to the LDEQ, the Arkansas Department of Energy and Environment, Division of Environmental Quality (ADEQ) did not meet the July 31, 2021 SIP submission deadline, but subsequently submitted a final SIP to the EPA for review. The ADEQ reviewed Entergy’s Independence plant but determined that additional air emission controls would not be cost-effective considering the facility’s commitment to cease coal-fired combustion by December 31, 2030.

In June 2024, the EPA entered into a consent decree that sets deadlines for the EPA to take proposed and final actions on 34 states’ SIP submittals. The deadline for a proposed action to approve or disapprove the Arkansas SIP in part or in whole was August 2025, and the deadline for final action is August 2026. The EPA missed the deadline to finalize the Arkansas SIP, but, in September 2025, issued a proposed approval. Comments on the proposed approval were due October 2025.

In August 2022 the EPA issued findings of failure to submit regional haze SIPs to 15 states, including Louisiana. These findings were effective September 2022, which started the two-year period for the EPA to either approve a SIP submitted by the state or issue a final federal plan. That two-year period expired in September 2024, but the EPA has not yet proposed a FIP for Louisiana.

Greenhouse Gas Emissions

In May 2024 the EPA finalized rules regulating greenhouse gas emissions from new combustion turbine electric generating units (EGUs) under Section 111(b) of the Clean Air Act and from certain existing coal- and gas-fired EGUs under Section 111(d) of the Clean Air Act.

For new gas combustion turbine EGUs, the final rule includes three subcategories of emission standards based on the unit’s annual capacity factor. Applicable emission standards for each subcategory are: a heat-input based CO2 emission standard for low load (<20% annual capacity factor) EGUs; an output-based CO2 efficiency standard for intermediate load (>20% but <40% annual capacity factor) EGUs; and, for base load (>40% annual capacity factor) EGUs, a Phase 1 output-based CO2 efficiency standard followed by a more stringent Phase 2 CO2 standard which will apply beginning January 1, 2032. The Phase 2 standard was established based on an EPA determination that carbon capture and sequestration represents the best system of emission reduction for new base load combustion turbine EGUs. The final rule allows for a possible one-year extension to the compliance date for the Phase 2 standard in circumstances where a source faces a delay in installation of controls due to factors outside of the control of the EGU owner/operator.

For existing generating units, the final rule includes emission guidelines issued under Section 111(d) of the Clean Air Act and allows states two years to develop a plan to implement the new emission guidelines with respect to subject emission units within their state. The final emission guidelines require reductions in CO2 emissions from existing coal-fired generating units which plan to operate beyond January 1, 2032 and exempts coal-fired units which plan to permanently cease operations prior to this date. Due to Entergy’s intention to cease burning coal by the end of 2030, Entergy’s coal-fired generating units are expected to be exempt from this aspect of the final rule. The emission guidelines also include CO2 efficiency standards for existing gas-fired steam EGUs. These emission standards will apply beginning January 1, 2030. Entergy’s existing gas-fired steam generating units are expected to meet these CO2 emission standards. The EPA did not finalize emission guidelines for existing gas turbine EGUs and has announced plans to conduct a subsequent rulemaking for such units. Numerous lawsuits were filed in the D.C. Circuit challenging the final rule, and oral argument was held in December 2024. In June 2025 the EPA released a rule proposing to repeal the May 2024 rule in its entirety, or alternatively, to repeal (1) the Phase 2 standard requiring carbon capture and sequestration for new combustion turbines because it is not an adequately demonstrated technology and (2) the standards for existing coal and gas units. Thus, under the proposed alternative proposal, the only standards that would remain are the Phase 1 standards for new gas combustion turbines. Entergy continues to monitor the status of the EPA’s efforts to repeal the May 2024 rule, with a final rule expected in early 2026.

In February 2026, the EPA announced the repeal of its 2009 Greenhouse Gas Endangerment Finding, a regulatory determination that provided foundation for the EPA's regulation of greenhouse gas emissions from new motor vehicles and new motor vehicle engines. This final action does not immediately or directly impact greenhouse gas emission regulations applicable to Entergy’s operations, including the May 2024 Section 111 rule. Entergy is staying apprised of developments associated with this repeal of federal greenhouse gas regulation and cannot predict the impact of such repeal.

Entergy continues to support national legislation that would most efficiently reduce economy-wide greenhouse gas emissions and increase planning certainty for electric utilities. By virtue of its proportionally large investment in low-emitting generation technologies, Entergy has a relatively low overall carbon dioxide emission “intensity,” as measured by the pounds of carbon dioxide emitted per megawatt-hour of electricity generated. Over the past 25 years, Entergy has set and achieved multiple goals to stabilize or reduce its carbon dioxide emissions. During the period of 2019-2022, Entergy established its most recent goals: (1) a 50% reduction in carbon dioxide emission intensity from owned generation and purchased power, relative to a 2000 baseline, by 2030; (2) 50% carbon-free energy generating capacity by 2030; and (3) a commitment to achieve net zero greenhouse gas emissions by 2050.

As a result of recent sales growth, necessitating the development of new generation capacity that is not carbon-free, combined with changes to the tax credits applicable to carbon-free generation, Entergy can now forecast that it will not achieve either of the 2030 goals. Further, Entergy will not at this time establish new or modified interim (i.e., pre-2050) carbon dioxide-only or greenhouse gas emission goals. Entergy is currently maintaining a goal of achieving net zero greenhouse gas emissions by 2050. As Entergy has communicated in various forums, its clean energy and carbon-reducing generation initiatives will be customer-led. Also, Entergy recognizes and has communicated that carbon capture and storage is a technology that Entergy is well positioned to deploy in the future as an element of a net zero emissions strategy. Entergy plans to pursue carbon capture and storage on new combined cycle generation when feasible and supported by customer demand. Carbon capture and storage, while offering the potential to meet customers’ long-term clean energy demands, is not carbon-free nor will it be deployed in the immediate term. See “Risk Factors” in Part I, Item 1A for discussion of the risks associated with pursuing voluntary climate goals.

Coal Combustion Residuals

In April 2015 the EPA published the final coal combustion residuals (CCR) rule (2015 CCR Rule) regulating CCRs destined for disposal in landfills or surface impoundments as non-hazardous wastes regulated under Resource Conservation and Recovery Act Subtitle D. The final regulations created new compliance requirements including modified storage, new notification and reporting practices, product disposal considerations, and CCR unit closure criteria but excluded CCRs that are beneficially reused in certain processes. Entergy believes that on-site disposal options will be available at its facilities, to the extent needed.

Pursuant to the 2015 CCR Rule, Entergy operates groundwater monitoring systems surrounding its CCR landfills located at White Bluff, Independence, and Nelson. Monitoring to date has detected concentrations of certain listed constituents in the area but has not indicated that these constituents originated at the active landfill cells. Reporting and detection monitoring will continue as the rule requires. In late-2017, Entergy determined that certain in-ground wastewater treatment system recycle ponds at its White Bluff and Independence facilities required management under the 2015 CCR Rule. Consequently, in order to move away from using the recycle ponds, White Bluff and Independence each installed a new permanent bottom ash handling system. As of November 2020, both sites are operating the new system and are no longer sending waste to the recycle ponds. Each site commenced closure of its two recycle ponds (four ponds total) prior to the April 11, 2021 deadline for unlined recycle ponds and the ponds were certified closed in October 2023.

In May 2024 the EPA finalized a rule (2024 CCR Rule) establishing management standards for legacy CCR surface impoundments (i.e., inactive surface impoundments at inactive power plants) and establishing a new class of units referred to as CCR management units (CCRMUs) (i.e., non-containerized CCR located at a regulated CCR facility). CCR utilized in roadbeds and embankments is excluded from the CCRMU definition. Entergy does not have any legacy impoundments; however, the definition of CCRMUs includes on-site areas where CCR was beneficially used. This is contrary to the 2015 CCR Rule which exempted beneficial uses that met certain criteria. Under this expanded rule, all facilities must identify and delineate any CCRMU greater than one ton and submit a facility evaluation report by February 2026. Any potential requirements for corrective action or operational changes under the 2015 CCR Rule and the 2024 CCR Rule continue to be assessed. Notably, ongoing litigation has resulted in the EPA’s continuing review of the rules. Additionally, in March 2025 as part of its deregulatory agenda, the EPA announced that it was evaluating whether to extend the compliance deadlines under the 2024 CCR Rule, and in July 2025 the EPA published a proposal to extend various deadlines, including the facility evaluation report deadline by one year, until February 2027. Consequently, the nature and cost of additional corrective action requirements may depend, in part, on the outcome of the litigation and further EPA review. Given the complexity and recency of the EPA guidance, Entergy is still evaluating the level of work that will ultimately be required to comply with the 2024 CCR Rule. Based on initial estimates of multiple possible remediation scenarios, Entergy recorded in 2024 a $42 million increase in its decommissioning cost liabilities for White Bluff and Independence, along with corresponding increases in the related asset retirement cost assets that will be depreciated over the remaining useful lives of the unit. Entergy will continue to update the asset retirement obligation as the requirements of the 2024 CCR Rule are clarified. As of December 31, 2025, Entergy has recorded asset retirement obligations related to CCR management of $69 million. Additionally, all three sites (White Bluff, Independence, and Nelson) are preparing to implement measures to meet the new and updated Effluent Limitation Guidelines discussed below.

Effluent Limitation Guidelines (ELG)

The 2015 Steam Electric Effluent Limitations Guidelines required, among other things, that there be no discharge of bottom ash transport water. In 2020 the EPA finalized the Reconsideration Rule, allowing limited discharges of bottom ash transport water up to 10% of system volume, under certain defined circumstances including significant (10-year, 24-hour) rain events. The 2020 rule also created a subcategory for units that permanently cease coal combustion by December 31, 2028. Entergy’s White Bluff facility filed a notice of planned participation for this subcategory in October 2021. In May 2024 the EPA finalized a supplemental rule that retains the “retirement by 2028” subcategory, creates a new “retirement by 2034” subcategory, otherwise reinstates the zero-discharge requirement for bottom ash transport water, and imposes new requirements for leachate after the facility ceases to burn coal. Thus, units which permanently cease combustion of coal by December 31, 2028 or December 31, 2034 are exempt from the zero-discharge requirement. However, for units in the 2034 subcategory, the 10% discharge allowance must be incorporated into the facility’s discharge permit. In December 2025, Entergy Arkansas submitted a Notice of Planned Participation to opt into this 2034 subcategory under the 2024 ELG rule. To help ensure facilities cease combustion of coal by the required subcategory 2028 and 2034 dates, zero discharge of bottom ash transport water is required after April 30, 2029 and April 30, 2035, respectively. In October 2025, as part of its deregulatory agenda, the EPA issued proposed revisions to the ELG rule extending existing compliance deadlines and adding compliance flexibilities. The EPA finalized this proposal on December 31, 2025 with an effective date of March 2, 2026. Entergy is evaluating the impacts from these changes to the ELG rule.

Potential Legislative and Regulatory Developments

In addition to the specific instances described above, there are a number of legislative and regulatory initiatives that are or have recently been under consideration at the federal, state, and local level. Because of the nature of Entergy’s business, the imposition of any of these initiatives could affect Entergy’s operations. Entergy continues to monitor these initiatives and activities in order to analyze their potential operational and cost implications. These initiatives have included:

• reconsideration and revision of ambient air quality standards downward which could lead to additional areas of nonattainment;
• designation by the EPA and state environmental agencies of areas that are not in attainment with national ambient air quality standards;
• introduction of bills in Congress and development of regulations by the EPA proposing further limits on SO2, mercury, carbon dioxide, and other air emissions. New legislation or regulations applicable to stationary sources could take the form of market-based cap-and-trade programs, direct requirements for the installation of air emission controls onto air emission sources, or other or combined regulatory programs;
• efforts in Congress or at the EPA to establish a federal carbon dioxide emission tax, control structure, or unit performance standards;
• revisions to the estimates of the Social Cost of Carbon and its use for regulatory impact analysis of federal laws and regulations;
• implementation of the regional cap and trade programs to limit carbon dioxide and other greenhouse gases;
• efforts on the local, state, and federal level to codify renewable portfolio standards, clean energy standards, or a similar mechanism requiring utilities to produce or purchase a certain percentage of their power from defined renewable energy sources or energy sources with lower emissions;
• efforts to develop more stringent state water quality standards, effluent limitations for Entergy’s industry sector, stormwater runoff control regulations, and cooling water intake structure requirements;
• efforts to restrict the previously-approved continued use of oil-filled equipment containing certain levels of polychlorinated biphenyls (PCBs) and increased regulation of per- and polyfluorinated substances or other chemicals;
• efforts by certain external groups to encourage reporting and disclosure of environmental, social, and governance risk;
• efforts by state agencies to start new regulatory programs or acquire primacy of federal programs;
• the listing of additional species as threatened or endangered, the protection of critical habitat for these species, and developments in the legal protection of eagles and migratory birds;
• the regulation of the management, disposal, and beneficial reuse of coal combustion residuals; and
• the regulation of the management and disposal and recycling of equipment associated with renewable and clean energy sources such as used solar panels, wind turbine blades, hydrogen usage, or battery storage.

Other Environmental Matters

Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy Texas

The EPA notified Entergy that the EPA believes Entergy is a potentially responsible party (PRP) concerning PCB contamination at the F.J. Doyle Salvage facility in Leonard, Texas. The facility operated as a scrap salvage business during the 1970s to the 1990s. In May 2018 the EPA investigated the site surface and sub-surface soils, and in November 2018 the EPA conducted a removal action, including disposal of PCB contaminated soils. Entergy responded to the EPA’s information requests in May and July 2019. In November 2020 the EPA sent Entergy and other PRPs a demand letter seeking reimbursement for response costs totaling $4 million expended at the site. In December 2020, Entergy responded to the demand letter, without admitting liability or waiving any rights, indicating that it would engage in good faith negotiations with the EPA with respect to the demand. An initial meeting between the EPA and the PRPs took place in June 2021. A consent decree, which would resolve and settle the matter for approximately $0.3 million, is near finalization.

Litigation

Entergy and its subsidiaries use legal and appropriate means to contest litigation threatened or filed against them, but the states in which Entergy and the Registrant Subsidiaries operate have proven to be unusually litigious environments. Judges and juries in these states have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. The litigation environment in these states poses a significant business risk to Entergy.

Asbestos Litigation (Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas)

See Note 8 to the financial statements for a discussion of this litigation.

Employment and Labor-related Proceedings (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

See Note 8 to the financial statements for a discussion of these proceedings.

Dorrell, et al. v. Constellation Energy, et al. Antitrust Class Action Litigation

On July 11, 2025, an antitrust class action lawsuit was filed in the United States District Court for the District of Maryland on behalf of a putative class against Entergy Corporation, 26 other entities alleged to own and/or operate commercial nuclear power plants in the United States (together with Entergy Corporation, the “nuclear defendants”), and two consulting companies. The class action complaint purports to be brought on behalf of all persons employed in nuclear power generation by the nuclear defendants and their subsidiaries and related entities in the United States from May 1, 2003 to the present. The plaintiffs primarily allege that the nuclear defendants, together with the consulting company defendants, violated Section 1 of the Sherman Act, 15 U.S. Code Chapter 1 by conspiring to suppress compensation and exchange collective bargaining agreement and wage information through a trade group, a consulting firm, and direct communications, including while in attendance at conferences, from May 2003 to the present. The plaintiffs are seeking unspecified monetary damages, including treble damages, interest, injunctive relief, attorney’s fees, and costs. In December 2025 the defendants filed a motion to dismiss.

Human Capital

Employees

Employees are an integral part of Entergy’s commitment to serving customers. As of December 31, 2025, Entergy subsidiaries employed 12,233 people.

There are 3,071 employees represented by the International Brotherhood of Electrical Workers, the United Government Security Officers of America, and the International Union, Security, Police, and Fire Professionals of America.

Entergy’s Approach to Human Resources

Entergy’s people and culture enable its success; that is why acquiring, retaining, and developing talent are important components of Entergy’s human resources strategy. Entergy’s approach to human capital management focuses on the employee experience and includes, among other things, governance and oversight; safety; organizational health, including inclusion and belonging; and talent management.

Governance and Oversight

Ensuring that workplace processes support the desired culture and strategy begins with the Board of Directors and the Office of the Chief Executive. The Talent and Compensation Committee is responsible for overseeing and monitoring the effectiveness of Entergy’s human capital strategies and initiatives, including those pertaining to talent management; organizational health and employee experience, including inclusion and belonging; retention and succession planning; safety; and executive compensation and performance, and receives briefings on these and other topics. The Talent and Compensation Committee establishes and regularly reviews priorities, strategies, and performance on these topics.

Other committees of the Board oversee other key aspects of Entergy’s culture. For example, the Audit Committee reviews reports on enterprise risks, ethics, and compliance training and performance, as well as regular reports on calls made to Entergy’s ethics line and related investigations. To maximize the sharing of information and facilitate the participation of all Board members in these discussions, the Board schedules its regular committee meetings in a manner such that all directors can attend.

The Office of the Chief Executive, which includes Entergy’s Chief Human Resources Officer, ensures annual business plans are designed to support Entergy’s talent objectives and regularly discusses the development, succession planning, and performance of their direct reports and other company officers.

Safety

Entergy’s safety objective is: Everyone Safe. All Day. Every Day. In 2025, Entergy continued its strong safety performance by achieving a recordable injury rate of 0.46 which is top quartile in the utility industry. In 2024, Entergy set a record for its total recordable incident rate, reaching a new low of 0.41 combined employee and contractor results. This was a significant improvement on Entergy’s performance of 0.49 in 2023. The recordable incident rate equals the number of recordable incidents per 100 full-time equivalents. Recordable incidents include fatalities, lost-time accidents, restricted-duty accidents, and medical attentions. In 2025, Entergy saw a reduction in serious injuries by over 30% and returned to operating without an employee or contractor fatality. In order to drive continued improvement, Entergy has developed a data-driven, enterprise-wide safety strategy that focuses on leadership training, front line employee-led improvement plans, and a proactive focus on risk management.

Organizational Health

Entergy believes that organizational health fosters an engaged and productive culture that positions Entergy to deliver sustainable value to its stakeholders. Entergy measures its progress in this area through an organizational health survey coordinated by an external third party. Since initially administering the survey in 2014, Entergy improved from an initial score of 49 (fourth quartile) to a score in 2023 of 62 (third quartile), in 2024 of 65 (third quartile), and in 2025 of 69 (third quartile). Improvement in behavioral expectations, which Entergy believes are the leading indicators of outcome improvements, suggests that Entergy is continuing to move in a positive direction.

Entergy believes that creating a culture of inclusion and belonging promotes the employee experience and drives engagement for all employees. Entergy is committed to developing and retaining a top-performing workforce with a wide variety of backgrounds, experiences, and perspectives. Entergy’s human resources department focuses on, among other things, talent management, workforce development, talent attraction/pipeline development, retention, organizational health, and inclusion and belonging. Among other strategies, Entergy partners with colleges and vocational-technical schools to develop a more viable pipeline of future talent, while also expanding efforts to increase employee engagement and cultivate an inclusive culture with high performance. Entergy has several employee resource groups, open to all employees, offers leadership development programs to support all employees, and facilitates skills training from the executive leadership ranks down to the frontline. Through these efforts, Entergy aspires to create greater understanding and accountability regarding the behaviors and outcomes that are indicative of a premier utility.

Talent Management

Entergy’s focus on talent management is organized in three areas: developing and attracting a highly qualified workforce with a broad range of backgrounds, skill sets, and experiences; equipping its leaders to develop the organization; and building premier utility capability through employee performance management and succession programs. Entergy believes that developing a workforce with a wide variety of backgrounds, experiences, and perspectives equipped with the skills needed, today and in the future, will give it a long-term competitive advantage. The focus of Entergy’s leadership development programs is to equip managers with the skills needed to effectively develop their teams and improve the leader-employee relationship. Entergy’s talent development infrastructure, which includes a combination of business function-specific and enterprise-wide learning and development programs, is designed to ensure Entergy has qualified employees with the skills, experiences, and behaviors needed to perform today and prepare for the future. Entergy strives to achieve its strategic priorities by aligning and enhancing team and individual performance with business objectives, effectively deploying talent through succession planning, and managing workforce transitions.

Availability of SEC filings and other information on Entergy’s website

Entergy electronically files reports with the SEC, including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements, and amendments to such filings. The SEC maintains an internet website that contains reports, proxy and information statements, and other information regarding registrants that file electronically with the SEC at https://www.sec.gov. Copies of the reports that Entergy files with the SEC can be obtained at the SEC’s website.

Entergy uses its website, https://www.entergy.com, as a routine channel for distribution of important information, including news releases, analyst presentations, and financial information. Filings made with the SEC are posted and available without charge on Entergy’s website as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC. These SEC filings include annual and quarterly reports on Forms 10-K and 10-Q and current reports on Form 8-K (including related filings in XBRL format), proxy statements, and any amendments to such filings. Entergy is providing the address to its internet website solely for the information of investors and does not intend the address to be an active link. Notwithstanding this reference or any references to the website in this report, the contents of the website are not incorporated into this report.

See “RISK FACTORS SUMMARY” in Part I, Item 1 for a summary of Entergy’s and the Registrant Subsidiaries’ risk factors.

Investors should review carefully the following risk factors and the other information in this Form 10-K. The risks that Entergy faces are not limited to those in this section. There may be additional risks and uncertainties (either currently unknown or not currently believed to be material) that could adversely affect Entergy’s business, financial condition, results of operations, and liquidity. See “FORWARD-LOOKING INFORMATION.”

Utility Regulatory Risks

(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

The terms and conditions of service, including electric rates, of the Utility operating companies and System Energy are determined through regulatory approval proceedings that can be lengthy and subject to appeal, potentially resulting in delays in effecting rate changes, lengthy litigation, the risk of disallowance of recovery of certain costs, and uncertainty as to ultimate results.

The Utility operating companies are regulated on a cost-of-service and rate of return basis and are subject to statutes and regulatory commission rules and procedures. The rates that the Utility operating companies and System Energy charge reflect their capital expenditures, operations and maintenance costs, allowed rates of return, financing costs, and related costs of service. These rates significantly influence the financial condition, results of operations, and liquidity of Entergy and each of the Utility operating companies and System Energy. These rates are determined in regulatory proceedings and are subject to periodic regulatory review and adjustment, including adjustment upon the initiative of a regulator or, in some cases, affected stakeholders. Regulators in a future rate proceeding may alter the timing or amount of certain costs for which recovery is allowed or modify the current authorized rate of return. Rate refunds may also be required, subject to applicable law.

In addition, regulators have initiated and may initiate additional proceedings to investigate the prudence of costs in the Utility operating companies’ and System Energy’s base rates and examine, among other things, the reasonableness or prudence of the companies’ operation and maintenance practices, level of expenditures (including storm costs and costs associated with capital projects), allowed rates of return and rate base, proposed resource acquisitions, and previously incurred capital expenditures that the operating companies seek to place in rates. The regulators may disallow costs subject to their jurisdiction found not to have been prudently incurred or found not to have been incurred in compliance with applicable tariffs, creating some risk to the ultimate recovery of those costs. Regulatory proceedings relating to rates and other matters typically involve multiple parties seeking to limit or reduce rates. Traditional base rate proceedings, as opposed to formula rate plans, generally have long timelines, are primarily based on historical costs, and may or may not be limited in scope or duration by statute. The length of these base rate proceedings can cause the Utility operating companies and System Energy to experience regulatory lag in recovering costs through rates, such that the Utility operating companies may not fully recover all costs during the rate effective period and may, therefore, earn less than their allowed returns. Decisions are typically subject to appeal, potentially leading to additional uncertainty associated with rate case proceedings. For a discussion of such appeals and related litigation for both the Utility operating companies and System Energy, see Note 2 to the financial statements.

The Utility operating companies have large customer and stakeholder bases and, as a result, could be the subject of public criticism or adverse publicity focused on issues including, but not limited to, efforts to obtain land and secure permits for infrastructure, efforts to execute on and/or obtain regulatory approvals for generation, transmission, carbon capture and storage, or other facilities, including, but not limited to, any such facilities that are intended to support load growth to the system associated with large-scale data centers, the operation and maintenance of their assets and infrastructure, including with respect to climate or environmental matters, their preparedness for major storms or other extreme weather events (including accelerated resilience plans and projects, as well as executing same and/or seeking and obtaining regulatory approvals for such plans and projects) and/or the time it takes to restore service after such events, the quality of their customer service, including timely and accurate billing practices and ability to resolve customer complaints, and the reasonableness of the cost of their service. Criticism or adverse publicity of this nature could, among other things, result in project delays or cancellations or render legislatures and other governing bodies, public service commissions and other regulatory authorities, and government officials less likely to view the applicable operating company in a favorable light and potentially negatively affect legislative or regulatory processes or outcomes, including but not limited to failure to obtain requested approvals on infrastructure investments, as well as lead to increased regulatory oversight or more stringent legislative or regulatory requirements or other legislation or regulatory actions that adversely affect the Utility operating companies.

The Utility operating companies and System Energy, and the energy industry as a whole, have experienced a period of rising costs and investments. An upward trend in spending, especially with respect to infrastructure investments (including those that have already been approved by a regulator), is likely to continue in the foreseeable future and could result in more frequent rate cases and requests for, and the continuation of, cost recovery mechanisms, all of which could result in adverse cost recovery determinations and/or face resistance from customers and other stakeholders especially in a rising cost environment, whether due to inflation, increased tariffs or changes to governmental policies and programs, including tax incentives or tax credits, grants, guarantees, and other subsidies, or high fuel prices or otherwise, and/or in periods of economic decline or hardship. Significant increases in costs associated with capital investments have occurred and could in the future increase financing needs and otherwise adversely affect Entergy, the Utility operating companies, and System Energy’s business, financial position, results of operation, or cash flows. For information regarding rate case proceedings and formula rate plans applicable to the Utility operating companies, see Note 2 to the financial statements.

Changes to state or federal legislation or regulation affecting electric generation, electric transmission, distribution, and related activities could adversely affect Entergy and the Utility operating companies’ financial position, results of operations, or cash flows and their utility businesses.

If legislative and regulatory structures evolve in a manner that erodes the Utility operating companies’ exclusive rights to serve their regulated customers, such as through “retail open access” or otherwise, they could lose customers and sales and their results of operations, financial position, or cash flows could be materially affected. Additionally, technological advances in energy efficiency and distributed energy resources are reducing the costs of these technologies and, together with current state and federal subsidies, the increasing penetration of these technologies could result in reduced sales by the Utility operating companies. Such loss of sales, due to the methodology used to determine cost of service rates or otherwise, could put upward pressure on rates, possibly resulting in adverse regulatory actions to mitigate such effects on rates. Further, the failure of regulatory structures to evolve to accommodate the changing needs and desires of customers with respect to the sourcing and use of electricity also could diminish sales by the operating companies. Additionally, any future laws and regulations regarding large-scale data centers, including those relating to energy use, efficiency standards and source of power, could adversely affect Entergy and the Utility operating companies serving these customers, and the effects of such laws and regulations could be heightened by these companies’ increasing exposure to the data center industry. Entergy and the Utility operating companies cannot predict if or when they may be subject to changes in law, regulation, or governmental policy, or the extent and timing of reductions of the cost of distributed energy resources, nor can they predict the impact of these changes on their results of operations, financial position, or cash flows.

The Utility operating companies recover fuel, purchased power, and associated costs through rate mechanisms that are subject to risks of delay or disallowance in regulatory proceedings, and sudden or prolonged increases in fuel and purchased power costs could lead to increased customer arrearages or bad debt expenses.

The Utility operating companies recover their fuel, purchased power, and associated costs from their customers through rate mechanisms subject to periodic regulatory review and adjustment. Because regulatory review can result in the disallowance of incurred costs found not to have been prudently incurred or not reflected in rates as permitted by approved rate schedules and accounting rules, including the cost of replacement power purchased when generators experience outages or when planned outages are extended, with the possibility of refunds to ratepayers, there exists some risk to the ultimate recovery of those costs, particularly when there are substantial or sudden increases in such costs, including due to inflation or as a result of changes to governmental policies and programs, including tariffs, tax incentives or tax credits, loans, grants, guarantees, and other subsidies. Regulators also may initiate proceedings to investigate the continued usage or the adequacy and operation of the fuel and purchased power recovery clauses of the Utility operating companies and, therefore, there can be no assurance that existing recovery mechanisms will remain unchanged or in effect at all.

The Utility operating companies’ cash flows can be negatively affected by the time delays between when gas, power, or other commodities are purchased and the ultimate recovery from customers of the costs in rates. On occasion, when the level of incurred costs for fuel and purchased power rises dramatically, some of the Utility operating companies may agree to defer recovery of a portion of that period’s fuel and purchased power costs for recovery at a later date, which could increase the near-term working capital and borrowing requirements of those companies. The Utility operating companies also may experience, and in some instances have experienced, an increase in customer bill arrearages and bad debt expenses due to, among other reasons, increases in fuel and purchased power costs, especially in a rising cost environment, whether due to inflation or increased tariffs and/or in periods of economic decline or hardship. For a description of fuel and purchased power recovery mechanisms and information regarding the regulatory proceedings for fuel and purchased power cost recovery, see Note 2 to the financial statements.

The Utility operating companies are subject to economic risks associated with participation in the MISO markets and the allocation of transmission upgrade costs. The operation of the Utility operating companies’ transmission system pursuant to the MISO RTO tariff and their participation in the MISO RTO’s wholesale markets may be adversely affected by regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.

The Utility operating companies are subject to economic risks associated with participation in the MISO markets and resource adequacy construct. MISO tariff rules and system conditions, including transmission congestion, could affect the Utility operating companies’ ability to sell capacity, energy, and/or ancillary services in certain regions and/or the economic value of such sales, or increase the cost of serving the Utility operating companies’ respective loads. MISO market rules may change or be interpreted in ways that cause additional cost and risk, including compliance risk. Additionally, each Utility operating company’s continued participation in MISO may be affected by the outcomes of proceedings at its respective retail regulator regarding the realized and expected costs and benefits associated with such Utility operating company’s ongoing participation in MISO.

The Utility operating companies participate in the MISO regional transmission planning process and are subject to risks associated with planning decisions that MISO makes in the exercise of control over the planning of the Utility operating companies’ transmission assets that are under MISO’s functional control. The Utility operating companies pay transmission rates that reflect the cost of transmission projects that the Utility operating companies do not own and are subject to the same increased costs due to factors described herein as potentially impacting other capital projects, which could increase cash or financing needs. Further, FERC policies and regulation addressing cost responsibility for transmission projects, including transmission projects to interconnect new generation facilities, such as new facilities to power large loads, may give rise to cash and financing-related risks as well as result in upward pressure on the retail rates of the Utility operating companies, which, in turn, may result in adverse actions by the Utility operating companies’ retail regulators. In addition to the cash and financing-related risks arising from the potential additional cost allocation to the Utility operating companies from transmission projects of others or changes in FERC policies or regulation related to cost responsibility for transmission projects (including, but not limited to, transmission projects that are intended to serve new large-scale data centers), there is a risk that the Utility operating companies’ business and financial position could be harmed as a result of lost investment opportunities and other effects that flow from an increased number of competitive and large-scale projects being approved and constructed that are interconnected with their transmission systems, as well as the risk associated with the large investment in serving an increasing number of customers concentrated in the data center industry.

Further, the terms and conditions of the MISO tariff, including provisions related to the design and implementation of wholesale markets, the allocation of transmission upgrade costs, the MISO-wide allowed base rate of return on equity, and any required MISO-related charges and credits are subject to regulation by the FERC. The operation of the Utility operating companies’ transmission system pursuant to the MISO tariff and their participation in the MISO wholesale markets, and the resulting costs, may be adversely affected by regulatory or market design changes relating to, among other issues, significant current and expected load growth to serve new large-scale data centers, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.

The MISO tariff provisions governing the rights and obligations associated with the resource adequacy construct provided under the MISO tariff are subject to change and have recently undergone significant changes, some of which are the subject of pending litigation and/or appeals. Due to their magnitude and, with respect to the changes already made, the speed with which they have been implemented, these changes carry risk, including compliance risk, and may result in material additional costs being passed through to the Utility operating companies’ customers in retail rates, including but not limited to additional capacity costs incurred in the annual MISO Planning Resource Auction, and these risks may be exacerbated by significant new load additions, including large-scale projects to serve data centers, whether by the Utility operating companies or by other MISO load-serving entities. Also, by virtue of the Utility operating companies’ participation in MISO and the design and terms of the MISO resource adequacy construct, other load-serving entities served by the Utility operating companies’ transmission assets, which are under MISO’s functional control, may be able to circumvent reasonable resource planning obligations and avoid, in whole or in part, the full cost of procuring the resources reasonably needed to reliably supply their respective loads. As a result, there are a variety of risks to the Utility operating companies and their customers, including the risk of bearing additional costs for resources needed to ensure reliable service, the risk of reduced reliability and the enhanced risk of outages or curtailments and lost sales which, because of the methodology for establishing cost of service rates, presents the risk of upward pressure on the Utility operating companies’ rates, and these risks may be exacerbated by significant new load additions, including large-scale projects to serve data centers and the increasing concentration of exposure to the data center industry, whether by the Utility operating companies or by other MISO load-serving entities.

In addition, a large volume of parties and individual generation resources, including large-scale projects to serve data centers, are presently seeking to interconnect to the transmission system MISO administers and over which MISO exercises functional control. Due to the resources and time required to study and evaluate these numerous interconnection requests, including the effects of speculative requests and requests that are withdrawn at late stages of the process, the current MISO interconnection queue to review new requests is subject to significant delays or periods in which MISO does not accept new interconnection requests. These delays present risks to the Utility operating companies and their ability to develop and procure new generation resources to serve their respective loads, and these risks may be exacerbated by significant new load additions. Moreover, MISO’s recently revised collateral and financial requirements for generation interconnections are stricter with larger initial financial obligations. In addition, they carry greater financial penalties and requirements tied directly to project readiness and speed.

For additional information on MISO regulation and the Utility operating companies’ membership in MISO, see “Federal Regulation of the Utility – Transmission and MISO Markets” section of Part I, Item 1.

(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)

A delay or failure in recovering amounts for storm restoration costs incurred as a result of severe weather, the impact on customer bills of permitted storm cost recovery, or the inability to securitize future storm restoration costs could have material effects on Entergy and its Utility operating companies.

Entergy’s and its Utility operating companies’ results of operations, liquidity, and financial condition can be materially affected by the destructive effects of severe weather. Severe weather can also result in significant outages for the customers of the Utility operating companies and, therefore, reduced revenues for the Utility operating companies during the period of the outages. A delay or failure in recovering amounts for storm restoration costs incurred, inability to securitize future storm restoration costs, or loss of revenues as a result of severe weather could have a material effect on Entergy and those Utility operating companies affected by severe weather, including lower credit ratings and, thus, higher costs for future debt issuances, as well as limitations on the ability to fund other investments to address customer needs, which limitations could have an adverse impact on the Utility operating companies’ financial results and/or customers and impede economic development opportunities that would benefit the Utility operating companies and their customers and communities. The inability to recover losses either excluded by insurance or in excess of the insurance limits that can be secured economically also could have a material effect on Entergy and its Utility operating companies. In addition, the recovery of major storm restoration costs from customers could effectively limit our ability to make planned capital or other investments due to the impact of such storm cost recovery on customer bills, especially in a rising cost environment due to factors described herein as potentially impacting other capital projects, and impede the ability to support economic development opportunities in the areas served by the Utility operating companies.

Weather, economic conditions, technological developments, and other factors may have a material impact on electricity sales and otherwise materially affect the Utility operating companies’ results of operations and system reliability.

Temperatures above normal levels in the summer tend to increase electric cooling demand and revenues, and temperatures below normal levels in the winter tend to increase electric heating demand and revenues. As a corollary, mild temperatures in either season tend to decrease energy usage and resulting revenues. Higher consumption levels coupled with seasonal pricing differentials typically cause the Utility operating companies to report higher revenues in the third quarter of the fiscal year than in the other quarters. Changing weather patterns and extreme weather conditions, including hurricanes or tropical storms, droughts, wildfires, flooding events, or ice storms, the frequency or intensity of which may be exacerbated by climate change, may stress the Utility operating companies’ generation facilities and transmission and distribution systems, resulting in increased maintenance and capital costs (and potential increased financing needs), limits on their ability to meet peak customer demand, increased regulatory oversight, criticism or adverse publicity, and reduced customer satisfaction. These extreme conditions could have a material effect on the Utility operating companies’ financial condition, results of operations, and liquidity.

Entergy’s electricity sales volumes are affected by a number of factors including weather and economic conditions, trends in energy efficiency, new technologies, and self-generation alternatives, including the willingness and ability of large industrial customers to develop co-generation facilities that greatly reduce their grid demand. In addition, changes to regulatory policies, such as those that allow customers to directly access the market to procure wholesale energy or those that incentivize development and utilization of new, developing, or alternative sources of generation, could, and in some instances, have already reduced sales, and other non-traditional procurements, such as virtual purchase power agreements or “behind the meter” generation solutions, could, and in some instances have already limited growth opportunities or reduced sales at the Utility operating companies. Some of these factors are inherently cyclical or temporary in nature, such as the weather or economic conditions, and typically do not have a long-lasting effect on Entergy’s operating results. Others, such as the organic turnover of appliances and lighting and their replacement with more efficient ones and adoption of newer technologies, including smart thermostats, new building codes, distributed energy resources, energy storage, demand side management, and rooftop solar, are adversely affecting sales growth rates on a more permanent basis. As a result of emerging efficiencies and technologies, the Utility operating companies may lose customers or experience lower average use per customer in the residential and commercial classes, and continuing advances have the potential to further limit sales or sales growth in the future.

