EDGAR 10-K Filing

Company CIK: 71508
Filing Year: 2025
Filename: 71508_10-K_2025_0000065984-25-000012.json

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ITEM 1. BUSINESS
Item 1. Business
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 and gas 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 and gas 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.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
•The reputation of Entergy or its Registrant Subsidiaries may be materially adversely affected by negative publicity or the inability to meet their stated goals or commitments, 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 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.
•The effect of higher purchased gas cost charges to customers taking gas service may adversely affect Entergy New Orleans’s results of operations 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, the 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.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
ENTERGY’S BUSINESS
Entergy is an integrated energy company engaged primarily in electric power production and retail distribution operations. Entergy owns and operates power plants with approximately 25,000 MW of electric generating capacity. Entergy delivers electricity to approximately 3 million Utility customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy had annual revenues of $11.9 billion in 2024 and had approximately 12,000 employees as of December 31, 2024.
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; and operation of a small natural gas distribution business in portions of Louisiana. See “Held for Sale - Natural Gas Distribution Businesses” in Note 14 to the financial statements for discussion of the planned sale of the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses. Entergy completed its multi-year strategy to exit the merchant nuclear power business in 2022. See Note 13 to the financial statements for discussion of and financial information regarding Entergy’s business segments.
Strategy
Entergy’s strategy is to operate and grow its utility business through a customer-centric approach designed to understand and meet customer needs, creating value for all of its key stakeholders, including customers, communities, employees, and owners. As part of its strategy, Entergy invests significant capital to support customer growth and its customers’ growing demands for greater reliability, resilience, and clean energy, while remaining focused on affordability. Entergy manages risks by ensuring its Utility investments are customer-driven, the result of robust analysis, supported by broad stakeholder outreach and progressive regulatory constructs, and executed with disciplined project management. Further, Entergy continues to integrate key sustainability elements, including social responsibility and good governance, into every decision it makes.
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. Entergy Louisiana and Entergy New Orleans also provide natural gas utility services to customers in and around Baton Rouge, Louisiana, and New Orleans, Louisiana, respectively. See “Held for Sale - Natural Gas Distribution Businesses” in Note 14 to the financial statements for discussion of the planned sale of the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses. 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 Louisiana, Entergy Mississippi, and Entergy New Orleans. 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 is being effectuated initially under a designated PPA between Entergy Louisiana and Entergy Mississippi, effective as of January 1, 2025. 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 increasingly carbon-free energy sources, which is consistent with Entergy’s strong support for the environment.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Customers
As of December 31, 2024, the Utility operating companies provided retail electric and gas service to customers in Arkansas, Louisiana, Mississippi, and Texas, as follows:
Electric Customers Gas Customers
Area Served (In Thousands) (%) (In Thousands) (%)
Entergy Arkansas Portions of Arkansas 735 24
Entergy Louisiana Portions of Louisiana 1,110 37 96 47
Entergy Mississippi Portions of Mississippi 459 15
Entergy New Orleans City of New Orleans 209 7 108 53
Entergy Texas Portions of Texas 524 17
Total
3,037 100 204 100
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 August 6, 2024, Entergy reached a 2024 peak demand of 22,697 MWh, compared to the 2023 peak of 23,319 MWh recorded on August 23, 2023. Selected electric energy sales data for 2024 is shown in the table below:
Entergy Arkansas Entergy Louisiana Entergy Mississippi Entergy New Orleans Entergy Texas System Energy Entergy (a)
(GWh)
Sales to retail customers 23,605 60,703 12,744 5,597 21,202 - 123,851
Sales for resale:
Affiliates 2,039 5,808 - - - 9,586 -
Others 4,058 1,574 5,568 2,123 687 - 14,010
Total 29,702 68,085 18,312 7,720 21,889 9,586 137,861
Average use per residential customer (kWh) 12,549 14,602 14,167 12,457 14,276 - 13,844
(a)Includes the effect of intercompany eliminations.
The following table illustrates the Utility operating companies’ 2024 combined electric sales volume as a percentage of total electric sales volume, and 2024 combined electric revenues as a percentage of total 2024 electric revenue, each by customer class.
Customer Class % of Sales Volume % of Revenue
Residential 26.1 38.8
Commercial 20.5 25.4
Industrial (a) 41.4 27.5
Governmental 1.8 2.3
Wholesale/Other 10.2 6.0
(a)Major industrial customers are primarily in the petroleum refining and chemical industries.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Natural Gas Energy Sales
Entergy New Orleans and Entergy Louisiana provide both electric power and natural gas to retail customers. Entergy New Orleans and Entergy Louisiana sold 8,872,535 Mcf and 6,816,140 Mcf, respectively, of natural gas to retail customers in 2024. In 2024, 99% of Entergy Louisiana’s operating revenue was derived from the electric utility business and only 1% from the natural gas distribution business. For Entergy New Orleans, 87% of operating revenue was derived from the electric utility business and 13% from the natural gas distribution business in 2024.
Following is data concerning Entergy New Orleans’s 2024 retail operating revenue sources:
Customer Class % of Electric Operating Revenue % of Natural Gas Operating Revenue
Residential 48 56
Commercial 35 26
Industrial 5 5
Governmental/Municipal 12 13
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.
Rate base (in billions) Current authorized return on common equity Weighted-average cost of capital (after-tax) Equity ratio Regulatory construct
Entergy Arkansas $11.3 (a) 9.15% - 10.15% 5.58%
37.9% (b)
- forward test year formula rate plan
- riders: fuel and purchased power, MISO, capacity, Grand Gulf, energy efficiency
Entergy Louisiana (electric) $16.4 (c) 9.3% - 10.1% 6.81% 50.81% - formula rate plan through 2023 test year
- riders: fuel, capacity, MISO, transmission, distribution, resilience plan
Entergy Louisiana (gas) $0.16 (d) 9.3% - 10.3% 7.08% 54.35% - gas rate stabilization plan
- rider: gas infrastructure
Entergy Mississippi $4.5 (e) 9.91% - 11.92% 7.52% 49.67% - formula rate plan with forward-looking features
- riders: fuel, Grand Gulf, MISO, unit power cost, storm damage mitigation and restoration, ad valorem tax adjustment, grid modernization, restructuring credit, power management
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Rate base (in billions) Current authorized return on common equity Weighted-average cost of capital (after-tax) Equity ratio Regulatory construct
Entergy New Orleans (electric) $1.3 (f) 8.85% - 9.85% 7.28% 55% (g) - formula rate plan with forward-looking features
- riders: fuel and purchased power, MISO, energy efficiency, environmental, capacity costs
Entergy New Orleans (gas) $0.2 (f) 8.85% - 9.85% 7.28% 55% (g) - formula rate plan with forward-looking features
- rider: purchased gas
Entergy Texas $4.4 (h) 9.57% 6.61% 51.2% - historical test year rate case and interim rate base riders (distribution, transmission, and generation cost recovery riders)
- riders: fuel, capacity, cost recovery riders (distribution, transmission, and generation), rate case expenses, and advanced metering infrastructure surcharge, among others
System Energy $1.83 (i) 9.65% 7.41% 52.0% - monthly cost of service
(a)Based on 2025 test year.
(b)Based on $2.0 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, 2023 test year and excludes approximately $100 million of transmission plant investment included in the transmission recovery mechanism and approximately $300 million of distribution plant investment included in the distribution recovery mechanism, as well as approximately $400 million of net accumulated deferred tax liability items included in the tax adjustment mechanism.
(d)Based on September 30, 2023 test year.
(e)Based on 2024 forward test year.
(f)Based on December 31, 2023 test year and known and measurables through December 31, 2024.
(g)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.
(h)Based on December 31, 2021 test year and excludes $0.5 billion in cost recovery riders.
(i)Based on calculation as of December 31, 2024 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 $1.82 billion as of December 31, 2024. 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
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Entergy Corporation, Utility operating companies, and System Energy
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 2026. As part of Entergy Arkansas’s base rate case in 2026, Entergy Arkansas may 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.
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
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Entergy Corporation, Utility operating companies, and System Energy
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, with a status conference requested for May 2025.
Entergy Louisiana’s gas rates include a purchased gas adjustment clause based on estimated gas costs for the billing month adjusted by a surcharge or credit that arises from an annual reconciliation of fuel costs incurred with fuel cost revenues billed to customers, including carrying charges.
Retail Rates - Gas
In accordance with the settlement of Entergy Gulf States Louisiana’s gas rate stabilization plan for the test year ended September 30, 2012, in August 2014, Entergy Gulf States Louisiana submitted for consideration a proposal for implementation of an infrastructure rider to recover expenditures associated with strategic plant investment and relocation projects mandated by local governments. After review by the LPSC staff and inclusion of certain customer safeguards required by the LPSC staff, in December 2014, Entergy Gulf States Louisiana and the LPSC staff submitted a joint settlement for implementation of an accelerated gas pipe replacement program providing for the replacement of approximately 100 miles of pipe over the next ten years, as well as relocation of certain existing pipe resulting from local government-related infrastructure projects, and for a rider to recover the investment associated with these projects. The rider allows for recovery of approximately $65 million over ten years. The rider recovery will be adjusted on a quarterly basis to include actual investment incurred for the prior quarter and is subject to the following conditions, among others: a ten-year term; application of any earnings in excess of the upper end of the earnings band as an offset to the revenue requirement of the infrastructure rider; adherence to a specified spending plan, within plus or minus 20% annually; annual filings comparing actual versus planned rider spending with actual spending and explanation of variances exceeding 10%; and an annual true-up. The joint settlement was approved by the LPSC in January 2015. Implementation of the infrastructure rider commenced with bills rendered on and after the first billing cycle of April 2015. In April 2022, Entergy Louisiana submitted for consideration a proposal to extend the infrastructure rider to address replacement of an additional 187 miles of pipe. In December 2022, Entergy Louisiana and the LPSC staff submitted an uncontested settlement that extends the rider for an additional ten years beginning after the end of the current term of the rider in 2025. The extension is subject to the same customer safeguards and conditions as the original term of the rider. The extension
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Entergy Corporation, Utility operating companies, and System Energy
allows for recovery of approximately $95 million over ten years. In February 2023 the uncontested settlement was approved by the LPSC.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Louisiana’s filings to recover storm-related costs.
LPSC Customer-Centered Options Rulemaking
In December 2019, an LPSC commissioner issued an unopposed directive to the LPSC staff to research customer-centered options for all customer classes, as well as other regulatory environments and recommend a plan for how to ensure customers are the focus. Since 2020, the LPSC staff has issued several requests for information on proposed scope and information related to retail open access, and interested parties filed responses to the requests.
In June 2024 the LPSC staff issued its Final Phase 1 Report setting forth a recommendation on sleeved PPAs, including many features similar to utility green tariffs previously approved by the LPSC, and adopting numerous limits and safeguards that had been proposed in comments by LPSC-jurisdictional utilities. The Final Phase 1 Report also addressed various new reporting requirements for all LPSC-jurisdictional utilities, including reliability metrics, customer counts, customers receiving federal Low-Income Home Energy Assistance Program aid, utility authorized and earned returns on equity, and other items. The report also recommended that the LPSC adopt requirements that, with each rate filing, a utility report certain information regarding bill impacts and similar matters. In June 2024 the LPSC voted unanimously to approve the LPSC staff’s Final Phase 1 Report and proposal, and an order was issued in August 2024.
In December 2024 the LPSC staff issued its Phase 2 Report, addressing enhanced combined heat and power options, energy displacement sleeved PPAs, and other matters. The LPSC staff also issued various data requests to be answered by all jurisdictional utilities. The LPSC staff has indicated that the Phase 3 Report, which will address partial or full retail open access and other issues that were deferred from the Phase 2 Report, is expected to be completed by the third quarter 2025. In January 2025, Entergy Louisiana filed a motion asking the LPSC to provide renewed guidance as to whether the inquiry in this proceeding into the remaining issues in the Phase 3 Report is appropriate and consistent with the LPSC’s current policy objectives, or whether the docket has achieved its purpose and may be closed. The LPSC is expected to consider the motion at its March 2025 meeting.
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
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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.
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.
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Entergy Corporation, Utility operating companies, and System Energy
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 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
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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.
Entergy New Orleans’s gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges.
To help stabilize gas costs, Entergy New Orleans seeks approval annually from the City Council to continue implementation of its natural gas hedging program consistent with the City Council’s stated policy objectives. The program uses financial instruments to hedge exposure to volatility in the wholesale price of natural gas purchased to serve Entergy New Orleans gas customers. Entergy New Orleans hedges up to 25% of actual gas sales made during the winter months.
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.
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.
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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 to provide that material over- and under-recovered fuel balances are to be refunded or surcharged through interim fuel adjustments and that fuel reconciliations must be filed at least once every two years. Entergy Texas expects the PUCT to undertake a rulemaking to effectuate the new legislation in 2025.
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.
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.
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Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Texas’s filings to recover storm-related costs.
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.
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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. Entergy Louisiana holds non-exclusive franchises to provide natural gas service to customers in the City of Baton Rouge and in East Baton Rouge Parish. Municipal franchise agreement terms range from 25 to 60 years while parish franchise terms range from 25 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 and gas 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 and gas 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 2025-2058.
The business of System Energy is limited to wholesale power sales. It has no distribution franchises.
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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, 2024 is indicated below:
Owned and Leased Capability MW(a)
Company Total CT / CCGT (b) Legacy Gas/Oil Nuclear (c) Coal Hydro (c) Solar (c)
Entergy Arkansas 5,559 1,547 522 1,821 967 72 630
Entergy Louisiana 10,809 5,629 2,789 2,052 339 - -
Entergy Mississippi 2,964 1,739 707 - 416 - 102
Entergy New Orleans 662 635 - - - - 27
Entergy Texas 3,234 990 1,994 - 250 - -
System Energy 1,251 - - 1,251 - - -
Total 24,479 10,540 6,012 5,124 1,972 72 759
(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 21,998 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 8,702 MW of new long-term resources and the deactivation of about 4,242 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
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products, including long-term contractual products and asset acquisitions. The RFP process has resulted in selections or acquisitions, including, among other things:
•In November 2018, Entergy Mississippi signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Sunflower Solar facility, located in Sunflower County, Mississippi. Entergy Mississippi received regulatory approval from the MPSC in April 2020, and closed on the acquisition, through use of a tax equity partnership, in May 2022. The Sunflower Solar facility commenced commercial operation in September 2022;
•In March 2019, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Searcy Solar facility, located in White County near Searcy, Arkansas. Entergy Arkansas received regulatory approval from the APSC in April 2020, and closed on the acquisition, through use of a tax equity partnership, in December 2021. The Searcy Solar facility commenced commercial operation in January 2022;
•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 November 2021, Entergy Louisiana signed an agreement for the purchase of an approximately 150 MW to-be-constructed solar photovoltaic energy facility, St. Jacques facility, to be sited in St. James Parish near Vacherie, Louisiana. In September 2022 the LPSC issued an order approving the St. Jacques facility; however, following the LPSC approval, the St. James Parish council issued a moratorium on new land use permits for solar facilities. 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 June 2024 the St. James Parish council denied the project developer’s solar energy facility farm permit 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. Entergy Louisiana is currently monitoring the status of the aforementioned lawsuits and also considering alternate paths forward;
•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 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 is expected to achieve commercial operation in January 2026;
•Entergy Mississippi will begin construction on the Delta Solar facility, an 80 MW solar facility to be located in Bolivar County, Mississippi, in April 2026. The facility is expected to achieve commercial operation by the end of 2027; and
•Entergy Mississippi will begin construction on the Penton Solar facility, a 190 MW solar facility in December 2025. The facility is expected to achieve commercial operation by early 2028.
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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 (only 60 MW of this PPA came through the RFP process). 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;
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•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 June 2021, Entergy Louisiana and Vacherie Solar Energy Center, LLC executed a 20-year PPA for 150 MW from a to-be-constructed solar photovoltaic electric generating facility located in St. James Parish, Louisiana. In September 2022 the LPSC voted to issue an order approving the Vacherie facility; however, following the LPSC approval, the St. James Parish council issued a moratorium on new land use permits for solar facilities. 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 June 2024 the St. James Parish council denied the project developer’s solar energy facility farm permit 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. Entergy Louisiana is currently monitoring the status of the aforementioned lawsuits and also considering alternate paths forward;
•In December 2022, Entergy Mississippi and Hinds Solar, LLC executed a 20-year PPA for approximately 150 MW from a to-be-constructed solar photovoltaic energy facility located in Hinds County, Mississippi. In August 2023 the MPSC approved the PPA;
•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 is expected to reach commercial operation in 2026;
•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 is expected to reach commercial operation as early as September 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 is expected to reach commercial operation as early as November 2025;
•In January 2023, Entergy Louisiana and Coastal Prairie Solar, LLC executed a 20-year PPA for approximately 175 MW from a to-be-constructed solar photovoltaic energy facility located in Iberville Parish, Louisiana. In January 2024 the LPSC approved the PPA, and the facility is expected to reach commercial operation as early as December 2027; 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 an RFP for solar generation resources. Entergy Texas selected a combination of PPA and owned resources in March 2022. The PPA negotiations were terminated after failure to reach agreement on terms. In July 2024, Entergy Texas filed an application with the PUCT seeking regulatory approval for the owned resource, the 141 MW Votaw Solar facility. Subject to receipt of required regulatory approval and other conditions, the Votaw Solar facility is expected to be in service by mid-2028.
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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, and negotiation of definitive agreements for the remaining resources are in progress.
In October 2022, Entergy Services, on behalf of Entergy Texas, issued an RFP for solar photovoltaic and wind resources. Entergy Texas selected a combination of PPA, build-own-transfer, and owned resources in July 2023. The PPA and build-own-transfer negotiations were terminated after failure to reach agreement on terms. In July 2024, Entergy Texas filed an application with the PUCT seeking regulatory approval for the owned resource, the 170 MW Segno Solar facility. Subject to receipt of required regulatory approval and other conditions, the Segno Solar facility is expected to be in service by early 2027.
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, and negotiation of a definitive agreement is in progress.
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. The RFP is expected to continue through 2026 with 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. The RFP is expected to continue through 2025 with selections expected in third quarter 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;
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•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.
Power Through Programs
In February 2019, Entergy Mississippi proposed a new technologies pilot to the MPSC, which was approved in December 2019. The pilot, previously referred to as the Power Through program, further modernized the energy grid and met customers’ evolving expectations by offering utility-owned, natural gas-fired backup generators to customers. Following conclusion of the three-year pilot, in October 2023, Entergy Mississippi proposed full-scale 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 full-scale 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.
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 megawatts 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
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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. A PUCT decision is expected in the first quarter of 2025.
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. 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 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.
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 January 2024, Amazon Web Services announced its plan to invest in two data centers located in Madison County, Mississippi. In March 2024, Entergy Mississippi executed a large customer supply and service agreement to serve the two data centers. In February 2025, Entergy Mississippi entered into a new large customer supply and service agreement with a customer. 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 addition, some of the Utility operating companies are engaged in discussions with other prospective customers concerning potential service to other data center projects. Because of the significant demand and energy needs associated with these facilities, which generally require power at levels near their maximum level of 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, although this risk can potentially be mitigated through appropriate commercial terms 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
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prospective customer to contribute significant funds 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 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 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, 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 the Entergy’s own sustainability commitments 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.
Gas Property
As of December 31, 2024, Entergy New Orleans distributed and transported natural gas for distribution within New Orleans, Louisiana, through approximately 2,600 miles of gas pipeline. As of December 31, 2024, the gas properties of Entergy Louisiana, which are located in and around Baton Rouge, Louisiana, were not material to Entergy Louisiana’s financial position. See “Held for Sale - Natural Gas Distribution Businesses” in Note 14 to the financial statements for discussion of the planned sale of the Entergy New Orleans and Entergy Louisiana natural gas distribution businesses.
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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 2022-2024 were:
Year Natural Gas Nuclear Coal Renewables (a) Purchased Power MISO Purchases (b)
2024 (Cents Per kWh)
Entergy Arkansas 2.02 0.57 3.04 1.67 10.21 0.37
Entergy Louisiana 2.30 0.73 3.34 11.48 3.70 2.32
Entergy Mississippi 1.86 - 2.60 0.11 2.36 2.89
Entergy New Orleans (c) 2.26 - - 3.60 - 2.75
Entergy Texas 2.04 - 3.33 3.53 6.80 2.80
System Energy - 0.65 - - - -
Utility 2.14 0.65 3.00 5.85 3.73 2.38
Entergy Arkansas 1.98 0.50 3.09 1.98 11.57 0.77
Entergy Louisiana 2.34 0.60 3.22 10.38 3.76 2.50
Entergy Mississippi 2.21 - 2.82 0.03 5.86 1.84
Entergy New Orleans (c) 2.05 - - 3.24 - 2.33
Entergy Texas 2.29 - 3.17 2.25 5.64 3.18
System Energy - 0.68 - - - -
Utility 2.25 0.58 3.06 6.14 4.03 2.61
Entergy Arkansas 4.98 0.52 2.93 2.11 10.90 (2.65)
Entergy Louisiana 5.50 0.57 2.84 10.70 6.95 6.45
Entergy Mississippi 4.38 - 2.85 0.04 6.53 6.68
Entergy New Orleans (c) 5.10 - - (5.16) - 7.21
Entergy Texas 5.77 - 2.83 6.26 5.61 6.68
System Energy - 0.65 - - - -
Utility 5.27 0.57 2.89 7.00 6.54 5.95
(a)Includes average fuel costs from both owned and purchased power resources.
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(b)Includes activity from financial transmission rights. See Note 15 to the financial statements for discussion of financial transmission rights.
(c)Entergy New Orleans’s renewables include liquidated damage payments of $0.5 million in 2024, $0.1 million in 2023, and $2.9 million in 2022 due to the delay of in-service dates related to purchased power agreements.
Actual 2024 and projected 2025 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:
CT / CCGT (b) Legacy Gas Nuclear (c) Coal Renewables (c) (d) Purchased Power (e) MISO Purchases (f)
Entergy Arkansas 29 % 1 % 56 % 6 % 4 % - % 4 %
Entergy Louisiana 45 % 10 % 20 % 1 % 2 % 8 % 14 %
Entergy Mississippi 65 % 2 % 20 % 7 % 1 % - % 5 %
Entergy New Orleans 46 % 2 % 41 % 1 % 2 % 1 % 7 %
Entergy Texas 32 % 28 % 11 % 3 % 2 % - % 24 %
System Energy (a) - % - % 100 % - % - % - % - %
Utility 42 % 10 % 27 % 3 % 2 % 4 % 12 %
CT / CCGT (b) Legacy Gas Nuclear (c) Coal Renewables (c) (d) Purchased Power (e) MISO Purchases (f)
Entergy Arkansas 28 % - % 59 % 5 % 8 % - % - %
Entergy Louisiana 52 % 4 % 23 % 2 % 3 % 16 % - %
Entergy Mississippi 60 % - % 30 % 9 % 1 % - % - %
Entergy New Orleans 51 % 1 % 43 % 1 % 3 % 1 % - %
Entergy Texas 46 % 32 % 14 % 6 % 2 % - % - %
System Energy (a) - % - % 100 % - % - % - % - %
Utility 47 % 6 % 32 % 4 % 4 % 7 % - %
(a)Capacity and energy from System Energy’s interest in Grand Gulf is allocated as follows under the Unit Power Sales Agreement: Entergy Arkansas - 36%; Entergy Louisiana - 14%; Entergy Mississippi - 33%; and Entergy New Orleans - 17%. Pursuant to purchased power agreements, Entergy Arkansas is selling a portion of its owned capacity and energy from Grand Gulf to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. Effective January 1, 2025, Entergy Louisiana has 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 is being effectuated initially under a designated PPA between Entergy Louisiana and Entergy Mississippi, effective as of January 1, 2025. See Note 8 to the financial statements for discussion of Entergy Louisiana’s divestiture from 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.
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(f)In December 2013, Entergy integrated its transmission system into the MISO RTO. Entergy offers all of 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, with MISO making dispatch decisions. The MISO purchases metric provided for 2024 is not projected for 2025.
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 fuel oil use in 2025, 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 70% 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 seven one- to three-year contracts that will supply at least 85% of the total coal supply needs in 2025. 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 2025. 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 2025.
Entergy Louisiana has committed to three two- to three-year contracts that will supply at least 90% of Nelson Unit 6 coal needs in 2025. 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 2025. Coal will be transported to Nelson via an existing transportation agreement that is expected to provide all of Entergy Louisiana’s rail transportation requirements for 2025.
For the year ended December 31, 2024, 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 2025 are expected to continue to be consistent with 2024 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, Louisiana Generating, LLC, has advised Entergy Louisiana and Entergy Texas that it has adequate rail car and barge capacity to meet the volumes of PRB coal requested for 2025.
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Entergy Louisiana’s and Entergy Texas’s coal nomination requests to Big Cajun 2 - Unit 3 are made on an annual basis.
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 2027. 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, like uranium, 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.
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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.
Natural Gas Purchased for Resale
Entergy New Orleans has several suppliers of natural gas. Its system is interconnected with one interstate and three intrastate pipelines. Entergy New Orleans has a “no-notice” service gas purchase contract with Symmetry Energy Solutions which ensures Entergy New Orleans gas delivery at specific delivery points and at any volume within the minimum and maximum set forth in the contract amounts. The Symmetry Energy Solutions gas supply is transported to Entergy New Orleans pursuant to a transportation service agreement with Gulf South Pipeline Co. This service is subject to FERC-approved rates. Entergy New Orleans also makes interruptible spot market purchases.
Entergy Louisiana has been purchasing natural gas for resale since April 2024 under a firm contract with Symmetry Energy Solutions. Entergy Louisiana’s prior contract with Sequent Energy Management L.P. was not renewed and ended in March 2024. The gas is delivered through a combination of intrastate and interstate pipelines.
As a result of the implementation of FERC-mandated interstate pipeline restructuring in 1993, curtailments of interstate gas supply could occur if Entergy Louisiana’s or Entergy New Orleans’s suppliers failed to perform their obligations to deliver gas under their supply agreements. Gulf South Pipeline Co. could curtail transportation capacity only in the event of pipeline system constraints.
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 Louisiana, 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 regulation 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 is now pursuing a larger scale reassessment of its overall accreditation practices, including accreditation of renewable resources.
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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 to 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.
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 Louisiana, 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 to Entergy Arkansas (36%), Entergy Louisiana (14%), Entergy Mississippi (33%), and Entergy New Orleans (17%). Effective January 1, 2025, Entergy Louisiana is divesting all of its rights, entitlements, and interests in such capacity and energy to Entergy Mississippi. See Note 8 to the financial statements for discussion of Entergy Louisiana’s divestiture from the Unit Power Sales Agreement. Each of these companies is obligated to make payments to System Energy for its 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 Louisiana, Entergy Mississippi, and Entergy New Orleans generally recover payments made under the Unit Power Sales Agreement through rates charged to their customers; however, as discussed further below, for the majority of 2025 and until it is removed from the Unit Power Sales Agreement, Entergy Louisiana will recover its payments made under the Unit Power Sales Agreement from Entergy Mississippi under a designated PPA in connection with Entergy Louisiana’s divesting to Entergy Mississippi its 14% share of capacity and energy from Grand Gulf under the Unit Power Sales Agreement and its 2.43% share of capacity and energy from Entergy Arkansas under the MSS-4 replacement tariff.
In the case of Entergy Arkansas and Entergy Louisiana, payments are also recovered through sales of electricity from their respective retained shares of Grand Gulf. Under a settlement agreement entered into with the APSC in 1985 and amended in 1988, Entergy Arkansas retains 22% of its 36% share of Grand Gulf-related costs
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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. Entergy Arkansas has life-of-resources purchased power agreements with Entergy Louisiana and Entergy New Orleans that sell a portion of the output of Entergy Arkansas’s retained share of Grand Gulf to those companies. The remainder of Entergy Arkansas’s retained share is sold to Entergy Mississippi through a separate life-of-resource purchase power agreement with Entergy Mississippi. Entergy Arkansas also has a life-of-resources purchased power agreement with Entergy Mississippi to sell a portion of the output of Entergy Arkansas’s non-retained share of Grand Gulf. Entergy Mississippi was granted cost recovery for those purchases by the MPSC through its annual unit power cost rate mechanism.
In a series of LPSC orders, court decisions, and agreements from late 1985 to mid-1988, Entergy Louisiana was granted cost recovery with respect to costs associated with Entergy Louisiana’s share of capacity and energy from Grand Gulf, subject to certain terms and conditions. Prior to the divestiture of Grand Gulf energy and capacity to Entergy Mississippi, Entergy Louisiana retained and did not recover from retail ratepayers 18% of its 14% share of the costs of Grand Gulf capacity and energy and recovers the remaining 82% of its share in rates. Entergy Louisiana was also allowed to recover through the fuel adjustment clause at 4.6 cents per kWh for the energy related to its retained portion of these costs. Alternatively, Entergy Louisiana was permitted to sell such energy to non-affiliated parties at prices above the fuel adjustment clause amount, subject to the LPSC’s approval.
Effective January 1, 2025, Entergy Louisiana has 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 is being effectuated initially under a designated PPA between Entergy Louisiana and Entergy Mississippi, which was accepted by the FERC in November 2024. The MPSC approved the MSS-4 replacement PPA, effective as of January 1, 2025. In 2025, System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans expect to file an amendment to the UPSA that will modify the purchasers’ entitlements to capacity and energy from System Energy’s share of Grand Gulf to reflect Entergy Louisiana’s divestiture, and when that amendment becomes effective, the designated PPA between Entergy Louisiana and Entergy Mississippi will terminate and Entergy Louisiana will cease to be a System Energy customer. The effectiveness of that amendment to the Unit Power Sales Agreement will be subject to the review and acceptance of the FERC.
Availability Agreement
The Availability Agreement among System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans was entered into in 1974 in connection with the original financing by System Energy of Grand Gulf. The Availability Agreement provides that System Energy make available to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans all capacity and energy available from System Energy’s share of Grand Gulf.
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.
The allocation percentages under the Availability Agreement are fixed as follows: Entergy Arkansas - 17.1%; Entergy Louisiana - 26.9%; Entergy Mississippi - 31.3%; and Entergy New Orleans - 24.7%. The allocation percentages under the Availability Agreement would remain in effect and would 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.
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System Energy has assigned its rights to payments and advances from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under the Availability Agreement as security for all of its outstanding series of first mortgage bonds, as well as for its 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 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.
Each of the assignment agreements relating to the Availability Agreement provides that Entergy Arkansas, Entergy Louisiana, 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 Louisiana, Entergy Mississippi, and Entergy New Orleans to make payments under the Availability Agreement are subject to the receipt and continued effectiveness of all necessary regulatory approvals. Sales of capacity and energy under the Availability Agreement would require that the 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 Availability Agreement, the jurisdictional portions of the 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 the Availability Agreement and, therefore, no payments under the Availability Agreement to System Energy have ever been required. However, if Entergy Arkansas or Entergy Mississippi fails to make its Unit Power Sales Agreement payments, and System Energy is unable to obtain funds from other sources, Entergy Louisiana and Entergy New Orleans could become subject to claims or demands by System Energy or certain of its creditors for payments or advances under the Availability Agreement (or the assignments thereof) equal to the difference between their required Unit Power Sales Agreement payments and their required Availability Agreement payments because their allocated shares under the Availability Agreement exceed their allocated shares under the Unit Power Sales Agreement.
The Availability Agreement may be terminated, amended, or modified by mutual agreement of the parties thereto, without further consent of any assignees or other creditors. Effective January 1, 2025, Entergy Mississippi entered into a Reimbursement Agreement with Entergy Louisiana, under which it agreed to assume Entergy Louisiana’s rights and obligations under and to hold Entergy Louisiana harmless with respect to the Availability Agreement. That Reimbursement Agreement is intended to be in effect until the Unit Power Sales Agreement is modified to reflect Entergy Mississippi’s increased entitlements to System Energy’s share of Grand Gulf energy and capacity, following Entergy Louisiana’s divestiture of its combined 16.43% share of the Unit Power Sales Agreement and purchased power agreement entitlements to energy and capacity to Entergy Mississippi. When the Unit Power Sales Agreement modifications become effective, System Energy also anticipates implementing an Availability Agreement that reflects the Unit Power Sales Agreement entitlements of Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans.
In December 2024, System Energy, Entergy Louisiana, Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans agreed to terminate the Reallocation Agreement. See Note 8 to the financial statements for further discussion of the reallocation agreement.
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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 to the Utility operating companies and System Energy on an “at cost” basis, pursuant to cost allocation methodologies for these service agreements that were approved by the FERC.
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. 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.
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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:
Plant Location Ownership Net Owned Capacity (a) Type
Independence Unit 2; 842 MW Newark, AR 14% 121 MW(b) Coal
Nelson Unit 6; 550 MW Westlake, LA 11% 60 MW(b) Coal
(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 Louisiana, 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,
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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’s electric and gas business 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, environmental adjustment charge, and purchased gas 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 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.
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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 generating facilities, certain transmission projects, and certain 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 and purchased gas 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.
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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, 2024 of $216 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
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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 2022, 2023, and 2024 related to Entergy’s nuclear owner/licensee subsidiaries’ litigation with the DOE. Through 2024, 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 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
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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 2023 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. In addition to this, insurance for property damage, costs of replacement power, and other risks relating to nuclear generating units is also purchased. 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.
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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.
Clean Air Act and Subsequent Amendments
The Clean Air Act and its amendments establish several programs that currently or in the future may affect Entergy’s fossil-fueled generation facilities and, to a lesser extent, certain operations at nuclear and other facilities. Individual states also operate similar independent state programs or delegated federal programs that may include requirements more stringent than federal regulatory requirements. These programs include:
•new source review and preconstruction permits for new sources of criteria air pollutants, greenhouse gases, and significant modifications to existing facilities;
•acid rain program for control of sulfur dioxide (SO2) and nitrogen oxides (NOx);
•nonattainment area programs for control of criteria air pollutants, which could include fee assessments for air pollutant emission sources under Section 185 of the Clean Air Act if attainment is not reached in a timely manner;
•hazardous air pollutant emissions reduction programs;
•interstate air transport;
•operating permit programs and enforcement of these and other Clean Air Act programs;
•regional haze programs; and
•new and existing source standards for greenhouse gas and other air emissions.
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
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requires state regulatory authorities to prepare state implementation plans 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 within two years, by May 2026. For any areas designated as nonattainment for this revised standard, State Implementation Plans (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 2021-2023 for Pulaski County and Union County, Arkansas, West Baton Rouge Parish, Louisiana, Harris County, Texas and Hinds 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 will be based on data from 2022-2024. Entergy will continue to work with state environmental agencies on appropriate methods for assessing attainment and nonattainment with this revised fine particulate NAAQS.
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. An additional one-year extension is possible for the installation of controls, if necessary. Entergy is currently evaluating its coal units to determine whether additional controls are necessary to comply with this new lower limit.
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 SO2 and 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
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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. Stays of the SIP disapprovals have been granted in all four states in which the Utility operating companies operate, and the FIP will not go into effect while the stays are in place. Decisions on the merits regarding the respective SIP disapprovals are expected in 2025. 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. Entergy is monitoring this litigation and assessing its compliance options in the event that the FIP becomes effective.
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. 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 September 2024 and the Louisiana Department of Environmental Quality (LDEQ) is currently reviewing comments received on the revised proposal. The agency, 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.
The Texas Commission on Environmental Quality has completed its second-planning period SIP and submitted it to the EPA for review. There were no Entergy sources selected for additional emission controls. In June 2024, the EPA entered into a consent decree that sets deadlines for the EPA to take final action on 34 states’ SIP submittals. This includes Arkansas and Texas, which are due August 2026 and May 2025, respectively.
The Mississippi Department of Environmental Quality also did not meet the July 31, 2021 SIP submission deadline. In June 2023 Mississippi issued its proposed SIP for public notice and comment but did not propose additional pollution controls for Entergy sources.
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In August 2022 the EPA issued findings of failure to submit regional haze SIPs to 15 states, including Louisiana and Mississippi. 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 EPA has not yet proposed a FIP for Louisiana or Mississippi.
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 commitment 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. Entergy continues to monitor the status of the litigation.
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 low overall carbon dioxide emission “intensity,” or rate of carbon dioxide emitted per megawatt-hour of electricity generated. In anticipation of the imposition of carbon dioxide emission limits on the electric industry, Entergy initiated actions designed to reduce its exposure to potential new governmental requirements related to carbon dioxide emissions. These voluntary actions included a formal program to stabilize owned power plant carbon dioxide emissions at 2000 levels through 2005, and Entergy succeeded in reducing emissions below 2000 levels. In 2006, Entergy started including emissions from controllable power purchases in addition to its ownership share of generation and established a second formal voluntary program to stabilize power plant carbon dioxide emissions and emissions from controllable power purchases, cumulatively over the period, at 20% below 2000 levels through 2010. In 2011, Entergy extended this commitment through 2020, which it ultimately outperformed by approximately 8% both cumulatively and on an annual basis. In 2019, in connection with a climate scenario analysis following the recommendations of the Task Force on Climate-related Financial Disclosures describing climate-related governance, strategy, risk management, and metrics and targets, Entergy announced a 2030 carbon dioxide emission rate goal focused on a 50% reduction from Entergy’s base year - 2000.
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In September 2020, Entergy announced a commitment to achieve net-zero greenhouse gas emissions by 2050 inclusive of all businesses, all applicable gases, and all emission scopes. In 2022, Entergy enhanced its commitment to include an interim goal of 50% carbon-free energy generating capacity by 2030 and expanded its interim emission rate goal to include all purchased power. Due to stronger than initially expected sales growth, likely necessitating the development of new generation capacity that is not carbon-free, Entergy expects that achievement of the 50% carbon-free energy generating capacity goal will be delayed for a period beyond 2030 that has not yet been determined. In addition, while current planning assumptions indicate the 2030 emission rate goal remains achievable, its achievement could also be challenged as a result of the forecasted and future sales growth. See “Risk Factors” in Part I, Item 1A for discussion of the risks associated with achieving these climate goals. Entergy’s comprehensive, third party verified greenhouse gas inventory and progress against its voluntary goals are published on its website.
Potential Legislative, Regulatory, and Judicial 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;
•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.
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Comprehensive Environmental Response, Compensation, and Liability Act of 1980
The Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (CERCLA), authorizes the EPA to mandate clean-up by, or to collect reimbursement of clean-up costs from, owners or operators of sites at which hazardous substances may be or have been released. Certain private parties also may use CERCLA to recover response costs. Parties that transported hazardous substances to these sites or arranged for the disposal of the substances are also deemed liable by CERCLA. CERCLA has been interpreted to impose strict, joint, and several liability on responsible parties. Many states have adopted programs similar to CERCLA. Entergy subsidiaries have sent waste materials to various disposal sites over the years, and releases have occurred at Entergy facilities including nuclear facilities that have been sold to decommissioning companies. In addition, environmental laws now regulate certain of Entergy’s operating procedures and maintenance practices that historically were not subject to regulation. Some disposal sites used by Entergy subsidiaries have been the subject of governmental action under CERCLA or similar state programs, resulting in site clean-up activities. Entergy subsidiaries have participated to various degrees in accordance with their respective potential liabilities in such site clean-ups and have developed experience with clean-up costs. The affected Entergy subsidiaries have established provisions for the liabilities for such environmental clean-up and restoration activities. Details of potentially material CERCLA and similar state program liabilities are discussed in the “Other Environmental Matters” section below.
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 no longer are 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 CCR management units 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. 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
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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, 2024, Entergy has recorded asset retirement obligations related to CCR management of $73 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.
Clean Water Act
The 1972 amendments to the Federal Water Pollution Control Act (known as the Clean Water Act) provide the statutory basis for the National Pollutant Discharge Elimination System permit program, section 402, and the basic structure for regulating the discharge of pollutants from point sources to waters of the United States. The Clean Water Act requires virtually all discharges of pollutants to waters of the United States to be permitted. Section 316(b) of the Clean Water Act regulates cooling water intake structures, section 401 of the Clean Water Act requires a water quality certification from the state in support of certain federal actions and approvals, and section 404 of the Clean Water Act regulates the dredge and fill of waters of the United States, including jurisdictional wetlands.
Federal Jurisdiction of Waters of the United States
In June 2020 the EPA’s revised definition of waters of the United States in the Navigable Waters Protection Rule (NWPR) became effective, narrowing the scope of Clean Water Act jurisdiction, as compared to a 2015 definition which had been stayed by several federal courts. In August 2021 a federal district court vacated and remanded the NWPR for further consideration. The EPA and the U.S. Army Corps of Engineers (Corps) subsequently issued a statement that the agencies would revert to pre-2015 regulations pending a new rulemaking. In December 2022 the EPA and the Corps released a final definition of waters of the United States (the 2022 Rule) that replaces the NWPR with a definition that is consistent with the pre-2015 regulatory regime as interpreted by several United States Supreme Court decisions. The 2022 Rule was subject to multiple legal challenges and was enjoined from implementation or enforcement throughout Entergy’s utility service territory. In May 2023 the U.S. Supreme Court issued a decision limiting the scope of federal jurisdiction over wetlands, and in September 2023 the EPA and the Corps issued a final rule incorporating the Supreme Court decision. Most notably, the exclusion for waste treatment systems is retained.
Effluent Limitation Guidelines
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. To be covered by this exemption, both Independence and Nelson Unit 6 will need to file Notices of Planned Participation in the 2034 subcategory by December 31, 2025. 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. Entergy continues to evaluate the compliance pathways and obligations of this rule.
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Other Environmental Matters
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy Texas
The EPA notified Entergy that the EPA believes Entergy is a 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. Liability and PRP allocation of response costs are yet to be determined. 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. Negotiations between the PRPs and the EPA are ongoing.
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.
Human Capital
Employees
Employees are an integral part of Entergy’s commitment to serving customers. As of December 31, 2024, Entergy subsidiaries employed 12,267 people.
Entergy Arkansas 1,314
Entergy Louisiana 1,669
Entergy Mississippi 770
Entergy New Orleans 302
Entergy Texas 741
System Energy -
Entergy Operations 3,211
Entergy Services 4,245
Entergy Nuclear Operations 13
Other subsidiaries 2
Total Entergy 12,267
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There are 3,105 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.
Below is the breakdown of Entergy’s employees by gender and race/ethnicity:
Gender (%) (a) 2024 2023
Female 23.0 23.0
Male 77.0 77.0
Race/Ethnicity (%) (a) 2024 2023
White 73.2 73.1
Black/African American 18.4 18.2
Hispanic/Latino 3.3 3.2
Asian 2.5 2.4
Other 2.6 3.1
(a)Based on employees who self-identify.
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 focuses on an approach that includes, among other things, governance and oversight; safety; organizational health, including diversity, 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, diversity, inclusion and belonging, organizational health, retention, 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, reviews workforce-related metrics, 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 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
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significant improvement on the company’s performance of 0.48 in 2023 and 0.51 in 2022. 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. Despite an active storm season in 2024, Entergy was able to manage restoration during the two named storms in Entergy’s service territory with only a single contractor heat related injury. The results of 2024 unfortunately included an increase in significant injuries and fatalities, including four contractor fatalities after almost 900 days without experiencing a single employee or contractor fatality. In response to the increase in significant injuries and fatalities, Entergy has enhanced its focused training, leadership efforts, and field presence for employees and contractors to further the objective of zero fatalities, which the company had been able to achieve in 2022 and 2023.
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 2022 of 61 (third quartile), in 2023 of 62 (third quartile), and in 2024 of 65 (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 diversity, inclusion, and belonging 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 diversity, 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
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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 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. All such postings and filings are available on Entergy’s Investor Relations website free of charge. 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.
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ITEM 1A. RISK FACTORS
Item 1A. Risk Factors
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 and gas 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, the operation and maintenance of their assets and
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
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 could 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 and natural gas 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. Entergy and the Utility operating companies cannot predict if or when they may be subject to changes in legislation, 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
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
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 increased tariffs or as a result of changes to governmental policies and programs, including 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 their respective retail regulators 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, 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, 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 projects being approved and constructed that are interconnected with their transmission systems.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
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, 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 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 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 whether by the Utility operating companies or by other MISO load-serving entities.
In addition, a large volume of parties and individual generation resources 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.
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
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
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 and gas 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 and gas 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 having a more permanent effect by reducing sales growth rates from historical norms. As a result of these 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
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
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, 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 sales, such as from large data center customers 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 2027. Entergy’s ability to purchase
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
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,
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
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 2024, 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
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
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 $72.2 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
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
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.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
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. The occurrence of one or more 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) 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 being unwilling to invest 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 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, 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.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
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, or increased bad debt expense;
•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;
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
•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 with Entergy’s safety culture; challenges or negative reaction to Entergy’s diversity, inclusion, and belonging efforts, or work culture and environment; challenges or negative reaction to Entergy’s climate goals; inability to meet their climate goals, 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, inclusive, and diverse workforce with 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.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
Recent 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 interpretive guidance issued by the IRS and state tax authorities may be inconsistent with Entergy’s own 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, or any other changes to or repeal 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 two to four 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 2024, 2023, and 2022 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, 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.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
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 commitments, 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 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 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. These customers may represent a high percentage of total sales, revenues, and cash flow with respect to the applicable Utility operating company and thereby create business 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. For example, each of Entergy Louisiana and Entergy New Orleans have entered into purchase and sale agreements to sell their respective regulated natural gas local distribution company businesses to a third-party. Also, a significant portion of 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
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
•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 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 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 customer 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 may engage in additional similar transactions in the future.
This concentration of business with a small number of customers in an industry based on emerging technologies, including artificial intelligence and machine learning, presents several risks for these Utility operating companies. These technologies and their related business applications have developed rapidly in recent years and continue to develop. 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. Additionally, these customers may experience business downturn, which may cause the loss of these customers or may weaken their financial condition. Similarly, customers may reduce their investment in these new technologies or abandon them entirely.
Any of these situations may result in the early termination or non-renewal of these customers’ electric service agreements or renewal on terms less favorable to the 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. In the event a customer does not renew its electric service agreement, the Utility operating companies are also subject to the risk that they may not be able to enter into services agreements with new customers or that 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. The small number of such customers and scale of the investment required to support those customers exacerbates 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 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, 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, direct and indirect
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
trade and tariff issues, 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, involve 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, project management expertise, 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 poor quality initial cost estimates from contractors; 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 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.
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.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
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. 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, rising salary and other labor costs, unavailability of contract resources, and labor disputes and work disruptions 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, 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, 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. 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.
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. 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.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
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 the achievement of voluntary climate commitments 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.
In an effort to address climate change concerns, some federal, state, and local authorities have been calling for additional laws and regulations aimed at known or suspected causes of climate change. For example, the EPA, various environmental interest groups, and other organizations have focused considerable attention on CO2 emissions from power generation facilities and their potential role in climate change. The EPA has promulgated regulations controlling greenhouse gas emissions from certain vehicles, and has proposed regulations for new, existing, and significantly modified stationary sources of emissions, 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. In Louisiana, the former Office of the Governor announced in 2020 the creation of a Climate Initiatives Task Force and issued an executive order that established a path to net-zero emissions by 2050, while in 2021, the City Council of New Orleans passed 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 voluntary climate commitments 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 could 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 inability to meet Entergy’s voluntary climate commitments, could negatively impact Entergy’s reputation or inhibit Entergy’s ability to pursue its 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.
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 Entergy’s 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
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
stranded costs if Entergy’s 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.
In March 2019, Entergy voluntarily set a climate goal to achieve a 50 percent reduction in its carbon emission rate from the year 2000 by 2030. In September 2020, Entergy voluntarily committed to achieving net zero carbon emissions by 2050. In November 2022, Entergy voluntarily set a climate goal to achieve 50 percent carbon-free energy capacity by 2030. Due to stronger than initially expected sales growth, likely necessitating the development of new generation capacity that is not carbon-free, Entergy expects that achievement of the 50% carbon-free energy generating capacity goal will be delayed for a period beyond 2030 that has not yet been determined. In addition, achievement of the 2030 emission rate goal could also be challenged as a result of the forecasted and future sales growth. Further risks to achieving the 2030 and 2050 goals include, among other things, the ability to execute on renewable resource plans, regulatory approvals, customer demand for carbon-free energy that exceeds Entergy’s or its Utility operating companies’ ability to add lower carbon or carbon-free capacity, load growth, potential tariffs, carbon policy and regulation at the federal or state level, including mandates related to reliability standards, and supply chain costs and constraints. Technology research and development, innovation, and advancements in carbon-free generation are also critical to Entergy’s ability to achieve its 2050 commitment. Entergy cannot predict the ultimate impact of achieving these objectives, or the various implementation aspects, on its system reliability, or its results of operations, financial condition, or liquidity.
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 recent increase 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. 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
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
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 and its subsidiaries.
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 and its subsidiaries.
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
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
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 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, 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.
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.
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.
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
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
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.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
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 arrangement 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. We 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, such insurance prices have increased substantially, and 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, higher premiums, and more restrictive terms and conditions. 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.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
(Entergy New Orleans)
The effect of higher purchased gas cost charges to customers taking gas service may adversely affect Entergy New Orleans’s results of operations and liquidity.
Gas rates charged to retail gas customers are comprised primarily of purchased gas cost charges, which provide no return or profit to Entergy New Orleans, and distribution charges, which provide a return or profit to the utility. Distribution charges recover fixed costs on a volumetric basis and, thus, are affected by the amount of gas sold to customers. When purchased gas cost charges increase due to higher gas procurement costs, customer usage may decrease, especially in weaker economic times, resulting in lower distribution charges for Entergy New Orleans, which, given its relatively smaller size, could adversely affect results of operations. Purchased gas cost charges, which comprise most of a customer’s bill and may be adjusted monthly, represent gas commodity costs that Entergy New Orleans recovers from its customers. Entergy New Orleans’s cash flows can be affected by differences between the time when gas is purchased and the time when ultimate recovery from customers occurs.
(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, the 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 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 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. 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
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
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 stock of its subsidiaries. Accordingly, all of its operations are conducted by its subsidiaries. Entergy Corporation has provided, and may continue to provide, 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’s common stock. 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. 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, dividends and distributions 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.
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.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
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.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B. Unresolved Staff Comments
None.

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ITEM 2. PROPERTIES
Item 2. Properties
Information regarding the registrant’s properties is included in Part I, Item 1. - Entergy’s Business under the sections titled “Utility - Property and Other Generation Resources” and “Other Business Activities - Property” in this report.

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ITEM 3. LEGAL PROCEEDINGS
Item 3. Legal Proceedings
Details of the registrant’s material environmental regulation and proceedings and other regulatory proceedings and litigation that are pending or those terminated in the fourth quarter of 2024 are discussed in Part I, Item 1. - Entergy’s Business under the sections titled “Retail Rate Regulation,” “Environmental Regulation,” and “Litigation.”

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4. Mine Safety Disclosures
Not applicable.
INFORMATION ABOUT EXECUTIVE OFFICERS OF ENTERGY CORPORATION
Executive Officers
Name Age Position Period
Andrew S. Marsh (a) 53 Chief Executive Officer of Entergy Corporation 2022-Present
Chair of the Board of Entergy Corporation
2023-Present
Executive Vice President and Chief Financial Officer of Entergy Corporation 2013-2022
Director of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy 2013-2022
Executive Vice President and Chief Financial Officer of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy 2014-2022
Kimberly A. Fontan (a) 51 Executive Vice President and Chief Financial Officer of Entergy Corporation 2022-Present
President and Chair of the Board of System Energy
2024-Present
Director of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy Texas, and System Energy 2022-Present
Executive Vice President and Chief Financial Officer of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy 2022-Present
Senior Vice President and Chief Accounting Officer of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy 2019-2022
Marcus V. Brown (a) 63 Executive Vice President and General Counsel of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy 2013-Present
Name Age Position Period
Jason Chapman (a)
54 Senior Vice President, Chief Technology and Business Services Officer of Entergy Corporation
2023-Present
Acting Senior Vice President, Corporate Business Services of Entergy Services 2023
Vice President, Enterprise Shared Services of Entergy Services 2019-2023
Kathryn A. Collins (a)
61 Senior Vice President and Chief Human Resources Officer of Entergy Corporation 2020-Present
Chief Human Resources Officer, Arcosa, Inc. 2018-2020
Kimberly Cook-Nelson (a) 52 Executive Vice President and Chief Nuclear Officer of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy 2022-Present
Director of System Energy 2022-Present
Chief Operating Officer, Nuclear Operations of Entergy Services 2021-2022
Vice President, System Planning of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas 2019-2021
John O. Hudson, III 54 Chief External Affairs Officer, Entergy Corporation 2024-Present
Senior Vice President, Federal Policy, Regulatory and Government Affairs, Entergy Services LLC 2022-2024
President, Entergy Charitable Foundation 2022-Present
President and Chief Executive Officer, Nicor Gas 2020-2022
Executive Vice President, External Affairs and Customer Operations, Southern Company Gas 2018-2020
Anastasia Minor 55 Chief Transformation Officer of Entergy Services 2023-Present
Senior Vice President, Strategy and Financial Planning of Entergy Services 2022-2023
Vice President, Financial Business Partners of Entergy Services 2017-2022
Peter S. Norgeot, Jr. (a) 59 Executive Vice President and Chief Operating Officer of Entergy Corporation 2022-Present
Director of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas 2022-Present
Senior Vice President, Operations and Development of Entergy Corporation 2022
Senior Vice President, Sustainable Planning, Development and Operations of Entergy Corporation 2021-2022
Senior Vice President, Transformation of Entergy Corporation 2018-2021
Reginald T. Jackson (a) 58 Senior Vice President and Chief Accounting Officer of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy 2022-Present
Vice President, Internal Audit and General Auditor of Entergy Services 2020-2022
Director, Real Estate and Security of Entergy Services 2014-2020
(a)In addition, this officer is an executive officer and/or director of various other wholly owned subsidiaries of Entergy Corporation and its operating companies.