The Utility operating companies also may face competition from other companies offering products and services to Entergy’s customers. Advances in technology and changes in laws or regulations offer alternative methods of producing and/or consuming energy, some potentially at a reduced cost. The Utility operating companies’ future success will depend, in part, on our ability to anticipate and successfully adapt to technological developments and to offer services that meet customer demand. Failure to keep pace or manage the related costs of such changes or additional technology investments may limit customer growth and have an adverse effect on the Utility operating companies’ operations or could make the Utility operating companies less competitive and negatively impact Entergy’s and the Utility operating companies’ financial condition, results of operations, and cash flows.

Electricity sales to industrial customers, in particular, benefit from steady economic growth and favorable commodity markets; however, industrial sales are or may be sensitive to changes in laws, regulations, trade-related governmental actions, including tariffs and other measures, such as new laws or regulations relating to data centers or other large loads, or conditions in the markets in which its customers operate. Negative changes in any of these or other factors, particularly sustained economic downturns or sluggishness, have the potential to result in slower sales growth or sales declines and increased bad debt expense, which could materially affect Entergy’s and the Utility operating companies’ results of operations, financial condition, and liquidity.

The Utility operating companies also may not realize anticipated or expected growth in industrial or large-scale data center sales or electrification opportunities to help such customers achieve their environmental sustainability goals. This could occur because of changes in customers’ goals or business priorities, changes in environmental policies and priorities of federal, state, and local officials and other stakeholders, competition from other companies, or decisions by such customers to seek to achieve such objectives or goals through methods not offered by Entergy.

Nuclear Operating, Shutdown, and Regulatory Risks

(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy)

Certain of the Utility operating companies and System Energy are expected to consistently operate their nuclear power plants at high capacity factors in order to be successful, and lower capacity factors could materially affect Entergy’s and their results of operations, financial condition, and liquidity.

Nuclear capacity factors significantly affect the results of operations of certain Utility operating companies and System Energy. Nuclear plant operations involve substantial fixed operating costs. Consequently, there is pressure on plant owners to operate nuclear power plants at higher capacity factors, though such operations always must be consistent with safety, reliability, and nuclear regulatory requirements. For the Utility operating companies that own nuclear plants, lower nuclear plant capacity factors can increase production costs by requiring the affected companies to generate additional energy, sometimes at higher costs, from their owned or contractually controlled facilities or purchase additional energy in the spot or forward markets in order to satisfy their supply needs.

Certain of the Utility operating companies and System Energy periodically shut down their nuclear power plants to replenish fuel. Plant maintenance and upgrades are often scheduled during such refueling outages. If refueling outages last longer than anticipated or if unplanned outages arise, Entergy’s and their results of operations, financial condition, and liquidity could be materially affected.

Outages at nuclear power plants to replenish fuel require the plant to be “turned off.” Refueling outages generally are planned to occur once every 18 to 24 months. Plant maintenance and upgrades are often scheduled during such planned outages, which may extend the planned outage duration beyond that required for only refueling activities. When refueling outages last longer than anticipated or a plant experiences unplanned outages, capacity factors decrease, and maintenance costs may increase.

Certain of the Utility operating companies and System Energy face risks related to the purchase of uranium fuel (and its conversion, enrichment, and fabrication). These risks could materially affect Entergy’s and their results of operations, financial condition, and liquidity.

Based upon currently planned fuel cycles, Entergy’s nuclear units have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable prices through the end of 2029. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners. While there are a number of possible alternate suppliers that may be accessed to mitigate any supplier performance failure, the pricing of any such alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S. Market prices for nuclear fuel have been extremely volatile from time to time in the past and may be subject to increased volatility due to the imposition of tariffs, domestic purchase requirements, supply chain disruptions, limitations or bans on importation of uranium or uranium products from foreign countries, evolving geopolitical conditions such as the wars between Russia and Ukraine and Israel and Hamas, the Nigerien coup, or shifting trade arrangements or sanctions between countries. Although Entergy’s nuclear fuel contract portfolio provides a degree of hedging against market risks for several years, costs for nuclear fuel in the future cannot be predicted with certainty due to inherent market uncertainties, as well as uncertainties arising from the factors described in the immediately preceding sentence, and price changes could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies and System Energy.

Entergy’s ability to assure uninterrupted nuclear fuel supply also depends upon the performance and reliability of conversion, enrichment, and fabrication services providers. These service providers are fewer in number than uranium suppliers. For conversion and enrichment services, Entergy diversifies its supply by supplier and country and may take special measures to ensure a reliable supply of enriched uranium for fabrication into nuclear fuel. For fabrication services, each plant is dependent upon the performance of the fabricator of that plant’s nuclear fuel; therefore, Entergy relies upon additional monitoring, inspection, and oversight of the fabrication process to assure reliability and quality of its nuclear fuel. Certain of the suppliers and service providers are located in or dependent upon foreign countries, such as Russia, and international sanctions, bans, retaliatory actions, or tariffs impacting trade with such countries could further restrict the ability of such suppliers or service providers to continue to supply fuel or provide such services at acceptable prices or at all. While such suppliers have performed as expected to date, the future inability of suppliers to perform such obligations could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies and System Energy.

Certain of the Utility operating companies and System Energy face the risk that the NRC will change or modify its regulations, suspend or revoke their licenses, or increase oversight of their nuclear plants, which could materially affect Entergy’s and their results of operations, financial condition, and liquidity.

Under the Atomic Energy Act and Energy Reorganization Act, the NRC regulates the operation of nuclear power plants. The NRC may modify, suspend, or revoke licenses, shut down a nuclear facility and impose civil penalties for failure to comply with the Atomic Energy Act, related regulations, or the terms of the licenses for nuclear facilities. Interested parties may also intervene in pending proceedings, which could result in prolonged proceedings. A change in the Atomic Energy Act, other applicable statutes, or the applicable regulations or licenses, or the NRC’s interpretation thereof, may require a substantial increase in capital expenditures or may result in increased operating or decommissioning costs and could materially affect the results of operations, liquidity, or financial condition of Entergy, certain of the Utility operating companies, or System Energy. A change in the classification of a plant owned by one of these companies under the NRC’s Reactor Oversight Process, which is the NRC’s program to collect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response, also could cause the owner of the plant to incur material additional costs as a result of the increased oversight activity and potential response costs associated with the change in classification. For additional information concerning the current classification of the plants owned by Entergy Arkansas, Entergy Louisiana, and System Energy, see “Regulation of Entergy’s Business - Regulation of the Nuclear Power Industry - NRC Reactor Oversight Process” in Part I, Item 1.

Events at nuclear plants owned by one of these companies, as well as those owned by others, may lead to a change in laws or regulations or the terms of the applicable licenses, or the NRC’s interpretation thereof, or may cause the NRC to increase oversight activity or initiate actions to modify, suspend, or revoke licenses, shut down a nuclear facility, or impose civil penalties. As a result, if an incident were to occur at any nuclear generating unit, whether an Entergy nuclear generating unit or not, it could materially affect the financial condition, results of operations, and liquidity of Entergy, certain of the Utility operating companies, or System Energy.

Certain of the Utility operating companies and System Energy are exposed to risks and costs related to operating and maintaining their nuclear power plants, and their failure to maintain operational efficiency at their nuclear power plants could result in a plant shutdown or operation at less than full capacity and could materially affect Entergy’s and their results of operations, financial condition, and liquidity.

The nuclear generating units owned by certain of the Utility operating companies and System Energy began commercial operations in the 1970s-1980s. Older equipment may require more capital expenditures to keep each of these nuclear power plants operating safely and efficiently. This equipment is also likely to require periodic upgrading and improvement. Any unexpected failure, including failure associated with breakdowns, forced outages, or any unanticipated capital expenditures, could result in increased costs, some of which costs may not be fully recoverable by these Utility operating companies and System Energy in regulatory proceedings should there be a determination of imprudence. Operations at any of the nuclear generating units owned and operated by Entergy’s subsidiaries could degrade to the point where the affected unit needs to be shut down or operated at less than full capacity. If this were to happen, identifying and correcting the causes may require significant time and expense. A decision may be made to close a unit rather than incur the expense of restarting it or returning the unit to full capacity. For these Utility operating companies and System Energy, this could result in certain costs being stranded and potentially not fully recoverable in regulatory proceedings. In addition, the operation and maintenance of Entergy’s nuclear facilities require the commitment of substantial human resources that can result in increased costs.

Moreover, Entergy is becoming more dependent on fewer suppliers for key parts of Entergy’s nuclear power plants that may need to be replaced or refurbished, and in some cases, parts are no longer available and have to be reverse-engineered for replacement. In addition, certain major parts have long lead-times to manufacture if an unplanned replacement is needed. This dependence on a reduced number of suppliers and long lead-times on certain major parts for unplanned replacements could result in delays in obtaining qualified replacement parts and, therefore, greater expense for certain of the Utility operating companies and System Energy.

The costs associated with the storage of the spent nuclear fuel of certain of the Utility operating companies and System Energy, as well as the costs of and their ability to fully decommission their nuclear power plants, could be significantly affected by the timing of the opening of a spent nuclear fuel disposal facility, as well as interim storage and transportation requirements.

Certain of the Utility operating companies and System Energy incur costs for the on-site storage of spent nuclear fuel. The approval of a license for a national repository for the disposal of spent nuclear fuel, such as the one proposed for Yucca Mountain, Nevada, or any interim storage facility, and the timing of such facility opening, will significantly affect the costs associated with on-site storage of spent nuclear fuel. For example, while the DOE is required by law to proceed with the licensing of the Yucca Mountain repository and, after the license is granted by the NRC, to construct the repository and commence the receipt of spent fuel, the NRC licensing of the Yucca Mountain repository is effectively at a standstill. These actions are prolonging the time before spent fuel is removed from Entergy’s plant sites. Because the DOE has not accomplished its objectives, it is in non-compliance with the Nuclear Waste Policy Act of 1982 and is in partial breach of its spent fuel disposal contracts, and Entergy has sued the DOE for such breaches, and has won and collected on judgments against the government totaling approximately $1.2 billion through 2025, and continues to be involved in litigation to recover damages. Furthermore, Entergy is uncertain as to when the DOE will commence acceptance of spent fuel from its facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at the companies’ nuclear sites and maintenance costs on existing storage facilities, including aging management of fuel storage casks, may increase. The costs of on-site storage are also affected by regulatory requirements for such storage. In addition, the availability of a repository or other off-site storage facility for spent nuclear fuel may affect the ability to fully decommission the nuclear units and the costs relating to decommissioning. For further information regarding spent fuel storage, see the “Critical Accounting Estimates – Nuclear Decommissioning Costs – Spent Fuel Disposal” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy and Note 8 to the financial statements.

Certain of the Utility operating companies and System Energy may be required to pay substantial retrospective premiums imposed under the Price-Anderson Act and/or by Nuclear Electric Insurance Limited (NEIL) in the event of a nuclear incident, and losses not covered by insurance could have a material effect on Entergy’s and their results of operations, financial condition, or liquidity.

Accidents and other unforeseen problems at nuclear power plants have occurred both in the United States and elsewhere. As required by the Price-Anderson Act, the Utility operating companies and System Energy carry the maximum available amount of primary nuclear off-site liability insurance with American Nuclear Insurers, which is $500 million for each operating site. Claims for any nuclear incident exceeding that amount are covered under Secondary Financial Protection. The Price-Anderson Act limits each reactor owner’s public liability (off-site) for a single nuclear incident to the payment of retrospective premiums into a secondary insurance pool, which is referred to as Secondary Financial Protection, up to approximately $165.9 million per reactor. With 95 reactors currently participating, this translates to a total public liability cap of approximately $15.8 billion per incident. The limit is subject to change to account for the effects of inflation, a change in the primary limit of insurance coverage, and changes in the number of licensed reactors. As a result, in the event of a nuclear incident that causes damages (off-site) in excess of the primary insurance coverage, each owner of a nuclear plant reactor, including Entergy’s Utility operating companies and System Energy, regardless of fault or proximity to the incident, will be required to pay a retrospective premium, equal to its proportionate share of the loss in excess of the primary insurance level, up to a maximum of approximately $165.9 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is approximately $830 million). The retrospective premium payment is currently limited to approximately $25 million per year per incident per reactor until the aggregate public liability for each licensee is paid up to the $165.9 million cap.

NEIL is a utility industry mutual insurance company, owned by its members, including the Utility operating companies and System Energy. NEIL provides onsite property and decontamination coverage. All member plants could be subject to an annual assessment (retrospective premium of up to 10 times current annual premium for all policies) should the NEIL surplus (reserve) be significantly depleted due to insured losses. The current maximum annual assessment amounts total approximately $76.1 million per occurrence for the Utility nuclear plants. The retrospective premium assessments are subject to change based on results of NEIL underwriting.

As mentioned above, as an owner of nuclear power plants, Entergy participates in industry self-insurance programs and could be liable to fund claims should a plant owned by a different company experience a major event. Any resulting liability from a nuclear accident may exceed the applicable primary insurance coverage and require contribution of additional funds through the industry-wide program that could significantly affect the results of operations, financial condition, or liquidity of Entergy, certain of the Utility operating companies, or System Energy.

The decommissioning trust fund assets for the nuclear power plants owned by certain of the Utility operating companies and System Energy may not be adequate to meet decommissioning obligations if market performance and other changes decrease the value of assets in the decommissioning trusts, if one or more of Entergy’s nuclear power plants is retired earlier than the anticipated shutdown date, if the plants cost more to decommission than estimated, or if current regulatory requirements change, which then could require significant additional funding.

Owners of nuclear generating plants have an obligation to decommission those plants. Certain of the Utility operating companies and System Energy maintain decommissioning trust funds for this purpose. Certain of the Utility operating companies and System Energy collect funds from their customers, which are deposited into the trusts covering the units operated for or on behalf of those companies. Those rate collections, as adjusted from time to time by rate regulators, are generally based upon operating license lives and trust fund balances as well as estimated trust fund earnings and decommissioning costs. Assets in these trust funds are subject to market fluctuations, will yield uncertain returns that may fall below projected return rates, and may result in losses resulting from the recognition of impairments of the value of certain securities held in these trust funds.

Under NRC regulations, nuclear plant owners are permitted to project the NRC-required decommissioning amount, based on an NRC formula or a site-specific estimate, and the amount that will be available in each nuclear power plant’s decommissioning trusts combined with any other decommissioning financial assurances in place. The projections are made based on the operating license expiration date and the mid-point of the subsequent decommissioning process, or the anticipated actual completion of decommissioning if a site-specific estimate is used. If the projected amount of each individual plant’s decommissioning trusts exceeds the NRC-required decommissioning amount, then its NRC license termination decommissioning obligations are considered to be funded in accordance with NRC regulations. If the projected costs do not sufficiently reflect the actual costs required to decommission these nuclear power plants, or if funding is otherwise inadequate, or if the formula, formula inputs, or site-specific estimate is changed to require increased funding, additional resources or commitments would be required. Furthermore, depending upon the level of funding available in the trust funds, the NRC may not permit the trust funds to be used to pay for related costs such as the management of spent nuclear fuel that are not included in the NRC’s formula. The NRC may also require a plan for the provision of separate funding for spent fuel management costs.

Further, federal or state regulatory changes, including mandated increases in decommissioning funding or changes in the methods or standards for decommissioning operations, may also increase the funding requirements of, or accelerate the timing for funding of, the obligations related to the decommissioning of the nuclear generating plant owned by certain of the Utility operating companies or System Energy or may restrict the decommissioning-related costs that can be paid from the decommissioning trusts. Such changes also could result in the need for additional contributions to decommissioning trusts, or the posting of parent guarantees, letters of credit, or other surety mechanisms. As a result, under any of these circumstances, the results of operations, liquidity, and financial condition of Entergy, certain of the Utility operating companies, or System Energy could be materially affected.

An early plant shutdown (either generally or relative to current expectations), poor investment results, or higher than anticipated decommissioning costs (including as a result of changing regulatory requirements) could cause trust fund assets to be insufficient to meet the decommissioning obligations, with the result that certain of the Utility operating companies or System Energy may be required to provide significant additional funds or credit support to satisfy regulatory requirements for decommissioning, which, with respect to these Utility operating companies or System Energy, may not be recoverable from customers in a timely fashion or at all.

For further information regarding nuclear decommissioning costs, see the “Critical Accounting Estimates - Nuclear Decommissioning Costs” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy, and Notes 9 and 16 to the financial statements.

New or existing safety concerns regarding operating nuclear power plants and nuclear fuel could lead to restrictions upon the operation and decommissioning of Entergy’s nuclear power plants.

New and existing concerns are being expressed in public forums about the safety of nuclear generating units and nuclear fuel. These concerns have led to, and may continue to lead to, various proposals to federal regulators and governing bodies in some localities where Entergy’s subsidiaries own nuclear generating units for legislative and regulatory changes that might lead to the shutdown of nuclear units, additional requirements or restrictions related to spent nuclear fuel on-site storage and eventual disposal, or other adverse effects on owning, operating, and decommissioning nuclear generating units. Entergy vigorously responds to these concerns and proposals. If any of the existing proposals, or any proposals that may arise in the future with respect to legislative and regulatory changes, become effective, they could have a material effect on Entergy’s results of operations and financial condition.

Business Risks

(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

Entergy and its Registrant Subsidiaries depend on access to the capital markets and, at times, may face potential liquidity constraints, which could make it more difficult to handle future contingencies such as natural disasters or substantial increases in gas and fuel prices. Disruptions in the capital and credit markets may adversely affect Entergy’s and its subsidiaries’ ability to meet liquidity needs, or to access capital to operate and grow their businesses, and the cost of capital.

Entergy’s business is capital intensive and dependent upon its ability to access capital at reasonable rates and other terms. At times there are also spikes in the price for natural gas and other commodities that increase the liquidity requirements of the Utility operating companies. In addition, Entergy’s and the Registrant Subsidiaries’ liquidity needs could significantly increase in the event of a hurricane or other weather-related or unforeseen disaster similar to that experienced in Entergy’s service area with Hurricane Katrina and Hurricane Rita in 2005, Hurricane Gustav and Hurricane Ike in 2008, Hurricane Isaac in 2012, Hurricane Laura, Hurricane Delta, and Hurricane Zeta in 2020, and Winter Storm Uri and Hurricane Ida in 2021. In recent years, the capital intensive nature of Entergy’s business has increased even further as a result of the capital expenditures required to build the infrastructure to serve multiple large-scale data centers in its utility service area. The occurrence of one or more adverse events or contingencies, including an adverse decision or a delay in regulatory recovery of fuel or purchased power costs or storm restoration costs, an acceleration of payments or decreased credit lines, less cash flow from operations than expected, changes in regulation, governmental policy (including tax and trade policy, such as increased tariffs, and new laws or regulations relating to data centers or other large loads) or governmental programs (including tax incentives or tax credits, loans, grants, guarantees, and other subsidies), or other unknown or unforeseen events, could cause the financing needs of Entergy and its subsidiaries to increase. In addition, accessing the debt capital markets more frequently in these situations may result in an increase in leverage. Material leverage increases could negatively affect the credit ratings of Entergy, the Utility operating companies, and System Energy, which in turn could negatively affect access to the capital markets.

The inability to raise capital on favorable terms, particularly during times of high interest rates and inflation, and uncertainty or reduced liquidity in the capital markets, could negatively affect Entergy and its subsidiaries’ ability to maintain and to expand their businesses. Access to capital markets could be restricted and/or borrowing costs could be increased due to certain sources of debt and equity capital avoiding participating in offerings to fund fossil fuel projects or companies that are impacted by extreme weather events or other catastrophes, that rely on fossil fuels, or that are impacted by risks related to climate change, or such sources of capital de-emphasizing their interest in investing in clean or renewable energy projects. Additionally, shifts in governmental policy surrounding tax incentives or tax credits, loans, grants, guarantees, and other subsidies (including as a result of the One Big Beautiful Bill Act of 2025) may increase borrowing costs. Factors beyond Entergy’s control may create uncertainty that could increase its cost of capital or impair its ability to access the capital markets, including the ability to draw on its bank credit facilities. These factors include depressed economic conditions, a recession, the economic impacts of another full or partial government shutdown, increasing interest rates, inflation, sanctions, trade restrictions, political instability, war, terrorism, and extreme volatility in the debt, equity, or credit markets. Entergy and its subsidiaries are unable to predict the degree of success they will have in renewing or replacing their credit facilities as they come up for renewal. Moreover, the size, terms, and covenants of any new credit facilities may not be comparable to, and may be more restrictive than, existing facilities. If Entergy and its subsidiaries are unable to access the credit and capital markets on terms that are reasonable, they may have to delay raising capital, issue shorter-term securities, and/or bear an unfavorable cost of capital, which, in turn, could impact their ability to grow their businesses, decrease earnings, significantly reduce financial flexibility, and/or limit Entergy Corporation’s ability to sustain its current common stock dividend level.

A downgrade in Entergy’s or its Registrant Subsidiaries’ credit ratings could negatively affect Entergy’s and its Registrant Subsidiaries’ ability to access capital or the cost of such capital and/or could require Entergy or its subsidiaries to post collateral, accelerate certain payments, or repay certain indebtedness.

There are a number of factors that rating agencies evaluate to arrive at credit ratings for each of Entergy and the Registrant Subsidiaries, including each Registrant Subsidiary’s regulatory framework, ability to recover costs and earn returns, storm or climate risk exposure, diversification, and financial strength and liquidity. If one or more rating agencies downgrade Entergy’s or any of the Registrant Subsidiaries’ ratings, particularly below investment grade, borrowing costs would increase, the potential pool of investors and funding sources would likely decrease, and cash or letter of credit collateral demands may be triggered by the terms of a number of commodity contracts, leases, and other agreements.

Most of Entergy’s and its subsidiaries’ suppliers and counterparties require sufficient creditworthiness to enter into transactions. If Entergy’s or the Registrant Subsidiaries’ ratings decline, particularly below investment grade, or if certain counterparties believe Entergy or the Utility operating companies are losing creditworthiness and demand adequate assurance under fuel, gas, and purchased power contracts, the counterparties may require posting of collateral in cash or letters of credit, prepayment for fuel, gas or purchased power or accelerated payment, or counterparties may decline business with Entergy or its subsidiaries.

Entergy’s and the Utility operating companies’ business, results of operations, and financial condition could be adversely affected by events beyond their control, such as public health crises, natural disasters, wildfires, geopolitical tensions, or other catastrophic events.

Entergy and the Utility operating companies could be adversely affected by various events beyond their control, including, without limitation, public health crises, natural disasters, wildfires, geopolitical tensions and other political instability, or other catastrophic events. Any of the foregoing, whether occurring locally, nationally, or globally, and the resulting effects thereof could lead to disruption of the general economy, impacts on the customers of the Utility operating companies, and disruption of the operations of Entergy’s subsidiaries, due to, among other things:

• supply chain, vendor, and contractor disruptions or other impacts, including those relative to any trade or tariff issues, as well as any shortages or delays in the availability of key components, parts, and supplies such as electronic components, steel, aluminum, and solar panels;
• delays in completion of capital or other construction projects, maintenance, and other operations activities, including prolonged or delayed refueling and maintenance outages;
• adverse impacts on liquidity and cash flows, including through declining sales, reduced revenues, delays in receipts of customer payments, increased bad debt expense, or customers or other counterparties failing to satisfy their obligations;
• delays in regulatory proceedings;
• regulatory outcomes that require the Utility operating companies to postpone planned investments and otherwise reduce costs due to, for example, the impact of a public health crises or such other catastrophic events on their customers;
• workforce availability challenges, including, for example, from infections, health, or safety issues resulting from a public health crisis;
• increased storm recovery costs;
• increased cybersecurity risks as a result of many employees telecommuting and working partially remotely or geopolitical risks;
• volatility in the credit or capital markets (and any related increased cost of capital or any inability to access the capital markets or draw on available credit facilities on favorable terms), which could in turn, cause a decrease in the value of its defined benefit pension and welfare benefit plan trusts or decommissioning trust funds;
• litigation;
• adverse impacts on Entergy’s credit metrics or ratings;
• governmental mandates in response to any such event; or
• other adverse impacts on their ability to execute on business strategies and initiatives.

To the extent any of these events occur, the business, results of operations, and financial condition of Entergy and the Utility operating companies could be adversely affected.

The reputation of Entergy or its Registrant Subsidiaries may be materially adversely affected by negative publicity or the inability to meet its stated goals or commitments, among other potential causes.

As with any company, Entergy’s and its Registrant Subsidiaries’ reputations are an important element of their ability to effectively conduct their businesses. Entergy’s and its Registrant Subsidiaries’ reputations could be harmed by a variety of factors, including: failure of a generating asset or supporting infrastructure; failure to restore power after a hurricane or other severe weather event or catastrophe in a manner perceived as timely by regulators or customers; the incurrence of storm restoration costs perceived as excessive by regulators or customers; failure to effectively manage land and other natural resources; failure to obtain land and secure permits for infrastructure investments; failure to execute on and/or obtain regulatory approvals for generation, transmission, or other facilities; real or perceived violations of environmental regulations, including those related to climate change; real or perceived issues surrounding the safety or environmental concerns regarding carbon capture and storage; real or perceived issues concerning the environmental impact of new generation, new large load customers, and potential rate increases resulting from investments relating to serving these customers; real or perceived issues with Entergy’s safety culture; challenges or negative reaction to Entergy’s employee inclusion and belonging efforts, work culture and workplace environment; challenges or negative reaction to Entergy’s climate goals or aspirations; inability to meet their climate goals or aspirations, including as a result of increased sales growth, or to achieve their human capital strategies, or failure to demonstrate meaningful progress toward such goals or strategies; deterioration in relations with bargaining employees and labor unions representing them; inability to effectively prepare for major storms and other weather events, including accelerated resilience planning and projects and challenges in execution thereof, including obtaining necessary regulatory approvals for scope and timing of such plans and projects; inability to keep their electricity rates stable; inability to provide quality customer service, including timely and accurate billing; involvement in a class-action or other high-profile lawsuit; significant delays in, or termination of, construction projects, including as a result of or in connection with changes in regulation or governmental policy (such as tax and trade policy, including increased tariffs and supply chain challenges) or governmental programs (such as tax incentives or tax credits, loans, grants, guarantees, and other subsidies); occurrence of or responses to cyber attacks, data breaches or physical- or cyber- security vulnerabilities; acts or omissions of Entergy management or acts or omissions of a contractor or other third party working with or for Entergy or its Registrant Subsidiaries, which actually or perceivably reflect negatively on Entergy or its Registrant Subsidiaries; measures taken to offset reductions in demand or to supply rising demand; a significant dispute with one of Entergy’s or its Registrant Subsidiaries’ customers or other stakeholders; or negative political and public sentiment resulting in a significant amount of adverse press coverage and other adverse statements affecting Entergy or its Registrant Subsidiaries.

Addressing any adverse publicity or regulatory scrutiny is time consuming and expensive and, regardless of the factual basis for the assertions being made (or lack thereof), can have a negative impact on the reputations of Entergy or its Registrant Subsidiaries, on the morale and performance of their employees, and on their relationships with their respective regulators, customers, investors, and commercial counterparties. Adverse publicity or regulatory scrutiny may also have a negative impact on Entergy or its Registrant Subsidiaries’ ability to take timely advantage of various business or market opportunities.

Deterioration in Entergy’s or its Registrant Subsidiaries’ reputations may harm Entergy’s or its Registrant Subsidiaries’ relationships with their customers, regulators, and other stakeholders, may increase their cost of doing business, may interfere with their ability to attract and retain a qualified workforce from a wide variety of backgrounds, experiences, and perspectives, may impact Entergy’s or its Registrant Subsidiaries’ ability to raise debt capital, and may potentially lead to the enactment of new laws and regulations, or the modification of existing laws and regulations, that negatively affect the way Entergy or its Registrant Subsidiaries conduct their business, or may have a material adverse effect on their financial condition and results of operations.

U.S. tax legislation may materially adversely affect Entergy’s financial condition, results of operations, and cash flows.

The Tax Cuts and Jobs Act of 2017 significantly changed the U.S. Internal Revenue Code, including taxation of U.S. corporations, by, among other things, reducing the federal corporate income tax rate, limiting interest deductions, and altering the expensing of capital expenditures. The Inflation Reduction Act of 2022 further significantly changed the U.S. Internal Revenue Code by, among other things, enacting a new corporate alternative minimum tax and expanding federal tax credits for clean energy production. The One Big Beautiful Bill Act of 2025 made additional changes to the U.S. Internal Revenue Code including, among other things: (i) the further altering of interest deductibility and the expensing of capital expenditures, (ii) the adoption of new “foreign entity of concern” rules intended to reduce influence of certain “prohibited foreign entities” that could limit the use of certain federal tax credits for clean energy investment and production, and (iii) the further limiting of federal tax credits available for wind and solar facilities.

The interpretive guidance issued by the IRS and state tax authorities may be inconsistent with Entergy’s own expectation or interpretation and the legislation could be subject to amendments, which could lessen or increase certain impacts of the legislation. Further, changes in tax legislation or guidance, or uncertainties regarding the repeal, continuation, or interpretation of such tax legislation or guidance, could impact interpretation of and negotiations around certain contractual arrangements with counterparties, which could result in unfavorable changes to such arrangements or delays. In addition, the retail regulatory treatment of the expanded tax credits and corporate alternative minimum tax included in the Inflation Reduction Act of 2022, the limitation of the use of certain tax credits in the One Big Beautiful Bill Act of 2025, or any other changes to or additional scaling back of such tax credits, could materially impact Entergy’s future cash flows, and this legislation and pending interpretive guidance could result in unintended consequences not yet identified that could have a material adverse impact on Entergy’s financial results and future cash flows.

Based on current IRS guidance and current internal forecasts, Entergy and the Registrant Subsidiaries may become subject to the corporate alternative minimum tax included in the Inflation Reduction Act of 2022 beginning in the next one to three years.

The tax rate decrease included in the Tax Cuts and Jobs Act required Entergy to record a regulatory liability for income taxes payable to customers. Such regulatory liability for income taxes is described in Note 3 to the financial statements.

See Note 3 to the financial statements for discussion of the effects of the Tax Cuts and Jobs Act on 2025, 2024, and 2023 results of operations and financial condition, the provisions of the Tax Cuts and Jobs Act, and Note 2 to the financial statements for discussion of the regulatory proceedings that have considered the effects of the Tax Cuts and Jobs Act. For further discussion of the effects of the Inflation Reduction Act of 2022, and the One Big Beautiful Bill Act of 2025, see the “Income Tax Legislation and Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 3 to the financial statements.

Changes in taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact Entergy’s and the Registrant Subsidiaries’ results of operations, financial condition, and liquidity.

Entergy and its subsidiaries make judgments regarding the potential tax effects of various transactions and results of operations to estimate their obligations to taxing authorities, which judgment may prove to be incorrect or may be disputed by regulators or taxing authorities. These tax obligations include income, franchise, real estate, sales and use, and employment-related taxes. These judgments include provisions for potential adverse outcomes regarding tax positions that have been taken. Entergy and its subsidiaries also estimate their ability to utilize tax benefits, including those in the form of carryforwards for which the benefits have already been reflected in the financial statements. Changes in federal, state, or local tax laws or interpretive guidance relating thereto, adverse tax audit results or adverse tax rulings on positions taken by Entergy and its subsidiaries could negatively affect Entergy’s and the Registrant Subsidiaries’ results of operations, financial condition, and liquidity. The intended and unintended consequences of recently enacted legislation could have a material adverse impact on Entergy’s financial results and future cash flows. For further information regarding Entergy’s income taxes, see the “Income Tax Legislation and Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 3 to the financial statements.

Entergy and its subsidiaries’ ability to successfully execute on their business strategies, including their ability to execute on their growth strategies and to complete strategic transactions, is subject to significant risks, and, as a result, they may be unable to achieve some or all of the anticipated results of such strategies.

Entergy and its subsidiaries’ future prospects and results of operations significantly depend on their ability to successfully implement their business strategies, including executing on their growth strategy and achieving Entergy’s climate goals and aspirations, which are subject to business, regulatory, economic, shareholder activism and other risks and uncertainties, many of which are beyond their control. As a result, Entergy and its subsidiaries may be unable to fully achieve the anticipated results of such strategies.

Entergy and its subsidiaries anticipate a high level of load growth in their industrial and large commercial customer segments, including from large-scale data centers owned by a small number of large customers. Entergy and its subsidiaries may be unsuccessful in capturing such opportunities or the opportunities to serve these new large customers may not materialize to the degree, extent, or duration currently expected. Entergy and its subsidiaries also may not have access to the capital needed to finance the incremental growth on terms and conditions satisfactory to Entergy or its subsidiaries and consistent with the maintenance of satisfactory credit ratings. Entergy and its subsidiaries may fail to execute within currently expected time frames or within currently expected costs, due to a number of factors, including failure to obtain, or any delay in obtaining, regulatory approval, shortages of qualified labor, supply chain constraints, other cost pressures, or inadequate project management and execution. Entergy and its subsidiaries may not be able to adequately protect contractually against the risks inherent in relying on such rapid growth within a small number of large customers concentrated in a single industry and/or recover any amounts outside those included in the contractual arrangements. Entergy expects that these customers will represent a high percentage of total sales, revenues, and cash flow with respect to the applicable Utility operating company for the foreseeable future. This creates business industry and credit concentration risks which Entergy and its subsidiaries may not be able to fully mitigate.

Additionally, Entergy and its subsidiaries have pursued and may continue to pursue strategic transactions including merger, acquisition, divestiture, joint venture, restructuring, or other strategic transactions. Entergy’s utility business plan over the next several years includes the construction and/or purchase of several natural gas plants and solar facilities. These or other transactions and plans are or may become subject to regulatory approval and other material conditions or contingencies, including increased costs or delays resulting from supply chain disruptions, import tariffs, and other issues. The failure to complete these transactions or plans or any future strategic transaction successfully or on a timely basis could have an adverse effect on Entergy’s or its subsidiaries’ financial condition or results of operations and the market’s perception of Entergy’s ability to execute its strategy. Further, these transactions, and any completed or future strategic transactions, involve substantial risks, including the following:

• acquired businesses or assets may not produce revenues, earnings, or cash flow at anticipated levels;
• acquired businesses or assets could have environmental, permitting, or other problems for which contractual protections prove inadequate;
• Entergy and/or its subsidiaries may assume liabilities that were not disclosed to them, that exceed their estimates, or for which their rights to indemnification from the seller are limited;
• Entergy may experience issues integrating businesses into its internal controls over financial reporting;
• the acquisition or disposition of a business could divert management’s attention from other business concerns;
• Entergy and/or its subsidiaries may be unable to obtain the necessary regulatory or governmental approvals to close a transaction, such approvals may be granted subject to terms that are unacceptable, or Entergy or its subsidiaries otherwise may be unable to achieve anticipated regulatory treatment of any such transaction or acquired business or assets;
• shifting governmental policies may impact government support for capital projects, including tax incentives or tax credits, grants, guarantees, or other subsidies; and
• Entergy or its subsidiaries otherwise may be unable to achieve the full strategic and financial benefits that they anticipate from the transaction, or such benefits may be delayed or may not occur at all.

Entergy and its subsidiaries may not be successful in managing these or any other significant risks that they may encounter in acquiring or divesting a business, or engaging in other strategic transactions, which could have a material effect on their business, financial condition, or results of operations.

The success of certain Utility operating companies’ investments in new generation and transmission assets to support large-scale data centers depends on a limited number of such customers, the continued demand for electricity to power data centers, and the successful completion of the associated generation and transmission projects. Any reduction in the demand for electricity to power data centers or delays or unexpected costs associated with such projects may harm the growth prospects, future operating results, and financial condition of Entergy and these Utility operating companies.

Subject to any pending regulatory approvals, certain Utility operating companies are making or are planning to make significant infrastructure investments in new solar projects, natural gas power plants, and other transmission and generation assets to power new large-scale data centers. These infrastructure investments are being made primarily in connection with electric service agreements with a small number of customers representing significant new load to provide power for new data centers being constructed to support artificial intelligence and other technology capabilities. The Utility operating companies continue to explore similar opportunities and have engaged, and may continue to engage, in additional similar transactions in the future.

This small number of data center customers representing a large portion of the anticipated business of certain of the Utility operating companies exposes these Utility operating companies to several risks, the impact of which is greater due to the common risks facing those customers in the businesses supported by the data centers. The recent dramatic expansion in anticipated demand from data center customers is largely based on emerging technologies, including artificial intelligence and machine learning. These technologies and their related business applications have developed rapidly in recent years and continue to evolve rapidly. Entergy cannot predict the rate at which or the extent to which these emerging technologies will be broadly adopted and successful as business models. Changes in industry practice or advances in these technologies could reduce the demand for electricity to power data centers, including from these customers. Some data center owners and operators are developing their own energy sources to power their data centers, and it is possible that the Utility operating companies’ customers could choose to develop their own energy sources in the future. Additionally, data centers could be subject to future laws and regulations relating to, among other things, energy efficiency standards and energy use and source of power restrictions. These customers may also experience business downturns, which may cause the loss of these customers or a portion of their load requirements or may weaken their financial condition or ability to satisfy contractual obligations. Similarly, these customers may reduce their investment in these new technologies or abandon them entirely. It is not possible for Entergy to predict the future level of demand for electricity from such customers.