Each officer of Entergy Corporation is elected yearly by the Board of Directors. Each officer’s age and title are provided as of December 31, 2024.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5. Market for Registrants’ Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities
Entergy Corporation
The shares of Entergy Corporation’s common stock are listed on the New York Stock and Chicago Stock Exchanges under the ticker symbol ETR. As of January 31, 2025, there were 18,974 stockholders of record of Entergy Corporation. See “Dividends and Stock Repurchases” in the “Capital Expenditure Plans and Other Uses of Capital” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 7 to the financial statements for details of Entergy Corporation’s payment of dividends.
Issuer Purchases of Equity Securities (1)
Period Total Number of Shares Purchased Average Price Paid per Share Total Number of Shares Purchased as Part of a Publicly Announced Plan Maximum $ Amount of Shares that May Yet be Purchased Under a Plan (2)
10/01/2024 - 10/31/2024
- $- - $350,052,918
11/01/2024 - 11/30/2024
- $- - $350,052,918
12/01/2024 - 12/31/2024
- $- - $350,052,918
Total - $- -
In accordance with Entergy’s stock-based compensation plans, Entergy periodically grants stock options to key employees, which may be exercised to obtain shares of Entergy’s common stock. According to the plans, these shares can be newly issued shares, treasury stock, or shares purchased on the open market. Entergy’s management has been authorized by the Board to repurchase on the open market shares up to an amount sufficient to fund the exercise of grants under the plans. In addition to this authority, the Board has authorized share repurchase programs to enable opportunistic purchases in response to market conditions. In October 2010 the Board granted authority for a $500 million share repurchase program. The amount of share repurchases under these programs may vary as a result of material changes in business results or capital spending or new investment opportunities. In addition, in the first quarter 2024, Entergy withheld 203,920 shares of its common stock at $49.66 per share, 105,036 shares of its common stock at $49.43 per share, 3,462 shares of its common stock at $51.97 per share, 632 shares of its common stock at $51.32 per share, 464 shares of its common stock at $51.39 per share, 82 shares of its common stock at $50.08 per share, and 12 shares of its common stock at $52.34 per share to pay income taxes due upon vesting of restricted stock granted and payout of performance units as part of its long-term incentive program.
(1)All share and per share amounts reflect the two-for-one forward stock split effective December 12, 2024. See Note 7 to the financial statements for discussion of the stock split. See Note 12 to the financial statements for additional discussion of the stock-based compensation plans.
(2)Maximum amount of shares that may yet be repurchased relates only to the $500 million share repurchase program plan and does not include an estimate of the amount of shares that may be purchased to fund the exercise of grants under the stock-based compensation plans.
Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy
There is no market for the common equity of the Registrant Subsidiaries.

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ITEM 6. SELECTED FINANCIAL DATA
Item 6. Reserved

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Refer to “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS” of each of Entergy Corporation and Subsidiaries, Entergy Arkansas, LLC and Subsidiaries, Entergy Louisiana, LLC and Subsidiaries, Entergy Mississippi, LLC and Subsidiaries, Entergy New Orleans, LLC and Subsidiaries, Entergy Texas, Inc. and Subsidiaries, and System Energy Resources, Inc.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Refer to “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS OF ENTERGY CORPORATION AND SUBSIDIARIES - Market and Credit Risk Sensitive Instruments.”

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. Financial Statements and Supplementary Data
Refer to “TABLE OF CONTENTS - Entergy Corporation and Subsidiaries, Entergy Arkansas, LLC and Subsidiaries, Entergy Louisiana, LLC and Subsidiaries, Entergy Mississippi, LLC and Subsidiaries, Entergy New Orleans, LLC and Subsidiaries, Entergy Texas, Inc. and Subsidiaries, and System Energy Resources, Inc.”

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
No event that would be described in response to this item has occurred with respect to Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, or System Energy.

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ITEM 9A. CONTROLS AND PROCEDURES
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
As of December 31, 2024, evaluations were performed under the supervision and with the participation of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy (each individually a “Registrant” and collectively the “Registrants”) management, including their respective Principal Executive Officers (PEO) and Principal Financial Officers (PFO). The evaluations assessed the effectiveness of the Registrants’ disclosure controls and procedures. Based on the evaluations, each PEO and PFO has concluded that, as to the Registrant or Registrants for which they serve as PEO or PFO, the Registrant’s or Registrants’ disclosure controls and procedures are effective to ensure that information required to be disclosed by each Registrant in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in Securities and Exchange Commission rules and forms; and that the Registrant’s or Registrants’ disclosure controls and procedures are also effective in reasonably assuring that such information is accumulated and communicated to the Registrant’s or Registrants’ management, including their respective PEOs and PFOs, as appropriate to allow timely decisions regarding required disclosure.
Internal Control over Financial Reporting (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
The managements of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy (each individually a “Registrant” and collectively the “Registrants”) are responsible for establishing and maintaining adequate internal control over financial reporting for the Registrants. Each Registrant’s internal control system is designed to provide reasonable assurance regarding the preparation and fair presentation of each Registrant’s financial statements presented in accordance with generally accepted accounting principles.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Each Registrant’s management assessed the effectiveness of each Registrant’s internal control over financial reporting as of December 31, 2024. In making this assessment, each Registrant’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. The 2013 COSO Framework was utilized for management’s assessment.
Based on each management’s assessment and the criteria set forth by the 2013 COSO Framework, each Registrant’s management believes that each Registrant maintained effective internal control over financial reporting as of December 31, 2024.
The report of Deloitte & Touche LLP, Entergy Corporation’s independent registered public accounting firm, regarding Entergy Corporation’s internal control over financial reporting is included herein. The report of Deloitte & Touche LLP is not applicable to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy because these Registrants are non-accelerated filers.
Changes in Internal Control over Financial Reporting
Under the supervision and with the participation of each Registrant’s management, including its respective PEO and PFO, each Registrant evaluated changes in internal control over financial reporting that occurred during the quarter ended December 31, 2024 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.
Attestation Report of Registered Public Accounting Firm
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and Board of Directors of
Entergy Corporation and Subsidiaries
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Entergy Corporation and Subsidiaries (the “Corporation”) as of December 31, 2024, based on criteria established in Internal Control -Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2024 of the Corporation and our report dated February 18, 2025 expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Item 9A, Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Corporation’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Corporation 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 audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 18, 2025

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ITEM 9B. OTHER INFORMATION
Item 9B. Other Information
U.S. Securities and Exchange Commission Investigation
The Staff of the Division of Enforcement of the U.S. Securities and Exchange Commission conducted an investigation regarding Entergy’s processes and controls relating to its accounting for materials and supplies inventory. In December 2024, Entergy reached a settlement with the SEC to resolve the previously disclosed SEC investigation into Entergy’s internal controls and books and records concerning potential surplus materials and supplies inventory. Under the settlement terms, in which Entergy neither admitted nor denied the SEC’s allegations, Entergy consented to the entry of an injunction, paid a $12 million civil penalty, which was accrued in 2024 and paid in January 2025, and agreed to engage a consultant to conduct an assessment and make recommendations concerning Entergy’s internal controls related to the accounting for surplus materials and supplies.
Rule 10b5-1 Trading Arrangements
During the three months ended December 31, 2024, the following directors or officers of Entergy or the Registrant Subsidiaries adopted, modified, or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408 of Regulation S-K, relating to shares of Entergy Corporation common stock:
Name and Title Action Date of Action Type of Trading Arrangement
(a) Aggregate Number of Shares to be Purchased or Sold Expiration Date
(b)
Philip R. May, Jr., Chairman of the Board, President, and Chief Executive Officer of Entergy Louisiana, LLC
Adopted 11/19/2024 Rule 10b5-1 trading arrangement Up to 35,184 shares to be sold (c)
12/15/2025
(a)Each trading arrangement marked as a Rule 10b5-1 trading arrangement is intended to satisfy the affirmative defense of Rule 10b5-1(c).
(b)Except as indicated by footnote, each trading arrangement permitted or permits transactions through and including the earlier to occur of (a) the completion of all purchases or sales or (b) the expiration date listed in the table. Each trading arrangement marked as a “Rule 10b5-1 Plan” only permitted or only permits transactions upon expiration of the applicable mandatory cooling-off period under Rule 10b5-1(c), as amended.
(c)This trading arrangement provides for the sale of up to 23,184 shares upon the exercise of outstanding options and for the sale of up to 12,000 shares of Entergy Corporation common stock owned outright. Mr. May’s trading arrangement was adopted prior to the two-for-one forward stock split of Entergy Corporation common stock effective December 12, 2024. The number of shares and limit prices established in Mr. May’s trading arrangement were adjusted accordingly as a result of the stock split and the number of shares reported in the table above reflects the stock split adjustment. See Note 7 to the financial statements for discussion of the stock split.
Other than those disclosed above, no director or officer of Entergy or any of the Registrant Subsidiaries adopted, modified, or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement” during the three months ended December 31, 2024.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10. Directors, Executive Officers, and Corporate Governance of the Registrants (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
Information required by this item concerning directors of Entergy Corporation is set forth under the heading “Proposal 1 - Election of Directors” contained in the Proxy Statement of Entergy Corporation, to be filed in connection with its Annual Meeting of Stockholders to be held May 2, 2025 (the “2025 Entergy Proxy Statement”), and is incorporated herein by reference.
All officers and directors listed below held the specified positions with their respective companies as of the date of filing this report, unless otherwise noted.
Name Age Position Period
Entergy Arkansas, LLC
Directors
Laura R. Landreaux 51 President and Chief Executive Officer of Entergy Arkansas 2018-Present
Director of Entergy Arkansas 2018-Present
Kimberly A. Fontan See information under the Information about Executive Officers of Entergy Corporation in Part I.
Peter S. Norgeot, Jr. See information under the Information about Executive Officers of Entergy Corporation in Part I.
Officers
Marcus V. Brown See information under the Information about Executive Officers of Entergy Corporation in Part I.
Kimberly Cook-Nelson See information under the Information about Executive Officers of Entergy Corporation in Part I.
Kimberly A. Fontan
See information under the Information about Executive Officers of Entergy Corporation in Part I.
Reginald T. Jackson See information under the Information about Executive Officers of Entergy Corporation in Part I.
Laura R. Landreaux
See information under the Entergy Arkansas Directors Section above.
Andrew S. Marsh
See information under the Information about Executive Officers of Entergy Corporation in Part I.
ENTERGY LOUISIANA, LLC
Directors
Phillip R. May, Jr. 62 President and Chief Executive Officer of Entergy Louisiana 2013-Present
Director of Entergy Louisiana 2013-Present
Kimberly A. Fontan See information under the Information about Executive Officers of Entergy Corporation in Part I.
Peter S. Norgeot, Jr. See information under the Information about Executive Officers of Entergy Corporation in Part I.
Officers
Marcus V. Brown See information under the Information about Executive Officers of Entergy Corporation in Part I.
Kimberly Cook-Nelson See information under the Information about Executive Officers of Entergy Corporation in Part I.
Kimberly A. Fontan See information under the Information about Executive Officers of Entergy Corporation in Part I.
Reginald T. Jackson See information under the Information about Executive Officers of Entergy Corporation in Part I.
Andrew S. Marsh See information under the Information about Executive Officers of Entergy Corporation in Part I.
Phillip R. May, Jr. See information under the Entergy Louisiana Directors Section above.
ENTERGY MISSISSIPPI, LLC
Directors
Haley R. Fisackerly 59 President and Chief Executive Officer of Entergy Mississippi 2008-Present
Director of Entergy Mississippi 2008-Present
Kimberly A. Fontan See information under the Information about Executive Officers of Entergy Corporation in Part I.
Peter S. Norgeot, Jr. See information under the Information about Executive Officers of Entergy Corporation in Part I.
Officers
Marcus V. Brown See information under the Information about Executive Officers of Entergy Corporation in Part I.
Haley R. Fisackerly See information under the Entergy Mississippi Directors Section above.
Kimberly A. Fontan See information under the Information about Executive Officers of Entergy Corporation in Part I.
Reginald T. Jackson See information under the Information about Executive Officers of Entergy Corporation in Part I.
Andrew S. Marsh See information under the Information about Executive Officers of Entergy Corporation in Part I.
ENTERGY NEW ORLEANS, LLC
Directors
Deanna D. Rodriguez 60 President and Chief Executive Officer of Entergy New Orleans 2021-Present
Director of Entergy New Orleans 2021-Present
Vice President, Regulatory and Public Affairs of Entergy Texas 2014-2021
Kimberly A. Fontan See information under the Information about Executive Officers of Entergy Corporation in Part I.
Peter S. Norgeot, Jr. See information under the Information about Executive Officers of Entergy Corporation in Part I.
Officers
Marcus V. Brown See information under the Information about Executive Officers of Entergy Corporation in Part I.
Kimberly A. Fontan See information under the Information about Executive Officers of Entergy Corporation in Part I.
Reginald T. Jackson See information under the Information about Executive Officers of Entergy Corporation in Part I.
Andrew S. Marsh See information under the Information about Executive Officers of Entergy Corporation in Part I.
Deanna D. Rodriguez See information under the Entergy New Orleans Directors Section above.
ENTERGY TEXAS, INC.
Directors
Eliecer Viamontes 42 President and Chief Executive Officer of Entergy Texas 2021-Present
Director of Entergy Texas 2021-Present
Vice President, Utility Distribution Operations of Entergy Services 2020-2021
Senior Director of Labor Relations and Corporate Safety, Florida Power and Light Corporation 2018-2020
Kimberly A. Fontan See information under the Information about Executive Officers of Entergy Corporation in Part I.
Peter S. Norgeot, Jr. See information under the Information about Executive Officers of Entergy Corporation in Part I.
Officers
Marcus V. Brown See information under the Information about Executive Officers of Entergy Corporation in Part I.
Kimberly A. Fontan See information under the Information about Executive Officers of Entergy Corporation in Part I.
Reginald T. Jackson See information under the Information about Executive Officers of Entergy Corporation in Part I.
Andrew S. Marsh See information under the Information about Executive Officers of Entergy Corporation in Part I.
Eliecer Viamontes See information under the Entergy Texas Directors Section above.
The directors and officers of Entergy Texas are elected annually to serve by the unanimous consent of its sole common stockholder. The directors and officers of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi,
and Entergy New Orleans are elected annually to serve by the unanimous consent of the sole common membership owner, Entergy Utility Holding Company, LLC. Entergy Corporation’s directors are elected annually at the annual meeting of shareholders. Entergy Corporation’s officers are elected annually at a meeting of its Board of Directors, which immediately follows the annual meeting of shareholders. The age of each officer and director for whom information is presented above is as of December 31, 2024.
Directors, Director Nomination Process and Audit Committee
The information required under Item 10 concerning directors and nominees for election as directors of Entergy Corporation at the annual meeting of shareholders (Item 401 of Regulation S-K), the director nomination process (Item 407(c)(3) of Regulation S-K), the audit committee (Item 407(d)(4) and (d)(5) of Regulation S-K), and the compliance with the reporting requirements of Section 16 (“Section 16”) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) (Item 405 of Regulation S-K) is incorporated herein by reference to information to be contained in the 2025 Entergy Proxy Statement to be filed with the SEC pursuant to Regulation 14A under the Exchange Act.
Code of Ethics
Entergy Corporation’s Code of Business Conduct and Ethics (Code of Business Conduct) is the code of ethics that applies to Entergy’s Chief Executive Officer and other senior financial officers, including those of the Registrant Subsidiaries. The Code of Business Conduct is filed as Exhibit 14 to this report and is available on Entergy Corporation’s website at www.entergy.com. The Code of Business Conduct will be made available, without charge, in print to any shareholder who requests such document from Entergy Corporation’s Corporate Secretary at Entergy Corporation, 639 Loyola Avenue, New Orleans, Louisiana 70113.
If any substantive amendments to the Code of Business Conduct are made or any waivers are granted, including any implicit waiver, from a provision of the Code of Business Conduct, for any director or executive officer of Entergy Corporation, Entergy will disclose the nature of such amendment or waiver on Entergy’s website, www.entergy.com. Entergy is providing the address to its internet site 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.
Insider Trading Policies and Procedures
Entergy Corporation and each of the Registrant Subsidiaries has adopted an insider trading policy which is reasonably designed to promote compliance with applicable insider trading laws, rules and regulations and which governs the purchase, sale, and/or other dispositions of Entergy Corporation’s and the Registrant Subsidiaries’ securities, by any directors, officers and employees of Entergy Corporation and its subsidiaries, including the Registrant Subsidiaries, and by Entergy Corporation and the Registrant Subsidiaries themselves as well as the applicable rules and regulations of the New York Stock Exchange. A copy of the insider trading policy that has been adopted by Entergy Corporation and each of the Registrant Subsidiaries is filed as Exhibit 19 to this report.

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ITEM 11. EXECUTIVE COMPENSATION
Item 11. Executive Compensation
ENTERGY CORPORATION
Information concerning compensation earned by the directors and officers of Entergy Corporation is set forth in the 2025 Entergy Proxy Statement, to be filed in connection with the Annual Meeting of Shareholders to be held May 2, 2025, under the headings “Compensation Discussion and Analysis,” “Annual Compensation Programs Risk Assessment,” “Compensation Tables,” “Pay Ratio Disclosure,” and “2024 Non-Employee Director Compensation,” all of which information is incorporated herein by reference. In this section, Entergy Corporation is also referred to as “Entergy” or the “Company.”
ENTERGY ARKANSAS, ENTERGY LOUISIANA, ENTERGY MISSISSIPPI, ENTERGY NEW ORLEANS, AND ENTERGY TEXAS
COMPENSATION DISCUSSION AND ANALYSIS
This Compensation Discussion and Analysis (“CD&A”) describes the executive compensation policies, programs, philosophy, and decisions regarding the Named Executive Officers (“NEOs”) for 2024. It also explains how and why the Talent and Compensation Committee of Entergy Corporation’s Board of Directors arrived at the compensation decisions involving the NEOs in 2024 who were:
Name(1)
Title
Marcus V. Brown Executive Vice President and General Counsel
Haley R. Fisackerly President and Chief Executive Officer, Entergy Mississippi
Kimberly A. Fontan Executive Vice President and Chief Financial Officer, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas
Laura R. Landreaux President and Chief Executive Officer, Entergy Arkansas
Andrew S. Marsh Chair of the Board and Chief Executive Officer
Phillip R. May, Jr. President and Chief Executive Officer, Entergy Louisiana
Peter S. Norgeot, Jr.
Executive Vice President and Chief Operating Officer, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas
Deanna D. Rodriguez President and Chief Executive Officer, Entergy New Orleans
Eliecer Viamontes President and Chief Executive Officer, Entergy Texas
Roderick K. West Former Group President, Utility Operations, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas
(1)Messrs. Brown, Marsh, and Norgeot and Ms. Fontan hold the positions referenced above as executive officers of Entergy Corporation. Mr. West held the position referenced above as an executive officer of Entergy Corporation until November 1, 2024 when he transitioned to a senior strategic advisory role effective November 1, 2024 in connection with his retirement from the Company on January 31, 2025. No additional compensation was paid in 2024 to any of these officers for their service as NEOs of the Utility operating companies.
On December 12, 2024, Entergy effected a two-for-one forward stock split of Entergy Corporation common stock and a proportionate increase in the number of authorized shares of its common stock (“Stock Split”). Shares began trading on a Stock Split-adjusted basis at market open on December 13, 2024. All share and per share information throughout this CD&A has been retroactively adjusted to reflect the Stock Split.
All of Entergy Arkansas’s, Entergy Louisiana’s, Entergy Mississippi’s, Entergy New Orleans’s, and Entergy Texas’s directors are employees of Entergy or its subsidiaries and do not receive any additional compensation for their services as director.
Entergy Corporation’s Compensation Principles and Philosophy
Entergy Corporation’s executive compensation programs are based on a philosophy of pay for performance aimed at achieving the Company’s strategy and business objectives. Entergy Corporation believes its executive compensation programs advance the interests of all of its stakeholders, as they are thoughtfully designed to:
•Motivate and reward the achievement of results that are deemed by the Talent and Compensation Committee to be consistent with the overall goals and strategic direction that the Board has approved for the Company.
•Attract and retain a highly experienced, diverse, and successful management team.
•Create sustainable value for the benefit of all of Entergy Corporation’s stakeholders, including its customers, employees, communities, and owners.
•Align the interests of Entergy Corporation’s executives with the Company’s long-term business strategy by tying equity-based awards to performance metrics designed to focus Entergy Corporation’s executives on driving continuous improvement in operational and financial results to the benefit of all stakeholders, including Entergy Corporation’s customers, employees, communities, and owners.
Compensation Best Practices
The Talent and Compensation Committee reviews Entergy’s executive compensation programs on an ongoing basis to evaluate whether they support the Company’s executive compensation principles and philosophy and are aligned with the interests of our stakeholders. The Company’s executive compensation practices include the following, each of which the Talent and Compensation Committee believes reinforces our executive compensation principles and philosophy:
Practice Description
Pay for Performance The executive compensation programs are designed to yield pay outcomes that the Company believes are highly correlated with performance and support long-term value creation.
Annual and Long-Term Incentive Measures Drive Desired Employee Behaviors
Performance measures for the annual and long-term incentive programs are designed to incentivize employee behaviors that serve the Company’s key stakeholders.
Double Trigger Change-in-Control The Company requires both a change-in-control and an involuntary termination without cause or voluntary termination with good reason for cash severance payments and immediate vesting of unvested equity awards.
Long-Term Incentives Paid in Stock All long-term incentive awards are settled in shares of Entergy common stock.
Stock Ownership Guidelines The Company requires executive officers to own a significant amount of Entergy Corporation common stock.
Cap on Incentive Awards for OCE Members
The maximum payout for members of the Office of the Chief Executive (“OCE”), which members include all of the NEOs, is capped at 200% of the target opportunity for the annual incentive and long-term Performance Unit Program (“PUP”) awards.
Rigorous Goals The Company sets financial goals based on externally disclosed annual and multi-year guidance and outlooks and non-financial goals based on a rigorous internal review.
Practice Description
Clawback Policies Beyond Dodd-Frank Requirements
Entergy’s officers (as defined under Section 16), including the NEOs, are subject to a recoupment policy that complies with and, in certain respects, goes beyond, the requirements of the SEC rules and NYSE Listing Standards for the recovery of any erroneously awarded performance-based incentive compensation. Additionally, all executive officers of Entergy and its subsidiaries, including the NEOs, are subject to a discretionary recoupment policy that allows for recovery of incentive compensation, including time-based awards, from an officer who engages in certain detrimental conduct. See section of this CD&A discussing “Recoupment of Compensation (Clawback Provisions)” for additional information about these policies.
No Hedging of Company Stock Directors, executive officers, and employees of Entergy and its subsidiaries may not directly or indirectly engage in transactions intended to hedge or offset the market value of the Company’s common stock owned by them.
No Pledging of Company Stock Directors and executive officers of Entergy and its subsidiaries may not directly or indirectly pledge Entergy common stock as collateral for any obligation.
No Excessive Perquisites Executive officers receive limited ongoing perquisites that make up a small portion of total compensation.
No Tax Gross-Ups
The Company does not provide tax gross-ups to the members of the OCE other than certain relocation benefits.
No Dividends on Unearned Performance Awards
The Company does not pay dividends on unearned PUP awards.
No Repricing or Exchange of Underwater Stock Options The Company’s equity incentive plan does not permit repricing or the exchange of underwater stock options without the approval of its shareholders.
No Employment Agreements The Company does not have employment contracts with its executive officers.
Independent Compensation Consultant
The Talent and Compensation Committee retains an independent compensation consultant to advise on the executive compensation programs and practices.
Annual Say-on-Pay The Company values the input of its shareholders on the executive compensation programs and holds annual say-on-pay votes.
Annual Compensation Risk Assessment A risk assessment of the compensation programs is performed on an annual basis to ensure that the programs and policies do not incentivize unnecessary or excessive risk-taking behavior.
2024 Incentive Program Changes
Based in part on shareholder feedback and consistent with our compensation principles and philosophy discussed earlier in this CD&A, the Talent and Compensation Committee refined Entergy's 2024 incentive compensation programs by:
•Moving the Adjusted FFO/Debt Ratio measure from the PUP to the annual incentive program, weighted at 10%, and moving the Environmental Stewardship measure from the annual incentive program to the PUP, beginning with the 2024-2026 performance period (“2024-2026 PUP”), weighted at 20%. The Environmental Stewardship measure introduced into the 2024-2026 PUP is based purely on quantitative components related to climate resilience and carbon-free generation, subject to a modifier for progress on carbon capture and storage (“CCS”) objectives;
•Removing the tax adjustment from the calculation of the ETR Adjusted EPS results in the annual incentive program;
•Adjusting the design of the Safety measure in the annual incentive program to incorporate Total Recordable Incident Rate (“TRIR”) as a component equally weighted with the existing Serious Injury and Fatality (“SIF”) component; and
•Adjusting the design of the Customer net promoter score (“NPS”) measure in the annual incentive program to incorporate large commercial and industrial (“C&I”) customer feedback, equally weighted with the residential and business customer feedback components.
As a result of the above refinements, the frameworks for our 2024 incentive compensation programs comprised the following measures:
Annual Incentive Program
2024-2026 PUP
Measure Weighting Measure
Weighting
ETR Adjusted EPS
60% Relative Total Shareholder Return (“TSR”)
80%
Adjusted FFO/Debt Ratio
10% Environmental Stewardship
Climate Resilience
Carbon-Free Generation*
20%
Safety
SIF Count
TRIR
10%
Customer NPS
Residential
Business
Large C&I
10% * subject to carbon capture modifier
Diversity, Inclusion, & Belonging (“DIB”)
10%
Under the 2024 incentive compensation program frameworks described above, the performance assessments for 90% of the overall annual incentive program funding and for 100% of the 2024-2026 PUP funding are purely quantitative.