Any of these situations may result in lower than anticipated revenue or the early termination or non-renewal of these customers’ electric service agreements or renewal on terms less favorable to the associated Utility operating company. Our electric service agreements with these customers include provisions for early termination payments in certain circumstances, but they do not fully protect against these risks. The Utility operating companies expect to incur a significant level of debt to finance the infrastructure investments associated with these customers’ projects. Although a significant portion of the costs of the infrastructure investments are expected to be recovered through payments under contractual agreements with the applicable customer, there is a risk that the Utility operating companies may not fully recover the costs of the infrastructure constructed to serve these customers despite contractual protections. Once this infrastructure becomes operational, Entergy expects that these customers will represent a high percentage of total sales, revenues, and cash flow for the associated Utility operating company in accordance with the terms of their electric service agreements. In the event a customer terminates or does not renew its electric service agreement, the Utility operating companies may not be able to enter into new services agreements, timely or at all, with one or more comparable revenue-generating customers, and the terms of any new agreements may be less favorable to the Utility operating companies. While the assets constructed to serve these customers may otherwise be useful in the Utility operating companies’ business, there is a risk that the Utility operating companies may not be able to fully recover their investment in or a return on those assets, either through retail or wholesale rates or meet the debt obligations incurred in connection with these assets. The small number of such customers and scale of the investment required to support those customers heightens this risk.

The success of these Utility operating companies’ investments in new generation and transmission assets to support large-scale data centers depends on the successful completion of large capital projects to provide electricity to these data centers. As discussed elsewhere in this report, the ability to complete large capital projects is dependent upon several factors, including, among others, the ability to obtain financing of such large-scale projects on satisfactory terms and conditions, secure regulatory permits, secure sufficient land for the siting of solar panels and power generation facilities, obtain and maintain MISO interconnection queue positions and otherwise obtain necessary interconnection or transmission service in MISO, and hire qualified labor, as well as levels of public support or opposition to these projects, including, but not limited to opposition arising out of concerns over environmental impacts or the potential for rate increases for all customers, and suppliers’ and contractors’ performance and ability to fulfill their obligations under contracts. Successful completion of these projects may be further influenced by changes in law or regulation, such as environmental compliance requirements or MISO tariff rules and processes; trade-related government actions, such as direct and indirect trade and tariff actions, including those associated with imported solar panels; as well as supply chain delays or disruptions, workforce challenges, and other events beyond the control of these Utility operating companies. The occurrence of any of these events may materially affect the schedule, cost, and performance of these projects. If these projects are significantly delayed or become subject to cost overruns or cancellation, Entergy and the Utility operating companies could incur additional costs and termination payments or face increased risk of potential write-offs of their investments in these projects or incur other costs or risks, including MISO market risks or charges. For additional information concerning these Utility operating companies’ investments in new generation to support large-scale data centers, see “Utility - Property and Other Generation Resources - Provision of Service to Large-Scale Data Center Customers” in Part I, Item 1.

The business, results of operations and financial condition of Entergy and these Utility operating companies could be materially adversely affected as a result of any or all of these factors.

The completion of capital projects, including the construction of power generation facilities, and other capital improvements, involves substantial risks. Should such efforts be unsuccessful, the financial condition, results of operations, or liquidity of Entergy and the Utility operating companies could be materially affected.

Entergy’s and the Utility operating companies’ ability to complete capital projects, including the construction of power generation facilities, or make other capital improvements, such as transmission and distribution infrastructure replacements or upgrades, in a timely and cost-effective manner and within budget is contingent upon many variables and subject to substantial risks. These variables include, but are not limited to, availability of project management expertise, availability of qualified, skilled labor, escalating costs for materials, labor, and environmental compliance, reliance on suppliers for timely and satisfactory performance, delays and cost increases, and supply chains and material constraints, including those that may result from major storm events, both within and outside of Entergy’s service area. Certain events may occur that may materially affect the schedule, cost, and performance of these projects. These events may relate to the actual siting and construction process, such as facing public opposition; delays in obtaining permits; challenges in securing sufficient land for the siting of solar panels, power generation facilities, and large transmission projects; shortages in materials and qualified labor; suppliers and contractors not performing as expected or required under their contracts and/or experiencing financial problems that inhibit their ability to fulfill their obligations under contracts; supply chain delays or disruptions; and changes in the scope and timing of projects. Various economic and financial factors may include early stage cost estimates from contractors that are lower than final costs; the inability to raise capital on favorable terms; changes in commodity prices affecting revenue, fuel costs, or materials costs; and downward changes in the economy. Regulatory and legal issues include items such as changes in law or regulation, including environmental compliance requirements and restrictive laws, regulations or policies relating to data centers or facilities that power data centers; and further direct and indirect trade and tariff issues, including those associated with imported solar panels or other goods or products required to complete major capital projects. Additionally, other events beyond the control of the Utility operating companies may occur that may materially affect the schedule, cost, and performance of these projects.

If these projects or other capital improvements are significantly delayed or become subject to cost overruns or cancellation, Entergy and the Utility operating companies could incur additional costs and termination payments or face increased risk of potential write-off of the investment in the project. In addition, the Utility operating companies could be exposed to higher costs and market volatility, which could affect cash flow and cost recovery, should their respective regulators decline to approve the construction of the project or new generation needed to meet the reliability needs of customers at the lowest reasonable cost.

The above risks are heightened by the number and size of the capital projects that Entergy and the Utility operating companies currently plan to undertake to serve load growth driven primarily by large-scale data centers.

For further information regarding capital expenditure plans and other uses of capital in connection with capital projects, including the potential construction and/or purchase of additional generation supply sources within the Utility operating companies’ service areas, see the “Capital Expenditure Plans and Other Uses of Capital” section of Management’s Financial Discussion and Analysis for Entergy and each of the Registrant Subsidiaries.

Failure to attract, retain and manage an appropriately qualified workforce could negatively affect Entergy or its subsidiaries’ results of operations.

Entergy relies on a large and changing workforce, including employees, contractors, and temporary staffing, to provide the services necessary to operate its business and execute on its business plan and growth strategy. Certain factors, such as an aging workforce, mismatching of skill sets for current and future needs, failing to appropriately anticipate future workforce needs, workforce impacts from public health concerns, challenges competing with other employers offering fully remote or more flexible work options, increased demand for skilled labor and challenging labor markets, particularly in rural areas where certain large-scale data centers and other large customers plan to be located, rising salary and other labor costs, unavailability of contract resources, and labor disputes, work disruptions, and increased labor organizing activity may lead to operating challenges and increased costs. The challenges include inability to attract or retain talent, lack of resources, loss of knowledge base, and the time required for skill development. Costs to attract and retain employees and contract labor, including costs for contractors to replace employees, productivity costs, and safety costs, may increase. Failure to hire and adequately train replacement employees, or the future availability and cost of contract labor, may adversely affect the ability to manage and operate the business and to execute on Entergy’s business plan and growth strategy, especially considering the specialized workforce needs associated with nuclear generation facilities and new skills required to develop and operate a modernized, technology-enabled, and lower carbon power grid. If Entergy and its subsidiaries are unable to successfully attract, retain, and manage an appropriately qualified workforce and/or retain sufficient skilled contract labor resources to supplement the workforce, their results of operations, financial position, and cash flows could be negatively affected.

Entergy and its subsidiaries, including the Utility operating companies and System Energy, may incur substantial costs to fulfill their obligations related to environmental and other matters.

The businesses in which Entergy’s subsidiaries, including the Utility operating companies and System Energy, operate are subject to extensive existing environmental regulation by local, state, and federal authorities. These laws and regulations affect the manner in which the Utility operating companies and System Energy conduct their operations and make capital expenditures. These laws and regulations also affect how Entergy’s subsidiaries, including the Utility operating companies and System Energy, manage air emissions, discharges to water, wetlands impacts, solid and hazardous waste storage and disposal, cooling and service water intake, the protection of threatened and endangered species, certain migratory birds and eagles, hazardous materials transportation, and similar matters. Federal, state, and local authorities continually revise these laws and regulations, and the laws and regulations are subject to judicial interpretation and to the implementing agencies’ permitting and enforcement decisions. Furthermore, in response to increased economic and industrial growth, federal, state, and local governments may adopt or change laws, regulations, or ordinances addressing the real or perceived environmental or other impacts. Developing and implementing plans for facility compliance with these requirements can lead to capital, personnel, and operation and maintenance expenditures. Violations of these requirements can subject the Utility operating companies and System Energy to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, remediation and clean-up costs, civil penalties, and exposure to third parties’ claims for alleged health or property damages or for violations of applicable permits or standards. In addition, Entergy and its subsidiaries, including the Utility operating companies and System Energy, are subject to potential liability under these laws for the costs of remediation of environmental contamination of property now or formerly owned or operated by the Utility operating companies and System Energy and of property potentially contaminated by hazardous substances they generate. The Utility operating companies currently are involved in proceedings relating to sites where hazardous substances have been released and may be subject to additional proceedings in the future. Entergy’s subsidiaries, including the Utility operating companies and System Energy, have incurred and expect to incur significant costs related to environmental compliance. To the extent that any such changes in law or regulation impact data centers or facilities that power data centers, these risks may be heightened by Entergy’s and the Utility operating companies’ increasing reliance on large-scale data center customers for revenue and load growth.

Emissions of nitrogen and sulfur oxides, mercury, particulates, greenhouse gases, and other regulated emissions from generating plants potentially are subject to increased regulation, controls, and mitigation expenses. The capital plan of certain Utility operating companies includes significant investments in generation facilities to serve the rapid growth in load demand from large customers and large-scale data centers. These generating facilities will produce regulated emissions, which amplifies these risks for Entergy and those Utility operating companies. In addition, existing environmental regulations and programs promulgated by the EPA often are challenged legally, or are revised or withdrawn by the EPA, sometimes resulting in large-scale changes to anticipated regulatory regimes and the resulting need to shift course, both operationally and economically, depending on the nature of the changes. Risks relating to global climate change, initiatives to regulate, or otherwise compel reductions of greenhouse gas emissions, and water availability issues are discussed below.

Entergy and its subsidiaries may not be able to obtain or maintain all required environmental regulatory approvals. If there is a delay in obtaining any required environmental regulatory approvals, or if Entergy and its subsidiaries fail to obtain, maintain, or comply with any such approval, the operation of its facilities could be stopped or become subject to additional costs. For further information regarding environmental regulation and environmental matters, including Entergy’s response to climate change, see the “Regulation of Entergy’s Business – Environmental Regulation” section of Part I, Item 1.

Environmental and regulatory obligations intended to combat the effects of climate change, including by compelling greenhouse gas emission reductions or reporting, increasing clean or renewable energy requirements, or placing a price on greenhouse gas emissions, or efforts to achieve climate goals could materially affect the financial condition, results of operations, and liquidity of Entergy and Entergy’s subsidiaries, including the Utility operating companies and System Energy.

Federal, state, and local authorities periodically propose and enact laws and regulations intended to address known or suspected causes of climate change. A particular focus at the federal level is the regulation of CO2 emissions from new, existing, and significantly modified stationary emission sources, including electric generating units. Such regulations continue to evolve. Various states and regions of the U.S. have taken action to establish greenhouse gas limitations and trading programs. For example, in 2021, the City Council of New Orleans promulgated a renewable and clean portfolio standard that sets a goal of net-zero emissions by 2040 and absolute zero emissions by 2050. The impact that continued changes in the governmental response to climate change risk and any judicial interpretation thereof will have on existing and pending environmental laws and regulations related to greenhouse gas emissions currently is unclear.

Developing and implementing plans for compliance with greenhouse gas emissions reduction or reporting or clean/renewable energy requirements, or for achieving a climate goal can lead to additional capital, personnel, and operation and maintenance expenditures and could significantly affect the economic position of existing facilities and proposed projects. The operations of low or non-emitting generating units (such as nuclear units and solar facilities) at lower than expected capacity factors could require increased generation from higher emitting units, thus increasing Entergy’s greenhouse gas emission rate. Similarly, increased load growth and the natural gas generation required to meet that increased demand is expected to result in an increase in Entergy’s absolute greenhouse gas emissions. Moreover, long-term planning to meet environmental requirements can be negatively impacted and costs may increase to the extent laws and regulations change prior to full implementation. These requirements could, in turn, lead to changes in the planning or operations of balancing authorities or organized markets in areas where Entergy’s subsidiaries, including the Utility operating companies or System Energy, do business. Violations of such requirements may subject the Utility operating companies to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, civil penalties, and exposure to third parties’ claims for alleged health or property damages or for violations of applicable permits or standards. Further, real or perceived violations of environmental regulations, including those related to climate change, or challenges meeting any climate goals Entergy might set or be required to achieve, could negatively impact Entergy’s reputation or inhibit Entergy’s ability to pursue its long-term decarbonization objectives. To the extent Entergy believes any of these costs are recoverable in rates, however, additional material rate increases for customers could be resisted by Entergy’s regulators and, in extreme cases, Entergy’s regulators might attempt to deny or defer timely recovery of these costs.

Recent or future changes in regulation or policies governing the reporting or emission of, or government programs relating to, CO2 and other greenhouse gases or mix of generation sources could (i) result in significant additional costs to the Utility operating companies, their suppliers, or customers; (ii) make some of Entergy’s electric generating units uneconomical to maintain or operate; (iii) result in the early retirement of generation facilities and stranded costs if the Utility operating companies are unable to fully recover the costs and investment in generation; (iv) increase the difficulty that Entergy and its Utility operating companies have with obtaining or maintaining required environmental regulatory approvals; and (v) cause the financing needs of Entergy and its subsidiaries to increase should such changes result in a repeal or limitation on government tax credits, loans, grants, guarantees, or other subsidies incentivizing the development or utilization of alternative sources of generation, each of which could materially affect the financial condition, results of operations, and liquidity of Entergy and its subsidiaries. In addition, lawsuits have occurred or are reasonably expected against emitters of greenhouse gases alleging that these companies are liable for personal injuries and property damage caused by climate change. These lawsuits may seek injunctive relief, monetary compensation, and punitive damages. The capital plan of certain Utility operating companies includes significant investments in generation facilities to serve the rapid growth in load demand from large customers and large-scale data centers, which facilities will emit CO2 or other greenhouse gases and amplify these risks for Entergy and those Utility operating companies.

The physical effects of climate change could materially affect the financial condition, results of operations, and liquidity of Entergy and its subsidiaries.

Potential physical risks from climate change include an increase in sea level, wind and storm surge damages, more frequent or intense hurricanes and wildfires, wetland and barrier island erosion, flooding and changes in weather conditions (such as increases in precipitation, drought, or changes in average temperatures), and potential increased impacts of extreme weather conditions or storms. Entergy’s subsidiaries own assets in, and serve, communities that are at risk from sea level rise, changes in weather conditions, storms, floods, and loss of the protection offered by coastal wetlands. A significant portion of the nation’s oil and gas infrastructure is located in these areas and susceptible to storm damage that could be aggravated by the physical impacts of climate change, which could give rise to fuel supply interruptions and price spikes. Entergy and its subsidiaries also face the risk that climate change could impact the availability and quality of water supplies necessary for operations.

Due in part to the increase over the past two decades in frequency and intensity of major storm activity along the Gulf Coast, Entergy has and continues to pursue and execute on plans to accelerate investments that would enhance the resilience of the electric systems of the Utility operating companies to enable them to better withstand major storms or other significant events, to mitigate the cost of restoration of the electric system after major storms or other significant events, to enable more rapid restoration of electricity after major storm or other significant adverse events, and to deliver electricity to critical customers more immediately after such events. These plans are generally subject to approval by the Utility operating companies’ retail regulators and may not be approved in full or at all. Certain accelerated resilience plans of the Utility operating companies have received regulatory approval for a limited scope and duration, generally at levels less than those proposed to the regulators; however, the Utility operating companies continue to work with their regulators to establish the appropriate scope and timing of resilience investment balanced against other customer needs. The Utility operating companies may not be able to successfully execute such plans and projects in the time and manner planned and there are risks regarding the ability to demonstrate the efficacy of the accelerated resilience investments in mitigating storm impacts, as well as in seeking and obtaining regulatory approval for additional accelerated resilience plans and projects that may be necessary. The need for this investment and these expenditures could give rise to execution, liquidity, capital or other financing-related risks as well as result in upward pressure on the retail rates of the Utility operating companies, which, particularly when combined with upward pressure resulting from the recovery of the costs of recent and future storms, may result in adverse actions by the Utility operating companies’ retail regulators or effectively limit the ability to make other planned capital or other investments.

Additionally, prolonged drought conditions and shifting weather patterns resulting from climate change as well as, among other things, buildup of dry vegetation in areas severely impacted by drought may increase the risk of severe wildfire events within the Utility operating companies’ service areas. Catastrophic wildfires occurring in the Utility operating companies’ service areas could give rise to large damage claims against Entergy or its subsidiaries for fire-related losses alleged to be the result of utility practices and/or the failure of electric and other utility equipment and could also cause Entergy or its subsidiaries to suffer reputational harm or face a more challenging operating, political and regulatory environment.

These and other physical changes could result in, among other things, changes in customer demand, increased costs associated with repairing and maintaining generation facilities and transmission and distribution systems resulting in increased maintenance and capital costs (and potential increased financing needs), limits on the Entergy system’s ability to meet peak customer demand, more frequent and longer lasting outages, increased regulatory oversight, criticism or adverse publicity, and lower customer satisfaction. Also, to the extent that climate change adversely impacts the economic health of a region or results in energy conservation or demand side management programs, it may adversely impact customer demand and revenues. Such physical or operational risks could have a material effect on Entergy’s and its subsidiaries’ financial condition, results of operations, and liquidity.

A decline in the continued and future availability and quality of water for cooling, process, and sanitary uses could materially affect the financial condition, results of operations, and liquidity of Entergy, its subsidiaries, and industrial customers.

Water is a vital natural resource that is also critical to Entergy and its subsidiaries. Entergy’s and its subsidiaries’ facilities use water for cooling, boiler make-up, sanitary uses, potable supply, and many other uses. Entergy’s Utility operating companies also own and/or operate hydroelectric facilities. Accordingly, water availability and quality are critical to Entergy’s and its subsidiaries’ business operations. Impacts to water availability or quality could negatively impact both operations and revenues.

Entergy and its subsidiaries secure water through various mechanisms (ground water wells, surface waters intakes, municipal supply, etc.) and operate under the provisions and conditions set forth by the provider and/or regulatory authorities. Entergy and its subsidiaries also obtain and operate in substantial compliance with water discharge permits issued under various provisions of the Clean Water Act and/or state water pollution control provisions. Regulations and authorizations for both water intake and use and for waste discharge can become more stringent in times of water shortages, low flows in rivers, low lake levels, low groundwater aquifer volumes, and similar conditions. The increased use of water by industry, agriculture, and the population at large, population growth, saltwater intrusion, and the potential impacts of climate change on the availability of water resources may cause water use restrictions that affect Entergy, its subsidiaries, and industrial customers.

The Utility operating companies, System Energy, and Entergy’s non-utility operations may incur substantial costs related to reliability standards.

Entergy’s business is subject to extensive and mandatory reliability standards. Such standards, which are established by the NERC, the SERC, and other regional enforcement entities, are approved by the FERC and frequently are reviewed, amended, and supplemented. Failure to comply with such standards could result in the imposition of fines or civil penalties, and potential exposure to third party claims for alleged violations of such standards. The standards, as well as the laws and regulations that govern them, are subject to judicial interpretation and to the enforcement discretion vested in the implementing agencies. In addition to exposure to civil penalties and fines, the Utility operating companies have incurred and expect to incur significant costs related to compliance with new and existing reliability standards, including costs associated with the Utility operating companies’ transmission system and generation assets. In addition, the retail regulators of the Utility operating companies possess the jurisdiction, and in some cases have exercised such jurisdiction, to impose standards governing the reliable operation of the Utility operating companies’ distribution systems, including penalties if these standards are not met. The changes to the reliability standards applicable to the electric power industry are ongoing and evolve to address new risk profiles such as grid transformation, resilience to extreme events, critical infrastructure interdependencies, security, and energy policy. Entergy cannot predict the ultimate effect that the reliability standards will have on its Utility and Entergy’s non-utility operations.

Entergy and its subsidiaries may not be adequately hedged against changes in commodity prices or interest rates, which could materially affect Entergy’s and its subsidiaries’ results of operations, financial condition, and liquidity.

To manage near-term and medium-term financial exposure related to commodity price fluctuations, Entergy and its subsidiaries, including the Utility operating companies, may enter into contracts to hedge portions of their purchase and sale commitments, fuel requirements, and inventories of natural gas, uranium and its conversion and enrichment, coal, refined products, and other commodities, within established risk management guidelines. As part of this strategy, Entergy and its subsidiaries may utilize fixed- and variable-price forward physical purchase and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges. However, Entergy and its subsidiaries normally cover only a portion of the exposure of their assets and positions to market price volatility, and the coverage will vary over time. In addition, Entergy also elects to leave certain volumes during certain years unhedged. To the extent Entergy and its subsidiaries have unhedged positions, fluctuating commodity prices can materially affect Entergy’s and its subsidiaries’ results of operations and financial position.

Entergy and its subsidiaries have in the past, and may in the future, enter into financial arrangements that are subject to variable interest rates and transactions to hedge variable interest rate risk associated with such financing arrangements, such as interest rate swaps, caps or collars. Entergy’s and its subsidiaries’ use of such hedging strategies may not be effective and may adversely affect their business, results of operations, or financial position. Furthermore, no hedging strategy can completely mitigate exposure to variable interest rate risk, and such strategies may limit Entergy’s and its subsidiaries’ ability to participate in the benefits of lower interest rates. Entergy cannot predict the outcome or effectiveness of such hedging strategies to mitigate this risk.

Although Entergy and its subsidiaries devote a considerable effort to these risk management strategies, they cannot eliminate all the risks associated with these activities. As a result of these and other factors, Entergy and its subsidiaries cannot predict with precision the impact that risk management decisions may have on their business, results of operations, or financial position.

The Utility operating companies and Entergy’s non-utility business are exposed to the risk that counterparties may not meet their obligations, which may materially affect the Utility operating companies and Entergy’s non-utility business, including the ability to meet debt obligations.

The risk management practices of the Utility operating companies and Entergy's non-utility business are exposed to the risk that counterparties that owe Entergy and its subsidiaries performance of certain obligations, money, energy, or other commodities will not perform their obligations. If counterparties to these arrangements, such as counterparties to large customer electric service agreements or hedging arrangements, fail to perform, Entergy or its subsidiaries may seek to enforce its contractual protections, but may be unsuccessful, such as in recovering proceeds adequate to cover the related obligations, which could materially affect the applicable Utility operating company or Entergy’s non-utility business, despite any contractual protections. With respect to the obligations of counterparties to large customer electric service agreements, Entergy has heightened exposure to a small number of large-scale data center customers which makes recovery of Entergy’s significant investments in transmission and generation assets to power those new large-scale data centers subject to a significant degree to the success of those customers. The contractual and credit and collateral protections included in the agreements with these customers may prove insufficient to protect Entergy under certain circumstances, such as in the event of a bankruptcy of the customer or a guarantor of its obligations. If any such customer is unable to fulfill its contractual obligations, there is a risk that the associated Utility operating company may not be able to fully recover its investment in and/or a return on those assets or meet its debt obligations.

Market performance and other changes may decrease the value of benefit plan assets, which then could require additional funding and result in increased benefit plan costs.

The performance of the capital markets affects the values of the assets held in trust under Entergy’s pension and postretirement benefits plans. A decline in the market value of the assets may increase the funding requirements relating to Entergy’s benefit plan liabilities and also result in higher benefit costs. As the value of the assets decreases, the “expected return on assets” component of benefit costs decreases, resulting in higher benefits costs. Additionally, asset losses are incorporated into benefit costs over time, thus increasing benefits costs. Volatility in the capital markets has affected the market value of these assets, which has affected and may affect Entergy’s planned levels of contributions in the future. Additionally, changes in interest rates affect the liabilities under Entergy’s pension and postretirement benefits plans; as interest rates decrease, the liabilities increase, potentially requiring additional funding and recognition of higher liability carrying costs. The funding requirements of the obligations related to the pension benefit plans can also increase as a result of changes in, among other factors, retirement rates, life expectancy assumptions, or federal regulations. For further information regarding Entergy’s pension and other postretirement benefits plans, refer to the “Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits” section of Management’s Financial Discussion and Analysis for Entergy and each of its Registrant Subsidiaries and Note 11 to the financial statements.

The litigation environment in the states in which the Registrant Subsidiaries operate poses a significant risk to those businesses.

Entergy and its subsidiaries and related entities are involved in the ordinary course of business in a number of lawsuits involving employment, commercial, asbestos, hazardous material and customer matters, and injuries and damages issues, among other matters. The states in which Entergy and the Registrant Subsidiaries operate have proven to be unusually litigious environments. Judges and juries in these states have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. Entergy and its subsidiaries use legal and appropriate means to contest litigation threatened or filed against them, but the litigation environment in these states poses a significant business risk.

Terrorist attacks and sabotage, physical attacks, cyber attacks, system failures, data breaches or other disruptions of Entergy’s and its subsidiaries’ or their suppliers’ infrastructure or technology systems, including disruptions affecting other third parties ultimately connected to Entergy and its subsidiaries or their suppliers through the transmission grid, may adversely affect Entergy’s business and results of operations.

As an operator of critical infrastructure, Entergy and its subsidiaries face a heightened risk of physical attacks or acts or threats of terrorism, cyber attacks, including ransomware and phishing attacks, business email compromises, viruses, malicious code, and data breaches, whether as a direct or indirect act against one of Entergy’s generation, transmission or distribution facilities, operations centers, infrastructure, or information technology systems used to manage, monitor, and transport power to customers and perform day-to-day business functions as well as against the systems of critical suppliers and contractors or other third parties interconnected through the grid. Like many businesses and operators of critical infrastructure, Entergy and its subsidiaries and their third-party suppliers have in the past and, will in the future, continue to be subject to cyber attacks, cybersecurity threats and attempts to compromise and penetrate the information technology systems of Entergy and its subsidiaries and disrupt their operations.

Entergy and its subsidiaries operate in a business that requires evolving and advanced information technology systems that include sophisticated data collection, processing systems, software, network infrastructure, and other technologies that are becoming more complex and may be subject to mandatory and prescriptive reliability and security standards. The functionality of Entergy’s technology systems depends on its own and its suppliers’ and their contractors’ technology. Suppliers’ and their contractors’ technology systems to which Entergy is connected directly or indirectly support a variety of business processes and activities to store sensitive data, including (i) intellectual property, (ii) proprietary business information, (iii) personally identifiable information of customers, employees, and others, and (iv) data with respect to invoicing and the collection of payments, accounting, procurement, and supply-chain activities. Any significant failure, misconfiguration, or malfunction of such information technology systems could result in loss of or inappropriate access to data or disruptions of operations.

There have been attacks and threats of attacks on energy infrastructure by cyber actors, including those associated with foreign governments. Further, attacks may become more frequent in the future as technology becomes more prevalent and sophisticated in energy infrastructure. An attack could affect Entergy’s or its subsidiaries’ ability to operate, including its ability to operate the information technology systems and network infrastructure on which it relies to conduct business.

Given the fraught geopolitical landscape and rapid technological advancements of existing and emerging threats, including threats fueled by artificial intelligence, Entergy’s technology systems remain inherently vulnerable despite implementations and enhancements of the multiple layers of security and controls. In addition, the prevalent use of smartphones, tablets, and other wireless devices, as well as ongoing remote or hybrid work-from-home arrangements for a significant portion of Entergy’s employees and those of its contractors and vendors may also heighten these risks. If Entergy’s or its subsidiaries’ technology systems, or those of critical suppliers or contractors or other third parties interconnected through the grid or otherwise, were compromised and unable to detect or recover in a timely fashion to a normal state of operations, Entergy or its subsidiaries could be unable to perform critical business functions that are essential to the company’s well-being and could result in a loss of or inappropriate access to its confidential, sensitive, and proprietary information, including personal information of its customers, employees, suppliers, and others in Entergy’s care. Entergy cannot anticipate, detect, or implement fully preventive measures against all cybersecurity threats.

Any such attacks, failures, or data breaches could have a material effect on Entergy’s and the Registrant Subsidiaries’ business, financial condition, results of operations or reputation. Although Entergy and the Registrant Subsidiaries purchase insurance for cyber attacks and data breaches, coverage may not be adequate to cover all losses that might arise in connection with these incidents. Such incidents may also expose Entergy to an increased risk of litigation (and associated damages and fines). For information on our cybersecurity risk management, strategy, and governance, see “Item 1C. Cybersecurity” in Part I, Item 1C.

Entergy and the Registrant Subsidiaries are subject to risks associated with their ability to obtain adequate insurance at acceptable costs.

The global economic cost to insurers resulting from cyber attacks, natural disasters, wildfires, and other catastrophic events, in addition to an increased focus on climate issues, has had and may continue to have disruptive effects on insurance markets. The availability of insurance capacity may decrease, and the insurance policies that Entergy or the Registrant Subsidiaries are able to obtain may have higher deductibles and more restrictive terms and conditions, including higher premiums. Entergy expects the recent pattern of increasing premiums to continue in the near and medium term. Further, the insurance policies of Entergy or the Registrant Subsidiaries may not cover all of their potential exposures or actual amounts of losses incurred.

Significant increases in commodity prices, the prices of other materials and supplies, and operation and maintenance expenses may adversely affect Entergy's results of operations, financial condition, and liquidity.

Entergy and its subsidiaries have observed and expect continued inflationary pressures related to commodity prices, other materials and supplies, and operation and maintenance expenses, including in the areas of labor, health care, and pension costs. The contracts for the construction of certain of the Utility operating companies’ generation facilities also have included, and in the future may include, price adjustment provisions that, subject to certain limitations, may enable the contractor to increase the contract price to reflect increases in certain costs of constructing the facility. These inflationary pressures could impact the ability of Entergy and its subsidiaries to control costs and/or make substantial investments in their businesses, including their ability to recover costs and investments, and to earn their allowed return on equity within frameworks established by their regulators while maintaining affordability of their services for their customers, in addition to having unpredictable effects on Entergy’s customers. Increases in commodity prices, the prices of other materials and supplies, and operation and maintenance expenses, including increasing labor costs and costs and funding requirements associated with Entergy's defined benefit retirement plans, health care plans, and other employee benefits, could increase their financing needs and otherwise adversely affect their results of operations, financial condition, and liquidity. The capital plan of certain Utility operating companies includes significant investments in generation facilities in the near term to serve the rapid growth in load demand from large customers and large-scale data centers, which heightens Entergy’s and those Utility operating companies’ exposure to these risks. Negotiated contract terms and credit collateral requirements may be insufficient to protect against these risks.

(Entergy Corporation and System Energy)

System Energy owns and, through an affiliate, operates a single nuclear generating facility, and it is dependent on sales to affiliated companies for all of its revenues. Certain contractual arrangements relating to System Energy, such affiliated companies, and these revenues are the subject of ongoing litigation and may be subject to future such litigation and regulatory proceedings.

System Energy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% ownership/leasehold interest in Grand Gulf. Charges under the Unit Power Sales Agreement are paid by the Utility operating companies (other than Entergy Louisiana and Entergy Texas) as consideration for their respective entitlements to receive capacity and energy. The useful economic life of Grand Gulf is finite and is limited by the terms of its operating license, which currently expires in November 2044. System Energy’s financial condition depends both on the receipt of payments from the Utility operating companies (other than Entergy Louisiana and Entergy Texas) under the Unit Power Sales Agreement and on the continued commercial operation of Grand Gulf. The Unit Power Sales Agreement has in the past been the subject of significant litigation, including claims for refunds and rate adjustments, and is currently the subject of a litigation proceeding at the FERC with respect to System Energy’s inclusion of pre-paid and accrued pension costs in rates. As part of a settlement of such litigation (which settlement does not resolve the prepaid and accrued pension litigation), effective October 1, 2025, the Unit Power Sales Agreement was amended to remove Entergy Louisiana from the entitlement and responsibility to purchase power from Grand Gulf and the respective entitlements of the other Utility operating companies party to the Unit Power Sales Agreement were adjusted accordingly. Entergy cannot predict with certainty the outcome of this proceeding or any future proceedings that may arise with respect to the Unit Power Sales Agreement.

See Note 2 to the financial statements for further discussion of the litigation proceedings that have been settled at the FERC. System Energy agreed to implement certain protocols for providing retail regulators with information regarding rates billed under the Unit Power Sales Agreement.

For information regarding the Unit Power Sales Agreement and certain other agreements relating to certain Entergy System companies’ support of System Energy, see Note 8 to the financial statements and the “Utility - System Energy and Related Agreements” section of Part I, Item 1.

(Entergy Corporation)

Entergy’s non-utility operations are subject to substantial governmental regulation and may be adversely affected by legislative, regulatory, or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.

Entergy’s non-utility operations, including wholesale sales of electricity, are subject to regulation under federal, state, and local laws. Compliance with the requirements under these various regulatory regimes may cause Entergy’s non-utility operations to incur significant additional costs, and failure to comply with such requirements could result in the imposition of liens, fines, and/or civil or criminal liability. If Entergy’s non-utility operations were deemed to violate market behavior rules, the FERC can impose potential penalties of up to $1.544 million per day for each violation by any such entity of market-based rate rules and regulations.

Entergy’s non-utility operations are also affected by legislative and regulatory changes, as well as by changes to market design, market rules, tariffs, cost allocations, and bidding rules imposed by the existing Independent System Operator. The Independent System Operator that oversees the relevant wholesale power market has imposed, and in the future may continue to impose, mitigation, including price limitations, offer caps and other mechanisms, to address some of the volatility and the potential exercise of market power in that market. These types of price limitations and other regulatory mechanisms may have an adverse effect on the profitability of Entergy’s non-utility operations’ generation facilities that sell energy and capacity into the wholesale power markets.

The regulatory environment applicable to the electric power industry is subject to changes as a result of restructuring initiatives at both the state and federal levels. Entergy cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on Entergy’s non-utility operations.

As a holding company, Entergy Corporation depends on cash distributions from its subsidiaries to meet its debt service and other financial obligations and to pay dividends on its common stock, and has provided, and may continue to provide, capital contributions or debt financing to its subsidiaries, which would reduce the funds available to meet its other financial obligations.

Entergy Corporation is a holding company with no material revenue generating operations of its own or material assets other than the equity of its subsidiaries. Accordingly, all of its operations are conducted by its subsidiaries. Entergy Corporation’s ability to satisfy its financial obligations, including the payment of interest and principal on its outstanding debt, and to pay dividends on its common stock depends on the payment to it of dividends or distributions by its subsidiaries. The subsidiaries of Entergy Corporation are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any dividends or make distributions to Entergy Corporation. The ability of such subsidiaries to make payments of dividends or distributions to Entergy Corporation depends on their results of operations and cash flows and other items affecting retained earnings, and on any applicable legal, regulatory, or contractual limitations on subsidiaries’ ability to pay such dividends or distributions, which may be more stressed if certain Utility operating companies incur a significant level of additional debt to finance the infrastructure investments to serve large-scale data centers. Prior to providing funds to Entergy Corporation, such subsidiaries have financial and regulatory obligations that must be satisfied, including among others, debt service and, in the case of Entergy Utility Holding Company, LLC and Entergy Texas, distributions and dividends, respectively, on preferred securities. Any distributions from the Registrant Subsidiaries other than Entergy Texas and System Energy are paid directly to Entergy Utility Holding Company, LLC and are therefore subject to prior payment of distributions on its preferred securities. Entergy Corporation has provided, and may continue to provide from time to time in the future, capital contributions or debt financing to its subsidiaries, which would reduce the funds available to meet its financial obligations, including making interest and principal payments on outstanding indebtedness, and to pay dividends on Entergy Corporation’s common stock.

The hazardous activities associated with power generation could adversely impact our results of operations and financial condition.

Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of rotating equipment and delivering electricity to transmission and distribution systems. In addition to natural risks, such as earthquakes, floods, lightning, hurricanes and wind, hazards, such as fire, explosion, collapse, and machinery failure, are inherent risks in our operations which may occur as a result of inadequate internal processes, technological flaws, human error, or actions of third parties or other external events. The control and management of these risks depend upon adequate development and training of personnel and on operational procedures, preventative maintenance plans, and specific programs supported by quality control systems, which may not prevent the occurrence and impact of these risks.

The hazards described above, along with other safety hazards associated with our operations, can cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment, contamination of, or damage to, the environment and suspension of operations. The occurrence of any one of these events may result in our being named as a defendant in lawsuits asserting claims for substantial damages, environmental cleanup costs, personal injury, and fines and/or penalties and may adversely affect our reputation.

Risk Management and Strategy

Entergy and the Registrant Subsidiaries maintain a security-risk-management system with defined roles, duties, governance, and accountability. Under this physical- and cyber-risk model, Entergy and the Registrant Subsidiaries streamline security into a centralized program. The Chief Security Officer (CSO) is responsible for establishing the security and reliability risk strategy, setting policies, monitoring controls and compliance, providing support activities, and reporting on the security program. The Chief Information Security Officer (CISO) is responsible for establishing the cybersecurity strategy and implementing physical and cyber security systems for the security program. The Chief Information Officer (CIO) is responsible for ensuring that Entergy’s information technology infrastructure is secure and reliable. The Chief Ethics & Compliance Officer works with the CSO to address requirements of external security-related regulations, and where applicable, incorporate them into business policies. Management is responsible for identifying and managing risk directly through execution of the security program and compliance with security policies. Entergy and the Registrant Subsidiaries’ risk management model addresses compliance with certain regulatory constructs, such as the NERC Reliability Standards, the NRC Code of Federal Regulations, the Payment Card Industry Data Security Standard, and the Health Insurance Portability and Accountability Act, among other regulations. Entergy and the Registrant Subsidiaries’ risk management model continuously evolves to improve and implement protections, controls, and monitoring to mitigate risks to their part of North America’s electric grid, to protect sensitive information, and to maintain secure business operations. Entergy and the Registrant Subsidiaries manage cybersecurity threats as an enterprise risk with close coordination and information sharing with its federal, state, and local partners. Entergy and the Registrant Subsidiaries also engage with local, state, and federal law enforcement agencies on initiatives to share threat information and participate in a wide range of industry collaborations and classified briefings on cybersecurity developments and evolving risks.

Entergy and the Registrant Subsidiaries maintain access-management controls, including a layered multi-factor authentication process for network and system access, and a defense-in-depth security ecosystem that includes advanced threat detection from independent third parties and federal agencies, security logging and monitoring, and independent third-party penetration and vulnerability assessments. Relevant employees and contractors must complete cybersecurity trainings periodically to heighten security and threat awareness, promote best practices, and meet regulatory requirements. Additional multi-layered prevention and detection processes and technologies to mitigate and minimize the effects of cybersecurity risks include email security, continuous monitoring, vulnerability scanning, anti-virus and anti-malware software, backups and recovery strategy, network segregation, third-party security, and information protection.

Entergy and the Registrant Subsidiaries have incorporated certain cyber-specific response protocols and procedures into their Entergy Incident Management System framework for responding to emergency incidents. This includes the Entergy Incident Response Team Plan, which outlines Entergy’s procedures, steps, and responsibilities for preparing for, detecting, containing, and recovering from an incident. The plan details the roles and responsibilities of Entergy’s officers who would be engaged in such a response to an emergency incident, including key questions to be addressed, critical decision points, and sources of key information to support decision-making. Senior management and the Emergency Incident Response Team periodically review and drill on the plan.

As cybersecurity risks continue to evolve with multiple threat vectors, including artificial intelligence related threats, Entergy and the Registrant Subsidiaries maintain a comprehensive security strategy to keep current with the changing threats. To inform this effort, Entergy and the Registrant Subsidiaries utilize the National Institute of Standards and Technology Cybersecurity Framework, which consists of standards, guidelines, and best practices to manage cybersecurity risk across the enterprise. A risk-based approach is used to direct security initiatives to the most significant risks and provide the most value in terms of risk reduction and protection. Entergy and the Registrant Subsidiaries use a vendor risk management program to assess and monitor security risks that arise from certain third-party vendors. In addition, Entergy and the Registrant Subsidiaries utilize technology and threat-intelligence services to assess and continuously monitor the cybersecurity risk of key vendors, as identified through the vendor risk management program.

While Entergy and the Registrant Subsidiaries have experienced cybersecurity incidents, except as otherwise summarized above or discussed elsewhere in this report, the risks from cybersecurity threats, including as a result of any previous cybersecurity incidents, have not materially affected them including their business strategy, results of operations, or financial condition. See “Risk Factors” in Part I, Item 1A for a detailed description of the risks related to cybersecurity.

Corporate Governance

The Board of Directors is responsible for oversight of the identification, management, and mitigation of enterprise-wide risk, including cybersecurity risk. The Audit Committee has the primary responsibility for overseeing risk management, including oversight of cybersecurity risk management practices and performance. The Audit Committee generally receives reports at each regular quarterly meeting provided by the CSO, the CISO, the CIO, and the General Auditor on the cybersecurity management program. The reports focus on the programs and protocols in place to mitigate cybersecurity risks, led by the CSO. Among other things, the reports may include: recent cyber risk and cybersecurity developments; industry engagement activities; legislative and regulatory developments; cyber-risk governance and oversight; selected cyber risk metrics and activities; cyber risk incident response plans and strategies; cybersecurity drills and exercises; assessments by third party experts and Internal Audit; and major projects and initiatives.

While the Board of Directors and Audit Committee oversee cybersecurity risk management, Entergy’s management is responsible for managing cybersecurity risk. Entergy and the Registrant Subsidiaries’ security-risk-management system, as discussed above, is comprised of a three lines of defense model to enhance risk management efforts and define roles in the security program. The first line of defense, comprised of business units performing operational functions, including the CISO and CIO, is responsible for identification and management of security and reliability risks directly through design, implementation, and execution of control activities. The second line of defense, comprised of the CSO, performs and supports security and reliability risk management and governs and oversees the execution of security and reliability controls by the first line of defense. Ownership of specific security operations may migrate from a business unit in the first line of defense to the second line of defense, as determined to be appropriate by the Chief Security Office. The third line of defense, which includes Internal Audit, independent third parties, and certain regulatory constructs, such as the NERC Reliability Standards and the NRC Cyber Rule, provides assurance of selective actions taken by the first and second lines of defense to senior management and the Board of Directors.

Entergy’s CSO is responsible for overseeing physical, cyber, and reliability risk, including governance, compliance, and threat intelligence. The CSO’s background includes serving as the Global Lead Business Information Security Officer for a multinational pharmaceutical and biotechnology company, Vice President of Cybersecurity Solutions for an international consulting firm, and an operations manager for a multinational technology company. The CSO is also a former intelligence officer in the U.S. Marine Corps, with experience in the Fleet Marine Force, Joint Staff J-2/Defense Intelligence Agency, and Headquarters Marine Corps Command, Control, Communications, and Computers (C4I). The CSO participated in numerous exercises and crisis operations during his time in the military. The CSO is a member of the Information Systems Audit and Control Association and a certified Information Privacy Manager from the International Association of Privacy Professionals. The CSO also completed the Harvard Kennedy School Executive Education Program in Cybersecurity and the FBI Domestic Security Executive Academy.

Entergy’s CISO is responsible for enterprise strategic and operational cybersecurity, physical security systems, and regulatory compliance. The CISO oversees investments in tools, resources, and processes that allow for the continuous improvement and maturity of Entergy’s cybersecurity posture. The CISO has expertise spanning more than 25 years in the realm of information technology, information security, and cyber/physical security management. The CISO’s background includes serving as the Vice President and Chief Information Security Officer for an electric utility with responsibility for enterprise cybersecurity covering corporate, electric, nuclear, and gas operations. Additionally, the CISO served as the Chief Security Officer for the Electric Reliability Council of Texas with overall responsibility for its cybersecurity, physical security, and emergency management programs. Her previous experience includes multiple technical, managerial, and strategic roles within industries ranging from energy, telecommunication, software development, and cybersecurity consulting. The CISO is a Certified Information Systems Security Professional, Certified Information Security Manager, and Certified in Risk and Information Systems Control.

Entergy’s CIO is responsible for ensuring that the organization’s information technology systems, infrastructure, and applications are designed, implemented, and maintained to provide secure and reliable performance in support of Entergy’s business objectives. The CIO establishes and enforces IT policies, procedures, and controls to mitigate information technology policies, procedures, and controls to mitigate information technology-related risks and provides guidance and support to the business units in the effective use of information technology resources and the management of information technology-related risks. By fulfilling these responsibilities across the three lines of defense model, the CIO plays a critical role in ensuring that Entergy’s information technology-related risks are effectively identified, managed, and mitigated, thereby supporting Entergy’s overall risk management and governance framework. The CIO’s background includes serving in senior leadership roles, including CIO for multiple global manufacturing companies, serving on the board of directors for a telecommunications company, and consulting leadership positions providing services for numerous large, global organizations.

In the event of a suspected or actual cybersecurity incident, the Security Incident Response Team (SIRT), which includes the CISO, has primary responsibility for initial identification and evaluation of potential business impacts and escalation of the incident’s severity classification using pre-established criteria with a specified communication matrix and escalation thresholds. The Security Incident Commander, which role is served by a leader in the CISO organization, provides tactical leadership and oversight management at the cross-functional level for the incident. The SIRT remains engaged throughout the incident response lifecycle, including detection and analysis, containment, eradication and recovery, and post-incident remediation, and coordinates with the impacted business functions, if warranted. Once a cyber incident is confirmed, the SIRT is responsible for maintaining situational awareness and continuous monitoring of the need for escalation or de-escalation of the incident’s severity classification. As certain escalation thresholds are exceeded, additional levels of management notification are required by the SIRT, including notification of and recurring communication with Entergy’s Incident Response Team, which includes the Chief Executive Officer, the Chief Operating Officer, the CSO, other executive management, and members of the affected business functions. Depending upon the facts, analysis, materiality, and anticipated or current impacts, the Chief Executive Officer and the General Counsel will determine the timing and cadence for communication of the cyber incident with the Board of Directors or Audit Committee.

Winter Storm Fern

See the “Winter Storm Fern” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Winter Storm Fern. Entergy Arkansas’s preliminary estimate for the cost of mobilizing crews and restoring power is approximately $50 million to $60 million, with the majority of the costs being capital. Natural gas purchases for Entergy Arkansas for January 2026 are $74 million compared to natural gas purchases for January 2025 of $25 million.

Results of Operations

2025 Compared to 2024

Net Income

Net income increased $118.0 million primarily due to a $131.8 million ($99.1 million net-of-tax) charge, recorded in first quarter 2024, to reflect the write-off of a previously recorded regulatory asset as a result of an adverse decision in the opportunity sales proceeding in March 2024, higher volume/weather, and higher retail electric price, partially offset by higher depreciation and amortization expenses, higher other operation and maintenance expenses, higher interest expense, an $18.3 million reduction in income tax expense in third quarter 2024 as a result of the resolution of an Arkansas state income tax audit, and higher taxes other than income taxes. See Note 2 to the financial statements for discussion of the opportunity sales proceeding. See Note 3 to the financial statements for discussion of the resolution of the Arkansas state income tax audit.

Operating Revenues

Following is an analysis of the change in operating revenues comparing 2025 to 2024:

(In Millions)

Entergy Arkansas’s 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 and residential usage. The increase in industrial usage is primarily due to an increase in demand from large industrial customers, primarily in the primary metals and technology industries, and an increase in demand from small industrial customers. The increase in residential usage is primarily due to an increase in customers.

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 Arkansas previously recorded a regulatory liability for the effects of the System Energy settlement with the APSC. See Note 2 to the financial statements for discussion of the System Energy settlement with the APSC and discussion of the Grand Gulf credit rider.

The retail electric price variance is primarily due to an increase in formula rate plan rates effective January 2025. See Note 2 to the financial statements for discussion of the 2024 formula rate plan filing.

Total electric energy sales for Entergy Arkansas for the years ended December 31, 2025 and 2024 are as follows:

See Note 19 to the financial statements for additional discussion of Entergy Arkansas’s operating revenues.

Other Income Statement Variances

Other operation and maintenance expenses increased primarily due to:

• an increase of $14.0 million in power delivery expenses primarily due to higher vegetation maintenance costs;
• an increase of $13.9 million in non-nuclear generation expenses primarily due to a higher scope of work, including during plant outages, in 2025 as compared to 2024;
• an increase of $6.1 million in bad debt expense;
• the expensing of $5.0 million of certain wind and solar project costs associated with the decision to evaluate alternative generation solutions; and
• several individually insignificant items.

The increase was partially offset by contract costs of $11.5 million in 2024 related to operational performance, customer service, and organizational health initiatives and a decrease of $10.9 million in energy efficiency expenses primarily due to the timing of recovery from customers.

Asset write-offs includes a $131.8 million charge, recorded in first quarter 2024, to reflect the write-off of a previously recorded regulatory asset as a result of an adverse decision in the opportunity sales proceeding in March 2024. See Note 2 to the financial statements for discussion of the opportunity sales proceeding.

Taxes other than income taxes increased primarily due to increases in ad valorem taxes resulting from higher assessments and millage rate increases.

Depreciation and amortization expenses increased primarily due to additions to plant in service, including the Walnut Bend Solar facility, which was placed in service in September 2024, and the West Memphis Solar facility and the Driver Solar facility, which were placed in service in December 2024.

Other regulatory charges (credits) - net includes:

• the reversal in third quarter 2024 of a $92.3 million regulatory liability recognized for the 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 the Grand Gulf credit rider;
• a regulatory credit of $28.3 million, recorded in fourth quarter 2025, to reflect the amount of the 2024 historical year netting adjustment to be collected from Entergy Arkansas’s 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 2025 formula rate plan filing; and
• a regulatory credit of $15.5 million, recorded in fourth quarter 2024, to reflect the amount of the 2023 historical year netting adjustment to be collected from Entergy Arkansas’s 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 2024 formula rate plan filing.

In addition, Entergy Arkansas 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.

Interest expense increased primarily due to the issuance 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 effective income tax rates were 19.8% for 2025 and 18.9% 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.

2024 Compared to 2023

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of Entergy Arkansas’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.

Income Tax Legislation and Regulation

See the “Income Tax Legislation and Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of income tax legislation and regulation.

Cash Flow

Cash flows for the years ended December 31, 2025, 2024, and 2023 were as follows:

(In Thousands)

2025 Compared to 2024

Operating Activities

Net cash flow provided by operating activities increased $356.4 million in 2025 primarily due to:

• higher collections from customers;
• net cash proceeds of $242.6 million received by Entergy Arkansas in 2025, including $215.2 million of proceeds received from Entergy Arkansas’s transfer of 2024 nuclear and solar production tax credits to third parties in 2025 and net cash receipts of $27.4 million from affiliates in 2025 in accordance with the Unit Power Sales Agreement and the MSS-4 replacement tariff related to the transfer of 2024 nuclear production tax credits by Entergy Arkansas and affiliates to third parties in 2025. See Note 3 to the financial statements for discussion of the nuclear and solar production tax credits;
• income tax refunds of $29.7 million in 2025 compared to income tax payments of $9.5 million in 2024. Entergy Arkansas received income tax refunds in 2025 and made income tax payments in 2024, each in accordance with Entergy’s tax allocation agreement;
• a decrease of $23.7 million in spending on nuclear refueling outages in 2025 as compared to 2024; and
• a decrease of $19.6 million in pension contributions in 2025. 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.

The increase was partially offset by:

• higher fuel and purchased power payments. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery;
• the timing of payments to vendors; and
• the receipt of $92.7 million in settlement proceeds in 2024 as a result of the System Energy settlement with the APSC, which was subsequently refunded to retail customers in third quarter 2024 with one-time bill credits through the Grand Gulf credit rider. See Note 2 to the financial statements for discussion of the System Energy settlement agreement with the APSC and the Grand Gulf credit rider.

Investing Activities

Net cash flow used in investing activities decreased $535.5 million in 2025 primarily due to:

• the initial and substantial completion payments totaling approximately $392.8 million in 2024 for the purchase of the Driver Solar facility;
• the initial and substantial completion payments totaling approximately $240.4 million in 2024 for the purchase of the West Memphis Solar facility;
• the initial and substantial completion payments totaling approximately $185.5 million in 2024 for the purchase of the Walnut Bend Solar facility;
• a decrease in cash used of $38.2 million as a result of fluctuations in nuclear fuel activity 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
• a decrease of $30.0 million in transmission construction expenditures primarily due to decreased spending on various transmission projects in 2025.

The decrease was partially offset by:

• an increase of $201.0 million in non-nuclear generation construction expenditures primarily due to higher spending on the Ironwood Power Station (formerly Lake Catherine Unit 5) project and the Jefferson Power Station project;
• an increase of $92.0 million in distribution construction expenditures primarily due to higher capital expenditures for storm restoration in 2025;
• cash collateral of $37.0 million posted in 2025 to support Entergy Arkansas’s obligations to MISO; and
• money pool activity.

Increases in Entergy Arkansas’s receivable from the money pool are a use of cash flow, and Entergy Arkansas’s receivable from the money pool increased $21.7 million in 2025. The money pool is an intercompany cash management program that makes possible intercompany borrowing and lending arrangements, and the money pool and other borrowing arrangements are designed to reduce the Registrant Subsidiaries’ dependence on external short-term borrowings.

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.

Financing Activities

Net cash flow provided by financing activities decreased $622.2 million in 2025 primarily due to:

• the issuances of $400 million of 5.45% Series mortgage bonds and $400 million of 5.75% Series mortgage bonds, each in May 2024;
• capital contributions of approximately $695 million received from Entergy Corporation in 2024 to partially finance the acquisitions of the Walnut Bend Solar facility, the West Memphis Solar facility, and the Driver Solar facility;
• the issuance of $70 million of 5.54% Series O notes by the Entergy Arkansas nuclear fuel company variable interest entity in March 2024; and
• a decrease of $16.6 million in advance payments from customers for construction related to transmission, distribution, and generator interconnection agreements.

The decrease was partially offset by:

• the repayment, at maturity, of $375 million of 3.70% Series mortgage bonds in June 2024;
• the issuance of $300 million of 5.45% Series mortgage bonds in May 2025;
• a decrease of $120 million in common equity distributions paid in 2025 in order to maintain Entergy Arkansas’s capital structure;
• money pool activity; and
• a decrease in net repayments of $38.9 million on the nuclear fuel company variable interest entity’s credit facility.

Decreases in Entergy Arkansas’s payable to the money pool are a use of cash flow, and Entergy Arkansas’s payable to the money pool decreased $15.2 million in 2025 compared to decreasing by $130.2 million in 2024.

See Note 5 to the financial statements for additional details of long-term debt.

2024 Compared to 2023

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy Arkansas’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.

Capital Structure

Entergy Arkansas’s debt to capital ratio is shown in the following table.

Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, finance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt and equity. Net capital consists of capital less cash and cash equivalents. Entergy Arkansas uses the debt to capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition. The net debt to net capital ratio is a non-GAAP measure. Entergy Arkansas also uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition because net debt indicates Entergy Arkansas’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.

Entergy Arkansas seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a distribution, to the extent funds are legally available to do so, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Arkansas may issue incremental debt or reduce distributions, or both, to maintain its capital structure. In addition, in certain infrequent circumstances, such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reduced distributions, Entergy Arkansas may receive equity contributions to maintain its capital structure.

Uses of Capital

Entergy Arkansas requires capital resources for:

• construction and other capital investments;
• debt maturities or retirements;
• working capital purposes, including the financing of fuel and purchased power costs; and
• distribution and interest payments.

Following are the amounts of Entergy Arkansas’s planned construction and other capital investments.

(In Millions)

In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Arkansas includes investments in generation projects to modernize, decarbonize, expand, and diversify Entergy Arkansas’s portfolio, as well as to support customer growth, including Ironwood Power Station (formerly Lake Catherine Unit 5), Jefferson Power Station, and Arkansas Cypress Solar; investments in ANO 1 and 2; distribution and Utility support spending to improve reliability and customer experience; transmission spending to improve reliability while also supporting customer growth and renewables expansion; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, governmental actions, including the trade-related governmental actions discussed below, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital, including any changes to governmental programs, such as loans, grants, guarantees, and other subsidies.

Recent announcements of changes to international trade policy and tariffs and further similar changes may impact Entergy Arkansas’s business, operations, results of operations, and liquidity and capital resources. Potential impacts may include increases in costs associated with Entergy Arkansas’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 Arkansas’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 Arkansas’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.

Entergy Arkansas has 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 its current and planned capital projects. Entergy Arkansas 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 its current and planned capital projects.

Following are the amounts of Entergy Arkansas’s existing debt and lease obligations (includes estimated interest payments).

(In Millions)

(a) Long-term debt is discussed in Note 5 to the financial statements.

(b) Lease obligations are discussed in Note 10 to the financial statements.

Other Obligations

Entergy Arkansas currently expects to contribute approximately $29.7 million to its qualified pension plans and approximately $710 thousand 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 Arkansas has $235.4 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.

In addition, Entergy Arkansas enters into fuel and purchased power agreements that contain minimum purchase obligations. Entergy Arkansas has rate mechanisms in place to recover fuel, purchased power, and associated costs incurred under these purchase obligations. See Note 8 to the financial statements for discussion of Entergy Arkansas’s obligations under the Unit Power Sales Agreement.

As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy Arkansas pays distributions from its earnings at a percentage determined monthly.

Ironwood Power Station

In 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 “State and Local Rate Regulation and Fuel-Cost Recovery - Retail Rates - Generating Arkansas Jobs Act Rider” below for discussion of the Generating Jobs Act rider, which was approved by the APSC in October 2025.

Jefferson Power Station

In 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 “State and Local Rate Regulation and Fuel-Cost Recovery - Retail Rates - Generating Arkansas Jobs Act Rider” below for discussion of the Generating Jobs Act rider, which was approved by the APSC in October 2025.

Special Rate Contract and Arkansas Cypress Solar

In 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 “State and Local Rate Regulation and Fuel-Cost Recovery - Retail Rates - Generating Arkansas Jobs Act Rider” below for discussion of the Generating Jobs Act rider, which was approved by the APSC in October 2025.

Sources of Capital

Entergy Arkansas’s sources to meet its capital requirements include:

• internally generated funds;
• cash on hand;
• the Entergy system money pool;
• debt or preferred membership interest issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
• capital contributions; and
• bank financing under new or existing facilities.

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, Entergy Arkansas expects to continue, when economically feasible, to retire higher-cost debt and replace it with lower-cost debt if market conditions permit.

All debt and common and preferred membership interest issuances by Entergy Arkansas require prior regulatory approval. Debt issuances are also subject to requirements set forth in Entergy Arkansas’s bond indenture and other agreements. Entergy Arkansas has sufficient capacity under these tests to meet its foreseeable capital needs for the next twelve months and beyond.

Entergy Arkansas’s receivables from (payables to) the money pool were as follows as of December 31 for each of the following years.

(In Thousands)

See Note 4 to the financial statements for a description of the money pool.

Entergy Arkansas has a credit facility in the amount of $300 million scheduled to expire in June 2030. Entergy Arkansas also has a $25 million credit facility scheduled to expire in April 2026. The $300 million credit facility includes fronting commitments for the issuance of letters of credit against $5 million of the borrowing capacity of the facility. As of December 31, 2025, there were no cash borrowings under either credit facility and no letters of credit outstanding under the $300 million credit facility. In addition, Entergy Arkansas is a party to two uncommitted letter of credit facilities as a means to post collateral to support its obligations to MISO. As of December 31, 2025, $93.3 million in letters of credit were outstanding under Entergy Arkansas’s uncommitted letter of credit facilities. See Note 4 to the financial statements for further discussion of the credit facilities.

The Entergy Arkansas nuclear fuel company variable interest entity has a credit facility in the amount of $80 million scheduled to expire in June 2027. As of December 31, 2025, there were $13.7 million in loans outstanding under the credit facility for the Entergy Arkansas nuclear fuel company variable interest entity. See Note 4 to the financial statements for further discussion of the nuclear fuel company variable interest entity credit facility.

Entergy Arkansas obtained authorization from the FERC through February 2028 for the following:

• short-term borrowings not to exceed an aggregate amount of $250 million at any time outstanding;
• long-term borrowings and securities issuances; and
• borrowings by its nuclear fuel company variable interest entity.

See Note 4 to the financial statements for further discussion of Entergy Arkansas’s short-term borrowing limits. In addition, the APSC has concurrent jurisdiction over Entergy Arkansas’s first mortgage bond/secured issuances. Entergy Arkansas has obtained first mortgage bond/secured financing authorization from the APSC that extends through December 2027.

State and Local Rate Regulation and Fuel-Cost Recovery

The rates that Entergy Arkansas charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Arkansas is regulated, and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the APSC, is primarily responsible for approval of the rates charged to customers.

Retail Rates

2023 Formula Rate Plan Filing

In July 2023, Entergy Arkansas filed with the APSC its 2023 formula rate plan filing to set its formula rate for the 2024 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2024 and a netting adjustment for the historical year 2022. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2024 projected year was 8.11% resulting in a revenue deficiency of $80.5 million. The earned rate of return on common equity for the 2022 historical year was 7.29% resulting in a $49.8 million netting adjustment. The total proposed revenue change for the 2024 projected year and 2022 historical year netting adjustment was $130.3 million. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to $88.6 million. The APSC general staff and intervenors filed their errors and objections report in October 2023, proposing certain adjustments, including the APSC general staff’s update to annual filing year revenues which lowers the constraint to $87.7 million. In October 2023, Entergy Arkansas filed with the APSC a settlement agreement reached with other parties resolving all issues in the proceeding, none of which affected Entergy Arkansas’s requested recovery up to the constraint of $87.7 million. The settlement agreement provided for amortization of the approximately $39 million regulatory asset for costs associated with the COVID-19 pandemic over a 10-year period as well as recovery of $34.9 million related to the resolution of the 2016 and 2017 IRS audits from previous tax positions that are no longer uncertain, partially offset by $24.7 million in excess accumulated deferred income taxes from reductions in state income tax rates, each before consideration of their respective tax gross-up. See Note 3 to the financial statements for further discussion of the resolution of the 2016-2018 IRS audit and the State of Arkansas corporate income tax rate changes. In December 2023 the APSC approved the settlement agreement as being in the public interest and approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2024.

2024 Formula Rate Plan Filing

In July 2024, Entergy Arkansas filed with the APSC its 2024 formula rate plan filing to set its formula rate for the 2025 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the 2025 projected year and a netting adjustment for the 2023 historical year. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2025 projected year was 8.43% resulting in a revenue deficiency of $69.5 million. The earned rate of return on common equity for the 2023 historical year was 7.48% resulting in a $33.1 million netting adjustment. The total proposed revenue change for the 2025 projected year and 2023 historical year netting adjustment was $102.6 million. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to $82.6 million. The APSC general staff and intervenors filed their errors and objections report in October 2024, proposing certain adjustments, including the APSC general staff’s update to annual filing year revenues that increases the constraint to $83.5 million. Entergy Arkansas filed its rebuttal in October 2024, and later in October 2024 the parties submitted a joint issues list and stipulations setting forth the disputed issues and the noncontested issues. In December 2024 the APSC approved the parties’ stipulations without modification, approved Entergy Arkansas’s adjustment with respect to storm costs, directed Entergy Arkansas to adjust its projected year distribution reliability capital closings, and deferred the recoverability of Entergy Arkansas’s opportunity sales legal fees until the next general rate case. Also in December 2024 the APSC approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2025. As a result of the proceeding, the total revenue change was $82.7 million, including a $63.7 million increase for the 2025 projected year and a $31.4 million netting adjustment for the 2023 historical year. In fourth quarter 2024, Entergy Arkansas recorded a regulatory asset of $15.5 million to reflect the amount of the 2023 historical year netting adjustment that it collected from its customers during the 2025 rate effective period. Pursuant to the terms of the parties’ stipulations, Entergy Arkansas made a filing with the APSC in January 2025 to refund customers $30.1 million in excess accumulated deferred income taxes resulting from the reduction in the State of Arkansas’s income tax rate from 4.8% to 4.3% in 2024. Entergy Arkansas began refunding this amount over a 24-month period effective with the first billing cycle of February 2025.

2025 Formula Rate Plan Filing

In July 2025, Entergy Arkansas filed with the APSC its 2025 formula rate plan filing to set its formula rate for the 2026 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the 2026 projected year and a netting adjustment for the 2024 historical year. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2026 projected year was 8.45% resulting in a revenue deficiency of $68.9 million. The earned rate of return on common equity for the 2024 historical year was 7.71% resulting in a $48.8 million netting adjustment. The total proposed revenue change for the 2026 projected year and 2024 historical year netting adjustment was $117.7 million. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to $92.3 million. The APSC general staff filed their errors and objections report in October 2025, proposing an adjustment to the coupon rate for the projected long-term debt issuance in 2026 and an update to annual filing year revenues that increases the constraint to $93.9 million. Entergy Arkansas filed its rebuttal in October 2025. A hearing was scheduled for November 2025, and an order was expected in December 2025. Due to no contested issues remaining outstanding among the parties to the proceeding, in October 2025, Entergy Arkansas and the APSC general staff filed a joint motion requesting the APSC cancel the hearing and issue a decision based on the pleadings and testimony in the record. The APSC granted this request. In December 2025 the APSC approved Entergy Arkansas’s request as modified by the APSC general staff’s errors and objections report and Entergy Arkansas’s rebuttal testimony. Also in December 2025 the APSC approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2026. As a result of the proceeding, the total revenue change was $93.9 million, including a $65.6 million increase for the 2026 projected year and a $48.8 million netting adjustment for the 2024 historical year. In fourth quarter 2025, Entergy Arkansas recorded a regulatory asset of $28.3 million to reflect the amount of the 2024 historical year netting adjustment that it expects to collect from its customers during the 2026 rate effective period.

Grand Gulf Credit Rider

In June 2024, Entergy Arkansas filed with the APSC a tariff to provide retail customers a credit resulting from the terms of the settlement agreement between Entergy Arkansas, System Energy, additional named Entergy parties, and the APSC pertaining to System Energy’s billings for wholesale sales of energy and capacity from the Grand Gulf nuclear plant. See “Complaints Against System Energy - System Energy Settlement with the APSC” in Note 2 to the financial statements for discussion of the System Energy settlement with the APSC. In July 2024 the APSC approved the tariff, under which Entergy Arkansas would refund to retail customers a total of $100.6 million. Entergy Arkansas refunded $92.3 million of the total through one-time bill credits under the Grand Gulf credit rider during the August 2024 billing cycle. In March 2025, Entergy Arkansas included the remaining balance as a credit to retail customers in its energy cost recovery rider rate redetermination filing. See further discussion within “Energy Cost Recovery Rider” below. In April 2025 the APSC approved Entergy Arkansas’s proposal to include the remaining balance in its energy cost recovery rider effective with the first billing cycle of April 2025 and the withdrawal of the Grand Gulf credit rider after all credits had been issued. Credits to retail customers were completed in second quarter 2025, and the Grand Gulf credit rider was subsequently withdrawn.

Generating Arkansas Jobs Act Rider

In March 2025 the State of Arkansas passed the Generating Arkansas Jobs Act of 2025, now Act 373 (Act 373), that authorizes the recovery of financing costs during construction of generation and transmission investments through a rider separate from the formula rate plan. Act 373 also permits cost recovery of those investments, when completed and in service, either through the next general rate case proceeding or under the formula rate plan. Act 373 streamlines and simplifies the regulatory approval process and provides increased timeliness and certainty of cost recovery.

In July 2025, Entergy Arkansas submitted a tariff filing with the APSC requesting approval of a strategic investment recovery rider, consistent with the provisions of Act 373. In October 2025 the APSC issued an order approving the proposed rider with several revisions, including elimination of an annual true-up adjustment, a change in cost allocation methodology, the removal of excess and deficient accumulated deferred income taxes to a separate rider, and the addition of reporting requirements. As directed by the order, in October 2025, Entergy Arkansas made a compliance filing. In November 2025, the APSC general staff recommended additional updates to the compliance filing, including limiting the accumulated deferred income tax adjustment to excess accumulated deferred income taxes. Also, in November 2025, Entergy Arkansas filed a second compliance filing, which was approved by the APSC.

Energy Cost Recovery Rider

Entergy Arkansas’s retail rates include an energy cost recovery rider to recover fuel and purchased energy costs in monthly customer bills. The rider utilizes the prior calendar-year energy costs and projected energy sales for the twelve-month period commencing on April 1 of each year to develop an energy cost rate, which is redetermined annually and includes a true-up adjustment reflecting the over- or under-recovery, including carrying charges, of the energy costs for the prior calendar year. The energy cost recovery rider tariff also allows an interim rate request depending upon the level of over- or under-recovery of fuel and purchased energy costs.

In January 2014, Entergy Arkansas filed a motion with the APSC relating to its upcoming energy cost rate redetermination filing that was made in March 2014. In that motion, Entergy Arkansas requested that the APSC authorize Entergy Arkansas to exclude from the redetermination of its 2014 energy cost rate $65.9 million of incremental fuel and replacement energy costs incurred in 2013 as a result of the ANO stator incident. Entergy Arkansas requested that the APSC authorize Entergy Arkansas to retain that amount in its deferred fuel balance, with recovery to be reviewed in a later period after more information was available regarding various claims associated with the ANO stator incident. In February 2014 the APSC approved Entergy Arkansas’s request to retain that amount in its deferred fuel balance. In July 2017, Entergy Arkansas filed for a change in rates pursuant to its formula rate plan rider. In that proceeding, the APSC approved a settlement agreement agreed upon by the parties, including a provision that requires Entergy Arkansas to initiate a regulatory proceeding for the purpose of recovering funds currently withheld from rates and related to the stator incident, including the $65.9 million of deferred fuel and purchased energy costs and costs related to the incremental oversight previously noted, subject to certain timelines and conditions set forth in the settlement agreement. In October 2023, Entergy Arkansas made a commitment to the APSC to make a filing to forgo its opportunity to seek recovery of the incremental fuel and purchased energy expense, among other identified costs, resulting from the ANO stator incident. As a result, in third quarter 2023, Entergy Arkansas recorded a write-off of its regulatory asset for deferred fuel of $68.9 million, which includes interest, related to the ANO stator incident. Consistent with its October 2023 commitment, Entergy Arkansas filed a motion to forgo recovery in November 2023, and the motion was approved by the APSC in December 2023. See the “ANO Damage, Outage, and NRC Reviews” section in Note 8 to the financial statements for further discussion of the ANO stator incident and the approved motion to forgo recovery.

In March 2017, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase in the rate from $0.01164 per kWh to $0.01547 per kWh. The APSC staff filed testimony in March 2017 recommending that the redetermined rate be implemented with the first billing cycle of April 2017 under the normal operation of the tariff. Accordingly, the redetermined rate went into effect on March 31, 2017 pursuant to the tariff. In July 2017 the Arkansas Attorney General requested additional information to support certain of the costs included in Entergy Arkansas’s 2017 energy cost rate redetermination.

In March 2018, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase in the rate from $0.01547 per kWh to $0.01882 per kWh. The Arkansas Attorney General filed a response to Entergy Arkansas’s annual redetermination filing requesting that the APSC suspend the proposed tariff to investigate the amount of the redetermination or, alternatively, to allow recovery subject to refund. Among the reasons the Attorney General cited for suspension were questions pertaining to how Entergy Arkansas forecasted sales and potential implications of the Tax Cuts and Jobs Act. Entergy Arkansas replied to the Attorney General’s filing and stated that, to the extent there are questions pertaining to its load forecasting or the operation of the energy cost recovery rider, those issues exceed the scope of the instant rate redetermination. Entergy Arkansas also stated that potential effects of the Tax Cuts and Jobs Act are appropriately considered in the APSC’s separate proceeding regarding potential implications of the tax law. The APSC general staff filed a reply to the Attorney General’s filing and agreed that Entergy Arkansas’s filing complied with the terms of the energy cost recovery rider. The redetermined rate became effective with the first billing cycle of April 2018. Subsequently in April 2018 the APSC issued an order declining to suspend Entergy Arkansas’s energy cost recovery rider rate and declining to require further investigation at that time of the issues suggested by the Attorney General in the proceeding. Following a period of discovery, the Attorney General filed a supplemental response in October 2018 raising new issues with Entergy Arkansas’s March 2018 rate redetermination and asserting that $45.7 million of the increase should be collected subject to refund pending further investigation. Entergy Arkansas filed to dismiss the Attorney General’s supplemental response, the APSC general staff filed a motion to strike the Attorney General’s filing, and the Attorney General filed a supplemental response disputing Entergy Arkansas and the APSC staff’s filing. Applicable APSC rules and processes authorize its general staff to initiate periodic audits of Entergy Arkansas’s energy cost recovery rider. In late-2018 the APSC general staff notified Entergy Arkansas it initiated an audit of the 2017 fuel costs. The timing of the audit’s completion is uncertain at this time.

In March 2023, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase in the rate from $0.01639 per kWh to $0.01883 per kWh. The primary reason for the rate increase was a large under-recovered balance as a result of higher natural gas prices in 2022 and a $32 million deferral related to the APSC general staff’s request in 2022 for Entergy Arkansas to defer its request for recovery related to the February 2021 winter storms until the 2023 energy cost rate redetermination. In February 2023 the APSC issued orders initiating proceedings to address the prudence of costs incurred and appropriate cost allocation of the February 2021 winter storms, and in September 2023 the APSC issued an order finding Entergy Arkansas’s practices during the February 2021 winter storms to be prudent. The under-recovered balance included in the March 2023 filing was partially offset by the proceeds of the $41.7 million refund that System Energy made to Entergy Arkansas in January 2023 related to the sale-leaseback renewal costs and depreciation litigation as calculated in System Energy’s January 2023 compliance report filed with the FERC. See “Complaints Against System Energy - Grand Gulf Sale-leaseback Renewal Complaint and Uncertain Tax Position Rate Base Issue” in Note 2 to the financial statements for discussion of the compliance report filed by System Energy with the FERC in January 2023. The redetermined rate of $0.01883 per kWh became effective with the first billing cycle in April 2023 through the normal operation of the tariff.

In March 2024, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease in the rate from $0.01883 per kWh to $0.00882 per kWh. Due to a change in law in the State of Arkansas, the annual redetermination included $9 million, recorded as a credit to fuel expense in first quarter 2024, for recovery attributed to net metering costs in 2023. The primary reason for the rate decrease was a large over-recovered balance as a result of lower natural gas prices in 2023. To mitigate the effect of projected increases in natural gas prices in 2024, Entergy Arkansas adjusted the over-recovered balance included in the March 2024 annual redetermination filing by $43.7 million. This adjustment reduced the rate change that was reflected in the 2025 energy cost rate redetermination. The redetermined rate of $0.00882 per kWh became effective with the first billing cycle in April 2024 through the normal operation of the tariff.

In March 2025, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase in the rate from $0.00882 per kWh to $0.01333 per kWh. The annual redetermination included a credit related to the remaining balance due to retail customers from the System Energy settlement with the APSC, plus carrying charges and interest. See “Retail Rates - Grand Gulf Credit Rider” above for further discussion. The primary reason for the rate increase was an adjustment to account for projected increases in natural gas prices in 2025. This adjustment is expected to reduce the rate change that will be reflected in Entergy Arkansas’s 2026 energy cost rate redetermination. The redetermined rate of $0.01333 per kWh became effective with the first billing cycle in April 2025 through the normal operation of the tariff.

Opportunity Sales Proceeding

In June 2009 the LPSC filed a complaint requesting that the FERC determine that certain of Entergy Arkansas’s sales of electric energy to third parties: (a) violated the provisions of the System Agreement that allocated the energy generated by Entergy System resources; (b) imprudently denied the Entergy System and its ultimate consumers the benefits of low-cost Entergy System generating capacity; and (c) violated the provision of the System Agreement that prohibited sales to third parties by individual companies absent an offer of a right-of-first-refusal to other Utility operating companies. The LPSC’s complaint challenged sales made beginning in 2002 and requested refunds. In July 2009 the Utility operating companies filed a response to the complaint arguing among other things that the System Agreement contemplated that the Utility operating companies may make sales to third parties for their own account, subject to the requirement that those sales be included in the load (or load shape) for the applicable Utility operating company. The FERC subsequently ordered a hearing in the proceeding.