What Entergy Corporation Pays and Why
How Entergy Corporation Makes Compensation Decisions
Role of the Talent and Compensation Committee
The Talent and Compensation Committee, which is composed solely of independent directors, determines the compensation for each member of the OCE and oversees the design and administration of Entergy’s executive compensation programs. Each year, the Talent and Compensation Committee reviews and considers a comprehensive assessment and analysis of the executive compensation programs, including the elements of each OCE member’s compensation, with input from the committee’s independent compensation consultant. When establishing the compensation programs for the NEOs, the Talent and Compensation Committee also considers input and recommendations from management, including Entergy’s Chief Executive Officer and Entergy’s Chief Human Resources Officer, who attend the Talent and Compensation Committee meetings as appropriate. The Talent and Compensation Committee regularly conducts executive sessions without management present.
Role of the Independent Compensation Consultant
In 2024, the Talent and Compensation Committee continued to retain Pay Governance, LLC (“Pay Governance”) as its independent compensation consultant. Pay Governance attends all Talent and Compensation Committee meetings and provides advice, including reviewing and commenting on market compensation data used to establish the compensation of the executive officers and Entergy Corporation’s directors, the terms and performance goals applicable to incentive program awards, the process for certifying achievement of the incentive goals, and analysis with respect to specific projects and information regarding trends and competitive practices. Pay Governance also meets with the Talent and Compensation Committee members without management present. The
committee annually conducts an independence assessment of its advisors including the compensation consultant, consistent with applicable NYSE listing standards and SEC rules.
Competitive Positioning
Market Data for Compensation Comparison
Annually, the Talent and Compensation Committee reviews:
•published and private compensation survey data analyzed and provided by Pay Governance;
•both utility and general industry data to help determine total direct compensation (base salary, annual, and long-term incentive) for non-industry specific roles; and
•data from utility companies to help determine total direct compensation for management roles that are utility-specific.
The Talent and Compensation Committee uses this survey data to develop compensation opportunities that are designed to deliver total direct compensation within a targeted range of approximately the 50th percentile of the surveyed companies in the aggregate. In general, compensation levels for an executive officer who is new to a position tend to be closer to the 25th percentile of surveyed companies, while seasoned executive officers whose experience and skill set are viewed as critical to retain may be positioned at or above the market median.
Compensation Peer Group
Although the survey data described above is the primary data used in benchmarking compensation, the Talent and Compensation Committee used compensation information from the companies included in the Philadelphia Utility Index to evaluate the overall reasonableness of the Company’s executive compensation programs and to determine Relative TSR performance levels for the 2022-2024 PUP. The Talent and Compensation Committee identified the Philadelphia Utility Index as the appropriate industry peer group for determining Relative TSR performance levels because the companies included in this index, in the aggregate, are viewed as comparable to the Company in terms of business and scale.
The Talent and Compensation Committee approved the 2024 compensation model and framework based on compensation information from the companies included in the Philadelphia Utility Index as of December 31, 2023, which were (in addition to Entergy):
AES Corporation Consolidated Edison Inc. Edison International Pinnacle West Capital Corporation
Ameren Corporation Constellation Energy Corporation Eversource Energy Public Service Enterprise Group, Inc.
American Electric Power Co. Inc. Dominion Energy Exelon Corporation Southern Company
American Water Works Company, Inc. DTE Energy Company FirstEnergy Corporation WEC Energy, Inc.
CenterPoint Energy Inc. Duke Energy Corporation NextEra Energy, Inc. Xcel Energy, Inc.
2024 Compensation Structure and Incentive Metrics
In 2024, the executive compensation programs consisted of base salary and annual and long-term incentives as outlined in the table below:
Compensation Element Form Objective Metrics/Performance Period
Base Salary Cash Provides a base level of competitive cash compensation for executive talent. Adjustments consider individual performance
Annual Incentive Program Awards Cash Motivates and rewards executives for performance on both key financial and non-financial measures during the year; incentivizes behaviors that serve the Company’s four stakeholders - customers, employees, communities, and owners.
•ETR Adjusted EPS
•Adjusted FFO/Debt Ratio
•Safety
•Customer NPS
•DIB
Measured over a one-year performance period
2024-2026
PUP Awards
Equity Provides market competitive compensation designed to retain skills and knowledge while increasing our executives’ ownership in the Company to further enhance their focus on driving continuous improvement in operational results to the benefit of all stakeholders. Designed to focus our executives on driving utility growth, building long-term shareholder value, making progress toward quantitative environmental goals aligning with desired customer outcomes for clean energy, reliable operations, and reduced storm restoration costs and delivering positive outcomes from capital investments relating to both the energy transition and environmental risks.
•Relative TSR
•Environmental Stewardship
Measured over a three-year performance period
Stock Options Equity Enhances management’s focus on driving continuous improvement in operational results to the benefit of all stakeholders. Designed to align interests of management with long-term shareholder value as demonstrated by increases in our share price, provide market competitive compensation, retain talent, and increase management’s ownership in the Company. Share price appreciation with three-year pro rata vesting
Restricted Stock Equity Enhances management’s focus on driving continuous improvement in operational results to the benefit of all stakeholders. Designed to provide market competitive compensation, retain talent, and increase management’s ownership in the Company. Service-based with three-year pro rata vesting
2024 Compensation Decisions
Base Salary
The salary for each NEO is based on the outcome of an annual merit review, results of the annual market assessment of NEO compensation as provided by Pay Governance, the need to retain an experienced team, job promotion, individual performance, scope of responsibility, leadership skills, and behaviors, current compensation, and internal equity. The Talent and Compensation Committee considers changes in the base salaries of the NEOs at least annually, and in 2024, all of the NEOs received increases in their base salaries ranging from approximately 3.5% to 13.6%, which were effective April 1, 2024, and were based on the factors above. In the case of Messrs. Marsh and Norgeot and Ms. Fontan, their increases were made to transition below-market base salary levels toward the market median in recognition of their performance since assuming their respective roles in 2022.
The following table sets forth the 2023 and 2024 annual base salaries, after adjusting for the annual merit increases, for the NEOs.
Named Executive Officer 2023 Base Salary 2024 Base Salary
Marcus V. Brown $761,302 $791,754
Haley R. Fisackerly $438,206 $458,019
Kimberly A. Fontan $625,000 $706,250
Laura R. Landreaux $411,351 $430,983
Andrew S. Marsh $1,100,000 $1,250,000
Phillip R. May, Jr. $454,593 $472,863
Peter S. Norgeot, Jr.
$598,000 $669,760
Deanna D. Rodriguez $362,274 $375,924
Eliecer Viamontes(1)
$365,385 $380,070
Roderick K. West $807,491 $835,753
(1) Following the annual merit increases, Mr. Viamontes received an off-cycle salary increase of approximately 10%, which brought his base salary to $418,077, effective September 29, 2024. This off-cycle adjustment to Mr. Viamontes’ salary was made to transition his below-market base salary level toward the market median.
Annual Incentive Compensation
The NEOs are eligible for annual incentive awards pursuant to the executive annual incentive program established under our 2019 Omnibus Incentive Plan (“2019 OIP”). The maximum funding available for the program is determined by a payout factor referred to as the Entergy Achievement Multiplier (“EAM”). Each year, after a review of the Company’s strategic plan, the Talent and Compensation Committee engages in a rigorous process to determine the performance measures and the minimum, target, and maximum performance goals for each measure that will be used to determine the EAM. The Talent and Compensation Committee also annually establishes target opportunities for each NEO who is a member of the OCE. For other NEOs, target opportunities are based on their management level within the Entergy organization. Executive management levels at Entergy Corporation range from management level 1 through management level 4. Accordingly, incentive award opportunities differ from one another based on either management level or the external market data developed by Pay Governance. The target opportunities for Mr. Marsh and Ms. Fontan were increased as compared to 2023 from 120% to 130% and from 75% to 85%, respectively, to align more closely with the market median due to their increased tenure in their roles and performance in their roles since their promotions to those roles in 2022. Effective November 1, 2024, Messrs. Fisackerly, May, and Viamontes and Mses. Landreaux and Rodriguez became members of the OCE. The 2024 target award opportunities for each of Messrs. Fisackerly, May, and Viamontes and Mses. Landreaux and Rodriguez were determined prior to the date they became members of the OCE and therefore, were based on their respective management level. The 2024 target award opportunities for each of the remaining NEOs,
including Messrs. Fisackerly, May, and Viamontes and Mses. Landreaux and Rodriguez, remained at the same level as those established for 2023.
Each January, after the end of the fiscal year, the Finance and Talent and Compensation Committees jointly review the Company’s results, and the Talent and Compensation Committee determines the EAM based on the level of achievement of each of the performance measure goals established. The Talent and Compensation Committee retains discretion to modify the EAM based on its assessment of the degree of management’s success in achieving the Company’s strategic objectives during the year, taking into account the business and operating environment.
Individual executive officer annual incentive awards are determined based on the Talent and Compensation Committee’s consideration of each executive officer’s role in executing the Company’s strategies and delivering the financial and operational performance achieved, but also the individual’s accountability for any challenges and achievements the Company experienced during the year.
2024 Annual Incentive Program Performance Measures and Methodology
The measures that the Talent and Compensation Committee approved to determine the EAM for 2024 were: ETR Adjusted EPS, Adjusted FFO/Debt Ratio, Safety, Customer NPS, and DIB, with ETR Adjusted EPS being the most heavily weighted at 60% and the remaining measures each weighted at 10%.
Minimum, target, and maximum performance goals were established for each of the measures, with no payout for results less than the designated minimum, a 25% payout opportunity for results at the minimum, a 100% payout opportunity for results at target, and a 200% payout opportunity for results equal to or exceeding the maximum. Payout opportunities for results between the minimum and target, and target and maximum performance achievement levels, respectively, were determined by straight line interpolation, with the EAM result being determined formulaically by the weighted average of the payouts determined for each of the performance measures.
Quantitative Performance Measures
All the performance measures used to determine the EAM except the DIB performance measure are purely quantitative measures. Following are summary descriptions of each of the quantitative performance measures, including the rationale for their selection and targets set for 2024:
Measure
Rationale
Goal
ETR Adjusted EPS
Non-GAAP measure, which is the earnings measure by which we provide external guidance, adjusted to eliminate the effect of: (i) major storms, including the impact on total debt of pending securitizations; (ii) resolutions during the year of certain unresolved regulatory litigation matters; (iii) unrealized gains or losses on equity securities; (iv) income tax law changes; and (v) any adjustments to contributions to pension investments or trusts related to post-retirement benefits that are elective and deviate from original plan assumptions (collectively, the “Pre-Determined Exclusions”)
•Based on an objective financial measure that we and our investors consider to be important in evaluating our financial performance
•Based on the same measure we use for internal and external financial reporting
•Provides both discipline and transparency
•Target performance was set to equal management’s expectation for the Company’s Adjusted EPS as reflected in its financial plan, or $3.60 per share ($7.20 per share pre-Stock Split)
•Minimum performance: $3.51 per share ($7.02 per share pre-Stock Split)
•Maximum performance: $3.69 per share ($7.38 per share pre-Stock Split)
Measure
Rationale
Goal
Adjusted FFO/Debt Ratio
Non-GAAP measure, which is the ratio of: (i) adjusted funds from operations calculated as consolidated operating cash flow adjusted for allowance for funds used during construction, working capital and the effects of securitization revenue and expense, and the Pre-Determined Exclusions (as defined earlier and also discussed later in this CD&A) to (ii) total consolidated debt, excluding current and pending securitization debt, in each case calculated to reflect rating agency treatment of interest and principal on the Company’s junior subordinated debentures
•Helps emphasize the importance of managing capital and operations and maintenance (O&M) spending, which directly impacts this metric
•Key measure evaluated by credit rating agencies
•Management of cash flows enables the Company to strengthen its balance sheet, which reduces borrowing costs and supports affordability for customers
•Target performance was set to equal to the prior year results, or 14.4%, which was believed to be a reasonable stretch goal because it exceeded the projected Adjusted FFO/Debt Ratio forecast as reflected in the Company's financial plan
•Minimum performance: 14.0%
•Maximum performance: 14.9%
Safety
Quantitative measure based 50% on the Company's SIF count as defined by the Edison Electric Institute (EEI) and 50% on the Company's TRIR, with results of both sub-metrics being equally weighted
•SIF count is the number of Entergy employee and contractor serious injuries and fatalities over a one-year period, with employee and contractor targets and results are combined to arrive at reported results and one fatality automatically setting the sub-metric result to zero
•TRIR is based on Occupational Safety and Health Administration (OSHA) reporting guidelines and measures the number of work-related injuries and illnesses per 100 full-time employees over a one-year period
•Supports our goal of maintaining a safe and incident-free workplace for all of our employees and contractors
•TRIR was incorporated as a sub-metric in 2024 because:
◦It is a target that can be impacted by everyone since not all employees are exposed to high energies that lead to SIF events
◦Improvements in TRIR are associated with improvements in enterprise safety culture, which should contribute to a reduction in SIF events
SIF count
•Target performance was set at a level representing top quartile performance among electric utilities for 2024, as reported by the EEI, or 5
•Minimum performance: 7
•Maximum performance: 3
•No payout if any fatalities
TRIR
•Target performance was set at 0.45, which represented significant improvement from 2023's result of 0.49
•Minimum performance: 0.55
•Maximum performance: 0.40
Measure
Rationale
Goal
Customer NPS
Quantitative measure based on a benchmark blind survey process for residential and business customers and a custom survey for large C&I customers, with the final result determined based on a composite of relative quartile ranking for residential and business customers and a numerical score for large C&I customers, equally weighted
•The blind survey of residential and business customers asks how likely they are to recommend Entergy, on a scale of 0 to 10
•The NPS is the percentage of promoters (scores 9-10) less the percentage of detractors (scores of 6 or less)
•A custom survey is used to determine large C&I NPS because a satisfactory benchmark survey is not available
•Incentivizes actions that drive positive customer outcomes (as measured through customer feedback), including impacts on reliability improvements, responsiveness, price/ affordability and brand/ reputation
•Signals overall health and loyalty of our customer relationship
Residential and Business NPS
•Target performance goals were set at levels believed to represent reasonably achievable incremental progress on the path to 1st Quartile Customer NPS
•Targets were set based on the year-end ranking in a benchmark survey of utility net promoter scores, for which the Company ranked in the 3rd Quartile in each sub-metric for 2023
◦Maximum performance was set at a rank equating to 2nd Quartile, and minimum performance was set at the median rank between the 2023 performance and the 2024 target performance, thereby requiring meaningful progress to achieve a minimum payout and achievement of 2nd Quartile results for the maximum payout
Residential
▪Target performance: 49
▪Minimum performance: 52
▪Maximum performance: 47
Business
▪Target performance: 37
▪Minimum performance: 39
▪Maximum performance: 32
Large C&I NPS
•Target performance was set at a two point improvement from the 2023 score, the minimum performance was set at the 2023 score, and the maximum performance was set at an improvement of four points to the 2023 score
◦Target performance: 45
◦Minimum performance: 43
◦Maximum performance: 47
Qualitative Performance Measure: Diversity, Inclusion and Belonging
The DIB measure is an overall qualitative assessment of diversity, culture and commerce outcomes using key DIB performance indicators, such as inclusive climate survey scores, diverse supplier managed spend, progress on DIB initiatives, and responsiveness to emergent issues.
The DIB measure was used in the annual incentive program because:
•It reinforces our commitment to offer a work environment that is welcoming to all and allows us to attract and retain superb talent allowing us to execute on strategy.
•It rewards progress toward developing and retaining a workforce with a variety of backgrounds, experiences and perspectives that reflects the rich diversity of the communities we serve, while maintaining our commitment to hiring the most qualified candidates.
•It drives an engaged workforce, customer-centric service and solutions, enhancement of owner value, and community partnerships.
2024 Annual Incentive Program Target Performance Goal Considerations
In determining the targets for 2024, the Talent and Compensation Committee reviewed anticipated drivers and risks to the Company’s expectations for ETR Adjusted EPS and Adjusted FFO/Debt Ratio for 2024 as set forth in the Company’s financial plan, as well as factors driving the strong financial performance achieved in 2023. The Talent and Compensation Committee noted that the proposed targets for ETR Adjusted EPS reflected year-to-year growth in the core earnings measure underlying the annual incentive program target consistent with Entergy’s stated objective at the beginning of the year of steady, predictable growth in ETR Adjusted EPS at a compound annual rate of 6%-8%. The Talent and Compensation Committee also considered the potential impact of a wide range of identified risks and opportunities and confirmed that the annual incentive program targets for each of the performance measures reflected a reasonable balancing of such risks and opportunities and an appropriate degree of challenge. The goals were designed to be achievable, but also to require the strong coordinated performance of the management team.
2024 Annual Incentive Program Performance Assessment
In January 2025, the Finance and Talent and Compensation Committees jointly reviewed the Company’s financial and operational results and assessed management’s performance against the performance measures and goals described above in order to determine the EAM. The following table summarizes the annual incentive program performance goals and results for 2024:
Performance Measure Performance Goals and Results
Weighting Minimum Target Maximum 2024 Results
Level of Achievement
ETR Adjusted EPS ($)(1)
60% 3.51 3.60 3.69 3.65 156%
Adjusted FFO/Debt Ratio(2)
10% 14.0% 14.4% 14.9% 15.0% 200%
Safety(3)
10% SIF: 7
TRIR: 0.55
SIF: 5
TRIR: 0.45
SIF: 3
TRIR: 0.40
SIF: 18
TRIR: 0.41
90%
Customer NPS(4)
10% Residential: 52
Business: 39
Large C&I: 43
Residential: 49
Business: 37
Large C&I: 45
Residential: 47
Business: 32
Large C&I: 47
Residential: 34
Business: 26
Large C&I: 49
200%
DIB 10% Qualitative assessment
89%
Calculated EAM(5)
100% 25% 100% 200% 151%
Adjusted EAM(6)
142%
(1)ETR Adjusted EPS is a non-GAAP measure. The goals and results set forth in the table above for ETR Adjusted EPS are presented on Stock Split adjusted basis; the pre-Stock Split target goal approved by the Talent and Compensation Committee in January 2024 for ETR Adjusted EPS was $7.20, with pre-Stock Split minimum and maximum goals set at $7.02 and $7.38, respectively. See "What Energy Corporation Pays and Why - 2024 Compensation Decisions - 2024 Annual Incentive Program Performance Measures and Methodology " for information regarding this non-GAAP financial measure.
(2)The Adjusted FFO/Debt Ratio, a non-GAAP measure, is the ratio of: (i) adjusted funds from operations calculated as consolidated operating cash flow adjusted for allowance for funds used during construction, working capital (including deferred fuel), the effects of securitization revenue and expense, and the Pre-Determined Exclusions (defined later in this CD&A) to (ii) total consolidated debt, excluding current and pending securitization debt, in each case calculated to reflect rating agency treatment of interest and principal on Entergy’s junior subordinated debentures. The Talent and Compensation Committee decided to calculate the Adjusted FFO/Debt Ratio in a manner consistent with the rating agency treatment of such debt, as updated in early 2024, in order to ensure that management’s incentives remained aligned with the goal of optimizing Entergy’s capital structure while maintaining its credit rating.
(3)For 2024, the Safety measure calculation was based on the Company's TRIR and the Company's SIF count as defined by the EEI, with results of both sub-metrics being equally weighted.
(4)For 2024, the Customer NPS measure was calculated based on equally weighted categories of residential, business and large C&I customer NPS scores.
(5)Reflects the EAM as a percentage of target and as calculated in accordance with the annual incentive program prior to the Talent and Compensation's discretionary adjustment.
(6)As discussed below, the Talent and Compensation Committee exercised its discretion to adjust the EAM downward to 142%, equating to a level of achievement on Safety of zero, due to the Company's poor performance on serious injuries and fatalities, including four contractor fatalities during the year.
In assessing the DIB measure, the committees performed a qualitative assessment of management’s performance in the areas of diversity, culture and commerce, informed by certain key performance indicators and quantitative measures, and assessed progress on DIB strategies and initiatives identified at the beginning of the
performance period as important to achieving the Company’s strategic objectives. Some of the 2024 actions taken and recognitions considered as part of the assessment of performance on the DIB measure included:
•Recognized within: Forbes Best Employers for Diversity List 2024, Newsweek America’s Greatest Workplaces for Diversity, USBE&IT Magazine Top Supporters of HBCU Schools;
•Received: Times-Picayune Top Workplaces Award (New Orleans), Houston Chronicle Top Workplace Award (Texas), Global Energy Transition Board Hero of the Community Award (Texas);
•Leadership Employee Resource Group recognized with 2024 Diversity Impact Spotlight Award;
•Seventh consecutive year receiving the U.S. Department of Labor Platinum Vets Medallion Award for veteran talent pipeline development, recruitment, and retention;
•Launched four new employee resource groups, which are open to all employees-ASPIRE (Black), VIDA (Hispanic), SHINE (Asian), and ABLE (Differently abled)-to further promote workplace inclusion;
•Sustained the Company's overall inclusion score of 78 (2nd Quartile) in the annual Inclusive Climate Survey; and
•Continued movement on workforce development programs to help promote a diverse pipeline.
In assessing 2024 performance, the Finance and Talent and Compensation Committees reviewed management’s performance under each of the performance measures referenced above in relation to the targets set at the beginning of the year, including primary drivers explaining how the results achieved compared to the targets set for each measure.
The foregoing performance resulted in a calculated EAM of 151%. However, the Talent and Compensation Committee exercised its discretion to reduce the EAM to 142%, due to the Company’s poor performance on serious injuries and fatalities, including four contractor fatalities during the year. This adjustment equated to resetting the level of achievement for the Safety metric to zero. The Talent and Compensation Committee concluded that despite the Company’s improved TRIR performance, such an adjustment was warranted by its SIF count performance at a level well below the minimum level of performance.
In addition to the foregoing financial and non-financial results, the Talent and Compensation Committee considered each NEO's degree of success in achieving various strategic, operational and regulatory objectives and in overcoming certain challenges that arose in the business during the course of the year. To determine the individual NEO annual incentive program awards, the Talent and Compensation Committee considered individual performance in executing on the Company’s strategies and delivering the strong financial performance and operational successes achieved in 2024, as well as the executive’s success in achieving individual goals within the executive’s scope of responsibilities. The committee also considered certain challenges the Company experienced during the year and each officer’s accountabilities and accomplishments in addressing those challenges. With these considerations in mind, the Talent and Compensation Committee approved the following annual incentive payouts to each of the NEOs, ranging from 112% to 159% of target.
Named Executive Officer Year-End Base Salary Target as Percentage of Year-End Base Salary 2024 Target Award
Payout as Percentage of Target 2024 Annual
Incentive Award
Marcus V. Brown $791,754 80% $633,403 146% $924,768
Haley R. Fisackerly $458,019 55% $251,910 159% $400,537
Kimberly A. Fontan $706,250 85% $600,313 146% $876,457
Laura R. Landreaux $430,983 55% $237,041 140% $331,857
Andrew S. Marsh $1,250,000 130% $1,625,000 142% $2,307,500
Phillip R. May, Jr. $472,863 60% $283,718 159% $451,112
Peter S. Norgeot, Jr.
$669,760 75% $502,320 112% $562,598
Deanna D. Rodriguez $375,924 50% $187,962 140% $263,147
Eliecer Viamontes $418,077 55% $229,942 140% $321,919
Roderick K. West $835,753 80% $668,602 146% $976,159
Long-Term Incentive Compensation
Long-term incentive compensation delivered in shares of Entergy common stock represents the largest portion of executive officer compensation. The Company believes the combination of long-term incentives it employs provides a compelling performance-based compensation opportunity, is effective at retaining a strong senior management team, and aligns the interests of the executive officers with the interests of Entergy’s customers and shareholders by enhancing executive officers’ focus on the Company’s long-term goals.
For each NEO, a dollar value is established to determine that NEO’s long-term incentive awards. The target award value for each NEO is determined based on market median compensation data for the officer’s role, adjusted to reflect internal equity and individual performance, including each NEO’s degree of success in achieving various strategic, operational, and regulatory objectives and in overcoming certain challenges that arose in the business during the course of the year.
2024 Long-Term Compensation Incentive Compensation Mix
In January 2024 the Talent and Compensation Committee approved the 2024 long-term incentive award target amounts for each NEO. This amount for each NEO was then converted into the number of performance units, stock options, and shares of restricted stock granted to each NEO based on an allocation of 60% performance units, 20% stock options, and 20% restricted stock.
NEO Long-Term Incentive
Grant Date Value(1)
(As of January 25, 2024)
2024-2026 Target Performance Units
Stock Options Shares of Restricted Stock
Marcus V. Brown $1,493,209 14,848 33,062 6,018
Haley R. Fisackerly $475,721 4,730 10,532 1,918
Kimberly A. Fontan $1,861,138 18,506 41,206 7,502
Laura R. Landreaux $609,407 6,060 13,492 2,456
Andrew S. Marsh $7,190,823 71,502 159,218 28,982
Phillip R. May, Jr. $574,332 5,710 12,716 2,316
Peter S. Norgeot, Jr.
$1,529,283 15,206 33,862 6,164
Deanna D. Rodriguez $304,960 3,032 6,750 1,230
Eliecer Viamontes $382,561 3,804 8,470 1,542
Roderick K. West(2)
$1,603,709 15,946 35,510 6,464
(1) Due to fluctuations in stock price, grant date value may differ from the value on date the long-term incentive award target dollar values are established for each NEO.
(2) The shares of restricted stock noted in the table above for Mr. West were forfeited upon his retirement from the Company on January 31, 2025. The stock options noted in the table above for Mr. West will continue to vest following his retirement, in accordance with the original vesting schedule and will expire five years after his retirement date. With respect to the target PUP performance units noted in the table above, Mr. West will be eligible for a pro-rated award based on actual performance and full months of service during the performance period. See "Potential Payments Upon Termination or Change in Control" for additional information on the treatment of Mr. West's outstanding equity awards in connection with his retirement from Entergy.
All the performance units, shares of restricted stock and stock options granted to the NEOs in 2024 were granted pursuant to the 2019 OIP. The 2019 OIP requires a “double trigger,” meaning both a change in control of Entergy and an involuntary job loss without cause or a resignation by the NEO for good reason within 24 months following the change in control, for the acceleration of these awards upon a change in control.
Performance Units
The NEOs are issued performance unit awards under the PUP with payout opportunities established by the Talent and Compensation Committee at the beginning of each three-year performance period. The PUP specifies minimum, target, and maximum performance goals, the achievement of which determines the number of performance units that may be earned by each participant.
2024-2026 PUP Performance Measures and Goals
For the 2024-2026 PUP, the Talent and Compensation Committee placed the Adjusted FFO/Debt Ratio measure used in the PUP for the 2021-2023, 2022-2024 and 2023-2025 performance periods with an Environmental Stewardship measure (weighted 20%) to better align with the Company's multi-year approach to decarbonization and also based on shareholder feedback to incorporate an environmental performance measure into
the PUP. The Talent and Compensation Committee continued to use Relative TSR in the 2024-2026 PUP, which retained its weighting of 80%.
Relative TSR
The Talent and Compensation Committee chose Relative TSR as a PUP performance measure because it reflects the Company’s creation of shareholder value relative to other electric utilities included in the Philadelphia Utility Index over the performance period. By measuring performance in relation to an industry benchmark, this measure is intended to isolate, and reward management for, the creation of shareholder value that is not driven by events that affect the industry as a whole.
Minimum, target and maximum performance goals are determined by reference to the ranking of Entergy’s TSR in relation to the TSR of the companies in the Philadelphia Utility Index. The Talent and Compensation Committee identified the Philadelphia Utility Index as the appropriate industry peer group for determining Relative TSR because the companies included in this index, in the aggregate, are viewed as comparable to the Company in terms of business and scale.
Environmental Stewardship
The Environmental Stewardship measure consists of two components designed to capture the key dimensions of Entergy's response to climate change:
•A Climate Resilience component, sub-weighted at 60%, which is focused on reduction in storm restoration costs attributable to completed infrastructure improvement investments.
•A Carbon-Free Generation component, sub-weighted at 40%, which is focused on generation of electricity from carbon emission-free sources as compared to the Company's projection for the 2024-2026 performance period.
A Carbon Capture Modifier applies to the Carbon-Free Generation component in the range of -9% to +9% based on the Talent and Compensation Committee's assessment of achievement (or lack of achievement) of specific CCS objectives.
The Environmental Stewardship measure was incorporated as a performance measure in the 2024-2026 PUP because:
•It measures progress towards quantitative goals that align with desired customer and owner outcomes for clean energy, reliable operation and reduced storm restoration costs.
•It aligns with interests of regulators to see positive outcomes from capital investments in managing both transition and physical risk.
In January 2024, the Talent and Compensation Committee established the following goals for the 2024-2026 PUP performance measures:
Performance Measures(1)
PUP
Measure Weight Goals(2)
Relative TSR 80% Minimum (25%) - Bottom of 3rd Quartile
Target (100%) - Median Percentile
Maximum (200%) - 1st Quartile
Environmental Stewardship
20% Climate Resilience (60%)(3)
2024: Minimum - 0%; Target - 2%; Maximum - 7%
2025: Minimum - 2%; Target - 3%; Maximum - 8%
2026: Minimum - 4%; Target - 9%; Maximum - 14%
Carbon-Free Generation (40%)(4)
Minimum - 128,320 TWh
Target - 133,900 TWh
Maximum - 139,479 TWh
(1)Payouts for performance between achievement levels are calculated using straight-line interpolation, between minimum and target and between target and maximum, with no payouts for performance below the minimum achievement level with respect to the applicable performance measure, and payouts capped at the maximum achievement level with respect to the applicable performance measure.
(2)There is no payout if the Relative TSR falls within the lowest quartile of the peer companies in the Philadelphia Utility Index and if both Climate Resilience and Carbon-Free Generation are below the minimum achievement levels.
(3)The achievement levels established for the Climate Resilience sub-metric are based on annual restoration cost reduction impacts of projects scheduled to be completed with funding under the financial plan based on a model approved by the Talent and Compensation Committee in January 2024.
(4)The goals for the Carbon-Free Generation sub-metric are based on cumulative TWhs generated over the three year period. The result of the Carbon-Free Generation sub-metric is subject to a carbon capture modifier in the range of -9% to +9% of the Carbon-Free Generation component based on the Talent and Compensation Committee's assessment of progress toward specific CCS objectives.
2022-2024 PUP Performance Measures, Goals and Payouts
In December 2021, the Talent and Compensation Committee chose Relative TSR and Adjusted FFO/Debt Ratio as the performance measures for the 2022-2024 PUP, with Relative TSR weighted 80% and Adjusted FFO/Debt Ratio weighted 20%. In January 2022, the Talent and Compensation Committee established the following minimum, target and maximum performance goals for the 2022-2024 PUP performance measures:
Performance Measures(1)
PUP
Measure Weight Goals(2)
Relative TSR 80% Minimum (25%) - Bottom of 3rd Quartile
Target (100%) - Median Percentile
Maximum (200%) - 1st Quartile
Adjusted FFO/Debt Ratio(3)
20% Minimum (25%) - 14.0%
Target (100%) - 15.0%
Maximum (200%) - 16.5%
(1)Payouts for performance between achievement levels are calculated using straight-line interpolation. There is no payout for performance below the minimum achievement level and payouts are capped at 200% for performance at or above the maximum achievement level.
(2)There is no payout if the Relative TSR falls within the lowest quartile of the peer companies in the Philadelphia Utility Index and the FFO/Debt Ratio is below the minimum achievement level.
(3)The Adjusted FFO/Debt Ratio, a non-GAAP financial measure, is the ratio of: (i) adjusted funds from operations calculated as consolidated operating cash flow adjusted for allowance for funds used during construction, working capital, excluding deferred fuel and the effects of securitization revenue and expense, and the Pre-Determined Exclusions (as defined this CD&A) to (ii) total consolidated debt, excluding current and pending securitization debt, in each case calculated to reflect rating agency treatment of interest and principal on the Company’s junior subordinated debentures. The Adjusted FFO/Debt Ratio is evaluated on an annual basis against the target set for each year, which, for the 2022-2024 performance period, was 15.0%. The annual results are then averaged to determine the Adjusted FFO/Debt Ratio overall result, which is then further adjusted by ±10 basis points for a favorable or unfavorable change in the Company's corporate credit outlook and ± 20 basis points for an upgrade or downgrade in the corporate credit rating for the Company, with a maximum adjustment of ±20 basis points. The Talent and Compensation Committee decided to calculate the Adjusted FFO/Debt Ratio in a manner consistent with the rating agency treatment of such debt, as updated in early 2024, in order to ensure that management’s incentives remained aligned with the goal of optimizing the Company's capital structure while maintaining its credit rating.
In January 2025, the Talent and Compensation Committee reviewed the Company’s Relative TSR and Adjusted FFO/Debt Ratio for the 2022-2024 PUP in order to determine the vesting level of the 2022-2024 PUP. The Talent and Compensation Committee compared the Company’s TSR against the TSR of the companies that were included in the Philadelphia Utility Index as of the last day of the year preceding the beginning of the three-year performance period, which were (in addition to Entergy):
•AES Corporation
•Eversource Energy
•Ameren Corporation
•Exelon Corporation
•American Electric Power Co. Inc.
•FirstEnergy Corporation
•American Water Works Company, Inc.
•NextEra Energy, Inc.
•CenterPoint Energy Inc.
•Pinnacle West Capital Corporation
•Consolidated Edison Inc.
•Public Service Enterprise Group, Inc.
•Dominion Energy
•Southern Company
•DTE Energy Company
•WEC Energy Group, Inc.
•Duke Energy Corporation
•Xcel Energy, Inc.
•Edison International
As recommended by the Finance Committee, the Talent and Compensation Committee concluded that Entergy Corporation’s Relative TSR for the 2022- 2024 PUP was in the 1st Quartile, resulting in an achievement level of 200% of target, and that the Adjusted FFO/Debt Ratio was 13.8% for 2022, 17.2% for 2023 and 15.6% for 2024, plus an upward adjustment of 10% due to the Company's improved credit outlook in 2024, resulting in an achievement level of 124% of target. These results yielded an overall payout of 185% of target for the NEOs.
Named Executive Officer
2022 - 2024 Target Performance Units
Number of Shares Issued(1)
Value of Shares Actually Issued(2)
Grant Date Fair Value(3)
Marcus V. Brown 12,954 26,041 $2,135,102 $862,153
Haley R. Fisackerly(4)
3,020 6,069 $497,597 $200,996
Kimberly A. Fontan(4)
10,604 21,063 $1,726,955 $705,749
Laura R. Landreaux(4)
3,538 7,097 $581,883 $235,472
Andrew S. Marsh(4)
46,236 91,954 $7,539,308 $3,077,237
Phillip R. May, Jr. 5,742 11,543 $946,411 $382,159
Peter S. Norgeot, Jr.(4)
12,186 24,319 $1,993,915 $811,039
Deanna D. Rodriguez(4)
2,508 5,035 $412,820 $166,920
Eliecer Viamontes(4)
3,154 6,324 $518,505 $209,914
Roderick K. West 19,050 38,296 $3,139,889 $1,267,873
(1)Includes accrued dividend equivalents.
(2)Value determined based on the closing price of Entergy Corporation common stock on January 17, 2025 ($81.99), the date the Talent and Compensation Committee certified the 2022-2024 PUP results.
(3)Represents the aggregate grant date fair value calculated in accordance with applicable accounting rules.
(4)Mses. Fontan, Landreaux, and Rodriguez and Messrs. Fisackerly, Norgeot, Marsh, and Viamontes each experienced a change in officer status in 2022, and accordingly, their target award opportunity was increased for all open PUP performance periods, including for the 2022-2024 PUP. Additionally, their promotions resulted in certain prorations with respect to the calculation of the dividend equivalents.
Pre-Determined Exclusions
The exclusions for the 2024 annual incentive program EAM and for the 2022-2024 PUP included effects of: (i) major storms, including the impact on total debt of pending securitizations; (ii) resolutions during the year of certain unresolved regulatory litigation matters; (iii) income tax law changes; and (iv) any adjustments to contributions to pension investments or trusts related to post-retirement benefits that are elective and deviate from original plan assumptions.
The Talent and Compensation Committee also considered, both at the time it chose ETR Adjusted EPS and the Adjusted FFO/Debt Ratio as the 2024 EAM performance measures and at the time it chose the Adjusted FFO/Debt Ratio as a performance measure in the 2022-2024 PUP and also at the time when it was establishing the targets for these measures, the appropriateness of excluding the effect of each of the specific Pre-Determined Exclusions it had identified. It viewed the exclusion of major storms as appropriate because although the Company includes estimates for minor storm costs in its financial plan, it does not include estimates for a major storm event, such as a hurricane, given management’s inability to control or predict acts of nature. The Talent and Compensation Committee considered the exclusion of the effects of any unanticipated changes in federal income tax law to be appropriate because of the inability of management to impact those results. It approved the exclusion of elective adjustments to Company contributions to pension and post-retirement benefit plan trusts because such elective adjustments are not viewed as reflective of the underlying performance of the business. The Talent and Compensation Committee approved the exclusion for the impact of certain unresolved legacy regulatory litigation primarily because of management’s inability to influence the related outcomes.
Stock Options and Restricted Stock
The Company grants stock options and shares of restricted stock as part of its long-term incentive award mix because it aligns the interests of the executive officers with long-term shareholder value, provides competitive compensation, and increases the executives’ ownership in Entergy’s common stock. Generally, stock options are granted annually on a pre-established schedule with a maximum term of ten years and vest one-third on each of the first three anniversaries of the date of grant. The date of grant for annual equity awards is the date of the Talent and Compensation Committee meeting at which they are approved, which is regularly scheduled each year in late January or the first week of February. The Talent and Compensation Committee does not take material nonpublic information into account when determining the timing and terms of option awards nor does it time the disclosure of material nonpublic information to affect the value of executive compensation. The exercise price for each option granted in January 2024 was $49.54 ($99.08 pre-Stock Split), which was based on the closing price of Entergy’s stock on the date of grant. Shares of restricted stock vest one-third on each of the first three anniversaries of the date of grant, are paid dividends which are reinvested in shares of Entergy stock, and have full voting rights. The dividend reinvestment shares are subject to the same vesting conditions as the underlying shares of restricted stock.
Health, Welfare, Retirement and other Benefit Elements
The NEOs are eligible to participate in or receive the following benefits:
Plan Type Description
Retirement Plans Entergy Corporation-sponsored:
Entergy Retirement Plan - a tax-qualified final average pay defined benefit pension plan that covers a broad group of employees hired before July 1, 2014. As used in this CD&A, “Entergy Retirement Plan” refers to the final average pay defined benefit pension plan benefit provided to eligible employees pursuant to the Entergy Corporation Retirement Plan for Non-Bargaining Employees.
Cash Balance Plan - a tax-qualified cash balance defined benefit pension plan that covers a broad group of employees hired on or after July 1, 2014 and before January 1, 2021. Effective January 1, 2022, the Cash Balance Plan was merged with and into the Entergy Retirement Plan, while maintaining the same cash balance pension benefit formula. As used in this CD&A, “Cash Balance Plan” refers to the cash balance defined benefit pension plan benefit provided to eligible employees.
Pension Equalization Plan (PEP) - a non-qualified pension restoration plan for certain highly compensated non-bargaining employees who participate in the Entergy Retirement Plan.
Cash Balance Equalization Plan (CBEP) - a non-qualified restoration plan for a certain highly compensated non-bargaining employees who participate in the Cash Balance Plan.
System Executive Retirement Plan (SERP) - a legacy non-qualified supplemental retirement plan for a select group of individuals who became executive officers before July 1, 2014.
See “2024 Pension Benefits” for additional information regarding the operation of and NEO participation in the plans described above.
Savings Plan Entergy Corporation-sponsored 401(k) Savings Plan that covers a broad group of employees and provides for an employer matching contribution.
Health & Welfare Benefits Medical, dental and vision coverage, health care and dependent care reimbursement plans, life and accidental death and dismemberment insurance, business travel accident insurance, and basic long-term disability insurance.
Eligibility, coverage levels, potential employee contributions, and other plan design features are the same for the NEOs as for the broad employee population.
Plan Type Description
2024 Perquisites
Corporate aircraft usage and annual mandatory physical exams. Members of the OCE do not receive tax gross ups on any benefits, except for relocation benefits.
For additional information regarding perquisites, including additional limited perquisites that were received by certain of the NEOs during 2024 prior to becoming members of the OCE, see the “All Other Compensation” column in the 2024 Summary Compensation Table.
Deferred Compensation The NEOs are eligible to defer up to 100% of their base salary and annual incentive awards into the Entergy Corporation sponsored Executive Deferred Compensation Plan.
Executive Disability Plan This plan pays eligible individuals a supplemental long-term disability (LTD) benefit if they are disabled and receiving LTD benefits from the broad-based LTD Plan. The benefit payable under this plan is equal to 65% of the difference between their annual base salary and the annual base salary that produces the maximum disability payment under our broad-based LTD plan, which is $15,000.
Entergy Corporation provides these benefits to the NEOs as part of its effort to provide a competitive executive compensation program and because it believes that these benefits are important retention and recruitment tools since many of the companies with which it competes for executive talent provide similar arrangements to their senior executive officers.
Severance and Retention Arrangements
The Talent and Compensation Committee believes that retention and transitional compensation arrangements are an important part of overall compensation as they help to secure the continued employment and dedication of the NEOs, notwithstanding any concern that they might have at the time of a change in control regarding their own continued employment. In addition, the Talent and Compensation Committee believes that these arrangements are important as recruitment and retention devices, as many of the companies with which Entergy Corporation competes for executive talent have similar arrangements in place for their senior employees.
To achieve these objectives, Entergy Corporation has established a System Executive Continuity Plan (“Continuity Plan”) under which each of our NEOs is entitled to receive “change in control” payments and benefits if such officer’s employment is involuntarily terminated without cause or if the officer resigns for good reason, in each case, in connection with a change in control of the Company. Entergy strives to ensure that the benefits and payment levels under the Continuity Plan are consistent with market practices. Entergy’s executive officers, including the NEOs, are not entitled to any tax gross up payments on any severance benefits received under this plan. For more information regarding our severance arrangements, see “Potential Payments Upon Termination or Change in Control.”
Risk Mitigation and Other Pay Practices
Policy for Recoupment of Compensation (Clawback Provisions)
On October 27, 2023, the Board adopted an amended and restated policy regarding the recoupment of certain compensation (the "Clawback Policy"), with an effective date of October 2, 2023. Any incentive compensation award granted or paid on or after this effective date is subject to the terms of the Clawback Policy, while awards granted or paid prior to the effective date of the Clawback Policy are subject to the Entergy Corporation Policy Regarding Recoupment of Certain Compensation in effect prior to its amendment and restatement. The board of directors of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas also adopted the Clawback Policy, effective October 2, 2023.
Under the Clawback Policy, which goes beyond the requirements of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), Entergy will seek reimbursement of certain compensation from current or former executive officers subject to Section 16, including all of the NEOs, where:
•Entergy is required to restate its financial statements due to noncompliance with any financial reporting requirement under securities laws; or
•there is a material miscalculation of a performance measure related to incentive compensation, regardless of whether Entergy’s financial statements are restated.
In addition, Entergy may seek reimbursement of certain compensation from current or former executive officers subject to Section 16, including all of the NEOs, if the Board determines that such executive officer engaged in fraud that resulted in either a restatement of Entergy’s financial statements or a material miscalculation of a performance measure relative to incentive compensation.
The Clawback Policy applies to incentive compensation, including cash or equity-based bonus or incentive or profit-sharing awards paid in respect of the three-year period prior to the year in which Entergy is required to prepare such restatement or in respect of the three-year period preceding the material miscalculation. The amount required to be reimbursed is equal to the excess of the gross incentive payment actually paid over the gross payment that would have been paid if the original payment had been determined based on the restated financial results or correct calculation. Entergy may enforce all or part of any executive officer’s repayment obligation under the policy by reducing any amounts that may be owed from time-to-time by Entergy or any of its subsidiaries to such individual, whether as wages, severance, vacation pay or in the form of any other benefit or for any other reason. In addition, Entergy will seek to recover any compensation received by its Chief Executive Officer and Chief Financial Officer that is required to be reimbursed under the Sarbanes-Oxley Act of 2002 following a material restatement of our financial statements.
In addition to the above-described Clawback Policy, in January 2024, the Entergy Board adopted an additional discretionary recoupment policy applicable to all officers of Entergy System companies, including the NEOs, that allows recoupment of incentive compensation from an officer who engages in certain detrimental conduct, including (i) commission of a felony or other crime that affects the officer’s ability to perform their duties, (ii) fraud in contravention of the officer’s duties to the enterprise, (iii) unauthorized disclosure of confidential or proprietary information of an Entergy System company or material violation of a material written Entergy System company policy or material agreement between the officer and an Entergy System company in either case that results in, or could have resulted in, termination for cause as defined in the 2019 OIP or that results in significant financial or operational loss, or significant reputational harm to Entergy; and (iv) other conduct that the officer knew or should have known could result in termination for Cause as defined in the 2019 OIP (regardless whether it does) and that results in significant financial or operational loss or significant reputational harm to Entergy. The discretionary recoupment policy for detrimental conduct applies to all incentive compensation, including time-based awards, and allows for the claw back of compensation received after the detrimental conduct and within the three-year period preceding the detrimental conduct, provided the recoupment efforts are commenced within five years after the detrimental conduct and before a change in control. The additional discretionary recoupment policy applies to detrimental conduct committed on or after January 26, 2024, the effective date of the policy.
Stock Ownership Guidelines and Share Retention Requirements
Entergy Corporation requires its NEOs to own Entergy stock to further align their interests with Entergy’s shareholders’ interests. Stock ownership levels are achieved through ownership of any Entergy shares held by the officer, including shares held in the 401(k) plan, restricted stock, dividends earned on restricted shares during the period of restriction, and restricted stock units. Performance units held under the PUP, stock options, whether vested or unvested, do not count toward achievement of stock ownership levels. Annually, the Talent and Compensation Committee monitors the executive officers’ compliance with these guidelines with all of the NEOs being in compliance with the applicable ownership guidelines at the time of the most recent annual review. The ownership guidelines are as follows:
Role Value of Common Stock to be Owned
Chief Executive Officer 6 x base salary
Executive Vice Presidents 3 x base salary
Senior Vice Presidents 2 x base salary
Vice Presidents 1 x base salary
Further, to facilitate compliance with the guidelines, until an executive officer satisfies the stock ownership guidelines, the officer must retain:
•all net after-tax shares paid out under the PUP;
•all net after-tax shares of our restricted stock and all net after-tax shares received upon the vesting of restricted stock units; and
•at least 75% of the after-tax net shares received upon the exercise of Entergy Corporation stock options.
Trading Controls
Executive officers, including the NEOs, are subject to the Company's insider trading policy (included as Exhibit 19 to this Annual Report on Form 10-K) and thus are required to receive permission from the Company’s General Counsel or his designee prior to entering into any transaction involving Company securities, including gifts, other than an exercise of employee stock options that is not funded through a sale in the market. Trading is generally permitted only during specified open trading windows beginning shortly after the release of earnings. Employees who are subject to trading restrictions, including the NEOs, may enter into trading plans under Rule 10b5-1 of the Exchange Act, but these trading plans or any amendment to an existing plan may be entered into only during an open trading window and must be approved by the Company.
No Pledging/Hedging
Entergy Corporation also prohibits directors and executive officers, including the NEOs, from pledging any Entergy Corporation securities or entering into margin accounts involving Entergy Corporation securities. Entergy Corporation prohibits these transactions because of the potential that sales of Entergy Corporation securities could occur outside trading periods and without the required approval of the General Counsel. In addition, Entergy Corporation prohibits directors and executive officers, including the NEOs, from engaging in any hedging transactions with respect to Entergy securities.
Compensation Consultant Independence
Annually, the Talent and Compensation Committee reviews the relationship with its compensation consultant to determine whether any conflicts of interest exist that would prevent the consultant from independently advising the Talent and Compensation Committee. When assessing the independence of Pay Governance, its current compensation consultant, in 2024, the committee considered the following factors, among others:
•Pay Governance has policies in place to prevent conflicts of interest;
•No member of Pay Governance’s consulting team serving the committee has a business relationship with any member of the committee or any of Entergy Corporation’s executive officers;
•Neither Pay Governance nor any of its principals own any shares of Entergy Corporation’s common stock; and
•The amount of fees paid to Pay Governance is less than 1% of Pay Governance’s total consulting income.
Based on these factors, the Talent and Compensation Committee concluded that Pay Governance is independent in accordance with SEC and NYSE rules and that no conflicts of interest exist that would prevent Pay Governance from independently advising the committee.
In addition, Pay Governance has agreed that it will not accept any engagement with management without prior approval from the Talent and Compensation Committee, and Entergy Corporation’s Board has adopted a policy that prohibits a compensation consultant from providing other services to it if the aggregate amount for those services would exceed $120,000 in any year. During 2024, Pay Governance did not provide any services to Entergy Corporation other than the services it performed on behalf of the Talent and Compensation and Corporate Governance Committees, and it worked with Entergy Corporation’s management only as directed by those committees.
TALENT AND COMPENSATION COMMITTEE REPORT
The Talent and Compensation Committee Report included in the 2025 Entergy Proxy Statement is incorporated by reference, but will not be deemed to be “filed” in this Annual Report on Form 10-K. None of the Registrant Subsidiaries has a compensation committee or other board committee performing equivalent functions. The board of directors of each of the Registrant Subsidiaries is comprised of individuals who are officers or employees of Entergy Corporation or one of the Registrant Subsidiaries. These boards do not make determinations regarding the compensation paid to executive officers of the Registrant Subsidiaries.
EXECUTIVE COMPENSATION TABLES
2024 Summary Compensation Table
The following table summarizes the total compensation paid or earned by each of the NEOs for the fiscal year ended December 31, 2024, and to the extent required by SEC executive compensation disclosure rules, the fiscal years ended December 31, 2023 and 2022. For information on the principal positions held by each of the NEOs, see Item 10, “Directors, Executive Officers, and Corporate Governance of the Registrants.”
The compensation set forth in the table represents the aggregate compensation paid by all Entergy System companies. For additional information regarding the material terms of the awards reported in the following table, including a general description of the formula or criteria to be applied in determining the amounts payable, see “Compensation Discussion and Analysis.”
(a) (b) (c) (e) (f) (g) (h) (i) (j) (k)
Name and Principal Position (1) Year
Salary
(2)
Stock Awards
(3)
Option
Awards
(4)
Non-Equity
Incentive
Plan
Compen-
sation
(5)
Change in
Pension
Value and
Non-qualified
Deferred
Compen-
sation
Earnings
(6)
All
Other
Compen-
sation
(7)
Total
Total
Without
Change in
Pension
Value
(8)
Marcus V. Brown 2024 $783,555 $1,185,567 $307,642 $924,768 $455,800 $67,092 $3,724,424 $3,268,624
Executive Vice
2023 $753,419 $1,226,636 $290,192 $950,104 $731,700 $77,328 $4,029,379 $3,297,679
President and
2022 $726,363 $1,144,238 $273,358 $761,302 $976,700 $93,793 $3,975,754 $2,999,054
General Counsel -
Entergy Corp.
Haley R. Fisackerly 2024 $452,266 $377,721 $98,000 $400,537 $319,800 $50,558 $1,698,882 $1,379,082
CEO - Entergy 2023 $431,421 $453,653 $107,294 $325,368 $247,800 $47,415 $1,612,951 $1,365,151
Mississippi 2022 $410,557 $752,209 $62,595 $319,427 $- $46,281 $1,591,069 $1,591,069
Kimberly A. Fontan 2024 $684,375 $1,477,716 $383,422 $876,457 $433,100 $34,937 $3,890,007 $3,456,907
Executive Vice 2023 $625,000 $1,165,112 $275,621 $646,875 $409,600 $31,860 $3,154,068 $2,744,468
President and CFO -
2022 $404,809 $1,034,293 $80,519 $379,688 $- $29,720 $1,929,029 $1,929,029
Entergy Corp.,
Entergy Arkansas,
Entergy Louisiana,
Entergy Mississippi,
Entergy New
Orleans, and
Entergy Texas
Laura R. Landreaux 2024 $425,320 $483,864 $125,543 $331,857 $89,900 $23,491 $1,479,975 $1,390,075
CEO - Entergy 2023 $406,405 $377,082 $89,191 $305,428 $175,600 $23,719 $1,377,425 $1,201,825
Arkansas 2022 $390,161 $341,381 $62,595 $271,015 $- $25,313 $1,090,465 $1,090,465
Andrew S. Marsh 2024 $1,209,615 $5,709,300 $1,481,523 $2,307,500 $2,043,600 $94,837 $12,846,375 $10,802,775
Chair of the
2023 $1,100,000 $5,159,370 $1,220,557 $1,821,600 $982,400 $89,281 $10,373,208 $9,390,808
Board and CEO - 2022 $781,560 $4,598,890 $414,050 $960,700 $- $106,560 $6,861,760 $6,861,760
Entergy Corp.