The FERC issued a decision in June 2012 and held that, while the System Agreement was ambiguous, it did provide authority for individual Utility operating companies to make opportunity sales for their own account and Entergy Arkansas made and priced these sales in good faith. The FERC found, however, that the System Agreement did not provide authority for an individual Utility operating company to allocate the energy associated with such opportunity sales as part of its load but provides a different allocation authority. The FERC further found that the after-the-fact accounting methodology used to allocate the energy used to supply the sales was inconsistent with the System Agreement. The FERC in its decision established further hearing procedures to quantify the effect of repricing the opportunity sales in accordance with the FERC’s June 2012 decision. The hearing was held in May 2013 and the ALJ issued an initial decision in August 2013.

In April 2016 the FERC issued orders addressing requests for rehearing filed in July 2012 and the ALJ’s August 2013 initial decision. The first order denied Entergy’s request for rehearing and affirmed the FERC’s earlier rulings that Entergy’s original methodology for allocating energy costs to the opportunity sales was incorrect and, as a result, Entergy Arkansas must make payments to the other Utility operating companies to put them in the same position that they would have been in absent the incorrect allocation. The FERC clarified that interest should be included with the payments. The second order affirmed in part, and reversed in part, the rulings in the ALJ’s August 2013 initial decision regarding the methodology that should be used to calculate the payments Entergy Arkansas is to make to the other Utility operating companies. The FERC affirmed the ALJ’s ruling that a full re-run of intra-system bills should be performed but required that methodology be modified so that the sales have the same priority for purposes of energy allocation as joint account sales. The FERC reversed the ALJ’s decision that any payments by Entergy Arkansas should be reduced by 20%. The FERC also reversed the ALJ’s decision that adjustments to other System Agreement service schedules and excess bandwidth payments should not be taken into account when calculating the payments to be made by Entergy Arkansas. The FERC held that such adjustments and excess bandwidth payments should be taken into account but ordered further proceedings before an ALJ to address whether a cap on any reduction due to bandwidth payments was necessary and to implement the other adjustments to the calculation methodology.

The hearing required by the FERC’s second April 2016 order was held in May 2017. In July 2017 the ALJ issued an initial decision addressing whether a cap on any reduction due to bandwidth payments was necessary and whether to implement the other adjustments to the calculation methodology. In August 2017 the Utility operating companies, the LPSC, the APSC, and FERC staff filed individual briefs on exceptions challenging various aspects of the initial decision. In September 2017 the Utility operating companies, the LPSC, the APSC, the MPSC, the City Council, and FERC staff filed separate briefs opposing exceptions taken by various parties.

Based on testimony previously submitted in the case and its assessment of the April 2016 FERC orders, in the first quarter 2016, Entergy Arkansas recorded a liability of $87 million, which included interest, for its estimated increased costs and payment to the other Utility operating companies, and a deferred fuel regulatory asset of $75 million. Following its assessment of the course of the proceedings, including the FERC’s denial of rehearing in November 2017 described above, in the fourth quarter 2017, Entergy Arkansas recorded an additional liability of $35 million and a regulatory asset of $31 million.

In October 2018 the FERC issued an order addressing the ALJ’s July 2017 initial decision. The FERC reversed the ALJ’s decision to cap the reduction in Entergy Arkansas’s payment to account for the increased bandwidth payments that Entergy Arkansas made to the other operating companies. The FERC also reversed the ALJ’s decision that Grand Gulf sales from January through September 2000 should be included in the calculation of Entergy Arkansas’s payment. The FERC affirmed on other grounds the ALJ’s rejection of the LPSC’s claim that certain joint account sales should be accounted for as part of the calculation of Entergy Arkansas’s payment. In November 2018 the LPSC requested rehearing of the FERC’s October 2018 decision. In December 2019 the FERC denied the LPSC’s request for rehearing.

In December 2018, Entergy made a compliance filing in response to the FERC’s October 2018 order. The compliance filing provided a final calculation of Entergy Arkansas’s payments to the other Utility operating companies, including interest. Refunds and interest, totaling $135 million, were paid by Entergy Arkansas to the other operating companies in December 2018.

Entergy Arkansas previously recognized a regulatory asset with a balance of $116 million as of December 31, 2018 for a portion of the payments due as a result of this proceeding.

The FERC’s opportunity sales orders were appealed to the D.C. Circuit. In February 2020 all of the appeals were consolidated and in April 2020 the D.C. Circuit established a briefing schedule. Briefing was completed in September 2020 and oral argument was heard in December 2020. In July 2021 the D.C. Circuit issued a decision denying all of the petitions for review filed in response to the FERC’s opportunity sales orders.

In May 2019, Entergy Arkansas filed an application and supporting testimony with the APSC requesting approval of a special rider tariff to recover the costs of these payments from its retail customers over a 24-month period. In January 2020 the Attorney General and Arkansas Electric Energy Consumers, Inc. filed testimony opposing the recovery by Entergy Arkansas of the opportunity sales payment but also claiming that certain components of the payment should be segregated and refunded to customers. In March 2020, Entergy Arkansas filed rebuttal testimony.

In July 2020 the APSC issued a decision finding that Entergy Arkansas’s application is not in the public interest. The order also directed Entergy Arkansas to refund to its retail customers within 30 days of the order the FERC-determined over-collection of $13.7 million, plus interest, associated with a recalculated bandwidth remedy. In addition to these primary findings, the order also denied the Attorney General’s request for Entergy Arkansas to prepare a compliance filing detailing all of the retail impacts from the opportunity sales and denied a request by the Arkansas Electric Energy Consumers to recalculate all costs using the revised responsibility ratio. The refunds were issued in the August 2020 billing cycle. Entergy Arkansas believed its actions were prudent and, therefore, the costs, including the $13.7 million, plus interest, were recoverable, and in September 2020, Entergy Arkansas filed a complaint in the U.S. District Court for the Eastern District of Arkansas challenging the APSC’s order denying Entergy Arkansas’s request to recover the costs of these payments.

In March 2024 the U.S. District Court for the Eastern District of Arkansas issued a judgment in favor of the APSC and against Entergy Arkansas. In March 2024 Entergy Arkansas filed a notice of appeal and a motion to expedite oral arguments with the United States Court of Appeals for the Eighth Circuit and the court granted the motion to expedite. Briefing to the United States Court of Appeals for the Eighth Circuit concluded in July 2024 and oral arguments concluded in September 2024. As a result of the adverse decision by the U.S. District Court for the Eastern District of Arkansas, Entergy Arkansas concluded that it could no longer support the recognition of its $131.8 million regulatory asset reflecting the previously-expected recovery of a portion of the costs at issue in the opportunity sales proceeding and recorded a $131.8 million ($99.1 million net-of-tax) charge to earnings in first quarter 2024. In December 2024 the United States Court of Appeals for the Eighth Circuit affirmed the decision of the U.S. District Court for the Eastern District of Arkansas, and Entergy Arkansas filed a petition for rehearing en banc. In January 2025 the United States Court of Appeals for the Eighth Circuit denied Entergy Arkansas’s petition. In April 2025, Entergy Arkansas filed a petition for certiorari with the United States Supreme Court. In June 2025 the United States Supreme Court denied Entergy Arkansas’s petition for certiorari.

Net Metering Legislation

After the passage of an Arkansas net metering law that was enacted effective July 2019, the APSC approved numerous applications allowing Entergy Arkansas customers to enter into purchase power agreements with third parties and to utilize these purchase power agreements to offset power usage by Entergy Arkansas, despite the lack of proximity between the purchase power agreement and the end-use customer. The APSC also allowed the aggregation of accounts by net metering customers. These decisions by the APSC created subsidies in favor of eligible net metering customers to the detriment of non-participating customers. The level of this subsidy grew as additional net metering applications were approved by the APSC. The size and number of customers eligible under the 2019 law present a risk of loss of load and shifting of costs to customers.

Another Arkansas law was enacted effective March 2023 that revised the billing arrangements for net metering facilities in order to reduce the cost shift to non-net metering customers. The new law also imposes a new limit of 5 MW for future net metering facilities, allows utilities to recover net metering credits in the same manner as fuel, and grandfathers certain net metering facilities that are online or in process to be online by September 2024. As of October 2024, new net metering facilities are subject to two-channel billing. Because of the new law, in May 2023, the APSC closed its prior cost-shifting proceeding and grandfathering rulemaking relating to the prior net metering rate structure. Under the new law, the APSC had to approve revisions to utilities’ net metering tariffs to conform to the new law no later than December 2023. The APSC opened a new rulemaking in April 2023 to consider implementation of the new law and tariffs. In October 2023 the APSC issued new net metering rules to conform to the new law, and utilities, including Entergy Arkansas, filed revised net metering tariffs to comply with the new rules on October 16, 2023. Entergy Arkansas’s revised net metering tariff was approved by the APSC in December 2023.

Industrial and Commercial Customers

Entergy Arkansas’s large industrial and commercial customers continually explore ways to reduce their energy costs. Entergy Arkansas 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 Arkansas’s industrial customer base. Entergy Arkansas actively participates in economic development, customer retention, and reclamation activities to increase industrial and commercial demand from both new and existing customers.

Federal Regulation

See the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.

Nuclear Matters

Entergy Arkansas owns and, through an affiliate, operates the ANO 1 and 2 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 Arkansas’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. In the event of an unanticipated early shutdown of either ANO 1 or 2, Entergy Arkansas may be required to file with the APSC a rate mechanism to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. ANO 1’s operating license expires in 2034 and ANO 2’s operating license expires in 2038. In November 2025, Entergy Arkansas notified the NRC of its intent to submit applications to further extend the operating licenses for ANO 1 and 2. Entergy Arkansas expects to submit the renewal applications for ANO 1 by the end of fourth quarter 2029 and for ANO 2 by the end of fourth quarter 2033.

Environmental Risks

Entergy Arkansas’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Arkansas is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.

Critical Accounting Estimates

The preparation of Entergy Arkansas’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 Arkansas’s financial position, results of operations, or cash flows.

Nuclear Decommissioning Costs

See “Nuclear Decommissioning Costs” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates inherent in accounting for nuclear decommissioning costs.

Utility Regulatory Accounting

See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.

Taxation and Uncertain Tax Positions

See “Taxation and Uncertain Tax Positions” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.

Qualified Pension and Other Postretirement Benefits

Entergy Arkansas’s qualified pension and other postretirement reported costs, 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. See “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. 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.

Cost Sensitivity

The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).

The following chart reflects the sensitivity of postretirement benefits cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).

Each fluctuation above assumes that the other components of the calculation are held constant.

Costs and Employer Contributions

Total qualified pension cost for Entergy Arkansas in 2025 was $20.9 million, including $1.5 million in settlement costs. Entergy Arkansas anticipates 2026 qualified pension cost to be $16.5 million. Entergy Arkansas contributed $35.5 million to its qualified pension plans in 2025 and estimates pension contributions will be approximately $29.7 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.

Total postretirement health care and life insurance benefit income for Entergy Arkansas in 2025 was $6.8 million. Entergy Arkansas expects 2026 postretirement health care and life insurance benefit income of approximately $9.4 million. Entergy Arkansas contributed $1.1 million to its other postretirement plans in 2025 and estimates that 2026 contributions will be approximately $710 thousand.

Other Contingencies

See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.

See the “New Accounting Pronouncements” section of Note 1 to the financial statements for a discussion of new accounting pronouncements.

To the member and Board of Directors of

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Entergy Arkansas, LLC and Subsidiaries (the “Company”) as of December 31, 2025 and 2024, the related consolidated statements of income, cash flows and changes in equity (pages 348 through 352 and applicable items in pages 53 through 246), for each of the three years in the period ended December 31, 2025, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates 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 matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Rate and Regulatory Matters — Entergy Arkansas, LLC and Subsidiaries — Refer to Note 2 to the financial statements

The Company is subject to rate regulation by the Arkansas Public Service Commission (the “APSC”), which has jurisdiction with respect to the rates of electric companies in Arkansas, and to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). 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 Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the APSC and the FERC set the rates the Company is allowed to charge customers based on allowable costs, including a reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company 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 Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the APSC and the FERC 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 APSC and the FERC, 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 APSC and the FERC, 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 Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
• We read relevant regulatory orders issued by the APSC and the FERC for the Company to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the APSC’s and the FERC’s 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 Company’s filings with the APSC and the FERC and orders issued, and considered the filings with the APSC and the FERC by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.
• We obtained an analysis from management and support from 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.

/s/ DELOITTE & TOUCHE LLP

ENTERGY ARKANSAS, LLC AND SUBSIDIARIES

CONSOLIDATED INCOME STATEMENTS

(In Thousands)

348

ENTERGY ARKANSAS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

349

ENTERGY ARKANSAS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

(In Thousands)

350

ENTERGY ARKANSAS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY

(In Thousands)

351

ENTERGY ARKANSAS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

For the Years Ended December 31, 2025, 2024, and 2023

(In Thousands)

352

Winter Storm Fern

See the “Winter Storm Fern” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Winter Storm Fern. Entergy Louisiana’s preliminary estimate for the cost of mobilizing crews and restoring power is approximately $240 million to $300 million, with the majority of the costs being capital. Natural gas purchases for Entergy Louisiana for January 2026 are $256 million compared to natural gas purchases for January 2025 of $115 million.

Results of Operations

2025 Compared to 2024

Net Income

Net income increased $222.1 million primarily due to expenses of $151.5 million ($110.7 million net-of-tax), recorded 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. Also contributing to the increase was higher other income, higher volume/weather, and a higher return on construction work in progress for certain utility plant investments. The increase was partially offset by higher interest expense, higher other operation and maintenance expenses, and higher depreciation and amortization expenses. See Note 2 to the financial statements for discussion of the agreement in principle and the subsequently filed global stipulated settlement agreement.

Operating Revenues

Following is an analysis of the change in operating revenues comparing 2025 to 2024:

(In Millions)

Entergy Louisiana’s 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 resulting from an increase in demand from large industrial customers, primarily in the petroleum refining, chlor-alkali, industrial gases, and petrochemicals industries.

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 investment, which is recognized as the related costs are incurred.

The retail electric price variance is primarily due to 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. The decrease was partially offset by increases in Entergy Louisiana’s formula rate plan revenues, including an increase in the distribution recovery mechanism, effective September 2024. See Note 2 to the financial statements for discussion of the formula rate plan proceedings.

The effect of sale of natural gas distribution business variance represents the decrease in operating revenues resulting from the absence of natural gas revenues following the sale of the natural gas distribution business on July 1, 2025. See Note 14 to the financial statements for discussion of the sale of Entergy Louisiana’s natural gas distribution business on July 1, 2025.

Total electric energy sales for Entergy Louisiana for the years ended December 31, 2025 and 2024 are as follows:

See Note 19 to the financial statements for additional discussion of Entergy Louisiana’s operating revenues.

Other Income Statement Variances

Nuclear refueling outage expenses decreased primarily due to the amortization of lower costs associated with the most recent outages as compared to previous outages.

Other operation and maintenance expenses increased primarily due to:

• an increase of $19.7 million in power delivery expenses primarily due to a higher scope of work performed in 2025 as compared to 2024 and higher vegetation maintenance costs;
• the expensing of $10.8 million of project costs associated with the Bayou Power Station project following Entergy Louisiana’s election in 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 the Bayou Power Station project;
• an increase of $10.1 million in bad debt expense;
• an increase of $7.7 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 $5.6 million in transmission costs allocated by MISO. See Note 2 to the financial statements for discussion of the recovery of these costs;
• an increase of $5.1 million in loss provisions; and
• several individually insignificant items.

The increase was partially offset by:

• an $18.6 million gain, recorded in 2025, resulting from the sale of the natural gas distribution business on July 1, 2025. See Note 14 to the financial statements for discussion of the sale of Entergy Louisiana’s natural gas distribution business on July 1, 2025;
• contract costs of $17.4 million in 2024 related to operational performance, customer service, and organizational health initiatives; and
• a decrease of $13.3 million in nuclear generation expenses primarily due to a lower scope of work performed in 2025 as compared to 2024.

Taxes other than income taxes increased primarily due to increases in ad valorem taxes resulting from higher assessments.

Depreciation and amortization expenses increased primarily due to additions to plant in service and an increase in nuclear depreciation rates effective September 2024 and September 2025 in accordance with the global stipulated settlement agreement approved by the LPSC in August 2024. See Note 2 to the financial statements for discussion of the global stipulated settlement agreement.

Other regulatory charges (credits) - net includes regulatory charges of $150.2 million, recorded 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. In addition, Entergy Louisiana 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. See Note 2 to the financial statements for discussion of the agreement in principle and the subsequently filed global stipulated settlement agreement.

Other income increased primarily due to:

• an increase of $43.3 million in the amortization of tax gross ups on customer advances, including customer advances for construction;
• an increase of $25.8 million in interest earned on money pool investments;
• an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2025; and
• a $17.1 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 $17.5 million in affiliated dividend income from affiliated preferred membership interests related to storm cost securitizations. See Note 2 to the financial statements for discussion of the storm cost securitizations.

Interest expense increased primarily due to the issuance of $750 million of 5.80% Series mortgage bonds in January 2025, the issuance of $700 million of 5.15% Series mortgage bonds in August 2024, and an increase of $38.4 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.

The effective income tax rates were 17.6% for 2025 and 20.2% 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.

2024 Compared to 2023

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of Entergy Louisiana’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.

Income Tax Legislation and Regulation

See the “Income Tax Legislation and Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of income tax legislation and regulation.

Sale of Natural Gas Distribution Business

See the “Dispositions - Natural Gas Distribution Businesses” section in Note 14 to the financial statements for discussion of the sale of the Entergy Louisiana natural gas distribution business.

Cash Flow

Cash flows for the years ended December 31, 2025, 2024, and 2023 were as follows:

(In Thousands)

356

2025 Compared to 2024

Operating Activities

Net cash flow provided by operating activities increased $494.2 million in 2025 primarily due to:

• higher collections from customers;
• an increase of $257.7 million in receipts from advance payments related to customer agreements in 2025, which are recorded as current liabilities and included within changes in other working capital accounts;
• net cash proceeds of $170.1 million received by Entergy Louisiana in 2025, including $198.3 million in proceeds received from Entergy Louisiana’s transfer of 2024 nuclear production tax credits to third parties in 2025 and net cash payments of $28.2 million to affiliates in 2025 in accordance with the Unit Power Sales Agreement and the MSS-4 replacement tariff related to the transfer of 2024 nuclear production tax credits by Entergy Louisiana and affiliates to third parties in 2025. See Note 3 to the financial statements for discussion of the nuclear production tax credits;
• income tax refunds of $146 million in 2025 compared to income tax payments of $16.9 million in 2024. Entergy Louisiana received income tax refunds in 2025 and made income tax payments in 2024, each in accordance with Entergy’s tax allocation agreement; and
• a decrease of $18.4 million in storm spending primarily due to Hurricane Francine restoration efforts in 2024.

The increase was partially offset by:

• the timing of payments to vendors;
• the receipt of $80.2 million in settlement proceeds in December 2024 as a result of the System Energy settlement with the LPSC. See Note 2 to the financial statements for discussion of the System Energy settlement agreement with the LPSC;
• an increase of $47.2 million in interest paid;
• an increase of $24.5 million in spending on nuclear refueling outages in 2025 as compared to 2024;
• $21.3 million received in third quarter 2024 related to the wind up of the NISCO partnership. See Note 9 to the financial statements for a discussion of the NISCO partnership; and
• higher fuel and purchased power payments. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery.

Investing Activities

Net cash flow used in investing activities increased $1,365.4 million in 2025 primarily due to:

• an increase of $661.5 million in non-nuclear generation construction expenditures primarily due to higher spending on the Franklin Farms Power Station Units 1 and 2 project, the Waterford 5 Power Station project, and the Sterlington facility project;
• an increase of $347 million in transmission construction expenditures primarily due to higher capital expenditures as a result of increased development in Entergy Louisiana’s service area, including increased investment in the resilience of the transmission system, higher spending on the Amite South transmission projects, and increased spending on various other transmission projects in 2025;
• an increase of $286 million in distribution construction expenditures primarily due to increased investment in the resilience of the distribution system, partially offset by lower capital expenditures for storm restoration in 2025. The decrease in storm restoration expenditures is primarily due to decreased spending on Hurricane Francine restoration efforts in 2025 as compared to 2024;
• an increase of $126.9 million in nuclear construction expenditures primarily due to increased spending on various nuclear projects in 2025;
• an increase in cash used of $80.8 million as a result of fluctuations in nuclear fuel activity 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;
• cash collateral of $58.4 million posted in 2025 to support Entergy Louisiana’s obligations to MISO; and
• payments totaling $41.4 million to Entergy Texas for the transfer of assets related to the Segno Solar and Votaw Solar facilities to Entergy Louisiana in 2025. See “Uses and Sources of Capital - Segno Solar and Votaw Solar” below for further discussion of the facilities and transfer.

The increase was partially offset by the receipt of $200 million in proceeds from the sale of the natural gas distribution business on July 1, 2025 and the receipt of $33.5 million from the storm reserve escrow account in first quarter 2025. See Note 14 to the financial statements for discussion of the sale of Entergy Louisiana’s natural gas distribution business on July 1, 2025. See Note 2 to the financial statements for a discussion of the storm reserve funds.

Financing Activities

Entergy Louisiana’s financing activities provided $585.7 million of cash in 2025 as compared to using $411.1 million of cash in 2024 primarily due to the following activity:

• the repayment, prior to maturity, of $1 billion of 0.95% Series mortgage bonds in August 2024;
• the issuance of $750 million of 5.80% Series mortgage bonds in January 2025;
• an increase of $683.9 million in net customer advances for construction related to transmission, distribution, and generator interconnection agreements;
• the repayment, prior to maturity, of $400 million of 5.40% Series mortgage bonds in April 2024;
• a decrease of $102.9 million in common equity distributions paid in 2025 in order to maintain Entergy Louisiana’s capital structure and for future general corporate purposes;
• net long-term borrowings of $56.4 million in 2025 compared to net repayments of $38.5 million in 2024 on the nuclear fuel company variable interest entities’ credit facilities;
• the repayment, prior to maturity, of $110 million of 3.78% Series mortgage bonds in March 2025;
• the repayment, prior to maturity, of $190 million of 3.78% Series mortgage bonds in March 2025;
• the issuance of $700 million of 5.15% Series mortgage bonds in August 2024;
• the issuances of $500 million of 5.35% Series mortgage bonds and $700 million of 5.70% Series mortgage bonds in March 2024; and
• money pool activity.

Decreases in Entergy Louisiana’s payable to the money pool are a use of cash flow, and Entergy Louisiana’s payable to the money pool decreased $156.2 million in 2024. The money pool is an intercompany cash management program that makes possible intercompany borrowing and lending arrangements, and the money pool and other borrowing arrangements are designed to reduce the Registrant Subsidiaries’ dependence on external short-term borrowings.

See Note 5 to the financial statements for additional details of long-term debt.

2024 Compared to 2023

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy Louisiana’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.

Capital Structure

Entergy Louisiana’s debt to capital ratio is shown in the following table.

Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, finance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt and equity. Net capital consists of capital less cash and cash equivalents. Entergy Louisiana uses the debt to capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Louisiana’s financial condition. The net debt to net capital ratio is a non-GAAP measure. Entergy Louisiana also uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Louisiana’s financial condition because net debt indicates Entergy Louisiana’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.

Entergy Louisiana seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a distribution, to the extent funds are legally available to do so, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Louisiana may issue incremental debt or reduce distributions, or both, to maintain its capital structure. In addition, in certain infrequent circumstances, such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reduced distributions, Entergy Louisiana may receive equity contributions to maintain its capital structure.

Uses of Capital

Entergy Louisiana requires capital resources for:

• construction and other capital investments;
• debt maturities or retirements;
• working capital purposes, including the financing of fuel and purchased power costs; and
• distribution and interest payments.

Following are the amounts of Entergy Louisiana’s planned construction and other capital investments.

(In Millions)

In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Louisiana includes investments in generation projects to modernize, decarbonize, expand, and diversify Entergy

Louisiana’s portfolio, as well as to support customer growth, including 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, and other new generation resources; investments in River Bend and Waterford 3; distribution and Utility support spending to improve reliability, resilience, and customer experience; transmission spending to improve reliability and resilience while also supporting customer growth and renewables expansion; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, governmental actions, including the trade-related governmental actions discussed below, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital, including any changes to governmental programs, such as loans, grants, guarantees, and other subsidies.

Recent announcements of changes to international trade policy and tariffs and further similar changes may impact Entergy Louisiana’s business, operations, results of operations, and liquidity and capital resources. Potential impacts may include increases in costs associated with Entergy Louisiana’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 Louisiana’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 Louisiana’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.

Entergy Louisiana has 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 its current and planned capital projects. Entergy Louisiana 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 its current and planned capital projects.

Following are the amounts of Entergy Louisiana’s existing debt and lease obligations (includes estimated interest payments).

(In Millions)

(a) Long-term debt is discussed in Note 5 to the financial statements.

(b) Lease obligations are discussed in Note 10 to the financial statements.

Other Obligations

Entergy Louisiana currently expects to contribute approximately $41.6 million to its qualified pension plans and approximately $14.1 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 Louisiana has $425.5 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.

In addition, Entergy Louisiana enters into fuel and purchased power agreements that contain minimum purchase obligations. Entergy Louisiana has rate mechanisms in place to recover fuel, purchased power, and associated costs incurred under these purchase obligations. See Note 8 to the financial statements for discussion of Entergy Louisiana’s divestiture from the Unit Power Sales Agreement and its obligations under the Vidalia purchased power agreement.

As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy Louisiana pays distributions from its earnings at a percentage determined monthly.

Renewables

2021 Solar Certification and the Geaux Green Option

In November 2021, Entergy Louisiana filed an application seeking LPSC approval and certification of the addition of four new solar photovoltaic resources with a combined nameplate capacity of 475 MW (the 2021 Solar Portfolio) and the implementation of a new green tariff, the Geaux Green Option (Rider GGO). The 2021 Solar Portfolio consisted of four resources that were expected to provide $242 million in net benefits to Entergy Louisiana’s customers. These resources, all of which would be constructed in Louisiana, include (i) the Vacherie Facility, a 150 MW resource in St. James Parish; (ii) the Sunlight Road Facility, a 50 MW resource in Washington Parish; (iii) the St. Jacques Facility, a 150 MW resource in St. James Parish; and (iv) the Elizabeth Facility, a 125 MW resource in Allen Parish. The St. Jacques Facility would be acquired through a build-own-transfer agreement; the remaining resources involve power purchase agreements. The Sunlight Road Facility and the Elizabeth Facility each achieved commercial operation in 2024, and the Vacherie Facility and the St. Jacques Facility originally had estimated in service dates in 2025. The filing proposed to recover the costs of the power purchase agreements through the fuel adjustment clause and the formula rate plan and the acquisition costs through the formula rate plan.

The proposed Rider GGO was a voluntary rate schedule designed to enhance Entergy Louisiana’s ability to help customers meet their sustainability goals by allowing customers to align some or all of their electricity requirements with renewable energy from the resources. Because subscription fees from Rider GGO participants are expected to help offset the cost of the resources, the design of Rider GGO was also designed to preserve the benefits of the 2021 Solar Portfolio for non-participants by providing them with the reliability and capacity benefits of locally-sited solar generation at a discounted price.

In March 2022 direct testimony from Walmart, the Louisiana Energy Users Group (LEUG), and the LPSC staff was filed. Each party recommended that the LPSC approve the resources proposed in Entergy Louisiana’s application, and the LPSC staff witness indicated that the process through which Entergy Louisiana solicited or obtained the proposals for the resources complied with applicable LPSC orders. The LPSC staff and LEUG’s witnesses made recommendations to modify the proposed Rider GGO and Entergy Louisiana’s proposed rate relief. In April 2022 the LPSC staff and LEUG filed cross-answering testimony concerning each other’s proposed modifications to Rider GGO and the proposed rate recovery. Entergy Louisiana filed rebuttal testimony in June 2022. In August 2022 the parties reached a settlement certifying the 2021 Solar Portfolio and approving implementation of Rider GGO. In September 2022 the LPSC approved the settlement. Following the LPSC approval, the St. James Parish council issued a moratorium on new land use permits for solar facilities until the later of March 2023 or the completion of an environmental and economic impact study. In November 2023, St. James Parish lifted the moratorium and adopted an ordinance modifying the parish’s land use plan to establish solar as an approved land use and defining corresponding solar regulations. In March 2024 the project developer submitted a solar energy facility farm permit application to the St. James Parish planning commission to request approval for the Vacherie and St. Jacques Facilities. In June 2024 the St. James Parish council denied the application and following this denial, the project developer and one of the project’s ground lessors filed separate lawsuits seeking to overturn the council’s decision. The council’s decision was subsequently affirmed by the Louisiana 23rd Judicial District Court. Entergy Louisiana is no longer pursuing the addition of resources through an acquisition of the St. Jacques Facility or through a power purchase agreement with the Vacherie Facility.

2022 Solar Portfolio and Expansion of the Geaux Green Option

In February 2023, Entergy Louisiana filed an application seeking LPSC approval and certification of the Iberville/Coastal Prairie facility, which will provide 175 MW of capacity through a PPA with a third party, and the Sterlington facility, a 49 MW self-build project located near the deactivated Sterlington power plant (the 2022 Solar Portfolio). Entergy Louisiana is seeking to include these resources within the portfolio supporting the Rider GGO rate schedule to help fulfill customer interest in access to renewable energy. Entergy Louisiana has requested the costs of these facilities, as offset by Rider GGO revenues, be deemed eligible for recovery in accordance with the terms of the formula rate plan and fuel adjustment clause rate mechanisms that exist at the time the facilities are placed into service. In January 2024, the parties filed an uncontested stipulated settlement agreement on the key issues in the case, which stated that the 2022 Solar Portfolio should be constructed, found that Entergy Louisiana’s proposed cost recovery mechanisms were appropriate, and confirmed the resources’ eligibility for inclusion in Rider GGO. The settlement was approved by the LPSC in January 2024. The Sterlington facility achieved commercial operation in January 2026.

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.

Segno Solar and Votaw Solar

In 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.

Cypress Harvest Solar

In 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.

Other Generation and Transmission

Bayou Power Station

In 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.

Additional Generation and Transmission Resources

In 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 Projects

In 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 Station

In 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 Project

In 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 Station

In 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.

Resilience and Grid Hardening

In 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.

Sources of Capital

Entergy Louisiana’s sources to meet its capital requirements include:

• internally generated funds;
• cash on hand;
• the Entergy system money pool;
• storm reserve escrow accounts;
• debt or preferred membership interest issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
• capital contributions; and
• bank financing under new or existing facilities.

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,

Entergy Louisiana expects to continue, when economically feasible, to retire higher-cost debt and replace it with lower-cost debt if market conditions permit.

All debt and common and preferred membership interest issuances by Entergy Louisiana require prior regulatory approval. Debt issuances are also subject to requirements set forth in its bond indentures and other agreements. Entergy Louisiana has sufficient capacity under these tests to meet its foreseeable capital needs for the next twelve months and beyond.

Entergy Louisiana’s receivables from (payables to) the money pool were as follows as of December 31 for each of the following years.

(In Thousands)

See Note 4 to the financial statements for a description of the money pool.

Entergy Louisiana has a credit facility in the amount of $400 million scheduled to expire in June 2030. The credit facility includes fronting commitments for the issuance of letters of credit against $15 million of the borrowing capacity of the facility. As of December 31, 2025, there were no cash borrowings and no letters of credit outstanding under the credit facility. In addition, Entergy Louisiana is a party to two uncommitted letter of credit facilities as a means to post collateral to support its obligations to MISO. As of December 31, 2025, $164.1 million in letters of credit were outstanding under Entergy Louisiana’s uncommitted letter of credit facilities. See Note 4 to the financial statements for additional discussion of the credit facilities.

The Entergy Louisiana nuclear fuel company variable interest entities have two separate credit facilities, each in the amount of $105 million and scheduled to expire in June 2027. As of December 31, 2025, $50.3 million in loans were outstanding under the credit facility for the Entergy Louisiana River Bend nuclear fuel company variable interest entity and $43.7 million in loans were outstanding under the Entergy Louisiana Waterford nuclear fuel company variable interest entity credit facility. See Note 4 to the financial statements for additional discussion of the nuclear fuel company variable interest entity credit facilities.

Entergy Louisiana obtained authorizations from the FERC through January 2027 for the following:

• short-term borrowings not to exceed an aggregate amount of $450 million at any time outstanding;
• long-term borrowings and security issuances; and
• borrowings by its nuclear fuel company variable interest entities.

See Note 4 to the financial statements for further discussion of Entergy Louisiana’s short-term borrowing limits.

State and Local Rate Regulation and Fuel-Cost Recovery

The rates that Entergy Louisiana charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Louisiana is regulated, and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the LPSC, is primarily responsible for approval of the rates charged to customers.

Retail Rates - Electric

Filings with the LPSC

2022 Formula Rate Plan Filing

In May 2023, Entergy Louisiana filed its formula rate plan evaluation report for its 2022 calendar year operations. The 2022 test year evaluation report produced an earned return on common equity of 8.33%, requiring an approximately $70.7 million increase to base rider revenue. Due to a cap for the 2021 and 2022 test years, however, base rider formula rate plan revenues were only increased by approximately $4.9 million, resulting in a revenue deficiency of approximately $65.9 million and providing for prospective return on common equity opportunity of approximately 8.38%. Other changes in formula rate plan revenue driven by increases in capacity costs, primarily legacy capacity costs, additions eligible for recovery through the transmission recovery mechanism and distribution recovery mechanism, and higher sales during the test period were offset by reductions in net MISO costs as well as credits for FERC-ordered refunds. Also included in the 2022 test year distribution recovery mechanism revenue requirement was a $6 million credit relating to the distribution recovery mechanism performance accountability standards and requirements. In total, the net increase in formula rate plan revenues, including base formula rate plan revenues inside the formula rate plan bandwidth and subject to the cap, as well as other formula rate plan revenues outside of the bandwidth, was $85.2 million. In August 2023 the LPSC staff filed a list of objections/reservations, including outstanding issues from the test years 2017-2021 formula rate plan filings, the calculation of certain refunds from System Energy, and certain calculations relating to the tax reform adjustment mechanism. Subject to LPSC review, the resulting net increase in formula rate plan revenues of $85.2 million became effective for bills rendered during the first billing cycle of September 2023, subject to refund. In September 2024 the LPSC issued an order approving a settlement that resolved, with prejudice, all other issues identified by the staff in the matter and closed the docket. See “2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request” below for further discussion.

2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request

In August 2023, Entergy Louisiana filed an application for approval of a regulatory blueprint necessary for it to strengthen the electric grid for the State of Louisiana, which contained a dual-path request to update rates through either: (1) extension of Entergy Louisiana’s current formula rate plan (with certain modifications) for three years (the Rate Mitigation Proposal), which was Entergy Louisiana’s recommended path; or (2) implementation of rates resulting from a cost-of-service study (the Rate Case path). The application complied with Entergy Louisiana’s previous formula rate plan extension order requiring that for Entergy Louisiana to obtain another extension of its formula rate plan that included a rate reset, Entergy Louisiana would need to submit a full cost-of-service rate case. Entergy Louisiana’s filing supported the need to extend Entergy Louisiana’s formula rate plan with credit supportive mechanisms needed to facilitate investment in the distribution, transmission, and generation functions.

In July 2024, Entergy Louisiana reached an agreement in principle with the LPSC staff and the intervenors in the proceeding and filed with the LPSC a joint motion to suspend the procedural schedule to allow for all parties to finalize a stipulated settlement agreement.

In August 2024, Entergy Louisiana and the LPSC staff jointly filed a global stipulated settlement agreement for consideration by the LPSC with key terms as follows:

• continuation of the formula rate plan for 2024-2026 (test years 2023-2025);
• a base formula rate plan revenue increase of $120 million for test year 2023, effective for rates beginning September 2024;
• a $140 million cumulative cap on base formula rate plan revenue increases, if needed, for test years 2024 and 2025, excluding outside the bandwidth items;
• $184 million of customer rate credits to be given over two years, including increasing customer sharing of income tax benefits resulting from the 2016-2018 IRS audit, to resolve any remaining disputed issues stemming from formula rate plan test years prior to test year 2023, including but not limited to the investigation into Entergy Services costs billed to Entergy Louisiana. As discussed in Note 3 to the financial statements, a $38 million regulatory liability was recorded in 2023 in connection with the 2016-2018 IRS audit;
• $75.5 million of customer rate credits, as provided for in the System Energy global settlement, to be credited over three years subject to and conditioned upon FERC approval of the System Energy global settlement, which was approved in November 2024. See “Complaints Against System Energy – System Energy Settlement with the LPSC” in Note 2 to the financial statements for further details of the System Energy global settlement;
• $5.8 million of customer rate credits provided for in the Entergy Louisiana formula rate plan global settlement agreement approved by the LPSC in November 2023 credited over one year. See “Formula Rate Plan Global Settlement” below for further discussion of the settlement;
• an increase in the allowed midpoint return on common equity from 9.5% to 9.7%, with a bandwidth of 40 basis points above and below the midpoint, for the extended term of the formula rate plan, except that for test year 2023 in which the authorized return on common equity shall have no bearing on the change in base formula rate plan revenue described above and, for test year 2024, any earnings above the authorized return on common equity shall be returned to customers through a credit;
• an increase in nuclear depreciation rates by $15 million in each of the 2023, 2024, and 2025 test years outside of the formula rate plan bandwidth calculation; and
• for the transmission recovery mechanism and the distribution recovery mechanism, no change to the existing floors, but the caps for both would be $350 million for test year 2023, $375 million for test year 2024, and $400 million for test year 2025. Transmission projects filed with the LPSC will be exempt from the transmission recovery mechanism cap.