(a) (b) (c) (e) (f) (g) (h) (i) (j) (k)
Name and Principal Position (1) Year
Salary
(2)
Stock Awards
(3)
Option
Awards
(4)
Non-Equity
Incentive
Plan
Compen-
sation
(5)
Change in
Pension
Value and
Non-qualified
Deferred
Compen-
sation
Earnings
(6)
All
Other
Compen-
sation
(7)
Total
Total
Without
Change in
Pension
Value
(8)
Phillip R. May, Jr. 2024 $467,944 $456,010 $118,322 $451,112 $146,500 $36,357 $1,676,245 $1,529,745
CEO - Entergy 2023 $449,491 $459,481 $108,679 $340,945 $114,400 $36,586 $1,509,582 $1,395,182
Louisiana 2022 $430,676 $957,246 $121,176 $326,732 $- $39,225 $1,875,055 $1,875,055
Peter S. Norgeot, Jr. 2024 $650,440 $1,214,197 $315,086 $562,598 $127,900 $52,852 $2,923,073 $2,795,173
Executive Vice
President and Chief
Operating Officer
Deanna D. Rodriguez 2024 $372,249 $242,151 $62,809 $263,147 $197,300 $26,228 $1,163,884 $966,584
CEO - Entergy 2023 $358,208 $270,525 $63,983 $226,421 $270,200 $23,671 $1,213,008 $942,808
New Orleans 2022 $342,565 $260,189 $48,328 $217,320 $- $27,087 $895,489 $895,489
Eliecer Viamontes 2024 $384,887 $303,748 $78,813 $321,919 $34,200 $33,055 $1,156,622 $1,122,422
CEO - Entergy 2023 $361,284 $333,024 $78,755 $251,202 $28,700 $25,846 $1,078,811 $1,050,111
Texas 2022 $347,459 $296,861 $53,528 $240,731 $11,800 $168,309 $1,118,688 $1,106,888
Roderick K. West 2024 $828,144 $1,273,288 $330,421 $976,160 $212,500 $119,140 $3,739,653 $3,527,153
Former Group
2023 $799,130 $1,547,047 $365,976 $775,192 $204,800 $112,338 $3,804,483 $3,599,683
President Utility
2022 $770,432 $3,682,723 $402,025 $776,434 $- $101,107 $5,732,721 $5,732,721
Operations - Entergy
Corp.
(1)No compensation information is provided for Mr. Norgeot for 2023 and 2022, as he was not included as a NEO in the Annual Report on Form 10-K for the years ended December 31, 2023 and December 31, 2022.
(2)The amounts in column (c) represent the actual base salary paid to the NEOs in the applicable year. The 2024 changes in base salaries noted in the CD&A were effective in April 2024. Mr. Viamontes’ off-cycle base salary adjustment noted in the CD&A was effective in September 2024.
(3)The amounts in column (e) represent the aggregate grant date fair value of restricted stock and performance units granted under the 2019 OIP, each calculated in accordance with FASB ASC Topic 718, without taking into account estimated forfeitures. The grant date fair value of the restricted stock, restricted stock units, and the portion of the performance units with vesting based on the Adjusted FFO/Debt Ratio (within the 2022-2024 PUP and 2023-2025 PUP) and the Environmental Stewardship measure (used within the 2024-2026 PUP) is determined using the closing price of Entergy Corporation common stock on the date of grant. The grant date fair value of the portion of the performance units attributable to Relative TSR was measured using a Monte Carlo simulation valuation model. The simulation model applies a risk-free interest rate and an expected volatility assumption. The risk-free interest rate is assumed to equal the yield on a three-year treasury bond on the grant date. Volatility is based on historical volatility for the 36-month period preceding the grant date. The performance units in the table are also valued based on the probable outcome of the applicable performance condition at the time of grant. The maximum value of shares that would be received if the highest achievement level is attained with respect to both the Relative TSR and Environmental Stewardship measures, for performance units granted in 2024 are as follows: Mr. Brown, $1,471,140; Mr. Fisackerly, $468,648; Ms. Fontan, $1,833,574; Ms. Landreaux, $600,425; Mr. Marsh, $7,084,418; Mr. May, $565,747; Mr. Norgeot, $1,506,610; Ms. Rodriguez, $300,411; Mr. Viamontes, $376,900; and Mr. West, $1,579,930.
(4)The amounts in column (f) represent the aggregate grant date fair value of stock options granted under the 2019 OIP calculated in accordance with FASB ASC Topic 718. For a discussion of the relevant assumptions used in valuing these awards, see Note 12 to the financial statements.
(5)The amounts in column (g) represent annual incentive award cash payments made pursuant to the annual incentive program established under the 2019 OIP.
(6)The amounts in column (h) include the annual actuarial change in the present value of these NEOs’ benefits under all pension plans established by Entergy Corporation using interest rate and mortality rate assumptions consistent with those used in Entergy Corporation’s financial statements. None of the increases for any of the NEOs are attributable to above-market or preferential earnings on non-qualified deferred compensation and includes any amounts which the NEOs may not currently be entitled to receive because such amounts are not vested. See “2024 Pension Benefits.”
(7)The amounts in column (i) for 2024 include (a) matching contributions by Entergy Corporation under the Savings Plan to each of the NEOs; (b) dividends and dividend equivalents paid on restricted stock and performance units when vested; (c) life insurance premiums; (d) tax reimbursements on club dues; and (e) perquisites and other compensation as described further below. The 2024 amounts are listed in the following table:
Named Executive Officer Company Matching Contribution - Savings Plan Dividends Paid on Restricted Stock and PUP Awards Life Insurance Premium Tax Reimbursement Perquisites and Other Compensation
Total
Marcus V. Brown $14,490 $37,692 $11,484 $- $3,426 $67,092
Haley R. Fisackerly $14,490 $8,120 $7,482 $5,375 $15,091 $50,558
Kimberly A. Fontan $14,490 $13,971 $1,757 $- $4,719 $34,937
Laura R. Landreaux $- $7,710 $2,215 $4,086 $9,480 $23,491
Andrew S. Marsh $14,490 $69,947 $5,372 $- $5,028 $94,837
Phillip R. May, Jr. $14,490 $11,131 $10,736 $- $- $36,357
Peter S. Norgeot, Jr.
$20,700 $23,492 $7,482 $- $1,178 $52,852
Deanna D. Rodriguez $14,490 $9,182 $2,556 $- $- $26,228
Eliecer Viamontes $20,700 $7,834 $864 $- $3,657 $33,055
Roderick K. West $14,490 $47,974 $7,038 $- $49,638 $119,140
(8)The Total Without Change in Pension Value represents total compensation, as determined under applicable SEC rules, minus the change in pension value reported in the Change in Pension Value and Nonqualified Deferred Compensation Earnings column for the applicable year. The amounts reported in the Total Without Change in Pension Value column may differ substantially from the amounts reported in the Total column required under SEC rules and are not a substitute for total compensation. The change in pension value is subject to many external variables, such as interest rates, assumptions about life expectancy, and changes in the discount rate determined at each year end, which are functions of economic factors and actuarial calculations that are not related to Entergy’s performance and are outside of the control of the Talent and Compensation Committee.
Perquisites and Other Compensation
The amounts set forth in column (i) also include perquisites and other personal benefits that Entergy provides to its NEOs as part of providing a competitive executive compensation program and for employee retention. The following perquisites were provided to the NEOs in 2024.
Named Executive Officer Personal Use of Corporate Aircraft Club Dues Executive Physical Exams Relocation
Marcus V. Brown X
Haley R. Fisackerly X X
Kimberly A. Fontan X
Laura R. Landreaux X
Andrew S. Marsh X
Phillip R. May, Jr.
Peter S. Norgeot, Jr. X
X
Deanna D. Rodriguez
Eliecer Viamontes X
Roderick K. West X X
For security and business reasons, Entergy Corporation’s Chief Executive Officer is permitted to use its corporate aircraft for personal use at the expense of Entergy Corporation. The other NEOs may use the corporate aircraft for personal travel subject to the approval of Entergy Corporation’s Chief Executive Officer. The NEOs also may occasionally use the corporate aircraft for the evacuation of themselves and immediate family in advance of anticipated major storms for business continuity purposes. Entergy Corporation believes that its officers’ ability to use its plane for limited personal use saves time and helps to ensure their safety and security while traveling, thereby benefiting the Company. Annually, the Talent and Compensation Committee reviews the level of personal use of the corporate aircraft by each of the executive officers.
The amounts included in column (i) of the 2024 Summary Compensation Table for the personal use of corporate aircraft, reflect the incremental cost to Entergy Corporation for use of the corporate aircraft, determined on the basis of the variable operational costs of each flight, including fuel, maintenance, flight crew travel expense, catering, communications, and fees, including flight planning, ground handling, and landing permits. The aggregate incremental aircraft usage cost associated with Mr. West’s personal use of the corporate aircraft was $45,822 for fiscal year 2024. In addition, Entergy Corporation offers its executives comprehensive annual physical exams at Entergy Corporation’s expense. In addition, executive officers may have the occasional personal use of tickets to athletic and cultural events when such tickets are not being used for business purposes, for which there is no incremental cost to the Company. Aside from Mr. West’s personal use of the corporate aircraft, none of the perquisites referenced above exceeded $25,000 for any of the NEOs.
2024 Grants of Plan-Based Awards
The following table summarizes award grants during 2024 to the NEOs. All share and per share information in this table has been adjusted to reflect the Stock Split.
Estimated Possible Payouts Under Non-Equity Incentive Plan Awards (1)
Estimated Future Payouts under Equity Incentive Plan Awards (2)
(a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l)
Name Grant Date Thresh-
old
Target
Maximum
Thresh-
old
Target
Maximum
All Other Stock Awards: Number of Shares of Stock or Units All Other Option Awards: Number of Securities Under-lying Options Exercise or Base Price of Option Awards Grant Date Fair Value of Stock and Option Awards
($) ($) ($) (#)
(#)
(#)
(#)
(3)
(#)
(4)
($/Sh) ($)
(5)
Marcus V. 1/25/24 $- $633,403 $1,266,806
Brown 1/25/24 3,712 14,848 29,696 $887,435
1/25/24 6,018 $298,132
1/25/24 33,062 $49.54 $307,642
Haley R. 1/25/24 $- $251,910 $503,820
Fisackerly 1/25/24 1,183 4,730 9,460 $282,703
1/25/24 1,918 $95,018
1/25/24 10,532 $49.54 $98,000
Kimberly A. 1/25/24 $- $600,313 $1,200,625
Fontan 1/25/24 4,627 18,506 37,012 $1,106,067
1/25/24 7,502 $371,649
1/25/24 41,206 $49.54 $383,422
Laura R. 1/25/24 $- $237,041 $474,082
Landreaux 1/25/24 1,515 6,060 12,120 $362,194
1/25/24 2,456 $121,670
1/25/24 13,492 $49.54 $125,543
Andrew S. 1/25/24 $- $1,625,000 $3,250,000
Marsh 1/25/24 17,876 71,502 143,004 $4,273,532
1/25/24 28,982 $1,435,768
1/25/24 159,218 $49.54 $1,481,523
Phillip R. 1/25/24 $- $283,718 $567,436
May, Jr. 1/25/24 1,428 5,710 11,420 $341,275
1/25/24 2,316 $114,735
1/25/24 12,716 $49.54 $118,322
Peter S.
1/25/24 $- $502,320 $1,004,640
Norgeot, Jr.
1/25/24 3,802 15,206 30,412 $908,832
1/25/24 6,164 $305,365
1/25/24 33,862 $49.54 $315,086
Estimated Possible Payouts Under Non-Equity Incentive Plan Awards (1)
Estimated Future Payouts under Equity Incentive Plan Awards (2)
(a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l)
Name Grant Date Thresh-
old
Target
Maximum
Thresh-
old
Target
Maximum
All Other Stock Awards: Number of Shares of Stock or Units All Other Option Awards: Number of Securities Under-lying Options Exercise or Base Price of Option Awards Grant Date Fair Value of Stock and Option Awards
($) ($) ($) (#)
(#)
(#)
(#)
(3)
(#)
(4)
($/Sh) ($)
(5)
Deanna D. 1/25/24 $- $187,962 $375,924
Rodriguez 1/25/24 758 3,032 6,064 $181,217
1/25/24 1,230 $60,934
1/25/24 6,750 $49.54 $62,809
Eliecer 1/25/24 $- $229,942 $459,884
Viamontes 1/25/24 951 3,804 7,608 $227,357
1/25/24 1,542 $76,391
1/25/24 8,470 $49.54 $78,813
Roderick K. 1/25/24 $- $668,602 $1,337,205
West(6)
1/25/24 3,987 15,946 31,892 $935,061
1/25/24 6,464 $320,227
1/25/24 35,510 $49.54 $330,421
(1)The amounts in columns (c), (d), and (e) represent minimum, target, and maximum payment levels under the annual incentive program. The actual amounts awarded are reported in column (g) of the 2024 Summary Compensation Table.
(2)The amounts in columns (f), (g), and (h) represent the minimum, target, and maximum payment levels under the 2024-2026 PUP. Performance units granted under the 2024-2026 PUP pursuant to the 2019 OIP will vest on December 31, 2026 based on two performance measures-Relative TSR, weighted 80%, and Environmental Stewardship, weighted 20%, as described under “What We Pay and Why - Long-Term Incentive Compensation - 2024 Long-Term Incentive Compensation Mix - Performance Units” in the CD&A. Subject to the achievement of performance targets, each unit will be converted into one share of Entergy Corporation’s common stock on the last day of the performance period for the 2024-2026 long-term PUP cycle (December 31, 2026). Accrued dividends on the shares earned will also be paid in Entergy Corporation common stock.
(3)The amounts in column (i) represent shares of restricted stock granted under the 2019 OIP. Shares of restricted stock vest one-third on each of the first, second and third anniversaries of the grant date, have voting rights, and accrue dividends during the vesting period.
(4)The amounts in column (j) represent options to purchase shares of Entergy Corporation’s common stock granted under the 2019 OIP. The options vest one-third on each of the first, second and third anniversaries of the grant date and have a ten-year term from the date of grant.
(5)The amounts in column (l) are valued based on the aggregate grant date fair value of the award calculated in accordance with FASB ASC Topic 718 and, in the case of the performance units, are based on the probable outcome of the applicable performance conditions. See footnotes 4 and 5 to the 2024 Summary Compensation Table for a discussion of the relevant assumptions used in calculating the grant date fair value.
(6)The shares of restricted stock noted in the table above for Mr. West were forfeited upon his retirement from the Company on January 31, 2025. The stock options noted in the table above for Mr. West will continue to vest following his retirement, in accordance with the original vesting schedule and expire five years from
his retirement date. Mr. West will be eligible for a pro-rated PUP award based on actual performance and full months of service during the performance period. See "Potential Payments Upon Termination or Change in Control" for additional information on the treatment of Mr. West's outstanding equity awards in connection with his retirement from the Company.
2024 Outstanding Equity Awards at Fiscal Year-End
The following table summarizes, for each NEO, their outstanding unexercised options, outstanding restricted stock that has not vested, and equity incentive plan awards outstanding as of December 31, 2024. All share and per share information in this table has been adjusted to reflect the Stock Split.
Option Awards Stock Awards
(a) (b) (c) (d) (e) (f) (g) (h) (i) (j)
Name Number of
Securities
Underlying
Unexercised
Options
Exercisable Number of
Securities
Underlying
Unexercised
Options
Unexercisable Equity
Incentive
Plan
Awards:
Number of
Securities
Underlying
Unexer-
cised
Unearned
Options Option
Exercise
Price Option
Expiration
Date Number
of Shares
or Units
of Stock
That
Have
Not
Vested Market
Value of
Shares or
Units of
Stock
That Have
Not
Vested Equity
Incentive
Plan
Awards:
Number
of
Unearned
Shares,
Units or
Other
Rights
That
Have Not
Vested Equity
Incentive
Plan
Awards:
Market or
Payout
Value of
Unearned
Shares,
Units or
Other
Rights That
Have Not
Vested
(#) (#) (#) ($) (#) ($) (#) ($)
Marcus V. - 33,062 1
$49.54 1/25/2034
Brown 9,638 19,280 2
$54.24 1/26/2033
22,428 11,216 3
$54.80 1/27/2032
14,604 - $47.94 1/28/2031
57,148 - $65.86 1/30/2030 29,696 4
$2,251,551
29,380 5
$2,227,592
6,252 6
$474,027
3,998 7
$303,128
1,930 8
$146,333
Haley R. - 10,532 1
$49.54 1/25/2034
Fisackerly 3,564 7,128 2
$54.24 1/26/2033
5,136 2,568 3
$54.80 1/27/2032
8,202 - $47.94 1/28/2031
8,600 - $65.86 1/30/2030
9,460 4
$717,257
10,864 5
$823,708
1,992 6
$151,033
1,480 7
$112,214
443 8
$33,588
8,106 9
$614,597
Option Awards Stock Awards
(a) (b) (c) (d) (e) (f) (g) (h) (i) (j)
Name Number of
Securities
Underlying
Unexercised
Options
Exercisable Number of
Securities
Underlying
Unexercised
Options
Unexercisable Equity
Incentive
Plan
Awards:
Number of
Securities
Underlying
Unexer-
cised
Unearned
Options Option
Exercise
Price Option
Expiration
Date Number
of Shares
or Units
of Stock
That
Have
Not
Vested Market
Value of
Shares or
Units of
Stock
That Have
Not
Vested Equity
Incentive
Plan
Awards:
Number
of
Unearned
Shares,
Units or
Other
Rights
That
Have Not
Vested Equity
Incentive
Plan
Awards:
Market or
Payout
Value of
Unearned
Shares,
Units or
Other
Rights That
Have Not
Vested
(#) (#) (#) ($) (#) ($) (#) ($)
Kimberly A. - 41,206 1
$49.54 1/25/2034
Fontan 9,154 18,312 2
$54.24 1/26/2033
6,606 3,304 3
$54.80 1/27/2032
10,890 - $47.94 1/28/2031
12,800 - $65.86 1/30/2030
12,000 - $44.60 1/31/2029
5,000 - $39.04 1/25/2028
37,012 4
$2,806,250
27,908 5
$2,115,985
7,794 6
$590,941
3,796 7
$287,813
569 8
$43,142
Laura R. - 13,492 1
$49.54 1/25/2034
Landreaux 2,962 5,926 2
$54.24 1/26/2033
5,136 2,568 3
$54.80 1/27/2032
7,746 - $47.94 1/28/2031
8,600 - $65.86 1/30/2030
10,200 - $44.60 1/31/2029
12,120 4
$918,938
9,032 5
$684,806
2,551 6
$193,417
1,228 7
$93,107
443 8
$33,588
Option Awards Stock Awards
(a) (b) (c) (d) (e) (f) (g) (h) (i) (j)
Name Number of
Securities
Underlying
Unexercised
Options
Exercisable Number of
Securities
Underlying
Unexercised
Options
Unexercisable Equity
Incentive
Plan
Awards:
Number of
Securities
Underlying
Unexer-
cised
Unearned
Options Option
Exercise
Price Option
Expiration
Date Number
of Shares
or Units
of Stock
That
Have
Not
Vested Market
Value of
Shares or
Units of
Stock
That Have
Not
Vested Equity
Incentive
Plan
Awards:
Number
of
Unearned
Shares,
Units or
Other
Rights
That
Have Not
Vested Equity
Incentive
Plan
Awards:
Market or
Payout
Value of
Unearned
Shares,
Units or
Other
Rights That
Have Not
Vested
(#) (#) (#) ($) (#) ($) (#) ($)
Andrew S. - 159,218 1
$49.54 1/25/2034
Marsh 40,542 81,088 2
$54.24 1/26/2033
33,972 16,988 3
$54.80 1/27/2032
58,392 - $47.94 1/28/2031
72,158 - $65.86 1/30/2030
90,364 - $44.60 1/31/2029
98,000 - $39.04 1/25/2028
88,000 - $35.27 1/26/2027
143,004 4
$10,842,563
123,580 5
$9,369,836
30,112 6
$2,283,092
16,810 7
$1,274,534
2,924 8
$221,698
Phillip R. - 12,716 1
$49.54 1/25/2034
May, Jr. 3,610 7,220 2
$54.24 1/26/2033
9,942 4,972 3
$54.80 1/27/2032
10,784 - $47.94 1/28/2031
14,600 - $65.86 1/30/2030
12,400 - $44.60 1/31/2029
11,420 4
$865,864
11,004 5
$834,323
2,406 6
$182,423
1,497 7
$113,503
857 8
$64,978
8,106 9
$614,597
Peter S. - 33,862 1
$49.54 1/25/2034
Norgeot, Jr. 9,514 19,030 2
$54.24 1/26/2033
12,890 6,446 3
$54.80 1/27/2032
7,924 - $47.94 1/28/2031
25,172 - $65.86 1/30/2030
30,412 4
$2,305,838
29,004 5
$2,199,083
6,404 6
$485,551
3,946 7
$299,186
1,109 8
$84,084
Option Awards Stock Awards
(a) (b) (c) (d) (e) (f) (g) (h) (i) (j)
Name Number of
Securities
Underlying
Unexercised
Options
Exercisable Number of
Securities
Underlying
Unexercised
Options
Unexercisable Equity
Incentive
Plan
Awards:
Number of
Securities
Underlying
Unexer-
cised
Unearned
Options Option
Exercise
Price Option
Expiration
Date Number
of Shares
or Units
of Stock
That
Have
Not
Vested Market
Value of
Shares or
Units of
Stock
That Have
Not
Vested Equity
Incentive
Plan
Awards:
Number
of
Unearned
Shares,
Units or
Other
Rights
That
Have Not
Vested Equity
Incentive
Plan
Awards:
Market or
Payout
Value of
Unearned
Shares,
Units or
Other
Rights That
Have Not
Vested
(#) (#) (#) ($) (#) ($) (#) ($)
Deanna D. - 6,750 1
$49.54 1/25/2034
Rodriguez - 4,252 2
$54.24 1/26/2033
- 1,984 3
$54.80 1/27/2032
6,064 4
$459,772
6,480 5
$491,314
1,277 6
$96,822
$66,797
$25,855
Eliecer - 8,470 1
$49.54 1/25/2034
Viamontes 2,616 5,232 2
$54.24 1/26/2033
4,392 2,196 3
$54.80 1/27/2032
7,608 4
$576,839
7,976 5
$604,740
1,602 6
$121,464
1,085 7
$82,265
$28,584
Roderick K. - 35,510 1
$49.54 1/25/2034
West 11
12,156 24,314 2
$54.24 1/26/2033
32,986 16,494 3
$54.80 1/27/2032
53,504 - $47.94 1/28/2031
63,410 - $65.86 1/30/2030
51,128 - $44.60 1/31/2029
28,334 - $39.04 1/25/2028
31,892 4
$2,418,051
37,056 5
$2,809,586
6,716 6
$509,207
5,040 7
$382,133
2,839 8
$215,253
24,016 10
$1,820,893
(1)Consists of options granted under the 2019 OIP; 1/3 of the options vested on January 25, 2025 and 1/3 of the remaining options will vest on each of January 25, 2026 and January 25, 2027.
(2)Consists of options granted under the 2019 OIP; 1/2 of the options vested on January 26, 2025 and the remaining options will vest on January 26, 2026.
(3)Consists of options granted under the 2019 OIP that vested on January 27, 2025.
(4)Consists of 2024-2026 PUP performance units granted under the 2019 OIP that will vest on December 31, 2026 based on two performance measures- Entergy Corporation’s Relative TSR performance and Environmental Stewardship with Relative TSR weighted eighty percent and Environmental Stewardship weighted twenty percent, as described under “What Entergy Corporation Pays and Why - Long-Term Incentive Compensation - 2024 Long-Term Incentive Compensation Mix - Performance Units” in the CD&A.
(5)Consists of 2023-2025 PUP performance units granted under the 2019 OIP that will vest on December 31, 2025 based on two performance measures - Entergy Corporation’s Relative TSR performance and Adjusted FFO/Debt Ratio with Relative TSR weighted eighty percent and Adjusted FFO/Debt Ratio weighted twenty percent.
(6)Consists of shares of restricted stock granted under the 2019 OIP; 1/3 of the shares of restricted stock vested on January 25, 2025 and 1/2 of the remaining shares will vest on each of January 25, 2026 and January 25, 2027.
(7)Consists of shares of restricted stock granted under the 2019 OIP; 1/2 of the shares of restricted stock vested on January 26, 2025 and the remaining shares of restricted stock will vest on January 26, 2026.
(8)Consists of shares of restricted stock granted under the 2019 OIP that vested on January 27, 2025.
(9)Consists of restricted stock units granted under the 2019 OIP which will vest on October 1, 2025.
(10)Consists of restricted stock units granted under the 2019 OIP which were scheduled to vest in two equal installments on each of June 1, 2025, and June 1, 2026, but which were forfeited upon Mr. West’s retirement from the Company on January 31, 2025.
(11)All shares of restricted stock reported for Mr. West in the table above which were unvested at the time of his retirement from the Company on January 31, 2025 were forfeited. The stock options noted in the table above for Mr. West will continue to vest following his retirement, in accordance with the original vesting schedule and expire five years after his retirement date. With respect to the PUP performance units noted in the table above, Mr. West will be eligible for a pro-rated award based on actual performance and full months of service during the performance period. See "Potential Payments Upon Termination or Change in Control" for additional information on the treatment of Mr. West's outstanding equity awards in connection with his retirement from the Company.
2024 Option Exercises and Stock Vested
The following table provides information concerning each exercise of stock options and each vesting of stock during 2024 for the NEOs. All share and per share information in this table has been adjusted to reflect the Stock Split.