The global stipulated settlement agreement was unanimously approved by the LPSC in August 2024 and an order was issued by the LPSC in September 2024 reflecting the approval of the settlement.

Based on the July 2024 agreement in principle, in second quarter 2024 Entergy Louisiana recorded expenses of $151 million ($112 million net-of-tax) primarily consisting of regulatory charges to reflect the effects of the agreement in principle.

Formula Rate Plan Global Settlement

In October 2023 the LPSC staff and Entergy Louisiana reached a global settlement which resolved all outstanding issues related to the 2017, 2018, and 2019 formula rate plan filings and resolved certain issues with respect to the 2020 and 2021 formula rate plan filings. The settlement was approved by the LPSC in November 2023. The settlement resulted in a one-time cost of service credit to customers of $5.8 million, allowed Entergy Louisiana to retain approximately $6.2 million of securitization over-collection as recovery of a regulatory asset associated with late fees related to the 2016 Baton Rouge flood, and resulted in Entergy Louisiana recording the reversal of a $105.6 million regulatory liability, primarily associated with the Hurricane Isaac securitization, initially recognized in 2017 as a result of the Tax Cuts and Jobs Act.

2023 Formula Rate Plan Filing

In August 2024, pursuant to the global stipulated settlement agreement approved by the LPSC also in August 2024, Entergy Louisiana filed its formula rate plan evaluation report for its 2023 calendar year operations. Consistent with the global stipulated settlement agreement, the filing reflected a 9.7% allowed return on common equity with a bandwidth of 40 basis points above and below the midpoint. For the 2023 test year, however, the bandwidth provisions of the formula rate plan were temporarily suspended and, pursuant to the terms of the global stipulated settlement agreement, Entergy Louisiana implemented the September 2024 formula rate plan rate adjustments effective with the first billing cycle of September 2024. Those adjustments included a $120 million increase in base rider formula rate plan revenue and a $101.8 million one-time incremental net decrease consistent with the terms of the global stipulated settlement. The formula rate plan rate adjustments reflected in the evaluation report also include a redetermination of the transmission recovery mechanism, the distribution recovery mechanism, the additional capacity mechanism, the tax adjustment mechanism, the MISO cost recovery mechanism, and other one-time adjustments. In January 2025, Entergy Louisiana and the LPSC filed a joint report indicating that no disputed issues remained in the proceeding and requesting that the LPSC issue an order accepting Entergy Louisiana’s evaluation report and, ultimately, resolving this matter. In March 2025 the LPSC issued an order accepting the evaluation report.

In December 2024, pursuant to the terms of the global stipulated settlement agreement, Entergy Louisiana filed an interim rate adjustment for the 2023 test year reflecting the return of $25.1 million of refunds from the System Energy settlement with the LPSC to customers from January through August 2025. In February 2025, pursuant to the terms of the global stipulated settlement agreement, Entergy Louisiana filed a second interim rate adjustment for the 2023 test year reflecting the divestiture of Entergy Louisiana’s share of Grand Gulf capacity and energy, which was effective as of January 1, 2025. The second interim rate adjustment also reflected a revenue increase of $17.8 million for the recovery of Hurricane Francine costs as approved by the LPSC (on an interim basis). The second interim rate adjustment was implemented with the first billing cycle of March 2025. See further discussion of the Hurricane Francine proceeding in “Storm Cost Recovery Filings with Retail Regulators – Entergy Louisiana – Hurricane Francine” in Note 2 to the financial statements. See Note 8 to the financial statements for discussion of Entergy Louisiana’s divestiture from the Unit Power Sales Agreement.

2024 Formula Rate Plan Filing

In May 2025, Entergy Louisiana filed its formula rate plan evaluation report for its 2024 calendar year operations. Consistent with the global stipulated settlement agreement approved by the LPSC in August 2024, the filing reflected a 9.7% allowed return on common equity with a bandwidth of 40 basis points above and below the midpoint. For the test year 2024, however, any earnings above the allowed return on common equity were to be returned to customers through a credit, pursuant to the terms of the global stipulated settlement agreement. The 2024 test year evaluation produced an earned return on common equity of 9.98%, which was within the approved formula rate plan bandwidth, but above the allowed return on common equity, resulting in customer credits of $31.9 million which were returned to customers during September and October 2025.

Other changes in formula rate plan revenue were driven by higher nuclear depreciation rates, additions to transmission and distribution plant in service reflected through the transmission recovery mechanism and distribution recovery mechanism, and the expiration of customer credits related to the LPSC’s order, offset by increased customer credits resulting from an increase in net MISO revenues reflected through the MISO cost recovery mechanism and the reduction in the Louisiana corporate income tax rate effective January 1, 2025, reflected through the tax adjustment mechanism, as discussed below. Excluding the customer credit for earnings above the authorized return on common equity discussed above, the net result of these changes on an annualized basis was a $2 million increase in formula rate plan revenue.

As noted above, the 2024 evaluation report included the effects of the change in Louisiana state tax law that reduced the corporate income tax rate to a flat 5.5% (from the then-current highest marginal rate of 7.5%) effective

January 1, 2025. As such, the 2024 evaluation report reflected the calculation of current and deferred income tax expenses as well as the revaluation of accumulated deferred income taxes based on the income tax laws currently in effect. The 2024 evaluation report proposed that the rate effects associated with the revaluation of accumulated deferred income taxes, including the collection of any net accumulated deferred income tax deficiency and any related effects on rate base, should be reflected in the tax adjustment mechanism consistent with the treatment of similar Tax Cuts and Jobs Act and prior state tax change-related impacts. The effects of the change in tax law on Entergy Louisiana’s authorized return on rate base were also reflected in the 2024 evaluation report consistent with the treatment cited above, including a credit in the extraordinary cost change mechanism for the prospective change in Entergy Louisiana’s authorized return and a credit within the tax adjustment mechanism for over-collection of income tax expense through August 2025. Subject to LPSC review, the resulting changes from the 2024 formula rate plan evaluation report became effective for bills rendered during the first billing cycle of September 2025, subject to refund. In August 2025 the LPSC staff filed its errors and objections report, as required by the formula rate plan’s process, and found that Entergy Louisiana’s formula rate plan is in compliance with the LPSC’s requirements and the global stipulated settlement agreement. The LPSC staff reserved the right to determine whether Entergy Louisiana appropriately credited certain revenues to customers during the September and October 2025 billing cycles. In December 2025 the LPSC staff and Entergy Louisiana filed a joint report indicating that no unresolved, disputed issues existed and recommending that the LPSC accept the joint report, confirm that no outstanding issues existed, and close the docket. In January 2026 the LPSC issued an order accepting the joint report.

Fuel and purchased power cost recovery

Entergy Louisiana recovers electric fuel and purchased power costs for the billing month based upon the level of such costs incurred two months prior to the billing month. Entergy Louisiana’s purchased gas adjustments, which ceased following the sale of its natural gas distribution business on July 1, 2025, included estimates for the billing month adjusted by a surcharge or credit that arose from an annual reconciliation of fuel costs incurred with fuel cost revenues billed to customers, including carrying charges. See Note 14 to the financial statements for discussion of the sale of Entergy Louisiana’s natural gas distribution business on July 1, 2025.

In March 2020 the LPSC staff provided notice of an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s fuel adjustment clause for the period from 2016 through 2019. The LPSC staff issued its audit report in September 2021, and although certain internal record keeping recommendations were made, the LPSC staff did not recommend any disallowances. The next step is for the LPSC to issue its final report, but there is not a deadline or timing requirement associated with the issuance of the final report.

To mitigate high electric bills, primarily driven by high summer usage and elevated gas prices, Entergy Louisiana deferred approximately $225 million of fuel expense incurred in April, May, June, July, August, and September 2022 (as reflected on June, July, August, September, October, and November 2022 bills). These deferrals were included in the over/under calculation of the fuel adjustment clause, which was intended to recover the full amount of the costs included on a rolling twelve-month basis.

In January 2023 the LPSC staff provided notice of an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s fuel adjustment clause for the period from 2020 through 2022. Discovery is ongoing, and no audit report has been filed.

In June 2025 the LPSC staff provided notice of an audit of Entergy Louisiana’s purchased gas adjustment clause filings (for Entergy Louisiana’s gas operations). The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s purchased gas adjustment clause for the period from January 2023 through June 2025. Discovery is ongoing, and no audit report has been filed.

Industrial and Commercial Customers

Entergy Louisiana’s large industrial and commercial customers continually explore ways to reduce their energy costs. Entergy Louisiana 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 Louisiana’s industrial customer base. Entergy Louisiana actively participates in economic development, customer retention, and reclamation activities to increase industrial and commercial demand from both new and existing customers.

Federal Regulation

See the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.

Nuclear Matters

Entergy Louisiana owns and, through an affiliate, operates the River Bend and Waterford 3 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 Louisiana’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. In the event of an unanticipated early shutdown of River Bend or Waterford 3, Entergy Louisiana may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. Waterford 3’s operating license expires in 2044 and River Bend’s operating license expires in 2045.

Environmental Risks

Entergy Louisiana’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Louisiana is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.

Critical Accounting Estimates

The preparation of Entergy Louisiana’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 Louisiana’s financial position, results of operations, or cash flows.

Nuclear Decommissioning Costs

See “Nuclear Decommissioning Costs” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates inherent in accounting for nuclear decommissioning costs.

Utility Regulatory Accounting

See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.

Taxation and Uncertain Tax Positions

See “Taxation and Uncertain Tax Positions” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.

Qualified Pension and Other Postretirement Benefits

Entergy Louisiana’s qualified pension and other postretirement reported costs, 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. See “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. 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.

Cost Sensitivity

The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).

The following chart reflects the sensitivity of postretirement benefits cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).

Each fluctuation above assumes that the other components of the calculation are held constant.

Costs and Employer Contributions

Total qualified pension cost for Entergy Louisiana in 2025 was $16.9 million, including $6 million in settlement costs. Entergy Louisiana anticipates 2026 qualified pension cost to be $7.9 million. Entergy Louisiana contributed $41.3 million to its qualified pension plans in 2025 and estimates pension contributions will be approximately $41.6 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.

Total postretirement health care and life insurance benefit income for Entergy Louisiana in 2025 was $5.6 million, including $2.1 million in settlement and curtailment credits. Entergy Louisiana expects 2026 postretirement health care and life insurance benefit costs of approximately $5.3 million. Entergy Louisiana contributed $15.8 million to its other postretirement plans in 2025 and estimates that 2026 contributions will be approximately $14.1 million.

Other Contingencies

See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.

See the “New Accounting Pronouncements” section of Note 1 to the financial statements for a discussion of new accounting pronouncements.

To the member and Board of Directors of

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Entergy Louisiana, LLC and Subsidiaries (the “Company”) as of December 31, 2025 and 2024, the related consolidated statements of income, comprehensive income, cash flows, and changes in equity (pages 377 through 382 and applicable items in pages 53 through 246), for each of the three years in the period ended December 31, 2025, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates 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 matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Rate and Regulatory Matters — Entergy Louisiana, LLC and Subsidiaries — Refer to Note 2 to the financial statements

The Company is subject to rate regulation by the Louisiana Public Service Commission (the “LPSC”), which has jurisdiction with respect to the rates of electric companies in Louisiana, and to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). 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 Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the LPSC and the FERC set the rates the Company is allowed to charge customers based on allowable costs, including a reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company 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 Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the LPSC and the FERC 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 LPSC and the FERC, 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 LPSC and the FERC, 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 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 Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
• We read relevant regulatory orders issued by the LPSC and the FERC for the Company to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the LPSC’s and the FERC’s 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 Company’s filings with the LPSC and the FERC and orders issued, and considered the filings with the LPSC and the FERC by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.
• We obtained an analysis from management and support from 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.

/s/ DELOITTE & TOUCHE LLP

ENTERGY LOUISIANA, LLC AND SUBSIDIARIES

CONSOLIDATED INCOME STATEMENTS

(In Thousands)

377

ENTERGY LOUISIANA, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In Thousands)

378

ENTERGY LOUISIANA, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

379

ENTERGY LOUISIANA, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

(In Thousands)

380

ENTERGY LOUISIANA, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY

(In Thousands)

381

ENTERGY LOUISIANA, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

For the Years Ended December 31, 2025, 2024, and 2023

(In Thousands)

382

Winter Storm Fern

See the “Winter Storm Fern” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Winter Storm Fern. Entergy Mississippi’s preliminary estimate for the cost of mobilizing crews and restoring power is approximately $170 million to $200 million, with the majority of the costs being capital. Natural gas purchases for Entergy Mississippi for January 2026 are $85 million compared to natural gas purchases for January 2025 of $28 million.

Results of Operations

2025 Compared to 2024

Net Income

Net income increased $63.3 million primarily due to higher retail electric price, higher volume/weather, higher other income, a return on construction work in progress for certain utility plant investments in 2025, and $10.2 million of liquidated damages, net of customer sharing, recognized in 2025 resulting from a counterparty’s termination of a purchased power agreement. The increase was partially offset by higher other operation and maintenance expenses, higher interest expense, and a regulatory charge, recorded in the first quarter 2025, to reflect an adjustment to the grid modernization over/under recovery deferral balance.

Operating Revenues

Following is an analysis of the change in operating revenues comparing 2025 to 2024:

(In Millions)

Entergy Mississippi’s 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 retail electric price variance is primarily due to increases in formula rate plan rates effective April 2024 and July 2024 and an increase in formula rate plan rates resulting from an increase in interim facilities rate adjustment revenues effective January 2025. See Note 2 to the financial statements for discussion of the 2024 formula rate plan filing and the interim facilities rate adjustment.

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 data centers and technology industries, partially offset by a decrease in demand from small industrial customers.

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 investment, which is recognized as the related costs are incurred.

The purchased power agreement termination proceeds variance represents $10.2 million of liquidated damages, net of customer sharing, recognized in 2025 resulting from a counterparty’s termination of a purchased power agreement. See Note 2 to the financial statements for discussion of the customer sharing included in the power management cost factor effective for February 2026 bills.

Total electric energy sales for Entergy Mississippi for the years ended December 31, 2025 and 2024 are as follows:

See Note 19 to the financial statements for additional discussion of Entergy Mississippi’s operating revenues.

Other Income Statement Variances

Other operation and maintenance expenses increased primarily due to:

• an increase of $32.1 million in power delivery expenses primarily due to higher vegetation maintenance expenses;
• an increase of $13.8 million in non-nuclear generation expenses primarily due to a higher scope of work performed in 2025 as compared to 2024; and
• an increase of $5.8 million in bad debt expense.

The increase was partially offset by contract costs of $7.2 million in 2024 related to operational performance, customer service, and organizational health initiatives.

Taxes other than income taxes increased primarily due to increases in ad valorem taxes resulting from higher assessments and millage rate increases.

Other regulatory charges (credits) – net includes:

• a regulatory charge of $21 million, recorded in first quarter 2025, to reflect an adjustment to the grid modernization over/under recovery deferral balance; and
• regulatory credits of $7.3 million, recorded in second quarter 2024, to reflect the effects of the joint stipulation reached in the 2024 formula rate plan filing proceeding. See Note 2 to the financial statements for discussion of the 2024 formula rate plan filing.

Other income increased primarily due to an increase of $14.6 million in interest earned on money pool investments and an increase of $12.1 million in the amortization of tax gross ups on customer advances, including customer advances for construction.

Interest expense increased primarily due to the issuance of $600 million of 5.80% Series mortgage bonds in March 2025, the issuance of $300 million of 5.85% Series mortgage bonds in May 2024, and carrying costs of $12.4 million in 2025 on customer advances, including customer advances for construction. The increase was partially offset by a decrease of $3.8 million in carrying costs related to the deferred fuel balance.

The effective income tax rates were 23.5% for 2025 and 24.7% 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.

2024 Compared to 2023

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of Entergy Mississippi’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.

Income Tax Legislation and Regulation

See the “Income Tax Legislation and Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of income tax legislation and regulation.

Cash Flow

Cash flows for the years ended December 31, 2025, 2024, and 2023 were as follows:

(In Thousands)

385

2025 Compared to 2024

Operating Activities

Net cash flow provided by operating activities increased $5.2 million in 2025 primarily due to:

• the receipt of $133.4 million in advance payments related to customer agreements in 2025, of which $108.4 million is recorded as current liabilities and included within changes in other working capital accounts;
• the receipt of $69.7 million in payments from System Energy in 2025 in accordance with the Unit Power Sales Agreement related to the transfer of 2024 nuclear production tax credits by System Energy to third parties in 2025. See Note 3 to the financial statements for discussion of the nuclear production tax credits;
• higher collections from customers; and
• the receipt of a $15.0 million liquidated damages payment in third quarter 2025 resulting from a counterparty’s termination of a purchased power agreement.

The increase was substantially offset by:

• the timing of payments to vendors;
• income tax payments of $82.5 million in 2025 as compared to income tax refunds of $14.2 million in 2024. Entergy Mississippi made income tax payments in 2025 and received income tax refunds in 2024, each in accordance with Entergy’s tax allocation agreement; and
• higher fuel and purchased power payments. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery.

Investing Activities

Net cash flow used in investing activities increased $740.9 million in 2025 primarily due to an increase of $757.6 million in non-nuclear generation construction expenditures primarily due to higher spending on the Delta Blues Advanced Power Station project, the Vicksburg Advanced Power Station project, the Traceview Advanced Power Station project, the Penton Solar project, and the Delta Solar project and an increase of $42.4 million in distribution construction expenditures primarily due to higher capital expenditures for storm restoration in 2025. The increase was partially offset by:

• a decrease of $23.1 million in transmission construction expenditures primarily due to decreased spending on various transmission projects in 2025;
• the receipt of a $14.5 million initial payment for the sale of transmission rights and excess land related to Entergy Mississippi’s interest in the Independence power plant in third quarter 2025; and
• a decrease of $8.9 million in information technology capital expenditures primarily due to decreased spending on various technology projects in 2025.

Financing Activities

Net cash flow provided by financing activities increased $772.3 million in 2025 primarily due to:

• the issuance of $600 million of 5.80% Series mortgage bonds in March 2025;
• capital contributions of $265.5 million received from Entergy Corporation in 2025 in order to maintain Entergy Mississippi’s capital structure;
• the repayment, prior to maturity, of $100 million of 3.75% Series mortgage bonds in June 2024;
• money pool activity; and
• $44.6 million in common equity distributions paid in 2024 in order to maintain Entergy Mississippi’s capital structure.

The increase was partially offset by the issuance of $300 million of 5.85% Series mortgage bonds in May 2024.

Decreases in Entergy Mississippi’s payable to the money pool are a use of cash flow, and Entergy Mississippi’s payable to the money pool decreased $73.8 million in 2024. The money pool is an intercompany cash management program that makes possible intercompany borrowing and lending arrangements, and the money pool and other borrowing arrangements are designed to reduce the Registrant Subsidiaries’ dependence on external short-term borrowings.

See Note 5 to the financial statements for additional details of long-term debt.

2024 Compared to 2023

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy Mississippi’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.

Capital Structure

Entergy Mississippi’s debt to capital ratio is shown in the following table.

Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, finance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt and equity. Net capital consists of capital less cash and cash equivalents. Entergy Mississippi uses the debt to capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Mississippi’s financial condition. The net debt to net capital ratio is a non-GAAP measure. Entergy Mississippi uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Mississippi’s financial condition because net debt indicates Entergy Mississippi’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.

Entergy Mississippi seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a distribution, to the extent funds are legally available to do so, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Mississippi may issue incremental debt or reduce distributions, or both, to maintain its capital structure. In addition, in certain infrequent circumstances, such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reduced distributions, Entergy Mississippi may receive equity contributions to maintain its capital structure.

Uses of Capital

Entergy Mississippi requires capital resources for:

• construction and other capital investments;
• debt maturities or retirements;
• working capital purposes, including the financing of fuel and purchased power costs; and
• distributions and interest payments.

Following are the amounts of Entergy Mississippi’s planned construction and other capital investments.

(In Millions)

In addition to routine capital spending to maintain operations, the planned capital investment estimate includes investments in generation projects to modernize, decarbonize, expand, and diversify Entergy Mississippi’s portfolio, as well as to support customer growth, including Delta Blues Advanced Power Station, Delta Solar, Penton Solar, Traceview Advanced Power Station, and Vicksburg Advanced Power Station; distribution and Utility support spending to improve reliability, resilience, and customer experience; transmission spending to improve reliability and resilience while also supporting customer growth and renewables expansion; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, governmental actions, including the trade-related governmental actions discussed below, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital, including any changes to governmental programs, such as loans, grants, guarantees, and other subsidies.

Recent announcements of changes to international trade policy and tariffs and further similar changes may impact Entergy Mississippi’s business, operations, results of operations, and liquidity and capital resources. Potential impacts may include increases in costs associated with Entergy Mississippi’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 Mississippi’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 Mississippi’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.

Entergy Mississippi has 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 its current and planned capital projects. Entergy Mississippi 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 its current and planned capital projects.

Following are the amounts of Entergy Mississippi’s existing debt and lease obligations (includes estimated interest payments).

(a) Long-term debt is discussed in Note 5 to the financial statements.

(b) Lease obligations are discussed in Note 10 to the financial statements.

Other Obligations

Entergy Mississippi currently expects to contribute approximately $4 million to its qualified pension plans and approximately $176 thousand 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 Mississippi has $1.9 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.

In addition, Entergy Mississippi enters into fuel and purchased power agreements that contain minimum purchase obligations. Entergy Mississippi has rate mechanisms in place to recover fuel, purchased power, and associated costs incurred under these purchase obligations. See Note 8 to the financial statements for discussion of Entergy Mississippi’s obligations under the Unit Power Sales Agreement.

As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy Mississippi pays distributions from its earnings at a percentage determined monthly.

Additional Generation and Transmission Resources

In 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. See further discussion of the interim facilities rate adjustments below.

Delta Blues Advanced Power Station

In 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.

Delta Solar

In 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 Solar

In 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.

Traceview Advanced Power Station

Entergy 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 Station

In 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.

Sources of Capital

Entergy Mississippi’s sources to meet its capital requirements include:

• internally generated funds;
• cash on hand;
• the Entergy system money pool;
• debt or preferred membership interest issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
• capital contributions; and
• bank financing under new or existing facilities.

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, Entergy Mississippi expects to continue, when economically feasible, to retire higher-cost debt and replace it with lower-cost debt if market conditions permit.

All debt and preferred membership interest issuances by Entergy Mississippi require prior regulatory approval. Debt issuances are also subject to requirements set forth in its bond indenture and other agreements. Entergy Mississippi has sufficient capacity under these tests to meet its foreseeable capital needs for the next twelve months and beyond.

Entergy Mississippi’s receivables from (payables to) the money pool were as follows as of December 31 for each of the following years.

(In Thousands)

See Note 4 to the financial statements for a description of the money pool.

Entergy Mississippi has a credit facility in the amount of $300 million scheduled to expire in June 2030. The credit facility includes fronting commitments for the issuance of letters of credit against $5 million of the borrowing capacity of the facility. As of December 31, 2025, there were no cash borrowings and no letters of credit outstanding under the credit facility. In addition, Entergy Mississippi is a party to two uncommitted letter of credit facilities as a means to post collateral to support its obligations to MISO and for other purposes. As of December 31, 2025, $86.1 million in MISO letters of credit and $1.3 million in non-MISO letters of credit were outstanding under Entergy Mississippi’s uncommitted letter of credit facilities. See Note 4 to the financial statements for additional discussion of the credit facilities.

Entergy Mississippi obtained authorization from the FERC through January 2027 for short-term borrowings, not to exceed an aggregate amount of $200 million at any time outstanding, and long-term borrowings and security issuances. See Note 4 to the financial statements for further discussion of Entergy Mississippi’s short-term borrowing limits.

State and Local Rate Regulation and Fuel-Cost Recovery

The rates that Entergy Mississippi charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Mississippi is regulated, and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the MPSC, is primarily responsible for approval of the rates charged to customers.

Filings with the MPSC

Retail Rates

2023 Formula Rate Plan Filing

In March 2023, Entergy Mississippi submitted its formula rate plan 2023 test year filing and 2022 look-back filing showing Entergy Mississippi’s earned return on rate base for the historical 2022 calendar year to be below the formula rate plan bandwidth and projected earned return for the 2023 calendar year to be below the formula rate plan bandwidth. The 2023 test year filing showed a $39.8 million rate increase was necessary to reset Entergy Mississippi’s earned return on rate base to the specified point of adjustment of 6.67%, within the formula rate plan bandwidth. The 2022 look-back filing compared actual 2022 results to the approved benchmark return on rate base and reflected the need for a $19.8 million temporary increase in formula rate plan revenues, including the refund of a $1.3 million over-recovery resulting from the demand-side management costs true-up for 2022. In fourth quarter 2022, Entergy Mississippi recorded a regulatory asset of $18.2 million in connection with the look-back feature of the formula rate plan to reflect that the 2022 estimated earned return was below the formula rate plan bandwidth. In accordance with the provisions of the formula rate plan, Entergy Mississippi implemented a $27.9 million interim rate increase, reflecting a cap equal to 2% of 2022 retail revenues, effective in April 2023.

In May 2023, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed a 2023 test year filing resulting in a total revenue increase of $26.5 million for 2023. Pursuant to the joint stipulation, Entergy Mississippi’s 2022 look-back filing reflected an earned return on rate base of 6.10% in calendar year 2022, which was below the look-back bandwidth, resulting in a $19.0 million increase in the formula rate plan revenues on an interim basis through June 2024. Entergy Mississippi recorded a regulatory credit of $0.8 million in June 2023 to reflect the increase in the look-back regulatory asset. In addition, certain long-term service agreement and conductor handling costs were authorized for realignment from the formula rate plan to the annual power management and grid modernization riders effective January 2023, resulting in regulatory credits recorded in June 2023 of $4.1 million and $4.3 million, respectively. Also, the amortization of Entergy Mississippi’s COVID-19 bad debt expense deferral was suspended for calendar year 2023, but resumed in July 2024. In June 2023 the MPSC approved the joint stipulation with rates effective in July 2023.

2024 Formula Rate Plan Filing

In March 2024, Entergy Mississippi submitted its formula rate plan 2024 test year filing and 2023 look-back filing showing Entergy Mississippi’s earned return on rate base for the historical 2023 calendar year to be within the formula rate plan bandwidth and projected earned return for the 2024 calendar year to be below the formula rate plan bandwidth. The 2024 test year filing showed a $63.4 million rate increase was necessary to reset Entergy Mississippi’s earned return on rate base to the specified point of adjustment of 7.10%, within the formula rate plan bandwidth. The 2023 look-back filing compared actual 2023 results to the approved benchmark return on rate base and reflected no change in formula rate plan revenues. In accordance with the provisions of the formula rate plan, Entergy Mississippi implemented a $32.6 million interim rate increase, reflecting a cap equal to 2% of 2023 retail revenues, effective April 2024.

In December 2014 the MPSC ordered Entergy Mississippi to file an updated depreciation study at least once every four years. Pursuant to this order and Entergy Mississippi’s filing cycle, Entergy Mississippi would have filed an updated depreciation report with its formula rate plan filing in 2023. However, in July 2022 the MPSC directed Entergy Mississippi to file its next depreciation study in connection with its 2024 formula rate plan filing notwithstanding the MPSC’s prior order. Accordingly, Entergy Mississippi filed a depreciation study in February 2024. The study showed a need for an increase in annual depreciation expense of $55.2 million. The calculated increase in annual depreciation expense was excluded from Entergy Mississippi’s 2024 formula rate plan revenue increase request because the MPSC had not yet approved the proposed depreciation rates.

In June 2024, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed the 2024 test year filing, with the exception of immaterial adjustments to certain operation and maintenance expenses. After performance adjustments, the formula rate plan reflected an earned return on rate base of 6.08% for calendar year 2024, which resulted in a total revenue increase of $64.6 million for 2024. The joint stipulation also recommended approval of a revised customer charge of $31.82 per month for residential customers and $53.10 per month for general service customers. Pursuant to the stipulation, Entergy Mississippi’s 2023 look-back filing reflected an earned return on rate base of 6.81%, resulting in an increase of $0.3 million in the formula rate plan revenues for 2023. Finally, the stipulation recommended approval of Entergy Mississippi’s proposed depreciation rates with those rates to be implemented upon request and approval at a later date. In June 2024 the MPSC approved the joint stipulation with rates effective in July 2024. The approval also included a reduction to the energy cost factor, resulting in a net bill decrease for a typical residential customer using 1,000 kWh per month. Also in June 2024, Entergy Mississippi recorded regulatory credits of $7.3 million to reflect the difference between interim rates placed in effect in April 2024 and the rates reflected in the joint stipulation.

2025 Formula Rate Plan Filing

In February 2025, Entergy Mississippi submitted its formula rate plan 2025 test year filing and 2024 look-back filing showing Entergy Mississippi’s earned return on rate base for the historical 2024 calendar year to be within the formula rate plan bandwidth and projected earned return for the 2025 calendar year to also be within the formula rate plan bandwidth. The 2025 test year filing resulted in an earned return on rate base of 7.64% and reflected no change in formula rate plan revenues. The 2024 look-back filing compared actual 2024 results to the approved benchmark return on rate base and reflected no change in formula rate plan revenues, although Entergy Mississippi proposed to adjust interim rates by $135 thousand to reflect two outside-the-bandwidth changes: (1) the completion of Entergy Mississippi’s return to customers of credits under its restructuring credit rider; and (2) a true-up of demand side management costs.

In June 2025, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed the 2025 test year filing, with the exception of immaterial adjustments to certain operation and maintenance expenses. The formula rate plan reflected an earned return on rate base of 7.68% for calendar year 2025, resulting in no change in formula rate plan revenues for 2025. Pursuant to the stipulation, Entergy Mississippi’s 2024 look-back filing reflected an earned return on rate base of 7.55%, which also resulted in no change in formula rate plan revenues for 2024. In addition, the stipulation included the recovery of the two outside-the-bandwidth changes discussed above as well as the ratemaking treatment of customer contributions, deferred revenue and prepaid contributions in aid of construction. In June 2025 the MPSC approved the joint stipulation with rates effective in July 2025.

Interim Facilities Rate Adjustments to the Formula Rate Plan

In May 2024, Entergy Mississippi received approval from the MPSC for formula rate plan revisions that were necessary for Entergy Mississippi to comply with state legislation passed in January 2024. The legislation allows Entergy Mississippi to make interim rate adjustments 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. Entergy Mississippi filed the first of its annual interim facilities rate adjustment reports in May 2024 to recover approximately $8.7 million of these costs over a six-month period with rates effective the first billing cycle of July 2024. Entergy Mississippi filed its second annual interim facilities rate adjustment report in November 2024 to recover approximately $46.7 million of these costs over a 12-month period with rates effective the first billing cycle of January 2025. In February 2025, Entergy Mississippi filed a true-up interim facilities rate adjustment report to the initial annual interim facilities rate adjustment report filed in May 2024, reflecting the recovery of an additional approximately $1.0 million of costs over a 12-month period with rates effective with the first billing cycle of April 2025. Entergy Mississippi filed its third annual interim facilities rate adjustment report in November 2025 to recover approximately $111.3 million of these costs over a 12-month period, or approximately $64.7 million incremental to the second annual interim facilities rate adjustment report filed in November 2024, with rates effective the first billing cycle of January 2026.

Grand Gulf Capacity Filing

In September 2024, Entergy Mississippi filed a notice of intent with the MPSC to implement revisions to its unit power cost recovery rider that would allow Entergy Mississippi to recover the first year of costs associated with the transfer of Entergy Louisiana’s entitlements to Grand Gulf capacity and energy, which consists of Entergy Louisiana’s interest in and purchases of Grand Gulf capacity and energy under the revised rider schedule, effective by January 1, 2025. This notice filing related to the divestiture of Entergy Louisiana’s 14% share of Grand Gulf capacity and energy under the Unit Power Sales Agreement and 2.43% share of capacity and energy from Entergy Arkansas under the MSS-4 replacement tariff. This divestiture was effectuated initially through Entergy Mississippi’s purchases from Entergy Louisiana pursuant to a PPA governed by the MSS-4 replacement tariff, a tariff governing the sales of energy and capacity among the Utility operating companies as described in the System Energy global settlement with the LPSC and Entergy Louisiana. The MSS-4 replacement PPA to effectuate this divestiture was approved by the FERC in November 2024. In February 2025 the MPSC approved Entergy Mississippi’s notice of intent, finding that it was just and reasonable for Entergy Mississippi to obtain Entergy Louisiana’s entitlements to Grand Gulf capacity and energy and that Entergy Mississippi should be allowed to recover the costs associated with the transfer of such entitlements to Grand Gulf capacity and energy, as described above. The MPSC approved the MSS-4 replacement PPA, effective as of January 1, 2025. An amended Unit Power Sales Agreement became effective as of October 1, 2025, which removed Entergy Louisiana from the entitlement and responsibility to purchase power from Grand Gulf. Thus on October 1, 2025, the MSS-4 replacement PPA was terminated. See “Complaints Against System Energy - System Energy Settlement with the LPSC” in Note 2 to the financial statements for further details of the System Energy global settlement with the LPSC and Note 8 to the financial statements for discussion of the amendment to the Unit Power Sales Agreement.

Fuel and purchased power cost recovery

Entergy Mississippi’s rate schedules include an energy cost recovery rider and a power management rider, both of which are adjusted annually to reflect accumulated over- or under-recoveries. Entergy Mississippi recovers fuel and purchased energy costs through its energy cost recovery rider and recovers costs associated with natural gas hedging and capacity payments through its power management rider. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.

See “Complaints Against System Energy - System Energy Settlement with the MPSC” in Note 2 to the financial statements for discussion of the settlement agreement filed with the FERC in June 2022. The settlement, which was approved by the FERC in November 2022, provided for a refund of $235 million from System Energy to Entergy Mississippi. In July 2022 the MPSC directed the disbursement of settlement proceeds, ordering Entergy Mississippi to provide a one-time $80 bill credit to each of its approximately 460,000 retail customers to be effective during the September 2022 billing cycle and to apply the remaining proceeds to Entergy Mississippi’s under-recovered deferred fuel balance. In accordance with the MPSC’s directive, Entergy Mississippi provided approximately $36.7 million in customer bill credits as a result of the settlement. In November 2022, Entergy Mississippi applied the remaining settlement proceeds in the amount of approximately $198.3 million to Entergy Mississippi’s under-recovered deferred fuel balance.

Entergy Mississippi had a deferred fuel balance of approximately $291.7 million under the energy cost recovery rider as of July 31, 2022, along with an over-recovery balance of $51.1 million under the power management rider. Without further action, Entergy Mississippi anticipated a year-end deferred fuel balance of approximately $200 million after application of a portion of the System Energy settlement proceeds, as discussed above. In September 2022, Entergy Mississippi filed for interim adjustments under both the energy cost recovery rider and the power management rider. Entergy Mississippi proposed five monthly incremental adjustments to the net energy cost factor designed to collect the under-recovered fuel balance as of July 31, 2022 and to reflect the recovery of a higher natural gas price. Entergy Mississippi also proposed five monthly incremental adjustments to the power management adjustment factor designed to flow through to customers the over-recovered power management rider balance as of July 31, 2022. In October 2022 the MPSC approved modified interim adjustments to Entergy Mississippi’s energy cost recovery rider and power management rider. The MPSC approved dividing the energy cost recovery rider interim adjustment into two components that would allow Entergy Mississippi to (1) recover a natural gas fuel rate that is better aligned with current prices; and (2) recover the estimated under-recovered deferred fuel balance as of September 30, 2022 over a period of 20 months. The MPSC approved six monthly incremental adjustments to the net energy cost factor designed to reflect the recovery of a higher natural gas price. The MPSC also approved six monthly incremental adjustments to the power management adjustment factor designed to flow through to customers the over-recovered power management rider balance. In accordance with the order of the MPSC, Entergy Mississippi did not file an annual redetermination of the energy cost recovery rider or the power management rider in November 2022.

In June 2023 the MPSC approved the joint stipulation agreement between Entergy Mississippi and the Mississippi Public Utilities Staff for Entergy Mississippi’s 2023 formula rate plan filing. The stipulation directed Entergy Mississippi to make a compliance filing to revise its power management cost adjustment factor, to revise its grid modernization cost adjustment factor, and to include a revision to reduce the net energy cost factor to a level necessary to reflect an average natural gas price of $4.50 per MMBtu. The MPSC approved the compliance filing in June 2023, effective for July 2023 bills. See “Retail Rate Proceedings - Filings with the MPSC (Entergy Mississippi) - Retail Rates - 2023 Formula Rate Plan Filing” in Note 2 to the financial statements for further discussion of the 2023 formula rate plan filing and the joint stipulation agreement.

In November 2023, Entergy Mississippi filed its annual redeterminations of the energy cost factor and the power management cost adjustment factor. The calculation of the annual factor for the energy cost recovery rider included a projected over-recovery balance of approximately $142 million as of January 31, 2024. The calculation of the annual factor for the power management rider included a projected under-recovery balance of $47 million as of January 31, 2024. In January 2024 the MPSC approved the proposed energy cost factor and the proposed power management cost factor effective for February 2024 bills.

In June 2024 the MPSC approved the joint stipulation agreement between Entergy Mississippi and the Mississippi Public Utilities Staff for Entergy Mississippi’s 2024 formula rate plan filing. The 2024 formula rate plan filing included the conclusion of the modified interim adjustments to Entergy Mississippi’s energy cost recovery rider and power management rider, which were approved in October 2022 and allowed Entergy Mississippi to recover certain under-collected fuel balances, effective for July 2024 bills. The stipulation provided for Entergy Mississippi to reduce its net energy cost factor. See “Retail Rate Proceedings - Filings with the MPSC (Entergy Mississippi) - Retail Rates - 2024 Formula Rate Plan Filing” in Note 2 to the financial statements for further discussion of the 2024 formula rate plan filing and the joint stipulation agreement.

In November 2024, Entergy Mississippi filed its annual redeterminations of the energy cost factor and the power management cost adjustment factor. The calculation of the annual factor for the energy cost recovery rider included a projected over-recovery balance of approximately $144.6 million as of September 30, 2024. The calculation of the annual factor for the power management rider included a projected under-recovery balance of $60.1 million as of September 30, 2024. In January 2025 the MPSC approved a revised energy cost factor, effective for February 2025 bills, that did not reflect the fuel savings associated with Entergy Mississippi’s incremental increase in its share of capacity and energy in connection with Entergy Mississippi’s assumption of Entergy Louisiana’s entitlements to Grand Gulf capacity and energy, which was subject to the MPSC’s review at such time. In February 2025 the MPSC approved Entergy Mississippi’s notice of intent for Entergy Mississippi’s assumption of Entergy Louisiana’s entitlements to Grand Gulf capacity and energy, with associated fuel savings to be reflected in Entergy Mississippi’s energy cost recovery rider, effective for March 2025 bills. Additionally, in February 2025 the MPSC approved the proposed power management cost adjustment factor, effective for March 2025 bills.

In November 2025, Entergy Mississippi filed its annual redeterminations of the energy cost factor and the power management cost adjustment factor. The calculation of the annual factor for the energy cost recovery rider included a projected over-recovery balance of approximately $21.5 million as of September 30, 2025. The calculation of the annual factor for the power management rider included a projected under-recovery balance of $9.3 million as of September 30, 2025. In January 2026 the MPSC approved the proposed energy cost factor effective for February 2026 bills. In January 2026 the MPSC also approved a power management cost factor effective for February 2026 bills, based on an under-recovery balance that was $4.8 million lower than the previously filed under-recovery balance, due to a rate mitigation adjustment that utilized, for the benefit of customers, certain liquidated damages payments received by Entergy Mississippi.

Storm Cost Recovery Filings with Retail Regulators

Prior to June 2024, Entergy Mississippi had approval from the MPSC to collect a storm damage provision of $1.75 million per month. If Entergy Mississippi’s accumulated storm damage provision balance exceeded $15 million, the collection of the storm damage provision ceased until such time that the accumulated storm damage provision became less than $10 million. Entergy Mississippi’s storm damage provision balance had been less than $10 million since May 2019, and Entergy Mississippi had been billing the monthly storm damage provision since July 2019.

In December 2023, Entergy Mississippi filed a Notice of Storm Escrow Disbursement and Request for Interim Relief notifying the MPSC that Entergy Mississippi had requested disbursement of approximately $34.5 million of storm escrow funds from its restricted storm escrow account. The filing also requested authorization from the MPSC, on a temporary basis, that the $34.5 million of storm escrow funds be credited to Entergy Mississippi’s storm damage provision, pending the MPSC’s review of Entergy Mississippi’s storm-related costs, and that Entergy Mississippi continue to bill its monthly storm damage provision without suspension in the event the storm damage provision balance exceeded $15 million, in anticipation of a subsequent filing by Entergy Mississippi in this proceeding. The storm damage provision exceeded $15 million upon receipt of the storm escrow funds. Because the MPSC had not entered an order on Entergy Mississippi’s filing on the requested relief to continue billing this provision, Entergy Mississippi suspended billing the monthly storm damage provision effective with February 2024 bills.

In March 2024, Entergy Mississippi made a combined dual filing which included a notice of intent to make routine change in rates and schedules and a motion for determination relating to the above-described notice of storm escrow disbursement. The notice of intent proposed a new storm damage mitigation and restoration rider to supersede both the then-current storm damage rate schedule and the vegetation management rider schedule, in which the collection of both expenses would be combined. The proposal requested that the MPSC authorize Entergy Mississippi to collect approximately $5.2 million per month for vegetation management and a storm damage provision. Furthermore, if Entergy Mississippi’s accumulated vegetation management and storm damage provision balance were to exceed $70 million, collection under the storm damage mitigation and restoration rider would cease until such time that the accumulated vegetation management and storm damage provision would become less than $60 million.

The Mississippi Public Utilities Staff reviewed the storm-related costs submitted by Entergy Mississippi and found them prudent. In June 2024 the MPSC considered and unanimously granted the relief sought by Entergy Mississippi, including authorization to credit any remaining funds in the storm escrow account to Entergy Mississippi’s storm damage provision and to close the storm escrow account and approving the new storm damage mitigation and restoration rider. Entergy Mississippi’s storm escrow account was liquidated in July 2024, and the new combined storm damage mitigation and restoration rider became effective with the July 2024 billing cycle. Additionally, Entergy Mississippi made a compliance filing to cease billing under the existing vegetation management rider schedule as of the same billing cycle.

Industrial and Commercial Customers

Entergy Mississippi’s large industrial and commercial customers continually explore ways to reduce their energy costs. Entergy Mississippi 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 Mississippi’s industrial customer base. Entergy Mississippi actively participates in economic development, customer retention, and reclamation activities to increase industrial and commercial demand from both new and existing customers.

Federal Regulation

See the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.

Nuclear Matters

See the “Nuclear Matters” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of nuclear matters.

Environmental Risks

Entergy Mississippi’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Mississippi is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.

Critical Accounting Estimates

The preparation of Entergy Mississippi’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 Mississippi’s financial position, results of operations, or cash flows.

Utility Regulatory Accounting

See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.

Taxation and Uncertain Tax Positions

See “Taxation and Uncertain Tax Positions” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.

Qualified Pension and Other Postretirement Benefits

Entergy Mississippi’s qualified pension and other postretirement reported costs, 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. See “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. 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.

Cost Sensitivity

The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).

398

The following chart reflects the sensitivity of postretirement benefits cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).

Each fluctuation above assumes that the other components of the calculation are held constant.

Costs and Employer Contributions

Total qualified pension cost for Entergy Mississippi in 2025 was $3.2 million, including $146 thousand in settlement costs. Entergy Mississippi anticipates 2026 qualified pension cost to be $2.6 million. Entergy Mississippi contributed $8.1 million to its qualified pension plans in 2025 and estimates 2026 pension contributions will be approximately $4 million, 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.

Total postretirement health care and life insurance benefit income for Entergy Mississippi in 2025 was $3.9 million. Entergy Mississippi expects 2026 postretirement health care and life insurance benefit income of approximately $3.5 million. Entergy Mississippi contributed $223 thousand to its other postretirement plans in 2025 and estimates that 2026 contributions will be approximately $176 thousand.

Other Contingencies

See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.

See the “New Accounting Pronouncements” section of Note 1 to the financial statements for a discussion of new accounting pronouncements.

To the member and Board of Directors of

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Entergy Mississippi, LLC and Subsidiaries (the “Company”) as of December 31, 2025 and 2024, the related consolidated statements of income, cash flows and changes in equity (pages 402 through 406 and applicable items in pages 53 through 246), for each of the three years in the period ended December 31, 2025, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates 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 matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Rate and Regulatory Matters — Entergy Mississippi, LLC and Subsidiaries — Refer to Note 2 to the financial statements

The Company is subject to rate regulation by the Mississippi Public Service Commission (the “MPSC”), which has jurisdiction with respect to the rates of electric companies in Mississippi, and to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). 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 Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the MPSC and the FERC set the rates the Company is allowed to charge customers based on allowable costs, including a reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company 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 Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the MPSC and the FERC 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 MPSC and the FERC, 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 MPSC and the FERC, 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 Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
• We read relevant regulatory orders issued by the MPSC and the FERC for the Company to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the MPSC’s and FERC’s 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 Company’s filings with the MPSC and the FERC and orders issued, and considered the filings with the MPSC and the FERC by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.
• We obtained an analysis from management and support from 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.

/s/ DELOITTE & TOUCHE LLP

ENTERGY MISSISSIPPI, LLC AND SUBSIDIARIES

CONSOLIDATED INCOME STATEMENTS

(In Thousands)

402

ENTERGY MISSISSIPPI, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

403

ENTERGY MISSISSIPPI, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

(In Thousands)

404

ENTERGY MISSISSIPPI, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY

(In Thousands)

405

ENTERGY MISSISSIPPI, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

For the Years Ended December 31, 2025, 2024, and 2023

(In Thousands)

406

Results of Operations

2025 Compared to 2024

Net Income

Net income increased $34.6 million primarily due to a $78.5 million ($57.4 million net-of-tax) regulatory charge, recorded 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. Also contributing to the increase were lower other operation and maintenance expenses, lower taxes other than income taxes, and lower depreciation and amortization expenses. The increase was partially offset by a $12.8 million ($9.6 million net-of-tax) charge, recorded in third quarter 2025, 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, higher interest expense, and lower other income. 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. 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.

Operating Revenues

Following is an analysis of the change in operating revenues comparing 2025 to 2024:

(In Millions)

Entergy New Orleans’s 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 effect of sale of natural gas distribution business variance represents the decrease in operating revenues resulting from the absence of natural gas revenues following the sale of the natural gas distribution business on July 1, 2025. 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.

The volume/weather variance is primarily due to a decrease in weather-adjusted residential usage and a decrease in commercial usage, partially offset by the effect of more favorable weather on residential sales.

The retail electric price variance is primarily due to a decrease in formula rate plan rates effective September 2025 in accordance with the terms of the 2025 formula rate plan filing, partially offset by an increase in formula rate plan rates effective September 2024 in accordance with the terms of the 2024 formula rate plan filing. See Note 2 to the financial statements for discussion of the formula rate plan filings.

Total electric energy sales for Entergy New Orleans for the years ended December 31, 2025 and 2024 are as follows:

See Note 19 to the financial statements for additional discussion of Entergy New Orleans’s operating revenues.

Other Income Statement Variances

Other operation and maintenance expenses decreased primarily due to:

• a decrease of $6.6 million in gas operation expenses resulting from the absence of expenses during the last six months of 2025 and a $2.7 million gain, recorded in 2025, both as a result of the sale of the natural gas distribution business on July 1, 2025. 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;
• contract costs of $3.3 million in 2024 related to operational performance, customer service, and organizational health initiatives;
• $1.8 million in costs recognized in 2024 related to credits provided to customers as part of the rate mitigation plan approved in the settlement of the 2023 formula rate plan filing. See Note 2 to the financial statements for discussion of the 2023 formula rate plan filing; and
• a decrease of $1.6 million in loss provisions.

The decrease was partially offset by an increase of $2.3 million in energy efficiency expenses primarily due to higher energy efficiency costs, partially offset by the timing of recovery from customers.

Asset write-offs includes a $12.8 million charge, recorded in third quarter 2025, 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 decreased primarily due to decreases in local franchise fees as a result of lower retail revenues in 2025 as compared to 2024, including decreased natural gas revenues resulting from the sale of Entergy New Orleans’s natural gas distribution business on July 1, 2025, and decreases in ad valorem taxes resulting from lower assessments. 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.

Depreciation and amortization expenses decreased primarily due to the absence of depreciation and amortization expenses associated with natural gas plant in service following the sale of the natural gas distribution business on July 1, 2025, partially offset by additions to plant in service. 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.

Other regulatory charges (credits) - net includes a regulatory charge of $78.5 million, recorded 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.

Other income decreased primarily due to the deferral of certain other postretirement benefit expense credits, effective September 2024, in accordance with the terms of the 2024 formula rate plan filing. See Note 2 to the financial statements for discussion of the 2024 formula rate plan filing and Note 11 to the financial statements for discussion of the other postretirement benefits accounting treatment.

Interest expense increased primarily due to an increase of $8 million in carrying costs on regulatory liability balances, partially offset by lower interest accrued on customer deposits.

The effective income tax rates were 23.9% for 2025 and 15.2% 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.

2024 Compared to 2023

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of Entergy New Orleans’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.

Income Tax Legislation and Regulation

See the “Income Tax Legislation and Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of income tax legislation and regulation.

Sale of Natural Gas Distribution Business

See the “Dispositions - Natural Gas Distribution Businesses” section in Note 14 to the financial statements for discussion of the sale of the Entergy New Orleans natural gas distribution business.

Cash Flow

Cash flows for the years ended December 31, 2025, 2024, and 2023 were as follows:

(In Thousands)

2025 Compared to 2024

Operating Activities

Net cash flow provided by operating activities decreased $103 million in 2025 primarily due to:

• the receipt of $98.1 million in settlement proceeds in 2024 as a result of the System Energy settlement with the City Council. See Note 2 to the financial statements for discussion of the System Energy settlement with the City Council;
• the timing of payments to vendors; and
• income tax payments of $10.1 million in 2025 compared to income tax refunds of $17.9 million in 2024. Entergy New Orleans made income tax payments in 2025 primarily related to estimated state income taxes and in accordance with Entergy’s tax allocation agreement. Entergy New Orleans received income tax refunds in 2024 primarily in accordance with Entergy’s tax allocation agreement.

The decrease was partially offset by higher collections from customers and the receipt of $59.9 million in payments from affiliates in 2025 in accordance with the Unit Power Sales Agreement and the MSS-4 replacement tariff related to the transfer of 2024 nuclear production tax credits by affiliates to third parties in 2025. See Note 3 to the financial statements for discussion of the nuclear production tax credits.

Investing Activities

Entergy New Orleans’s investing activities provided $115.4 million of cash in 2025 compared to using $163.5 million of cash in 2024 primarily due to the following activity:

• $283.9 million in proceeds from the sale of the natural gas distribution business on July 1, 2025. 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;
• an increase of $20.3 million in non-nuclear generation construction expenditures primarily due to a higher scope of work performed during plant outages in 2025 as compared to 2024; and
• the receipt of $13.1 million from the storm reserve escrow account in 2025.

Financing Activities

Net cash flow used in financing activities increased $129.1 million in 2025 primarily due to:

• the issuances of $65 million of 6.41% Series mortgage bonds, $50 million of 6.54% Series mortgage bonds, and $35 million of 6.25% Series mortgage bonds, each in May 2024;
• the repayment, at maturity, of $78 million of 3.00% Series mortgage bonds in March 2025; and
• an increase of $15 million in common equity distributions paid in 2025 in order to maintain Entergy New Orleans’s capital structure.

The increase was partially offset by the repayment, at maturity, of an $85 million unsecured term loan in June 2024 and money pool activity.

Decreases in Entergy New Orleans’s payable to the money pool are a use of cash flow, and Entergy New Orleans’s payable to the money pool decreased $21.7 million in 2024. The money pool is an intercompany cash management program that makes possible intercompany borrowing and lending arrangements, and the money pool and other borrowing arrangements are designed to reduce the Registrant Subsidiaries’ dependence on external short-term borrowings.

See Note 5 to the financial statements for more details on long-term debt.

2024 Compared to 2023

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy New Orleans’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.

Capital Structure

Entergy New Orleans’s debt to capital ratio is shown in the following table.

Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, finance lease obligations, long-term debt, including the currently maturing portion, and the long-term payable due to an associated company. Capital consists of debt and equity. Net capital consists of capital less cash and cash equivalents. The net debt to net capital ratio is a non-GAAP measure. Entergy New Orleans uses the debt to capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy New Orleans’s financial condition. Entergy New Orleans also uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy New Orleans’s financial condition because net debt indicates Entergy New Orleans’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.

Entergy New Orleans seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a distribution, to the extent funds are legally available to do so, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy New Orleans may issue incremental debt or reduce distributions, or both, to maintain its capital structure. In addition, in certain infrequent circumstances, such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reduced distributions, Entergy New Orleans may receive equity contributions to maintain its capital structure.

Uses of Capital

Entergy New Orleans requires capital resources for:

• construction and other capital investments;
• working capital purposes, including the financing of fuel and purchased power costs;
• debt maturities or retirements; and
• distribution and interest payments.

Following are the amounts of Entergy New Orleans’s planned construction and other capital investments.

(In Millions)

In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy New Orleans includes distribution and Utility support spending to improve reliability, resilience, and customer experience; transmission spending to improve reliability and resilience; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, governmental actions, including the trade-related governmental actions discussed below, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital, including any changes to governmental programs, such as loans, grants, guarantees, and other subsidies.

Recent announcements of changes to international trade policy and tariffs and further similar changes may impact Entergy New Orleans’s business, operations, results of operations, and liquidity and capital resources. Potential impacts may include increases in costs associated with Entergy New Orleans’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 New Orleans’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 New Orleans’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.

Entergy New Orleans has 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 its current and planned capital projects. Entergy New Orleans 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 its current and planned capital projects.

Following are the amounts of Entergy New Orleans’s existing debt and lease obligations (includes estimated interest payments).

(In Millions)

(a) Long-term debt is discussed in Note 5 to the financial statements.

(b) Lease obligations are discussed in Note 10 to the financial statements.

Other Obligations

Entergy New Orleans currently expects to contribute approximately $3.3 million to its qualified pension plans and approximately $336 thousand 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 New Orleans has $14.8 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.

In addition, Entergy New Orleans enters into fuel and purchased power agreements that contain minimum purchase obligations. Entergy New Orleans has rate mechanisms in place to recover fuel, purchased power, and associated costs incurred under these purchase obligations. See Note 8 to the financial statements for discussion of Entergy New Orleans’s obligations under the Unit Power Sales Agreement.

As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy New Orleans pays distributions from its earnings at a percentage determined monthly.

Resilience and Grid Hardening

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.

Sources of Capital

Entergy New Orleans’s sources to meet its capital requirements include:

• internally generated funds;
• cash on hand;
• the Entergy system money pool;
• storm reserve escrow accounts;
• debt and preferred membership interest issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
• capital contributions; and
• bank financing under new or existing facilities.

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, Entergy New Orleans expects to continue, when economically feasible, to retire higher-cost debt and replace it with lower-cost debt if market conditions permit.

All debt and common and preferred membership interest issuances by Entergy New Orleans require prior regulatory approval. Debt issuances are also subject to requirements set forth in its bond indenture and other agreements. Entergy New Orleans has sufficient capacity under these tests to meet its foreseeable capital needs for the next twelve months and beyond.

Entergy New Orleans’s receivables from (payables to) the money pool were as follows as of December 31 for each of the following years.

(In Thousands)

See Note 4 to the financial statements for a description of the money pool.

Entergy New Orleans has a credit facility in the amount of $25 million scheduled to expire in June 2027. The credit facility includes fronting commitments for the issuance of letters of credit against $10 million of the borrowing capacity of the facility. As of December 31, 2025, there were no cash borrowings and no letters of credit outstanding under the credit facility. In addition, Entergy New Orleans is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations to MISO. As of December 31, 2025, a $0.5 million letter of credit was outstanding under Entergy New Orleans’s uncommitted letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.

Entergy New Orleans obtained authorization from the FERC through January 2027 for short-term borrowings not to exceed an aggregate amount of $150 million at any time outstanding and long-term borrowings and securities issuances. See Note 4 to the financial statements for further discussion of Entergy New Orleans’s short-term borrowing limits. The long-term securities issuances of Entergy New Orleans are limited to amounts authorized not only by the FERC, but also by the City Council, and the current City Council authorization extends through December 2027.

State and Local Rate Regulation

The rates that Entergy New Orleans charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy New Orleans is regulated, and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the City Council, is primarily responsible for approval of the rates charged to customers.

Retail Rates

2023 Formula Rate Plan Filing

In April 2023, Entergy New Orleans submitted to the City Council its formula rate plan 2022 test year filing. The 2022 test year evaluation report produced an electric earned return on equity of 7.34% and a gas earned return on equity of 3.52% compared to the authorized return on equity for each of 9.35%. Entergy New Orleans sought approval of a $25.6 million rate increase based on the formula set by the City Council in the 2018 rate case. The formula would result in an increase in authorized electric revenues of $17.4 million and an increase in authorized gas revenues of $8.2 million. Entergy New Orleans also sought to commence collecting $3.4 million in electric revenues that were previously approved by the City Council for collection through the formula rate plan. In July 2023, Entergy New Orleans filed a report to decrease its requested formula rate plan revenues by approximately $0.5 million to account for minor errors discovered after the filing. The City Council advisors issued a report seeking a reduction in the requested formula rate plan revenues of approximately $8.3 million, combined for electric and gas, due to alleged errors. The City Council advisors proposed additional rate mitigation in the amount of $12 million through offsets to the formula rate plan rate increase by certain regulatory liabilities. In September 2023 the City Council approved an agreement to settle the 2023 formula rate plan filing. Effective with the first billing cycle of September 2023, Entergy New Orleans implemented rates reflecting an amount agreed upon by Entergy New Orleans and the City Council, per the approved process for formula rate plan implementation. The agreement provided for a total increase in electric revenues of $10.5 million and a total increase in gas revenues of $6.9 million. The agreement also provided for a minor storm accrual of $0.5 million per year and the distribution of $8.9 million of then-held customer credits to implement the City Council advisors’ mitigation recommendations.

Request for Extension and Modification of Formula Rate Plan

In September 2023, Entergy New Orleans filed a motion seeking City Council approval of a three-year extension of Entergy New Orleans’s electric and gas formula rate plans. In October 2023 the City Council granted Entergy New Orleans’s request for an extension, subject to minor modifications which included a 55% equity ratio for rate setting purposes.

2024 Formula Rate Plan Filing

In April 2024, Entergy New Orleans submitted to the City Council its formula rate plan 2023 test year filing. Without the requested rate change in 2024, the 2023 test year evaluation report produced an electric earned return on equity of 8.66% and a gas earned return on equity of 5.87% compared to the authorized return on equity for each of 9.35%. Entergy New Orleans sought approval of a $12.6 million rate increase based on the formula set by the City Council in the 2018 rate case and approved again by the City Council in 2023. The formula would result in an increase in authorized electric revenues of $7.0 million and an increase in authorized gas revenues of $5.6 million. Following City Council review, the City Council’s advisors issued a report in July 2024 seeking a reduction in Entergy New Orleans’s requested formula rate plan revenues in an aggregate amount of approximately $1.6 million for electric and gas together due to alleged errors. Effective with the first billing cycle of September 2024, Entergy New Orleans implemented rates reflecting an amount agreed upon by Entergy New Orleans and the City Council, per the approved process for formula rate plan implementation. The total formula rate plan increase implemented was $11.2 million, which included an increase of $5.8 million in electric revenues and an increase of $5.4 million in gas revenues.

2025 Formula Rate Plan Filing

In April 2025, Entergy New Orleans submitted to the City Council its formula rate plan 2024 test year filing. The 2024 evaluation report produced an electric earned return on equity of 10.98% compared to the authorized return on equity of 9.35%. Without adjustments, this would have resulted in a decrease in electric rates of $13.8 million. The decrease in electric rates was driven by the realignment of regulatory liabilities into the formula from a separate rate mechanism, partially offset by the cost of known and measurable electric capital additions. The filing also commenced the previously authorized recovery of certain regulatory costs and requested a revenue-neutral recovery to offset a proposed reduction in bill payment late fees. Taking into account these proposed adjustments, the filing presented a decrease in authorized electric revenues of $8.6 million. The City Council’s advisors issued a report in July 2025 seeking a reduction in Entergy New Orleans’s requested electric formula rate plan revenues of approximately $7.2 million due to certain proposed cost realignments and disallowances, of which $4.1 million was associated with Entergy New Orleans’s proposed implementation, on a revenue neutral basis, of a proposed reduction in customer late fees. The City Council’s advisors also proposed rate mitigation in the amount of $4.4 million through offsets to the formula rate plan funded by certain regulatory liabilities. In August 2025 the City Council approved an agreement to settle the 2025 formula rate plan filing. Effective with the first billing cycle of September 2025, Entergy New Orleans implemented rates reflecting an amount agreed upon by Entergy New Orleans and the City Council, per the approved process for formula rate implementation. The electric formula rate plan decrease implemented was $19.2 million.

Fuel and purchased power cost recovery

Entergy New Orleans’s electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges.

Distributed Energy Resources Program

In October 2024 the City Council opened a docket to evaluate potential opportunities to increase the availability of distributed energy resources, battery storage, and related facilities in New Orleans. In December 2025 the City Council issued a resolution establishing a distributed energy resources program to be implemented and operated under the existing Energy Smart program, with $28 million in customer incentives available through credits funded by credits from the System Energy settlement with the City Council. See “Complaints Against System Energy - System Energy Settlement with the City Council” in Note 2 to the financial statements for discussion of the System Energy settlement with the City Council.

Federal Regulation

See the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.

Nuclear Matters

See the “Nuclear Matters” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of nuclear matters.

Environmental Risks

Entergy New Orleans’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy New Orleans is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.

Critical Accounting Estimates

The preparation of Entergy New Orleans’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 New Orleans’s financial position, results of operations, or cash flows.

Utility Regulatory Accounting

See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.

Taxation and Uncertain Tax Positions

See “Taxation and Uncertain Tax Positions” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.

Qualified Pension and Other Postretirement Benefits

Entergy New Orleans’s qualified pension and other postretirement reported costs, 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. See “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. 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.

Cost Sensitivity

The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).

The following chart reflects the sensitivity of postretirement benefits cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).

Each fluctuation above assumes that the other components of the calculation are held constant.

Costs and Employer Contributions

Total qualified pension cost for Entergy New Orleans in 2025 was $6.4 million, including $6.2 million in settlement costs. Entergy New Orleans anticipates 2026 qualified pension cost to be $1 million. Entergy New Orleans contributed $5 million to its qualified pension plans in 2025 and estimates 2026 pension contributions will be approximately $3.3 million, 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.

Total postretirement health care and life insurance benefit costs for Entergy New Orleans in 2025 was $12.3 million, including $1.6 million in settlement and curtailment credits. Entergy New Orleans expects 2026 postretirement health care and life insurance benefit income of approximately $4.7 million. Entergy New Orleans contributed $97 thousand to its other postretirement plans in 2025 and estimates 2026 contributions will be approximately $336 thousand.

Other Contingencies

See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.

See the “New Accounting Pronouncements” section of Note 1 to the financial statements for a discussion of new accounting pronouncements.

To the member and Board of Directors of

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Entergy New Orleans, LLC and Subsidiaries (the “Company”) as of December 31, 2025 and 2024, the related consolidated statements of income, cash flows, and changes in member’s equity (pages 421 through 426 and applicable items in pages 53 through 246), for each of the three years in the period ended December 31, 2025, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates 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 matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Rate and Regulatory Matters — Entergy New Orleans, LLC and Subsidiaries — Refer to Note 2 to the financial statements

The Company is subject to rate regulation by the Council of the City of New Orleans, Louisiana (the “City Council”), which has jurisdiction with respect to the rates of electric companies in the City of New Orleans, Louisiana, and to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). 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 Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the City Council and the FERC set the rates the Company is allowed to charge customers based on allowable costs, including a reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company 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 Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the City Council and the FERC 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 City Council and the FERC, 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 City Council and the FERC, 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 Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
• We read relevant regulatory orders issued by the City Council and the FERC for the Company to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the City Council’s and the FERC’s 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 Company’s filings with the City Council and the FERC and orders issued, and considered the filings with the City Council and the FERC by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.
• We obtained an analysis from management and support from 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.

/s/ DELOITTE & TOUCHE LLP

ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES

CONSOLIDATED INCOME STATEMENTS

(In Thousands)

421

ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

423

ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

(In Thousands)

424

ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY

(In Thousands)

425

(In Thousands)

426

Results of Operations

2025 Compared to 2024

Net Income

Net income increased $40.5 million primarily due to higher retail electric price, higher volume/weather, and higher other income, partially offset by higher purchased power costs related to the procurement of capacity through MISO’s annual planning resource auction, higher interest expense, higher other operation and maintenance expenses, higher taxes other than income taxes, and higher depreciation and amortization expenses.

Operating Revenues

Following is an analysis of the change in operating revenues comparing 2025 to 2024:

(In Millions)

Entergy Texas’s 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 retail electric price variance is primarily due to 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. See Note 2 to the financial statements for discussion of the distribution cost recovery factor rider filings.

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 transportation, petroleum refining, wood products, and primary metals industries.

Total electric energy sales for Entergy Texas for the years ended December 31, 2025 and 2024 are as follows:

See Note 19 to the financial statements for additional discussion of Entergy Texas’s operating revenues.

Other Income Statement Variances

Purchased power includes an increase in 2025 of $33.8 million in costs 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 at the earliest opportunity.

Other operation and maintenance expenses increased primarily due to:

• an increase of $8.0 million in bad debt expense;
• an increase of $7.9 million in power delivery expenses primarily due to higher vegetation maintenance costs;
• an increase of $3.7 million in loss provisions;
• an increase of $1.8 million in transmission costs allocated by MISO;
• an increase of $1.7 million in insurance expense primarily due to higher premiums in 2025 as compared to 2024;
• an increase of $1.6 million in energy efficiency costs primarily due to the timing of recovery from customers; and
• several individually insignificant items.

The increase was partially offset by:

• contract costs of $8.1 million in 2024 related to operational performance, customer service, and organizational health initiatives;
• a decrease of $6.9 million in non-nuclear generation expenses primarily due to a lower scope of work, including during plant outages, in 2025 as compared to 2024; and
• a decrease of $1.8 million in storm damage provisions.

Taxes other than income taxes increased primarily due to increases in ad valorem taxes resulting from higher assessments.

Depreciation and amortization expenses decreased primarily due to the recognition of $27.6 million in depreciation expense in 2024 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 2022 base rate case. The decrease was partially offset by additions to plant in service.

Other income increased primarily due to an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2025, including the Legend Power Station project, the Orange County Advanced Power Station project, and the Lone Star Power Station project, partially offset by lower interest earned on money pool investments.

Interest expense increased primarily due to the issuance of $500 million of 5.25% Series mortgage bonds in February 2025 and the issuance of $350 million of 5.55% Series mortgage bonds in August 2024, 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.

The effective income tax rates were 16.4% for 2025 and 18.3% 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.

2024 Compared to 2023

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of Entergy Texas’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.

Income Tax Legislation and Regulation

See the “Income Tax Legislation and Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of income tax legislation and regulation.

Cash Flow

Cash flows for the years ended December 31, 2025, 2024, and 2023 were as follows:

(In Thousands)

2025 Compared to 2024

Operating Activities

Net cash flow provided by operating activities decreased $195.7 million in 2025 primarily due to the timing of recovery of fuel and purchased power costs and higher fuel and purchased power payments, an increase of $32.7 million in interest paid, and the timing of payments to vendors. The decrease was partially offset by the receipt of $45.6 million in payments from affiliates in 2025 in accordance with the MSS-4 replacement tariff related to the transfer of 2024 nuclear production tax credits by affiliates to third parties in 2025 and a decrease of $19 million in storm spending primarily due to Hurricane Beryl restoration efforts in 2024. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery. See Note 3 to the financial statements for discussion of the nuclear production tax credits.

Investing Activities

Net cash flow used in investing activities increased $312.9 million in 2025 primarily due to an increase of $514.4 million in non-nuclear generation construction expenditures primarily due to higher spending on the Legend Power Station project, the Lone Star Power Station project, and the Orange County Advanced Power Station project and money pool activity. The increase was partially offset by:

• the receipt of $358.8 million in proceeds from the sale of assets related to the 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;
• a decrease of $53.2 million in transmission construction expenditures primarily due to decreased spending on various transmission projects in 2025;
• proceeds of $41.4 million received in 2025 from the transfer of assets related to the Segno Solar and Votaw Solar facilities from Entergy Texas to Entergy Louisiana. See “Uses and Sources of Capital - Segno Solar and Votaw Solar” below for discussion of the facilities and transfer; and
• a decrease of $23.0 million in distribution construction expenditures primarily due to lower capital expenditures for storm restoration in 2025, partially offset by higher capital expenditures as a result of increased development in Entergy Texas’s service area. The decrease in storm restoration expenditures is primarily due to Hurricane Beryl restoration efforts in 2024.

Increases in Entergy Texas’s receivable from the money pool are a use of cash flow, and Entergy Texas’s receivable from the money pool increased $4.0 million in 2025 compared to decreasing by $299.4 million in 2024. The money pool is an intercompany cash management program that makes possible intercompany borrowing and lending arrangements, and the money pool and other borrowing arrangements are designed to reduce the Registrant Subsidiaries’ dependence on external short-term borrowings.

Financing Activities

Net cash flow provided by financing activities increased $435.7 million in 2025 primarily due to:

• the issuance of $500 million of 5.25% Series mortgage bonds in February 2025;
• a capital contribution of $225 million received from Entergy Corporation in 2025 in order to maintain Entergy Texas’s capital structure and in anticipation of various capital expenditures; and
• the payment of $69 million of common stock dividends in 2024. No common stock dividends were paid in 2025 in order to maintain Entergy Texas’s capital structure.

The increase was partially offset by a decrease of $20.9 million in advance payments from customers for construction related to transmission, distribution, and generator interconnection agreements and the issuance of $350 million of 5.55% Series mortgage bonds in August 2024.

See Note 5 to the financial statements for additional details of long-term debt.

2024 Compared to 2023

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy Texas’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.

Capital Structure

Entergy Texas’s debt to capital ratio is shown in the following table.

(a) Calculation excludes the securitization bonds, which are non-recourse to Entergy Texas.

Net debt consists of debt less cash and cash equivalents. Debt consists of finance lease obligations and long-term debt, including the currently maturing portion. Capital consists of debt and equity. 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 Texas 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 Texas’s financial condition because the securitization bonds are non-recourse to Entergy Texas, as more fully described in Note 5 to the financial statements. Entergy Texas 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 Texas’s financial condition because net debt indicates Entergy Texas’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.

Entergy Texas seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that 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 the extent funds are legally available to do so, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Texas may issue incremental debt or reduce dividends, or both, to maintain its capital structure. In addition, Entergy Texas may receive equity contributions to maintain its capital structure for certain circumstances such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reduced dividends.

Uses of Capital

Entergy Texas requires capital resources for:

• construction and other capital investments;
• debt maturities or retirements;
• working capital purposes, including the financing of fuel and purchased power costs; and
• dividend and interest payments.

Following are the amounts of Entergy Texas’s planned construction and other capital investments.

(In Millions)

In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Texas includes investments in generation projects to modernize, decarbonize, expand, and diversify Entergy Texas’s portfolio, including Orange County Advanced Power Station, Lone Star Power Station, and Legend Power Station; distribution and Utility support spending to improve reliability, resilience, and customer experience; transmission spending to improve reliability and resilience while also supporting renewables expansion and customer growth; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, governmental actions, including trade-related governmental actions, such as tariffs and other measures, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, 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 Texas 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.

Recent announcements of changes to international trade policy and tariffs and further similar changes may impact Entergy Texas’s business, operations, results of operations, and liquidity and capital resources. Potential impacts may include increases in costs associated with Entergy Texas’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 Texas’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 Texas’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.

Entergy Texas has 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 its current and planned capital projects. Entergy Texas 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 subsidiaries, and trade-related governmental actions, such as tariffs and other measures, on its current and planned capital projects.

Following are the amounts of Entergy Texas’s existing debt and lease obligations (includes estimated interest payments).

(In Millions)

(a) Long-term debt is discussed in Note 5 to the financial statements.

(b) Lease obligations are discussed in Note 10 to the financial statements.

Other Obligations

Entergy Texas currently expects to contribute approximately $5.9 million to its qualified pension plans and approximately $149 thousand 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 Texas has $103.5 million of unrecognized tax benefits net of unused tax attributes plus interest and payments 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 build-to-suit lease arrangement for the Legend Power Station.

In addition, Entergy Texas enters into fuel and purchased power agreements that contain minimum purchase obligations. Entergy Texas has rate mechanisms in place to recover fuel, purchased power, and associated costs incurred under these purchase obligations.

As a subsidiary, Entergy Texas dividends its earnings to Entergy Corporation at a percentage determined monthly.

Orange County Advanced Power Station

In 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 Station

In 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.

Segno Solar and Votaw Solar

In 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.

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.

Legend to Sandling 230kV Transmission Line

In April 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 230 kV transmission line. The transmission line is expected to be approximately 9 to 10 miles in length and the estimated cost of the project ranges from $87.4 million to $88.6 million, depending on the route ultimately approved by the PUCT. Also in April 2025 the PUCT referred the proceeding to the State Office of Administrative Hearings. In July 2025, Entergy Texas filed an unopposed settlement agreement resolving all issues in the proceeding and a joint motion, which the ALJ with the State Office of Administrative Hearings granted, on behalf of the parties to the proceeding to cancel the remaining procedural schedule, to admit evidence, and to remand the proceeding to the PUCT to consider the unopposed settlement agreement. In September 2025 the PUCT issued a notice of approval for the requested amendment to Entergy Texas’s certificate of convenience and necessity to construct, own, and operate the new single-circuit 230 kV transmission line, with a selected route at an estimated cost of $87.6 million. Subject to receipt of required permits and other conditions, the facility is expected to be in service by second quarter 2027.

Cypress to Legend 500 kV Transmission Line

In 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

In 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.

Sources of Capital

Entergy Texas’s sources to meet its capital requirements include:

• internally generated funds;
• cash on hand;
• the Entergy system money pool;
• debt or preferred stock issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
• capital contributions; and
• bank financing under new or existing facilities.

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, Entergy Texas expects to continue, when economically feasible, to retire higher-cost debt and replace it with lower-cost debt if market conditions permit.

All debt and common and preferred stock issuances by Entergy Texas require prior regulatory approval. Debt issuances are also subject to requirements set forth in its bond indenture and other agreements. Entergy Texas has sufficient capacity under these tests to meet its foreseeable capital needs for the next twelve months and beyond.

Entergy Texas’s receivables from the money pool were as follows as of December 31 for each of the following years.

(In Thousands)

See Note 4 to the financial statements for a description of the money pool.