Options Awards Stock Awards
(a) (b) (c) (d) (e)
Name Number of Shares Acquired on Exercise Value Realized on Exercise Number of Shares Acquired on Vesting Value Realized on Vesting (1)
(#) ($) (#) ($)
Marcus V. Brown - $- 60,535 $3,964,799
Haley R. Fisackerly 8,268 $247,392 7,631 $575,223
Kimberly A. Fontan - $- 24,003 $1,873,014
Laura R. Landreaux - $- 8,518 $652,494
Andrew S. Marsh 138,000 $3,243,158 105,900 $8,231,875
Phillip R. May, Jr. - $- 13,647 $1,050,900
Peter S. Norgeot, Jr. 68,990 $1,207,091 28,520 $2,202,601
Deanna D. Rodriguez 6,088 $117,714 6,714 $496,257
Eliecer Viamontes 8,664 $104,531 7,661 $584,936
Roderick K. West - $- 58,248 $4,183,770
(1)Represents the value of performance units which vested under the 2022-2024 PUP (payable solely in shares based on the closing stock price of Entergy Corporation on the date of vesting) under the PUP and the vesting of restricted stock and restricted stock units, if applicable, in 2024.
2024 Pension Benefits
The following table shows the present value as of December 31, 2024, of accumulated benefits payable to each of the NEOs, including the number of years of service credited to each NEO, under the retirement plans sponsored by Entergy Corporation, determined using interest rate and mortality rate assumptions set forth in Note 11 to the financial statements. The amount of the SERP benefit provided in this table is the present value of the SERP benefit due at age 65 discounted using the interest rates that we used for financial reporting for the non-qualified pension liability at December 31, 2024, with the exception of Mr. Brown as discussed in the footnotes accompanying the table. Additional information regarding these retirement plans follows this table.
Name Plan Name Number of Years Credited Service Present Value of Accumulated Benefit Payments During 2024
Marcus V. Brown(1)(2)
System Executive Retirement Plan 29.74 $10,484,000 $-
Entergy Retirement Plan 29.74 $1,446,000 $-
Haley R. Fisackerly(1)
System Executive Retirement Plan 29.08 $2,692,700 $-
Entergy Retirement Plan 29.08 $1,187,200 $-
Kimberly A. Fontan Pension Equalization Plan 28.56 $1,468,200 $-
Entergy Retirement Plan 28.56 $793,300 $-
Laura R. Landreaux Pension Equalization Plan 17.48 $511,100 $-
Entergy Retirement Plan 17.48 $477,100 $-
Andrew S. Marsh System Executive Retirement Plan 26.37 $8,236,900 $-
Entergy Retirement Plan 26.37 $748,200 $-
Phillip R. May, Jr. (1)(3)
System Executive Retirement Plan 38.56 $3,092,000 $-
Entergy Retirement Plan 38.56 $1,800,500 $-
Peter S. Norgeot, Jr. Cash Balance Equalization Plan 10.37 $368,500 $-
Cash Balance Plan 10.37 $219,200 $-
Deanna D. Rodriguez(1)
Pension Equalization Plan 30.19 $896,300 $-
Entergy Retirement Plan 30.19 $1,321,700 $-
Eliecer Viamontes Cash Balance Equalization Plan 4.95 $44,700 $-
Cash Balance Plan 4.95 $64,400 $-
Roderick K. West(1)
System Executive Retirement Plan 25.75 $5,991,600 $-
Entergy Retirement Plan 25.75 $871,200 $-
(1)As of December 31, 2024, Mr. Brown, Mr. Fisackerly, Mr. May, Ms. Rodriguez, and Mr. West were retirement eligible.
(2)In 2022, the Company entered into an agreement with Mr. Brown and amended the PEP and the SERP, pursuant to which agreement and amendments if certain contingencies are met, the benefit payable to Mr. Brown (or to his surviving spouse) under the SERP when he separates from employment with the Company is fixed and will be determined as if such separation from employment occurred as of November 30, 2022 (including the use of final average monthly compensation, service and actuarial assumptions applicable to separations as of such date). If Mr. Brown separates from service and the contingencies are not met, then Mr. Brown (or his surviving spouse) will receive the lesser of the previously described benefit amount
under the SERP or the benefit that would have been payable to Mr. Brown under the SERP or the PEP, without regard to the above-described amendments to the SERP and PEP.
(3)Service under the SERP is granted from the date of hire. Service under the qualified Entergy Retirement Plan is granted from the later of the date of hire or the plan participation date. The SERP amounts reflected in the table for Mr. May is calculated based on 30 years of service pursuant to the terms of the SERP.
The tables below contain summaries of the pension benefit plans sponsored by Entergy that the NEOs participated in during 2024. Benefits for the NEOs who participate in these plans are determined using the same formulas as for other eligible employees.
Qualified Retirement Benefits
All of our NEOs, except Messrs. Norgeot and Viamontes participate in the Entergy Retirement Plan, a tax-qualified final average pay defined benefit pension plan sponsored by Entergy. Messrs. Norgeot and Viamontes participate in the Cash Balance Plan, which is a tax-qualified cash balance defined benefit pension plan Entergy sponsors for employees hired after June 30, 2014 and before January 1, 2021. Summaries of these plans are provided below. Benefits for the NEOs are determined using the same formulas as for other eligible employees:
Entergy Retirement Plan Cash Balance Plan(1)
Eligible Named Executive Officers Marcus V. Brown
Haley R. Fisackerly
Andrew S. Marsh
Laura R. Landreaux
Phillip R. May, Jr.
Kimberly A. Fontan
Deanna D. Rodriguez
Roderick K. West Peter S. Norgeot, Jr.
Eliecer Viamontes
Eligibility Non-bargaining employees hired before July 1, 2014 Non-bargaining employees hired on or after July 1, 2014 and before January 1, 2021.
Vesting A participant becomes vested in the Entergy Retirement Plan upon attainment of at least 5 years of vesting service or upon attainment of age 65 while actively employed by an Entergy system company. A participant becomes vested in the Cash Balance Plan upon attainment of at least 3 years of vesting service or upon attainment of age 65 while actively employed by an Entergy system company.
Form of Payment Upon Retirement
Benefits are payable as an annuity. For employees who separate from service on or after January 1, 2018, a single lump sum distribution may be elected by the participant if eligibility criteria are met. Benefits are payable as an annuity or single lump sum distribution.
Entergy Retirement Plan Cash Balance Plan(1)
Retirement Benefit Formula Benefits are calculated as a single life annuity payable at age 65 and generally are equal to 1.5% of a participant’s Final Average Monthly Earnings (“FAME”) multiplied by years of service (not to exceed 40).
Earnings for the purpose of calculating FAME generally includes the employee’s base salary and eligible annual incentive awards subject to limitations imposed by the Internal Revenue Code of 1986, as amended (“Code”), and excludes all other bonuses. Executive annual incentive awards are not eligible for inclusion in earnings under this plan.
FAME is calculated using the employee’s average monthly earnings for the 60 consecutive months in which the employee’s earnings were highest during the 120 month period immediately preceding the employee’s retirement and includes up to 5 eligible annual incentive awards paid during the 60 month period, except that executive annual incentive awards are not included in the FAME calculation.
The normal retirement benefit at age 65 is determined by converting the sum of an employee’s annual pay credits and his or her annual interest credits into an actuarially equivalent annuity.
Pay credits ranging from 4-8% of an employee’s eligible earnings are allocated annually to a notional account for the employee based on an employee’s age and years of service. Earnings for purposes of calculating an employee’s pay credit include the employee’s base salary and annual incentive awards, subject to Code limitations, and exclude all other bonuses. Executive annual incentive program awards are eligible for inclusion in earnings under this plan.
Interest credits are calculated based upon the annual rate of interest on 30-year U.S. Treasury securities, as specified by the Internal Revenue Service, for the month of August preceding the first day of the applicable calendar year subject to a minimum rate of 2.6% and a maximum rate of 9%.
Benefit Timing(2)
Normal retirement age under the plan is 65.
A reduced terminated vested benefit may be commenced as early as age 55. The amount of this benefit is determined by reducing the normal retirement benefit by 7% per year for the first 5 years commencement precedes age 65 and 6% per year for each additional year commencement precedes age 65.
A subsidized early retirement benefit may be commenced by employees who are at least age 55 with 10 years of service at the time they separate from service. The amount of this benefit is determined by reducing the normal retirement benefit by 2% per year for each year that early retirement precedes age 65. Normal retirement age under the plan is 65.
A vested cash balance benefit may be commenced as early as the first day of the month following separation from service. The amount of the benefit is determined in the same manner as the normal retirement benefit described above in the “Retirement Benefit Formula” section.
(1)Effective January 1, 2022, the Entergy Corporation Cash Balance Plan for Non-Bargaining Employees merged into and became Appendix J of the Entergy Corporation Retirement Plan for Non-Bargaining Employees, but retained its eligibility, benefit formula, and all benefits, rights, and features.
(2)As of December 31, 2024, Messrs. Brown, Fisackerly, May, and West and Ms. Rodriguez were eligible for early retirement under the Entergy Retirement Plan.
Non-qualified Retirement Benefits
The NEOs are eligible to participate in certain non-qualified retirement benefit plans that provide retirement income in addition to the benefit provided under the qualified retirement plans, including the PEP, the CBEP, and the SERP. Upon separation from the Company, those NEOs who participate in both the PEP and the SERP will be paid only the greater of the benefit under the PEP or the SERP. Each of the SERP, PEP, and CBEP is an unfunded non-qualified defined benefit pension plan that provides benefits to key management employees. In general, upon
disability, participants in the PEP and the SERP remain eligible for continued service credits until the earliest of recovery, separation from service due to disability, or retirement eligibility. Generally, spouses of participants who die before commencement of benefits may be eligible for a portion of the participant’s accrued benefit under these plans.
Pension Equalization Plan Cash Balance Equalization Plan System Executive Retirement Plan
Eligible Named Executive Officers Marcus V. Brown
Haley R. Fisackerly
Laura R. Landreaux
Andrew S. Marsh
Philip R. May, Jr.
Kimberly A. Fontan
Deanna D. Rodriguez
Roderick K. West
Peter S. Norgeot, Jr.
Eliecer Viamontes
Marcus V. Brown
Haley R. Fisackerly
Andrew S. Marsh
Philip R. May, Jr.
Roderick K. West
Eligibility(1)
Management or highly compensated employees who participate in the Entergy Retirement Plan Management or highly compensated employees who participate in the Cash Balance Plan Certain individuals who became executive officers before July 1, 2014
Form of Payment Upon Retirement Single lump sum distribution Single lump sum distribution Single lump sum distribution
Retirement Benefit Formula Benefits generally are equal to the actuarial present value of the difference between (1) the amount that would have been payable as an annuity under the Entergy Retirement Plan, including executive annual incentive program awards as eligible earnings and without applying the limitations of the Code on pension benefits and earnings that may be considered in calculating tax-qualified pension benefits, and (2) the amount actually payable as an annuity under the Entergy Retirement Plan.
Executive annual incentive awards are taken into account as eligible earnings under this plan.
Benefits generally are equal to the difference between the amount that would have been payable as a lump sum under the Cash Balance Plan, but for the Code limitations on pension benefits and earnings that may be considered in calculating tax-qualified cash balance plan benefits, and the amount actually payable as a lump sum under the Cash Balance Plan. Benefits generally are equal to the actuarial present value of a specified percentage, based on the participant’s years of service and management level of the participant’s “Final Average Monthly Compensation” (which is generally 1/36th of the sum of the participant’s base salary and annual incentive plan award for the three highest years during the last 10 years preceding separation from service), after first being reduced by the value of the participant’s Entergy Retirement Plan benefit.
Pension Equalization Plan Cash Balance Equalization Plan System Executive Retirement Plan
Benefit timing(2)
Payable at age 65
Benefits payable prior to age 65 are subject to the same reduced terminated vested or early retirement reduction factors as benefits payable under the Entergy Retirement Plan as described above.
An employee with supplemental credited service who terminates employment prior to age 65 must receive prior written consent of the Entergy employer in order to receive the portion of their benefit attributable to their supplemental credited service agreement.
Payable upon separation from service subject to six month delay if the participant is a "specified employee" under Code Section 409A.
Payable upon separation from service subject to six month delay required under the Code Section 409A. Payable at age 65
Prior to age 65, vesting is conditioned on the prior written consent of the officer’s Entergy employer.
Benefits payable prior to age 65 are subject to the same reduced terminated vested or subsidized early retirement reduction factors as benefits payable under the Entergy Retirement Plan as described above.
Payable upon separation from service subject to six month delay if the participant is a "specified employee" under Code Section 409A.
(1)The SERP was closed to new executive officers effective July 1, 2014. Effective July 1, 2014, no new grants of supplemental service may be provided to participants in the PEP. Participants in Entergy Corporation’s Cash Balance Plan are not eligible to participate in the PEP and instead may be eligible to participate in the CBEP.
(2)Benefits accrued under the SERP, PEP, and CBEP, if any, will become fully vested if a participant is involuntarily terminated without cause or terminates his or her employment for good reason in connection with a change in control with payment generally made in a lump-sum payment as soon as reasonably practicable following the first day of the month after the termination of employment, unless delayed six months under Code Section 409A.
2024 Non-Qualified Deferred Compensation
As of December 31, 2024, Mr. May had a deferred account balance under a frozen Defined Contribution Restoration Plan. The amount is deemed invested, as chosen by Mr. May, in certain T. Rowe Price investment funds that are also available to participants under the Savings Plan. Mr. May has elected to receive the deferred account balance after he retires. The Defined Contribution Restoration Plan, until it was frozen in 2005, credited eligible employees’ deferral accounts with employer contributions to the extent contributions under the qualified savings plan in which the employee participated were subject to limitations imposed by the Code.
Defined Contribution Restoration Plan
Name Executive Contributions in 2024
Registrant Contributions in 2024
Aggregate Earnings in 2024(1)
Aggregate Withdrawals/Distributions Aggregate Balance at December 31, 2024
(a) (b) (c) (d) (e) (f)
Phillip R. May, Jr. $- $- $1,406 $- $5,029
(1)Amounts in this column are not included in the Summary Compensation Table.
2024 Potential Payments Upon Termination or Change in Control
Entergy has plans and other arrangements that provide compensation to a NEO if his or her employment terminates under specified conditions, including following a change in control of Entergy.
Change in Control
Entergy does not have any plans or agreements that provide for payments or benefits to any of our NEOs solely upon a Change in Control (as defined below). Under the Continuity Plan, executive officers, including each of the continuing NEOs are eligible to receive the cash severance payment and welfare plan benefits described below if their employment is terminated by their Entergy System employer other than for Cause (as defined below) or if they terminate their employment for Good Reason during a period beginning with a potential change in control and ending 24 months following the effective date of a Change in Control (a “Qualifying Termination”). A participant will not be eligible for benefits under the Continuity Plan if such participant: accepts employment with Entergy or any of its subsidiaries; elects to receive the benefits of another severance or separation program; removes, copies, or fails to return any property belonging to Entergy Corporation or any of its subsidiaries or violates the non-compete provision of the Continuity Plan (which generally runs for two years but extends to three years if permissible under applicable law). The Continuity Plan does not include any provisions for the waiver of a breach of any of these restrictive covenants.
In addition, under the 2019 OIP or an applicable equity award agreement issued under the 2019 OIP, upon a Qualifying Termination, our executive officers, including the continuing NEOs, are eligible for the payments and benefits described in the table below under “Performance Units” and “Equity Awards.” Further, in the event of a Qualifying Termination, our executive officers, including the continuing NEOs, are eligible for the benefits described in the table below for “Retirement Benefits” under the terms of the SERP, PEP, and/or CBEP, as applicable.
In the event of a Qualifying Termination, the executive officers, including the continuing NEOs would receive lump sum severance payments and welfare benefits described below. In the event of a Qualifying Termination, all of the NEOs would receive the treatment described below for their retirement benefits and their outstanding performance units and equity awards:
Compensation Element Payment and/or Benefit
Severance(1)
A lump sum severance payment equal to a multiple of the sum of: (a) the participant’s annual base salary as in effect at any time within one year prior to the commencement of a change in control period or, if higher, immediately prior to a circumstance constituting good reason, plus (b) the participant’s annual incentive award, calculated using the average annual target opportunity derived under the annual incentive program for the two calendar years immediately preceding the calendar year in which termination occurs.
Performance Units For outstanding performance units, participants would receive a number of shares of Entergy common stock equal to the greater of (1) the target number of performance units subject to the performance unit agreement or (2) the number of units that would vest under the performance unit agreement calculated based on Company performance through the participant’s termination date, in either case pro-rated based on the portion of the performance period that occurs through the termination date.
Equity Awards All unvested stock options and restricted stock units will vest immediately, and restrictions will lift on restricted shares, upon a Qualifying Termination pursuant to the terms of Entergy’s equity plans.
Retirement Benefits Benefits already accrued under the SERP, PEP, and CBEP, if any, will become fully vested.
Welfare Benefits Participants who are not retirement-eligible would be eligible to receive Entergy-subsidized COBRA benefits for a period of 18 months.
(1) Cash severance payments are capped at 2.99 times the sum of (a) an executive’s annual base salary in effect at any time within one year before commencement of the change in control period, or, if higher, immediately prior to a circumstance constituting Good Reason under the Continuity Plan in effect at any time within one year before commencement of the change in control period or, if higher, immediately prior to a circumstance constituting Good Reason under the Continuity Plan, plus (b) the higher of the executive’s actual annual incentive payment under the annual incentive program for the year immediately preceding the calendar year in which termination occurs or the average of the executive’s target annual incentive award for the two calendar years preceding the year in which termination occurs. Any cash severance payments to be paid under the Continuity Plan in excess of this cap will be forfeited by the participant.
To protect shareholders and Entergy Corporation’s business model, executives are required to comply with non-compete provisions (which generally run for two years but extend to three years if permissible under applicable law) and confidentiality provisions. If an executive discloses non-public data or information concerning Entergy Corporation or any of its subsidiaries or violates his or her non-compete provision, he or she will be required to repay any benefits previously received under the Continuity Plan.
For purposes of the Continuity Plan, the following events are generally defined as:
•Change in Control: (a) the purchase of 30% or more of either Entergy Corporation’s common stock or the combined voting power of Entergy Corporation’s voting securities; (b) the merger or consolidation of Entergy Corporation (unless its Board members constitute at least a majority of the board members of the surviving entity); (c) the liquidation, dissolution, or sale of all or substantially all of Entergy Corporation’s assets; or (d) a change in the composition of Entergy Corporation’s Board such that, during any two-year period, the individuals serving at the beginning of the period no longer constitute a majority of Entergy Corporation’s Board at the end of the period.
•Potential Change in Control: (a) Entergy Corporation or an affiliate enters into an agreement, the consummation of which would constitute a Change in Control; (b) the Entergy Corporation Board adopts resolutions determining that, for purposes of the Continuity Plan, a potential Change in Control has occurred; (c) a System Company or other person or entity publicly announces an intention to take actions that would constitute a Change in Control; or (d) any person or entity becomes the beneficial owner (directly or indirectly) of Entergy Corporation’s outstanding shares of common stock constituting 20% or more of the voting power or value of the Entergy Corporation’s outstanding common stock.
•Cause: The participant’s (a) willful and continuous failure to perform substantially his or her duties after written demand for performance; (b) engagement in conduct that is materially injurious to Entergy Corporation or any of its subsidiaries; (c) conviction or guilty or nolo contendere plea to a felony or other crime that materially and adversely affects the participant’s ability to perform his or her duties or Entergy Corporation’s reputation; (d) material violation of any agreement with Entergy Corporation or any of its subsidiaries; or (e) disclosure of any of Entergy Corporation’s confidential information without authorization.
•Good Reason: The participant’s (a) nature or status of duties and responsibilities is substantially altered or reduced; (b) salary is reduced by 5% or more; (c) primary work location is relocated outside the continental United States; (d) compensation plans are discontinued without an equitable replacement; (e) benefits or number of vacation days are substantially reduced; or (f) employment is terminated by an Entergy employer for reasons other than in accordance with the Continuity Plan.
Other Termination Events
For termination events, other than in connection with a Change in Control, the executive officers, including the continuing NEOs, generally will receive the benefits set forth below:
Termination Event Compensation Element
Severance Annual Incentive Stock Options Restricted Stock(2)
Performance Units
Voluntary Resignation (Not Retirement)
None Forfeited(1)
Unvested options are forfeited. Vested options expire on the earlier of (i) 90 days from the last day of active employment and (ii) the option’s normal expiration date. Forfeited Forfeited(3)
Termination for Cause None Forfeited Forfeited Forfeited Forfeited
Retirement None Pro-rated based on number of days employed during the performance period Unvested stock options continue to vest following retirement, in accordance with the original vesting schedule and expire the earlier of (i) five years from the retirement date and (ii) the option’s normal expiration date. Forfeited Officers with a minimum of 12 months of participation are eligible for a pro-rated award based on actual performance and full months of service during the performance period
Death/Disability None Pro-rated based on number of days employed during the performance period
Unvested stock options vest on the termination date and expire on the earlier of (i) five years from the termination date and (ii) the option’s normal expiration date Fully Vest Officers are eligible for pro-rated award based on actual performance and full months of service during the performance period
(1)If an officer resigns after the completion of an annual incentive program performance period, but before the payment date of the annual incentive payment, he or she may receive, at Entergy’s discretion, an annual incentive payment.
(2)This column refers solely to restricted stock awards. Certain officers are occasionally granted restricted stock units for retention purposes, to offset forfeited compensation from a previous employer or for other limited purposes. The treatment of restricted stock units depends on the terms of the individual restricted stock unit agreement, which terms can vary. The standard off-cycle restricted stock unit agreement approved by the Talent and Compensation Committee provides that the units are forfeited if employment is terminated for any reason before the vesting date, except in the case of a termination other than for cause or voluntary termination for Good Reason during a Change in Control period. However, individual restricted stock unit agreements may provide for accelerated vesting in certain events, such as death or disability. Messrs. Fisackerly and May each have outstanding restricted stock units, the treatment of which upon various events of termination is disclosed in connection with the table below. Mr. West had outstanding restricted stock units as of December 31, 2024, which were forfeited when he retired from the Company on January 31, 2025.
(3)If an officer resigns after the completion of a PUP performance period, he or she will receive a payout under the PUP based on actual performance during the performance period.
Aggregate Termination Payments
The tables below reflect the amount of compensation each of the NEOs would have received if his or her employment had been terminated as of December 31, 2024 under the various scenarios described above. For purposes of these tables, a stock price of $75.82 was used, which was the closing market price of Entergy Corporation stock on December 31, 2024, the last trading day of the year. All share and per share information in this table has been adjusted to reflect the Stock Split.
Benefits and Payments Upon
Termination
Voluntary
Resignation
For
Cause
Termination for
Good Reason or
Not for Cause
Retirement Disability Death Termination
Related to a
Change in
Control
Marcus V. Brown(1)
Severance Payment $- $- $- $- $- $- $4,275,471
Performance Units(3)
$- $- $- $1,117,890 $1,117,890 $1,117,890 $1,117,890
Stock Options(4)
$- $- $- $- $1,520,691 $1,520,691 $1,520,691
Restricted Stock $- $- $- $- $923,622 $923,622 $923,622
Welfare Benefits(5)
$- $- $- $- $- $- $-
Haley R. Fisackerly(1)
Severance Payment $- $- $- $- $- $- $1,419,859
Performance Units(3)
$- $- $- $394,188 $394,188 $394,188 $394,188
Stock Options(4)
$- $- $- $- $484,582 $484,582 $484,582
Restricted Stock $- $- $- $- $296,952 $296,952 $296,952
Welfare Benefits(5)
$- $- $- $- $- $- $-
Unvested Restricted Stock Units(7)
$- $- $- $- $- $- $614,597
Kimberly A. Fontan(2)
Severance Payment $- $- $- $- $- $- $3,707,813
Performance Units(3)
$- $- $- $- $1,173,087 $1,173,087 $1,173,087
Stock Options $- $- $- $- $1,547,517 $1,547,517 $1,547,517
Restricted Stock $- $- $- $- $922,011 $922,011 $922,011
Welfare Benefits(6)
$- $- $- $- $- $- $32,661
Laura R. Landreaux(2)
Severance Payment $- $- $- $- $- $- $1,336,047
Performance Units(3)
$- $- $- $- $381,450 $381,450 $381,450
Stock Options $- $- $- $- $536,432 $536,432 $536,432
Restricted Stock $- $- $- $- $320,240 $320,240 $320,240
Welfare Benefits(6)
$- $- $- $- $- $- $32,661
Andrew S. Marsh(2)
Severance Payment $- $- $- $- $- $- $8,250,000
Performance Units(3)
$- $- $- $- $4,930,423 $4,930,423 $4,930,423
Stock Options $- $- $- $- $6,291,216 $6,291,216 $6,291,216
Restricted Stock $- $- $- $- $3,779,466 $3,779,466 $3,779,466
Welfare Benefits(6)
$- $- $- $- $- $- $32,661
Benefits and Payments Upon
Termination
Voluntary
Resignation
For
Cause
Termination for
Good Reason or
Not for Cause
Retirement Disability Death Termination
Related to a
Change in
Control
Phillip R. May, Jr.(1)
Severance Payment $- $- $- $- $- $- $1,513,162
Performance Units(3)
$- $- $- $422,469 $422,469 $422,469 $422,469
Stock Options(4)
$- $- $- $- $594,495 $594,495 $594,495
Restricted Stock $- $- $- $- $361,010 $361,010 $361,010
Welfare Benefits(5)
$- $- $- $- $- $- $-
Unvested Restricted Stock Units(8)
$- $- $- $- $- $- $614,597
Peter S. Norgeot(1)
Severance Payment $- $- $- $- $- $- $3,516,240
Performance Units(3)
$- $- $- $1,117,360 $1,117,360 $1,117,360 $1,117,360
Stock Options(4)
$- $- $- $- $1,436,055 $1,436,055 $1,436,055
Restricted Stock $- $- $- $- $868,907 $868,907 $868,907
Welfare Benefits(6)
$- $- $- $- $- $- $24,354
Deanna D. Rodriguez(1)
Severance Payment $- $- $- $- $- $- $1,127,771
Performance Units(3)
$- $- $- $240,425 $240,425 $240,425 $240,425
Stock Options(4)
$- $- $- $- $310,852 $310,852 $310,852
Restricted Stock $- $- $- $- $189,650 $189,650 $189,650
Welfare Benefits(5)
$- $- $- $- $- $- $-
Eliecer Viamontes(2)
Severance Payment $- $- $- $- $- $- $1,296,039
Performance Units(3)
$- $- $- $- $297,745 $297,745 $297,745
Stock Options $- $- $- $- $381,659 $381,659 $381,659
Restricted Stock $- $- $- $- $232,429 $232,429 $232,429
Welfare Benefits(6)
$- $- $- $- $- $- $32,661
Roderick K. West(1)
Severance Payment $- $- $- $- $- $- $4,513,068
Performance Units(3)
$- $- $- $1,339,588 $1,339,588 $1,339,588 $1,339,588
Stock Options(4)
$- $- $- $- $1,804,603 $1,804,603 $1,804,603
Restricted Stock $- $- $- $- $1,106,680 $1,106,680 $1,106,680
Welfare Benefits(5)
$- $- $- $- $- $- -
Unvested Restricted Stock Units(9)
$- $- $- $- $- $- $1,820,893
(1)As of December 31, 2024, Mr. Brown, Mr. Fisackerly, Mr. May, Mr. Norgeot, Mr. West, and Ms. Rodriguez were retirement eligible and would retire rather than voluntarily resign, and in addition to the payments and benefits in the table, each (except for Mr. Norgeot) also would be entitled to receive their vested pension benefits under the Entergy Retirement Plan and their benefit under the PEP or the SERP, to the extent applicable, the latter of which requires the prior written consent of the officer’s Entergy employer to separate prior to age 65. As previously discussed, Ms. Rodriguez does not participate in the SERP. Mr. Norgeot would also be entitled to receive his vested pension benefit under the Cash Balance Plan and the CBEP. For a description of these benefits, see “2024 Pension Benefits.” Mr. West retired from the Company on January 31, 2025.