Entergy Texas has a credit facility in the amount of $300 million scheduled to expire in June 2030. The credit facility includes fronting commitments for the issuance of letters of credit against $25 million of the borrowing capacity of the facility. As of December 31, 2025, there were no cash borrowings and $1.1 million in letters of credit outstanding under the credit facility. In addition, Entergy Texas is a party to two uncommitted letter of credit facilities as a means to post collateral to support its obligations to MISO. As of December 31, 2025, $59.6 million in letters of credit were outstanding under one of Entergy Texas’s uncommitted letter of credit facilities. See Note 4 to the financial statements for additional discussion of the credit facilities.

Entergy Texas obtained authorizations from the FERC through January 2027 for short-term borrowings, not to exceed an aggregate amount of $200 million at any time outstanding, and long-term borrowings and security issuances. See Note 4 to the financial statements for further discussion of Entergy Texas’s short-term borrowing limits.

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.

State and Local Rate Regulation and Fuel-Cost Recovery

The rates that Entergy Texas charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Texas is regulated, and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the PUCT, is primarily responsible for approval of the rates charged to customers.

Filings with the PUCT and Texas Cities

Retail Rates

2022 Base Rate Case

In July 2022, Entergy Texas filed a base rate case with the PUCT seeking a net increase in base rates of approximately $131.4 million. The base rate case was based on a 12-month test year ending December 31, 2021. Key drivers of the requested increase were changes in depreciation rates as the result of a depreciation study and an increase in the return on equity. In addition, Entergy Texas included capital additions placed into service for the period of January 1, 2018 through December 31, 2021, including those additions reflected in the then-effective distribution and transmission cost recovery factor riders and the generation cost recovery rider, all of which were reset to zero in June 2023 as a result of this proceeding. In July 2022 the PUCT referred the proceeding to the State Office of Administrative Hearings. In October 2022 intervenors filed direct testimony challenging and supporting various aspects of Entergy Texas’s rate case application. The key issues addressed included the appropriate return on equity, generation plant deactivations, depreciation rates, and proposed tariffs related to electric vehicles. In November 2022 the PUCT staff filed direct testimony addressing a similar set of issues and recommending a reduction of $50.7 million to Entergy Texas’s overall cost of service associated with the requested net increase in base rates of approximately $131.4 million. Entergy Texas filed rebuttal testimony in November 2022.

In May 2023, Entergy Texas filed on behalf of the parties an unopposed settlement resolving all issues in the proceeding, except for issues related to electric vehicle charging infrastructure which were eventually severed to a separate proceeding and resolved in October 2024, and Entergy Texas filed an agreed motion for interim rates, subject to refund or surcharge to the extent that the interim rates differ from the final approved rates. The unopposed settlement reflected a net base rate increase to be effective and relate back to December 2022 of $54 million, exclusive of, and incremental to, the costs being realigned from the distribution and transmission cost recovery factor riders and the generation cost recovery rider and $4.8 million of rate case expenses to be recovered through a rider over a period of 36 months. The net base rate increase of $54 million includes updated depreciation rates and a total annual revenue requirement of $14.5 million for the accrual of a self-insured storm reserve and the recovery of the regulatory assets for the pension and postretirement benefits expense deferral, costs associated with the COVID-19 pandemic, and retired non-advanced metering system electric meters. In May 2023 the ALJ with the State Office of Administrative Hearings granted the motion for interim rates, which became effective in June 2023. Additionally, the ALJ remanded the proceeding to the PUCT to consider the settlement. In August 2023 the PUCT issued an order approving the unopposed settlement. Concurrently, Entergy Texas recorded the reversal of $21.9 million of regulatory liabilities to reflect the recognition of certain receipts by Entergy Texas under affiliated PPAs that have been resolved.

Following the PUCT’s approval of the unopposed settlement in August 2023, Entergy Texas recorded a regulatory liability of $10.3 million, which reflected the net effects of higher depreciation and amortizations for the relate back period, partially offset by the relate back of base rate revenues that would have been collected had the approved rates been in effect for the period from December 2022 through June 2023, the date the new base rates were implemented on an interim basis. In October 2023, Entergy Texas filed a relate back surcharge rider to collect over six months beginning in January 2024 an additional approximately $24.6 million, which was the revenue requirement associated with the relate back of rates from December 2022 through June 2023, including carrying costs, as authorized by the PUCT’s August 2023 order. In November 2023, Entergy Texas filed an amended relate back surcharge rider to collect approximately $24.1 million based on a revised carrying cost rate. The amended relate back surcharge rider was approved by the PUCT in December 2023. The higher depreciation and amortizations for the relate back period were also recognized over the six months beginning in January 2024, resulting in no effect on net income from the collection of the relate back surcharge rider.

Distribution Cost Recovery Factor (DCRF) Rider

In June 2024, Entergy Texas filed with the PUCT a request to set a new DCRF rider. The new rider was designed to collect from Entergy Texas’s retail customers approximately $40.3 million annually based on its capital invested in distribution between January 1, 2022 and March 31, 2024. In September 2024 the PUCT approved the DCRF rider, consistent with Entergy Texas’s as-filed request, and rates became effective with the first billing cycle in October 2024.

In September 2024, Entergy Texas filed with the PUCT a request to amend its DCRF rider. The amended rider was designed to collect from Entergy Texas’s retail customers approximately $48.9 million annually, or $8.6 million in incremental annual revenues beyond Entergy Texas’s then-effective DCRF rider based on its capital invested in distribution between April 1, 2024 and June 30, 2024. In December 2024, Entergy Texas filed an errata to revise its DCRF application for minor corrections, which decreased the requested annual revenue requirement to $48.5 million. The amended request represented an incremental increase of $8.2 million in annual revenues beyond Entergy Texas’s then-effective DCRF rider. Also in December 2024 the PUCT approved the DCRF rider, consistent with Entergy Texas’s filed errata, and rates became effective on December 20, 2024.

In April 2025, Entergy Texas filed with the PUCT a request to amend its DCRF rider. The amended rider was designed to collect from Entergy Texas’s retail customers approximately $77.8 million annually, or $29.3 million in incremental annual revenues beyond Entergy Texas’s then-effective DCRF rider based on its capital invested in distribution between July 1, 2024 and December 31, 2024, including distribution-related restoration costs associated with Hurricane Beryl. In June 2025 the PUCT approved the DCRF rider, consistent with Entergy Texas’s as-filed request, and rates became effective on June 25, 2025.

In September 2025, Entergy Texas filed with the PUCT a request to amend its DCRF rider. The amended rider was designed to collect from Entergy Texas’s retail customers approximately $94.7 million annually, or $16.9 million in incremental annual revenues beyond Entergy Texas’s then-effective DCRF rider based on its capital invested in distribution between January 1, 2025 and June 30, 2025. In November 2025, Entergy Texas filed an errata to revise its DCRF application for minor corrections, which decreased the requested annual revenue requirement to $92.1 million. The amended request represented an incremental increase of $14.3 million in annual revenues beyond Entergy Texas’s then-effective DCRF filing. In December 2025 the PUCT approved the DCRF rider, consistent with Entergy Texas’s filed errata, and rates became effective on December 15, 2025.

Transmission Cost Recovery Factor (TCRF) Rider

In December 2018, Entergy Texas filed with the PUCT a request to set a new TCRF rider. The new TCRF rider was designed to collect approximately $2.7 million annually from Entergy Texas’s retail customers based on its capital invested in transmission between January 1, 2018 and September 30, 2018. In April 2019 parties filed testimony proposing a load growth adjustment, which would fully offset Entergy Texas’s proposed TCRF revenue requirement. In July 2019 the PUCT granted Entergy Texas’s application as filed to begin recovery of the requested $2.7 million annual revenue requirement, rejecting opposing parties’ proposed adjustment; however, the PUCT found that the question of prudence of the actual investment costs should be determined in Entergy Texas’s next rate case similar to the procedure used for the costs recovered through the DCRF rider. In October 2019 the PUCT issued an order on a motion for rehearing, clarifying and affirming its prior order granting Entergy Texas’s application as filed. Also in October 2019 a second motion for rehearing was filed, and Entergy Texas filed a response in opposition to the motion. The second motion for rehearing was overruled by operation of law. In December 2019, Texas Industrial Energy Consumers filed an appeal to the PUCT order in district court alleging that the PUCT erred in declining to apply a load growth adjustment.

In October 2024, Entergy Texas filed with the PUCT a request to amend its TCRF rider, which was previously reset to zero in June 2023 as a result of the 2022 base rate case. The amended rider was designed to collect from Entergy Texas’s retail customers approximately $9.7 million annually based on its capital invested in transmission between January 1, 2022 and June 30, 2024 and changes in other transmission charges. In April 2025 the PUCT approved the TCRF rider, consistent with Entergy Texas’s as-filed request, and rates became effective for usage on and after April 7, 2025.

In October 2025, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The proposed rider is designed to collect from Entergy Texas’s retail customers approximately $30.3 million annually, or $20.6 million in incremental annual revenues beyond Entergy Texas’s currently effective TCRF rider based on its capital invested in transmission between July 1, 2024 and June 30, 2025 and changes in other transmission charges. In January 2026 the PUCT staff filed a recommendation that the PUCT approve Entergy Texas’s as-filed application.

Generation Cost Recovery Rider

In December 2020, Entergy Texas also filed an application to amend its generation cost recovery rider to reflect its acquisition of the Hardin County Peaking Facility, which closed in June 2021. Because the facility was to be acquired in the future, the initial generation cost recovery rider rates proposed in the application represented no change from the generation cost recovery rider rates established in Entergy Texas’s previous generation cost recovery rider proceeding. In July 2021 the PUCT issued an order approving the application. In August 2021, Entergy Texas filed an update application to recover its actual investment in the acquisition of the Hardin County Peaking Facility, and in January 2022, Entergy Texas filed an update to its application to align the requested revenue requirement with the terms of the generation cost recovery rider settlement approved by the PUCT in January 2022. In April 2022, Entergy Texas filed on behalf of the parties a unanimous settlement agreement that would adjust its generation cost recovery rider to recover an annual revenue requirement of approximately $92.8 million, which was $4.5 million in incremental annual revenue above the revenue requirement approved in January 2022 described above and related to Entergy Texas’s investment in the Montgomery County Power Station. The PUCT approved the settlement agreement and rates became effective in August 2022. In September 2022, Entergy Texas filed a relate-back rider designed to collect over three months an additional approximately $5.7 million, which is the revenue requirement, plus carrying costs, associated with Entergy Texas’s acquisition of Hardin County Peaking Facility from June 2021 through August 2022 when the updated revenue requirement took effect. In April 2023 the PUCT approved Entergy Texas’s as-filed request with rates effective over three months beginning in May 2023.

Fuel and purchased power cost recovery

Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, not recovered in base rates. Historically, semi-annual revisions of the fixed fuel factor have been made in March and September based on the market price of natural gas and changes in fuel mix. The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT. In 2023 the Texas legislature modified the Texas Utilities Code with regard to how material over- and under-recovered fuel balances are to be addressed and directed that fuel reconciliations must be filed at least once every two years. In July 2025 the PUCT initiated a rulemaking to effectuate the new legislation. In December 2025 the PUCT adopted amendments to its fuel rules that maintain a periodic revision to utility fuel factors coupled with accelerated processing of surcharges and refunds to address material over- and under-recovered amounts.

In September 2022, Entergy Texas filed an application with the PUCT to reconcile its fuel and purchased power costs for the period from April 2019 through March 2022. During the reconciliation period, Entergy Texas incurred approximately $1.7 billion in eligible fuel and purchased power expenses, net of certain revenues credited to such expenses and other adjustments. As of the end of the reconciliation period, Entergy Texas’s cumulative under-recovery balance was approximately $103.1 million, including interest, which Entergy Texas requested authority to carry over as the beginning balance for the subsequent reconciliation period beginning April 2022, pending future surcharges or refunds as approved by the PUCT. In November 2022 the PUCT referred the proceeding to the State Office of Administrative Hearings. In July 2023, Entergy Texas filed an unopposed settlement, supporting testimony, and an agreed motion to admit evidence and remand the proceeding to the PUCT. Pursuant to the unopposed settlement, Entergy Texas would receive no disallowance of fuel costs incurred over the three-year reconciliation period and retain $9.3 million in margins from off-system sales made during the reconciliation period, resulting in a cumulative under-recovery balance of approximately $99.7 million, including interest, as of the end of the reconciliation period. In July 2023 the ALJ with the State Office of Administrative Hearings granted the motion to admit evidence and remanded the proceeding to the PUCT for consideration of the unopposed settlement. The PUCT approved the settlement in September 2023.

In September 2024, Entergy Texas filed an application with the PUCT to reconcile its fuel and purchased power costs for the period from April 2022 through March 2024. During the reconciliation period, Entergy Texas incurred approximately $1.6 billion in eligible fuel and purchased power expenses to generate and purchase electricity to serve its customers, net of certain revenues credited to such expenses and other adjustments. Entergy Texas’s cumulative under-recovery balance for the reconciliation period was approximately $30 million, including interest, which Entergy Texas requested authority to carry over as part of the cumulative fuel balance for the subsequent reconciliation period beginning April 2024. In March 2025, Texas Industrial Energy Consumers, an intervenor, filed testimony regarding the recovery of capacity costs for a certain power purchase agreement, arguing the capacity costs should be imputed and treated as non-reconcilable fuel expense, recovered in Entergy Texas’s base rates. In April 2025 the PUCT staff filed testimony and later in April 2025, Entergy Texas filed rebuttal testimony. In August 2025, Entergy Texas filed an unopposed settlement agreement that results in no disallowance and establishes a regulatory asset for the future recovery of imputed capacity costs and associated carrying costs related to a certain purchased power agreement, with recovery effective retroactive to June 1, 2024. In October 2025 the PUCT approved the unopposed settlement agreement.

In December 2024, Entergy Texas filed an application with the PUCT to implement an interim fuel refund of $45.5 million, including interest. Entergy Texas proposed that the interim fuel refund be implemented over a three-month period beginning with the first billing cycle in February 2025 for residential and other small customers and through a one-time credit, or surcharge depending on historical usage for the respective customer, for certain transmission voltage level and seasonal agricultural customers in February 2025. Also in December 2024 the PUCT referred the proceeding to the State Office of Administrative Hearings. In January 2025 the ALJ with the State Office of Administrative Hearings issued an order approving the interim fuel refund consistent with Entergy

Texas’s application and, because no hearing was requested in the proceeding, dismissing the case from the State Office of Administrative Hearings and the PUCT.

Industrial and Commercial Customers

Entergy Texas’s large industrial and commercial customers continually explore ways to reduce their energy costs. Entergy Texas responds by working with industrial and commercial customers to negotiate electric service contracts, under existing rate schedules, with competitive rates that match specific customer needs and load profiles. Additionally, cogeneration is an option available to a portion of Entergy Texas’s industrial customer base. Entergy Texas actively participates in economic development, customer retention, and reclamation activities to increase industrial and commercial demand from both new and existing customers.

Federal Regulation

See the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.

Nuclear Matters

See the “Nuclear Matters” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of nuclear matters.

Environmental Risks

Entergy Texas’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Texas is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.

Critical Accounting Estimates

The preparation of Entergy Texas’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 Texas’s financial position, results of operations, or cash flows.

Utility Regulatory Accounting

See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.

Taxation and Uncertain Tax Positions

See “Taxation and Uncertain Tax Positions” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.

Qualified Pension and Other Postretirement Benefits

Entergy Texas’s qualified pension and other postretirement reported costs, 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. See “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. 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.

Cost Sensitivity

The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).

The following chart reflects the sensitivity of postretirement benefits cost and accumulated postretirement benefit obligation changes in certain actuarial assumptions (dollars in thousands).

Each fluctuation above assumes that the other components of the calculation are held constant.

Costs and Employer Contributions

Total qualified pension cost for Entergy Texas in 2025 was $2.7 million, including $617 thousand in settlement costs. Entergy Texas anticipates 2026 qualified pension cost to be $1.5 million. Entergy Texas contributed $7.7 million to its qualified pension plans in 2025 and estimates 2026 pension contributions will be approximately $5.9 million, 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.

Total postretirement health care and life insurance benefit income for Entergy Texas in 2025 was $10.6 million. Entergy Texas expects 2026 postretirement health care and life insurance benefit income to approximate $9.6 million. In 2025, Entergy Texas’ contributions to its other postretirement plans, specifically contributions to the external trusts plus claims payments, were offset by trust claims reimbursements, resulting in a net reimbursement of $171 thousand. Entergy Texas estimates that 2026 contributions will be approximately $149 thousand.

Other Contingencies

See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.

See the “New Accounting Pronouncements” section of Note 1 to the financial statements for a discussion of new accounting pronouncements.

To the shareholders and Board of Directors of

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Entergy Texas, Inc. and Subsidiaries (the “Company”) as of December 31, 2025 and 2024, the related consolidated statements of income, cash flows, and changes in equity (pages 449 through 454 and applicable items in pages 53 through 246), for each of the three years in the period ended December 31, 2025, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

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 Texas, Inc. and Subsidiaries — Refer to Note 2 to the financial statements

The Company is subject to rate regulation by the Public Utility Commission of Texas (the “PUCT”), which has jurisdiction with respect to the rates of electric companies in Texas, and to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). 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 Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the PUCT and the FERC set the rates the Company is allowed to charge customers based on allowable costs, including a reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company 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 Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the PUCT and the FERC 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 PUCT and the FERC, 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 PUCT and the FERC, 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 Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
• We read relevant regulatory orders issued by the PUCT and the FERC for the Company to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the PUCT’s and the FERC’s 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 Company’s filings with the PUCT and the FERC and orders issued, and considered the filings with the PUCT and the FERC by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.
• We obtained an analysis from management and support from 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.

Entergy Texas Build-to-Suit Lease Arrangement for the Legend Power Station—Entergy Texas, Inc. and Subsidiaries — Refer to Note 8 to the financial statements

In December 2025, the Company entered into a build-to-suit lease arrangement for the Legend Power Station (the “Facility”) as the lessee with a consortium of investors (“the Investors”). Under the terms of the arrangement, the Investors purchased the in-process Facility from the Company at cost of $359 million and will spend up to $1.45 billion (including the initial purchase price) to construct the Facility as designed by the Company. The Company is engaged to serve as the construction agent for the Facility. The Investors, however, control the Facility during construction. If the Company 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 the Company, causing a sale of the Facility to a third party, or certain other options. If there are certain changes to the terms of the PUCT approval of the Facility or certain other circumstances outside of the Company’s control, then either the Investors or the Company could exercise the right to terminate the arrangement, in which case the Company would be required to purchase the in-process Facility from the Investors at an amount equal to their costs incurred to date, including carrying costs. Since the Company does not control the in-process Facility, it will not recognize the Facility (i.e., construction work in progress) or an associated liability during construction.

Upon the Facility’s readiness for first synchronization to the grid, expected in early 2028, a triple-net lease will commence under which the Company will have control of the Facility and receive all output from the plant.

We identified management’s conclusion that the Company does not control the Facility being constructed before the commencement of the lease (i.e., during the construction period) and thus is not the deemed accounting owner of the Facility during the construction period as a critical audit matter due to the judgments made by management to support its conclusion. Auditing management’s judgments involved especially subjective judgment and specialized knowledge of accounting for lease transactions.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the build-to-suit lease arrangement for the Facility included the following, among others:

• We tested the effectiveness of management’s controls over the evaluation of the accounting impact of this build-to-suit lease arrangement, including the conclusion that the Company does not control the Facility being constructed before the commencement of the lease.
• We evaluated the Company’s disclosures related to the impacts of the build-to-suit lease arrangement.
• We read relevant transaction documents between the Company and the Investors as well as regulatory orders issued by the PUCT for the Company and evaluated the external information to compare to management’s conclusions.
• We obtained an analysis from management to assess management’s assertion that the Company does not control the Facility being constructed before the commencement date of the lease.
• With the assistance of professionals in our firm having expertise and experience in addressing the accounting for build-to-suit lease arrangements, we evaluated the Company’s analysis, including the conclusion that the Company does not control the Facility being constructed before the commencement date of the lease.
• We obtained representation from management regarding the conclusion that the Company does not control the Facility being constructed before the commencement date of the lease.

/s/ DELOITTE & TOUCHE LLP

ENTERGY TEXAS, INC. AND SUBSIDIARIES

CONSOLIDATED INCOME STATEMENTS

(In Thousands)

449

ENTERGY TEXAS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

451

ENTERGY TEXAS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

(In Thousands)

452

ENTERGY TEXAS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND EQUITY

(In Thousands)

453

ENTERGY TEXAS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

For the Years Ended December 31, 2025, 2024, and 2023

(In Thousands)

454

System Energy’s principal asset consists of an ownership interest and a leasehold interest in Grand Gulf. The capacity and energy from its 90% interest is sold under the Unit Power Sales Agreement to its only three customers, Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans. System Energy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% interest in Grand Gulf pursuant to the Unit Power Sales Agreement. See Note 8 to the financial statements for additional information regarding the amended Unit Power Sales Agreement. Payments under the Unit Power Sales Agreement are System Energy’s only source of operating revenues. As discussed in “Complaints Against System Energy” in Note 2 to the financial statements, System Energy and the Unit Power Sales Agreement have been the subject of several litigation proceedings at the FERC. Settlements that resolve all significant aspects of these complaints have been reached with the MPSC, the APSC, the City Council, and the LPSC, and these settlements have been approved by the FERC.

Results of Operations

2025 Compared to 2024

Net Income

Net income decreased $15.4 million primarily due to a lower rate of return on rate base, including the effects of the lower authorized rate of return on equity and capital structure limitations reflected in monthly bills issued to Entergy Louisiana effective with the September 2024 service month per the settlement agreement with the LPSC and the lower authorized rate of return on equity and capital structure limitations reflected in monthly bills issued to Entergy New Orleans effective with the June 2024 service month per the settlement agreement with the City Council. See Note 2 to the financial statements for discussion of the settlements with the City Council and the LPSC.

Income Taxes

The effective income tax rates were 18.2% for 2025 and 22.2% 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.

2024 Compared to 2023

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of System Energy’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.

Income Tax Legislation and Regulation

See the “Income Tax Legislation and Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of income tax legislation and regulation.

Cash Flow

Cash flows for the years ended December 31, 2025, 2024, and 2023 were as follows:

(In Thousands)

2025 Compared to 2024

Operating Activities

Net cash flow provided by operating activities increased $220.2 million in 2025 primarily due to:

• the receipt of $133.8 million related to the transfer of the 2024 nuclear production tax credits to third parties in 2025. See Note 3 to the financial statements for discussion of the nuclear production tax credits;
• the refund of $98.1 million made in 2024 to Entergy New Orleans as a result of the settlement with the City Council. See Note 2 to the financial statements for discussion of the settlement with the City Council;
• the refund of $92.7 million made in 2024 to Entergy Arkansas as a result of the settlement with the APSC. See Note 2 to the financial statements for discussion of the settlement with the APSC;
• the refund of $80.2 million made in 2024 to Entergy Louisiana as a result of the settlement with the LPSC. See Note 2 to the financial statements for discussion of the settlement with the LPSC; and
• a decrease of $16.8 million in spending on nuclear refueling outage costs in 2025 as compared to 2024.

The increase was partially offset by $174.4 million in payments to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans in 2025 related to the net proceeds from the transfers of the 2024 nuclear production tax credits in accordance with the Unit Power Sales Agreement. See Note 3 to the financial statements for discussion of the nuclear production tax credits.

Investing Activities

Net cash flow used in investing activities decreased by $126.7 million in 2025 primarily due to a decrease in cash used of $99.1 million as a result of fluctuations in nuclear fuel activity 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 a decrease of $32.7 million in nuclear construction expenditures primarily due to higher spending in 2024 on Grand Gulf outage projects and upgrades.

Financing Activities

System Energy’s financing activities used $89.4 million of cash in 2025 compared to providing $315.3 million of cash in 2024 primarily due to the following activity:

• the issuance of $300 million of 5.30% Series mortgage bonds in December 2024;
• the repayment, prior to maturity, of $200 million of 2.14% Series mortgage bonds in June 2025;
• a capital contribution of $150 million received from Entergy Corporation in January 2024 in order to maintain System Energy’s capital structure;
• net repayments of $36.3 million in 2025 compared to net long-term borrowings of $51.2 million in 2024 on the nuclear fuel company variable interest entity’s credit facility;
• money pool activity;
• a decrease of $70 million in common stock dividends and distributions paid in 2025 in order to maintain System Energy’s capital structure; and
• the issuance of $240 million of 5.30% Series mortgage bonds in May 2025.

Increases in System Energy’s payable to the money pool are a source of cash flow, and System Energy’s payable to the money pool increased $16.3 million in 2025 compared to decreasing by $12.2 million in 2024. The money pool is an intercompany cash management program that makes possible intercompany borrowing and lending arrangements, and the money pool and other borrowing arrangements are designed to reduce the Registrant Subsidiaries’ dependence on external short-term borrowings.

See Note 5 to the financial statements for additional details of long-term debt.

2024 Compared to 2023

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of System Energy’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.

Capital Structure

System Energy’s debt to capital ratio is shown in the following table.

Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings and long-term debt, including the currently maturing portion. Capital consists of debt and common equity. Net capital consists of capital less cash and cash equivalents. System Energy uses the debt to capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating System Energy’s financial condition. The net debt to net capital ratio is a non-GAAP measure. System Energy uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating System Energy’s financial condition because net debt indicates System Energy’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.

System Energy seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend or a capital distribution, to the extent funds are legally available to do so, or a combination of the three, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments and other uses of cash such as the payment of expenses in the ordinary course, System Energy may issue incremental debt or reduce dividends, or both, to maintain its capital structure. In addition, System Energy may receive equity contributions to maintain its capital structure for certain circumstances that would materially alter the capital structure if financed entirely with debt and reduced dividends.

Uses of Capital

System Energy requires capital resources for:

• construction and other capital investments;
• debt maturities or retirements;
• working capital purposes, including the financing of fuel costs and tax payments; and
• dividend, distribution, and interest payments.

Following are the amounts of System Energy’s planned construction and other capital investments.

(In Millions)

In addition to routine spending to maintain operations, the planned capital investment estimate includes amounts associated with Grand Gulf investments and initiatives. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, governmental actions, including trade-related governmental actions discussed below, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital, including any changes to governmental programs, such as loans, grants, guarantees, and other subsidies.

Recent announcements of changes to international trade policy and tariffs and further similar changes may impact System Energy’s business, operations, results of operations, and liquidity and capital resources. Potential impacts may include increases in costs associated with System Energy’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 System Energy’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 System Energy’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.

System Energy has 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 its current and planned capital projects. System Energy 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 its current and planned capital projects.

Following are the amounts of System Energy’s existing debt obligations (includes estimated interest payments).

(In Millions)

(a) Long-term debt is discussed in Note 5 to the financial statements.

Other Obligations

System Energy currently expects to contribute approximately $13.2 million to its qualified pension plans and approximately $49 thousand 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.

System Energy has $140.9 million of unrecognized tax benefits and interest net of unused tax attributes and payments 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.

In addition, System Energy enters into nuclear fuel purchase agreements that contain minimum purchase obligations. As discussed in Note 8 to the financial statements, System Energy recovers these costs through charges under the Unit Power Sales Agreement.

As a wholly-owned subsidiary, System Energy dividends its earnings to Entergy Corporation at a percentage determined monthly.

Sources of Capital

System Energy’s sources to meet its capital requirements include:

• internally generated funds;
• cash on hand;
• the Entergy system money pool;
• debt issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
• equity contributions; and
• bank financing under new or existing facilities.

Circumstances such fuel and purchased power price fluctuations and unanticipated expenses, including unscheduled plant outages, 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, System Energy expects to continue, when economically feasible, to retire higher-cost debt and replace it with lower-cost debt if market conditions permit.

All debt issuances by System Energy require prior regulatory approval. Debt issuances are also subject to requirements set forth in its bond indenture and other agreements. System Energy has sufficient capacity under these tests to meet its foreseeable capital needs for the next twelve months and beyond.

System Energy’s receivables from (payables to) the money pool were as follows as of December 31 for each of the following years.

(In Thousands)

See Note 4 to the financial statements for a description of the money pool.

The System Energy nuclear fuel company variable interest entity has a credit facility in the amount of $120 million scheduled to expire in June 2027. As of December 31, 2025, $36.4 million in loans were outstanding under the System Energy nuclear fuel company variable interest entity credit facility. See Note 4 to the financial statements for additional discussion of the variable interest entity credit facility.

System Energy obtained authorizations from the FERC through January 2027 for the following:

• short-term borrowings not to exceed an aggregate amount of $200 million at any time outstanding;
• long-term borrowings and security issuances; and
• borrowings by its nuclear fuel company variable interest entity.

See Note 4 to the financial statements for further discussion of System Energy’s short-term borrowing limits.

Federal Regulation

See the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.

Complaints Against System Energy

System Energy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% ownership/leasehold interest in Grand Gulf. System Energy sells its Grand Gulf capacity and energy to Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans, and sold to Entergy Louisiana through September 30, 2025, pursuant to the Unit Power Sales Agreement. System Energy and the Unit Power Sales Agreement have been the subject of several litigation proceedings at the FERC, including challenges with respect to System Energy’s authorized return on equity and capital structure, renewal of its sale-leaseback arrangement, treatment of uncertain tax positions, a broader investigation of rates under the Unit Power Sales Agreement, and two prudence complaints, one challenging the extended power uprate completed at Grand Gulf in 2012 and the operation and management of Grand Gulf, particularly in the 2016-2020 time period, and the second challenging the operation and management of Grand Gulf in the 2021-2022 time period. Settlements that resolve all significant aspects of these complaints have been reached with the MPSC, the APSC, the City Council, and the LPSC, and these settlements have been approved by the FERC. See “Complaints Against System Energy” in Note 2 to the financial statements for discussion of these complaint proceedings and settlements.

Unit Power Sales Agreement

System Energy Formula Rate Annual Protocols Formal Challenges Concerning 2020-2022 Calendar Year Bills

System Energy’s Unit Power Sales Agreement includes formula rate protocols that provide for the disclosure of cost inputs, an opportunity for informal discovery procedures, and a challenge process. In February 2022, pursuant to the protocols procedures, the LPSC, the APSC, the MPSC, the City Council, and the Mississippi Public Utilities Staff filed with the FERC a formal challenge to System Energy’s implementation of the formula rate during calendar year 2020. In March 2023, pursuant to the protocols procedures discussed above, the LPSC, the APSC, and the City Council filed with the FERC a formal challenge to System Energy’s implementation of the formula rate during calendar year 2021. In February 2024, pursuant to the protocols procedures, the LPSC and the City Council filed with the FERC a formal challenge to System Energy’s implementation of the formula rate during calendar year 2022. These formal challenges were ultimately settled as a result of System Energy’s global settlements with the MPSC, the APSC, the City Council, and the LPSC. See “Complaints Against System Energy” in Note 2 to the financial statements for further discussion of the System Energy settlements with the MPSC, the APSC, the City Council, and the LPSC.

Depreciation Amendment Proceeding

In December 2021, System Energy submitted to the FERC proposed amendments to the Unit Power Sales Agreement to adopt updated rates for use in calculating Grand Gulf plant depreciation and amortization expenses. The proposed amendments would result in higher charges to the Utility operating companies that buy capacity and energy from System Energy under the Unit Power Sales Agreement. In February 2022 the FERC accepted System Energy’s proposed increased depreciation rates with an effective date of March 1, 2022, subject to refund pending the outcome of the settlement and/or hearing procedures. In June 2023 System Energy filed with the FERC an unopposed offer of settlement that it had negotiated with intervenors to the proceeding. In August 2023 the FERC approved the settlement, which resolves the proceeding. In third quarter 2023, System Energy recorded a reduction in depreciation expense of $41 million representing the cumulative difference in depreciation expense resulting from the depreciation rates used from March 2022 through June 2023 and the depreciation rates included in the settlement filing approved by the FERC. In October 2023, System Energy filed a refund report with the FERC. The refund provided for in the refund report was included in the September 2023 service month bills under the Unit Power Sales Agreement. No comments or protests to the refund report were filed.

Pension Costs Amendment Proceeding

In October 2021, System Energy submitted to the FERC proposed amendments to the Unit Power Sales Agreement to include in rate base the prepaid and accrued pension costs associated with System Energy’s qualified pension plans. Based on data ending in 2020, the increased annual revenue requirement associated with the filing is approximately $8.9 million. In March 2022 the FERC accepted System Energy’s proposed amendments with an effective date of December 1, 2021, subject to refund pending the outcome of the settlement and/or hearing procedures. In August 2023 the FERC chief ALJ terminated settlement procedures and designated a presiding ALJ to oversee hearing procedures. Testimony was filed by the parties from October 2023 through April 2024, and the hearing concluded in June 2024.

In September 2024 the presiding ALJ issued an initial decision recommending that the FERC approve inclusion of a line item in rate base for prepaid and accrued pension costs; however, the presiding ALJ did not agree with System Energy’s proposed methodology to calculate the value of the prepaid and accrued pension cost input. Instead, the presiding ALJ recommended limiting System Energy’s recovery to the prepaid and accrued pension costs that were incurred beginning in 2015 and later. The ALJ’s initial decision was not binding on the FERC and was an interim step in the hearing process.

System Energy disputed the presiding ALJ's determination concerning the methodology used to calculate the prepaid and accrued pension input, and System Energy filed exceptions to these rulings in October 2024. In October 2024, the LPSC, the APSC, and the FERC trial staff filed separate briefs on exceptions; these parties generally argue that the presiding ALJ should have rejected System Energy’s filing entirely, rather than limit System Energy’s recovery of the prepaid and accrued pension costs. Later in October 2024, System Energy, the LPSC, the APSC, and the FERC trial staff filed separate briefs opposing exceptions.

In November 2025 the FERC issued an order on the initial decision and reversed the ALJ’s decision. The FERC approved System Energy’s proposed prepaid and accrued pension recovery mechanism. System Energy has been utilizing this methodology in billings since December 1, 2022 and will continue to utilize it going forward. As a result of the FERC’s order, System Energy does not owe any refunds. In December 2025 the APSC filed a request for rehearing of the November 2025 order. In January 2026 the FERC denied the APSC’s rehearing request by operation of law. The FERC indicated that the APSC’s request for rehearing will be addressed substantively in a future order. This proceeding is not covered by the global settlements described in Note 2 to the financial statements.

Nuclear Matters

System Energy owns and, through an affiliate, operates the Grand Gulf nuclear generating plant 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 Grand Gulf to meet its operational goals; the performance and capacity factors of Grand Gulf; 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 the 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. In the event of an unanticipated early shutdown of Grand Gulf, System Energy may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. Grand Gulf’s operating license expires in 2044.

Environmental Risks

System Energy’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that System Energy is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.

Critical Accounting Estimates

The preparation of System Energy’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 System Energy’s financial position, results of operations, or cash flows.

Nuclear Decommissioning Costs

See “Nuclear Decommissioning Costs” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates inherent in accounting for nuclear decommissioning costs.

Utility Regulatory Accounting

See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.

Taxation and Uncertain Tax Positions

See “Taxation and Uncertain Tax Positions” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.

Qualified Pension and Other Postretirement Benefits

System Energy’s qualified pension and other postretirement reported costs, 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. See “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. 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.

Cost Sensitivity

The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).

The following chart reflects the sensitivity of postretirement benefits cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).

Each fluctuation above assumes that the other components of the calculation are held constant.

Costs and Employer Contributions

Total qualified pension cost for System Energy in 2025 was $5.9 million, including $512 thousand in settlement costs. System Energy anticipates 2026 qualified pension cost to be $4.4 million. System Energy contributed $15.7 million to its qualified pension plans in 2025 and estimates 2026 pension contributions will be approximately $13.2 million, 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.

Total postretirement health care and life insurance benefit income for System Energy in 2025 was $855 thousand. System Energy expects 2026 postretirement health care and life insurance benefit income to approximate $257 thousand. System Energy contributed $1.2 million to its other postretirement plans in 2025 and expects 2026 contributions to approximate $49 thousand.

Other Contingencies

See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.

See the “New Accounting Pronouncements” section of Note 1 to the financial statements for a discussion of new accounting pronouncements.

To the shareholder and Board of Directors of

Opinion on the Financial Statements

We have audited the accompanying balance sheets of System Energy Resources, Inc. (the “Company”) as of December 31, 2025 and 2024, the related statements of income, cash flows, and changes in common equity (pages 467 through 472 and applicable items in pages 53 through 246), for each of the three years in the period ended December 31, 2025, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that is 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 matter below, providing a separate opinion on the critical audit matters or on the accounts or disclosures to which they relate.

Rate and Regulatory Matters — System Energy Resources, Inc. — Refer to Note 2 to the financial statements

The Company is subject to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). 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 Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the FERC sets the rates the Company is allowed to charge customers based on allowable costs, including a reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company 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 Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the FERC 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 FERC, 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 FERC, 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 Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
• We read relevant regulatory orders issued by the FERC for the Company to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the FERC’s 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 Company’s and intervenors’ filings with the FERC and FERC orders issued for any evidence that might contradict management’s assertions.
• We obtained an analysis from management and support from 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.

/s/ DELOITTE & TOUCHE LLP

SYSTEM ENERGY RESOURCES, INC.

INCOME STATEMENTS

(In Thousands)

467

SYSTEM ENERGY RESOURCES, INC.

STATEMENTS OF CASH FLOWS

(In Thousands)

469

SYSTEM ENERGY RESOURCES, INC.

BALANCE SHEETS

ASSETS

(In Thousands)

470

SYSTEM ENERGY RESOURCES, INC.

BALANCE SHEETS

LIABILITIES AND EQUITY

(In Thousands)

471

SYSTEM ENERGY RESOURCES, INC.

STATEMENTS OF CHANGES IN COMMON EQUITY

For the Years Ended December 31, 2025, 2024, and 2023

(In Thousands)

472