(2)See “2024 Pension Benefits” for a description of the pension benefits Ms. Fontan, Ms. Landreaux, Mr. Marsh, and Mr. Viamontes may receive upon the occurrence of certain termination events since they are not yet retirement eligible.
(3)For purposes of the table, in the event of a qualifying termination related to a change in control, each NEO would receive a number of performance units for the 2023-2025 PUP performance period and a number of performance units for the 2024-2026 PUP performance period, calculated as follows:
The greater of (1) the target number of performance units subject to the performance unit agreements or (2) the number of performance units that would vest under the performance unit agreements calculated based on Entergy Corporation’s actual performance through the NEO’s termination date, in either case pro-rated based on the portion of the performance period that occurs through the termination date.
For purposes of the table, the values of the performance unit awards for the open PUP performance periods for each NEO were calculated as follows, based on the assumption that the target number of performance units was the greater number:
Mr. Brown’s:
2023-2025 PUP Performance Period: 9,794 (24/36x14,690) performance units at target, assuming a stock price of $75.82 = $742,581
2024-2026 PUP Performance Period: 4,950 (12/36x14,848) performance units at target, assuming a stock price of $75.82 = $375,309
Total: $1,117,890
Mr. Fisackerly’s:
2023 - 2025 PUP Performance Period: 3,622 (24/36x5,432) performance units at target, assuming a stock price of $75.82 = $274,620
2024 - 2026 PUP Performance Period: 1,577 (12/36x4,730) performance units at target, assuming a stock price of $75.82 = $119,568
Total: $394,188
Ms. Fontan’s:
2023-2025 PUP Performance Period: 9,303 (24/36x13,954) performance units at target, assuming a stock price of $75.82 = $705,353
2024-2026 PUP Performance Period: 6,169 (12/36x18,506) performance units at target, assuming a stock price of $75.82 = $467,734
Total: $1,173,087
Ms. Landreaux’s:
2023 - 2025 PUP Performance Period: 3,011 (24/36x4,516) performance units at target, assuming a stock price of $75.82 = $228,294
2024 - 2026 PUP Performance Period: 2,020 (12/36x6,060) performance units at target, assuming a stock price of $75.82 = $153,156
Total: $381,450
Mr. Marsh’s:
2023-2025 PUP Performance Period: 41,194 (24/36x61,790) performance units at target, assuming a stock price of $75.82 = 3,123,329
2024-2026 PUP Performance Period: 23,834 (12/36x71,502) performance units at target, assuming a stock price of $75.82 = $1,807,094
Total: $4,930,423
Mr. May’s:
2023 - 2025 PUP Performance Period: 3,668 (24/36x5,502) performance units at target, assuming a stock price of $75.82 = $278,108
2024 - 2026 PUP Performance Period: 1,904 (12/36x5,710) performance units at target, assuming a stock price of $75.82 = $144,361
Total: $422,469
Mr. Norgeot’s:
2023-2025 PUP Performance Period: 9,668 (24/36x14,502) performance units at target, assuming a stock price of $75.82 = $733,028
2024-2026 PUP Performance Period: 5,069 (12/36x15,206) performance units at target, assuming a stock price of $75.82 = $384,332
Total: $1,117,360
Ms. Rodriguez’s:
2023 - 2025 PUP Performance Period: 2,160 (24/36x3,240) performance units at target, assuming a stock price of $75.82 = $163,771
2024 - 2026 PUP Performance Period: 1,011 (12/36x3,032) performance units at target, assuming a stock price of $75.82 = $76,654
Total: $240,425
Mr. Viamontes’:
2023 - 2025 PUP Performance Period: 2,659 (24/36x3,988) performance units at target, assuming a stock price of $75.82 = $201,605
2024 - 2026 PUP Performance Period: 1,268 (12/36x3,804) performance units at target, assuming a stock price of $75.82 = $96,140
Total: $297,745
Mr. West’s:
2023-2025 PUP Performance Period: 12,352 (24/36x18,528) performance units at target, assuming a stock price of $75.82 = $936,529
2024-2026 PUP Performance Period: 5,316 (12/36x15,946) performance units at target, assuming a stock price of $75.82 = $403,059
Total: $1,339,588
In the event of retirement, in the case of Mr. Brown, Mr. Fisackerly, Mr. May, Mr. Norgeot, Mr. West, or Ms. Rodriguez each would receive a prorated portion of the applicable achievement level of PUP performance units for each open PUP performance period, based on his or her full months of participation in such PUP performance period, provided he or she has completed a minimum of 12 months of full-time employment in the applicable PUP performance period. For purposes of calculating for the above table the number of performance units Mr. Brown, Mr. Fisackerly, Mr. May, Mr. West, and Ms. Rodriguez would receive in the event of retirement, it is assumed the achievement levels for the 2023-2025 PUP Performance Period and the 2024-2026 PUP performance period are at target. The resulting number of performance units and values are the same as calculated above for a qualifying termination related to a change in control. In connection with his retirement on January 31, 2025, Mr. West will be eligible for a pro-rated award under the 2023-2025 PUP and 2024-2026 PUP based on actual performance and his full months of service during the respective performance period.
In the event of death or disability of any NEO, the NEO or his or her estate would receive a prorated portion of the applicable achievement level of PUP performance units for each open PUP performance period, based on his or her full months of participation in such PUP performance period, with no required minimum amount of full-time employment in the applicable PUP performance period.
(4)As discussed previously, upon retirement, unvested stock options would continue to vest for each of Mr. Brown, Mr. Fisackerly, Mr. May, Mr. Norgeot, Mr. West, and Ms. Rodriguez in accordance with the original vesting schedule and expire the earlier of (i) five years from the retirement date and (ii) the option’s normal expiration date. See “2024 Outstanding Equity Awards at Fiscal Year-End” for information regarding each of these NEOs’ unvested stock options as of December 31, 2024. Assuming a stock price as of December 31, 2024 on the vesting dates of each these NEOs’ unvested stock options, the in-the-money value of their stock options in the event of retirement (including stock options that remain unvested) would be the same as is set forth in the table above within the Death, Disability and Termination Related to a Change in Control columns.
(5)Upon retirement, Mr. Brown, Mr. Fisackerly, Mr. May, Mr. West, and Ms. Rodriguez would be eligible for retiree medical and dental benefits, the same as all other retirees who are eligible for post-retirement benefits.
(6)Pursuant to the Executive Continuity Plan, in the event of a termination related to a Change in Control Ms. Fontan, Ms. Landreaux, Mr. Marsh, Mr. Norgeot and Mr. Viamontes would be eligible to receive Entergy-subsidized COBRA benefits for 18 months.
(7)Mr. Fisackerly’s 8,106 restricted stock units are scheduled to vest 100% on October 1, 2025. In the event of a Change in Control, the unvested restricted stock units will fully vest upon Mr. Fisackerly’s Qualifying Termination during a change in control period. Pursuant to his restricted stock unit agreement, Mr. Fisackerly is subject to certain restrictions on his ability to compete with Entergy and its affiliates during and for 12 months after his employment with Entergy, or to solicit its employees or customers during and for 24 months after his employment with Entergy. In addition, the restricted stock unit agreement limits Mr. Fisackerly’s ability to disparage Entergy and its affiliates. In the event of a breach of these restrictions, other than following certain constructive terminations of his employment, Mr. Fisackerly must repay to Entergy any shares of Entergy stock paid to him in respect of the restricted stock units and any amounts he received upon the sale or transfer of any such shares.
(8)Mr. May’s 8,106 restricted stock units are scheduled to vest 100% on October 1, 2025. In the event of a Change in Control, the unvested restricted stock units will fully vest upon Mr. May’s Qualifying Termination during a change in control period. Pursuant to his restricted stock unit agreement, Mr. May is subject to certain restrictions on his ability to compete with Entergy and its affiliates during and for 12 months after his employment with Entergy, or to solicit its employees or customers during and for 24 months after his employment with Entergy. In addition, the restricted stock unit agreement limits Mr. May’s ability to disparage Entergy and its affiliates. In the event of a breach of these restrictions, other than following certain constructive terminations of his employment, Mr. May must repay to Entergy any shares of Entergy stock paid to him in respect of the restricted stock units and any amounts he received upon the sale or transfer of any such shares.
(9)Mr. West’s 24,016 unvested restricted stock units were scheduled to vest in two equal installments on each of June 1, 2025, and June 1, 2026; however, they were forfeited as a result of his retirement from the Company on January 31, 2025 in accordance with the terms of the applicable grant agreement. In the event of a Change in Control, the unvested restricted stock units would have fully vested upon Mr. West’s Qualifying Termination during the change in control period. Pursuant to his restricted stock unit agreement, Mr. West is subject to certain restrictions on his ability to compete with Entergy and its affiliates during and for 12 months after his employment with Entergy, or to solicit its employees or customers during and for 24 months after his employment with Entergy. In addition, the restricted stock unit agreement limits Mr. West’s ability to disparage Entergy and its affiliates. In the event of a breach of these restrictions, other than following certain constructive terminations of his employment, Mr. West must repay to Entergy any shares of Entergy stock paid to him in respect of the restricted stock units and any amounts he received upon the sale or transfer of any such shares.
Pay Ratio
As required by Section 953(b) of the Dodd-Frank Act, the following disclosure is being provided about the relationship of the annual total compensation of the employees of each of the Utility operating companies to the annual total compensation of their respective Presidents and Chief Executive Officers. The pay ratio estimate for each of the Utility operating companies has been calculated in a manner consistent with Item 402(u) of Regulation S-K.
Identification of Median Employee
For each of the Utility operating companies, October 18, 2024 was selected as the date on which to determine the median employee. This date is different from the date used in the prior year; however, the methodology used to determine the date is consistent with that used in the prior year. Both dates correspond to the first day of the three month period prior to fiscal year-end for which information can be obtained about employees and all subsidiaries have the same number of pay cycles. To identify the median employee from each of the Utility operating companies’ employee population base, all compensation included in Box 5 of Form W-2 was considered with all before-tax deductions added back to this compensation (“Box 5 Compensation”). For purposes of determining the median employee of each Utility operating company, Box 5 Compensation was selected as it is believed to be representative of the compensation received by the employees of each respective Utility operating company and is readily available. The calculation of annual total compensation of the median employee for each Utility operating company is the same calculation used to determine total compensation for purposes of the 2024 Summary Compensation Table with respect to each of the NEOs.
Entergy Arkansas Ratio
For 2024,
•The median of the annual total compensation of all of Entergy Arkansas’s employees, other than Ms. Landreaux, was $141,875.
•Ms. Landreaux’s annual total compensation, as reported in the Total column of the 2024 Summary Compensation Table, was $1,479,975.
•Based on this information, the ratio of the annual total compensation of Mrs. Landreaux to the median of the annual total compensation of all employees is estimated to be 10:1.
Entergy Louisiana Ratio
For 2024,
•The median of the annual total compensation of all of Entergy Louisiana’s employees, other than Mr. May, was $159,265.
•Mr. May’s annual total compensation, as reported in the Total column of the 2024 Summary Compensation Table, was $1,676,245.
•Based on this information, the ratio of the annual total compensation of Mr. May to the median of the annual total compensation of all employees is estimated to be 11:1.
Entergy Mississippi Ratio
For 2024,
•The median of the annual total compensation of all of Entergy Mississippi’s employees, other than Mr. Fisackerly, was $146,332.
•Mr. Fisackerly’s annual total compensation, as reported in the Total column of the 2024 Summary Compensation Table, was $1,698,882.
•Based on this information, the ratio of the annual total compensation of Mr. Fisackerly to the median of the annual total compensation of all employees is estimated to be 12:1.
Entergy New Orleans Ratio
For 2024,
•The median of the annual total compensation of all of Entergy New Orleans’s employees, other than Ms. Rodriguez, was $129,518.
•Ms. Rodriguez’s annual total compensation, as reported in the Total column of the 2024 Summary Compensation Table, was $1,163,884.
•Based on this information, the ratio of the annual total compensation of Ms. Rodriguez to the median of the annual total compensation of all employees is estimated to be 9:1.
Entergy Texas Ratio
For 2024,
•The median of the annual total compensation of all of Entergy Texas’s employees, other than Mr. Viamontes, was $162,544.
•Mr. Viamontes’ annual total compensation, as reported in the Total column of the 2024 Summary Compensation Table, was $1,156,622.
•Based on this information, the ratio of the annual total compensation of Mr. Viamontes to the median of the annual total compensation of all employees is estimated to be 7:1.
Policies and Practices Related to the Timing of Grants of Certain Equity Awards
The Talent and Compensation Committee and senior management monitor the Company’s equity grant practices to evaluate whether such policies comply with governing regulations and are consistent with good corporate practices. When making regular annual equity grants, including stock options, the Talent and Compensation Committee’s practice is to approve them at its meeting in late January or in the first week of February of each year, which is near the beginning of the Company’s fiscal year, as part of the annual compensation review. In addition, the Talent and Compensation Committee may make grants at other times during the year for new hires or for other reasons, including, for example, job promotions or for retention purposes. Because the Talent and Compensation Committee’s regular meeting schedule is generally determined in the prior fiscal year and, as noted above, the Company generally makes annual equity awards to our NEOs at approximately the same time each year, the proximity of any awards to other significant corporate events is coincidental. The Company does not time its equity awards to take advantage of the release of earnings or other major announcements by the Company or market conditions.
During 2024, no stock option grants were made to any of our NEOs during any period beginning four business days before the filing or furnishing of a periodic report or current report and ending one business day after the filing or furnishing of any such report with the SEC.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Item 12. Security Ownership of Certain Beneficial Owners and Management
Entergy Corporation owns 100% of the outstanding common stock of Entergy Texas and indirectly 100% of the outstanding common membership interests of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. The information with respect to (i) the beneficial ownership of Entergy Corporation’s directors and NEOs is included under the heading “Entergy Share Ownership - Directors and Executive Officers;” and (ii) persons known by Entergy Corporation to be beneficial owners of more than 5% of Entergy Corporation’s outstanding common stock is included under the heading “Entergy Share Ownership - Beneficial Owners of More Than Five Percent of Entergy Common Stock” in the 2025 Entergy Proxy Statement, which information is incorporated herein by reference. The registrants know of no contractual arrangements that may, at a subsequent date, result in a change in control of any of the registrants.
The following table sets forth the beneficial ownership of common stock of Entergy Corporation and stock-based units as of January 31, 2025 for the directors and NEOs of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas. Unless otherwise noted, each person had sole voting and investment power over the number of shares of common stock and stock-based units of Entergy Corporation set forth across from his or her name.
Name Shares (1)
Options Exercisable Within 60 Days Stock Units (2)
Entergy Arkansas
Marcus V. Brown** 51,412 135,694 -
Kimberly A. Fontan*** 44,785 82,644 -
Laura R. Landreaux*** 22,675 44,670 -
Andrew S. Marsh** 348,704 592,032 -
Peter S. Norgeot, Jr. ***
82,320 82,746 -
All directors and executive officers as a group (7 persons)
584,827 972,416 -
Entergy Louisiana
Marcus V. Brown** 51,412 135,694 -
Kimberly A. Fontan*** 44,785 82,644 -
Andrew S. Marsh** 348,704 592,032 -
Phillip R. May, Jr.*** 54,853 64,156 31
Peter S. Norgeot, Jr. ***
82,320 82,746 -
All directors and executive officers as a group (7 persons)
617,005 991,902 31
Entergy Mississippi
Marcus V. Brown** 51,412 135,694 -
Haley R. Fisackerly*** 16,375 35,144 -
Kimberly A. Fontan*** 44,785 82,644 -
Andrew S. Marsh** 348,704 592,032 -
Peter S. Norgeot, Jr. ***
82,320 82,746 -
All directors and executive officers as a group (6 persons)
552,120 941,730 -
Entergy New Orleans
Marcus V. Brown** 51,412 135,694 -
Kimberly A. Fontan***
44,785 82,644 -
Andrew S. Marsh** 348,704 592,032 -
Peter S. Norgeot, Jr. ***
82,320 82,746 -
Deanna D. Rodriguez*** 14,406 6,360 -
All directors and executive officers as a group (6 persons)
550,151 912,946 -
Name Shares (1)
Options Exercisable Within 60 Days Stock Units (2)
Entergy Texas
Marcus V. Brown** 51,412 135,694 -
Kimberly A. Fontan*** 44,785 82,644 -
Andrew S. Marsh** 348,704 592,032 -
Peter S. Norgeot, Jr. ***
82,320 82,746 -
Eliecer Viamontes*** 18,686 14,642 -
All directors and executive officers as a group (6 persons)
554,431 921,228 -
* Director of the respective company
** NEO of the respective company
*** Director and NEO of the respective company
(1)The number of shares of Entergy Corporation common stock owned by each individual and by all non-employee directors and executive officers as a group does not exceed one percent of the outstanding shares of Entergy Corporation common stock. This column also includes shares of Entergy Corporation common stock held in the Entergy Savings Plan (401(k)) by Messrs. Brown, Fisackerly, Marsh, May, and Viamontes and Mses. Fontan and Rodriguez. For Mr. Viamontes, this column includes shares of Entergy Corporation common stock held by him indirectly through his spouse.
(2)Represents the balances of phantom units each director or executive holds under the defined contribution restoration plan and the deferral provisions of Entergy Corporation’s equity ownership plans. These units will be paid out in either Entergy Corporation common stock or cash equivalent to the value of one share of Entergy Corporation common stock per unit on the date of payout, including accrued dividends. The deferral period is determined by the individual and is at least two years from the award of the bonus.
Equity Compensation Plan Information
The following table summarizes the equity compensation plan information as of December 31, 2024. Information is included for equity compensation plans approved by the shareholders. There are no shares authorized for issuance under equity compensation plans not approved by the shareholders. On December 12, 2024, Entergy effected a two-for-one forward stock split of Entergy Corporation common stock and a proportionate increase in the number of authorized shares of its common stock (“Stock Split”). Shares began trading on a Stock Split-adjusted basis at market open on December 13, 2024. The amounts reported in the table below have been retroactively adjusted to reflect the Stock Split.
Plan Category Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants, and Rights (a) Weighted-Average Exercise Price of Outstanding Options, Warrants, and Rights
(b)(2)
Number of Securities Remaining Available for Future Issuance under Equity Compensation Plans (excluding securities reflected in column (a))
(c)
Equity compensation plans approved by security holders (1)
3,226,456 $53.38 13,966,025
Equity compensation plans not approved by security holders - - -
Total 3,226,456 $53.38 13,966,025
(1)Includes the 2011 Equity Ownership Plan, the 2015 EOP, and the 2019 OIP (collectively, the “Plans”). The 2011 Equity Ownership Plan was approved by Entergy Corporation shareholders on May 6, 2011 and only applies to awards granted between May 6, 2011 and May 7, 2015. The 2015 EOP was approved by Entergy Corporation shareholders on May 8, 2015 and only applies to awards granted between May 8, 2015 and May 3, 2019. The Entergy Corporation shareholders approved the 2019 OIP on May 3, 2019 and approved the issuance of 14,600,000 shares of Entergy Corporation common stock from the 2019 OIP for equity-based incentive awards. On May 5, 2023, the Entergy Corporation shareholders approved Amendment No. 1 to the 2019 OIP, which increased the aggregate number of shares available for equity-based incentive awards under the 2019 OIP by 9,800,000 shares of Entergy Corporation common stock, and extended the term of the 2019 OIP by approximately four years to January 27, 2033. The Plans are administered by the Talent and Compensation Committee of the Entergy Corporation Board of Directors (other than with respect to awards granted to non-employee directors, which awards are administered by the entire Board of Directors). Eligibility under the Plans is limited to the non-employee directors and to the officers and employees of an Entergy employer or an affiliate of Entergy Corporation. The Plans provide for the issuance of stock options, restricted stock, equity awards (units whose value is related to the value of shares of the common stock but do not represent actual shares of common stock), performance awards (performance shares or units valued by reference to shares of common stock or performance units valued by reference to financial measures or property other than common stock), restricted stock unit awards, and other stock-based awards.
(2)The weighted-average exercise price reported in this column does not include outstanding performance awards.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13. Certain Relationships and Related Party Transactions and Director Independence
The additional information required by this item will be set forth under Director Independence and Review and Approval of Related Party Transactions in the 2025 Entergy Proxy Statement, to be filed in connection with the Annual Meeting of Shareholders to be held May 2, 2025, which is incorporated herein by reference.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14. Principal Accountant Fees and Services (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Aggregate fees billed to Entergy Corporation (consolidated), Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy for the years ended December 31, 2024 and 2023 by Deloitte & Touche LLP (PCAOB ID No. 34) were as follows:
2024 2023
Entergy Corporation (consolidated)
Audit Fees (a) $10,675,300 $9,850,000
Audit-Related Fees (b) 1,475,000 2,235,668
Total Audit and Audit-Related Fees
12,150,300 12,085,668
Tax Fees - -
All Other Fees (c) 151,895 1,895
Total Fees (d) $12,302,195 $12,087,563
Entergy Arkansas
Audit Fees (a) $1,251,629 $1,221,014
Audit-Related Fees (b) - -
Total Audit and Audit-Related Fees
1,251,629 1,221,014
Tax Fees - -
All Other Fees - -
Total Fees (d) $1,251,629 $1,221,014
Entergy Louisiana
Audit Fees (a) $2,487,155 $2,172,029
Audit-Related Fees (b) 625,000 1,209,547
Total Audit and Audit-Related Fees
3,112,155 3,381,576
Tax Fees - -
All Other Fees - -
Total Fees (d) $3,112,155 $3,381,576
Entergy Mississippi
Audit Fees (a) $1,251,629 $1,246,014
Audit-Related Fees (b) 150,000 -
Total Audit and Audit-Related Fees
1,401,629 1,246,014
Tax Fees - -
All Other Fees - -
Total Fees (d) $1,401,629 $1,246,014
Entergy New Orleans
Audit Fees (a) $1,042,729 $1,121,014
Audit-Related Fees (b) 210,000 576,121
Total Audit and Audit-Related Fees
1,252,729 1,697,135
Tax Fees - -
All Other Fees - -
Total Fees (d) $1,252,729 $1,697,135
2024 2023
Entergy Texas
Audit Fees (a) $1,341,629 $1,296,014
Audit-Related Fees (b) - -
Total Audit and Audit-Related Fees
1,341,629 1,296,014
Tax Fees - -
All Other Fees - -
Total Fees (d) $1,341,629 $1,296,014
System Energy
Audit Fees (a) $1,176,629 $1,136,014
Audit-Related Fees (b) - -
Total Audit and Audit-Related Fees
1,176,629 1,136,014
Tax Fees - -
All Other Fees - -
Total Fees (d) $1,176,629 $1,136,014
(a)Audit Fees include fees for the audit of the registrant’s annual financial statements and internal control over financial reporting, reviews of financial statements including in the registrant’s quarterly reports, services that are normally provided in connection with statutory and regulatory filings or engagements, and services associated with securities filings, such as comfort letters and consents.
(b)Audit-Related Fees includes fees for employee benefit plan audits, accounting due diligence services related to the gas business in 2023, agreed upon procedures for storm securitizations in 2023, and other attestation services.
(c)Includes the fees for the SEC climate-related disclosure rules readiness assessment and a training provided in 2024, as well as the license fee for the accounting research tool in 2024 and 2023.
(d)100% of fees in 2024 and 2023 were pre-approved by the Entergy Corporation Audit Committee in accordance with the policy described below.
Entergy Audit Committee Guidelines for Pre-approval of Independent Auditor Services
The Audit Committee has adopted the following guidelines regarding the engagement of Entergy’s independent auditor to perform services for Entergy:
1.The independent auditor will provide the Audit Committee, for approval, an annual engagement letter outlining the scope of services proposed to be performed during the fiscal year, including audit services and other permissible non-audit services (e.g. audit-related services, tax services, and all other services).
2.For other permissible services not included in the engagement letter, Entergy management will submit a description of the proposed service, including a budget estimate, to the Audit Committee for pre-approval. Management and the independent auditor must agree that the requested service is consistent with the SEC’s rules on auditor independence prior to submission to the Audit Committee. The Audit Committee, at its discretion, will pre-approve permissible services and has established the following additional guidelines for permissible non-audit services provided by the independent auditor:
a.Aggregate non-audit service fees are targeted at fifty percent or less of the approved audit service fee.
b.All other services should only be provided by the independent auditor if it is a highly qualified provider of that service or if the Audit Committee pre-approves the independent audit firm to provide the service.
3.The Audit Committee will be informed quarterly as to the status of pre-approved services actually provided by the independent auditor.
4.To ensure prompt handling of unexpected matters, the Audit Committee delegates to the Audit Committee Chair or its designee the authority to approve permissible services and fees. The Audit Committee Chair or designee will report action taken to the Audit Committee at the next scheduled Audit Committee meeting.
5.The Vice President and General Auditor will be responsible for tracking all independent auditor fees and will report quarterly to the Audit Committee.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15. Exhibits and Financial Statement Schedules
(a)1. Financial Statements and Independent Auditors’ Reports for Entergy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are listed in the Table of Contents.
(a)2. Financial Statement Schedules
Reports of Independent Registered Public Accounting Firm (see page 554)
Financial Statement Schedules are listed in the Index to Financial Statement Schedules (see page S-1)
(a)3. Exhibits
Exhibits for Entergy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are listed in the Exhibit Index (see page 529 and are incorporated by reference herein). Each management contract or compensatory plan or arrangement required to be filed as an exhibit hereto is identified as such by footnote in the Exhibit Index.